Reflections on San Bruno, PG&E and the CPUC

Question of the week: I heard the California Public Utilities Commission levied a fine of $1.6 billion dollars against PG&E for pipeline safety violations relating to the terrible San Bruno pipeline explosion in 2010. Do you think this will make a difference and improve PG&E’s safety? Is that all that will happen?

Reflections on San Bruno, PG&E and the CPUC

In case you missed it, last week, the California Public Utilities Commission (CPUC) levied a fine of $1.6 billion dollars against PG&E for violations of the state pipeline safety regulations, violations identified following the failure and explosion of one of PG&E’s natural gas transmission lines in San Bruno, California in 2010. That explosion killed 8 people and injured many more, destroyed an entire neighborhood and laid bare a multitude of shortcomings and outright failures of natural gas pipeline safety regulation in California. The City of San Bruno undertook a monumental effort on several fronts, seeking out every possible forum where PG&E might be held to account, and where regulatory change might be made so that no other community needlessly suffer from another completely preventable pipeline failure.

Whether or not one believes the utility’s and the regulator’s exclamations of intent to reform, whether or not one gives credence to the much-publicized efforts to operate more safely or to oversee more carefully, there is plenty of evidence that there remains a long way to go. The report of the National Transportation Safety Board following the explosion described a utility that didn’t know what pipes it had in the ground, and didn’t have adequate records or integrity programs. And it described a regulator that had apparently ignored those shortcomings of which it was aware, and simply hadn’t looked very hard to find others. Since the NTSB report, the media has been filled for nearly 5 years now with seemingly endless disclosures of cronyism between the regulator and the utility, the misappropriation of ratepayer funds collected in the name of safety upgrades but spent elsewhere, descriptions of yet another home destroyed and community disrupted because PG&E’s records did not accurately reflect what pipes were in the ground, and numerous reports and audits suggesting that the CPUC is not yet capable of adequately regulating.

While the fine imposed against PG&E is of record size, the company’s stock price recovered and closed higher on the day after the penalty was announced. This, in spite of the company’s 2013 protestation that a fine of that magnitude would surely force a bankruptcy or some other catastrophic result. In fact, PG&E has recently announced that it will not appeal the CPUC fine and decision.

Meanwhile, the aftermath of the failure continues in a variety of forums: Rulemaking efforts on the federal level that might respond to some of the concerns raised by the NTSB in its report on the PG&E failure have been bogged down for years. We continue to wait for a proposed rule to be released and open to comment, review by the Technical Advisory committees and perhaps one day become new regulations. State legislation has strengthened some California gas safety rules, and proposed legislation may alter the allocation of the fine levied by the CPUC to further benefit pipeline safety rather than the state’s general fund. The cronyism exposed by the dogged efforts of the City of San Bruno to obtain emails and other documents has resulted in changes in personnel in high levels both within PG&E and within the CPUC. The federal prosecutor impaneled a grand jury that last year returned criminal indictments against PG&E. The State Attorney General has opened a criminal investigation of PG&E and its relationship with the CPUC, seeking evidence of wrongdoing on the part of the CPUC, its former president, and perhaps others. These criminal proceedings are still in the very early stages. The legacy of the San Bruno tragedy will continue for some time, and we can only hope, for all our sakes, that it eventually results in significant safety improvements, regulatory capacity, and some small measure of justice.  

Natural Gas Compressor Stations – Does PHMSA regulate?

Question of the week

 We got a message through the Pipeline Safety Trust Facebook page (find us and like us there!) with some questions from Howard, who was trying to find some information about the regulation of compressor stations on interstate natural gas pipelines, like the one being proposed near his New England community. He had heard two distinctly different stories: one that compressor stations are “self-regulating”, which is to say not regulated at all; the other was that the Pipeline and Hazardous Material Administration (PHMSA of the US Department of Transportation) regulates them, but the details about exactly what that meant were a bit fuzzy.

Here’s what we told Howard, plus a few more tidbits:

Hi Howard – Compressor stations like the ones on the proposed Kinder Morgan pipeline are regulated by PHMSA. Compressor stations are included in the regulatory definition of “pipeline facility” in the PHMSA regulations governing gas transmission lines (49 CFR Part 192). Specifically, that definition is found in 49 CFR 192.5. Compressor stations are specifically called out in several regulations governing design, emergency exits and shutdown, fencing, ventilation, etc. Those specific regs can be found at 49 CFR 192.163, .165, .167, .169, .171, and .173. Compressor stations may also be subject to air quality regulation under the Clean Air Act, requiring a separate permitting process, but that permit is usually dealt with in the context of the FERC certification proceedings, sometimes as a condition on the granting of the certificate. Compressor stations that are not part of an interstate transmission line subject to siting by FERC may also be subject to zoning and permitting by local governments, and to safety inspections by a state if it has been certified to regulate intrastate natural gas facilities.  

PHMSA decides how often to inspect operators and for what purpose. For example, sometimes inspections throughout a region would focus on operator qualification requirements or control room management rules, and PHMSA will check all of the operators in the region for those specific topics. Other times inspections are a more wide-ranging inspection of individual operators or facilities, checking records and the facility for compliance with a wide variety of safety regulations. I’d suggest that for more information on how PHMSA schedules the inspections of facilities and how often they check a specific individual facility, you contact a Community and Technical Assistance (CATS) staff person in the regional office of PHMSA nearest you. You can find contact information for them here. You can also find a flowchart generally describing the inspection and enforcement process here. Records from enforcement actions resulting from previous inspections are included in the PHMSA reports on enforcement actions, but they are mixed in with those relating to incidents, so finding them requires a bit of searching.

Hope that helps. 

Send us your questions, big or little, hot-button or not, we’ll get the pig to root out the answer. 

 

Another Spill into the Yellowstone – Are we learning anything?

 

Many rivers to cross
But I can’t seem to find my way over

                                                ~Jimmy Cliff

 

Dear Readers: An unfortunate deja-vu-all-over-again moment occurred recently: another pipeline ruptured at a crossing of the Yellowstone River in eastern Montana.

First, there was the Silvertip spill….

You may remember that after the ExxonMobil Co.’s Silvertip Pipeline ruptured and spilled 1,500 barrels of oil into the Yellowstone River in 2011, I got a letter from my friend King Fisher of Riparian Ranch asking about the rules that govern pipelines crossing rivers. It was clear by then that the Silvertip spill was caused by the pipeline being damaged by riverbed scour and debris and he was understandably confused about the existing rule requiring operators to bury their pipelines a minimum of only four feet when they construct pipelines across rivers of at least 100 feet in width. He wondered whether there were other rules, and what they might be. 

I answered that letter in the Trust’s newsletter in January of 2013 (at pages 4-6). Here are the highlights of that response:

  • The current rules require pipelines crossing rivers that are wider than 100 feet to be buried at least 4 feet at the time of construction. A separate rule requires lines that cross navigable rivers to be checked at least every 5 years “to determine the condition of the crossing”. There is no rule requiring any specific depth of cover to be maintained after installation, unless the pipeline is one where a spill could affect a “high consequence area,” say, for example, the drinking water supply of a small city that takes its water directly from, say, the Yellowstone River.
  • The 2011 amendments to the Pipeline Safety Act included a directive to PHMSA to undertake a study of liquid pipeline incidents at river crossings to determine if depth of cover was a factor, and to make recommendations for any legislative action to improve the safety of buried pipelines at river crossings. No regulatory action was required of PHMSA.
  • PHMSA produced its report describing its data management challenges (it doesn’t have a database, geographic or otherwise that shows the crossings that are subject to the 100 foot crossing/4 feet deep rule); and describing the pipeline failures at crossings in the last 20 or so years (well, at least some of them). In an NTSB document not cited in PHMSA’s report to Congress, a chart shows that 6 of Exxon’s pipelines in the San Jacinto floodplain ruptured or were undermined for up to 120 feet in the 1994 flood event; most of these were not included in the PHMSA analysis.

Then there was the Bridger spill – Another spill into the Yellowstone River last month

The Bridger pipeline failed at its crossing of the Yellowstone River, spilling approximately 1,000 barrels of crude into the river. Complicating response, investigation and recovery is that the river is entirely frozen over, but with ice of varying thickness from day to day, creating safety concerns for responders and physical limitations on recovery operations.

Initial reports were that the pipeline was buried at least 8 feet under the bed of the river. Then we learned that was an assessment from 2011. Then we learned that sonar showed much of the pipeline crossing the river was exposed on the riverbed, and some of it was suspended above the bed, entirely exposed. Although we do not yet know the reason for the pipe’s failure, clearly the lessons of the Silvertip (and a USGS study showing parts of the Missouri River scouring to depths of up to 40 feet) had not been learned – that rivers change all the time and quickly, that riverbeds move a lot of sediment, and quickly.

My 2013 reply to King Fisher was written before PHMSA had fulfilled its second obligation under the 2011 Act: to determine whether the depth of cover requirements are inadequate and if so, to make legislative recommendations. I suggested staying tuned to find out what PHMSA would do, and raised concerns about some of the options open to it:

The risk is that PHMSA either: a) decides to change the depth of cover at installation rule, creating a political sideshow that exhausts safety advocates’ energy arguing over the number of feet or inches it should be raised, completely ignoring the fact that the installation rule makes very little difference over time if there are no maintenance of cover rules or viable, enforceable integrity management rules to require operators to manage for the risk of riverbed scour; or b) decides to argue that the operator’s obligations under integrity management rules to identify and mitigate the risks of riverbed scouring are sufficient, regardless of the 4-foot depth of cover at installation requirement, and therefore the depth of cover rules don’t need to be changed. 

Unless PHMSA opts for: c) an enforceable and enforced maintenance of cover rule for all crossings that is based on a study of the specific location and characteristics of each crossing; and d) actually enforcing integrity management obligations of operators to design for and mitigate against the risk of riverbed scour before an incident occurs, this smart pig is not optimistic about improving the safety of crossings at rivers.

So, how did PHMSA do?

Well, to some extent it remains to be seen, but there is recent reason to hope for improvement.

When PHMSA reported to Congress with the second half of its homework assignment – do you have legislative recommendations? – PHMSA reported that it believed that its existing legislative authority was adequate to protect pipelines at river crossings. PHMSA has yet to publish ANY substantive proposed changes to its safety regulations since the 2011 reauthorization, and until those major proposed rulemakings are released, we won’t know whether PHMSA intends to change the depth-of-cover-at-construction rule or to propose any new rules requiring maintenance of cover to some depth.

But just last week, in the midst of the awful news about the Bridger spill into the Yellowstone, PHMSA released its Final Order on ExxonMobil’s appeal of the fine imposed for its Silvertip spill. In the order, PHMSA responded to the operator’s (EMPCo’s) arguments that they had complied with the regulations relating to adequate risk assessments and integrity management measures to manage the identified risks:

The fact that flooding had not previously caused an integrity issue for Respondent’s pipeline does not mean future flooding could never cause a failure. One of the purposes of the integrity management regulations is to anticipate the possible threats to the pipeline in the future. Given that flooding is a threat in general and that flooding had caused integrity issues for other pipelines at the same location, it was not reasonable for EMPCo to assume seasonal flooding would never impact its own pipeline. At a minimum, the Operator had a duty to evaluate the likelihood of a pipeline release occurring from flooding. [Order at page 9.]

The order continues by analyzing the documents in the record to determine if such a risk analysis had been made, notes that the 2010 Preventive and Mitigative Measures Analysis identified only three risks to the line — third-party damage, manufacturing, and external corrosion — in spite of the fact that the entire line had been identified as one which could affect a high consequence area, and further noting that the presence of the Yellowstone River or the risk of a failure at its crossing was never mentioned.

The good news

The Conclusion of the PHMSA order on this violation is this:

Given the history of flooding and impact to other pipelines at this location, the threat of flooding was relevant to the likelihood of a release occurring on Respondent’s pipeline. Respondent did not evaluate the likelihood of a release caused by flooding of the Yellowstone River and failed to consider risk factors relevant to flooding. Accordingly, PHMSA finds Respondent violated § 195.452(i)(2) by failing to conduct a risk analysis of the Silvertip Pipeline that considered all risk factors relevant to the likelihood of a release on the Silvertip Pipeline and potential consequences affecting the Yellowstone River. [Order at page 12.]

This suggests that PHMSA may, in fact, be choosing Option D from my response to my friend King Fisher: d) actually enforcing integrity management obligations of operators to design for and mitigate against the risk of riverbed scour before an incident occurs.

Well, okay, technically, they haven’t yet enforced those obligations before an incident occurs as far as we know, but this is at least a start. Most importantly, it should certainly put every other operator on notice, whether they’ve had a flooding/riverbed scour/earth movement failure or not, that PHMSA will enforce the operators’ obligation to adequately assess those risks and to integrate sufficient preventive and mitigative measures into their integrity management programs to protect against failures. Unfortunately, PHMSA didn’t do that when they inspected the Silvertip a year or so before the Yellowstone rupture. When regulators enforce those obligations in routine inspections of integrity management programs independent of (and hopefully before) any incidents, that will indeed be good news.

Natural Gas Components, Transmission Line Leaks and Karst Topography

Smart Pig’s Question of the Week –

We were recently contacted by a resident of Virginia who wanted to know whether natural gas transmission lines leak, and particularly about how the methane and other constituents of transported gas might behave if a leak occurred in an aquifer associated with karst topography.

To best respond to his concerns, we’ve divided his questions up into smaller bits:

1) Do gas transmission lines leak?

2) How do we find out what else is in gas transmission lines in addition to methane?

3) How will gas behave when it is released by a leaking transmission line into an aquifer, specifically one in a karst landscape?

1. Do gas transmission lines leak?

Yes, gas transmission lines leak, but because of a variety of factors such as size of leak, weather conditions, how the gas might migrate and/or collect, and available ignition sources, leaks may or may not reach the right mixture with air to ignite. The natural gas in these types of pipelines is primarily methane which is lighter than air, so if there is a leak the gas rises in the atmosphere and dissipates, and is not typically a problem for groundwater contamination like other types of liquid pipelines and pipelines that carry liquid gases (ethane, propane, butane, etc.).

Emissions from all the different types of gas pipelines is a problem that has recently been recognized by the EPA and White House in relation to concerns over climate change. In general “leaks” from gas transmission lines are not the largest source of gas coming from such pipelines. Emissions from compressor stations, blow downs at valves, and releases associated with maintenance programs account for more gas released. If you are interested in the emission concerns that are starting to be highlighted nationally regarding climate change at our recent national conference we had representatives from a variety of groups talking about those issues. You can find video of some of those presentations here.

How long an operator can allow a leak to continue depends on its characteristics and whether it falls into a geographic area known as a “high consequence area” – usually a higher population area – where there are additional safety requirements with which operators must comply. See our next installation for a more detailed discussion of leak repair criteria.

2. How do we find out what else might be in natural gas transmission lines in addition to methane?

Interstate natural gas pipelines will typically only be transporting natural gas that is made up of a high percentage of methane. The specific ratio of gases will be set by the gas ‘quality’ tariffs that the company drafts. A maximum BTU/SCF (British Thermal Unit per standard cubic foot) quality tariff usually sets a maximum on the “richness” of heavier than methane gas components such as ethane, propane etc., that can be in the natural gas. The pipeline company wants to set quality standards for what is included in the natural gas so the end users can use it with the minimal amount of processing, and so it does not contain things that could damage the pipeline. As an example, here is a screenshot of the gas quality measurements from a Williams Transco pipeline that goes through Virginia.

Click for larger version

Click for larger version

You will see that at the Fredricksburg station, the “natural gas” was made up of about 95% methane, with a few other components (predominantly ethane and CO2) also included. You can find this info for the Transco pipeline at http://www.1line.williams.com/Transco/index.html  There are buttons on the left hand side of the page that will take you to the “gas quality” section. There you can choose between various tabs to see daily gas quality values and the actual gas quality tariff provisions. Most companies post their tariffs on their websites.

3. How will natural gas behave when it is released by a leaking transmission line into an aquifer, specifically one in a karst landscape?

Karst topography and landforms are created by the action of water on soluble rock types like limestone and gypsum. Karst is typified by sinkholes and caves.  Aquifers in karst topography can transport pollutants much more quickly than other aquifers, simply because there are frequently large cracks and caves through which the water can travel, rather than having to pass through less porous, less permeable rock types. One additional risk incurred by pipelines in these areas is that they must be engineered and maintained accounting for the possibility of rapid changes in the geologic stability of the route, as sinkholes and caverns can collapse quite quickly placing abnormal loads that can cause a pipeline to fail. Another additional risk is that leaked gas could migrate to a pocket in the rock or a cave where it could become trapped and eventually become an explosion hazard if it were to find an ignition source.

The methane being transported in a transmission pipeline will, if released, dissipate as a gas into the atmosphere, making its way through whatever soil or rock type the pipe is buried in. At the low concentrations present in natural gas, the ethane in the gas mixture tends to travel as a gas and not a liquid. If there were to be a transmission line leak, the ethane would release into the atmosphere as a gas, although because it is heavier than air, it will not dissipate as quickly as the methane. If a natural gas line were to leak into groundwater, the small percentage of ethane will tend to be carried with the methane and dissipate as a gas.