March 2016, Vol. 71, No. 3
Washington Watch
FERC Investigates Potential Overcharging At Four Pipelines
It is not unprecedented that the Federal Energy Regulatory Commission (FERC) investigates potential overcharging at pipelines, as it announced it was doing in late January. But it doesn’t happen very frequently, just three other times since 2009.
The agency announced on Jan. 21, that it will initiate Natural Gas Act Section 5 investigations of the rates charged by Tuscarora Gas Transmission Company, Empire Pipeline Inc., Iroquois Gas Transmission System LP and Columbia Gulf Transmission. The commission charged that each pipeline is collecting revenue substantially in excess of the pipeline’s actual cost of service, including a reasonable return on equity. FERC directed each pipeline to file a cost and revenue study within 75 days of the issuance date of that pipeline’s order. The commission also set each case for evidentiary hearings before a FERC administrative law judge.
The companies can use any data they wish to submit to argue the FERC’s calculations are in error. Karen Merkel, spokeswoman for Empire, an affiliate of National Fuel Gas Company, says, “We are in the process of reviewing the final order and intend to timely file the requested cost and revenue study as required in the order.”
Ruth Parkins, manager, public affairs, Iroquois Pipeline Operating Company, says the same thing, as does Jenna Palfrey at Tuscarora.
James Yardley, director of corporate communications for the Columbia Pipeline Group, to which Columbia Gulf belongs, states, “Our current rates were established in a recent rate case which was settled in 2011. Because of this recent rate review, we believe that Columbia Gulf’s existing rates are reasonable, particularly in light of the changing market conditions.”
Asked about the reference to “changing market conditions,” Yardley adds, “I am simply referring to the changing natural gas supply sources and demand centers and resulting pipeline flow dynamics.”
Changing market conditions can come into play in Section 5 investigations. That was the case in the investigation FERC initiated in 2009 in order to determine whether Northern Natural Gas Company was overcharging its customers. In that case, a group of customers, essentially taking Northern’s side, argued Northern’s field area revenues had dropped substantially since the 2008 period relied on by the Commission in the Nov. 19, 2009, Order initiating the Section 5 hearing. Northern had threatened to file a new section 4 rate case if FERC didn’t back off. The customer group feared new rates would outweigh any refunds they could obtain from the successful conclusion of the Section 5 investigation. They therefore pressed the FERC to drop the Section 5 investigation in return for Northern’s commitment to delay its Section 4 filing. The FERC complied.
Liquid Pipeline Safety Proposal Criticized From All Sides
Reaction to the Pipeline and Hazardous Materials Safety Administration (PHMSA) proposed rule (NPRM) tightening liquid pipeline safety regulations has run along predictable lines. The pipelines think the proposal is too expansive and expensive. The environmental community and some notable safety experts believe PHMSA should have gone further.
“We are greatly frustrated by the NPRM’s many deficiencies,” says Lois Epstein, Arctic program director at The Wilderness Society. “Our organizations are concerned that this very long rulemaking process did not produce a more substantial regulatory product.” Epstein submitted comments on behalf of a number of environmental groups.
Susan Ginsberg, vice president of crude oil and natural gas regulatory affairs, at the Independent Petroleum Association of America, is miffed about the PHMSA’s intention to extend reporting requirements to all gathering lines. This would require owners, whether onshore, offshore, regulated or not, to submit annual, safety-related condition and incident reports. She maintains this requirement exceeds PHMSA’s statutory authority.
Moreover the proposal is targeted at pipelines that, at most, have caused 1.9 percent of the reportable accidents in the last five years. She argues that the PHMSA cannot regulate gathering lines until it submits a report to Congress required by the Pipeline Safety Regulatory Certainty and Job Creation Act of 2011. PHMSA says it submitted that report in 2015. But it was essentially a compilation of existing regulations. Congress mandated an analysis of the sufficiency of existing regulation and the costs and benefits of additional regulation. “The May 8, 2015, study is merely a first step in that analysis and does not fulfill the congressional mandate,” argues Ginsberg.
But state regulators are onboard with heighten attention to gathering lines. Steve Allen, national chairman, National Association of Pipeline Safety Representatives, says NAPSR, whose members enforce liquid pipeline safety in 14 states, agrees with inclusion of all gathering lines under the reporting requirements.
PHMSA is also proposing to extend reporting requirements to gravity lines as well. Another proposal requires inspections of pipelines in areas affected by extreme weather, natural disasters and other similar events. All pipelines subject to the integrity management (IM) requirements would have to be capable of accommodating inline inspection (ILI) tools within 20 years, unless the basic construction of a pipeline cannot be modified to permit that accommodation. Leak detection systems would have to be installed on hazardous liquid pipelines in all locations. Criticism of this proposal focuses on the lack of standards for these leak detection systems. Pipeline repair criteria would be made stricter, too.
The proposed rule has a section which dictates pipelines take certain actions after “an extreme weather incident.” It suggests that pipeline inspections will be required if any of the specified weather events occur. The American Petroleum Institute (API) and the Association of Oil Pipe Lines (AOPL) argue the proposal does not take into account the nuances that accompany events such as hurricanes which range in intensity and the potential for damage. In some instances the particular design and construction characteristics might, in and of themselves, mitigate the exposure or risk.
A broader requirement would force operators to periodically assess pipelines outside of high consequence areas (HCAs). The big concern is pipelines would have to assess non-HCA pipeline segments with an ILI tool or “tools capable of detecting corrosion and deformation anomalies, including dents, cracks, gouges and grooves” at least once every 10 years. If a segment is not capable of accommodating an ILI tool, an operator could use an alternative assessment method, provided it gives prior notice to PHMSA and demonstrates that the alternative methodology renders “a substantially equivalent understanding of the pipeline’s condition in light of the threats that could affect its safe operation.” PHMSA proposes requiring use of ILI tools for non-HCA pipelines for all forms of potential pipeline anomalies, regardless of whether such issues are present in the pipeline.
This has caused pipeline executives to scratch their heads a little because companies are not required to use ILI on pipelines in HCAs. So why force them to use ILI outside HCAs? That view gets some support from NAPSR’s Allen, who feels that PHMSA should allow pressure testing in lieu of ILI. “Pressure testing may be more economical for operators with legacy piping with no material records or operating and maintenance records,” says Allen.
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