Energy & Environmental Law Adviser

D.C. Circuit Upholds the Utility MACT Rule in 2-1 Split

Posted in Air

White Stallion Energy Center, LLC v. EPA, No. 12-1100 (D.C. Cir. Apr. 15, 2014).

The D.C. Circuit upheld the controversial Utility MACT Rule, also known as the Mercury and Air Toxics Standard or MATS, on April 15, 2014, with a 2-1 split, rejecting challenges from State, Industry, and Labor petitioners to the United States Environmental Protection Agency’s (USEPA) 2012 promulgation of emission standards for several listed hazardous air pollutants (HAPs) emitted by coal- and oil-fired electric utility steam generating units. White Stallion Energy Ctr., LLC v. EPA, No. 12-1100 (D.C. Cir. Apr. 15, 2014); see National Emission Standards for Hazardous Air Pollutants from Coal- and Oil-Fired Electric Utility Steam Generating Units and Standards of Performance for Fossil-Fuel Fired Electric Utility, Industrial-Commercial-Institutional, and Small Industrial-Commercial- Institutional Steam Generating Units, Final Rule, 77 Fed. Reg. 9304 (Feb. 16, 2012)(to be codified at 40 C.F.R. parts 60 and 63) (“Final Rule”).  The court’s long and detailed decision hinged on whether USEPA’s interpretation of the term “appropriate and necessary” from Section 112 of the Clean Air Act in the development of the Final Rule was permissible.  White Stallion Energy Ctr., LLC, No. 12-1100, 16.

As directed by Congress in the 1990 Clean Air Act Amendments, several studies were conducted to determine whether HAPs emitted by power plants should be regulated under Section 112.  In 2000, USEPA concluded that they should be (the 2000 Finding) but, in 2005, USEPA reversed itself (the 2005 Delisting).  Id. at 9-11.  States and other parties petitioned for review, and the D.C. Circuit vacated the 2005 Delisting based on the statute’s unambiguous limitation on USEPA’s discretion to remove sources once they have been added to the 112(c)(1) list.  Id. at 11 (discussing New Jersey v. EPA, 517 F.3d 574, 583 (D.C. Cir. 2008)).

The Final Rule, issued in 2012, confirmed USEPA’s 2000 Finding, concluding that regulation of emissions from coal- and oil-fired electric generating units (“EGUs”) under Section 112 is “appropriate and necessary.” White Stallion Energy Ctr., LLC, No. 12-1100, 12 (discussing 77 Fed. Reg. at 9310-11).  In the proposed rule, USEPA “rejected as ‘unreasonable’ its interpretation in [the 2005 Finding] that regulation under 112 was ‘necessary’ only if no other provisions in the CAA—whether implemented or only anticipated—could ‘directly or indirectly’ reduce HAP emissions to acceptable levels.”  White Stallion Energy Ctr., LLC, No. 12-1100, 13 (discussing Proposed Rule, 76 Fed. Reg. 24,976, 24,992 (May 3, 2011)).  While several challenges to the Final Rule were raised, this case addressed those challenges with respect to existing EGUs only.

The court’s discussion upholding the Final Rule can be summarized as follows:

  • USEPA acted within its legal authority and demonstrated a reasonable connection between its action and the record of decision.  Thus, the action was not “arbitrary and capricious” and was to be accorded Chevron deference. Id. at 36.
  • Chevron does not require that that agency prove that its “reasons for the new policy are better than the reasons for the old one.” Id. at 17 (citing FCC v. Fox Television Stations, Inc., 556 U.S. 502, 515 (2009)).  Further, the court did not need to consider the earlier findings because any issues had been cured with the Final Rule.  White Stallion Energy Ctr., LLC, No. 12-1100, 15.
  • USEPA properly relied on the Section 112(c)(9) criteria to inform its interpretation of the undefined statutory term “hazard to public health.” Id. at 19.
  • USEPA was not required by the language of the statute to consider costs in determining whether it was “appropriate” to regulate HAPs from EGUs.  Id. at 30.
  • USEPA did not err in considering environmental effects in addition to human health effects in order to make its “appropriate and necessary” determination.  While other readings of the statute were plausible, the one USEPA chose was also plausible and entitled to deference.  Id. at 31.
  • Further, USEPA may regulate all HAP substances emitted by EGUs.  Id. at 36.  Once USEPA has made an “appropriate and necessary” decision, “EGUs shall be regulated under Section 112 in the same manner as other categories for which the statute requires regulation.”  Id. at 35 (citing 77 Fed. Reg. at 9326).  “This source-based approach to regulating EGU HAPs was affirmed in New Jersey, 517 F.3d at 582, which held that EGUs could not be delisted without demonstrating that EGUs, as a category, satisfied the delisting criteria set forth in §112(c)(9).”  Id. at 36.
  • USEPA’s choice not to distinguish between EGUs with larger emissions of HAPs (major sources) and fewer emissions of HAPs (area sources) was reasonable.  Instead, USEPA chose to regulate HAPs from EGUs with a certain electrical output because it had traditionally done this in other HAP rules according to Section 112(a)(8). USEPA permissibly relied on the more specific rule in interpreting the statute. White Stallion Energy Ctr., LLC, No. 12-1100 at 39.
  • USEPA’s method and the resulting standards for mercury emissions from existing coal-fired EGUs were reasonable based on the data collection process used, even if it was not perfect.  Id. at 42.
  • The court rejected petitioners’ challenge to USEPA’s declination to establish a less stringent, health-based emission standard for acid gases under § 112(d)(4), despite the fact that USEPA did not conclusively determine that emissions of acid gases such as hydrogen chloride from EGUs pose a health hazard.  Id. at 42.   USEPA stated in the Final Rule it did not have enough evidence to determine whether an alternative standard would protect health “with an ample margin of safety.”  Id. (citing 77 Fed. Reg. at 9405-9506). The court concluded that petitioners did not offer a “compelling basis for second-guessing USEPA’s analysis.” White Stallion Energy Ctr., LLC, No. 12-1100 at 42.

Industry specific challenges were raised, including USEPA’s decisions with respect to subcategories of sources.

  • In particular, a group of petitioners argued that circulating fluidized EGUs, or CFBs, should have been placed in a separate subcategory due to the significant design differences. Id. at 44. The court noted that the Clean Air Act allows, but does not require, USEPA to create subcategories. Id.; see 42 U.S.C. §7412(d)(1). USEPA’s determination not to create a subcategory for CFBs relied on data reflecting CFBs were among the best and worst performers for pollutants, which the court found demonstrated that CFB emission profiles are similar to other EGUs. Id. at 45.
  • A challenge was also raised regarding the MACT floor set for lignite-fired EGUs, which USEPA chose to subcategorize.  Id. at 46-47.  Again the court found USEPA’s data collection process to be reasonable.
  • Lastly, the court rejected an argument that USEPA is required to grant a blanket, one-year extension to public utility companies because while USEPA has the discretion to do so, it is not so required. Id. at 48.  Further USEPA’s data indicated that “most units will be able to fully comply” within the three-year period established by USEPA.  Id. at 49 (citing 77 Fed. Reg. at 9410).

Several environmental groups challenged the Final Rule provisions that permit compliance with the emission standards to be demonstrated through 1) emissions averaging and 2) options for non-mercury metal HAP emissions monitoring.  The court held that USEPA’s decision for both provisions was permissible under Section 112 and subject to Chevron deference.  Id. at 51, 56.

Lastly, the court considered Julander Energy Company’s challenge that USEPA should have required fuel-switching by EGUs from coal to natural gas.  Id. at 56.  However, the court determined Julander Energy Company lacked standing because its interests did not come within the “zone of interests to be protected or regulated by the statute.”  Id. at 57 (citing Match-E-Be-Nash-She-Wish Band of Pottawatomi Indians v. Patchak, 132 S. Ct. 2199, 2210 (2012).

Dissent sets the stage for Supreme Court Appeal?

Judge Kavanaugh wrote a “powerful-sounding dissent,” as described by the majority. White Stallion Energy Ctr., LLC, No. 12-1100, 26. The dissent challenges USEPA’s decision not to consider costs where the legislative history suggests that doing so was the purpose of the term “appropriate.” Id. (Kavanaugh, B., dissenting).  The failure to do so will have significant practical implications because “meeting the [MACT] floor will be prohibitively expensive . . . regardless of whether USEPA decides to go further and set a ‘beyond-the-floor’ standard.”  Id. at 71.  Industry petitioners found the benefits of the Rule were valued at only $4-6 million, versus USEPA’s estimate of the benefits at $37-90 billion  based on “the indirect benefits of reducing PM2.5, a type of fine particulate matter that is not itself regulated as a hazardous air pollutant.”  Id. at 71 (citing 77 Fed Reg. at 9428).

Judge Kavanaugh suggests an additional, related flaw in the majority’s ruling by the inappropriate reliance on the Chevron test alone.   Id. at 76.  The majority should have also considered the implications of State Farm, which held that the APA requires an agency to “consider the relevant factors when exercising its discretion under the governing statute.”  Id.; see Motor Vehicle Manufacturers Association of the United States, Inc. v. State Farm Mutual Automobile Insurance Co., 463 U.S. 29, 42-43 (1983).  In Judge Kavanaugh’s view, the relevant factors surely would have included the costs of the regulation, if only to ensure that the benefits outweigh the costs.  Id.

Read the full opinion.

Obama Administration Issues Strategy to Reduce Methane Emissions

Posted in Air

As part of its Climate Action Plan, the Obama Administration issued a “Strategy to Reduce Methane Emissions” (the Methane Strategy) at the end of March 2014.  According to the Methane Strategy, methane emissions currently account for almost nine percent of all domestic greenhouse gas emissions (GHGs) in the United States.  While methane emissions have decreased since 1990, they are expected to increase over the next 15 years if no additional action is taken.  The Obama Administration’s Methane Strategy focuses on reducing methane emissions from landfills, coal mines, and the agriculture and oil and gas sectors.  Building on and updating existing programs is key to the strategy.  The key proposals for reducing methane emissions from these areas are outlined by sector below:

  • Landfills:   The U.S. Environmental Protection Agency (USEPA) will propose updated standards to reduce methane from new landfills this summer, and will also seek public comment on updating standards for existing landfills.   USEPA will also (1) continue to promote voluntary methane recovery projects at landfills through the Landfill Methane Outreach Program; and (2) continue to reduce, recover, or recycle food waste as a method of reducing the size of landfills, and consequently, reducing the emissions from landfills through the U.S. Food Waste Challenge.
  • Coal Mines:  The Bureau of Land Management (BLM) will issue an Advanced Notice of Proposed Rulemaking shortly that will seek public comment on developing a program for capturing, selling, and/or disposing of waste mine methane produced on Federal government lands through coal and other solid mineral leases.  USEPA will continue to promote voluntary recovery and beneficial use of methane in the coal mining industry.
  • Agriculture:  The Department of Agriculture and the Department of Energy (DOE), in cooperation with the dairy industry, will release a “Biogas Roadmap” this June.  The Biogas Roadmap will provide voluntary strategies for implementing technologies for reducing GHGs from this sector of the economy.  Primary focus will be on encouraging the use of anaerobic digestion and biogas utilization systems.
  • Oil and Gas:  This spring, USEPA will begin investigating how to reduce GHG emissions from this industry through white papers from independent experts.  These white papers will focus on reducing both Volatile Organic Compounds (VOCs) and methane.  After the white papers are peer reviewed this summer, USEPA intends to decide the next steps for reducing emissions from this sector next fall.  This process will include determining whether the current regulatory authorities apply to these sources.  If USEPA decides to take regulatory action, any proposed regulations will be issued by the end of 2016.  USEPA will also continue to promote its Natural Gas STAR Program which outlines technologies and practices for reducing and/or avoiding methane emissions.  BLM will also release a proposed rule (informally called the “Onshore Order 9”) for regulating venting and flaring from oil and gas production on Federal government lands.  Finally, DOE will issue the first Quadrennial Energy Review (QER) in January 2015 to recommend actions for improving energy transmission, storage, and distribution, including opportunities to abate methane emissions.

The full strategy is available on the White House website.

Recent Developments in Toxic Torts and Environmental Law

Posted in Uncategorized

A team of Schiff Hardin attorneys compiled “Recent Developments in Toxic Torts and Environmental Law”  for the Tort Trial & Insurance Practice Law Journal originally published in the fall of 2013 (Vol. 49-1) on the evolving landscape of the environmental and toxic tort areas of law.

Toxic tort-related topics covered by this article include class action decisions discussing procedural aspects of damage calculations and whether plaintiffs can stipulate to damages to avoid jurisdiction.

Key toxic tort subjects covered in this update include “duty to warn” and medical monitoring, punitive damages, and new asbestos-related decisions.

Key decisions in fracking- and greenhouse gas-related cases are summarized, as are major Supreme Court and federal appellate decisions under major environmental statutes, including the Clean Air Act (CAA), Clean Water Act (CWA), Resource Conservation and Recovery Act (RCRA), and Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA).

© American Bar Association 2014. This information or any portion thereof may not be copied or disseminated in any form or by any means or downloaded or stored in an electronic database or retrieval system without the express written consent of the American Bar Association.


EPA and Army Corps Propose to Amend Bounds of Federal Jurisdiction over Wetlands and Other Water Bodies

Posted in Water

On Tuesday, March 25, 2014, the U.S. Environmental Protection Agency and the U.S. Army Corps of Engineers jointly announced a proposed rule to amend the regulatory definition of “waters of the United States,” which essentially governs the scope of federal jurisdiction under the Clean Water Act.  The proposed rule would redefine which areas are covered under regulations for all Clean Water Act programs, including sections 303 (water quality standards programs), 311 (oil spill prevention and response program), 401 (state water quality certification requirements), 402 (National Pollutant Discharge Elimination System (NPDES) permit program), and 404 (dredge and fill permitting).

The Agencies state in the preamble of the proposed rule that certain water bodies which, under current law, would have been deemed to be subject to federal jurisdiction only after a case-by-case determination, would be deemed to be jurisdictional waters by definition.  Specifically, under the proposed rule, waters of the United States would, by definition, include not only traditional navigable waters, interstate waters, territorial seas, and tributaries of those water bodies, but also waters and wetlands that are adjacent to those waters.[1]  The proposed rule also includes several definitions central to the interpretation of the scope of the terms “tributary” and “adjacent.”

  • As proposed, “tributary” means a water with a bed, banks and an ordinary high water mark, which contributes flow, either directly or through another water, to a navigable water, interstate water, territorial sea, or an impoundment of such waters.  Wetlands, lakes, and ponds would also fit within the definition (even those lacking a bed and banks or ordinary high water mark) if they contribute flow, either directly or through another water, to a navigable water, interstate water, or territorial sea.  The term would also encompass rivers, streams, lakes, ponds, impoundments, canals, and ditches, whether natural or man-made, unless a particular water body is specifically excluded, as discussed below.  The presence of one or more man-made breaks (such as a bridge, culvert, pipe, or dam) or natural breaks (such as wetlands at the head of or along the run a stream, debris piles, boulder fields, or a stream that flows underground) would not necessarily disqualify a water body from meeting the definition of a tributary so long as a bed and banks and ordinary high water mark can be identified upstream of the break.
  • With regard to whether waters or wetlands are adjacent to other waters of the United States, the proposed rule retains the existing regulatory definition for “adjacent,” which means “bordering, contiguous or neighboring.”  The proposed rule, however, provides new definitions for related terms, including:
    • “Neighboring,” which, for purposes of the term “adjacent”, is defined to include waters located within the “riparian area” or “floodplain” of a water of the United States or “waters with a shallow subsurface hydrologic connection or confined surface hydrologic connection to such a jurisdictional water.”
    • “Riparian area” is defined to mean “area bordering a water where surface or subsurface hydrology directly influence the ecological processes and plant and animal community structure in that area. Riparian areas are transitional areas between aquatic and terrestrial ecosystems that influence the exchange of energy and materials between those ecosystems.”
    • “Floodplain” is defined as “an area bordering inland or coastal waters that was formed by sediment deposition from such water under present climatic conditions and is inundated during periods of moderate to high water flows.”

While the inclusion of the newly defined terms would avoid the application of the current “significant nexus” test to determine whether tributaries or adjacent waters are subject to Clean Water Act jurisdiction, the foregoing definitions appear to leave considerable room for varying interpretations as to whether a given area’s hydrology could, for instance, “influence ecological processes” or even whether or not an area is inundated during periods of “moderate to high water flows.”

The proposed rule would also leave open the possibility that “other waters” might also come within federal jurisdiction if, upon a case specific determination, “those waters alone, or in combination with other similarly situated waters, including wetlands, located in the same region, have a significant nexus” to a traditional navigable water, interstate water, or territorial sea.

The proposed rule defines “significant nexus” to mean “that a water, including wetlands, either alone or in combination with other similarly situated waters in the region (i.e., the watershed that drains to the nearest [traditional navigable water, interstate water, or territorial sea]), significantly affects the chemical, physical, or biological integrity of a [traditional navigable water, interstate water, or territorial sea]. For an effect to be significant, it must be more than speculative or insubstantial. Other waters, including wetlands, are similarly situated when they perform similar functions and are located sufficiently close together or sufficiently close to a ‘water of the United States’ so that they can be evaluated as a single landscape unit with regard to their effect on the chemical, physical, or biological integrity of a [traditional navigable water, interstate water, or territorial sea].”

The proposed rule would specifically exclude the following from the definition of waters of the United States:

  • Waste treatment systems, including treatment ponds or lagoons, designed to meet the requirements of the Clean Water Act
  • Prior converted cropland.  Notwithstanding the determination of an area’s status as prior converted cropland by any other federal agency, for the purposes of the Clean Water Act, the final authority regarding Clean Water Act jurisdiction remains with EPA
  • Ditches that are excavated wholly in uplands, drain only to uplands, and have less than perennial flow
  • Ditches that do not contribute flow, either directly or through another water, to navigable waters, interstate waters, territorial seas, or impoundments of such waters
  • Certain other water features:
    • Artificially irrigated areas that would revert to upland should application of irrigation water to that area cease
    • Artificial lakes or ponds created by excavating and/or diking dry land and used exclusively for such purposes as stock watering, irrigation, settling basins, or rice growing
    • Artificial reflecting pools or swimming pools created by excavating and/or diking dry land
    • Small ornamental waters created by excavating and/or diking dry land for primary aesthetic reasons
    • Water-filled depressions created incidental to construction activity
    • Groundwater, including groundwater drained through subsurface drainage systems
    • Gullies and rills and non-wetland swales

Exemptions contained elsewhere in the Clean Water Act (such as those related to farming) would still apply, even if a particular water body would otherwise meet the definition of a water of the United States as proposed.

Comments on the proposed rule will be due 90 days from the date it is published in the Federal Register, which should occur soon.

[1] Interpreting Justice Kennedy’s concurring opinion in Rapanos v. United States, 547 U.S. 715 (2006), the Agencies have since applied the “significant nexus” test to determine whether adjacent wetlands or tributaries are subject to Clean Water Act jurisdiction on a case-by-case basis.  See Proposed Rule, to be published in the Federal Register and on in  Docket No. EPA-HQ-OW-2011-0880, prepublication version at 18.

Electric Reliability Actions at FERC Open Meeting

Posted in Electric, Energy Efficiency

During the March 20, 2014 Open Meeting, the Federal Energy Regulatory Commission (FERC) took several actions regarding electric reliability requirements. It:

  • Approved five Generator Verification Reliability Standards submitted by the North American Electric Reliability Corporation (NERC);
  • Granted in part the requests for clarification of Order No. 791, its order on the Version 5 Critical Infrastructure Protection Reliability Standards, and denied requests for rehearing of that order;
  • Proposed a new Generator Relay Loadability Reliability Standard and revisions to the existing Transmission Relay Loadability Reliability Standard; and
  • Approved the revised definition of Bulk Electric System.

Generator Verification Reliability Standards (Order No. 796)

This Final Rule approves five modeling Reliability Standards: MOD-025-2 (Verification and Data Reporting of Generator Real and Reactive Power Capability and Synchronous Condenser Reactive Power Capability), MOD-026-1 (Verification of Models and Data for Generator Excitation Control System or Plant Volt/Var Control Functions), MOD-027-1 (Verification of Models and Data for Turbine/Governor and Load Control or Active Power/Frequency Control Functions), PRC-019-1 (Coordination of Generating Unit or Plant Capabilities, Voltage Regulating Controls, and Protection), and PRC-024-1 (Generator Frequency and Voltage Protective Relay Settings) as well as the associated implementation plans, violation risk factors and violation severity levels. FERC also approved the retirement of Reliability Standards MOD-024-1 and MOD-025-1 immediately prior to the effective date of MOD-025-2. According to FERC, these Reliability Standards “help ensure that generators remain in operation during specified voltage and frequency excursions; properly coordinate protective relays and generator voltage regulator controls; and enhance the ability of generator models to accurately reflect the generator’s capabilities and equipment performance.” Final Rule at P 3. They also “improve the accuracy of model verifications needed to support reliability and enhance the coordination of generator protection systems and voltage regulating system controls,” which, in turn, “should help reduce the risk of generator trips and provide more accurate models for transmission planners and planning coordinators to develop system models and simulations.” Id. at P 4.

In the Notice of Proposed Rulemaking  (NOPR) that preceded the Final Rule, FERC sought comment on three issues: (1) whether the higher applicability thresholds for MOD-026-1 and MOD-027-1 could limit their effectiveness, especially in areas with a high concentration of generators falling below the thresholds, or impede transmission planners’ ability to address reliability risk; (2) whether the provision in Reliability Standard MOD-026-1 allowing transmission planners to compel a generator owner below the applicability threshold with a “technically justified” unit to comply with the Reliability Standard’s requirements is “sufficiently clear and workable”; and (3) whether the “technical justification” provision should be included in Reliability Standard MOD-027-1. FERC also expressed concern in the NOPR regarding the violation severity levels (VSL) associated with MOD-026-1 Requirement R6 and MOD-027-1 Requirement R5 because the proposed VSLs did not address all of the obligations of the requirements. NERC addressed this concern by agreeing to expand the VSLs to address the full requirements and no other commenters touched on this issue. Commenters did, however, respond to the first three questions posed by FERC and also expressed concern regarding a lack of flexibility in the reactive power verification requirements in Reliability Standard MOD-025-2.

FERC responded to these comments in the Final Rule, finding many of them persuasive and dismissing others. FERC agreed with NERC and others’ responses to its first question, finding that “the higher applicability thresholds of Reliability Standards MOD-026-1 and MOD-027-1 are appropriate for a continent-wide standard,” and noting that “the higher applicability threshold does not excuse generator owners with small units from the expectation that estimated model data they provide to transmission planners for use in simulations will be accurate.” Final Rule at P 37. FERC also found the responses to its second question persuasive, concluding that “the basis and associated process for a transmission planner to demonstrate that it is ‘technically justified’ for a generator owner below the applicability threshold to comply with Requirement R5 of Reliability Standard MOD-026-1 under Section 4.2.4 is sufficiently clear and workable.” Id. at P 44. FERC agreed with EEI that “a more prescriptive, ‘one size fits all’ approach could ‘unintentionally limit or otherwise undermine the regional knowledge and judgment of transmission planners.’” Id. With respect to its third query, FERC concluded that “the technical justification provision is not workable in MOD-027-1 because there is more subjectivity involved in verifying the data pertaining to turbine/governors, the equipment subject to the modeling verification requirements of MOD-027-1.” Id. at P 51. Finally, FERC dismissed commenters’ suggestions that MOD-025-2 should include more flexibility to verify unit reactive power capability, but suggested that “NERC, in consultation with EEI and other industry representatives, should consider potential modifications to MOD-025-2 “that would better reflect rapidly evolving modeling technology, as well as successful methods and processes already in use by some companies.” Id. at PP 55-56.

Version 5 Critical Infrastructure Protection Reliability Standards

In an Order on Clarification and Rehearing, FERC grants in part the requests for clarification and denies the requests for rehearing of Order No. 791, which approved the Critical Infrastructure Protection Version 5 Reliability Standards. The requests were filed by the American Public Power Association (APPA) and National Rural Electric Cooperative Association (NRECA); Utility Services, Inc.; and Edison Electric Institute (EEI) and Electric Power Supply Association (EPSA). In the Order, FERC reiterated that the 24- and 36-month implementation periods proposed by NERC commence from the effective date of the Final Rule and declined to extend the implementation period for Low Impact assets and for responsible entities that are currently not subject to the CIP Reliability Standards as requested by Utility Services. Order at PP 10-11. FERC also clarified that the implementation plan submitted by NERC and approved in Order No. 791 requires responsible entities to comply with the High and Medium Impact asset requirements by April 1, 2016. Id. at P 12.

FERC denied APPA-NRECA’s request for clarification concerning how responsible entities should address the “identify, assess, and correct” language pending NERC’s Order No. 791 compliance filing, stating that it “expect[s] responsible entities to move forward with implementation of the substantive, technical controls approved in Order No. 791 while NERC addresses the Commission’s directive regarding the ‘identify, assess, and correct’ compliance language.” Id. at P 16. It explained that in the Final Rule, FERC had “highlighted its support for a move away from a ‘zero tolerance’ approach to compliance; the development and adoption of strong internal controls by responsible entities; and the development of Reliability Standards that focus on those activities with the greatest impact on Bulk-Power System reliability.” Id.

With respect to EEI-EPSA’s request for rehearing or, in the alternative, clarification of the directive in Order No. 791 requiring NERC to conduct a survey and submit an informational filing regarding the “15-minute parameter” in the definition of BES Cyber Asset, FERC denied rehearing but clarified that “Order No. 791 did not direct NERC to conduct an inventory-type survey of all Cyber Assets impacted by the 15-minute parameter. Instead, the scope of the survey was left for NERC to determine.” Id. at P 21. FERC also clarified that while “Order No. 791 did not require the development of controls for third-party communications networks,” it anticipates that it will address the need for such controls during the April 29, 2014 staff-led technical conference. Id. at P 22.

Finally, FERC denied APPA-NRECA’s request for clarification regarding the Order No. 791 Regulatory Flexibility Act certification that the CIP version 5 Standards will not have a significant economic impact on a substantial number of small entities.

Generator Relay Loadability and Revised Transmission Relay Loadability Reliability Standards

In this NOPR, FERC proposes to approve a new Reliability Standard, PRC-025-1 (Generator Relay Loadability) and revisions to a currently-effective Reliability Standard, PRC-023-3 (Transmission Relay Loadability), the prior version of which was approved under Order No. 733 on March 10, 2010. According to NERC, proposed Reliability Standard PRC-025-1 addresses the second part of the Order No. 733 directives and “is designed to prevent generator tripping when conditions do not pose a direct risk to the generator and associated equipment and will reduce the risk of unnecessary generator tripping – events that increase the severity of the disturbance.” NOPR at P 7. FERC believes that proposed Reliability Standard PRC-025-1 “adequately” addresses the directive in Order No. 733 “that NERC develop a separate Reliability Standard that addresses generator step-up and auxiliary transformer loadability, and do so ‘in a way that is coordinated with the Requirements and expected outcomes of PRC-023-1.’” Id. at P 17. FERC also “believe[s] that PRC-025-1 will enhance reliability by imposing mandatory requirements governing generator relay loadability settings, thereby reducing the likelihood of premature or unnecessary tripping of generators during system disturbances.” Id. As a result, FERC proposes to approve Reliability Standard PRC-025-1, including its associated violation risk factors and violation severity levels, Reliability Standard PRC-023-3, and NERC’s proposed implementation plans for the new and revised standards. FERC explains that it agrees that “the clarifying modifications reflected in Reliability Standard PRC-023-3. . . serve to clarify the applicability of the two standards governing relay loadability and prevent potential compliance overlap due to inconsistencies.” Id. at P 18.

Comments in response to this NOPR are due 30 days after its publication in the Federal Register.

Order Approving Revised Definition of “Bulk Electric System”

In this Order, FERC approves changes filed by NERC on December 13, 2013, in response to FERC’s directives in Order Nos. 773 and 773-A and industry concerns raised during the initial development of the revisions to the definition (Phase 1). The revised definition will supersede in its entirety the version approved in Order Nos. 773 and 773-A and will go into effect on July 1, 2014. The changes include refinements to the exclusions for radial facilities and local networks as well as revisions clarifying that all forms of generation, including variable generation resources, are included in the bulk electric system and that certain generator interconnection facilities also are included in the bulk electric system. Specifically, Order approves:

  • The modification of exclusion E1 to include a 50 kV threshold for excluding certain radial loops. FERC justified its determination that the modification was reasonable on the basis that “NERC’s technical analysis demonstrates that 50 kV is an appropriate level for determining whether a portion of the system is considered radial and is therefore a candidate for exclusion from the bulk electric system by application of exclusion E1 or is considered a networked system and therefore a candidate for exclusion by application of exclusion E3.” Order at P 43. FERC explained that the “technical justification resulted from NERC’s extensive simulations which demonstrate that power flow reversal into the bulk electric system is unlikely when circuit loop operating voltages are below 50 kV.” Id.
  • Revisions to (1) exclusions E1 and E3 to ensure that generator interconnection facilities at or above 100 kV connected to bulk electric system generators identified in inclusion I2 are not excluded from the bulk electric system and (2) exclusion E3 to remove the phrase “or above 100 kV but.” FERC explained that the removal of the 100 kV floor in exclusion E3 would “decrease the burden for some entities that would have otherwise been included in the bulk electric system because these entities may now apply exclusion E3.” Id. at P 45.
  • A revision to inclusion I4 to include collector systems from the point where the gross nameplate capacity aggregates to greater than 75 MVA to a common point of connection at a voltage of 100 kV or above because “the inclusion of the collector system is appropriate and consistent with the overall concept of applying the definition to identify elements that provide a reliability benefit to the interconnected transmission network.” Id. at P 46.
  • A clarification to inclusion I4 that all forms of generation resources, including variable generation resources, are included in the bulk electric system.  Id. at P 47. FERC explains that it “agree[s] with NERC that, given the increasing presence of wind, solar, and other non-traditional forms of generation, continuing the inclusion of individual variable generation units within the scope of the definition is appropriate to ensure that, where necessary to support reliability, these units may be subject to Reliability Standards. Moreover, inclusion I4 is limited to individual resources that aggregate to a total capacity greater than 75 MVA, the same threshold applicable to other types of generating resources.” Id.

In addition, FERC encouraged the American Wind Energy Association and FirstWind to participate in the NERC standards development process given their concerns regarding the potential costs of dispersed generation facilities having to comply with a full array of NERC Reliability Standards that apply to generator owners and operators. Id. at P 49.

FERC Issues Orders to Synchronize Gas and Electric Scheduling Deadlines

Posted in Electric, Natural Gas

On March 20, 2014, the Federal Energy Regulatory Commission issued three related orders addressing the lack of harmonization between the nomination and scheduling timelines currently used by interstate natural gas pipelines and electric transmission providers. These orders are further attempts by the Commission to cope with problems related to gas-electric coordination and the increased use of natural gas as a fuel for electric generation. The first order is a Notice of Proposed Rulemaking (Docket No. RM14-2) proposing changes to the nomination and scheduling timelines used in the natural gas industry. The second order (Docket No. EL14-22) institutes an FPA Section 206 proceeding into the day ahead scheduling practices of RTOs and ISOs to determine if they should be modified to better coordinate with the natural gas industry. The third order (Docket No. RP14-442) institutes an NGA Section 5 investigation to determine whether pipelines permit potential shippers to post offers to purchase released capacity.

NOPR, Docket No. RM14-2

The Notice of Proposed Rulemaking proposes substantial changes to the nomination and scheduling deadlines that have been adopted by NAESB and are currently used by all interstate pipelines in the country. The Commission, however, recognizes that the natural gas and electric industries are currently discussing proposed changes to the timelines and that an industry consensus proposal would be preferable to one imposed by Commission fiat. As such, the NOPR affords industry participants six months (180 days from the date the NOPR is published in the Federal Register) to develop a consensus proposal. If the industry is able to reach consensus in a timely fashion, interested parties will be afforded the opportunity to comment on that proposal 60 days later. If no consensus proposal is developed, interested parties may comment on the NOPR’s proposal 240 days after it is published in the Federal Register.

The NOPR’s most significant changes proposed to pipeline nomination and scheduling deadlines are a change in the start of the Gas Day, a change to the first Timely Nomination deadline, and the addition of a fourth intra-day nomination opportunity. Currently, the Gas Day begins at 9:00 a.m. Central Clock Time (CCT) and ends 24 hours later. The Commission proposes to move the start of the Gas Day to 4:00 a.m. CCT in order to accommodate the fact that electric usage begins to increase in the early morning hours. NOPR at P 40. The NOPR states that gas-fired generators may no longer have sufficient gas available to meet this early morning increase in demand when the Gas Day has nearly expired. The Commission recognizes that a 4:00 a.m. start to the Gas Day may raise issues regarding natural gas operations in darkness, but believes those concerns can be successfully resolved. Id. The NOPR also proposes to move the first Timely Nomination Deadline from 11:30 a.m. to 1:00 p.m. to provide electric generators with sufficient time to obtain gas supplies prior to submitting bids to the Day Ahead electric markets. Id. at P 48. In addition, the Commission proposes to add a fourth intra-day nomination opportunity to the Gas Day in order to provide generators an additional chance to modify their gas supply arrangements to meet actual electric demand. Id. at P 63.

In addition to the timing changes, the NOPR clarifies the applicability of the “No Bump Rule.” The No Bump Rule provides that, once gas has been scheduled during the Gas Day, even if it is scheduled as interruptible service, gas will continue to flow even if a higher priority service attempts to nominate gas to flow at an intra-day nomination deadline. Currently, the No Bump Rule applies only to the third and final intra-day nomination deadline. Thus, if a firm shipper makes an intra-day nomination at either the first or second opportunity during a Gas Day, a firm shipper can bump previously scheduled interruptible service. The firm shipper may not, however, bump scheduled interruptible service if it waits until the third intra-day nomination deadline to attempt to nominate additional volumes. The NOPR does not propose significant revisions to the No Bump Rule, other than to recognize that a fourth intra-day nomination will be available under the NOPR’s proposal. NOPR at PP 69-70. The No Bump Rule would apply only to that fourth and final intra-day nomination opportunity. Id. If pipelines permit nominations in addition to those required by the NOPR, they may permit firm shippers to bump interruptible shippers provided that the interruptible shippers are afforded an a opportunity to re-nominate the bumped gas. Id. at P 75.

The NOPR’s proposed changes to the gas pipeline nomination and scheduling timeline, based on a 4:00 a.m. CCT start to the Gas Day are as follows (NOPR at P 64):

Intra-Day 1:    Nominations due by 8:00 a.m. to be effective by noon

Intra-Day 2:    Nominations due by 10:30 a.m. to be effective by 4:00 p.m.

Intra-Day 3:    Nominations due by 4:00 p.m. to be effective by 7:00 p.m. (notice to bumped shippers by 6:00 p.m.)

Intra-Day 4:    Nominations due by 7:00 p.m. to be effective by 9:00 p.m. (No Bump Rule applies)

The NOPR proposed one other important change to the ability to nominate and schedule service on an interstate pipeline. The Commission proposes to require all pipelines to permit shippers to enter into multi-party firm transportation service agreements. NOPR at P 80. In other words, multiple shippers may sign a firm service agreement for the same pipeline capacity and may, in effect, share that capacity. Shippers electing such multi-party service agreements will be jointly and severally liable under those agreements.

FPA Section 206 Proceeding, Docket No. EL14-22 (“Paper Hearing Order”)

The Commission is commencing an investigation into the justness and reasonableness bidding schedules applicable to the Day Ahead markets in all RTOs and ISOs. Specifically, the Commission believes that RTOs and ISOs should notify generators if their Day Ahead bids have cleared the market before the proposed 1:00 p.m. on CCT Timely Nomination Deadline for pipelines. All RTOs and ISOs will have to demonstrate that their bidding deadlines are just and reasonable 90 days after the publication of a Final Rule in Docket No. RM14-2. Paper Hearing Order at PP 17, 19. In addition, the Commission indicates that RTOs and ISOs should complete their reliability unit commitment processes prior to the Evening Nomination Cycle, and the order requires the RTOs and ISOs to show that the timing of their current reliability unit commitment processes remains just and reasonable. Id. at PP 18-19.

NGA Section 5 Proceeding, Docket No. RP14-442 (“Show Cause Order”)

The Commission also commenced an investigation to determine if all pipeline tariffs permit potential shippers to post offers to buy released capacity. The Show Cause Order states that section 284.8(d) of the Commission’s regulations requires pipelines to post offers to sell and to purchase released capacity. Show Cause Order at P 3. Within 60 days of the publication of the NOPR in the Federal Register, pipelines must either demonstrate that their tariffs fully comport with Section 284.8(d) or propose tariff medications that are fully compliant. Id. at P 6.

FERC directs NERC to Develop Physical Security Reliability Standards

Posted in Electric

On March 7, 2014, the Federal Energy Regulatory Commission (FERC) issued an order directing the North American Electric Reliability Corporation (NERC) to develop reliability standards requiring owners and operators of the Bulk-Power System to address risks due to physical security threats and vulnerabilities within 90 days of the date of the order (June 5, 2014). FERC expects the proposed Reliability Standards to “require owners or operators of the Bulk-Power System to take at least three steps to address the risks that physical security attacks pose to the reliable operation of the Bulk-Power System,” the results of which should be updated periodically and verified independently by NERC, the Regional Entities, reliability coordinators or some other third parties. Order at P 6.

First, FERC states that “the Reliability Standards should require owners or operators of the Bulk-Power System to perform a risk assessment of their systems to identify their ‘critical facilities.’” Id. As under CIP-002, FERC defines a “critical facility” as “one that, if rendered inoperable or damaged, could have a critical impact on the operation of the interconnection through instability, uncontrolled separation or cascading failures on the Bulk-Power System.” Id. Based on discussions with NERC staff and past experience with identifying critical assets under NERC’s cybersecurity standards, the physical security standards will likely provide high level criteria by which the industry should assess which facilities are critical, but NERC and FERC staff contemplate that the new standards will cover relatively few (under 500) bulk-power system facilities.

Second, FERC states that “the Reliability Standards should require owners or operators of the identified critical facilities to evaluate the potential threats and vulnerabilities to those identified facilities.” Id. at P 8. FERC expects the Reliability Standards to require that owners or operators of critical facilities “tailor their evaluation to the unique characteristics of the identified critical facilities and the type of attacks that can be realistically contemplated.” Id.

Third, FERC states that “the Reliability Standards should require those owners or operators of critical facilities to develop and implement a security plan designed to protect against attacks to those identified critical facilities based on the assessment of the potential threats and vulnerabilities to their physical security.” Id. at P 9. FERC expects that the Reliability Standards will “require that owners or operators of identified critical facilities have a plan that results in an adequate level of protection against the potential physical threats and vulnerabilities they face at the identified critical facilities.” Id.

Finally, FERC directs NERC to “include in the Reliability Standards a procedure that will ensure confidential treatment of sensitive or confidential information but still allow for the Commission, NERC and the Regional Entities to review and inspect any information that is needed to ensure compliance with the Reliability Standards” because “[g]uarding sensitive or confidential information is essential to protecting the public by discouraging attacks on critical infrastructure.” Id. at P 10. FERC also has designated six employees as non-decisional staff to assist in the development of the physical security standards.

The impetus behind the Order is the recent public focus on an April 16, 2013 attack on PG&E’s Metcalf substation, located south of San Jose, California, and pressure from lawmakers, including U.S. Senators Harry Reid, D-NV, Ron Wyden, D-OR., Dianne Feinstein, D-CA, and Al Franken, D-MN, for FERC and NERC to establish new physical security standards. During the Metcalf attack, 150 rounds were fired from an assault rifle, knocking out 17 transformers. (Smith, Rebecca, “Mystery Assault on Power Grid,” WSJ, Feb. 5, 2014; Martinez, Michael, “Sniper Attack on Silicon Valley Power Grid Spurs Security Crusade by Ex-Regulator,” CNN, Feb. 7, 2014; Smith, Rebecca, “Assault on California Power Station Raises Alarm on Potential for Terrorism,”, Feb. 18. 2014.) Utility workers successfully rerouted power to avoid a blackout, but the repair to the substation took almost a month, which is not atypical given the limited inventory and custom nature of transformers. To date, no arrests have been made in connection with this incident

While attention has remained focused on the Metcalf incident, it is not alone. Utilities regularly contend with sabotage. In October 2013, the U.S. Attorney’s office for the Eastern District of Arkansas announced the arrest of an Arkansas resident charged with multiple acts of sabotage on transmission facilities in August and September of 2013. The sabotage included (1) setting fire to a control house at a substation, (2) removing bolts from the base of a transmission tower, which was subsequently pulled down by a moving train, (3) cutting into and then using a tractor to pull down two electrical poles causing outages for 9,000 customers.

In response to public interest on the physical security of the grid, NERC officials and electric industry representatives have reiterated that providing safe, reliable, and affordable electricity is the industry’s top priority. Although the 90-day time frame by which NERC must write the new physical security standards is very short compared to other standards development projects, NERC officials recognize the political pressure to act expeditiously. Because FERC’s order contemplates process-oriented standards, technical input will be needed less in the drafting of the standards and more in the implementation. This should facilitate NERC’s prompt compliance with FERC’s directive.

In a separate concurring statement, Commissioner Norris was critical of FERC’s order for a number of reasons. Procedurally, Commissioner Norris was concerned that the order and the Commission’s ex parte rules would cut off needed discussion with the industry for the development of a comprehensive approach to physical security issues. In addition, Commissioner Norris indicated that the Commission’s ability to succeed in developing a comprehensive approach to physical security depended on its ability to manage confidentiality of sensitive materials, and he urged Congress to amend the Freedom of Information Act to foster more direct, but more protected dialog between the industry and the Commission on physical threats and vulnerabilities to the grid. Finally, and most fundamentally, Commissioner Norris cautioned the industry against overreacting to news reports about the Metcalf incident or undertaking costly physical security measures at the expense of other activities needed to protect grid reliability. This is in keeping with Commissioner Norris’s statements leading up to the Order in which he cautioned that “erecting various physical barriers to our grid infrastructure” is a “20th century solution for a 21st century problem.” Statement of Commissioner John R. Norris on Physical Security of the Electric Grid, Feb. 20, 2014.

NIST Publishes Final Cybersecurity Framework

Posted in Electric

On February 12, 2014, the National Institute for Standards and Technology (NIST) published its final Cybersecurity Framework document. NIST developed this Cybersecurity Framework in response to Executive Order No. 13636 for Improving Critical Infrastructure Cybersecurity.  As previously reported in blog posts on February 15 and February 21 last year,President Obama issued this executive order to foster greater cooperation between owners and operators of critical infrastructure and federal agencies and to establish a voluntary program for protecting the cybersecurity of the nation’s critical assets.

As we reported in a blog post last October, NIST issued a preliminary Cybersecurity Framework document and solicited comments.  NIST collected these comments on its website. The commenters in the energy sector largely sought recognition of the many cybersecurity protections that the energy sector has already established (such as NERC’s critical infrastructure protection (CIP) standards or the DOE’s Electricity Subsector Cybersecurity Capability Maturity Model (C2M2)), and asked for the Cybersecurity Framework to be implemented on a coordinated basis across individual sectors.

In the final Cybersecurity Framework, NIST addressed the comments with modest changes to underscore how flexible the Cybersecurity Framework could be applied.  As NIST notes, the Framework “can be used to manage cybersecurity risk across entire organizations or it can be focused on the delivery of critical services within an organization. Different types of entities — including sector coordinating structures, associations, and organizations — can use the Framework for different purposes, including the creation of common Profiles.”  Elsewhere, NIST notes that “The Framework is not a one-size-fits-all approach to managing cybersecurity risk for critical infrastructure,” and that individual organizations will need to bring to employ their own individual risk management policies and risk tolerances, legal and regulatory requirements, and business missions in employing the Framework.  In the end, because of the open-architecture nature of the Cybersecurity Framework, the Framework establishes more of a process for describing existing and potential cybersecurity practices rather than spelling out what cybersecurity protections should be adopted by entities in critical sector industries.

Because of the flexibility built into the Cybersecurity Framework, it is difficult to tell how much traction the Framework will have in the energy sector.  Since the electricity subsector has done a lot of work across the subsector on cybersecurity under NERC’s mandatory CIP standards, individual utilities may face compliance risks utilizing the Framework to develop protections beyond those required by the NERC standards.  The entire electricity subsector (or energy sector as a whole) may need to come together to develop a common approach to implementing the Framework.

Even with coordinated efforts at the subsector or sector level, implementation of the Framework is complicated by the potential divergence between NERC’s CIP standards and the Framework.  NERC defines assets subject to the CIP standards by reference to their impact on electric reliability, while the NIST framework defines critical infrastructure by reference to issues of national importance — economy and national security issues.  The CIP standards are mandatory and prescriptive, while the Framework is voluntary and open ended.  Moreover, the NIST framework relies on more than 400 “informative references” of which 11 are the NERC CIP standards.  Understanding how to apply all of those informative references in the energy sector will require substantial effort.

Another factor that will affect voluntary adoption of the NIST Cybersecurity Framework will be the incentives that the Administration and the sector agencies will adopt to encourage private participation.  Executive Order 13636 directed the Secretaries of the Department of Homeland Security (DHS), Treasury and Commerce to work together to establish a set of incentives.  As we reported last August, the White House and DHS floated suggestions for possible incentives, including, inter alia, technical assistance, cybersecurity insurance, grants, streamlined regulation, cost recovery, and liability limitations.  However, to date, the White House has not formally announced any final set of incentives.

Lastly, while posting the Cybersecurity Framework as a final product in conformance with the directive in Executive Order 13636, NIST made clear that more work needed to be done.  NIST labeled the Framework as “version 1.0,” and as a companion to the Framework, NIST also released a “Roadmap for Improving Critical Infrastructure Cybersecurity.” In this Roadmap document, NIST makes clear its commitment to help organizations understand and use the Framework and to serve as a “convener and coordinator” of future improvements to the Framework, “at least through version 2.0.”  NIST, however, made clear that it would like to transition the responsibility for the Framework to a non-governmental organization, and it outlined several substantive areas for improvement as required by Executive Order 13636, including authentication tools, automated indicator sharing, conformity assessment, cybersecurity workforce, data analytics, federal agency alignment, international impacts, supply chain risk management, and technical privacy standards.

FERC Responds to Emergency Propane Shortage in Midwestern States

Posted in Natural Gas

On February 4, 2014, the Governers of the Midwestern States (Mark Dayton – MN; Terry Branstad – IA; Mike Pence – IN; Sam Brownback – KS; Rick Snyder – MI; John Kasich – OH; and Scott Walker – WI) sent a letter to President Obama requesting immediate assistance to address the propane supply shortage and subsequent price increases due to lower-than-average temperatures. In addition, on January 28, 2014, the Department of Homeland Security’s (DHS) Integrated Analysis Task Force issued an update on Propane Supply Issues in the United States, with three key findings, two of which are directly related to the Governers’ request for assistance: (1) unseasonably cold weather was expected over the next two weeks and additional regions or states are likely to extend or issue emergency declarations; and (2) because prices are continuing to rise some states are providing emergency heating assistance to residents who can no longer afford fuel costs.

In response to these concerns regarding propane availability, on February 7, 2014, FERC issued an order requiring Enterprise TE Products Pipeline Company, LLC (Enterprise TEPPCO) to temporarily provide priority treatment to propane shipments from Mont Belvieu, Texas, to locations in the Midwest and Northeast in order to help alleviate the shortage of propane supplies in those regions. The Commission concludes in the order that an emergency exists, and that the Commission should exercise its emergency powers pursuant to Section 1(15)(d) of the Interstate Commerce Act (ICA) to direct Enterprise TEPPCO to immediately provide priority for propane as permitted by the prorationing policy included in Enterprise TEPPCO’s tariff.  The Commission has never before used its authority under Section 1(15)(d) to require such priority treatment for shipments to particular regions of the country.

Initially, Enterprise TEPPCO was required to comply with this emergency directive for seven days pending further review and order of the Commission. However, due to an agreement between the Commission and Enterprise TEPPCO dated February 10, 2014, Enterprise TEPPCO will continue to provide priority treatment for propane shipments to the Midwest and Northeast through February 21, 2014. The Commission issued an order regarding this extension of time on February 11, 2014.

FERC Approves Stipulation and Consent Agreement with Louis Dreyfus Energy Services Regarding Use of Virtual Trades to Enhance the Value of FTRs in Violation of the Anti-Manipulation Rule

Posted in Electric

On Friday, February 7, 2014 the Federal Energy Regulatory Commission (FERC) approved a Stipulation and Consent Agreement between FERC Enforcement Staff and Louis Dreyfus Energy Services L.P. (LDES) in Docket No. IN12-6-000, 146 FERC ¶ 61,072 (2014). The conduct at issue involved the “FTR Group” at LDES which traded in virtual supply bids, virtual demand bids and Financial Transmission Rights (FTRs) in the Midcontinent Independent System Operator, Inc. (MISO) markets.

LDES stipulates to the facts in the Consent Agreement, but neither admits nor denies the violations.  LDES agrees to:

  1. pay to MISO disgorgement of $3,334,000 plus interest of $383,743;
  2. pay a civil penalty of $4,072,257 to the United States Treasury; and
  3. implement procedures to improve compliance in the future, subject to monitoring via submission of semi-annual reports for two years.

In addition, one of the LDES traders, Xu Cheng, individually will pay a civil penalty of $310,000 to the United States Treasury.  The virtual supply, virtual demand and FTR trading occurred from November 2009 through February 2010.


Virtual supply bids and virtual demand bids are cleared in the day-ahead market and are settled in the real-time market.  There is no obligation to buy or sell physical power with a virtual demand bid and virtual supply bid; the trade’s profits or losses come from settlement difference between the day-ahead price and the real-time price.  Virtual bidding promotes convergence between Day-Ahead and Real Time energy prices.

However, virtual supply bids and virtual demand bids also have the potential to affect day-ahead congestion at a given node because they are bid and cleared in the day-ahead market.  Moreover, a large volume of virtual supply bids and/or virtual demand bids can increase or decrease nearby day-ahead congestion enough to affect the value of FTRs that “source” or “sink” at that same node or other nearby nodes.  This increase in the value of FTRs can be profitable even if the settlement of the underlying virtual bid(s) results in a loss.  This is precisely what occurred in the instant proceeding.

LDES Trading Activity

LDES’s FTR Group started trading FTRs at a particular MISO node (Velva) in North Dakota and it made little to no profit on these trades.   However, profits on the FTRs began to accrue in November of 2009 when LDES’s trader submitted virtual demand bids at the same node.  By the end of February 2010, the FTR Group had realized profits of $3,334,000 on its FTRs that were directly attributable to the virtual demand bids at the Velva node.   This was the case even though over the same period the virtual demand bids produced losses.  FERC Enforcement Staff also noted that in March of 2010, when LDES’s FTR positions at Velva dropped off substantially, the FTR Group also stopped its virtual trading at the Velva node.

In addition to the monetary fines and disgorgement of profits mentioned earlier, LDES is to institute new policies and associated processes to review and document the purpose of each virtual transaction it executes in MISO.  These processes include incorporating into its trading software a log for each virtual trade made.  The log must be retained for three years and identify: (i) the trader that submitted the trade to MISO; and (ii) the primary congestion that the FTR group was attempting to capture with the trade or other reason for the trade.  The processes also require LDES to identify a single computer that LDES shall use for at least three years to conduct all of its virtual trades in MISO.  The computer is to include software that automatically records key strokes and screen shots.

Finally, LDES is to submit semi-annual compliance monitoring reports to Enforcement for two years following the Effective Date of the Consent Agreement.  Each report is to:

  1. identify any known violations of FERC regulations that occurred during the applicable period, including a description of the nature of the violation and what steps were taken to rectify the situation;
  2. describe all compliance measures and procedures related to compliance with FERC regulations that LDES instituted or modified during the applicable period;
  3. describe all FERC-related compliance training that LDES administered concerning such products during the applicable period, including the dates of the training, the topics covered, and the procedures used to confirm which personnel attended.

In addition, each compliance monitoring report must include an affidavit executed by one of LDES’s officers stating that the report is true and accurate to the best of his/her knowledge.