FERC on January 21 announced it will initiate Natural Gas Act section 5 investigations of the rates charged by four interstate natural gas pipelines to determine if the companies may be substantially over-recovering costs, resulting in unjust and unreasonable rates. The Commission will investigate the rates of Tuscarora Gas Transmission Co. (RP16-299), Empire Pipeline, Inc. (RP16-300), Iroquois Gas Transmission System, LP (RP16-301) and Columbia Gulf Transmission, LLC (RP16-302). The Commission had reviewed the cost and revenue information provided by the companies in their filings of FERC Form No. 2, the Annual Report for Major Natural Gas Companies, and FERC Form No. 2-A, Annual Report for Non-Major Natural Gas Companies, for 2013 and 2014. Based on this review, the Commission became concerned that each company 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. The Commission also set each case for evidentiary hearings before a FERC administrative law judge, with a deadline.
In a statement posted on its website, after FERC’s order issued, the Natural Gas Supply Association’s (NGSA) president and CEO Dena declared that the gas suppliers are “pleased that FERC continues to be committed to ensuring just and reasonable pipeline rates. Natural gas suppliers and other pipeline customers look to FERC for protection from excessive pipeline charges and we are gratified that FERC has chosen to initiate these Section 5 investigations.”
Wiggins added, “Legislation that reforms Section 5, granting FERC the authority to award refunds to shippers in cases where pipelines are determined to have overcharged, would further enhance consumer protections since currently FERC can only order an over earning pipeline to lower its rates going forward from the date of the Commission’s order. Now that FERC has adopted a new modernization surcharge policy that grants interstate pipelines new opportunities to recover costs outside of a general rate case, Section 5 reform is more important than ever,” her statement concluded.
Columbia Gulf. In Columbia Gulf’s case, the company’s current rates are the result of a settlement agreement that grew out of its last NGA general section 4 rate case, which was approved on 12/1/11. That settlement provided that neither Columbia Gulf nor any other settling party would seek to modify Columbia Gulf’s base rates before 4/1/14 and required Columbia Gulf to file a cost and revenue study no earlier than 4/1/14 and no later than 5/1/17. Columbia Gulf is currently under no obligation to file a new rate case at any time in the future beyond its settlement obligation to file a cost and revenue study.
Columbia Gulf’s interstate natural gas pipeline system consists of approximately 3,400 miles of pipeline and 11 compressor stations with nearly half a million horsepower, located primarily in Louisiana, Mississippi, Tennessee, and Kentucky. Columbia Gulf is “interconnected to virtually every major pipeline system in the Gulf Coast,” the Commission’s order noted.
FERC recently approved Columbia Gulf’s Cameron Access Project, which includes improvements to existing pipeline and ancillary facilities near Lake Arthur, Louisiana, and the installation of a new pipeline in Cameron Parish to provide for additional market access to the Cameron LNG Terminal. The pipeline is approved to roll the project’s fuel into its system-wide retainage percentages and to assess its generally applicable system-wide fuel retainage percentages. “It is anticipated that this project will add additional capacity and revenue to the system after the anticipated in-service date in the spring of 2018.”
Based upon a review of the cost and revenue information contained in Form 2 filed 2013-2014, the Commission estimates Columbia Gulf’s return on equity for those calendar years to be 17.3% and 18.2%, respectively. That leads to a concern that Columbia Gulf’s level of earnings may substantially exceed its actual cost of service, including a reasonable return on equity.
Specifically, for 2013, the Commission calculated Columbia Gulf’s 2013 cost of service to be $105.62 million, excluding equity return and related income taxes. Next, the Commission compared this estimated cost of service to Columbia Gulf’s 2013 Form 2 reported revenues, as adjusted, of $141.20 million. The difference between the reported adjusted revenues and the estimated cost of service is $35.58 million, before income taxes. After taking into consideration income taxes, Columbia Gulf’s equity return totals approximately $21.90 million for 2013 — which equates to an estimated return on equity of 17.3%.
An identical analysis of the next year’s Form 2 (2014) “generated a similar estimated return on equity.” Columbia Gulf’s cost of service for 2014 came to be $108.87 million, exclusive of equity return and related income taxes. Columbia Gulf’s 2014 Form 2 reported revenues, as adjusted, total $151.69 million. The difference between reported adjusted revenues and the estimated cost of service is $42.82 million, before income taxes. After taking into consideration taxes, Columbia Gulf’s equity return totals approximately $26.36 million for 2014 — an estimated return on equity of 18.2%.
Columbia Gulf does not appear to have adjusted its system’s rates since its most recent settlement was approved in 2011. Accordingly, the investigation will examine the justness and reasonableness of Columbia Gulf’s rates. The cost and revenue study that is required “will provide a baseline of actual annual costs and revenues, which can then be used as a starting point for further analysis of Columbia Gulf’s costs and revenues.”
Among other admonitions to the ALJ, the Commission directed that the initial decision in the Columbia Gulf case, as well as the others reviewed below, must issue within 47 weeks of the date the cost and revenue study is due.
Iroquois. Iroquois owns pipeline facilities extending from the U.S.-Canadian border at Iroquois, Ontario, and Waddington, New York, through New York State, western Connecticut, and under the Long Island Sound to South Commack, New York, and then extending back under the Sound to a terminus at Hunts Point in the Bronx. According to the Commission, Iroquois does not appear to have adjusted its system’s rates since its most recent section 4 rate case settlement, which was approved on 10/13/04, more than 11 years ago.
On 12/2/14, the Commission approved a certificate for Iroquois to construct the Wright Interconnect Project in conjunction with the proposed Constitution Pipeline Co., LLC. The Wright Interconnect consists of new compression facilities to enable delivery of up to 650,000 dth/d of natural gas from the terminus of Constitution’s pipeline in Schoharie County, N.Y. into both Iroquois and the Tennessee Gas Pipeline Co. LLC under a 15-year capacity lease agreement with Constitution. Iroquois will lease the new capacity created on its system by the additional compression to Constitution. Constitution’s monthly lease payments to Iroquois would cover the full cost of the project.
Based upon the information provided by Iroquois in its Form 2 for 2013, Iroquois’s 2013 cost of service amounted to $110.16 million, excluding equity return and related income taxes. Comparing Iroquois’s 2013 cost of service to 2013 Form 2 adjusted revenues of $199.69 million, the difference between Iroquois’s adjusted reported revenues and the estimated cost of service is $89.54 million, before income taxes. After taking into consideration income taxes, Iroquois’s equity return of approximately $54.03 million for 2013 equates to an estimated return on equity of 16.2%.
An identical analysis of the pipeline’s 2014 Form 2, generated a similar estimated return on equity. The Commission calculated Iroquois’s cost of service for 2014 to be $111.03 million (excluding equity return and related income taxes) and its reported revenues, as adjusted, to total $199.89 million. The difference between Iroquois’s adjusted reported revenues and the estimated cost of service is $88.87 million, Iroquois’s estimated return totals approximately $55.63 million for 2014, and this equates to an estimated return on equity of 16.3%.
As in the other pipeline cases recited here to be subject to investigation, the Commission believes that conducting the hearing pursuant to the Administrative Law Judges’ Track II Hearing Timeline is reasonable. The Commission ordered that the deadlines in the timeline run from the date the pipeline’s cost and revenue study is due, rather than the date of the order designating the presiding judge. Therefore, the initial decision must issue within 47 weeks of the date the cost and revenue study is due.
Empire Pipeline. Empire, an affiliate of National Fuel Gas Co., started operations as a non-jurisdictional Hinshaw natural gas pipeline in 1993, transporting natural gas imported from Canada to locations within the state of New York. In 1995, the Commission granted Empire a limited jurisdiction certificate to perform interstate service pursuant to open access requirements of section 284 of the regulations. Then in 2006, the Commission issued Empire an NGA section 7 certificate to expand to an interconnection with Millennium Pipeline, and Empire thus become a natural gas company subject to the Commission’s Natural Gas Act jurisdiction.
In 2011, the Commission authorized Empire to construct the Tioga County Extension Project, which expanded Empire’s system south to Jackson, Pennsylvania. That expansion enabled Empire to provide bi-directional transportation service, so that it can both transport Canadian natural gas south from the Canadian border and Marcellus shale production north from Pennsylvania. Empire was granted a predetermination that it could roll in the costs in its next section 4 rate case. However, the Commission denied a request that Empire be required to file a cost and revenue study within three years of the in-service date of the project. Empire has not filed a rate case since it became subject to the Commission’s NGA jurisdiction, nor is it currently under any obligation to file a new rate case at any time in the future.
Based upon its review so far, the Commission estimates Empire’s return on equity to be 15.8% and 20.2% in 2013 and 2014, respectively. The Commission calculated Empire’s 2013 cost of service to be $35.66 million (again, excluding equity return and related income taxes). The estimated revenues, as adjusted, was $76.38 million. The difference is $40.72 million before income taxes, translating to equity return totals of approximately $24.59 million for 2013, or 15.8% rate of return.
For 2014, the Commission calculated Empire’s cost of service for 2014 to be $34.43 million; the Form 2 reported revenues, as adjusted, total $81.82 million; and the difference is $47.39 million before income taxes. Empire’s equity return totals approximately $28.62 million, or an estimated return on equity of 20.2% in 2014.
Tuscarora. Tuscarora Gas Transmission Co. also finds itself in the investigation and hearing pool. Tuscarora operates a 229-mile pipeline system in Nevada and northwestern California that serves public utility companies, electric generators, municipalities, casinos, and industrial facilities. Its facilities extend from an interconnection with Gas Transmission Northwest, LLC near Malin, Oregon, to a terminus near Wadsworth, Nevada, where Tuscarora interconnects with Paiute Pipeline Co.
In 2006 Tuscarora filed a prepackaged uncontested settlement agreement resolving all issues with its customers and the Public Utilities Commission of Nevada (PUCN) concerning Tuscarora’s firm and interruptible transportation rates. The settlement set rates were for the period 6/1/06 until 5/31/10. In 2012, the PUCN and various shippers filed a complaint (RP11-1823) against Tuscarora’s rates and that complaint was set by the Commission for hearing under NGA section 5. A settlement approved in March 2012 included a rate reduction and a rate case moratorium through 12/31/14. Tuscarora’s rates have not been re-examined since the settlement, nor is Tuscarora currently under any obligation to file a new rate case in the future, according to the instant order.
The Commission estimates Tuscarora’s return on equity for 2013 and 2014 to be 23.6% and 24.9%, respectively. The Commission calculated Tuscarora’s 2013 cost of service to be $12.42 million (excluding equity return and related income taxes), and compared that result to Tuscarora’s 2013 Form 2 reported revenues, as adjusted, of $27.64 million. The difference $15.22 million, after taking into consideration income taxes, confers an equity return totaling approximately $9.69 million for 2013 or estimated return on equity of 23.6%.
Tuscarora’s cost of service for 2014 was similarly calculated to be $11.89 million. Its 2014 Form 2 reported revenues, as adjusted, total $27.53 million. The difference between Tuscarora’s reported adjusted revenues and the estimated cost of service is $15.63 million, before income taxes. After taking into consideration income taxes, Empire’s equity return totals approximately $9.62 million — an estimated return on equity of 24.9%.
 As other recent section 5 proceedings, in addition to the cost and revenue study required, Columbia Gulf may file a separate cost and revenue study that reflects adjustments for changes Columbia Gulf projects will occur during an abbreviated six-month adjustment period following the 12-month base period used for the cost and revenue study.
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