May 2012, Vol. 239 No. 5
Government
PHMSA Proposes Metrics For State Damage Prevention Laws
The Pipeline Hazardous Materials and Safety Administration (PHMSA) took the next step in its, so far, six-year effort to step in when states fail to punish excavators who damage pipelines.
The 2006 PIPES Act gave PHMSA the authority to take civil enforcement action against excavators in states whose damage prevention laws are weak. But first, PHMSA has to define “weak.” The proposed rule PHMSA issued April 2 describes some of the “metrics” it might use in making that determination.
If PHMSA decides a state “fails to enforce” Section 2 of the PIPES Act it can take civil enforcement action against excavators who: 1) fail to use a state’s one-call notification system, 2) disregard location information or markings established by a pipeline, or fail to report excavation damage promptly.
The metrics PHMSA wants to use in making a “fail to enforce” decision might include determining whether a state is imposing civil penalties at levels sufficient to ensure compliance, whether an adequate damage reporting system is in place, the quality of the state investigations related to excavation accidents and whether the state law mandates use of a one-call system by excavators and requires immediate reporting of damage.
A big issue, from the standpoint of the pipeline industry, is the exemptions from one-call systems often offered on a state-by-state basis. The Pipeline Security, Job Creation, and Regulatory Certainty Act of 2011, passed unanimously by Congress and signed into law by the president in January, said state damage prevention programs should not exempt agencies of state and local governments, public works departments, for example, from calling damage prevention hotlines before excavating, and required a study of the threat to safety caused by other one-call exemptions. The proposed rule issued by PHMSA does not require states, cities and counties to eliminate other one-call exemptions.
Pipelines, Electric Utilities To Duel Over Reliability And Integration; Rate Structure At Issue
Federal Energy Regulatory Commission (FERC) policies on pipeline rates built around “firm” capacity may be up for grabs as the Commission wades into the issue of increasing dependence by electric utilities on natural gas. Electric utilities most often depend on cheaper “interruptible” service which can leave them vulnerable during times of peak needs. Those peak needs become more of a concern as generators move toward decommissioning coal-fired units in the face of Environmental Protection Agency restrictions and build new natural gas units, incentivized by the floods of low-cost natural gas from shale finds washing over the U.S.
Issues of pipeline rates and supply reliability are arising at FERC because of a docket started based on a workshop held last February. Commissioner Philip Moeller is leading the effort to determine what, if anything, the FERC should do to encourage pipeline/utility integration and assure reliability, the latter issue most recently raised by events during the Southwest cold weather event in early 2011. He was joined by Commissioner Cheryl LaFleur who issued a statement seeking comments on, besides interdependence and reliability issues generally, new pipeline and storage service and pricing structures that might better meet the emerging needs of generators.
There is no question electric utilities have been switching to natural gas over the past decade, a trend that has picked up considerably in the last few years. The Edison Electric Institute reports that at the end of 2010, natural gas-fired generators constituted 41% of the nation’s total electric generation capacity of 1,135 gigawatts (GW) and that nearly 277 GW of natural gas-fired generation capacity was added between 2000-2010, representing 82% of total generation capacity additions over that period.
“A series of Environmental Protection Agency rulemakings is likely to force the replacement of 12,000 MW of coal-fired generation in the Midwest ISO footprint in the next few years. This, in turn, may require construction of significant infrastructure to bring natural gas supplies to the new generation fleet,” says Gregory A. Troxell, assistant general counsel, Midwest Independent Transmission System Operator, Inc., (MISO). “Combine this with the recognition that when MISO’s reliability and operations service territory responsibilities extend into the Entergy region and require focus on the Gulf Coast as well as Midwest supply and delivery dynamics, natural gas coordination will become paramount.”
The concerns about fast-increasing utility dependence on natural gas are that there is generally no natural gas storage close to utilities. So, at peak times, mostly during the summer, the utilities have to contract for expensive “interruptible” service at the last moment. They could, of course, contract up front for more expensive “firm” service, but the utilities have nowhere to store the gas they don’t use so that it would be available during a summer peak period.
Joan Dreskin, general counsel at INGAA, says, “It is not a reflection on the reliability of natural gas or the natural gas pipeline infrastructure when a pipeline has scheduled its firm customers’ nominations and has no capacity left to schedule lower priority, cheaper, interruptible transportation.”
The Regional Transmission Organizations (RTOs) and Independent System Operators (ISOs), which run most of the regional electricity distribution markets, point out that the current framework of Commission-jurisdictional pipeline services and rates were developed chiefly with the needs of local gas distribution companies (LDCs) in mind. LDC demand for natural gas generally peaks in the winter, concurrent with the home-heating season, while electric load normally peaks in the summer. LDCs have an “obligation to serve” imposed by state laws and regulations and earn revenues governed by traditional cost-of-service ratemaking.
Merchant electric generators have a different set of obligations and economic incentives. It is possible that more flexible pipeline services, such as hourly gas flows or “park and loan” services utilizing existing pipeline infrastructure will better meet the needs of gas-fired generation. “Participants in organized markets face competitive pressures and other requirements that may make the traditional firm and interruptible gas services, at best, a very imperfect match for their needs,” says Andrew Ulmer, director, Federal Regulatory Affairs, California Independent System Operator Corporation. “Making new types of service available may thus be especially valuable to the electricity markets in these regions.”
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