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Signed into law by President Obama on Jan. 3, 2012, the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 contains several monumental mandates from

Congress that will forever change the land-scape of the natural gas industry, particularly for operators of natural gas transmission pipelines. (For at look at the most critical regulations that will affect transmission operators, see page 24.)

While it is difficult to provide an estimate, there is little doubt that these regulatory initiatives will end up requiring the industry to invest several billions of dollars, particularly over the next 15 years. Still, AGA member companies have made it abundantly clear that they are supportive of the government’s efforts to enhance pipe-line safety.

To demonstrate AGA’s support and willingness to elevate the government’s efforts, AGA member executives issued a Commitment to Enhancing Safety in May 2012, which includes a collection of actions that may be taken voluntarily to improve the safety and reliability of the transmis-sion and distribution pipelines that local distribution companies operate.

Each operator will need to evaluate ac-tions in light of system variables, the opera-

tor’s independent integrity assessment, risk analysis and mitigation strategy, and what has been deemed reasonable and prudent by state regulators. Not all of the practices described in the document or in this article will be applicable to all operators due to the unique set of circumstances attendant to their specific systems.

Three AGA members agreed to share some recent activities underway to help en-hance the safety of their transmission pipeline infrastructure. Each of them represents their company on AGA’s Transmission Pipeline Operations Committee: Julie Hegedus, director of Pipeline Integrity for Consumers Energy; Neil Moser, director of Operations Compliance & Performance for Piedmont Natural Gas; and Sue King, principal engi-neer of Gas Planning for Xcel Energy.

Can you provide a high-level profile of the transmission pipelines your com-pany operates?

Julie Hegedus: Consumers Energy operates approximately 2,421 miles of transmission pipelines in the state of Michigan. This is made up of 305 miles of High Consequence Area and 2,116 non-HCA miles. Approxi-mately 78 percent of our pipeline system is made up of pre-’70s vintage pipe, mostly ’40s, ’50s, and ’60s vintage.

s a f e t y m a n d at e s

New regulatory

initiatives will require

huge investments. But

AGA members are

actively engaged

in actions that will

enhance safety and

reliability. Here’s what

three utilities are doing.

by Andrew Lu

New eNerGyregulations

ANd tHe

lANdscApe

Neil Moser: Piedmont Natural Gas operates approximately 2,900 miles of transmission pipelines in our North Carolina, South Carolina, and Tennes-see service areas. Roughly 270 miles meet Code of Federal Regulations 192 Subpart O Method 2 requirements for HCA iden-tification. Our pipelines range from less than 4 inches up to 30 inches in diameter and operate at pressures of as much as 1,000 psig on select pipelines. Of all our transmission pipelines, approximately 35 percent were in service prior to 1970.

Sue King: Xcel Energy operates approxi-mately 2,200 miles of natural gas transmis-sion pipelines, with about 220 miles in HCAs. Approximately half of the pipeline miles were installed before 1970.

Besides the effort to review your MAOP records, please describe some of the other measures your company is taking to enhance the safety of your transmis-sion system. JH: To date, Consumers Energy has as-sessed over 1,288 miles, or 53 percent, of our total transmission system. This is well above the 305 miles of HCA pipe-line miles in our system required to be assessed. We plan to assess over 74 percent of our total transmission system by the end of 2018. Consumers Energy believes that in-line inspection is the best meth-odology for inspecting our pipelines. Of the 1,288 miles that we have assessed, 90 percent of that has been with in-line inspection technology. In addition, pipeline anomalies that are identified by ILI are proactively addressed regardless of location. Finally, Consumers Energy is evaluating pre-’70s vintage pipelines with electric resistance welded seams for potential full-line replacements where feasible. This would mitigate and reduce the potential risk of seam defects.

NM: We have begun to install remote operated valves—for example, we installed ROVs for all mainline valve sites in our new Sutton Pipeline project. These valves are monitored via our SCADA system and

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operable from our Gas Control should conditions require activation. We are using the same ideology on all new transmis-sion pipelines under consideration today. Our existing pipeline system is also being evaluated for ROV installation where feasible and practical.

We have moved heavily toward ILI. We have retrofitted and inspected in excess of 200 miles of pipeline per year for the past three years. This includes both HCA and non-HCA mileage. As we have detected anomalies through these activities, we are reinforcing our pipeline data by includ-ing field tests, such as non-destructive evaluation and positive material identi-fication, to validate our pipeline records and GIS information. This movement toward ILI has also resulted in accelerating replacement programs for small-diameter and other “unpiggable” pipe. Our TIMP organization is continually exploring new ILI tools and capabilities, as this technol-ogy advances, and coordinating with our engineering department to ensure quality in our construction practices and field data collection activities.

Additionally, Piedmont is in the midst of a program focused on increasing integ-

rity management efforts by streamlining work processes, deploying technology to the field, improving system asset and work data capture and consistency, and increas-ing data accessibility within the organiza-tion. We are targeting an initial deploy-ment for transmission assets in a pilot location in 2014. When completed, this program will allow Piedmont to analyze, respond, react, and document field work performed in a way that will enhance our ability to meet current and projected in-tegrity management requirements for both transmission and distribution pipelines.

SK: Xcel Energy expects to proactively assess the integrity and condition of all its natural gas transmission lines outside of HCAs by 2022, using ILI. Xcel Energy anticipates evaluating approximately 70 percent of the line miles with this tech-nology. For the balance, alternate assess-ment methods will be utilized until ILI or other technology becomes available. To date, Xcel Energy has completed in-line inspections on 680 miles of transmission pipelines and assessed the condition of 1,030 miles of gas transmission lines.

Pressure testing is another important

tool used to determine the condition of gas pipelines, particularly when such a test will support MAOP validation. A parallel effort is underway to prioritize pipelines for replacement or accelerated reassess-ment by criticality of the line, population density, and key operating criteria. Xcel Energy has begun replacing pipelines that are nearing the end of their useful lives and/or display significant integrity issues. Systematic evaluation and replacement provides a greater measure of safety for the public and employees, plus better cost certainty and improved coordination with communities.

Other proactive steps taken by Xcel Energy in advance of federal regulations include installing automated valves and strain gauges on newly installed pipelines in mountainous areas that are susceptible to landslides, as well as accelerating re-assess-ment of critical gas transmission pipelines. The company has also prioritized locations for remote control valves on existing in-frastructure and expects to begin installing these key control assets this year.

Xcel Energy is working proactively with its state utility commissions to devel-op cost-recovery mechanisms to support

The Pipeline safety, regulatory certainty, and Job creation Act of 2011 contains many provisions that address transmission and distribution pipelines. Those interested in seeing the full law can access it at: http://bit.ly/Lb44uc

Following are the Act’s most critical items impacting natural gas transmission pipelines:

Section 4 mandates the u.s. department of Transportation, not later than two years after enactment, and if appropriate, to require by regulation the use of automatic or remote-controlled shut-off valves, or equivalent technology, where economically, technically, and operationally feasible on transmission pipeline facilities constructed or entirely replaced after dOT issues the final rule.

Section 5 requires dOT to evaluate, within 18 months of enactment:• Whether TIMP requirements, or elements

thereof, should be expanded beyond High consequence Areas.

• If applying TIMP requirements, or elements thereof, to additional areas would mitigate the need for class-location requirements.

Section 23 requires each owner or operator of a pipeline facility to: • Conduct a verification of pipeline records

for transmission pipelines located in a class 3 and class 4 locations, and class 1 and 2 HcAs to verify that records confirm the established mAOP.

• Identify and submit information indicating where records are insufficient to confirm the established mAOP.

(note: Pipeline operators submitted results of their records verification to dOT on the trans-mission operators annual report, which was due by June 15, 2013.)

for pipelines with insufficient MaOP records, DOT must:• Require the operator

to reconfirm the mAOP as expeditiously as is economically possible.

• Determine what actions are appropriate until the mAOP is confirmed. dOT must take into account potential consequence to public safety and the environment, impacts on pipeline system reliability and deliverability, and other factors, as appropriate.

The Act also requires dOT to issue regula-tions, within 18 months of enactment, for con-ducting tests to confirm the material strength of previously untested gas transmission lines in HcAs that operate at a pressure greater than 30 percent smys. dOT must consider safety testing methodologies including pressure test-ing and other alternative methods, including iLi, determined by dOT to be of equal or greater effectiveness.

THe IMPaCT ON TraNSMISSION PIPeLINeS

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COMMITMeNT TO eNHaNCINg SafeTyeAcH operAtor will Need to evAluAte ActioNs iN liGHt oF sucH criteriA As system vAriABles.

these actions. In Colorado, for example, the Pipeline Safety Integrity Adjustment rider has been in place since 2012. A new law was passed in Minnesota in 2013 to provide a similar rider. Both processes provide for significant transparency of the planning process as well as regular review of program results. Xcel Energy sees this type of partnership with regula-tors as a key way to improve public safety and provide certainty for customer rates. Today’s low natural gas prices provide the company with an excellent opportunity to improve public safety and invest in renew-ing aging infrastructure while minimizing the cost impact to customers.

What has been the messaging from your company’s executives and board of directors in terms of allocating resourc-es to enhance the safety and integrity of the transmission infrastructure?

JH: The message from Consumers Energy’s executives and board of direc-tors has been clear that safety is the top priority. They have supported the capital investments to install launchers and receivers on our transmission system to allow for ILI tools to be used. (We have utilized a robotics tool when a traditional ILI tool could not be used.) They have supported the “go above and beyond” approach to inspecting our transmission infrastructure outside of the HCA, and encouraged us to think creatively about new assessment techniques.

NM: Safety is our highest priority as a company. From the board down to our frontline employees, we have a saying: “Al-ways think safety first.” That includes our people, the public, and our system. Our management team is unfailingly support-ive of our overall system integrity plan. Additional staffing has been approved that support these facilities and systems in the areas of engineering promanage-ment, GIS, design engineering, and codes

and standards. Capital resources have been made available to support pipeline retrofitting and replacement projects. State regulatory efforts have focused on new rate mechanisms, in the form of integrity management riders in North Carolina and Tennessee, to provide support for the company, as integrity efforts will remain an intense focus into the foresee-able future. Our executives have routinely expressed a desire to ensure that a safe, reliable, and high-integrity pipeline system is in place now and in the future.

SK: Public and employee safety is a core value at Xcel Energy, with key metrics included on the corporate scorecard. Se-nior executives and the board of directors receive regular updates on the progress of these programs and support efforts to continue to improve operations and risk management.

Xcel Energy has increased investments in both human and capital resources to improve the safety of our employees and the public. In less than five years, the com-pany has added support and specialized skill sets in critical areas such as integrity management, engineering, project man-agement, geospatial data technology, and gas governance. Its operations organiza-tion has also been realigned to provide increased focus on its natural gas infra-structure integrity.

In addition, Xcel Energy has one of the best damage prevention and public aware-ness programs in the nation. The company is focused on a strong partnership with first responders in the communities in which its pipelines are located.

What do you see as the greatest chal-lenges for your company in addressing the new regulations that the industry expects the Department of Transpor-tation to issue in meeting the 2011 Pipeline Safety Reauthorization?

JH: Although Consumers Energy has in-

spected more than 53 percent of the total transmission pipeline system, expanding TIMP requirements beyond the HCA will be a large challenge. There are pipelines in our system that will currently not allow for the passage of an in-line inspection tool. Although we are exploring new technology and trying to be as proactive as possible, this expansion will be a signifi-cant undertaking.

NM: Piedmont’s engineering department believes the biggest challenge will be meet-ing regulatory timeline expectations as-sociated with any additional requirements. Our systems and infrastructure have been designed and installed over many decades. We need to work with regulators to bal-ance our ability to address safety concerns with the continued safe operations of existing pipeline systems and the needs to improve upon our safe, reliable, and high-integrity industry.

SK: Managing legacy pipeline assets will continue to be a challenge for Xcel Energy and the natural gas industry overall. Cer-tain historical records are not available and cannot be re-created, nor will we ever have perfect knowledge of these legacy assets. Some of PHMSA’s proposed rules (such as the proposed integrity verification process regulations) will require significant pipe-line replacement, which will mean sizable capital investment. In addition, qualified personnel to perform this type of work are scarce and often are simply not available.

Xcel Energy believes these legacy as-sets can be operated and overseen with a proactive integrity management program that supports maintaining a high degree of public safety. The company also strongly supports research and development ef-forts to improve asset knowledge, which provides more cost-effective improvements that benefit public safety. u

Andrew Lu is managing director, Operations & Engineering, for AGA.