The Bulls and Bears Emerge at FERC Meeting - Rate Issues and LNG Dominate
As has been its pattern, on the day before its Open Meeting last week, FERC issued a press release announcing the pipelines from Wave 3 for which it was closing the review of the Form 501G, and announced a Section 5 investigation against one of those companies, Stagecoach Storage. As we discuss below, this leaves 16 of 129 pipelines still in limbo as to whether they will need to reduce their rates or else be subject to a Section 5 investigation by FERC. Notably, four of the remaining sixteen pipelines, TransCanada’s ANR Pipeline, Enbridge’s Algonquin Transmission, Boardwalk’s Texas Gas, and Equitrans, generate more than $250 million in annual revenue.
While the risk of a rate review for the majority of pipelines has wound down, FERC opened up a new risk to the rates charged by pipelines by announcing that it was soliciting comments on the methodology it should use to calculate a pipeline’s return on equity (ROE) in rate cases. As we discussed in Will FERC Surprise Pipelines Tomorrow by Ruling on its ITA and ADIT Guidance?, a key question on which FERC seeks input is whether it should extend to pipelines, both oil and gas, the method for calculating ROEs that it recently adopted for electric utilities in the Emera Maine case.
Finally, Commissioners LaFleur and Glick used their opening comments at the Open Meeting to somewhat rebut the pronouncement by Chairman Chatterjee that the Calcasieu Pass LNG decision had cleared the way for the remaining projects to be approved. Further LNG approvals may still have to wait for the appointment of a fifth commissioner.
Pipelines Still in Limbo
While there are 25 pipelines that have yet to hear that their 501G form has been accepted as filed, we view nine of those pipelines as not being at a substantial risk for a rate reduction for one of two reasons -- they either voluntarily filed to reduce their rates as part of the 501G process, or they have a moratorium in place that prohibits changes to their rates until after the end of this year.
In the chart set forth below, we array the remaining 16 pipelines along two key measures that we believe FERC is using to determine which pipelines should be subjected to a Section 5 rate proceeding: the percentage of revenue generated under cost of service rates and the size of the indicated rate reduction reflected in the Form 501G. We believe that a pipeline’s risk of a rate investigation increases as compared to others when it is closer to the upper right corner of the chart (i.e., pipelines with higher than average Rate Reductions, and Recourse Rates approaching 100%). While it is unclear when FERC may act on these remaining pipelines, Chairman Chatterjee did note in his opening remarks that FERC is poised to take prompt action in the remaining cases. Of these 16 pipelines, all but Columbia Gulf encountered protests in response to their decision to not adjust their rates after filing their Form 501G.
Three of the five pipelines that are closest to the upper right corner of the graph, National Fuel Gas Supply Corporation, Paiute Pipeline, and Tallgrass Interstate, will be required to file a rate case this year under the comeback provisions of a previous settlement agreement, and two others, TransCanada’s Columbia Gulf Transmission and ANR Pipeline, both have moratoriums that end later this year. Although the comeback provisions in their settlements don’t require filing a rate case until 2020 and 2022, respectively, they may be under pressure to do so earlier. In particular, ANR Pipeline may opt to file, as it is also one of the remaining pipelines close to the upper right corner of the chart.
FERC Launches New Policy Review
At its Open Meeting, FERC announced that it was issuing a Notice of Inquiry (NOI) regarding its methodology for setting the ROEs for public utilities under the Federal Power Act and whether it should use the same methodology for natural gas and liquids pipelines. FERC is giving parties 90 days to provide comments on eight general topics:
- How FERC’s base ROE impacts investment decision-making and what objectives should guide the Commission’s approach;
- Whether FERC should apply the same methods for calculating base ROE across the electric, interstate natural gas pipeline and oil pipeline industries;
- How the Discounted Cash Flow (DCF) model has performed;
- How FERC should establish proxy groups;
- What financial models other than DCF should be used;
- Whether there is a mismatch between market-based ROE determinations and book-value rate base;
- How FERC should determine whether an existing ROE is unjust and unreasonable;
- If FERC adopts new models, what are the appropriate mechanics for implementing such new models.
The NOI has not yet been published in the Federal Register, but once it is, interested parties will have 90 days to provide FERC with comments. As we have seen with other recent NOIs (e.g., the April 2019 “Certification of New Interstate Natural Gas Facilities”), there is no requirement FERC ever act on the comments it receives and certainly no no time limit on when it takes any action. We intend to provide our view on the comments once they are filed.
Mixed Signals from Commissioners and A Renewed LNG Project
Since this past summer, the Commission has sent mixed signals to the LNG industry. For example, in our first Insights on this topic, Second Wave LNG Schedules Trumpeted by FERC - Smooth Sailing Ahead?, we discussed that, despite the blanket release of environmental schedules for Second Wave LNG projects, risks remained due to the potential split at the Commission, as Commissioners Glick and LaFleur have generally taken stances that require a more rigorous assessment of project need and an analysis of the impact on greenhouse gas emissions. Following the last Open Meeting in February, when FERC issued the certificate order for the Calcasieu Pass LNG export terminal, the signal seemed bullish for the industry. In fact, Chairman Chatterjee even went so far as to issue a press release in conjunction with the issuance of that certificate in which he stated that the decision was significant. According to the chairman, he believed that the framework developed in that order would allow the Commission to move forward to evaluate the other pending LNG certificates. The celebration, however, may have been premature.
Commissioner LaFleur used her opening comments to explain her continuing concerns that FERC is not treating climate impacts the same way as it treats all other cumulative impacts, and indicated that she thought the current path was unsustainable and likely to be overturned by a court. Commissioner Glick then used his opening comments to rebut the perception that the Calcasieu order was a breakthrough, because, as he stated, it “was anything but”. Therefore, as we discussed in Eleven Projects Caught in the Climate Change Crossfire: FERC and DC Circuit, projects may not move forward until there is a fifth commissioner, as Commissioner LaFleur holds a critical vote, which she may be withholding on certain projects.
Another challenge, this time from the market, occurred earlier this week when Shell and Energy Transfer signed an agreement to be 50/50 owners to develop the Lake Charles LNG import terminal to a large-scale LNG export facility. The agreement, which is described as a “framework,” may resuscitate interest in a project filed five years ago. If it progresses, it could put additional pressure on second wave LNG developers, already competing in a crowded market, because the Lake Charles project would offer low cost LNG supply since the dock, tanks and pipeline are all in place. The project would also presumably benefit from the fact that it has received all permits, including the FERC certificate. Nonetheless, the FID decision remains subject to an assessment of the EPC bidding process, project competitiveness and global LNG market conditions at the time of that decision.
Insights Coming Soon
- MXP/GXP Contract analysis on risk sharing and costs of projects
- Open season to filing timelines