The Federal Energy Regulatory Commission (FERC) is investigating the possibility that two interstate pipelines are charging unreasonable rates. The FERC opened mid-November investigations of Kinder Morgan Interstate Gas Transmission LLC and Ozark Gas Transmission LLC, a unit of Spectra Energy Partners LP., based on reviews of Form 2 cost of service and revenue information submitted by the companies for 2008 and 2009.
None of the FERC commissioners gave any indication they were beginning to look closely at pipeline rates more broadly, and that these two investigations were the front end of a longer string of upcoming cases. However, Chairman Jon Wellinghoff noted that the Kinder Morgan and Ozark investigations come one year after FERC initiated a Section 5 rate case against three interstate pipelines.
“Two of those proceedings have since resulted in uncontested settlements that provide significant benefits, such as reduced rates, reduced fuel retention factors, and, in one case, a revenue-sharing arrangement with pipeline customers,” he stated. FERC dropped the third case against MidAmerican Energy Holdings Co.’s Northern Natural Gas pipeline when public service commissions in Northern’s service area argued consumers would be hurt if FERC acted against Northern.
FERC calculated Kinder Morgan’ estimated return on equity for 2008 at 27.10% and 29.25% for 2009, inclusive of the dollar value of excess fuel retained by the company. When the dollar value of the excess fuel retained by the company is excluded, Kinder Morgan’s estimated return on equity for 2008 is 15.69%% and 17.81% for 2009.
From Ozark’s 2008 and 2009 Form 2 reports, FERC staff calculated its estimated return on equity, inclusive of revenues received from sale of shipper-supplied gas, to be 27.81% for 2008 and 31.01% for 2009. When revenue from the sale of shipper-supplied gas is excluded, FERC stimates the company’s return on equity to be 15.25% for 2008 and 25.63% for 2009.
Kinder Morgan and Ozark produced general statements after the probes were announced. KMIGT noted the FERC staff bears the burden of proving that Kinder Morgan’s rates are no longer just and reasonable. The company seemed to also be preparing for the worst. Referring to the possibility FERC would find its rates unreasonable, it said: “If there is a change in rates, typically the rates are changed from the point of the decision moving forward, rather than a refund to customers.”
Gregory J. Rizzo, president and CEO, Spectra Energy Partners, LP, pointed out that Ozark did benefit in 2009 from an opportunity to transport additional natural gas volumes due to another pipeline company being offline, which increased annual revenues. He said the company expected lower projected revenues in 2010 and a potential reduction in its revenues in 2011 of up to $10 million, related to increased competition from new pipelines and expiring contracts.
PHMSA Rejects INGAA Pleas On New Safety Reporting
New pipeline safety reporting requirements went into effect on Jan. 1 although implementation was delayed for some of the changes. Gas and hazardous liquid lines now must report an unintentional release of gas that results in an estimated gas loss of 3,000 Mcf or more. That represents a setback for INGAA which sought a 20,000 Mcf threshold. In addition, each operator of a gas pipeline, gas pipeline facility, LNG plant or LNG facility must obtain from PHMSA an Operator Identification Number (OPID) by Jan. 1, 2012. Many pipelines already have OPIDs which will be used by PHMSA to create a new National Registry of Pipeline and LNG Operators.
The most controversial issue in the rulemaking was PHMSA’s desire to expand the definition of “incident” to include unintentional leaks of 3,000 Mcf of gas. The key elements in the current and longstanding requirement are a leak causing more than $50,000 in damage, a death or deemed significant by the operator. Intentional releases of gas have to be reported if they result in death, inpatient hospitalization, or $50,000 in property damage. Transmission or gathering pipeline operators must submit DOT Form PHMSA F 7100.2 as soon as practicable but not more than 30 days after detection of an incident.
INGAA had argued in 2009, after the PHMSA put out a proposed rule, that the 3,000 Mcf threshold would cause its members to file incident reports for a significant number of the low-risk pinhole and fitting leaks, which are disclosed in the annual report. “The number of incident reports, and the cost of reporting, will increase sharply, and the incident database, which has proven useful in policy analysis and development, will lose its continuity,” argued Dan Regan, INGAA’s regulatory attorney and Terry Boss, senior vice president for environment, safety and operations.
The reporting changes imposed on pipelines result from recommendations from the National Transportation Safety Board, Government Accounting Office and Section 15 of the PIPES Act of 2006.
On the requirement to obtain an OPID, companies that already have them are required to validate the information in PHMSA’s records currently associated with those OPIDs by June. Operators who don’t have an OPID must get one by Jan. 1, 2012. Once the OPID is obtained, operators have to notify PHMSA, through the registry, of certain changes that affect the facilities associated with the OPID. That has to be done at least 60 days before the change occurs. Those changes include construction of 10 or more miles of a new pipeline. Some changes have to be acknowledged through the Registry within 60 days after they happen. That would be, for example, acquisition or divestiture of 50 or more miles of a pipeline.
INGAA had pressed for a requirement that would have pipelines report annually to the Registry, not whenever relevant changes were made during the year.
PHMSA Wants To Move Forward Deadline For Control Room Management
Interstate pipelines think some aspects of PHMSA’s proposed “speed-up” of its new pipeline controller safety requirements are irresponsible. PHMSA issued the final control room management rule in December 2009. Pipelines were to have developed programs by Aug.1, 2011 and implemented them by Feb. 1, 2013.
On Sept.17, 2010, PHMSA said it wants to expedite the program implementation deadline to Aug., 2011 for most of the requirements. It believes “most of the effort to comply with many of the provisions will have already been completed by the Aug. 1, 2011.”
Very few companies agree with that assessment. Most interstate and intrastate pipelines agree that the control room management rule is perfectly fine…with its original deadlines. Almost no one thinks moving the implementation deadline up to Aug. 1, 2011 is a good idea. Count Patrick Carey, director of DOT compliance services with El Paso Pipeline Group, in the skeptic category. He says the industry will be hiring about 200 controllers to comply with the new shift length, rotation and hour of service limitations in the final rule. Training them will take time and will not be complete by Aug. 1, 2011, Carey states. He says El Paso can support an expedited implementation schedule, not the one PHMSA suggests.
Industry concerns were aired at a workshop PHMSA held in November. The agency said it expected to put out guidance on compliance with the final rule in the first quarter. John Heer, director, gas control/peak shaving, CenterPoint Energy Resources Corp., says important questions were raised though not answered. He explains operators could have as little as four months after the guidance is published to implement the final rule, if PHMSA sticks to the Aug. 1, 2011 date. That would “compromise the quality of operators’ programs,” Heer says.