Testimony

• Ms. Katherine Siggerud

  Director, Physical Infrastructure Team

  Government Accountability Office
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  Testimony

  Ms. Katherine Siggerud

• The Honorable Mark Spitzer
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  Testimony

  The Honorable Mark Spitzer

  My name is Marc Spitzer, Chairman of the Arizona Corporation Commission (the “Arizona Corporation Commission” or “ACC”), and I am honored to address the Committee this morning. Today, I will update this Committee on the pipeline rupture in Arizona in July 2003, and the strides made by United States Department of Transportation Office of Pipeline Safety (“OPS”) and the ACC to not only strengthen the integrity of the pipelines in Arizona, but also the ongoing relationship between those two agencies. I will also propose for your consideration solutions addressing the need for some changes regarding the way agencies inspect and investigate the pipeline system. Finally, I suggest proposals to assure an adequate supply of energy. II. Kinder Morgan Rupture, An Infrastructure Example On July 30, 2003, Kinder Morgan’s 8-inch gasoline pipeline from Tucson to Phoenix burst, spewing gasoline on Tucson homes and disrupting the main supply line of gas to Phoenix. The resulting shortage combined with the difficulty in obtaining other sources of the correct “formula” of fuel to be used in the region led to long gas lines, filling stations running out of gas, motorists stranded in 100-degree heat and grave concern for the health, safety and welfare of our community. The pipeline rupture that occurred in Arizona in July 2003 is indicative of the aging U.S. infrastructure and is the reason federal and state governments need to conduct coordinated, aggressive inspections to reduce the risk of another pipeline rupture and the attendant environmental and economic damage. In October 2003, the Chairman of this Committee held a hearing in Phoenix in which I made suggestions for improvement to the OPS. Mr. Chairman, although more remains to be done, your efforts and those of OPS and my colleagues on the Arizona Commission have been successful. Let me briefly highlight the cooperation the Arizona Commission has enjoyed with OPS since the rupture. OPS timely released interstate pipeline safety records requested by the Commission on behalf of other Arizona state and local officials. OPS personnel visited the Commission and committed to develop rules governing the release of interstate pipeline records by state agents, consistent with the Patriot Act. OPS participated with our Commission in numerous public forums, including a special Task Force, to explain to the people of Arizona the federal and state roles in pipeline safety regulation. We particularly appreciate OPS’ support for a second metallurgical analysis of the Kinder Morgan pipe that failed last summer, enhanced inspection schedules for the fifty year-old segments of the pipeline and efforts to expedite replacement of that line. This spirit of cooperation should continue. III. Pipeline Inspection Solutions In light of today’s gasoline prices, Arizona cannot afford another situation like the one in July 2003, economically, environmentally or to protect public health. While improving the communications between agencies is a step in the right direction, I believe more can be done. I think the following areas need to be addressed: a. Arizona must be allowed to continue its participation with OPS in the oversight and inspection of pipelines, particularly in the Integrity Management Program (“IMP”). I should point out that in Arizona, OPS has graciously consented to state participation, which I understand is in accordance with the national model. This participation is important as each State has a cadre of trained experts at the ready, prepared to assist and support OPS in its task of ensuring interstate pipeline safety. b. Independent Exams should be required by law. The current system allows an entity that owns a pipeline to contract with a lab to do a “post mortem” on a piece of pipe that ruptured as the sole analysis as to why the problem occurred in the first place. This system of trust should be augmented with a system to independently verify those results. In Arizona, we have adopted rules requiring independent testing for intrastate pipeline accidents. Independent testing in serious cases should be federal law as well. c. Sharing is a two way street. At the ACC, we are currently making structural changes to our organization to increase the information flow from the ACC to OPS in order to better assist OPS and its sizable workload. d. Residential or commercial construction should not take place within 200 feet of a high pressure 8 or 12-inch gasoline pipeline. In Tucson, residential buildings were 37 feet from the pipeline. Within minutes over 6,000 gallons of gasoline had soaked several homes. We can only thank God they were unoccupied – but we must recognize the danger. Real estate development involves the use of heavy machinery and excavation – to continue to allow that to occur within 37 feet of a fifty-year old gasoline pipeline is insane. The federal and state governments are obligated to impose restrictions where counties and cities fail to act. The OPS should work with states to develop clear guidance for counties and cities on the dangers and locations of pipelines to prevent residential zoning within 200 feet. e. The gravest threat to pipeline safety is excavation. In an effort to prevent hazards due to excavations, I would point out the participation of OPS and the ACC in the Common Ground Alliance (“CGA”). The CGA is a group of government and industry stake holders that try to work toward a “common ground” in the excavation community. It focuses on the areas of best practices, education and research and development, to name a few. The CGA provides necessary information and education to the community about the dangers of unwary excavation. f. OPS funding must be sufficient to achieve the safety Americans expect in the transportation of hazardous liquids. IV. Energy Solutions Better, more coordinated pipeline inspections are only a part of the solution. This Committee should also evaluate the positive impacts on pipeline safety associated with increasing the supply of energy available to the market. No gasoline refinery has been built in the southwest United States since 1969. Limited refinery capacity imposes obvious stress on gasoline supply and relentless upward pressure on price. A new refinery in Arizona would reduce dependence on aging pipelines, the risks associated with high pressure in those lines, afford more dependable distribution and the ultimate reduction in required miles of pipeline will ease the burden on our Commission’s inspectors and OPS. The benefits of a refinery clearly serve the public health, safety and welfare. Government must address the connection between myriad boutique fuels and stress on the pipeline system. There are at least thirteen and as many as thirty formulations of gasoline. Fewer fuel formulations would simplify gasoline distribution, and make refineries more efficient, thereby reducing the price volatility associated with a local supply disruption. As Majority Leader in the Arizona Senate I negotiated Arizona’s State Implementation Program with the EPA Regional Administrator. I understand the importance of clean air and the need for clean burning gasoline to combat ozone, particulates and carbon monoxide in non-attainments areas in our State. However, the status quo hodgepodge of fuel blends, with no Federal effort to standardize, is highly inefficient for refineries, pipeline operators and service stations and needlessly expensive for motorists. As I note below, natural gas supply is now critically low. Arizona has no production, zero storage and constrained and costly pipeline transport. The lack of storage capacity is a key determinate of natural gas price volatility. Storage capacity provides the system with a buffer to supply and demand shocks, allowing it to smooth the natural, cyclical swings in prices. Natural gas volatility and the means to flatten the cost curve are especially important when we are faced with declining domestic gas reserves. Ninety percent of new power plants under construction in the U.S. are gas fired and eighteen new natural gas fired plants are proposed in Arizona alone. Federal and state agencies must unleash private operators willing to invest in natural gas production, new storage facilities, Liquefied Natural Gas (“LNG”) terminals and gas pipelines. A number of these projects are tied up in court. The Chair will be pleased to know it is not just the telecom companies that endlessly litigate, but as with telecommunications the public is ill-served by essential utilities mired in a perpetual legal morass. Congressional action may be necessary to sever this Gordian knot of parochial interests and Nimbyism. Our Commission is committed to renewable energy to clean the environment and reduce dependence on volatile and expense fossil fuels. Federal tax benefits for renewables, passed recently by the Senate, level the playing field viz a vis heavily subsidized oil, gas and nuclear, and stability in tax treatment of clean energy technologies is an imperative. In this extraordinary era of unstable crude oil supply and increasing global demand, the Congress should reconsider the CAFÉ standards. With premium gas at $3 per gallon, Detroit may be happy to adapt. The Arizona Commission has adopted demand-side management and energy efficiency programs. The goal is to avoid construction of costly and polluting power plants. We would welcome Federal teamwork with state agencies and the private sector to reduce demand. Finally, Michael Gent and the North American Reliability Council have for almost a year been seeking legislation to make the present electricity transmission rules legally enforceable. I am acutely aware of the temptation to attach special interest measures to a “must go” bill. But it is time for the gamesmanship to end. It should not take another blackout to coerce the Congress to enact the mandatory reliability standards proposed by NERC. V. Difficulties in Assuring Adequate Supplies of Energy at Reasonable Prices. Since my tenure on the Arizona Commission our ratepayers have endured the consequences of disruptions to energy supply, price spikes and the attendant economic and personal damage and dislocation. This is of course true throughout the country. In the 21st Century economy, dependent upon increasing amounts of energy to sustain high American productivity, the Government has fallen short. In January 2001, the California electricity market was unraveling, causing turmoil throughout the Western interconnection. There were many causes and culprits—lack of generation capacity, inadequate transmission, flawed regulation, absence of long-term contracts, misconduct of market participants culminating in old-fashioned panic. Enron’s collapse and California aftershocks helped crater the merchant power sector. Huge market capitalization was wiped out. Wall Street spurns the energy sector depriving an industry of necessary capital investment for infrastructure. Moreover, human capital is growing scarce as college classes in electrical engineering are only one-third filled. In natural gas, all evidence indicates the rosy scenario for North American gas production is a myth. The 2003 National Petroleum Council report indicates a structural deficit in natural gas production, something State utility regulators and customers already knew from the quintupling of commodity prices in 2001. Across the country, in the winter of 2003-2004 thousands of ratepayers could not afford to pay their gas heating bills and in then the shutoff notices came like the spring rains. Our Commission held a packed-house hearing at the Opera House in Prescott, Arizona to deal with customer complaints over high natural gas bills, and the villain was not even in the house. The gas LDC earned nothing on the high commodity costs passed through to our customers. Incantation of the term “market forces” was not accepted by those who knew the market was dysfunctional. In the meantime, hundreds of thousands of American jobs in the fertilizer, ammonia and other industries have been lost to high natural gas prices. Brand new, clean-burning gas-fired electricity plants stand idle while filthy, polluting coal plants run flat out—all due to commodity fuel prices. And press reports suggest opposition to LNG terminals has cancelled all five pending LNG applications. While Americans bear a great burden from inadequate supplies of natural gas, gas pipeline and storage contracts remain inadequate to deal with bottlenecks and shortages. The bottom line is America’s energy consumption has grown and will continue to grow, however, supplies are dwindling or remain untapped, our infrastructure is collapsing and the economic growth in other countries has resulted in increased competition for energy supplies in the global market. These pressing issues need immediate attention. I thank the Chairman and the Committee for the opportunity today, and I ask you to continue your consideration of the critical importance of our Nation’s pipelines and its energy supply. Marc Spitzer Chairman Arizona Corporation Commission U.S. Senate Testimony June 15, 2004

• The Honorable Kenneth Mead

  Inspector General

  U.S. Department of Transportation
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  Testimony

  The Honorable Kenneth Mead

  Mr. Chairman, Mr. Vice Chairman, and Members of the Committee: We appreciate the opportunity to testify today on the actions the Office of Pipeline Safety (OPS) has taken to improve pipeline safety and the actions that still need to be done. OPS is responsible for overseeing the safety of the Nation’s pipeline system, an elaborate network of more than 2 million miles of pipeline moving millions of gallons of hazardous liquids and more than 55 billion cubic feet of natural gas daily. The pipeline system is composed of predominantly three segments—natural gas transmission pipelines, natural gas distribution pipelines, and hazardous liquid pipelines—and has about 2,200 natural gas pipeline operators and 220 hazardous liquid pipeline operators. Pipelines are a relatively safe way to transport energy resources and other products, but they are subject to forces of nature, human action, and material defects that can cause potentially catastrophic accidents. Following the deadly pipeline explosion and fire in Bellingham, Washington, in June 1999, Senator Patty Murray requested the Office of Inspector General to review the activities of OPS. Also, a few months following the Bellingham accident, the United States Attorney’s Office, Western District of Washington, requested that we, in a joint effort with the Environmental Protection Agency’s Criminal Investigation Division, assist in an investigation to determine whether violations of Federal law occurred in connection with the accident. In the largest criminal and civil settlement ever obtained in a pipeline rupture case, two pipeline companies were ordered to pay $21 million in criminal penalties and $15 million in civil penalties. In addition, the companies were ordered to implement pipeline integrity/spill mitigation programs valued in the aggregate at $77 million. The charges, the first ever brought under the Hazardous Liquid Pipeline Safety Act of 1979, as amended, included three criminal counts for violating this act, which sets minimum safety standards for training employees who operate interstate pipelines that carry hazardous liquids. In response to Senator Murray’s request, we reported in March 2000 that weaknesses existed in OPS’s pipeline safety program and made recommendations designed to correct these weaknesses. These recommendations were later mandated in the Pipeline Safety Improvement Act of 2002 (2002 Act). This Act required us to review OPS’s progress in implementing our recommendations. Our testimony today is based largely on the results of this second review. Historically, OPS was slow to implement critical pipeline safety initiatives, congressionally mandated or otherwise, and to improve its oversight of the pipeline industry. The lack of responsiveness prompted Congress to repeatedly mandate basic elements of a pipeline safety program, such as requirements to inspect pipelines periodically and to use smart pigs to inspect pipelines. OPS is making considerable progress in implementing the recommendations in our March 2000 report by clearing out most, but not all, of the congressional mandates enacted in 1992 and 1996. It has also closed out nearly all the long-overdue National Transportation Safety Board (NTSB) safety recommendations we identified. In addition, OPS was removed from NTSB’s most-wanted list of safety improvements in 2002. Even though OPS has issued many important rules for improving pipeline safety, the most important rules, relating to Integrity Management Programs (IMP) will not be fully implemented for up to 8 years. This is a key issue as the IMP is the backbone of OPS’s risk based approach to overseeing pipeline safety. It is against this backdrop that I would like to discuss five major points regarding pipeline safety: (1) mapping the pipeline system; (2) monitoring the evolving nature of IMP implementation; (3) monitoring operators’ corrective actions for remediating pipeline integrity threats; (4) closing the safety gap on natural gas distribution pipelines; and (5) developing an approach to overseeing pipeline security. · Mapping the Pipeline System - The first step to an effective oversight program is to identify where the assets to be overseen are located. In the past year, OPS completed the development of its national pipeline mapping system (NPMS), an initiative the pipeline industry was reluctant to support, so Congress mandated it in the 2002 Act. The NPMS is now fully operational and has mapped 100 percent of the hazardous liquid (approximately 160,000 miles of pipeline) and natural gas transmission (more than 326,000 miles) pipeline systems operating in the United States. Congress exempted natural gas distribution pipelines from the mapping mandate, so currently OPS does not have mapping data on the approximately 1.8 million miles of this type of pipeline. · Monitoring the Evolving Nature of IMP Implementation - The next step is threefold: (1) operators assessing their pipelines for any potential integrity threat and correcting any threats that are identified, (2) OPS assessing whether the implementation of the operators’ IMPs were adequate, and (3) OPS continuing to support research and development projects to improve pipeline inspection technology. - As mandated by Congress, OPS issued regulations requiring pipeline operators of hazardous liquid and natural gas transmission pipelines to develop and implement IMPs. IMPs are in the early stages of implementation, and operators are not required to have all baseline integrity inspections completed of hazardous liquid pipelines until 2009 and of natural gas transmission pipelines until 2012. OPS required hazardous liquid pipeline operators—the first segment of the industry required to implement the IMP—to first complete baseline integrity inspections of pipeline miles in high-consequence areas, such as residential communities and business districts. These pipelines present the highest risk of fatalities, injuries, and property damage should an accident occur. About 135,000 miles of hazardous liquid and more than 326,000 miles of natural gas transmission pipeline still need baseline integrity inspections. Nevertheless, there are early signs that the baseline integrity inspections are working well for operators of hazardous liquid pipelines, and there was clearly a need for such inspections. According to OPS, in the pipelines inspected so far, more than 20,000 integrity threats have been identified and remediated. A key point to remember, though, is these threats were identified in less than 16 percent (about 25,000 miles) of hazardous liquid pipeline miles requiring baseline integrity inspections. - OPS will be monitoring the implementation of the IMP by more than 1,100 hazardous liquid and natural gas transmission pipeline operators. This is in addition to OPS’s ongoing oversight activities, such as inspecting new pipeline construction and investigating pipeline accidents. As of April 30, 2004, the 63 largest operators of hazardous liquid pipelines have undergone initial IMP reviews by OPS inspection teams, leaving 157 hazardous liquid and 884 natural gas transmission pipeline operators still needing an initial IMP review by an OPS inspection team. Monitoring the implementation of pipeline operators’ IMPs will be an ongoing process for years. - In addition, OPS must continue to support research and development projects to improve pipeline assessment technology. The majority of operators are using smart pigs to assess pipelines under their IMPs, but smart pigs are not a silver bullet that can identify all pipeline integrity threats. Smart pigs currently in use can successfully detect and measure corrosion, dents, and wrinkles but are less reliable in detecting other types of mechanical damage. As a result, certain integrity threats still go undetected after a baseline integrity inspection, and pipeline accidents may occur. Also, the smart pig technologies currently available cannot be used in natural gas distribution pipelines because the majority of distribution piping is too small in diameter (1 to 6 inches) and has multiple bends and material types intersecting over very short distances. · Monitoring Operators’ Corrective Actions for Remediating Pipeline Integrity Threats - Once a threat is identified, OPS will need to follow up to ensure that the operators take timely and appropriate corrective action. Of the more than 20,000 threats have been repaired to date, more than 1,200 required immediate repair, 760 threats required repairs within 60 days, and 2,400 threats required repairs within 180 days. More than 16,300 threats fall into the category of “other repairs,” for which remediation activities are not considered time sensitive. In understanding the operators’ actions to remediate many of these threats, IMP inspectors need a working knowledge of the operators’ pigging operations and of the interpretation of inspections’ results. At the time we issued our March 2000 report, OPS did not train its inspectors on the use of smart pig technologies and the interpretation of the result of the inspections. Since that time, OPS now provides a course to IMP inspectors where they gain the knowledge and skills required to conduct meaningful safety evaluations of operator pigging program inspections and of pigging data for hazardous liquid and natural gas transmission pipelines. OPS’s remediation criteria encompass a broad range of actions, which include mitigative measures (such as reducing the pipeline pressure flow), as well as repairs that an operator can take to resolve an integrity threat. But the process is not as simple as identifying the problem and determining how best to fix it. For some repairs, Federal and state environmental review and permitting processes have delayed preventive measures from occurring, as was demonstrated by the recent pipeline rupture in northern California. A hazardous liquid pipeline ruptured and released about 85,000 gallons of diesel fuel, affecting 20 to 30 acres of marshland. The deteriorating condition of this pipeline was well documented by the operator, who initiated action to relocate the pipeline in 2001. However, it took nearly 3 years and more than 40 permits before the operator was given approval to relocate the pipeline. It was too late to prevent this spill, but fortunately in this case there was no loss of human life. An Interagency Task Force was set up to monitor and assist agencies in their efforts to expedite their review of permits. However, the Task Force has yet to implement its Memorandum of Understanding (MOU) that would expedite the environmental review and permitting processes so that pipeline repairs can be made before a serious consequence occurs. If there are any further delays in implementing the MOU, then it may be necessary for Congress to take action. · Closing the Safety Gap on Natural Gas Distribution Pipelines - The natural gas distribution system makes up over 85 percent (1.8 million miles) of the 2.1 million miles of natural gas pipelines in the United States. Distribution is the final step in delivering natural gas to end users such as homes and businesses. While hazardous liquid and natural gas transmission pipeline operators are moving forward with IMPs, natural gas distribution pipeline operators are not required to have an IMP. According to industry officials, the initial reason why natural gas distribution pipelines were not required to have an IMP is that the majority of distribution pipelines cannot be inspected using smart pigs. The IMP is a risk-management tool designed to improve safety, environmental protection, and reliability of pipeline operations. That natural gas distribution pipelines cannot be internally inspected using smart pigs is not by itself a sufficient reason for not requiring operators of natural gas distribution pipelines to have IMPs. Other elements of the IMP can be readily applied to this segment of the industry, including but not limited to (1) a process for continual integrity assessment and evaluation, and (2) repair criteria to address issues identified by the integrity assessment and data analysis. Our concern is that the Department’s strategic safety goal is to reduce the number of transportation related fatalities and injuries, but natural gas distribution pipelines are not achieving this goal. Over the last 10 years, natural gas distribution pipelines have experienced over 4 times the number of fatalities (174 fatalities) and more than 3.5 times the number of injuries (662 injuries) than the combined totals of 43 fatalities and 178 injuries for hazardous liquid and natural gas transmission pipelines. To address this issue, the American Gas Foundation, with OPS support, is sponsoring a study to assess the Nation’s gas distribution infrastructure that will evaluate safety performance, current operating and regulatory practices, and emerging technologies. · Developing an Approach To Overseeing Pipeline Security - It is not only important that we ensure the safety of the Nation’s pipeline system, we must also ensure the security of the system. OPS took the lead to help reduce the risk of terrorist activity against the Nation’s pipeline infrastructure following the events of September 11, 2001, but OPS now states it plays a secondary or support role to the Department of Homeland Security’s (DHS) Transportation Security Administration (TSA). The current Presidential Directive that addresses this issue is at too high a level of generality to provide clear guidance on each Agency’s [DOT, DHS, and the Department of Energy (DOE)] responsibility in regards to pipeline security. The delineation of roles and responsibilities between DOT, DHS, and DOE needs to be spelled out in an MOU at the operational level so that we can better monitor the security of the Nation’s pipelines without impeding the supply of energy. Mapping the Pipeline System To provide effective oversight of the Nation’s pipeline system, OPS must first know where the pipelines are located, the size and material type of the pipe, and the types of products being delivered. The Nation’s pipeline system is an elaborate network of over 2 million miles of pipe moving millions of gallons of hazardous liquids and more than 55 billion cubic feet of natural gas daily. The pipeline system is composed of predominantly three segments—natural gas transmission pipelines, natural gas distribution pipelines, and hazardous liquid transmission pipelines—run by about 2,200 natural gas distribution and transmission pipeline operators and 220 operators of hazardous liquid pipelines (as seen in Table 1). Of the 2,200 operators of natural gas pipelines, there are approximately 1,300 operators of natural gas distribution pipelines and 880 operators of natural gas transmission pipelines. There are approximately 90 Federal and 400 state inspectors responsible for overseeing the operators’ compliance with pipeline safety regulations. Table 1. Pipeline System Facts and Description System Segment Facts Segment Description Natural GasTransmission Pipelines 326,595 Miles Lines used to gather and transmit natural gas from wellhead to distribution systems Natural GasDistribution Pipelines 1.8 Million Miles Mostly local distribution lines transporting natural gas from transmission lines to residential, commercial, and industrial customers Hazardous Liquid Transmission Pipelines 160,000 Miles Lines primarily transporting products such as crude oil, diesel fuel, gasoline, and jet fuel System Operators Facts Operators Description Natural Gas Transmission Operators 880 Large, medium, and small operators of natural gas transmission pipelines Natural Gas Distribution Operators 1,300 Large, medium, and small operators of natural gas distribution pipelines Hazardous Liquid Operators 220 Approximately 70 large operators and 150 small operators Originally, industry was reluctant to map the Nation’s pipeline system, so Congress responded by requiring, in the 2002 Act, the mapping of hazardous liquid and natural gas transmission pipelines. In the past year, OPS completed the development of the national pipeline mapping system (NPMS). The NPMS is now fully operational and has mapped 100 percent of the hazardous liquid (approximately 160,000 miles of pipeline) and natural gas transmission (more than 326,000 miles) pipeline systems operating in the United States. Congress excepted natural gas distribution pipelines from the mapping mandate, so OPS does not have mapping data on these pipelines. As a result of OPS and industry’s mapping efforts, Government agencies and industry have access to reasonably accurate pipeline data for hazardous liquid and natural gas transmission pipelines in the event of emergency or potentially hazardous situation. The public also has access to contact information about pipeline operators within specified geographic areas. Monitoring the Evolving Nature of IMP Implementation Hazardous liquid and natural gas transmission pipeline operators are in the early stages of implementing their IMPs. Safety baseline integrity inspections are just now being established systemwide—starting with hazardous liquid pipelines—so there are no comparable benchmarks. Nevertheless, as they begin implementing their IMPs, there is not yet enough evidence available to evaluate the IMP’s effectiveness in strengthening pipeline safety. However, there are early signs that the baseline integrity inspections are working well for operators of hazardous liquid pipelines, and there was clearly a need for such inspections. OPS is also in the early stages of overseeing the implementation of the operators’ IMPs, starting with IMP assessments of operators of hazardous liquid pipelines. In doing so, OPS is challenged with monitoring the implementation of the IMPs of more than 1,100 hazardous liquid and natural gas transmission pipeline operators and assisting in the development of technologies to meet the requirements of the IMP for all sizes and shapes of pipelines and different threat detections. Early Stages of Implementing Pipeline Operators’ IMPs The operators’ implementation of their IMPs is a lengthy process. Even though the IMP rules have been issued in their final form, they will not be fully implemented for up to 8 years. For example, as part of the rules requiring IMPs for operators of natural gas transmission pipelines, operators are required to begin baseline integrity inspections no later than June 17, 2004, with inspections completed no later than December 17, 2012. As operators begin implementing their IMPs, there are early signs that the baseline integrity inspections are working well for operators of hazardous liquid pipelines and that there was clearly a need for such inspections. So far, according to OPS, results from the operators’ baseline integrity inspections in predominantly high-consequence areas show that more than 20,000 integrity threats were identified and remediated. These threats may not have been discovered during the operators’ routine inspections. One of the most serious threats discovered was a case of corrosion where greater than 80 percent of the pipeline wall thickness had been lost. It has since been repaired. A lesser threat discovered was minor corrosion along a longitudinal seam. A key point to remember about the early baseline integrity inspection results for operators of hazardous liquid pipelines is that these 20,000 threats were discovered and remediated in less than 16 percent (about 25,000 miles) of pipeline miles needing inspection. About 135,000 miles of hazard liquid pipeline still needs baseline integrity inspections. Although 20,000 threats were discovered in the first 25,000 miles, we cannot statistically project the number of threats that could be expected in the remaining 135,000 miles that still need baseline integrity inspections. We also cannot project the number of threats that could be expected in the more than 326,000 miles of natural gas transmission pipelines that have yet to receive baseline integrity inspections. Also, baseline integrity inspections will not be completed for several years and certain threats may be very time sensitive, especially those to do with severe internal corrosion. OPS required hazardous liquid pipeline operators—the first segment of the industry required to implement the IMP—to first complete baseline integrity inspections of pipeline miles in high-consequence areas, as these areas are populated, unusually sensitive to environmental damage, or commercially navigable waterways. These pipelines present the highest risk of fatalities, injuries, and property damage should an accident occur. According to the American Petroleum Institute, nationwide there are approximately 160,000 miles of hazardous liquid pipelines, of which 51,400 miles are located in high consequence areas. As required by the IMP rule, 25,700 of the 51,400 miles (50 percent) should receive baseline inspections by September 30, 2004. OPS estimates, of the nearly 327,000 miles of natural gas transmission pipelines, 24,970 miles are located in high consequence areas. But pipelines in high-consequence areas represent only about 16 percent of the total miles (76,370 of 487,000 total miles) for both hazardous liquid and natural gas transmission pipelines and accidents that occur in non high-consequence areas can have catastrophic consequences, such as the deadly pipeline rupture, explosion, and fire near Carlsbad, New Mexico. On August 19, 2000, a 30-inch-diameter natural gas transmission pipeline ruptured adjacent to the Pecos River near Carlsbad. The released gas ignited and burned for 55 minutes. Twelve members of a family who were camping under a concrete-decked steel bridge that supported the pipeline across the river were killed and their three vehicles destroyed. Two nearby steel suspension bridges for gas pipelines crossing the river were extensively damaged. During the investigation, NTSB investigators found the rupture was a result of severe internal corrosion that caused a reduction in pipe wall thickness to the point that the remaining metal could no longer contain the pressure within the pipe. The significance of this finding cannot be overstated, as corrosion is the second leading cause of pipeline accidents, and pipeline operators will need to forge ahead on their baseline integrity inspections. Monitoring the Implementation of Pipeline Operators’ IMPs OPS must now begin assessing whether the implementation of more than 1,100 hazardous liquid and natural gas transmission pipeline operators’ IMPs were adequate. OPS must also perform ongoing oversight activities, such as inspecting new pipeline construction, monitoring research and development projects, and investigating pipeline accidents. To do so, OPS believes it will need to augment its own resources with those of the states to efficiently and effectively oversee the operators’ IMPs. OPS is actively overseeing IMP implementation through its assessments of hazardous liquid pipeline operators’ IMP plans. As of April 30, 2004, the 63 largest operators of hazardous liquid pipelines have undergone the initial IMP assessments. That leaves 157 more operators of hazardous liquid pipelines and 884 operators of natural gas transmission pipelines who will need initial IMP assessments. Monitoring the implementation of pipeline operators’ IMPs will be an ongoing process. OPS IMP inspection teams, made up of Federal and state inspectors, spent approximately 2 weeks at each operator’s headquarters reviewing results of integrity inspection and actions taken to address integrity threats, as well as overall IMP development and effectiveness. With about 1,041 pipeline operators who have not yet had an initial IMP assessment (at 2 weeks for each assessment), compounded by the fact that pipelines operators have up to 8 years to complete their baseline integrity inspections, the overall effectiveness of operators’ IMPs in strengthening pipeline safety will not be known for years. Advancing Threat Detection Technologies Is Fundamental to the Success of Integrity Inspections As part of OPS’s IMP rule, operators of hazardous liquid and natural gas transmission pipelines are required to inspect the integrity of their pipelines using smart pigs or an alternate equally effective method such as direct assessment. To date, OPS’s integrity management assessments indicate that operators of hazardous liquids pipelines used smart pigs about 70 percent of the time to conduct their baseline integrity inspections and strongly favored the use of smart pigs over alternative inspection methods available under the IMP. Although there have been significant advances in smart pig technology, the current technology still cannot identify all pipeline integrity threats. Smart pigs currently in use can successfully detect and measure corrosion, dents, and wrinkles but are less reliable in detecting other types of mechanical damage. As a result, certain integrity threats go undetected and pipeline accidents may occur. For example, on July 30, 2003, an 8 inch diameter hazardous liquid pipeline ruptured near a residential area under development in Tucson, Arizona, releasing more than 10,000 gallons of gasoline and shutting down the supply of gasoline to the greater metropolitan Phoenix area for 2 days. Whether this rupture could have been prevented is still not known because the cause of the rupture, stress crack corrosion, rarely causes failure in hazardous liquid pipelines. Also, currently there are no tools or mechanisms small enough to fit in 8 inch diameter piping in order to identify the threat of stress crack corrosion. OPS’s research and development (R&D) program is aimed at enhancing the safety and reducing the potential environmental effects of transporting natural gas and hazardous liquids through pipelines. Specifically, the program seeks to advance the most promising technological solutions to problems that imperil pipeline safety, such as damage to pipelines from excavation or corrosion. OPS sponsors R&D projects that focus on providing near-term solutions that will increase the safety, cleanliness, and reliability of the Nation’s pipeline system. OPS’s R&D funding has more than tripled, from $2.7 million in FY 2001 to $8.7 million in FY 2003. Nearly $4 million of the $8.7 million is funding projects to improve the technologies used to inspect the integrity of pipeline systems in support of the IMP. OPS currently has 22 active projects that explore a variety of ways to improve smart pig technologies, develop alternative inspection and detection technologies for pipelines that cannot accommodate smart pigs, and improve pipeline material performance. For example, OPS has a project underway that will improve the capabilities of smart pigs to better detect and measure both corrosion and mechanical damage. The expected project outcome is a smart pig that is simpler to build and use. The R&D challenge OPS now faces is seeing these projects through to completion, without undue delay and expense, to ensure that viable, reliable, cost effective technologies become readily available to meet the demands of increased usage required under the IMP. Monitoring Remediation of Pipeline Integrity Threats Much of the Nation’s existing pipeline infrastructure is over 50 years old. When pipeline integrity threats are identified, repairs may require Federal and state environmental reviews and permitting before the operator can proceed. However, OPS regulations identify repair criteria for the types of threats that must be repaired within specified time limits. At times, the environmental review and permitting processes become an obstacle that can delay the operators’ remediation efforts. When it passed the Pipeline Safety Improvement Act of 2002, Congress recognized that timely repair of pipeline integrity threats was essential to the well-being of human health, public safety, and the environment. Therefore, Congress directed the President to establish an interagency committee to develop and ensure the implementation of a coordinated environmental review and permitting process. This process should allow pipeline operators to commence and complete all activities necessary to carry out pipeline repairs within any time periods specified under OPS’s regulations. Certain Pipeline Repairs Must Be Completed Within Specified Time Limits OPS regulations identify remediation criteria for the types of threats that must be repaired within specified time limits, the length of which reflects the probability of failure. For hazardous liquid pipelines, the three categories of repair are defined as immediate repair, 60 days to repair, and 180 days to repair. For example, a top dent with any indication of metal loss requires immediate response and action, whereas a bottom dent with any indication of metal loss requires a response and action within 60 days. Other types of threats include remediation activities that are not considered time-sensitive. Using the criteria, pipeline operators must characterize the type of repair required, evaluate the risk of failure, and make the repair within the defined time limit. Of the more than 20,000 threats that have been identified and remediated to date, more than 1,200 required immediate repair, 760 required repairs within 60 days, and 2,400 required repairs within 180 days. More than 16,300 threats fall into the category of other remediation activities that are not considered time sensitive. OPS’s remediation criteria encompass a broad range of actions, which include mitigative measures (such as reducing the pipeline pressure flow), as well as repairs that an operator can make to resolve an integrity threat. For immediate repairs, an operator must temporarily reduce operating pressure or shut down the pipeline until the operator completes the repair of the threat. The challenges inspectors face during a review of an operator’s baseline integrity inspection results are to determine whether OPS’s repair criteria were properly used to characterize the type of repair required for each threat identified and whether the operator’s threat remediation plans are adequate to repair or mitigate the threat. More importantly, however, is that OPS will need to follow up to ensure that the operator has properly executed its remediation actions within the defined time limit. Improvements Are Needed in Coordinating Federal and State Environmental Reviews and Permitting Processes The transmission of energy through the Nation’s pipeline system in a safe and environmentally sound manner is essential to the well-being of human health, public safety, and the environment. One way to do this is to develop and ensure implementation of a coordinated Federal and state environmental review and permitting process that will enable pipeline operators to complete pipeline repairs quickly. There will be mounting pressures to accelerate the environmental review and permitting processes, given the high number of threats found during the early stages of pipeline operators’ baseline integrity inspections that must be repaired within specified time limits. The recent pipeline rupture in northern California demonstrates the perils of not being able to promptly repair pipeline threats. In April 2004, a hazardous liquid pipeline ruptured in the Suisun Marsh south of Sacramento, California, releasing about 85,000 gallons of diesel fuel into 20 to 30 acres of marshland. Muskrats, beaver, and water fowl were affected by the spill. Fortunately, there were no human fatalities or injuries as a result of the rupture. The deteriorating condition of the pipeline that ruptured was well documented by the pipeline operator, who had reduced pipeline operating pressure to lessen the risk of a rupture and keep the flow of energy to users in Sacramento and Chico, California, and Reno, Nevada. The pipeline operator wanted to relocate the pipeline away from the Suisun Marsh and initiated actions to do so in 2001. However, the environmental review and permitting processes took far too long: nearly 3 years and more than 40 permits in total. There is little doubt that the rupture would not have occurred had the permit process been quicker. The importance of accelerating the permit process, when necessary, cannot be overstated. As we have noted, results from the hazardous liquid pipeline operators’ baseline integrity inspections in high-consequence areas show that more than 20,000 integrity threats were identified for remediation. More than 1,200 threats required immediate repairs, 760 threats required repairs within 60 days, and 2,400 threats required repairs within 180 days. As operators continue with their baseline integrity inspections, the implications are that the number of integrity threats will continue to rise. According to OPS, repairs for other known pipeline threats are being delayed because of the environmental review and permitting processes, and they are best taken care of sooner rather than later, so as to prevent another incident like the Suisun March rupture. When it passed the 2002 Act, Congress recognized the need to expedite the environmental review and permitting process. Section 16 of the 2002 Act directed the President to establish an interagency committee that would implement a coordinated environmental review and permitting process so that pipeline repairs could be made within the time periods specified by IMP regulations. Committee activities were to include: · An evaluation of Federal permitting requirements. · Identification of best management practices to be used by industry. · The development of an MOU by December 17, 2003, (1 year after the enactment of the 2002 Act) to provide for a coordinated and expedited pipeline permit process that would result in no more than minimal adverse effects on the environment. The 2002 Act also requires the committee to consult with state and local environmental, pipeline safety, and emergency response officials, and requires the Secretary of Transportation to designate on ombudsman to assist in expediting the pipeline process and resolving disagreements over pipeline repairs between Federal, state, and local permitting agencies and the pipeline operator. To implement Section 16, the President issued an Executive Order in May 2003, establishing the Interagency Task Force and directed it to implement the committee activities. The Chairman of the Council on Environmental Quality chairs the Interagency Task Force, whose membership includes representatives from the Departments of Agriculture, Commerce, Defense, Energy, the Interior, and Transportation; the Environmental Protection Agency; the Federal Regulatory Commission; and the Advisory Council on Historic Preservation. Although an MOU has been drafted, it has not been finalized as of June 11, 2004. According to OPS, not all members of the Interagency Task Force have agreed to the provisions of the MOU, while other members believe that there are provisions in the Clean Air Act, Clean Water Act, the Endangered Species Act that prohibit them from taking any action to expedite the permitting process. Until the MOU is finalized, an evaluation of Federal permitting requirements and identification of best management practices to be used by industry will be further delayed. These issues need to be resolved by the Interagency Task Force. While the problem may not be easily resolved, Federal agencies must work together to accelerate the environmental review and permitting process to avoid failures like the Suisun Marsh rupture or even worse. If the Interagency Task Force set up to monitor and assist agencies in their efforts to expedite their review of permits cannot develop a method for expediting the environmental review and permit process so that pipeline repairs can be made before a serious consequence occurs, then it may be necessary for Congress to take action. Closing the Safety Gap on Natural Gas Distribution Pipelines The 2002 Act requires that the operators of natural gas pipeline facilities implement IMPs. However, the IMP requirement applies only to natural gas transmission pipelines and not to natural gas distribution pipelines. As part of the IMP, operators of hazardous liquid and natural gas transmission pipelines are required to inspect the integrity of their pipelines using one or more of the following inspection methods: smart pigs, pressure testing, or direct assessment. According to officials of the American Gas Association, the initial reason why IMPs were not required for natural gas distribution pipelines is that distribution pipelines cannot be inspected using smart pigs. The smart pig technologies currently available cannot be used in natural gas distribution pipelines because the majority of distribution piping is too small in diameter (1 to 6 inches) and has multiple bends and material types intersecting over very short distances. The IMP is a risk-management tool designed to improve safety, environmental protection, and reliability of pipeline operations. That natural gas distribution pipelines cannot be internally inspected using smart pigs is not by itself a sufficient reason for not requiring operators of natural gas distribution pipelines to have IMPs. Other elements of the IMP can be readily applied to this segment of the industry, including but not limited to (1) a process for continual integrity assessment and evaluation, (2) an analytical process that integrates all available information about pipeline integrity and the consequences of failure, and (3) repair criteria to address issues identified by the integrity assessment and data analysis. Natural Gas Distribution Pipeline Safety Concerns Our concern is that the Department’s strategic safety goal is to reduce the number of transportation related fatalities and injuries, but natural gas distribution pipelines are not achieving this goal. In the 10 year period from 1994 through 2003, OPS’s data show accidents in natural gas distribution pipelines have caused more than 4 times the number of fatalities (174 fatalities) and more than 3.5 times the number of injuries (662 injuries) when compared to a combined total of 43 fatalities and 178 injuries associated with hazardous liquid and gas transmission pipeline accidents combined. Accidents involving natural gas distribution pipelines can be as catastrophic as accidents involving hazardous liquids or natural gas transmission pipelines. For example, on December 11, 1998, in downtown St. Cloud, Minnesota, a communications crew ruptured an underground natural gas distribution pipeline, causing an explosion that killed 4 people, seriously injured 1, and injured 10 others. Six buildings were destroyed. In another example, in July 2002, a gas explosion in a multiple family dwelling in Hopkinton, Massachusetts, killed 2 children and injured 14 others. In the past 3 years, the number of fatalities and injuries from accidents involving natural gas distribution pipelines has increased while the number of fatalities and injuries from accidents involving hazardous liquid and natural gas transmission pipelines has held steady or declined. OPS’s data show that fatalities and injuries from accidents involving natural gas distribution pipelines increased from 5 fatalities and 46 injuries in 2001 to 11 fatalities and 58 injuries in 2003. For the same period, fatalities and injuries from accidents involving hazardous liquid and natural gas transmission pipelines decreased from 2 fatalities and 15 injuries in 2001 to 1 fatality and 13 injuries in 2003. Although OPS has moved forward with initiatives to enhance the safety of natural gas distribution pipelines, OPS needs to ensure that the pace of its efforts moves quickly enough, given the upward trend in fatalities and injuries involving these pipelines and the projected increase in distribution pipelines to meet the increasing demand for natural gas. OPS should require operators of natural gas distribution pipelines to implement some form of pipeline integrity management or enhanced safety program with the same or similar integrity management elements, except pigging, as the hazardous liquid and natural gas transmission pipelines. This would be consistent with OPS’s risk based approach to overseeing pipeline safety by using IMPs to reduce the risk of accidents that may cause injuries or fatalities to people living or working near natural gas distribution pipelines, as well as to reduce property damage. Developing an Approach To Overseeing Pipeline Security The focus of our recently completed review was pipeline safety. However, given the importance of protecting the Nation’s infrastructure of pipeline systems, we also reviewed OPS’s involvement in the security of the pipeline systems. OPS’s Security Efforts Following September 11, 2001 Following the events of September 11, 2001, OPS moved forward on several fronts to help reduce the risk of terrorist activity against the Nation’s pipeline infrastructure, such as opening the lines of communication among Federal and state agencies responsible for protecting the Nation’s critical infrastructure, including pipelines; conducting pipeline vulnerability assessments and identifying critical pipeline systems; developing security standards and guidance for security programs; and working with Government and industry to help ensure rapid response and recovery of the pipeline system in the event of a terrorist attack. To protect the Nation’s pipeline infrastructure, OPS issued new security guidance to pipeline operators nationwide in September 2002. In the guidance, OPS requested that all operators develop security plans to prevent unauthorized access to pipelines and identify critical facilities that are vulnerable to a terrorist attack. OPS also asked operators to submit a certification letter stating that the security plan had been implemented and that critical facilities had been identified. During 2003, OPS in conjunction with the DHS’s TSA started reviewing operator security plans. The plans reviewed have been judged responsive to the OPS guidance. Unlike its pipeline safety program, OPS’s security guidance is not mandatory: industry’s participation in a security program is strictly voluntary and cannot be enforced unless a regulation is issued to require industry compliance. In fact, it is still unclear what agency or agencies will have responsibility for pipeline security rulemaking, oversight, and enforcement. Although OPS took the lead to help reduce the risk of terrorist activity against the Nation’s pipeline infrastructure following the events of September 11, 2001, OPS has stated it now plays a secondary, or support, role to TSA, the agency with primary responsibility for ensuring the security of the Nation’s transportation system, including pipelines. Recent Initiatives Clarifying Security Responsibilities Certain steps have been taken to establish what agency or agencies would be responsible for ensuring the security of the Nation’s critical infrastructure, including pipelines. For example, in December 2003, Homeland Security Presidential Directive/HSPD-7 (HSPD 7): · Assigned the DHS the responsibility for coordinating the overall national effort to enhance the protection of the Nation’s critical infrastructure and key resources. · Assigned DOE the responsibility for ensuring the security of the Nation’s energy, including the production, refining, storage, and distribution of oil and gas. · Directed DOT and DHS to collaborate on all matters relating to transportation security and transportation infrastructure protection and to regulating the transportation of hazardous materials by all modes, including pipelines. Although HSPD-7 directs DOT and DHS to collaborate in regulating the transportation of hazardous materials by all modes, including pipelines, it is not clear from an operational perspective what “to collaborate” encompasses, and it is also not clear what OPS’s relationship will be with DOE. The delineation of roles and responsibilities between DOT and DHS needs to spelled out by executing an MOU or a Memorandum of Agreement. OPS also needs to seek clarification on the delineation of roles and responsibilities between itself and DOE. Mr. Chairman, this concludes my statement. I will be pleased to answer any questions that you might have.

• The Honorable James L. Connaughton
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  Testimony

  The Honorable James L. Connaughton

  Good morning Chairman McCain, Ranking Member Hollings, and Members of the Committee. I am pleased to appear before you today to describe our efforts to implement the provisions of the Pipeline Safety Act of 2002 by developing an efficient process for expedited pipeline testing and repair while ensuring environmental stewardship. The Nation’s existing pipeline infrastructure, much of which is over 50 years old, requires regular safety and environmental reviews to ensure its reliability. Timely testing and repair of both natural gas and hazardous liquid pipelines is essential to protect human life and property, and to facilitate the sufficient availability and use of natural gas and liquid fuels for our energy needs. At the same time, many natural gas and hazardous liquid pipelines run through “High Consequence Areas”: areas that are highly populated, are unusually sensitive to environmental damage, or are located along or near commercially navigable waterways. Effecting timely repairs of these pipelines, while enabling effective environmental protection, is a critical challenge we are tackling as directed by Congress in Section 16 of the Pipeline Safety Act of 2002. Our work is ongoing, and I am pleased to report to you today on our results thus far. Implementation of the Pipeline Safety Act of 2002 Through Executive Order 13212, issued on May 18, 2001, President Bush directed Federal agencies to expedite reviews of authorizations for energy-related projects and to take other actions necessary to accelerate the completion of projects that will increase the production, transmission, or conservation of energy, while maintaining safety, public health and environmental protections. The Executive Order also created a Task Force, chaired by CEQ, to monitor and assist Federal agencies in carrying out this directive. Following pipeline ruptures in Bellingham, Washington in June 1999 and Carlsbad, New Mexico in August 2000 which caused loss of life and significant property damage, Congress enacted the Pipeline Safety Improvement Act of 2002 (PSIA), which was signed into law by President Bush on December 17, 2002. Section 16 of the PSIA directed the President to establish an Interagency Committee to implement a coordinated environmental review and permitting process enabling pipeline repairs within the time periods specified by DOT regulations called for in other sections of the PSIA. To implement Section 16 of the PSIA, the President issued Executive Order 13302 on May 15, 2003, adding these pipeline safety functions to the charge given the Task Force authorized under Executive Order 13212. Therefore, CEQ has coordination responsibility for efforts to implement Section 16 of the PSIA, and that is why I appear before you today. MOU Development During the summer and fall of 2003, a working group of the Task Force evaluated Federal permitting requirements, identified best management practices (BMPs), and developed a memorandum of understanding (MOU) to provide for a coordinated and expedited pipeline permit review process. The text of the MOU is attached to my written testimony. The process envisioned under the MOU would expedite the ability of pipeline operators to obtain the necessary permits or authorizations prior to making repairs in a High Consequence Area when a “time-sensitive” repair is indicated by testing: that is, when the pipeline’s physical condition is such that repair is mandated within a certain period of time as directed by the PSIA and DOT’s implementing regulations. The MOU enhances coordination of the processes through which agencies with environmental and historic preservation review responsibilities under various statutes -- such as the Clean Water Act, or the Endangered Species Act -- meet those responsibilities in connection with the authorizations required to repair natural gas and hazardous liquid pipelines that have been identified by pipeline operators as in need of repair on a timely basis to protect life, health or physical property. The MOU recognizes that early planning, notice, and consultation among pipeline operators and Federal agencies can result in a structured process that facilitates timely decisions and enables critical repair actions to go forward, within the context of resource conservation. The MOU supports the development of a comprehensive, “one-stop” information system to allow pipeline operators and agencies alike access to the best available information on pipeline testing and repair schedules, agency official contact information, natural resource conservation needs, and recommendations on management practices for testing and repair. Further, the MOU recognizes that the identification and use of best management practices (BMPs) to avoid, reduce, or mitigate impacts to resources of concern can be one means of implementing specific measures to protect affected resources and encourage increased environmental stewardship. Further Actions The Task Force working group continues to consult on specific steps and agency actions to implement the process envisioned in the MOU. First, we are working with industry to encourage early notification by operators of their testing schedules, so as to enable early consultation on issues that arise, and coordinate pipeline testing so that energy supply and price impacts are minimized. Second, interagency discussions are well along in attempting to consolidate existing sequential permitting processes into a single, concurrent permitting process for general repairs that is triggered by the operator upon finding of a time-sensitive repair need. Third, we are considering the potential for proposing categorical exclusions under the National Environmental Policy Act for instances where repairs can occur entirely within an existing right-of-way, or where minimal additional access is required, so long as consensus Best Management Practices are used to minimize impacts. Issuance of a categorical exclusion would mean that the specific category of actions described in the categorical exclusion do not individually or cumulatively have a significant effect on the human environment, and therefore, neither an environmental assessment nor an environmental impact statement would be required. Finally, we are working with pipeline operators to identify those instances where specific issues and additional authorizations may have in the past prevented repairs in a timely manner (e.g., threatened or endangered species, navigable waterways, private lands, etc.). Once these instances are identified, we will work to develop specific procedures that will avoid these issues in the future and allow for timely completion of time-sensitive repairs in each case while allowing Federal agencies to carry out their resource protection responsibilities. Conclusion Given the state of our Nation’s aging pipeline infrastructure, we are working to ensure that timely repairs can be made, accidents can be avoided, and human life and property is protected. At the same time, we are working to minimize negative impacts on the surrounding environment, and on our Nation’s energy supply. I will be glad to take any questions you may have. Thank you.

• Mr. Samuel Bonasso
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  Testimony

  Mr. Samuel Bonasso

  Mr. Chairman, my name is Samuel Bonasso. I am the Deputy Administrator of RSPA, the Research and Special Programs Administration of the U.S. Department of Transportation. With me is Stacey Gerard, Associate Administrator for the Office of Pipeline Safety (OPS). Thank you for this opportunity to discuss our strategy and our long term prospects for improved safety and reliability of the Nation’s pipeline infrastructure. We greatly appreciate this committee’s attention and support for our work. Under Secretary Mineta’s leadership, RSPA and OPS have made great strides in meeting the mandates set forth in the Pipeline Safety Improvement Act (PSIA) of 2002. My testimony today will address our responses to these mandates, including specific implementation issues, and the results of our actions. Further, I want to make you aware of potential short and near term risks of reduced pipeline capacity and energy supply due to required pipeline testing and repairs. The Nation’s pipelines are essential to our way of life. The 2.3 million miles of natural gas and hazardous liquid pipelines carry nearly two-thirds of the energy consumed by our Nation. Pipelines are the safest and most efficient way to transport the enormous quantities of natural gas and hazardous liquids across land used by our country. Recent increased attention to the need for pipeline safety is rooted in demographic changes taking place in our country. Suburban development in previously rural areas has placed people closer to pipelines. This increases the risk that pipeline accidents, although infrequent, can have tragic consequences. Expansion and development also means more construction activity near pipelines— the leading cause of pipeline accidents. Pipeline safety is more than inspecting pipelines. It involves 1. having better information to understand safety problems, 2. knowing where to set the bar in safety standards, 3. advancing technology to find and fix those problems, 4. partnering with state and local governments to oversee this critical infrastructure, and 5. building alliances to prevent damage and educate the public about how to live safely with pipelines. Pipeline safety is a top priority for the Bush Administration and for Secretary Mineta, personally. With their support, RSPA and OPS have strengthened each of these five elements in just a few years. Expanded enforcement has been an important approach in strengthening the pipeline safety program. In the past 10 years, 57 inspectors have been added to the OPS staff, from 28 inspectors in 1994 to 85 inspectors today. Our partnerships with the states, such as our agreement with the Arizona Corporation Commission, provide several hundred more inspectors. I. We Are Implementing A Plan With the enactment of the PSIA, we embarked on a new, more comprehensive and informed plan to identify and manage the risks that pipeline operators face and that pipelines pose to our communities. By collecting and using better information about pipelines, today we know more about pipelines, the world they traverse, and the consequences of a pipeline failure. 1. Higher Standards We have raised the standards for pipeline safety, through integrity management requirements and 17 other regulations, and incorporated 30 new national consensus safety standards into our regulations. 2. Better Technology To improve the technology available to assess and repair pipelines, we have awarded almost eight million dollars, for three dozen research projects since March 2002. 3. Stronger Enforcement Our inspections are much more rigorous. Today, we spend 240 hours on a comprehensive integrity management inspection, in contrast to 32 hours in 1996 for a standard pipeline safety inspection. We have adopted a tough-but-fair approach to improving enforcement, making heavier use of large fines, while guiding pipeline operators to meet higher standards. We have initiated steps to ensure that penalties are collected and acknowledged promptly. 4. Better States’ Partnership We have strengthened our partnerships with state pipeline safety agencies, such as the Arizona Corporation Commission, through increased training, shared inspection data bases, a distributed information network to facilitate communications, and policy collaboration. 5. Cleaning Up Our Record Our new record as a regulator is important to us. In the past three years, the OPS has eliminated most of a 12-year backlog of outstanding mandates and recommendations from Congress, the National Transportation Safety Board, the DOT Inspector General, and the GAO. Over the past 4 years, we have responded positively to 41 NTSB safety recommendations and are working to close the remaining 10 recommendations. 6. Preparing Partners and Going Local Helping communities to know how they can live safely with pipelines is a very important goal. We cannot succeed in improving pipeline safety without enlisting the help of local officials. We are moving on a number of fronts: · Working with others, we have proposed to incorporate a new standard for public education in regulations to ensure community officials and citizens have essential safety information they need to make informed decisions; · We have commissioned a study by the Transportation Research Board of the National Academy of Sciences on issues of encroachment and maintenance on pipeline rights-of- way which will report results in July. · We have enlisted the help of the local fire marshals to bring information and guidance to communities to build understanding of pipeline safety and first responder needs, to help identify high consequence areas in communities, and to provide an understanding of LNG operations. · Similarly, to foster safety and environmental protection on Tribal Lands, we are working toward a partnership with the Council of Energy Resource Tribes. II. Responding to the Pipeline Safety Improvement Act of 2002 (PSIA) Pipelines are the arteries of our Nation’s energy infrastructure and critical to the Nation’s viability and well being. The Congress recognized the critical importance of pipelines when it passed the Pipeline Safety Improvement Act of 2002. The actions described above are consistent with the PSIA, which also has given us new mandates. Under Secretary Mineta’s leadership, RSPA and OPS are aggressively responding to these new mandates. 1. Integrity Management We have completed the most significant improvement in pipeline safety standards by finalizing regulation of integrity management programs for hazardous liquid and natural gas transmission operators. Going beyond the PSIA requirements, we are studying, in conjunction with the American Gas Association, the potential for an integrity management program that would be appropriate for gas distribution and municipal operators. We and our state partners have completed comprehensive inspections of large hazardous liquid operators. During these inspections, we observed that operators had completed over 20,000 repairs, 4,400 of which were time sensitive and important to find and fix expeditiously. 2. Operator Qualification We have completed half of the reviews of interstate operators’ qualification programs and expect to meet the 2006 statutory deadline. States have made similar progress. We plan to incorporate improved consensus standards for the qualification of pipeline operators for safety critical functions when the standards are completed later this year. 3. Public Education and Mapping We believe that communication between Federal, State and local government, the operator and the public about how to live safely with pipelines is an important element in helping to assure the safety of our Nation’s energy transportation pipeline infrastructure. Actions are underway to improve communications with state and local officials about actions they can take to protect their citizens and pipelines. We are improving opportunities for communities to understand pipeline safety and to take local action as required by the PSIA. We completed the National Pipeline Mapping system and we worked with pipeline operators to complete, by the December 2003 deadline, self assessments of their public education programs against new, higher standards. To respond to the need for improved public awareness of pipelines, OPS, the National Association of Pipeline Safety Representatives (NAPSR), and the pipeline industry have cooperated to develop a national consensus standard- American Petroleum Institute’s Recommended Practice 1162 (RP 1162) for public education. RP1162 is designed to help pipeline operators meet new standards established in the PSIA. It requires operators to identify audiences to be contacted, effective messages and communications methods, and information for evaluating and updating public awareness programs. We have proposed incorporation of RP 1162 into our regulations. We are starting a Crisis Communications Initiative to improve communications following an accident. In July, we will host a workshop to develop the framework for this initiative, including a pilot program on crisis communications and interagency relationships. We expect this initiative to meet national objectives and to be complementary to the Homeland Security’s National Response Plan, FERC’s Liquefied Natural Gas efforts, and the National Association of Fire Marshal’s education program. 4. Damage Prevention Working with the Common Ground Alliance and the Federal Communications Commission, we have provided for a single, national three-digit number for one call systems, most likely 811. The Federal Communications Commission is expected to finalize this action later this year. This will allow all Americans to take one action to protect all pipelines from excavation damage- the major cause of pipeline damage and failure. By making it simpler to call one number to mark underground lines, we expect more people to use this important prevention service. 5. Research and Development To provide a vision for the advancement of technology, we developed a memorandum of understanding with the Department of Energy and the National Institute of Standards and Technology for research planning, and have completed a five year plan. The plan includes a detailed management strategy for research solicitation and procurement; technology transfer and application of results; coordination and collaboration with other agencies, industry and stakeholders; approaches to communicate project findings; and methods of optimizing the use of resources. 6. Security Since 9/11, the Department has devoted considerable attention to security across all modes of transportation, including national pipeline security. While the PSIA did not speak specifically to security, pipeline system integrity and security are inextricably linked. We maintain clear expectations for critical pipeline operators’ security preparedness. With the Department of Homeland Security (DHS), we verify industry action by conducting audits of all major pipeline operators’ security preparedness. OPS expanded its oil spill emergency response exercise program to include focus on security and law enforcement for maintaining the reliability of energy supply. The Department plans to continue working closely with DHS on pipeline security issues. 7. Interagency efforts to Implement Section 16 of the PSIA Section 16 of the PSIA requires agencies with responsibilities relating to pipeline repair projects to develop and implement a coordinated process for environmental review and permitting. The interagency working group currently has five efforts underway to: · refine early notification and Federal involvement procedures; · identify electronic communication methods that would expedite and streamline review; · establish practices that would reduce or minimize effects to the environment such that reviews would be expedited; and · refine permitting and review procedures for time-sensitive pipeline repairs consistent with our regulatory and statutory obligations. III. Keeping the Energy Infrastructure Viable The Nation’s economic viability and well-being depend on the enormous quantities of oil, fuel and natural gas transported safely, efficiently and at low cost by pipelines each and every day. The energy pipeline infrastructure in the United States represents a $31 billion investment in over 2 million miles of pipeline technology that is essential to American economic interests- a myriad of goods and services as well as millions of jobs are made possible and supported by this transportation infrastructure. Federal integrity regulations and PSIA have significantly increased the requirements on operators to test the integrity of this infrastructure, discover any defects and make repairs before ruptures or leaks can occur during the implementation of this important safety initiative. This initiative could take more pipelines temporarily out of service for inspection, assessment and repairs and could impact the delivery of energy. There are two aspects of this safety initiative which are being given special attention by DOT and other Federal agencies. First, we, from our safety purview, are the agency that sees the results of the testing of multiple pipelines by multiple operators across the regions of our Nation. Our experience suggests that many repairs will be required under our integrity management regulations- potentially tens of thousands of repairs annually, and perhaps clustering in a particular region of the country. Second, while a pipeline operator awaits permits for repairs, the operating pressure of the pipeline usually needs to be reduced to maintain a safety margin. There is a risk that the amount of pressure reductions required pending permitting of repairs could measurably reduce the energy capacity of pipeline systems in certain regions. Depending on where pipelines are located and how energy markets are impacted, pressure reductions during peak demand periods could result in fuel shortages and price increases. The Congress recognized this potential problem and required Federal agencies to participate in an Interagency Committee to facilitate the prompt repair of our pipelines. Work is ongoing with the other relevant Federal agencies to develop guidance to ensure that any necessary Federal permits for repairs of pipelines in danger of rupture can be coordinated and expedited. Some of the specific issues the Interagency Committee is addressing include: · Feasibility of providing Federal permitting agencies with advance information about operator test schedule. Obtaining this information in advance could help agencies anticipate resources needed for permitting repairs and to exchange information about required actions as soon as possible. Pipeline operators, however, are concerned that by providing this information they might be expected to meet the schedule regardless of factors that are beyond their control (weather, availability of appropriate equipment and certified crews, etc.). Operators are also concerned that the testing schedules could become public information that can not be protected as proprietary information, releasing business-sensitive and possibly security-sensitive information. · Methods to expedite environmental reviews. The Interagency Committee is examining the required consultative processes for permitting repairs in order to determine if actions can be taken that would enable operators to carry out repairs quickly while meeting safety standards. · Potential energy supply impacts of multiple repairs in a regional area. As we have experienced recently in gasoline markets, a small change in pipeline supplies can have a dramatic impact on fuel price. In a situation with multiple pipelines in a regional area in need of repair, OPS would work with operators to prioritize the order of repairs and maintain safety. A time sensitive repair might qualify for expedited permitting because of the potential energy supply impact. Maintaining pipeline capacity and throughput is essential in supplying fuels to regional markets and vital to the Nation’s industries. IV. We are achieving results. Comparing years 1999 to 2003 to the previous five years, from 1994 to 1998, hazardous liquid incidents have decreased by 25 percent. By 2003, the volume of oil spilled had decreased by 15 percent from the previous 10-year average. Excavation accidents have decreased over the past ten years by 59 percent. This is largely the result of work with our state partners and the more than 900 members of a damage prevention organization we initiated – the Common Ground Alliance (CGA). The CGA has formed 22 regional alliances to foster damage prevention activities and will soon announce two additional regional alliances, including a western regional common ground alliance, which is the result of a three-state effort led by the Arizona Corporation Commission. In closing, I want to reassure you, Mr. Chairman, and all of the members of this committee, that Secretary Mineta, RSPA and the hardworking men and women in the Office of Pipeline Safety share your strong commitment to improving safety, reliability, and public confidence in our nation’s pipeline infrastructure. I will be happy to take your questions. ##

Witness Panel 2

• Ms. Lois Epstein
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  Witness Panel 2

  Ms. Lois Epstein

  Good morning. My name is Lois Epstein and I am a licensed engineer and an oil and gas industry specialist with Cook Inlet Keeper in Anchorage, Alaska. Thank you very much, Senator McCain, for holding this oversight hearing on pipeline safety and for your ongoing attention to this issue (even if some of that attention results from an unfortunate pipeline accident which took place in Tucson last July). Cook Inlet Keeper is a nonprofit, membership organization dedicated to protecting Alaska’s Cook Inlet watershed and the life it sustains. My background in pipeline safety includes membership since 1995 on the U.S. Department of Transportation’s (DOT’s) Technical Hazardous Liquid Pipeline Safety Standards Committee which oversees the Office of Pipeline Safety’s (OPS’) oil pipeline activities and rule development, testifying before Congress in 1999 and 2002 on pipeline law reauthorization, and researching and analyzing the performance of Cook Inlet’s pipeline infrastructure by pipeline operator and type. I have worked on safety and environmental issues for 20 years for two private consultants, the U.S. Environmental Protection Agency, Environmental Defense, and Cook Inlet Keeper. My work in Alaska is entirely focused on the Cook Inlet watershed’s oil and gas operations. From this vantage point, I can see how well the policies developed in DC work in the real-world. The Cook Inlet watershed, which includes Anchorage and drains an area approximately the size of Virginia, is where oil and gas first was developed commercially in Alaska, beginning in the late 1950s. Cook Inlet is an extraordinarily scenic and fisheries- and wildlife-rich, region. In this testimony I will discuss: · Implementation of the Pipeline Safety Improvement Act of 2002, including safety, regulatory, and policy progress, and enforcement concerns; · Ongoing pipeline safety needs, namely increased public information and modifying the state preemption provision in the law; · The role of OPS in Liquified Natural Gas facility oversight; and, · The DOT reorganization and how that might impact OPS. Implementation of the Pipeline Safety Improvement Act of 2002 The Pipeline Safety Improvement Act of 2002 (the 2002 law) was passed by Congress on November 15, 2002 following several tragic pipeline events, one of which – the June 10, 1999 Bellingham rupture that killed three youths – occurred 5 years ago last week. Since this 1999 event and the August 19, 2000 natural gas pipeline rupture which killed 12 people including 5 children, there has been increased scrutiny of the pipeline industry, its performance, and of deficiencies in federal and state oversight. The 2002 law contains some needed improvements but, like many acts of Congress, it represents a compromise among competing interests. As a result, safety will be improved, but not necessarily by as much or as fast as the public would like. To put my presentation in context, the graph below displays the performance of the industry over time based on reported incidents. As you can see from the top line, reported hazardous liquid pipeline incidents dropped after 1994, two years after Congress imposed mandatory requirements on OPS to prevent releases that impacted the environment (as opposed to releases which solely affected safety). It’s also apparent that there has not been a discernable upward or downward trend in natural gas transmission or distribution incidents in recent years. It is critical for this committee and its House counterparts to hold periodic oversight hearings to see if the law and its resulting regulations are, in fact, having an impact in reducing pipeline accidents. Keeping the time lag for pipeline performance improvements in mind, I now will discuss regulatory progress, regulatory gaps, important enforcement concerns, and Pipeline Safety Information Grants to Communities (Section 9 of the 2002 law). Regulatory Progress: The most important rule issued as a result of the 2002 law, the natural gas transmission pipeline integrity management rule published on December 15, 2003 which went into effect this past January, will not reduce incidents on those lines for several years and it’s unclear how much of a reduction we can expect. This is true for several reasons. First, the law requires baseline integrity assessments to occur within 10 years, with 50% of the assessments occurring within 5 years of the law’s enactment; this long timeframe will delay the benefits. Second, because the rule only applies to an estimated 7% of transmission pipelines, by 2007 (i.e., five years after the law’s enactment) we may expect only a 3.5% reduction in incidents, though the incidents that do occur should take place in areas of lesser consequences. Third, since the rule allows the use of not-fully-proven methodologies (i.e., “direct assessment” and “confirmatory direct assessment”), we need to wait several years to see whether OPS’ approach to this rule will result in a meaningful reduction in incidents. Public interest organizations are particularly concerned about the large portions of pipelines that currently are not covered by the oil and natural gas pipeline integrity rules. For example, it’s unclear whether the existing natural gas integrity management rule covers the location near Carlsbad where the August 2000 pipeline tragedy occurred. Some of the uncovered portions of pipelines eventually might be covered as High Consequence Areas that are culturally or historically significant, a designation that has not yet been developed by OPS but which it committed to develop in meetings with the Technical Hazardous Liquid Pipeline Safety Standards Committee. In summary, this committee needs to pay attention over the next few years as to whether the natural gas integrity management rule makes a noticeable difference in pipeline incidents and their severity. Regulatory Gaps: The 2002 law required OPS to develop integrity management standards for natural gas distribution pipelines as well as for natural gas transmission pipelines, but OPS has not yet proposed an integrity management rulemaking to address distribution lines. This is not the only gap in OPS regulations, however. Also needed are regulations that cover gathering lines and related flowlines (as Congress mandated in 1992 and which OPS has made some progress on, holding public hearings in Austin and Anchorage 11 years later in 2003); specific requirements for shut-off valves for oil and natural gas lines (as Congress mandated in 1992 and 1996); leak detection performance standards for oil transmission pipelines to ensure that leaks of a particular size are rapidly discovered, as is the case for crude oil transmission lines in Alaska; enhanced regulation of low-stress oil lines given their potential for serious environmental impacts; requirements ensuring that operators submit revised accident reports which they are not required to do now (as the DOT Inspector General recommended ); and failsafe requirements to prevent over-pressurization. Enforcement: It’s clear the public is very concerned that OPS has been unable to date to collect significant fines for violations of OPS regulations from the tragedies in Bellingham and Carlsbad. OPS touts the improvements it has required in those pipeline systems as a result of the accidents, however that is like requiring brake upgrades in cars with brakes that failed and caused injuries and deaths. The public has no evidence that the increased penalties contained in Section 8 of the 2002 law are being used by OPS to send a message to pipeline operators that violations are both unacceptable and costly. The U.S. General Accounting Office (GAO) soon will issue a report on OPS’ enforcement record. I urge both GAO and this committee to compare OPS’ enforcement program statistics with those of EPA, i.e., examining the highest penalties issued for similar types of releases including pipeline-related oil pollution fines levied by EPA. To improve its enforcement program, OPS also needs to consider initiating a public comment period on significant pipeline penalties, as EPA does. I look forward to seeing GAO’s updated statistics on the rate of OPS fines – in 1998, GAO found that OPS proposed a fine in only 1 of every 25 enforcement actions (a reduction from 1 in 2 in 1990) , far too low a ratio if the government wants operators to follow regulations at least in part to avoid penalties. Additionally, as I stated in my 2002 testimony, OPS needs to initiate several high-profile, preventive enforcement actions to deter potential violators. Currently, OPS only pursues high-profile enforcement actions following pipeline accidents. Preventive enforcement, in contrast, would require OPS to penalize pipeline companies whose operations might result in serious releases prior to a release occurring. Major civil enforcement actions identifying violations of standards prior to accidents should be publicized and readily available on OPS’ website. Without a preventive approach to enforcement, it’s practically pointless to have preventive requirements in place. Thus, the committee needs to ensure that OPS commits to enforce violations of its regulations, both prior to and following accidents. Pipeline Safety Information Grants: Section 9 of the 2002 law states that: The Secretary of Transportation may make grants for technical assistance to local communities and groups of individuals (not including for-profit entities) relating to the safety of pipeline facilities in local communities…The amount of any grant under this section may not exceed $50,000 for a single grant recipient. The Secretary shall establish appropriate procedures to ensure the proper use of funds provided under this section. (§ 60130(a)(1)) To date, OPS has not established any such procedures, nor has it had any success obtaining appropriated funds for this purpose. As time goes on, there are missed opportunities for use of these funds, e.g., such funds might have helped community organizations understand the technical and regulatory issues associated with the Tucson pipeline accident and/or assisted public interest groups in commenting on ongoing regulations and standards development. Public interest groups request that both Senator McCain and Senator Stevens on the Appropriations Committee help ensure that this section of the 2002 law is carried out as intended. Pipeline Safety Needs Increased Public Information: Pipelines do not require periodic renewals of operating permits so the public has almost no knowledge of the adequacy of pipeline operations following siting approvals. This means the public cannot help regulators identify High Consequence Areas, nor can it weigh in on the integrity measures utilized by particular pipeline operators. OPS and the industry have unreasonably resisted providing more information to the public on pipeline operations even though the types of additional information requested – such as the primary threats to pipelines, the integrity assessment tools utilized, the leak detection strategies used – would have no security-related value. As stated in the preamble to the natural gas transmission pipeline integrity management rulemaking: RSPA/OPS does not consider it appropriate to collect additional information relevant to integrity management for public dissemination. RSPA/OPS will implement an inspection program to evaluate operator implementation of this rule…Regulators will take enforcement action when appropriate, and records of such enforcement will be available to the public as they are now. (68 Federal Register 69800, December 15, 2003) From this statement, it’s clear that OPS does not appreciate the value of the public participating in integrity management rule implementation and enforcement. The statement implies that the public has nothing to add in terms of technical analyses of trends and patterns and/or on-the-ground knowledge, and that OPS has foolproof inspection and enforcement mechanisms. Given that OPS has been frequently criticized for its poor enforcement record, the latter is a particularly implausible claim. Because public participation and public dissemination of operational data are likely to strengthen pipeline safety (the latter through a powerful, non-regulatory means of demonstrating progress), the committee should encourage OPS to provide more information on pipeline operations to the public. State Preemption: Current pipeline safety law prevents states from regulating and enforcing violations on interstate pipelines even if such regulation would improve safety and/or environmental protection and would not affect interstate commerce. This is an unnecessary intrusion on states’ rights with serious adverse consequences since national regulations might not protect states sufficiently from pipeline hazards, e.g., from earthquakes, difficult cleanup terrain, etc. There are numerous areas of oversight and regulation (e.g., testing requirements, right-of-way management, landslide and earthquake zone provisions, enforcement, defining high consequence areas) where states might want to exceed federal requirements to enhance pipeline safety, and where their actions would not compromise a company’s ability to operate its pipelines smoothly and safely. Interestingly, Sec. 3(a) of the 2002 law also finds the existing state preemption provision too broad. This provision contains a limitation on preemption for enforcement of state “one-call” notification programs. As this example shows, a well-designed provision that limits the preemption language currently in the law could strengthen pipeline safety. OPS and Liquified Natural Gas Oversight The 2002 law contains language dating from 1968 and 1979 that describes OPS’ role in regulating liquified natural gas (LNG) facilities. While much recent attention has been focused on the Federal Energy Regulatory Commission’s role in siting LNG import-regassification facilities, little attention has been paid to OPS’ role in developing, implementing, and enforcing LNG siting, operating, and contingency plan rules. The reason this issue is important to the committee is that the committee is aware of OPS’ currently constrained inspection and enforcement resources. Given these resource constraints and the likelihood that OPS will need to initiate some new LNG-related rulemaking, policy, and enforcement work with the expected expansion of new LNG facilities in the U.S., OPS soon might face severe resource challenges. Without additional OPS resources, safety concerns for LNG and/or pipeline facilities nationwide might result. Potential DOT Reorganization On December 8, 2003, DOT Secretary Mineta proposed removing OPS from the Research and Special Programs Administration and combining it with the Federal Railroad Administration to form the Federal Railroad and Pipeline Administration. At least partly in response to this proposal, Congressman Young introduced H.R. 4277, a bill that would establish the Pipeline Safety Administration at DOT. In general, public interest organizations believe that pipeline safety should be elevated within DOT, so we are supportive of Congressman Young’s bill. Pipelines have enormous impacts both locally and nationwide and for too long have been relegated to a small, obscure office at DOT. Summary In conclusion, the committee should pursue the following items further in its oversight work: · Periodically review the annual natural gas transmission line incident rate to see whether the integrity management rule is making a noticeable difference in the rate of incidents and incident severity; · Ensure that OPS continues to fill regulatory gaps; · Ensure that OPS diligently enforces violations of its regulations, both prior to and following accidents; · Ensure that OPS distributes Pipeline Safety Information Grants; · Strongly encourage OPS to provide information on pipeline operations with no security-related value to the public; · Research how best to amend the preemption provision of the pipeline safety law so it provides needed flexibility to states that wish to strengthen pipeline safety without impacting interstate commerce; · Ensure that OPS’ increased LNG responsibilities do not comprise safety at LNG or pipeline facilities; and, · Consider passage of a bill similar to H.R. 4277 to create a Pipeline Safety Administration at DOT. Thank you very much for your interest in this important topic. Feel free to contact me at any time with your questions or comments.

• Mr. Robert T. Howard
  Read statement

  Witness Panel 2

  Mr. Robert T. Howard

  Mr. Chairman and Members of the Committee: Good morning. My name is Bob Howard and I am Vice President and General Manager of Pipeline Operations for Gas Transmission Northwest Corporation (GTN). I am testifying today on behalf of the Interstate Natural Gas Association of America (INGAA). INGAA represents the interstate and interprovencial natural gas pipeline industry in North America. INGAA’s members transport over 90 percent of the natural gas consumed in the U.S., through an 180,000-mile pipeline network. Gas Transmission Northwest is an interstate natural gas pipeline headquartered in Portland, Oregon. With 1,350 miles of transmission pipeline in three states, GTN delivers about 2.9 billion cubic feet of natural gas per day, supplying almost a third of the West Coast’s total natural gas needs every day. The North American pipeline network provides the indispensable link between natural gas supply and the local distribution companies that serve retail customers. Natural gas represents 25 percent of the primary energy consumed annually in the United States, a contribution second only to petroleum and exceeding that of coal. Consequently, the natural gas pipeline delivery network is a critical part of the nation’s infrastructure. This is why the safe and reliable operation of these pipeline systems is so important. Because the natural gas pipeline network is essentially a “just-in-time” delivery system, with limited storage capability, customers large and small depend on reliable around-the-clock service. And of course, the public wants to know that these pipeline systems crisscrossing the nation and serving their communities are safe. Mr. Chairman, these pipeline systems are safe – the safest mode of transportation in the country – and working together the pipeline industry and the Office of Pipeline Safety are making this valuable network even more safe and secure. Progress at the Office of Pipeline Safety Since this Committee last debated the issue of pipeline safety, several years ago, a great deal of progress has been made at the Department of Transportation’s Office of Pipeline Safety (OPS). As recently as five years ago, many in Congress and in the public at large were saying that the OPS was an agency of sub-standard performance. The General Accounting Office cited the backlog of unfinished, congressionally mandated rulemakings, the numerous DOT Inspector General recommendations that had not been implemented, and the poor acceptance rate for National Transportation Safety Board (NTSB) recommendations. For years, the OPS had the lowest acceptance rate of any modal office at DOT for NTSB safety recommendations, at about 69 percent. Take a look at what has happened since that time. The OPS now has the second-highest acceptance rate for NTSB safety recommendations, right behind the Highway Safety Administration, at 86 percent. The backlog of unfinished, congressionally mandated rulemakings is virtually gone, and by any measure, OPS has made great strides in improving its effectiveness. Perhaps the most important accomplishment by the OPS since the passage of the Pipeline Safety Improvement Act of 2002 is the completion of the natural gas pipeline integrity management rule. This rule, required by the 2002 Act, took the better part of 2003 to develop before its final issuance in December. When the Notice of Proposed Rulemaking was released to the public in early 2003, the INGAA membership had a great deal of concern about its focus, its effectiveness, and workability. However, the OPS took our concerns about the proposed rule seriously, and worked with our industry in developing a final rule that remains true to the mandate from Congress, and does so in a way that is technically-based, practical and effective. INGAA believes that all of this work on the part of OPS has made the agency a more effective safety regulator. Enforcement has improved. Public education and communications efforts have improved. Audit and inspection activity is more focused and effective. All this should translate into Congress and the public having more faith in the safety and reliability of the natural gas pipeline infrastructure. What the Pipeline Industry is Doing to Implement the New Integrity Rule The pipeline industry has been working hard too. As the nation increases its demand for natural gas, more pipeline capacity is needed to deliver additional supplies to growing markets. Whenever a new pipeline is proposed, or an existing pipeline proposes an expansion, communities and citizen groups raise the issue of safety. These communities and groups often have significant influence in the approval process, and therefore their concerns need to be taken seriously. In order for our industry to meet its objectives for serving a growing natural gas market, we also need to reassure the public that pipelines are a safe mode for energy transportation. Recent accident statistics are worth examination. For the years 2002 and 2003, there were no fatalities or injuries associated with accidents on interstate natural gas pipelines located in “high consequence areas,” or the areas with higher population near a pipeline. There were four accidents during this period that resulted in injuries to one pipeline employee and three pipeline contractors, but these occurred on natural gas pipeline segments located in rural areas; i.e., not high consequence areas. Three accidents did occur on interstate natural gas pipelines in high consequence areas during 2002 and 2003, but these did not result in either a fatality or an injury, and were therefore only reported to OPS because the damage costs (including the cost of natural gas lost) exceeded $50,000. The new natural gas pipeline integrity rule has been a significant area of focus for the industry. Let me assure the Committee that we are not resting on our existing safety record. Over a dozen consensus standards have been completed, or are near completion, to support this rule, and have been supported by multimillion dollar collaborative research programs. The Pipeline Safety Improvement Act requires each natural gas pipeline operator to conduct a risk analysis and develop an integrity management plan for pipeline in high consequence areas by December 17th of this year. However, the law also required operators to begin integrity assessments on their pipelines by June 17th – two days from now. The “highest priority” fifty percent of an operator’s high consequence areas (based on the risk analysis) must complete a baseline integrity assessment within five years of enactment (December 17th, 2007), with the remaining fifty percent to be completed within ten years of enactment (December 17th, 2012). This integrity assessment work is already well underway. INGAA has surveyed its membership to measure the amount of inspection activity taking place. One respondent’s answers are illustrative of the larger group. This pipeline has about 5900 miles of transmission pipeline, of which about 200 miles is located in high consequence areas (HCAs). To date, about ten miles of these HCAs have completed a baseline assessment, but as a function of inspecting these ten miles of HCAs, the operator has had to also inspect 250 miles of non-HCA pipe. The reason for these assessments going beyond the HCA requirement is simple. The vast majority of our pipelines are going to be inspected with internal inspection devices, commonly referred to as “smart pigs.” Special launcher and receiver facilities have to be constructed to both introduce a smart pig into a pipeline, and remove it at some point downstream. The most practical place (and often, the only place) to construct these launcher/receiver facilities are at compressor stations, which are typically located about 75 to 100 miles apart along a pipeline. The pipeline segment between compressor stations may have a few, discrete miles of HCAs, but in order to inspect the five or six miles of HCA pipe, the entire 75 to 100 mile segment between the stations will be inspected by the smart pig. INGAA estimates that about 6 percent of total natural gas transmission pipeline mileage is actually located in HCAs, but in order to assess the integrity of this 6 percent of pipeline mileage, about 60 to 70 percent of total interstate pipeline mileage will have to be inspected. Mr. Chairman, I would like to provide the Committee with another example to illustrate my point. One INGAA member company is in the process of modifying a 58-mile section of pipeline so that internal inspection devices can be employed for integrity assessments. Since this pipeline was originally constructed in the mid-1950s, before the advent of smart pigs, it was not engineered to accommodate these devices. The pipeline operator has already identified 14 HCAs along this 58-mile segment, for a total HCA length of 8.74 miles. In order to assess the HCA portions of the pipe, pig launchers and receivers must be installed, and several valves will need to be replaced. The estimated modification costs for this one segment are $5.1 million, and the estimated integrity assessment and repair costs are $640,000. The work on this pipeline segment started last month, and is expected to last five months. During this five-month period, some part of the pipeline segment will either be completely shut down, or operating at reduced pressure. At Gas Transmission Northwest, we are well underway with the installation of internal inspection infrastructure and our baseline assessments. We recently ran a “smart pig” through a section of our system and are in the process of examining the results. I am proud of the work we have done so far and we are committed to fulfilling and surpassing the rule requirements. One Important Concern The scope of the integrity assessment work to be done over the next eight years gives the INGAA membership some pause for concern. This is due to the fact that a significant number of pipeline segments will have to be removed from service in order to prepare for and perform assessments and any resulting repairs. This unprecedented integrity program will almost certainly affect natural gas deliverability and delivered natural gas commodity prices. The effect could be compounded because, coincidentally, the integrity assessments are happening during what will likely be a protracted period of tight natural gas supplies. In past years, pipelines were able to perform most maintenance and repair activities during the warm months of the year, when natural gas demand was relatively low. During these periods of low seasonal demand, the natural gas pipeline network could more readily handle system downtime. Few, if any, customers were impacted in terms of service disruptions or higher natural gas commodity prices. In today’s natural gas market, however, demand not only peaks during the cold winter months, but also during hot summer months, due to the increased use of natural gas to generate electricity. This means that there are fewer weeks of the year when maintenance and repair can take place without impacting customers in some manner. In 2002, the INGAA Foundation prepared an economic analysis of these pipeline capacity reductions, and their effects on consumer prices. The report looked at anticipated pipeline inspection scenarios under an integrity management program, based in large part on how long the industry would be given to perform a baseline assessment. For a ten-year baseline period (i.e., the one ultimately adopted by Congress), the report estimated increased consumer natural gas prices of about $1 billion per year for the first ten years. Please note that these costs are not associated with the actual cost of inspections and repair activities, even though these costs will also be significant. Rather, the study looked only at the “costs to consumers due to deliverability constraints” and their effect on the natural gas commodity markets downstream. One way these unintentional price spikes can be minimized is by allowing for the coordination of inspection and repair activities among various competing pipeline operators. Anti-trust law currently restricts such coordination. In the absence of such coordination, however, it is possible and even likely that multiple pipelines serving a given market could be down for inspection/repair at the same time, causing significant price increases and even service disruptions for that market. INGAA urges Congress to consider an anti-trust waiver for coordination of pipeline integrity assessment and repair activities. We also want to join with others in urging the various federal and state agencies involved in permitting pipeline inspection and repair activities to do so on a coordinated and expedited basis. We anticipate that our industry will be required to make significant modifications to our pipeline facilities over the next eight years, in order to accommodate internal inspection devices. The construction of smart pig launchers and receivers, for example, as well as replacing pipeline bends, segments and valves that cannot accept internal inspection devices may require permits from federal and state authorities. The interstate natural gas pipeline members of INGAA are regulated economically by the Federal Energy Regulatory Commission (FERC). The FERC must approve the construction of any new interstate natural gas pipeline, or any major expansion or modification (in excess of a certain dollar amount) of an existing interstate natural gas pipeline. The FERC has also accepted the primary role for the enforcement of the National Environmental Policy Act (NEPA) as it relates to pipeline construction and the resulting effects on the environment. In 2002, the FERC lead an effort to create and sign a Memorandum of Understanding (MOU) between all of the federal agencies associated with any permitting activities for pipelines, such as the Corp of Engineers, the Environmental Protection Agency, and the U.S. Fish and Wildlife Service. This MOU commits the signatory agencies to concurrent review of a pipeline construction application, such that agencies can work together rather than at cross-purposes, thus saving time and effort. We are hopeful that this MOU can also be applied to integrity management-related activities. It should be noted, however, that this MOU does not include participation by state agencies. These state agencies are often the most intransigent in terms of approving permits on a timely basis. Once again, a signal from Congress as to the importance of approving these permits in a timely manner will be critical to the success of the Pipeline Safety Improvement Act of 2002. The Proposed Merger of the OPS and the Federal Railroad Administration Before concluding, INGAA would like to provide some comments to the Committee on the proposed merger of the Office of Pipeline Safety and the Federal Railroad Administration (FRA). The Secretary of Transportation announced his intent to move forward with this idea as part of an overall vision to gather the various research functions at DOT and place them under one authority. OPS is currently a part of the Research and Special Programs Administration (RSPA), which the Secretary envisions would be restructured in order to accept all transportation research-related activities from the various modal administrations. Since OPS is a regulatory body, it would not fit within the new RSPA, and thus the proposal to move it to FRA. INGAA does not have a quarrel with the Secretary regarding his vision for transportation research. Our concern is that the OPS would lose its focus and effectiveness if it were to be subsumed into the much larger FRA. As you have already heard, OPS has made great strides in improving its performance over the last five years. Much of that success is related to the fact that it has been able to act quickly and decisively in improving its programs and enforcement activities. It would indeed be a shame if, after having worked so hard to gain back its credibility, OPS were to lose it once again by getting lost in a large and unfamiliar bureaucracy. Rather than merging with the FRA, INGAA supports the creation of a new Pipeline Safety Administration at DOT. House Transportation and Infrastructure Chairman Don Young introduced legislation (H.R. 4277) last month to create a separate pipeline safety entity at DOT, and we strongly support his efforts. We hope that a Senate companion bill will be introduced soon, and that it will have this Committee’s support. Conclusion Let me thank you once again, Mr. Chairman, for allowing me to testify today. Safety is of paramount importance to our industry, and we believe that it is our obligation to work with Congress and the OPS to maintain and improve the safe, reliable operation of our pipelines in the years ahead. I would be happy to answer any questions you or the Committee members might have.

• Mr. Barry Pearl
  Read statement

  Witness Panel 2

  Mr. Barry Pearl

  I am Barry Pearl, President and CEO of TEPPCO Partners, LP and Chairman of the Association of Oil Pipe Lines (AOPL). I am here to speak on behalf of AOPL and the pipeline members of the American Petroleum Institute (API). I appreciate this opportunity to appear before the Committee today on behalf of the AOPL and API. AOPL is an unincorporated trade association representing 50 interstate common carrier oil pipeline companies. AOPL members carry nearly 85% of the crude oil and refined petroleum products moved by pipeline in the United States. API represents over 400 companies involved in all aspects of the oil and natural gas industry, including exploration, production, transportation, refining and marketing. Together, these two organizations represent the vast majority of the U.S. pipeline transporters of petroleum products. TEPPCO Partners, L.P. is a publicly traded master limited partnership, listed on the New York Stock exchange under the symbol TPP. TEPPCO owns and operates more than 11,600 miles of pipeline in over 16 states. Our operations include one of the largest common carrier pipelines of refined petroleum products and liquefied petroleum gases in the United States; petrochemical and natural gas liquid pipelines; crude oil transportation, storage, gathering and marketing activities; and natural gas gathering systems. TEPPCO also owns 50% interests in Seaway Crude Pipeline Company, Centennial Pipeline LLC, and Mont Belvieu Storage Partners, L.P., and an undivided ownership interest in the Basin Pipeline. Texas Eastern Products Pipeline Company, LLC, an indirect wholly owned subsidiary of Duke Energy Field Services, LLC, is the general partner of TEPPCO Partners, L.P. Summary It has been a year and a half since the enactment of the Pipeline Safety Improvement Act of 2002 (Public Law 107-355, the “PSIA”). On behalf of the members of AOPL and API, I wish to thank the Members of this Committee for their leadership in passing that comprehensive and very important legislation. As the Committee reviews the current state of pipeline safety and the progress that has been made since the PSIA became effective, there are a few points that we would like to emphasize. · First, there is a growing recognition of the importance of the oil pipeline infrastructure to the American economy and the interrelations between pipeline safety, pipeline economic regulation and the essential energy supplies delivered through that infrastructure. · Second, there has been tremendous progress in pipeline safety because of the PSIA, but there has also been much progress because of actions undertaken by the industry and by the Office of Pipeline Safety, even before the PSIA was signed into law. · Third, while many of the initiatives of the PSIA are being implemented in a satisfactory manner and on schedule, this is not universally the case, and I will cite an important example at the intersection between pipeline safety and fuel supply where the Committee’s help is needed. · Finally, a warning. We strongly believe that much of the progress that has been made in elevating the importance of pipeline safety and empowering the federal role in ensuring the operation of an effective pipeline infrastructure is threatened by a reorganization plan that we understand is pending that would uproot the pipeline safety program and move it to the Federal Railroad Administration. The Role of Pipelines in Petroleum Supply About one-half of total U.S. energy supply comes from petroleum, with 95% of the energy that powers transportation derived from petroleum. Very few of the elements of the Nation’s transportation system – the core of this Committee’s jurisdiction – could operate without petroleum. Fully two-thirds of the ton-miles of domestic petroleum transportation are provided by pipeline. The total amount delivered by both crude oil and refined petroleum products pipelines is nearly twice the number of barrels of petroleum (14 billion) consumed annually in the United States. The major alternatives to pipelines for delivery of petroleum are tank ship and barge, which require that the user be located adjacent to navigable water, and truck or rail, which are limited in very practical ways in the volume they can transport. In fact, pipelines are the only reasonable way to supply large quantities of petroleum to most of the nation’s consuming regions. Pipelines do so efficiently and cost-effectively – typically at 2-3 cents per gallon for the pipeline transportation cost charged to deliver petroleum to any part of the United States. Oil pipelines are common carriers whose rates are controlled by the Federal Energy Regulatory Commission. Pipelines only provide transportation. Pipelines only provide transportation, and our owners do not own or profit from the sale of the fuels they transport. Oil pipeline rates are not related to the price of the products that are transported. Oil pipelines move 17% of interstate ton-miles but only receive 2% of the total amount charged for interstate freight transportation, a bargain that American consumers have enjoyed for decades. The oil pipeline infrastructure is crucial to American energy supply. The care and stewardship of this critical national asset is an appropriate public policy concern and an important joint responsibility of the industry I represent, the Department of Transportation and Congress through this Committee. I’ve included a report by Richard A. Rabinow entitled “The Liquid Pipeline Industry in the U.S. - Where It's Been and Where It's Going” prepared for AOPL that provides an overview of trends in the oil pipeline industry. Progress Report on Pipeline Safety: Integrity Management Companies represented by AOPL and API operate 85 percent of the nation’s oil pipeline infrastructure. Since March 2001, these operators have been subject to a mandatory federal pipeline safety integrity management rule (Title 49, section 95.452) administered by the Department of Transportation’s Office of Pipeline Safety. The oil pipeline industry’s experience with pipeline integrity management preceded the enactment of the Pipeline Safety Improvement Act of 2002. Our operators will complete the required 50 percent of their baseline testing of the highest risk segments prior to the September 30, 2004 midpoint deadline set by the integrity management regulations. OPS has inspected the performance of each of these operators under these regulations at least twice – an initial “quick hit” inspection and a subsequent full inspection – and is proceeding with the second round of full integrity inspections. We have experience with the program that will be instructive to the Committee in its review. The oil pipeline integrity management program is generating safety benefits that significantly exceed anything anticipated when the program was designed. To see how this is occurring, it is helpful to have a general understanding of how the integrity management program operates. The integrity management program requires integrity assessment, that is, regular safety testing with an internal inspection device (a “ smart pig”), hydrostatic pressure or other equivalent means, and enhanced protections for those segments of pipe that “could affect” a “high consequence area”. A “high consequence area” (HCA) is a defined term in the regulations that means a commercially navigable waterway, a high population area or an area unusually sensitive to environmental damage. Such unusually sensitive areas are also defined in the regulations. Each operator must have a process to determine whether a segment of pipe “could affect” an HCA. The process must consider a range of factors, such as the terrain, the volume and type of oil in the pipe and the physical ways oil released from the segment of pipe might impact the HCA. In 2000, OPS estimated that under the proposed integrity management system approximately 22 percent of the pipeline segments in the national oil pipeline network would affect an HCA and therefore that operators in aggregate would be required to assess and provide enhanced protection for 22 percent of the national system. In fact, when oil pipeline operators carried out their analyses of how many of their segments could affect the high consequence areas that were actually identified under the regulations, it turned out that almost twice as many segments, 43 percent of the pipeline network nationally, could affect an HCA. So the anticipated benefits in theory were nearly twice as large as originally estimated. But in fact, our experience indicates that the actual benefits realized will be significantly larger than that. The predominant method of testing oil pipelines utilizes internal inspection devices. The ports at which these devices are inserted into and removed from a pipeline are fixed in the system. These locations were established prior to the advent of integrity management regulations and without regard for the location of HCAs. The internal inspection devices therefore travel between ports, generating information about all the segments between those ports, whether they affect an HCA or not. As a result, as shown in OPS inspections of operators’ plans, it is estimated that integrity testing will cover approximately 82 percent of the nations’ oil pipeline infrastructure. Thus the actual mileage tested is almost four times the original OPS estimate. Operators are finding and repairing many conditions in need of repair and many less serious conditions that are found near defects. For every condition repaired under the rule, approximately six other conditions are excavated and evaluated. Operators are fixing what they find, often going beyond the requirements of the law. The largest cost to the operator is in the scheduling and renting of the internal inspection device, obtaining the permits and carrying out the excavation, so once the pipeline is uncovered, operators fix many conditions that might never have failed in the lifetime of the pipeline. This result is a huge additional benefit to pipeline safety that will reduce the risk of pipelines to the public far into the future. Although benefits from the integrity management rule are much greater than originally estimated, so is the cost. Costs per operator are often running at a rate of tens of millions of dollars per year, far more than originally anticipated and a substantial amount by any standard. Operators have nevertheless moved aggressively to provide the resources needed to implement integrity management. Integrity Management Conclusions What are the lessons of this experience? OPS’s integrity management program, which relies on the initiative, judgment and priorities of individual pipeline operators, is producing major benefits for the public and the environment without prescriptive regulation. The program is a mandatory one, so operators must participate, must carry out regular testing of their pipelines and must act promptly to address risks. But the operator has flexibility under the program in designing and administering the plan for testing and repair subject only to periodic inspection reviews by OPS. This partnership is proving enormously successful without resort to prescriptive, detailed regulations, intrusive second-guessing of operator decisions or aggressive enforcement with fines and penalties. It is important to note that operators have been incurring the costs required to find the conditions that need repair, to make the repairs and to protect the lines for the future without specific assurance that these costs will be covered in the rates allowed by the Federal Energy Regulatory Commission. The integrity management program has been successful without resort to the threat of punishment or the need for financial incentives because the program aligns the interests of the operator and the regulator – to adopt the most effective and efficient preventative measures to keep the oil in the pipe. The recent spill and accident record of the pipeline industry (see charts) only underlines this success. Put simply, our industry’s substantial investment in pipeline integrity and leak prevention is a sound one, providing long-term benefits to both pipeline operators and the public. Pipeline Safety: The Pipeline Safety Improvement Act of 2002 and More In the Pipeline Safety Improvement Act of 2002 Congress endorsed the integrity management approach to pipeline safety that OPS had been administering with the oil pipeline industry at the time of enactment and extended the integrity management concept to natural gas transmission pipelines. In addition, the PSIA contains important provisions: · Coordinating permitting by federal agencies so that pipeline repairs can be carried out in a timely manner · Strengthening the qualifications of pipeline personnel and contractors; · Ensuring that pipeline operators are active in promoting public awareness of pipelines along pipeline rights of way · Increasing OPS outreach to states and state regulators to assist with OPS activities · Authorizing a promising research and development program to develop better pipeline safety technology · Establishing a nationwide, toll-free three-digit telephone number to connect excavators to their local call-before-you-dig, one-call notification center · Supporting a study of pipeline right of way encroachment issues through the Transportation Research Board of the National Academies of Science and Engineering · Authorizing adequate funding for the operation of the Office of Pipeline Safety In our view, the OPS has been very aggressive in seeking to implement these PSIA provisions and, with one exception that I will mention below, the progress achieved has been excellent. In addition, OPS has been responding to and satisfactorily addressing Congressional mandates from the time before the PSIA and outstanding National Transportation Safety Board, General Accounting Office and DOT Inspector General safety recommendations. Here the progress has been truly impressive. We anticipate that by the end of 2004 nearly all outstanding mandates and recommendations to the agency will have been appropriately addressed. Finally, OPS has been playing a very important role in assisting the pipeline industry and the Department of Homeland Security in developing a security program to protect critical pipeline infrastructure. Pipeline Repair Permit Streamlining An important initiative of the PSIA that needs the Committee’s encouragement is the implementation of section 16, “Coordination of Environmental Reviews”, which is concerned with expediting the repair of pipeline defects. Some limited progress has been made on implementing this section, but the largest portion of the work remains to be done, and the deadlines for agency action under the provision have passed. Under section 16, a federal Interagency Committee on Coordination of Environmental Reviews for Pipeline Repair Projects has completed a Memorandum of Understanding that lays the foundation for a federal pipeline repair permit streamlining process, but this MOU does not actually contain the provisions needed to effectuate the streamlining. Rather, it establishes a Working Group of federal agency personnel to develop a joint regulatory approach to streamlining (which may rely on existing regulations of the participating agencies or may recommend changes to certain regulations). A successful federal streamlining process will help with federal permitting and also provide a model for state and local permitting agencies to follow. However, to our understanding the draft MOU of March 4, 2004 has not yet been signed by all the participating agencies and so is not effective. Nevertheless, the Working Group has held several meetings since the draft MOU became available, although to date the pipeline industry permitting experts have not been allowed to brief the Working Group or review its plans to see if any of the Working Group’s proposals will actually facilitate pipeline repair permit streamlining. A central theme of the PSIA is safety through prevention. The purpose of section 16 is to accelerate actions that prevent pipeline releases. OPS requires pipeline operators to investigate the condition of their pipelines on a regular basis and act within a time certain to repair any defects discovered that are judged to require repair. The more severe the defect, the shorter the timeframe required to make the repair. Pipeline repair will typically involve an excavation to uncover the buried pipe at the location of the defect on the pipeline right of way, and any such excavation in general requires a series of permits, some federal, some local, and most designed to protect the environment. The purpose of section 16 is to ensure that federal agencies involved in permitting for such excavations coordinate so that pipeline operators are allowed to make the repairs that are needed in the timeframes required by the regulations. The coordination envisioned would not affect existing environmental law, but might require some adjustments to the existing regulations of some of the environmental permitting agencies. The goal of section 16 is to see that the priority on pipeline safety set by this Committee and, through this Committee, by the Congress as a whole is implemented and is not frustrated because, although defects are discovered in a timely fashion to prevent releases, the permitting delays block carrying out the repairs needed to effectuate this prevention. The purpose of section 16 is to ensure timely actions required by one federal agency, OPS, in the name of pipeline safety are not blocked by one or more other federal agencies that do not have pipeline safety as a priority. Pipeline repair permitting delays can also have an impact on energy supply. When a pipeline defect cannot be repaired within the time limits set by OPS, the pipeline operator must reduce pipeline pressure, and therefore throughput, by an amount that depends on the suspected seriousness of the defect – a greater reduction for defects that are more likely to be severe, but the reduction is typically at least 20%. Many operators reduce pressure on discovery of a potential defect. Once the repair is complete the operator is allowed to return to normal throughput capacity. The Number of Pipeline Excavations is Large Now and Will be Much Larger in the Future Under OPS rules for oil pipeline operators, tens of thousands of potential defects are being discovered and repaired annually. As of December 31, 2003, the largest 47 oil pipeline operators have undergone inspection by OPS covering 97% of the mileage operated by these companies. These are the operators who eventually plan to include approximately 82% of their mileage in the mandatory testing program, even though strict requirements of the regulation would only require 43% of their mileage to be tested. According to OPS data as of the date of their respective first full inspections, these operators had carried out 4,344 time-sensitive repairs and 16,081 other repairs. Time sensitive repairs are those judged potentially serious enough that OPS regulations stipulate a repair deadline. These numbers underestimate the total volume of repairs prior to December 31, 2003 because they only include the repairs completed prior to each operator’s particular inspection date, all of which occurred before December 31, 2003. Completion of over 4,000 time-sensitive repairs is a success story of sorts, but it is not without some impact on the capacity of the Nation’s petroleum delivery system. Many of those repairs required pipeline pressure reductions until the repairs were completed. When a pipeline system operates at lowered pressure, its capacity is often reduced, increasing the likelihood of supply shortages, which generally puts upward pressure on petroleum prices. We do not know the extent to which the Nation’s current oil pipeline capacity has been reduced because of pressure reductions occasioned by repairs. There is also no assurance that the required federal, state and local permits for pipeline repair activity can be obtained in a timely way even when federal regulations set a clear deadline for completion of the repair. In the absence of full implementation of section 16 there is currently no organized process to streamline the pipeline repair permitting process to ensure that all involved are doing what they can to see that the Nation’s fuel supply system is not limited by capacity restrictions. It seems to us that it would be prudent to put such a process in place, as the PSIA wisely requires. We have been asked to forecast the magnitude of the permitting problems the pipeline industry will face in complying with OPS pipeline integrity management rules. We will try to respond. The oil pipeline integrity management regulations have been in effect since 2001, so our industry has some experience that can be used to try to answer this question. One thing is clear: the “where” and “when” associated with complex permitting problems is inherently uncertain. It depends on where the apparent defects show up in testing, and that cannot be known in advance. While the industry has much experience with pipeline repairs that predates the pipeline integrity regulations, the sheer number of tests and repairs being executed and the existence of mandatory federal time deadlines for completing particular repairs are unprecedented in the industry. We are learning as we go along. An anecdote: a pipeline operator recently completed an internal inspection of a segment of pipe that produced approximately 100 potential repairs that under OPS rules appear to require completion in 180 days. The operator estimates that more than half of the required excavations for repair can be carried out routinely and another 40 can be carried out with the use of an Army Corps of Engineers Nationwide Permit. However, there are 3-5 excavations needed in locations that that will be difficult to permit in a timely manner, which may result in the operator being unable to complete the repairs within the required regulatory deadline. So a large number of repairs will be made without special permitting concerns and a significant number of additional repairs can probably be made because of a pre-existing federal permit-streamlining program. However, this entire pipeline segment may nevertheless be required to operate under reduced because of a few situations for which there is no process in place to ensure the operator can obtain the necessary federal permits that will allow them to meet the federal repair deadline. The burden on federal, state and local permitting agencies will increase as the OPS program of integrity management for natural gas transmission pipelines takes hold and as state integrity management programs for intrastate pipelines that mimic the federal program are implemented. Attached to my testimony are a number of recent examples that illustrate the very practical difficulties that arise for operators seeking in approval of the various repair site access permits required by federal, state and local agencies that have not been encouraged and are not organized to accord the same priority to pipeline safety that this Committee and OPS expects. Recommendations on Pipeline Repair Permit Streamlining The pipeline industry has several recommendations that we believe would foster progress towards effective pipeline repair permit streamlining: · Agree to allow representatives of the pipeline industry who are experts in pipeline repair permitting to meet with the Working Group to serve as a resource in providing information about what is likely to be useful in expediting pipeline repairs. · Work with industry to develop a set of pre-approved pipeline repair site access, use and restoration Best Management Practices such that a commitment by an operator to adhere in good faith to such BMPs would result in expedited permission to access repair sites to carry out the repair from any of the signatory agencies either through use of that agency’s emergency procedures or another approach that allows the repair to be completed within the timeframes specified by DOT regulation. · Commitment to use pre approved BMPs should result in a presumption of compliance by the operator with the requirements of the BMPs and a presumption that actions beyond restoration to pre-construction condition will not be required if BMPs are followed. · BMPs should be habitat-specific rather than species-specific so that multiple species protection can be obtained within a single umbrella BMP. · Coordinate multi-agency response to requests for permits such that involved agencies operate in parallel or in concert to issue all required permissions (not just that of certain agencies) to the operator in a timely fashion to allow the repair to be completed within the timeframes specified by DOT regulation. To the extent possible the permitting process should be consolidated to limit to one the number of permits required (a consolidated permit). A process is needed to ensure that federal agencies are aware of the relationships in permitting pipeline repairs among federal, state and local requirements and can act accordingly to achieve the goal of section 16. · With respect to compliance with the Endangered Species Act, establish an agreement between the Department of Transportation and the Department of the Interior under which DOT will voluntarily assume the role of default coordinator, or a “nexus” by any other name, for pipeline repairs in those cases where no other federal agency is available or able to act as the federal nexus for ESA consultation. This agreement would stipulate that DOT’s voluntary participation in a coordination role for pipeline repairs does not mean that ordering or providing for pipeline repairs through regulation is a federal action subject to the ESA or the National Environmental Policy Act. The federal government and the pipeline industry should be natural partners in seeing that the OPS integrity management program succeeds. The pipeline safety goals of the industry and the government are entirely aligned in this program. Done properly, pipeline repair permit streamlining will help significantly to ensure the success of this program, while reducing the burden on federal, state and local permitting agencies and allowing these agencies to focus resources on much more serious environmental problems. Done properly, pipeline repair permit streamlining will ensure the safety and reliability of the nation’s pipeline infrastructure. Done properly, pipeline repair permit streamlining will reduce the risk of higher fuel prices to the Nation’s consumers. The oil pipeline industry stands ready to work with the Interagency Committee and the Working Group to provide the information and any other assistance needed to carry out the intent of section 16 of the PSIA. Proposed Transfer of OPS to the Federal Railroad Administration Let me now turn to a troublesome subject. In December 2003 we were informed that Secretary of Transportation Norman Y. Mineta intended to propose a reorganization of the Department of Transportation as a part of the FY 2005 budget. As part of this proposal, the Research and Special Programs Administration, which houses the Office of Pipeline Safety, would be abolished and reinvented as the Research and Technology Innovation Administration, an entity built around the Department’s Volpe Research center and devoted to transportation research and development. As a consequence, the Office of Pipeline Safety (and other “special programs” in the former RSPA) would be left without a home in the Department. The Secretary’s proposed solution for the OPS would be to transfer the pipeline safety program to the Federal Railroad Administration, an existing DOT administration governing a mode judged to be most similar to pipelines. The oil pipeline industry and the members of AOPL and API have great appreciation for Secretary Mineta and all he has done to improve the programs of the Department of Transportation, including the pipeline safety program. However, our members’ reaction to the proposal to sever the pipeline safety program from its existing location and place it under the Federal Railroad Administration was uniformly negative. There has been a sea change in pipeline safety in the last several years, and the federal pipeline safety program has gained impressive and much-needed momentum. The quality and credibility of the program administered by the Office of Pipeline Safety has been immeasurably strengthened, and this strengthening is both recognized and augmented by Congress’ unanimous enactment of the PSIA. OPS’s successes have been accomplished through the hard work and creativity of its employees and particularly because of its very effective leadership during this period. We feel very strongly that this progress must continue. We have come a long way in pipeline safety, but we still have much further to go. We believe the Secretary’s proposal, if implemented, would inevitably disrupt the momentum the agency has worked to hard to create in the past several years. The period required to re-establish this momentum can’t be known for sure, but we believe it would be measured in years, not months. This would be much more than a loss for OPS. It would be a loss for Congress, the public and for pipeline safety. There are several reasons for our grave reservations about the Secretary’s proposal. · As indicated above, the proposal is not likely to be neutral in terms of performance. Pipeline operator experience with mergers in the private sector teaches that merged activities are very susceptible to a loss in momentum, particularly for the lesser of the merger partners, and often for both. The pipeline safety program has made very considerable progress in gathering strength and credibility in the last five years and is currently heavily engaged in the implementation of PSIA initiatives. Loss of this momentum through a transfer to a subordinate position in a substantially different program such as that of FRA would be a very serious concern for the pipeline industry. · The proposal is not likely to be neutral in terms of flexibility and responsiveness. The Office of Pipeline Safety, operating within RSPA, has been very creative in finding solutions to problems. OPS has established a successful and very well-regarded pipeline safety research and development program that has attracted substantial private sector interest while requiring peer review and at least 50% private matching funds. OPS has been an active partner in creating the Common Ground Alliance, a non-profit organization focusing resources on preventing damage to pipelines and other underground facilities. OPS is leveraging the work of the National Association of State Fire Marshals to improve the understanding of pipeline issues in local fire departments and to provide more informed public participants in pipeline safety at the local level. OPS has been successfully addressing pipeline safety concerns of the National Transportation Safety Board, effectively closing almost every recommendation of the Board. OPS has continually worked to improve its relationship with the states that have active intrastate programs and states that don't. We believe it is critical to the credibility of OPS that these initiatives maintain or accelerate momentum under a reorganized DOT. · The proposal does not recognize competition between railroads and pipelines. Liquid pipelines and railroads each transport petroleum. In certain markets there is therefore business competition between railroads and pipelines. All pipelines contest vigorously with railroads over the terms and conditions of railroad right of way crossings. The merged pipeline-railroad entity could influence this competition in favor of one side over the other, most likely to the detriment of the lesser merger partner. · The proposal is not likely to be neutral in terms of budget. Most federal umbrella organizations like RSPA provide generic services to the programs they house. OPS uses generic services provided by RSPA. These include information technology (OPS uses IT heavily); training; regional office support; advisory committees (two); budget development; procurement and contracting; legal and policy support; and state programs. Currently, FRA capabilities and expertise do not match RSPA’s in the services used by OPS. Replicating these services within FRA would increase the cost of the merger by an estimated 5-10%, while likely failing, at least initially, to provide services fully replacing those that had been received from RSPA. · Separation of budgets would be required. OPS is fully funded by the transmission pipeline industry through user fees and the Oil Spill Liability Trust Fund; FRA is taxpayer funded. Equity would require careful separation of budgets in the merged organization so that pipeline operators do not subsidize railroad operations. · The Federal Railroad Administration’s budget is volatile. FRA’s budget includes Amtrak funding at several hundred million dollars ($1,218 million in 2004 enacted, $900 million in 2005 as proposed, with Amtrak recently estimating that $1,800 million is actually required in 2005). Routine fluctuation in FRA’s budget annually significantly exceeds the amount of the entire OPS budget. Within the merged railroad-pipeline entity, there may be significant uncertainty or actual fluctuation in the budget amounts available to the pipeline program relative to the experience in RSPA. HR 4277 We were very pleased to see the introduction by the Chairman of the House Transportation and Infrastructure Committee, Rep. Don Young (R-AK), of H.R. 4277, the Pipeline Safety Administration Establishment Act. This legislation would establish an independent pipeline safety administration with the Department of Transportation with minimal disruption of OPS activities. Our support for the legislation is based first of all on its merits. As I have testified, we believe the federal pipeline safety program has become much stronger and more effective in recent years and the importance of the program and the infrastructure it oversees has received greater recognition than in the past. The federal pipeline safety program deserves greater organizational recognition in the Department that befits its importance to the Nation. We also welcome Chairman Young’s initiative in introducing H.R. 4277 because it provides a significant alternative to the Secretary’s proposal to place the pipeline safety under the Federal Railroad Administration and changes the nature of the conversation about the appropriate organizational structure for the program. The five associations that represent the Nations’ oil and natural gas pipelines recently expressed our views on H.R. 4277 and the Secretary’s proposal in a joint letter to Chairman Young. I have provided a copy of that letter for the Committee’s records. The tests for any new organizational structure for the federal pipeline safety program are whether it strengthens the program, whether it helps make the program more effective and credible and whether it will further the hard work ahead to continue the progress the program has made. We plan to judge any proposal for structuring the pipeline safety program based on these tests. The oil pipeline industry supports competent, effective, and credible federal pipeline safety regulation. The nature of the commodities carried in oil pipelines and the level of public confidence pipeline operators are able to inspire mean some level of oversight is inevitable. Public confidence in the safety of pipelines, and our ability to continue to operate pipelines with the public’s trust depends on the perception and the reality of competent oversight. The interstate character of the business and, indeed, the interstate character of the physical facilities themselves, require that the federal government have the primary responsibility for this oversight. We therefore strongly believe that pipeline safety oversight should be housed in the U.S. Department of Transportation. If the structure governing the pipeline safety program within DOT has to change, we would urge the Committee to very carefully consider the impact of the change on stature of the program and the implications for the highly important service pipelines provide to the Nation. The PSIA set an ambitious but highly appropriate course for the federal pipeline safety program. H.R. 4277 opens the dialogue on the proper organizational structure to complement and facilitate the success of that program. The pipeline members of AOPL and API look forward to working with the Committee as this dialogue moves ahead. Conclusion Thank you for the opportunity to testify before the Committee on these important matters. The Committee’s work product, the PSIA, is in our view a significant success, but all those interested in pipeline safety have much work ahead of us if we are to fully achieve the purposes of this very important legislation. Our industry pledges to seek alignment with the OPS to the maximum extent practicable in this important task. We need help from this Committee to ensure that a key section of the legislation, section 16, relating to pipeline repair permit streamlining, achieves the full intent of Congress and is effective in fostering a safer and more reliable pipeline infrastructure. We also ask that the Committee carefully consider the issue of the proper organizational structure within the Department of Transportation for the federal pipeline safety program, an issue that has been raised by the Secretary in his proposed reorganization of the Department and by the legislation introduced by Chairman Young. Thank you very much.

• Mr. R. Earl Fischer
  Read statement

  Witness Panel 2

  Mr. R. Earl Fischer

  Good morning, Mr. Chairman and members of the Committee. I am pleased to appear before you today and wish to thank the Committee for calling this hearing on the important topic of pipeline safety. My name is Earl Fischer. I am Senior Vice President, Utility Operations of Atmos Energy Corporation. Atmos Energy is one of the largest pure natural gas distributors in the United States, delivering natural gas to about 1.7 million residential, commercial, and industrial and public-authority customers. Our regulated utility services are provided to more than 1,000 small and medium-size communities in 12 states. I am here testifying today on behalf of the American Gas Association (AGA) and the American Public Gas Association (APGA). The American Gas Association represents 192 local energy utility companies that deliver natural gas to more than 53 million homes, businesses and industries throughout the United States. AGA member companies account for roughly 83 percent of all natural gas delivered by the nation's local natural gas distribution companies. AGA is an advocate for local natural gas utility companies and provides a broad range of programs and services for member natural gas pipelines, marketers, gatherers, international gas companies and industry associates. The American Public Gas Association is the national, non-profit association of publicly owned natural gas distribution systems. APGA was formed in 1961, as a non-profit and non-partisan organization, and currently has 606 members in 36 states. Overall, there are 949 municipally owned systems in the U.S. serving nearly five million customers. Publicly owned gas systems are not-for-profit retail distribution entities that are owned by, and accountable to, the citizens they serve. They include municipal gas distribution systems, public utility districts, county districts, and other public agencies that have natural gas distribution facilities. Natural gas meets one-fourth of the United States' energy needs. I am pleased to appear here today and hope that my testimony will provide you with a better understanding of how distribution systems work and how the implementation of the Pipeline Safety Improvement act of 2002 affects us. AGA, APGA and its members commend Congress for ensuring that the safety bill passed in 2002. The legislation that was finally passed in the final days of the 104th Congress was a balanced, fair bill and will bring yet further safety improvements. This Committee and Chairman McCain in particular, had a very significant role seeing that the bill went through and I and the industry thank you for your commitment and leadership. We would also like to commend the U.S. Department of Transportation Office of Pipeline Safety (OPS) for diligently working to address much of the disapproval that arose during the debate on the 2002 bill. OPS was criticized by Congress, the National Transportation Safety Board, DOT’s Inspector General, and members of the public for not addressing numerous congressional mandates and safety recommendations. To their credit, OPS has dealt with the vast majority of this backlog and is moving expeditiously, and often in consultation with all affected stakeholders, to address the mandates in the Pipeline Safety Improvement Act of 2002. Given this tremendous progress, we are concerned over the proposed reorganization of DOT that would include moving OPS into the Federal Railroad Administration. Indeed, we cannot understand the rationale for wanting to make any move that could jeopardize this positive momentum. Gas Distribution Utilities Serve The Customer Gas distribution utilities or Local Distribution Companies (LDCs) are the last, critical link in the natural gas delivery chain. To most customers, utilities are the “face of the industry”. Our customers see our name on their bills, our trucks in the streets and our company sponsor ship of many civic initiatives. We live in the communities we serve and interact daily with our customers. Consequently, we take very seriously the responsibility of continuing to deliver natural gas to our communities safely, reliably and affordably. Natural Gas Utilities Are Committed to Safety Safety is a top priority, a source of pride and a matter of corporate policy for every company. These policies are carried out in specific and unique ways. Each company employs safety professionals, provides on-going employee evaluation and safety training, conducts rigorous system inspections, testing, and maintenance, repair and replacement programs, distributes public safety information, and complies with a wide range of federal and state safety regulations and requirements. Individual company efforts are supplemented by collaborative activities in the safety committees of regional and national trade organizations. Our industry’s commitment to safety is borne out each year through the National Transportation Safety Board’s annual statistics. Delivery of energy by pipeline is consistently the safest mode of energy transportation. Natural gas utilities are dedicated to seeing this continue. Over the last 17 years, the amount of natural gas traveling through distribution pipelines has increased by almost a third and more than 650,000 miles of pipeline have been added to the system – yet the number of reportable incidents on distribution pipelines has decreased by 25 percent. This is a remarkable achievement, one that AGA and APGA attribute to the industry’s overarching commitment to safety. Natural gas distribution pipelines are thoroughly regulated. As part of an agreement with the Federal government, in most states, State pipeline safety authorities have primary responsibility to regulate natural gas utilities as well as intrastate pipeline companies. However, state governments have to adopt as minimum standards the federal safety standards promulgated by the DOT. In exchange, DOT reimburses the State for up to 50% of their pipeline safety enforcement costs. Therefore, what Congress does affects state regulations and our companies. The states may also choose to adopt standards that are more stringent than the federal ones. The Difference in “Pipelines” While many may unintentionally link all “pipelines” together, there are indeed significant differences between the liquid transmission systems, natural gas transmission systems and natural gas distribution systems. Each industry faces different challenges, operating conditions and consequences of incidents. Interstate transmission systems are generally made up of long runs of generally straight pipelines, having large diameter, and operated at high volumes and high pressures. Distribution systems, in contrast, are constructed in configurations that look like a network or web, use smaller diameter pipe, and operate at much lower volumes and pressures. However, many distribution companies also own and operate transmission pipeline segments within their systems. Federal regulations recognize the differences between these three types of pipelines, and different sets of rules have been created for each. 49 CFR Part 192 sets out the regulations for natural gas transmission and distribution and the rules discriminate between the two, while 49 CFR Part 195 sets out the regulations for liquid transmission lines. Status of Implementing the Pipeline Safety Improvement Act of 2002 Since the Pipeline Safety Improvement Act of 2002 was signed into law on December 17, 2002, many programs are under way to specifically address implementation of the law’s mandates and further safety enhancements of gas transmission and distribution systems. For gas transmission systems, most notable among many of the 2002 legislative mandates was integrity management for gas transmission pipelines. The law’s provisions have also resulted in a substantial number of regulatory mandates, initiatives and voluntary programs for distribution systems. Federal Regulatory Mandates The 2002 regulatory mandates affecting distribution systems include: · Direct assessment standards development · Environmental repair permit streamlining · One-call 3-digit number rulemaking · Right-of-way population encroachment study · Operator qualification standard development · Public awareness communication effectiveness rulemaking · Infrastructure R&D grants program Integrity Management Rule for Natural Gas Transmission OPS issued the integrity management rule for natural gas transmission lines on December 12, 2003. The rule requires natural gas transmission pipeline operators to conduct periodic inspections in “high consequence areas”, which for natural gas pipelines are generally high-density population areas. The nature of utility-owned transmission requires that over 50 percent of the lines under the integrity management rule be inspected using direct assessment methods. Direct assessment is an alternative to internal inspection (smart pigging) or pressure testing. It comprises a variety of screening and examination techniques to locate and identify potential problems in the pipeline. The anomalies located by direct assessment usually involve corrosion of the pipeline. Corrosion is the second leading cause of gas pipeline failures. The direct assessment process entails performing two non-invasive complementary indirect exams of the section of the pipeline targeted by engineering analysis and predictions on that section. Typical indirect exams involve different approaches in measuring electrical values, so that any variations along the pipeline can give an indication of the locations where possible anomalies might be present. They may also involve checking for corrosion inside the pipe at preset sampling locations. The pipeline is then excavated at the previously identified locations, examined and repaired if necessary. The results are compared with predictions, becoming part of a learning curve about the condition of the pipeline and facilitating future direct assessments of similar sections of pipeline. Direct assessment is estimated to cost between $7,000 and $15,000 per mile of pipeline examined, not including any necessary excavations. The latter can cost from $2,500 to $250,000 per excavation, depending on location. Many gas pipeline operators have already begun implementing the integrity rule and many more will be ready to begin assessments by the deadline on June 17, 2004. Approximately 30,000 miles of gas transmission operated by gas distribution utilities will have to be assessed under this rule. In the aggregate, for gas distribution utilities, estimated costs of compliance with this rule will exceed $3 billion in 20 years, not including integrity management pass-through costs from their gas transmission suppliers upstream, repairs, modifications, and changes in operations that may be necessary to maintain the reliability of gas supply in the face of large scale pipeline inspections and testing. Direct Assessment Standards Development The 2002 pipeline safety legislation also required that the DOT issue regulations prescribing standards for inspection of a pipeline facility by direct assessment. Such standards have been prescribed for external corrosion and are now being developed for internal corrosion and for stress corrosion cracking. The standards body leading this effort is the National Association of Corrosion Engineers (NACE). These standards will also be applicable to distribution pipelines. Expedite Permit Streamlining: Timely Repairs vs. Permit Delays Integrity management applied to distribution utility transmission lines will result in at least 100,000 excavation locations and possibly many more over the next 7 years. The vast majority of them will not result in repairs or replacement of pipe but ALL will require permits. In the Pipeline Safety Improvement Act of 2002, Congress wisely recognized that it would be bad government and very inequitable to allow one agency to prohibit or prevent a citizen from taking an action required by another agency, and then penalize the citizen. This is what could happen if a federal environmental agency fails to take timely action on a permit application for a pipeline safety repair, so that work cannot begin and end by the deadline set by the natural gas IMP rule. Under that rule, integrity repairs must be completed either (1) immediately, or (2) within one year after the discovery of an anomaly, depending on the type of defect involved. If a repair is not completed by the applicable deadline, the operator is required to reduce pressure and throughput on the affected pipeline by 20% until the repair can be completed. We are concerned that widespread, long-term pressure reductions would restrict supply and drive prices up. Our members estimate they must perform about 110,000 integrity inspections requiring excavation on intra-state pipelines (5 inspections per mile on average) over the next 7 years. That means there will be about 15,000 inspections per year requiring a test hole. Although we have made our best estimates, we do not yet know what percentage of these will require further excavation to repair the line. The bottom line is that there are too many of these projects to use the traditional, time consuming process for obtaining individual permits for each and every site. Congress wisely recognized this should not be allowed to happen and therefore directed federal agencies to develop a streamlined process to ensure that permits are given in time to allow timely repairs. We need a more efficient process. Please note that we do not advocate changing underlying environmental standards or requirements. Our concerns are purely with the process. We only ask that the agencies work together in a seamless, efficient and coordinated way so that this important public safety work can start and finish on time. Federal agencies have made some progress in streamlining their permit process. Interstate natural gas pipelines get their permits through an integrated FERC certification process and environmental review under the National Environmental Policy Act (NEPA). In December 2002, FERC and other federal agencies entered into a Memorandum of Understanding (MOU) to coordinate and accelerate the way in which they process permits for the construction of new interstate natural gas pipelines. The 2002 MOU also covers permits for maintenance and repairs of interstate pipelines, so it has been interpreted to help streamline permits for repairs under the IMP Rule. Although AGA is pleased because some AGA members operate interstate pipelines, the 2002 FERC MOU does not cover integrity repairs on intra-state pipelines because they are not certificated by FERC. The final Pipeline Repair Streamlining MOU specifically addresses the need to expedite integrity repairs that must be done “immediately” under the IMP Rule. We are pleased that the MOU sets out the general framework for authorizing other repairs to proceed without site-specific permits, provided certain conditions are met. However, we are very concerned that there are no details in the MOU regarding how this will work. Instead, the MOU delegates this difficult and essential task to a new interagency working group. This group has little time remaining to develop a working process to streamline repair permits. Our members are on a tight schedule for beginning their integrity testing and first phase of repairs, and they will need timely authorization to begin this important public safety work. AGA has been urging the agencies to seek broad input from experts in the field and to solicit creative “outside the box” solutions. There are good options for ensuring environmental protection in a way that is less process-intense. This can be done within the authority agencies have under existing environmental laws. 3 Digit Number for One-Call Systems Congress has required the Federal Communications Commission to issue a rule that provides a toll-free 3-digit number that excavators and the public can use to easily connect to the appropriate one call center. One-call centers are designed to have personnel dispatched to the excavation site to have underground facilities – natural gas lines, petroleum and product lines, fiber optics, telephone, electricity, water and sewer lines – to avoid them being damaged. An easily remembered, easily advertised 3 digit number will increase the use of these vital services and therefore help avoid unnecessary accidents. The Federal Communications Commission just issued a proposed rule mandating the establishment of the 3-digit number. The leading cause of accidents on distribution pipelines comes from excavators unintentionally striking our lines. It is known as excavation damage, also commonly called third-party damage. Year after year, these strikes cause over 60% of the total ruptures on utilities and the vast majority of injuries and fatalities. We are continually urging states to require government agencies and their contractors to participate in One-Call programs. This would help eliminate some exemptions some state agencies currently have in several states from participation in One-Call. The Pipeline Safety Improvement Act of 2002did help address this critical problem by clarifying that State departments of transportation should participate. However, there still is nothing to compel them to do so. Needless accidents continue to occur. Injuries, fatalities, property loss and disruption of services could be reduced with better use of One-Call centers and recommended practices for damage prevention. Right-of-Way Encroachment Study The 2002 pipeline safety legislation directed DOT to work with the Federal Energy Regulatory Commission and other federal and state agencies to study the difficult problem of encroachment on pipeline rights-of-way and to make recommendations for improvements. We understand that this study is under way under the direction of a steering group. Encroachment is where buildings and structures are placed on or very near the “no build zones” that a pipeline right-of-way represents. This is especially a problem where cities and towns expand to ultimately push up to a pipeline location that was rural when built. We hope that the Committee will work with us to make progress on addressing this problem once the study’s recommendations are made public. Operator Qualification Standards In compliance with the 2002 legislative mandate, the OPS is leading development of a standard (ASME B31Q) for pipeline operations personnel qualification programs. This is another standard that has required significant member AGA and APGA member involvement in handling both training and operational aspects. The standard is still being developed and its completion is slated for the end of this year. Public Awareness Communication Effectiveness OPS is working with stakeholders from the liquids and gas industries to define what would be required to evaluate effectiveness of operator communication programs. With input from industry, OPS is separately working with the states to define regulatory requirements that will cover gas utilities. AGA and APGA members have been involved via a task group to highlight the fact that flexibility is needed to avoid duplication of communication efforts already being carried out by gas utilities in their respective service territories at the local levels. Infrastructure Research and Development Grants Congress significantly increased the authorization for OPS’ pipeline safety research and development program to $10 million per year for four years. As OPS receives their funding primarily through user fees assessed on pipelines, these monies will likely be routinely provided. The pipeline safety act of 2002 also sought to coordinate the efforts of OPS with those of the Department of Energy. Generally OPS’ focus on those technologies that represent near-term development for field applications and provides matching dollars to the recipients. With the increase in inspections and repairs and the expanding use of natural gas, better ways to do the job need to be found. Industry typically cannot provide directly all that is needed for R&D due to the nature of their rate framework. The natural gas surcharge that the Federal Energy Regulatory Commission (FERC) allowed for many years ends this year on August 1st. FERC is considering an alternative proposal. AGA is also pursuing legislation that would establish a collaborative research program. AGA and APGA are hopeful that either the regulatory or legislative R&D funding proposal will become a reality. Either would solidify industry contributions to research. However, additional contributions for R&D are needed and AGA and APGA would welcome the opportunity to discuss with Committee members and staff the gas supply, transmission, distribution and utilization research that could be accomplished with increased public funding. Additional Federal Regulatory Initiatives Current federal regulatory initiatives for distribution systems include: · Operator qualification rule revision · Public communications standard development · Better crisis communication · Excess flow valve installation · Operator safety performance metrics Operator qualification rule revision To comply with NTSB recommendations, OPS expects to revise the operator qualification rule to include greater specificity. This has required significant AGA and APGA member involvement to ensure our members’ concerns are taken into account. AGA and APGA believe reasonable additional requirements are being developed to adequately address the NTSB concerns and will soon become part of the revised rule. Public Communications Standard Development A public communications standard (API Recommended Practice 1162) designed to address a variety of audiences has been completed under the American Petroleum Institute (API) banner, with input from industry and the regulatory community. It will be adopted by OPS via rulemaking on public education and communications. Better Crisis Communication OPS is working with stakeholders to define guidelines for operators to follow in issuing communications in the event of involvement in an accident involving pipelines. The most recent one occurred on a gasoline pipeline in Tucson, AZ and sparked high-profile public hearings. Distribution utilities are engaged in deliberations with the other stakeholders to ensure concerns for gas utility communications are addressed. Excess Flow Valve Installation In response to an NTSB recommendation and more recently, public testimony, OPS is reconsidering whether to mandate the installation of excess flow valves on service lines. Mandated installation would pose a potential major added burden on AGA and APGA members that elect not to install such devices, but instead notify customers and install such devices upon request from the customer. Cost-benefit studies performed to date by OPS do not adequately justify the nationwide installation of these devices on a mandatory basis unless some shaky, easily refutable assumptions are made. Operator safety performance metrics OPS continues to look for ways to more clearly demonstrate the effectiveness of their safety programs. To this end, the agency is seeking to further improve and increase the gathering of safety performance data from operators. Federal regulators are contemplating further changes in operator reports to DOT that will also cover distribution systems. The distribution utilities remain committed to develop reasonable safety performance measurements with OPS and other stakeholders. Voluntary Industry Programs Voluntary industry programs involving distribution utilities include: · A government-industry group examining existing regulations and practices addressing distribution system integrity in an effort to identify needed enhancements. Along with APGA, many AGA member companies are participating in this study, which is supported by the American Gas Foundation. · In response to an NTSB recommendation, numerous gas distribution utilities have been collecting data on the performance of plastic pipe since January 2001. Government and industry stakeholders convene periodically to examine the data for areas of concern. · Continued participation in the Common Ground Alliance to promote infrastructure damage prevention LDCs comply with a regulatory program that devotes stringent attention to design, construction, testing, maintenance, operation, replacement, inspection and monitoring practices. We continually refine our safety practices. Natural gas utilities spend an estimated $6.4 billion each year in safety-related activities and this figure will significantly increase once the legislative mandates adopted to date are implemented fully. Historically, approximately half of the current $6.4 billion is spent in compliance with federal and state regulations. The other half is spent, as part of our companies’ voluntary commitment to ensure that our systems are safe and that the communities we serve are protected and products delivered. Summary In summary, many programs are under way to address implementation of the legislative mandates of 2002. They must be given sufficient time to allow verification of their effectiveness. We believe it would be premature to currently draw conclusions on the results or consequences of any of these programs. Furthermore, in view of the growing need for energy to support continued economic growth, legislative decisions on pipeline safety should support or be consistent with the needed growth in the energy delivery infrastructure. The natural gas utility industry is proud of its safety record. Natural gas has become the recognized fuel of choice by citizens, businesses and the federal government. Public safety is the top priority of natural gas utilities. We invite you to visit our facilities and observe for yourselves our employees’ dedication to safety. We are committed to continue our efforts to operate safe and reliable systems and to strengthen One-Call laws and systems in every state. Thank you for providing the opportunity to present our views on the important matter of pipeline safety. We look forward to working with federal, state and local authorities and representatives, as well as within our industry, to achieve the highest possible level of public and employee safety. Written Testimony of Earl Fischer Senior Vice President, Utility Operations Atmos Energy Corporation On Behalf of the American Gas Association and The American Public Gas Association Before the U.S. Senate Commerce, Science and Transportation Oversight Hearing on Pipeline Safety June 15, 2004 Good morning, Mr. Chairman and members of the Committee. I am pleased to appear before you today and wish to thank the Committee for calling this hearing on the important topic of pipeline safety. My name is Earl Fischer. I am Senior Vice President, Utility Operations of Atmos Energy Corporation. Atmos Energy is one of the largest pure natural gas distributors in the United States, delivering natural gas to about 1.7 million residential, commercial, and industrial and public-authority customers. Our regulated utility services are provided to more than 1,000 small and medium-size communities in 12 states. I am here testifying today on behalf of the American Gas Association (AGA) and the American Public Gas Association (APGA). The American Gas Association represents 192 local energy utility companies that deliver natural gas to more than 53 million homes, businesses and industries throughout the United States. AGA member companies account for roughly 83 percent of all natural gas delivered by the nation's local natural gas distribution companies. AGA is an advocate for local natural gas utility companies and provides a broad range of programs and services for member natural gas pipelines, marketers, gatherers, international gas companies and industry associates. The American Public Gas Association is the national, non-profit association of publicly owned natural gas distribution systems. APGA was formed in 1961, as a non-profit and non-partisan organization, and currently has 606 members in 36 states. Overall, there are 949 municipally owned systems in the U.S. serving nearly five million customers. Publicly owned gas systems are not-for-profit retail distribution entities that are owned by, and accountable to, the citizens they serve. They include municipal gas distribution systems, public utility districts, county districts, and other public agencies that have natural gas distribution facilities. Natural gas meets one-fourth of the United States' energy needs. I am pleased to appear here today and hope that my testimony will provide you with a better understanding of how distribution systems work and how the implementation of the Pipeline Safety Improvement act of 2002 affects us. AGA, APGA and its members commend Congress for ensuring that the safety bill passed in 2002. The legislation that was finally passed in the final days of the 104th Congress was a balanced, fair bill and will bring yet further safety improvements. This Committee and Chairman McCain in particular, had a very significant role seeing that the bill went through and I and the industry thank you for your commitment and leadership. We would also like to commend the U.S. Department of Transportation Office of Pipeline Safety (OPS) for diligently working to address much of the disapproval that arose during the debate on the 2002 bill. OPS was criticized by Congress, the National Transportation Safety Board, DOT’s Inspector General, and members of the public for not addressing numerous congressional mandates and safety recommendations. To their credit, OPS has dealt with the vast majority of this backlog and is moving expeditiously, and often in consultation with all affected stakeholders, to address the mandates in the Pipeline Safety Improvement Act of 2002. Given this tremendous progress, we are concerned over the proposed reorganization of DOT that would include moving OPS into the Federal Railroad Administration. Indeed, we cannot understand the rationale for wanting to make any move that could jeopardize this positive momentum. Gas Distribution Utilities Serve The Customer Gas distribution utilities or Local Distribution Companies (LDCs) are the last, critical link in the natural gas delivery chain. To most customers, utilities are the “face of the industry”. Our customers see our name on their bills, our trucks in the streets and our company sponsor ship of many civic initiatives. We live in the communities we serve and interact daily with our customers. Consequently, we take very seriously the responsibility of continuing to deliver natural gas to our communities safely, reliably and affordably. Natural Gas Utilities Are Committed to Safety Safety is a top priority, a source of pride and a matter of corporate policy for every company. These policies are carried out in specific and unique ways. Each company employs safety professionals, provides on-going employee evaluation and safety training, conducts rigorous system inspections, testing, and maintenance, repair and replacement programs, distributes public safety information, and complies with a wide range of federal and state safety regulations and requirements. Individual company efforts are supplemented by collaborative activities in the safety committees of regional and national trade organizations. Our industry’s commitment to safety is borne out each year through the National Transportation Safety Board’s annual statistics. Delivery of energy by pipeline is consistently the safest mode of energy transportation. Natural gas utilities are dedicated to seeing this continue. Over the last 17 years, the amount of natural gas traveling through distribution pipelines has increased by almost a third and more than 650,000 miles of pipeline have been added to the system – yet the number of reportable incidents on distribution pipelines has decreased by 25 percent. This is a remarkable achievement, one that AGA and APGA attribute to the industry’s overarching commitment to safety. Natural gas distribution pipelines are thoroughly regulated. As part of an agreement with the Federal government, in most states, State pipeline safety authorities have primary responsibility to regulate natural gas utilities as well as intrastate pipeline companies. However, state governments have to adopt as minimum standards the federal safety standards promulgated by the DOT. In exchange, DOT reimburses the State for up to 50% of their pipeline safety enforcement costs. Therefore, what Congress does affects state regulations and our companies. The states may also choose to adopt standards that are more stringent than the federal ones. The Difference in “Pipelines” While many may unintentionally link all “pipelines” together, there are indeed significant differences between the liquid transmission systems, natural gas transmission systems and natural gas distribution systems. Each industry faces different challenges, operating conditions and consequences of incidents. Interstate transmission systems are generally made up of long runs of generally straight pipelines, having large diameter, and operated at high volumes and high pressures. Distribution systems, in contrast, are constructed in configurations that look like a network or web, use smaller diameter pipe, and operate at much lower volumes and pressures. However, many distribution companies also own and operate transmission pipeline segments within their systems. Federal regulations recognize the differences between these three types of pipelines, and different sets of rules have been created for each. 49 CFR Part 192 sets out the regulations for natural gas transmission and distribution and the rules discriminate between the two, while 49 CFR Part 195 sets out the regulations for liquid transmission lines. Status of Implementing the Pipeline Safety Improvement Act of 2002 Since the Pipeline Safety Improvement Act of 2002 was signed into law on December 17, 2002, many programs are under way to specifically address implementation of the law’s mandates and further safety enhancements of gas transmission and distribution systems. For gas transmission systems, most notable among many of the 2002 legislative mandates was integrity management for gas transmission pipelines. The law’s provisions have also resulted in a substantial number of regulatory mandates, initiatives and voluntary programs for distribution systems. Federal Regulatory Mandates The 2002 regulatory mandates affecting distribution systems include: · Direct assessment standards development · Environmental repair permit streamlining · One-call 3-digit number rulemaking · Right-of-way population encroachment study · Operator qualification standard development · Public awareness communication effectiveness rulemaking · Infrastructure R&D grants program Integrity Management Rule for Natural Gas Transmission OPS issued the integrity management rule for natural gas transmission lines on December 12, 2003. The rule requires natural gas transmission pipeline operators to conduct periodic inspections in “high consequence areas”, which for natural gas pipelines are generally high-density population areas. The nature of utility-owned transmission requires that over 50 percent of the lines under the integrity management rule be inspected using direct assessment methods. Direct assessment is an alternative to internal inspection (smart pigging) or pressure testing. It comprises a variety of screening and examination techniques to locate and identify potential problems in the pipeline. The anomalies located by direct assessment usually involve corrosion of the pipeline. Corrosion is the second leading cause of gas pipeline failures. The direct assessment process entails performing two non-invasive complementary indirect exams of the section of the pipeline targeted by engineering analysis and predictions on that section. Typical indirect exams involve different approaches in measuring electrical values, so that any variations along the pipeline can give an indication of the locations where possible anomalies might be present. They may also involve checking for corrosion inside the pipe at preset sampling locations. The pipeline is then excavated at the previously identified locations, examined and repaired if necessary. The results are compared with predictions, becoming part of a learning curve about the condition of the pipeline and facilitating future direct assessments of similar sections of pipeline. Direct assessment is estimated to cost between $7,000 and $15,000 per mile of pipeline examined, not including any necessary excavations. The latter can cost from $2,500 to $250,000 per excavation, depending on location. Many gas pipeline operators have already begun implementing the integrity rule and many more will be ready to begin assessments by the deadline on June 17, 2004. Approximately 30,000 miles of gas transmission operated by gas distribution utilities will have to be assessed under this rule. In the aggregate, for gas distribution utilities, estimated costs of compliance with this rule will exceed $3 billion in 20 years, not including integrity management pass-through costs from their gas transmission suppliers upstream, repairs, modifications, and changes in operations that may be necessary to maintain the reliability of gas supply in the face of large scale pipeline inspections and testing. Direct Assessment Standards Development The 2002 pipeline safety legislation also required that the DOT issue regulations prescribing standards for inspection of a pipeline facility by direct assessment. Such standards have been prescribed for external corrosion and are now being developed for internal corrosion and for stress corrosion cracking. The standards body leading this effort is the National Association of Corrosion Engineers (NACE). These standards will also be applicable to distribution pipelines. Expedite Permit Streamlining: Timely Repairs vs. Permit Delays Integrity management applied to distribution utility transmission lines will result in at least 100,000 excavation locations and possibly many more over the next 7 years. The vast majority of them will not result in repairs or replacement of pipe but ALL will require permits. In the Pipeline Safety Improvement Act of 2002, Congress wisely recognized that it would be bad government and very inequitable to allow one agency to prohibit or prevent a citizen from taking an action required by another agency, and then penalize the citizen. This is what could happen if a federal environmental agency fails to take timely action on a permit application for a pipeline safety repair, so that work cannot begin and end by the deadline set by the natural gas IMP rule. Under that rule, integrity repairs must be completed either (1) immediately, or (2) within one year after the discovery of an anomaly, depending on the type of defect involved. If a repair is not completed by the applicable deadline, the operator is required to reduce pressure and throughput on the affected pipeline by 20% until the repair can be completed. We are concerned that widespread, long-term pressure reductions would restrict supply and drive prices up. Our members estimate they must perform about 110,000 integrity inspections requiring excavation on intra-state pipelines (5 inspections per mile on average) over the next 7 years. That means there will be about 15,000 inspections per year requiring a test hole. Although we have made our best estimates, we do not yet know what percentage of these will require further excavation to repair the line. The bottom line is that there are too many of these projects to use the traditional, time consuming process for obtaining individual permits for each and every site. Congress wisely recognized this should not be allowed to happen and therefore directed federal agencies to develop a streamlined process to ensure that permits are given in time to allow timely repairs. We need a more efficient process. Please note that we do not advocate changing underlying environmental standards or requirements. Our concerns are purely with the process. We only ask that the agencies work together in a seamless, efficient and coordinated way so that this important public safety work can start and finish on time. Federal agencies have made some progress in streamlining their permit process. Interstate natural gas pipelines get their permits through an integrated FERC certification process and environmental review under the National Environmental Policy Act (NEPA). In December 2002, FERC and other federal agencies entered into a Memorandum of Understanding (MOU) to coordinate and accelerate the way in which they process permits for the construction of new interstate natural gas pipelines. The 2002 MOU also covers permits for maintenance and repairs of interstate pipelines, so it has been interpreted to help streamline permits for repairs under the IMP Rule. Although AGA is pleased because some AGA members operate interstate pipelines, the 2002 FERC MOU does not cover integrity repairs on intra-state pipelines because they are not certificated by FERC. The final Pipeline Repair Streamlining MOU specifically addresses the need to expedite integrity repairs that must be done “immediately” under the IMP Rule. We are pleased that the MOU sets out the general framework for authorizing other repairs to proceed without site-specific permits, provided certain conditions are met. However, we are very concerned that there are no details in the MOU regarding how this will work. Instead, the MOU delegates this difficult and essential task to a new interagency working group. This group has little time remaining to develop a working process to streamline repair permits. Our members are on a tight schedule for beginning their integrity testing and first phase of repairs, and they will need timely authorization to begin this important public safety work. AGA has been urging the agencies to seek broad input from experts in the field and to solicit creative “outside the box” solutions. There are good options for ensuring environmental protection in a way that is less process-intense. This can be done within the authority agencies have under existing environmental laws. 3 Digit Number for One-Call Systems Congress has required the Federal Communications Commission to issue a rule that provides a toll-free 3-digit number that excavators and the public can use to easily connect to the appropriate one call center. One-call centers are designed to have personnel dispatched to the excavation site to have underground facilities – natural gas lines, petroleum and product lines, fiber optics, telephone, electricity, water and sewer lines – to avoid them being damaged. An easily remembered, easily advertised 3 digit number will increase the use of these vital services and therefore help avoid unnecessary accidents. The Federal Communications Commission just issued a proposed rule mandating the establishment of the 3-digit number. The leading cause of accidents on distribution pipelines comes from excavators unintentionally striking our lines. It is known as excavation damage, also commonly called third-party damage. Year after year, these strikes cause over 60% of the total ruptures on utilities and the vast majority of injuries and fatalities. We are continually urging states to require government agencies and their contractors to participate in One-Call programs. This would help eliminate some exemptions some state agencies currently have in several states from participation in One-Call. The Pipeline Safety Improvement Act of 2002did help address this critical problem by clarifying that State departments of transportation should participate. However, there still is nothing to compel them to do so. Needless accidents continue to occur. Injuries, fatalities, property loss and disruption of services could be reduced with better use of One-Call centers and recommended practices for damage prevention. Right-of-Way Encroachment Study The 2002 pipeline safety legislation directed DOT to work with the Federal Energy Regulatory Commission and other federal and state agencies to study the difficult problem of encroachment on pipeline rights-of-way and to make recommendations for improvements. We understand that this study is under way under the direction of a steering group. Encroachment is where buildings and structures are placed on or very near the “no build zones” that a pipeline right-of-way represents. This is especially a problem where cities and towns expand to ultimately push up to a pipeline location that was rural when built. We hope that the Committee will work with us to make progress on addressing this problem once the study’s recommendations are made public. Operator Qualification Standards In compliance with the 2002 legislative mandate, the OPS is leading development of a standard (ASME B31Q) for pipeline operations personnel qualification programs. This is another standard that has required significant member AGA and APGA member involvement in handling both training and operational aspects. The standard is still being developed and its completion is slated for the end of this year. Public Awareness Communication Effectiveness OPS is working with stakeholders from the liquids and gas industries to define what would be required to evaluate effectiveness of operator communication programs. With input from industry, OPS is separately working with the states to define regulatory requirements that will cover gas utilities. AGA and APGA members have been involved via a task group to highlight the fact that flexibility is needed to avoid duplication of communication efforts already being carried out by gas utilities in their respective service territories at the local levels. Infrastructure Research and Development Grants Congress significantly increased the authorization for OPS’ pipeline safety research and development program to $10 million per year for four years. As OPS receives their funding primarily through user fees assessed on pipelines, these monies will likely be routinely provided. The pipeline safety act of 2002 also sought to coordinate the efforts of OPS with those of the Department of Energy. Generally OPS’ focus on those technologies that represent near-term development for field applications and provides matching dollars to the recipients. With the increase in inspections and repairs and the expanding use of natural gas, better ways to do the job need to be found. Industry typically cannot provide directly all that is needed for R&D due to the nature of their rate framework. The natural gas surcharge that the Federal Energy Regulatory Commission (FERC) allowed for many years ends this year on August 1st. FERC is considering an alternative proposal. AGA is also pursuing legislation that would establish a collaborative research program. AGA and APGA are hopeful that either the regulatory or legislative R&D funding proposal will become a reality. Either would solidify industry contributions to research. However, additional contributions for R&D are needed and AGA and APGA would welcome the opportunity to discuss with Committee members and staff the gas supply, transmission, distribution and utilization research that could be accomplished with increased public funding. Additional Federal Regulatory Initiatives Current federal regulatory initiatives for distribution systems include: · Operator qualification rule revision · Public communications standard development · Better crisis communication · Excess flow valve installation · Operator safety performance metrics Operator qualification rule revision To comply with NTSB recommendations, OPS expects to revise the operator qualification rule to include greater specificity. This has required significant AGA and APGA member involvement to ensure our members’ concerns are taken into account. AGA and APGA believe reasonable additional requirements are being developed to adequately address the NTSB concerns and will soon become part of the revised rule. Public Communications Standard Development A public communications standard (API Recommended Practice 1162) designed to address a variety of audiences has been completed under the American Petroleum Institute (API) banner, with input from industry and the regulatory community. It will be adopted by OPS via rulemaking on public education and communications. Better Crisis Communication OPS is working with stakeholders to define guidelines for operators to follow in issuing communications in the event of involvement in an accident involving pipelines. The most recent one occurred on a gasoline pipeline in Tucson, AZ and sparked high-profile public hearings. Distribution utilities are engaged in deliberations with the other stakeholders to ensure concerns for gas utility communications are addressed. Excess Flow Valve Installation In response to an NTSB recommendation and more recently, public testimony, OPS is reconsidering whether to mandate the installation of excess flow valves on service lines. Mandated installation would pose a potential major added burden on AGA and APGA members that elect not to install such devices, but instead notify customers and install such devices upon request from the customer. Cost-benefit studies performed to date by OPS do not adequately justify the nationwide installation of these devices on a mandatory basis unless some shaky, easily refutable assumptions are made. Operator safety performance metrics OPS continues to look for ways to more clearly demonstrate the effectiveness of their safety programs. To this end, the agency is seeking to further improve and increase the gathering of safety performance data from operators. Federal regulators are contemplating further changes in operator reports to DOT that will also cover distribution systems. The distribution utilities remain committed to develop reasonable safety performance measurements with OPS and other stakeholders. Voluntary Industry Programs Voluntary industry programs involving distribution utilities include: · A government-industry group examining existing regulations and practices addressing distribution system integrity in an effort to identify needed enhancements. Along with APGA, many AGA member companies are participating in this study, which is supported by the American Gas Foundation. · In response to an NTSB recommendation, numerous gas distribution utilities have been collecting data on the performance of plastic pipe since January 2001. Government and industry stakeholders convene periodically to examine the data for areas of concern. · Continued participation in the Common Ground Alliance to promote infrastructure damage prevention LDCs comply with a regulatory program that devotes stringent attention to design, construction, testing, maintenance, operation, replacement, inspection and monitoring practices. We continually refine our safety practices. Natural gas utilities spend an estimated $6.4 billion each year in safety-related activities and this figure will significantly increase once the legislative mandates adopted to date are implemented fully. Historically, approximately half of the current $6.4 billion is spent in compliance with federal and state regulations. The other half is spent, as part of our companies’ voluntary commitment to ensure that our systems are safe and that the communities we serve are protected and products delivered. Summary In summary, many programs are under way to address implementation of the legislative mandates of 2002. They must be given sufficient time to allow verification of their effectiveness. We believe it would be premature to currently draw conclusions on the results or consequences of any of these programs. Furthermore, in view of the growing need for energy to support continued economic growth, legislative decisions on pipeline safety should support or be consistent with the needed growth in the energy delivery infrastructure. The natural gas utility industry is proud of its safety record. Natural gas has become the recognized fuel of choice by citizens, businesses and the federal government. Public safety is the top priority of natural gas utilities. We invite you to visit our facilities and observe for yourselves our employees’ dedication to safety. We are committed to continue our efforts to operate safe and reliable systems and to strengthen One-Call laws and systems in every state. Thank you for providing the opportunity to present our views on the important matter of pipeline safety. We look forward to working with federal, state and local authorities and representatives, as well as within our industry, to achieve the highest possible level of public and employee safety. W/pipeline safety/written testimony Fischer draft final.doc June 8, 2004 Kyle Rogers W/pipeline safety/written testimony Fischer draft final.doc June 8, 2004 Kyle Rogers