Month: July 2019

FERC Streamlines Processes for Market-Based Sellers

FERC Streamlines Processes for Market-Based Sellers

The Federal Energy Regulatory Commission (FERC) has finalized a set of rules to help “ease the regulatory burden for electric power sellers with market-based rate authority,” while making sure that FERC keeps preventing the “potential exercise of market power.”

The first rule “concerns the horizontal market power analysis required for market-based rate sellers.” They have eliminated the “obligation to submit indicative screens in order to obtain or retain market-based rate authority in certain organized wholesale power markets.” The sellers will not have to “submit the pivotal supplier screen and the wholesale market share screen in any organized wholesale power market that administers energy, ancillary services, and capacity markets subject to Commission-approved monitoring and mitigation.”

In the organized markets that “do not administer capacity markets” with the FERC approved monitoring and mitigation, “that is the Southwest Power Pool and California Independent System Operator, market-based rate sellers will be required to submit analyses if they wish to sell capacity there. All market-based rate sellers still would be required to file a vertical market power analysis as well as an asset appendix, which provides comprehensive information relevant to determine a seller’s market power and ensure just and reasonable rates.”

The second rule FERC finalized will help improve their “monitoring of wholesale power markets by streamlining the way it collects certain data for market-based rate purposes, specifically collecting this information in a database. The approved changes will eliminate duplication, minimize compliance burdens, modernize data collections, and make information collected through its programs more usable and accessible for the Commission, its staff, and the public.” One of the main things this rule does is adopt changes to help “reduce and clarify the scope of ownership information that sellers must provide as part of their market-based rate filings, revises the information required in a seller’s asset appendix as well as the format through which such information must be submitted, and eliminates the requirement that sellers submit corporate organizational charts.”

FERC issued a Notice of Proposed Rulemaking about this in July 2016, proposing to “collect connected entity data from market-based rate sellers and entities that trade virtual products or hold financial transmission rights;” the final rule did not adopt that proposal.

The first rule will go into effect 60 days after it is published in the Federal Register.

The second rule will go into effect on October 1, 2020.

FERC Commissioner Richard Glick issued a statement dissenting the second rule and explaining his choice to do so.

Glick said that while he does support some aspects of the rule “that streamline collection of the data needed to regulate market-based rates by creating a relational database and revising certain information requirements.” He noted that he dissented because FERC “is declining to finalize a critical aspect of the underlying notice of proposed rulemaking that would have required Sellers and entities that trade virtual products or that hold financial transmission rights (Virtual/FTR Participants) to report information regarding their legal and financial connections to various other entities.” He said that this “information is critical to combatting market manipulation and the Commission’s retreat from the NOPR proposal will hinder our efforts to detect and deter such manipulation.”

Glick explained that the context is important in policing market manipulation, and “a transaction that seems benign when viewed in isolation may raise serious concerns when viewed with an understanding of the relationships between the transacting parties and/or other market participants. Unfortunately, information regarding the legal and contractual relationships between market participants is not widely available and may, in some cases, be impossible to ascertain without the cooperation of the participants themselves.  That lack of information can leave the Commission in the dark and unable to fully monitor wholesale market trading activity for potentially manipulative acts.”

The problem is more acute, Glick explained, “when it comes to market participants that transact only in virtual or FTR products.  Virtual/FTR Participants are very active in RTO/ISO markets and surveilling their activity for potentially manipulative acts consumes a significant share of the Office of Enforcement’s time and resources.” He said it may be somewhat surprising that FERC collects “limited information about Virtual/FTR Participants and often cannot paint a complete picture of their relationships with other market participants.” FERC also has “no mechanism for tracking recidivist fraudsters who deal in these products and perpetuate their fraud by moving to different companies or participating in more than one RTO or ISO.  And, perhaps most egregiously, the Commission’s current regulations do not impose a duty of candor on Virtual/FTR Participants, meaning that bad actors can lie with impunity, at least insofar as the Commission is concerned. The abandoned aspects of the NOPR would have addressed all three deficiencies, among others.”

There can be consequences to having those deficiencies, Glick said, citing a recent example of a FERC order of “how an individual involved in one manipulative scheme was able to move, rather seamlessly, to allegedly perpetuate a similar scheme at another entity.” FERC “issued an Order to Show Cause with an accompanying report and recommendation from the Office of Enforcement that detailed how Federico Corteggiano allegedly engaged in a cross-product market manipulation scheme in the California Independent System Operator’s (CAISO). As described in that order, this alleged scheme used techniques that were similar to another manipulative scheme involving Corteggiano while he was employed at Deutsche Bank. Without the Connected Entity reporting requirements contemplated in the NOPR, the Commission lacks any effective means of tracking individuals who perpetrate a manipulative scheme at one entity and then move locations and engage in similar conduct elsewhere, as Corteggiano is alleged to have done. That makes no sense. We should not be leaving the Office of Enforcement to play ‘whack-a-mole,’ addressing recidivist fraudsters only when evidence of their latest fraud comes to light.”

Glick also used the example of “GreenHat Energy, LLC’s (GreenHat) default on its FTRs in PJM Interconnection, L.L.C. (PJM), at least as it is described in an independent report prepared for PJM’s Board.” In the report, there are allegations that “GreenHat told PJM it had bilateral contracts that would provide a future revenue stream, alleviating the need for additional collateral. 10   The report further contends that PJM mistakenly relied on GreenHat’s representations and the contracts in question did not provide the promised revenue stream, significantly exacerbating GreenHat’s collateral shortfall.” He said that under the current regulations, “no duty of candor attached to GreenHat’s allegedly misleading statements.  It is, of course, impossible to know how a duty of candor for Virtual/FTR Participants would affect potential misstatements.  But, if there were a duty of candor for Virtual/FTR Participants, it would give the Commission a basis for investigating potentially misleading statements and, if appropriate, sanctioning that conduct.”

Glick said that while FERC “does not dispute the benefits that the Connected Entities Information would provide, it ‘declines to adopt’ this aspect of the NOPR without any real analysis or explanation and based only on its ‘appreciat[ion]’ of the ‘difficulties of and burdens imposed by this aspect of the NOPR.'” There is nothing to suggest in the record that the associated burdens this reporting obligation may cause would outweigh the benefits. The Notice initially “paired back the scope of Connected Entity Information compared to the previous NOPR addressing this issue.” He believes that FERC “could have further explored ways to limit the impact of this rule if it were truly concerned about that burden by, for example, eliminating the inclusion of contracts for defining connected entities, which received strong pushback from industry.  Alternatively, the Commission could have established a phased-in implementation schedule to provide industry time to adjust to the new reporting requirements.”

Instead, FERC made a “conclusory statement based on an unspecified burden to industry.  It makes no effort to explain why that burden outweighs the benefits that Connected Entities Information would provide to the Commission’s ability to carry out its enforcement responsibilities.  Without such information, the predictable result of today’s order is that market participants are more likely to find themselves subject to a manipulative scheme than if we had proceeded to a final rule on these aspects of the NOPR.”

Glick said that one of FERC’s chief priorities should be “identifying, eliminating, and punishing market manipulation,” which it has been since 2005 when “Congress vested the Commission with that responsibility” when amendments were made to the “FPA in the wake of the Western Energy Crisis. In addition to the financial losses directly attributable to a particular instance of fraud, market manipulation erodes participants’ confidence in wholesale electricity markets—a dynamic that has serious deleterious consequences for the long-term health and viability of those markets.” He said he can “appreciate the importance of avoiding unnecessary regulatory burdens, the record in this proceeding indicates that the Connected Entity Information is necessary and would, in the long-term, benefit all market participants, including those subject to the regulations, by helping to ensure confidence in the integrity of wholesale electricity markets.”

The Importance of Properly Winterizing Electric Generation Facilities

The Importance of Properly Winterizing Electric Generation Facilities

The Federal Energy Regulatory Commission (FERC) and North American Electric Reliability Corporation (NERC) released a report to stress “the need for generation owners and operators to adequately prepare for winter weather conditions to ensure bulk electric system reliability.”

Abnormally low temperatures on January 17, 2018, led “regional operators in the Midwest and South Central U.S. (MidContinent Independent System Operator and Southwest Power Pool)” to call for voluntary reductions in electricity use. The system managed to stay stable during this cold front. “However, continued reliable operation would have required shedding firm load if MISO had experienced its largest single generation contingency in MISO South.”

The report found that “despite prior guidance from FERC and NERC, cold-weather events continue to result in unplanned outages that imperil reliable system operations.” The report recommends the creation of “one or more mandatory Reliability Standards requiring generator owner/operators to prepare for the cold weather and provide information about those preparations to their Reliability Coordinators and Balancing Authorities.”

In addition to developing a Reliability Standard, the report suggested that “enhanced outreach and actions by system operators to encourage generator performance can also help to prevent a recurrence of the large-scale unplanned outages like those seen during this event, the 2014 Polar Vortex and the 2011 Southwest cold weather event.”

FERC’s report also found that it was not just a failure to winterize the generation facilities properly, there were issues with the gas supply that contributed to the event.

FERC and NERC had several recommendations and sound practices to help in future cold-weather events, including:

  • “Generator owners and operators should perform winterization activities to prepare for cold weather, and should ensure the accuracy of their units’ ambient temperature design specifications;
  • “Balancing Authorities and Reliability Coordinators should be aware of generating units’ specific limitations, such as ambient temperatures beyond which they cannot be expected to perform or the lack of firm gas transportation;
  • “Planning coordinators and transmission planners should jointly develop and study scenarios to be better prepared for seasonal extreme weather conditions; and
  • “Transmission owners and operators should conduct analyses that delineate different summer and winter ratings for both normal and extreme conditions.”

The full report can be viewed here.

Energy Infrastructure Update for May

Energy Infrastructure Update for May

The Federal Energy Regulatory Commission (FERC) issued its Energy Infrastructure Update for May, which is related to hydropower and natural gas, and it covers the highlights of electric generation and transmissions.

In May, one natural gas pipeline was placed into service, another two were certified, and five more were proposed. One natural gas storage facility was proposed.

Thus far this year, a total of five pipelines have been placed into service, compared to four by this point last year. There have been 14 pipeline projects certified this year, compared to 25 last year. No storage facilities have been placed into service this year, and there were none last year in this timeframe either. One storage facility has been certified this year, compared to three last year. Two LNG export projects have been placed into service this year, compared to only one last year. Four LNG import/export projects have been certified this year, compared to none last year.

For nonfederal hydropower, there was one capacity amendment in May. This year, one hydropower project has filed for a license, and two capacity amendments have been filed. One license has been issued, and only one capacity amendment has been issued.

There were no new coal facilities in May, nor have there been all year; at this point last year there were four. There was one natural gas facility in May, bringing the year to date total to 34; there were 44 last year. No nuclear power facilities were added in May, only one has been placed into service this year; there were three at this point last year. Four new oil facilities were opened in May, bringing this year’s total to nine; there were 13 last year. No new hydropower facilities were added, and only four have been placed into service this year; there were eight last year. One wind power facility was added, bringing the total for the year up to 20, beating the 18 added last year. There continues to be no biomass and geothermal steam facilities opened this year; there were 12 for biomass last year, and three for geothermal steam. Six more solar power facilities were added, making the total for the year 131; last year there were 264 at this point.

There were a number of proposed additions and retirements in May, all of which are expected by June 2022. One additional coal facility was proposed, and it is considered high probability; 57 retirements were proposed. There were 222 additions for natural gas, 107 of which are considered high probability; 108 retirements were proposed. Nine additional nuclear power facilities were proposed, one of which is a high probability; eight retirements were proposed. Oil had 17 proposed additions, six of which are high probability; 21 units were proposed for retirement. Hydropower had 217 additions, 84 are highly probable; there were 19 retirements. Wind power had 536 additions, 160 are high probability; only one retirement was proposed. There were 61 biomass additions, 27 are highly probable; 32 retirements are proposed. Geothermal steam had 18 additions, six are highly probable; no retirements were proposed. Solar power had 2,528 additions proposed, 530 of them are considered high probability; only one retirement was proposed.

For electric transmissions, in the ≤230 range, 18 miles of line was completed in May, which brings this year’s total up to 109 miles; compared to 8.4 miles completed in May 2018, and 392.3 at this point in 2018. There were 1,564 miles proposed to be placed into service by June 2021, 454.3 are considered highly probable. There were not any lines completed in May in the 345 range, 169 miles have been completed this year; this is compared to eight miles last May, and 819.3 for the year to date. For proposed projects for June 2021, 2,404.4 miles were proposed, and 915.4 miles are considered highly probable. In the 500 range, there was not any line completed in May of this year or last year. This year so far, 7.4 miles have been completed, compared to 69.4 miles last year. There were 1,816 miles proposed to be added, and 813 miles of it are high probability. In total, 18 miles have been completed in May of this year; 16.4 miles were completed last May. A total of 285.4 miles have been completed this year, compared to 1,281 last year. For the proposed additions for June 2021, a total of 5,784.4 miles have been proposed, and 2,182.7 miles are considered high probability.

FERC Issues a Draft EIS

FERC Issues a Draft EIS

The Federal Energy Regulatory Commission (FERC) issued a “draft environmental impact statement (EIS) for the Jordan Cove LNG Project and the Pacific Connector Gas Pipeline Project (collectively referred to as the Project) proposed by Jordan Cove Energy Project, LP (Jordan Cove) and Pacific Connector Gas Pipeline, L.P. (Pacific Connector).” Both Pacific Connector and Jordan Cover sought “Authorization and a Certificate of Public Convenience and Necessity to construct and operate a liquefied natural gas (LNG) export terminal and an interstate natural gas transmission pipeline.”

If approved, the 200-acre terminal will be located in Coos County, Oregon and it would be able to liquefy “up to 1.04 billion cubic feet of natural gas per day for export… the LNG terminal would be called upon by about 120 LNG carriers per year.” The terminal site would include:

  • “a pipeline gas conditioning facility;
  • “five natural gas liquefaction trains;
  • “two full-containment LNG storage tanks and associated equipment;
  • “LNG loading platform and transfer line;
  • “marine facilities;
  • “an access channel from the existing Coos Bay Federal Navigation Channel to the LNG terminal;
  • “modifications adjacent to the existing Federal Navigation Channel;
  • “a temporary workforce housing facility;
  • “the non-jurisdictional Southwest Oregon Regional Security Center and Fire Department building;
  • “and other security and control facilities, administrative buildings, and other support structures.”

The pipeline project would be connected to the “existing pipeline systems in Klamath County, Oregon, and would span parts of Klamath, Jackson, Douglas, and Coos Counties, Oregon.” The pipeline would be “approximately 229-mile-long, 36-inch-diameter” and it will have the capability to transport “up to 1.2 billion cubic feet of natural gas per day. Operating the pipeline would require the use of one compressor station and other associated pipeline facilities.”

The draft EIS was “prepared in compliance with the requirements of the National Environmental Policy Act (NEPA), the Council on Environmental Quality regulations for implementing NEPA in Title 40 Code of Federal Regulations, Parts 1500–1508 (40 CFR 1500-1508), and FERC regulations implementing NEPA (18 CFR 380).”

FERC asserted that while they received input from “The U.S. Department of the Interior Bureau of Land Management (BLM); U.S. Department of Agriculture Forest Service (Forest Service); Bureau of Reclamation; U.S. Department of Energy; U.S. Army Corps of Engineers (COE); U.S. Environmental Protection Agency; U.S. Department of the Interior Fish and Wildlife Service; U.S. Department of Commerce National Oceanic and Atmospheric Administration’s National Marine Fisheries Service; U.S. Department of Homeland Security Coast Guard (Coast Guard); the Coquille Indian Tribe; and the Pipeline and Hazardous Materials Safety Administration within the U.S. Department of Transportation,” they were working as cooperating agencies, and that FERC was the lead federal agency that prepared this draft EIS.

FERC explained that a “cooperating agency has jurisdiction by law or has special expertise with respect to the environment potentially affected by the Project. The cooperating agencies provided input to the conclusions and recommendations presented in the draft EIS. Following issuance of the final EIS, the cooperating agencies will issue subsequent decisions, determinations, permits or authorizations for the Project in accordance with each individual agency’s regulatory requirements.”

They concluded that both the construction and the operation of the pipeline project would have temporary, long-term, and permanent impacts on the environment, but many of them will be insignificant “or would be reduced to less than significant levels with the implementation of proposed and/or recommended impact avoidance, minimization, and mitigation measures.” There are still some that will be significant and adverse to the environment.

FERC also reached the conclusions that constructing the pipeline project would have a significate, but temporary impact on housing in Coos Bay. Both the construction and operation of the pipeline project would have a permanent impact on “the visual character of Coos Bay.” The construction and operation are also likely to have an adverse effect on “13 federally-listed threatened and endangered species including the marbled murrelet, northern spotted owl, and coho salmon.”

Their conclusions were “based wholly or in part on:”

  • “the Project would be constructed in compliance with all applicable federal laws, regulations, permits, and authorizations;
  • “the applicants would implement all best management practices, the measures described in their Erosion Control and Revegetation Plan, Wetland and Waterbody Construction and Mitigation Procedures and Upland Erosion Control, Revegetation, and Maintenance Plans, and other impact avoidance, minimization, and mitigation measures;
  • “the applicants’ Compensatory Wetland Mitigation Plan would satisfy the COE’s regulatory requirements to mitigate unavoidable impacts on wetlands and waters of the U.S.;
  • “the BLM and Forest Service’s plan amendments would provide for the crossing of federal lands;
  • “compliance with the Endangered Species Act and the National Historic Preservation Act would be complete prior to construction;
  • “the LNG terminal was designed consistent with maximum tsunami run-up elevations and considered tsunami wave heights and inundation elevations;
  • “the LNG terminal would include protections and safeguards that ensure facility integrity and public safety;
  • “the Coast Guard issued a Letter of Recommendation indicating the Coos Bay Federal Navigation Channel would be considered suitable for the LNG marine traffic associated with the Project; and
  • “FERC’s environmental and LNG engineering construction inspection programs would ensure compliance with all applicants’ commitments, and the conditions of any FERC Authorization and Certificate.”

FERC also “recommend[ed] that the Project-specific impact avoidance, minimization, and mitigation measures that we have developed (included in the draft EIS as recommendations) be attached as conditions to any Authorization and Certificate of Public Convenience and Necessity issued by the Commission for the Project.”

The draft EIS and its Appendices can be read at: