Gas Pipeline Safety March 2012

Transcription

1 Gas Pipeline Safety March 2012 Contact:

2 Introduction Pipeline safety has become a top priority for the gas industry. Several drivers have increased scrutiny in this area over the past few years. A significant percentage of total pipeline infrastructure in the United States is aging and will require replacement in the near future Recent high-profile incidents have demonstrated that risks such as leaks, defects, and improper operations can have severe consequences The abundance of shale gas and increasing dependence on natural gas as a supply source have created higher demand for transmission pipelines As a result, industry stakeholders such as federal and state governments, utility commissions, and trade organizations are developing actions that will enhance and enforce safety standards. Integrity management programs New legislation Penalties for violations Cost recovery mechanisms In response, natural gas distribution and transmission companies will need to make significant infrastructure investments and implement operating practices to align with the new standards. 1

3 Miles of Onshore Transmission Pipeline Pipeline Infrastructure Transmission 80,000 Onshore Gas Transmission Pipeline by Decade of Construction and by Region (Miles) 70,000 60,000 50,000 70,699 71,220 Southeast Northeast Western Gulf Midwest 40,000 30,000 22,450 30,250 26,412 31,503 27,400 20,000 10,000 11,860 4,899 0 Pre Unknown 59% Transmission Pipelines by FERC Region FERC Region Miles of Main % Older than Total # of Leaks, 50 Years Onshore Transmission Midwest 88,305 34% 480 Gulf 71,998 36% 488 Western 55,046 31% 147 Northeast 43,846 39% 327 Southeast 37,497 39% 185 Grand Total 296,693 35% 1,627 Most of U.S. pipeline infrastructure is aging; 59% are 40 years old or older. The 1950s and 1960s saw a significant level of construction By comparison, the pipeline infrastructure is older than much of the U.S. highway system The northeast and southeast regions have the oldest transmission pipe, with 39% older than 50 years Source: PHMSA 2

4 Miles of Onshore Distribution Pipeline Pipeline Infrastructure Distribution 250,000 Onshore Gas Distribution Pipeline by Decade of Construction and by Region (Miles) 234, , , , , , ,340 Southeast Northeast Western Gulf Midwest 108, ,000 68,553 85,934 50,000 26,528 0 Pre Unknown 33% Distribution Pipelines by FERC Region FERC Region Miles of Main % Older than 50 Years Total # of Leaks Midwest 352,814 12% 128,875 Northeast 285,465 25% 186,630 Western 260,325 15% 95,705 Southeast 197,881 9% 76,393 Gulf 123,216 26% 65,395 Grand Total 1,219,701 17% 552,998 Source: PHMSA 3 Compared to transmission, the distribution infrastructure is newer; 33% of pipes are 40 years old or older, and 49% were constructed since 1980 The gulf and northeast regions have the oldest distribution pipes, with 26% and 25% older than 50 years, respectively

5 Significant Pipeline Incidents Recent high-profile incidents will keep the spotlight on pipeline safety for the foreseeable future. No. of incidents No. of fatalities/injuries Damage ($000) Reported Cause of Incident Transmission Distribution Number % Number % Corrosion 93 18% 24 3% Excavation Damage 93 18% % Incorrect Operation 22 4% 44 6% Material/Weld/Equipment Failure % 48 6% Natural Force Damage 37 7% 70 9% Other Outside Force Damage 40 8% % All Other Causes 74 14% % TOTAL % % Source: PHMSA 4 NOTE: Significant incidents meet one or more of the following criteria Fatality or injury requiring in-patient hospitalization $50,000 or more in total costs Highly volatile liquid releases of five barrels or more or other liquid releases of 50 barrels or more Liquid releases resulting in an unintentional fire or explosion Occurrences of significant incidents have not decreased materially in the last 10 years Material/weld/equipment failure is the largest cause of incidents for transmission pipelines, while excavation damage is the largest contributor to distribution incidents

6 Pipeline Capacity Additions For the past two years, pipeline capacity additions have been significantly lower than 2008 and 2009 but similar to historical levels 2008 was a year of extremely high construction activity, with long-haul pipeline additions and large-scale extensions to three new LNG terminals and several underground storage fields Recent additions (2010 and 2011) have been intended primarily to improve transportation between production areas (typically shale) and other markets In the future, the power generation industry is expected to increase its reliance on natural gas as a supply source Demand may double by 2030, driven largely by a shift from coal-fired to gas-fired generation To meet this demand, an additional 24,000 miles of pipeline may be required. Gas companies will be major players in this future build out of transportation infrastructure for power generation. For example: Piedmont Natural Gas plans to invest approximately $500 million on power generation-related projects through 2013 By 2014, NiSource plans to build a $1 billion pipeline that will span several southeast markets that have power plants that could switch from coal to gas Note: Capacity data only include interstate/intrastate transmission projects and exclude storage additions, gathering, and distribution lines. 5 Sources: U.S. Energy Information Administration, NERC, SNL, Piedmont Natural Gas

7 Industry Response Integrity Management Programs In the mid 1990s, the Pipeline and Hazardous Materials Safety Administration (PHMSA) began considering a risk-based approach to pipeline safety: integrity management. This approach recognizes that pipeline risks depend on factors such as location, age of pipe, and operating conditions In 2002, PHMSA published rules to establish integrity management requirements for gas transmission pipelines Under these rules, operators are required to collect pipeline system data, identify pipeline threats, analyze the associated risks, and mitigate the applicable threats and integrity concerns PHMSA determined in late 2004 that a similar rule was necessary for gas distribution pipelines, but a different approach was required due to some key differences with transmission Varying pipe sizes, materials, lengths, and operating pressures Threats to a distribution system that vary by location Proximity to populated areas PHMSA developed a new rule regarding distribution integrity management programs (DIMP) for gas operators of all sizes The primary objective of DIMP is to improve distribution pipeline safety The rule is designed to be a high-level, flexible federal regulation and is a new approach to pipeline maintenance and safety that requires operators to follow a risk-based program rather than a prescriptive set of regulations The final rule was issued in December 2009, and the deadline for operators to implement their plans was August 2011 Integrity Management Timeline DIMP Phase I Report published in 2005 In 2006, Congress mandated installation of excess flow valves on new and renewed single-familyresidence service lines DIMP rule issued in December Existing safety regulations for distribution pipelines were established in the early 1970s Pipeline Safety Improvement Act of 2002 required transmission operators to implement integrity management programs PHMSA published a Notice of Proposed Rulemaking for DIMP in June 2008 GPTC published draft guidelines in July 2008 Distribution operators must implement a DIMP plan by August 2011 Sources: AGA, Integrity Management for Gas Distribution: Report of Phase I Investigations, DOT 49 CFR Part 192 Pipeline Safety: Integrity Management Program for Gas Distribution Pipelines 6

8 Industry Response Federal- and State-Level Actions Below are examples of legislative and regulatory actions taken at the federal and state levels. Level Description Federal In January 2012, President Obama signed the Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011, which is designed to strengthen safety requirements and inspections and clarify accountability for pipeline operators for accidents. It includes the following provisions Doubling of DOT s civil penalties for safety violations Installation of automatic or remote-control valves on new pipelines where feasible Requirement for gas utilities to verify pipeline records for certain lines and for operators to reconfirm maximum allowable operating pressure for lines without sufficient records PHMSA published an Advance Notice of Proposed Rulemaking, which requests the public to comment on whether gas transmission pipeline regulations should be strengthened. Potential changes include eliminating certain regulatory exemptions for pipelines constructed prior to 1970 and expanding integrity management (August 2011) California The PUC augmented its natural gas safety efforts by creating a citation program under which natural gas companies can be fined for violating state and federal safety rules (December 2011) California The California legislature introduced a bill (AB1456) that would require the PUC to consider a gas utility s safety performance when determining the utility s rates (January 2012) Pennsylvania The PUC passed an order that outlines requirements for distribution integrity and management plans, new leak detection practices, and more stringent frost patrol requirements (December 2011) Texas The Railroad Commission approved draft rules that would implement new penalty guidelines for violations of its oil and gas safety measures, including those for pipeline safety (January 2012) Virginia The State Corporation Commission approved surcharges to recover costs of replacing natural gas pipelines to improve system safety and reliability for Columbia Gas of Virginia and Washington Gas Light (December 2011) Washington Cascade Natural Gas agreed to pay a $425,000 fine levied by the Utilities and Transportation Commission for alleged pipeline safety violations stemming from improper record keeping Sources: Washingtonwatch.com, Van Ness Feldman, SNL 7

9 Industry Response Distribution and Transmission Companies Distribution and transmission companies are responding by implementing various safety-related initiatives. Company Pacific Gas and Electric Company Description Announced a comprehensive pipeline safety enhancement plan to modernize its utility's natural gas transmission operations (August 2011) Pressure test approximately 780 miles of transmission pipeline to validate maximum allowable operating pressures Replace about 185 miles of pipeline Expand the use of automatic shut-off valves Improve asset management system for pipeline records Sempra Energy Proposed a pipeline safety enhancement program for Southern California Gas and San Diego Gas & Electric that includes more than $650 million in improvements on the utilities transmission systems (December 2011) Columbia Gas Transmission Columbus Gas of Ohio Enhancements include pressure testing, pipe replacements, in-line inspections, and automated valve installations Evaluating a program that would upgrade its pipeline infrastructure with about $4 billion of investment over 10 to 15 years. This program would respond to anticipated regulatory requirements (February 2012) Plans to invest more than $2 billion to replace 4,000 miles of bare steel and cast iron pipe over the next 25 years (February 2008) El Paso Conducting in-line inspections of all pipelines, to be completed by the end of 2012 in accordance with federal requirements Dominion East Ohio South Jersey Gas Requested permission from the Public Utilities Commission of Ohio to increase annual spending on its pipeline replacement program. The request, which would double spending to $200 million annually, is designed to accelerate the replacement program (March 2011) Filed request with the New Jersey Board of Public Utilities to extend its Capital Investment Recovery Tracker, which enables the utility to make investments to improve its pipeline infrastructure. This program is designed to accelerate planned capital expenditures and enhance the safety and reliability of SJG's delivery system Sources: PG&E, Columbus Gas of Ohio, Pipeline and Gas Journal, Colonial Pipeline, SNL 8

10 Implications for the Industry Recent incidents may result in greater federal oversight of integrity management programs The NTSB has recommended changes to how PHMSA provides oversight to integrity management programs (e.g., verification of operator information, measurement of operator performance) If these recommendations are adopted, PHMSA may get more involved in integrity management decision making (which has largely been left to operators) Once more stringent safety measures are established, companies will have to spend more money on inspections, equipment and technology, and pipeline repairs/replacements With 59% of the transmission pipelines 40 years old or older, this will likely be a significant issue for the industry DIMPs for gas LDCs will likely be tested in the near future Special focus will be on the methodology for identifying and mitigating distribution system risks, especially in leak detection/repair and damage prevention Gas utilities will need to assess their regulatory strategy with respect to cost recovery of pipeline investments Balancing the need to invest in integrity management with the opportunity to serve a growing power generation market will be important for many gas utilities Sources: DOT 49 CFR Part 192 Pipeline Safety: Integrity Management Program for Gas Distribution Pipelines, Pipeline and Gas Journal 9

11 Contact Us For more information on pipeline safety or our thoughts on other aspects of the natural gas industry, please contact us. Ed Baker Partner ScottMadden, Inc Piedmont Road Building 10, Suite 805 Atlanta, GA Jason G. Davis Director ScottMadden, Inc Piedmont Road Building 10, Suite 805 Atlanta, GA Phone: Mobile: Phone: Mobile: