Energy & Environmental Law Adviser

EEI Urges FERC to Reform its ROE Methodology

By Linda S. Kizuka on Posted in Electric

On June 6, 2013, the Edison Electric Institute (EEI) issued a white paper urging the Federal Energy Regulatory Commission (FERC) to reevaluate the method it uses to establish returns on equity (ROEs) for transmission investments. In the white paper, EEI asserts that investment in transmission infrastructure provides considerable benefits to transmission customers, and notes that transmission investment by its members has nearly doubled between 2001 and 2011.

According to EEI, the need for continued transmission investment is undisputed, and many of the projects that will provide the most significant benefits to customers are the large regional and inter-regional backbone projects. As EEI explains, “these projects also carry the most upfront development time, longer construction schedules, and overall risk.” However, without a sufficient ROE, electric utilities are likely to choose short-term, more local projects, instead of riskier, more strategic options. EEI also asserts that in order for the reforms in Order No. 1000 to be effective in promoting the construction of projects identified in regional and inter-regional planning processes, utilities need to be assured of adequate returns on those investments.

EEI stresses that the risks and challenges associated with developing transmission have not diminished in recent years. According to EEI, these risks and challenges separate transmission investment from investments in any other utility infrastructure where the projects tend to be smaller in size, shorter in duration, and located in a single area. Regulatory certainty is required to obtain and maintain financing, because transmission projects tend to be long-term in nature.

EEI also asserts that utilities compete globally and with other industries for capital. The ROE approved by FERC for an electric utility is intended to give investors a return “comparable to returns on similar investments of comparable risk. In order for utilities to attract capital to develop needed transmission, the ROE approved by FERC must be adequate and stable to attract investors and meet regulatory standards affirmed by the courts.” In order for investors to be willing to commit capital to utilities, they must expect to earn a predictable return that is commensurate with the returns for comparable-risk investments. Accordingly, EEI explains that FERC decisions significantly reducing ROEs would further shrink the pool of funds available for transmission investment. EEI states, “if returns on electric transmission infrastructure are not sufficient and stable, investors will avoid such investments and will instead seek better and more stable returns elsewhere.”

According to EEI, the Discounted Cash Flow (DCF) financial model currently used by FERC to establish ROEs results in transmission ROEs that are below currently authorized state ROEs by 200 or more basis points. EEI encourages FERC to take the opportunity to consider adjustments to its DCF methodology to avoid sending unintended investment signals. EEI’s white paper sets forth a number of specific suggestions:

  • Requests to lower existing ROEs should be required to demonstrate that the existing ROEs fall outside the range of reasonableness.
  • FERC should exercise flexibility, within or as an adjunct to, its existing DCF methodology to account for the current, extraordinary financial environment and ensure that ROEs are sufficient to support needed investment.
  • FERC should consider the results of alternative approaches, such as the risk premium method and the capital asset pricing model, and should consider the results of the current DCF analysis performed on a proxy group of companies from other capital-intensive industries or low-risk firms from the competitive sector.
  • FERC should increase the threshold for the exclusion of low estimates in a proxy group to eliminate returns that are not at least 200-300 basis points above the prevailing long-term utility bond yield; and/or incorporate projected bond yields and then apply the currently applicable 100-basis-point threshold.
  • FERC should adjust its policy of removing both the low and high DCF values if only one value is an outlier. The FERC should recognize that low and high DCF values for a utility are independent estimates, and the fact that one is considered to be an outlier does not compromise the remaining estimate for that utility.
  • FERC should establish a shorter period of time for excluding companies with a recent dividend cut.

EEI concludes by urging FERC to reaffirm its commitment to transmission investment by making necessary adjustments in its approach to setting a just and reasonable ROE for transmission investment. EEI’s white paper is available here.

EEI’s white paper is certain to be controversial, since customer groups have been arguing for lower ROEs for many months. With approximately 20 cases pending before FERC seeking amendments to electric utilities’ ROEs, FERC is likely to decide what direction to take in the near future. We expect to see action from FERC on these issues in the coming months, perhaps as soon as FERC’s open meeting in July.

FERC Staff Issues Report on Bonneville Power Administration’s Reliability Standards Audit

By Joel deJesus and Jesse Halpern on Posted in Electric

On April 24, 2013, FERC’s Director of Enforcement issued a letter order accepting a FERC Staff audit of Bonneville Power Administration (BPA) to evaluate its compliance with NERC’s Reliability Standards. This is one of a handful of instances in which FERC staff has undertaken to assess Reliability Standards compliance without the direct involvement of NERC or its regional entities.

One other unique aspect of this audit report is the fact that BPA is a non-public utility and is not subject to FERC’s ratemaking jurisdiction.  Of the four entities for which FERC staff has conducted Reliability Standards audits, two were non-public utilities — BPA and Salt River Project, for whom an audit report has not yet been issued.  This is the first FERC audit report related to a non-public utility’s compliance with the NERC Reliability Standards.

Audit Report

FERC’s staff issued its audit letter to BPA on November 15, 2011. The audit covered the period from June 18, 2007 to January 25, 2013 and addressed BPA’s role as a balancing authority, load serving entity, planning authority, purchasing-selling entity, resource planner, transmission operator, transmission planner, transmission owner and transmission service provider.

Ultimately FERC staff found six areas “in which BPA can improve compliance” and outlined 16 recommendations.  The audit report does not make any conclusions as to whether BPA committed any possible violations of the Reliability Standards.  In a number of cases, the findings and recommendations fall outside of the scope of the Reliability Standards, but in other instances the findings and recommendations appear to correct deficiencies with respect to compliance with the reliability standards:

  • Protection System Maintenance and Testing – FERC staff found that BPA did not specify maintenance and testing intervals for certain of its remedial action schemes as required under Reliability Standard PRC-005-1b R1.2.  The audit report notes that BPA required testing for those remedial action schemes “as required,” which generally meant annually but could be extended to 18 months or more if systems conditions warranted, but FERC staff recommended that BPA establish specific and supportable outer limits for the maintenance and testing intervals for these protection systems.  FERC staff also found that BPA failed to include several pieces of protection system equipment in its maintenance and tracking tool, which meant that BPA did not have complete documentation of its maintenance and testing as required by PRC-005-1b R2.  FERC staff recommended that BPA adopt a process to ensure that all facilities were properly tracked.  Going beyond the standards, FERC staff also recommended that BPA change the policy by which it could deviate from established maintenance and testing intervals, which FERC found lacked limits on the number or length of such deviations.
  • Outage Coordination – FERC staff noted that BPA conducts transmission planning studies and sets system operating limits (SOLs) under Reliability Standard TOP-002-2.1b in coordination with the Northwest Power Pool (NWPP).  FERC staff noted, however, the NWPP planning studies only considers planned outages of facilities at 230 kV or above or outages of other facilities that individual facility owners believe would be helpful to include in the studies.  FERC staff ultimately concluded that BPA studies the impact of all BPA-owned facilities operating at 115 kV and above in establishing SOLs.  However, FERC staff found that other NWPP members did not include facilities operating below 230kV in the SOL studies, which FERC staff feared would reduce the accuracy of the SOL studies.
  • Load Shedding Plans – FERC staff found that BPA had several areas prone to voltage stability issues, but to address those issues BPA had procedures in place that would allow BPA to direct load shedding by distribution providers in its footprint or, if the distribution providers did not respond to the directive, to initiate its own load shedding at the transmission level as necessary.  FERC staff raised concerns about whether BPA’s process would be effective within the 30 minute time frame required for responding to SOL violations under Reliability Standard TOP-007-WECC-1.  Although not provided for in the Reliability Standards, FERC staff recommended  that BPA (1) automate the processes by which load shedding amounts were calculated and by which BPA decided whether transmission level load shedding was needed and (2) conduct load shedding drills with its distribution providers
  • Transmission Planning – FERC staff found that BPA’s planning process entailed performing a screening study every three years, which included a full load flow and stability study for BPA’s entire transmission system, but would only do a more detailed area study if the screening study identified areas in which there was deficient performance.  FERC staff endorsed changes in BPA’s planning process that would require an annual review of all load service areas in its footprint, with detailed reviews for areas with significant changes in load or generation or for areas where system upgrades are planned.  Areas with no significant changes and no planned upgrades will be studied at least every two years.
  • Critical Cyber Asset Identification – FERC staff noted that while BPA had documented procedures for identification of critical cyber assets in its control centers, BPA did not have documented procedures for identification of critical cyber assets supporting equipment in the field.  Although FERC staff stated that Reliability Standard CIP-002-3 R3 does not require an entity to have such documented procedures, FERC staff recommended that BPA adopt them anyway and to model them after the brightline test for identification of critical cyber assets under a currently pending version 4 of Reliability Standard CIP-002.  Also, although CIP-002-3 R3 requires that BPA identify critical cyber assets by identifying cyber assets that are “essential” to the operation of BPA’s critical assets, FERC staff recommended that BPA read “essential” to mean not just cyber assets that control the operation of critical assets, but also cyber assets that monitor critical assets.

In a letter appended to the audit report, BPA indicated that it agreed with all of the recommendations and in some cases was well on its way to implementing a number of them already.

Conclusive Findings?

Despite the very detailed nature of the audit report, it is unclear whether the report provides FERC’s complete and final assessment of BPA’s compliance with the Reliability Standards.  As noted in our recent blog article related to the $975,000 civil penalty FERC assessed against Entergy, a FERC staff audit report  with a handful of recommendations can still result in a referral to FERC’s investigation staff.  In the Entergy case, a civil penalty was assessed two years after Entergy’s audit report was issued for several alleged violations of Reliability Standards that were not identified in Entergy’s audit report.  The BPA audit report gives no indication whether FERC audit staff has made a similar referral to FERC’s investigation staff or whether FERC staff was fully satisfied by the corrective actions by BPA, which are referenced in the audit report.  Despite significant efforts on the part of FERC to improve the transparency of its enforcement activities, the process by which FERC audits Reliability Standards and the relationship between those audits and an entity’s potential exposure to civil penalties remains unclear.

Cyber Security

Finally, the findings related to CIP-002 in the audit report are noteworthy for a few reasons.  First, as with the Entergy settlement, the BPA audit report publicly finds fault with BPA’s  identification of critical cyber assets, and departs from FERC’s and NERC’s traditional practice of masking the identity of entities that are alleged to have violated the CIP Reliability Standards.  Although that practice was intended to avoid disclosing weaknesses in cybersecurity controls which could be targets of future cyberattacks, FERC does not explain why it chose to disclose this particular cybersecurity issue or why the security concerns related to this particular disclosure are minimal.  A second item of note is the fact that FERC’s recommendation is to implement documented procedures based on the bright line test established in Version 4 of the CIP Reliability Standards, which were not due to take effect until April 2014.  As reported in a previous blog article, FERC recently proposed a rulemaking to adopt Version 5 of the CIP Reliability Standards and to have Version 5 supersede Version 4 before Version 4 ever becomes effective.  Finally, FERC staff’s recommendation in this regard appears inconsistent with the views of at least one regional entity (WECC), which found that an entity implementing the Version 4 bright line test had violated the Version 3 requirement that the entity needed to adopt a risk-based assessment methodology for determining critical assets and associated critical cyber assets.

FERC Proposes to Adopt Version 5 of NERC’s Cyber Security Standards and takes other Reliability-Related Actions

By Joel deJesus and Jed Dearborn on Posted in Electric, Regulatory

At its open meeting, on April 18, 2013, FERC took a number of actions related to reliability.

CIP Version 5

The most significant of these actions is the issuance of a notice of proposed rulemaking (NOPR) in which FERC proposes to adopt “Version 5 Critical Infrastructure Protection Reliability Standards.”  These are NERC’s proposals to modify cyber security controls and extend the scope of the systems that are protected by the critical infrastructure protection (CIP) reliability standards.  NERC’s proposal includes its new approach to identifying and classifying covered assets – now called “BES Cyber Systems.”   It also requires at least a minimum classification of “Low Impact” for all BES Cyber Systems.  While proposing to approve the proposed CIP standards, the Commission seeks comment on a number of aspects of the CIP standards and proposes to direct that NERC remove ambiguous language and assure that Low Impact assets have a clear compliance expectation that includes specified cyber security controls.

NERC’s January 31, 2013 petition submitting the Version 5 standards  sought Commission approval of eight modified CIP reliability standards and two new ones:

  1. CIP-002-5 – Cyber Security – BES Cyber System Categorization:
    Instead of designating “critical assets” and “critical cyber assets”, this revised standards identifies BES Cyber Systems, which can adversely affect the BES within 15 minutes of being compromised and adopts three categories of such systems (high, medium and low impact) based on specific criteria that characterize their potential impact for on the reliable operation of the BES.
  2. CIP-003-5 – Cyber Security – Security Management Controls:
    Requires implementation of policies related to cyber security awareness, physical security controls, electronic access controls, and incident response to a Cyber Security Incident for those assets that have Low Impact BES Cyber Systems under CIP-002-5’s categorization process.
  3. CIP-004-5 – Cyber Security – Personnel and Training:
    Requires documented processes or programs for security awareness, cyber security training, personnel risk assessment, and access management.  Also, the revised standard adds specific training roles for visitor control programs, electronic interconnectivity supporting the operation and control of BES Cyber Security Systems, and Storage Media as part of the treatment of BES Cyber System Information.
  4. CIP-005-5 – Cyber Security – Electronic Security Perimeter(s):
    Focuses on the discrete Electronic Access Points rather than the logical “perimeter” which is the focus of the currently effective CIP-005-3.
  5. CIP-006-5 – Cyber Security – Physical Security of BES Cyber Systems:
    Manages physical access to BES Cyber Systems by specifying a physical security plan to protect BES Cyber Systems against compromise that could lead to misoperation or instability.
  6. CIP-007-5 – Cyber Security – Systems Security Management:
    Addresses system security by specifying technical, operational, and procedural requirements in support of protecting BES Cyber Systems against compromise that could lead to misoperation or instability of the BES.  The changes to this standard make the requirements less dependent on specific technology so that they will remain relevant for future, yet-unknown developing technologies.
  7. CIP-008-5 – Cyber Security – Incident Reporting and Response Planning:
    Requires responsible entities to report Cyber Security Incidents within 1 hour of recognition, test to verify response plan effectiveness, and perform after-action review for tests or actual incidents.
  8. CIP-009-5 – Cyber Security – Recovery Plans for BES Cyber Systems:
    Includes controls to protect data that would be useful in the investigation of an event that results in the execution of a Cyber System recovery plan and operational testing to support the recovery of BES Cyber Systems.
  9. CIP-010-1- Cyber Security – Configuration Change Management and Vulnerability Assessments:
    Consolidates the configuration change management requirements previously included in CIP-003, CIP-005,and CIP-007 and establishes the configuration monitoring requirements intended to detect unauthorized modification of BES Cyber Systems, and establishes the vulnerability assessment requirements intended to ensure proper implementation of cyber security controls while promoting continuous improvement of a responsible entity’s cyber security posture.
  10. CIP-011-1 – Cyber Security – Information Protection:
    Consolidates information protection controls previously covered by CIP-003 and CIP-007 to prevent unauthorized access to BES Cyber System Information and specifies reuse and disposal provisions to prevent unauthorized dissemination of protected information.

In the NOPR, the Commission found that the modified CIP Version 5 standards are an improvement over the current CIP standards and are just, reasonable, not unduly discriminatory or preferential, and are in the public interest. The Commission also approved of NERC’s proposal to allow responsible entities to transition from compliance with the currently-effective CIP version 3 Standards to compliance with the CIP version 5 Standards, effectively retiring the CIP version 4 Standards prior to mandatory compliance. However, the Commission identified several concerns with certain provisions of the standards.

The Commission expressed concern that 17 requirements of the CIP Version 5 standards incorporate a requirement that Responsible Entities implement cyber policies in a manner to “identify, assess, and correct” deficiencies.  The Commission is concerned that this language is unclear with respect to the implementation and compliance obligations it places on regulated entities and that it is too vague to audit and enforce compliance.  Although the language appears to impose a substantive requirement to design cyber policies in a manner consistent with NERC’s risk-based approach to regulation and its efforts to encourage entities to develop strong internal controls, the Commission was concerned that the language could be read to impose to separate obligations – one, to adopt certain cyber policies and two, to correct deficiencies.  The Commission sought comment on the meaning of this language and how it will be implemented and enforced.

Also, Commission found that NERC’s new approach to categorizing BES Cyber Systems is “a step closer to comprehensively protecting assets that could cause cyber security risks to the [BES].”  However, the Commission indicated that NERC should consider improving the categorization process and should modify the minimum protections required for Low Impact assets.  Specifically, the Commission noted that the only the protections for Low Impact BES Cyber Systems were under CIP-003-5 R2  which requires an entity to document and implement policies for cyber security awareness, physical and electronic security and incident response.  Because the obligation to adopt policies may result in inconsistent implementation of the CIP Reliability Standards, the Commission proposed to direct NERC to develop a modification to CIP-003-5 to require responsible entities to adopt specific, technically-supported cyber security controls for Low Impact assets.

Additionally, the Commission sought comment on four areas where it generally believes the proposed standards could be enhanced:

  1. whether the adoption of certain communications security protections, such as cryptography and protections for non-routable protocol, would improve the CIP Reliability Standards;
  2. whether the adoption of more stringent controls for remote access would improve the CIP Reliability Standards;
  3. whether the proposed 24-month implementation period of High and Medium-Impact BES cyber systems, and 36-month implementation period for Low-Impact BES Cyber Systems, are justified and whether a shorter implementation period is feasible in light of the fact that FERC would not require entities would to come into compliance with version 4; and
  4. whether the adoption of certain aspects of the NIST Risk Management framework could improve the security controls proposed in the CIP Version 5 Standards.

Comments on the NOPR are due sometime in June, 60 days after the NOPR is published in the Federal Register.

BES Definition; GO/TO Standards; Criteria for 215 Funding

FERC issued three other orders related to different aspects reliability regulation.

First, in Order No. 773-A, “Revisions to Electric Reliability Organization Definition of Bulk Electric System and Rules of Procedure,” the Commission affirmed its findings in Order No. 773 that (1) the modified definition of “bulk electric system” improves upon the currently-effective definition by establishing a bright-line threshold that includes all facilities operated at or above 100 kV and removing language that allows for broad regional discretion; (2) NERC’s case-by-case exception process to add elements to, and remove elements from, the definition of the bulk electric system adds transparency and uniformity to the determination of what constitutes the bulk electric system; (3) the Commission can designate sub-100 kV facilities, or other facilities, as part of the bulk electric system; and (4) an entity can seek a determination by the Commission whether facilities are “used in local distribution” as set forth in the Federal Power Act.

Second, the Commission issued a second NOPR, entitled “Generator Requirements at the Transmission Interface.” In this NOPR, the Commission is proposing to approve four modified reliability standards to clarify their applicability to generator interconnection facilities. The Commission states that the proposed modifications improve reliability by extending their applicability to certain generator interconnection facilities, or by clarifying that the existing Reliability Standard is and remains applicable to generator interconnection facilities.  Among these four revised reliability standards are:

  • FAC-001-1 (Facility Connection Requirements) –  which was clarified to provide that generators need only publish facility connection requirements for their generator interconnection facilities when they have entered into a reliability impact study agreement with a third party
  • FAC-003-3 (Transmission Vegetation Management) – which extends the vegetation management requirements to generator leads  that extend more than a mile from the switchyard or that do not have a clear line of sight from the switchyard
  • PRC-004-2.1a (Analysis and Mitigation of Transmission and Generation Protection System Misoperations) – which was clarified to extend the requirement that a generator owner analyze misoperations on the protection systems both for the generating units and for the generator interconnection facilities
  • PRC-005-1.1b (Transmission and Generation Protection System Maintenance and Testing) – which was clarified to extend required maintenance and testing programs to protection systems governing the generator interconnection facilities (and not the protection systems for the generating units).

Finally in a third order, FERC accepted with minor modification NERC’s proposed criteria for identifying activities that would be subject to funding under Section 215 of the Federal Power Act. These criteria were proposed as a result of the 2011-12 audit of NERC by FERC audit staff.  The Edison Electric Edison objected strongly to these criteria as being too expansive and unrelated to NERC’s core statutory responsibilities of writing reliability standards, enforcing them, and conducting periodic reliability assessments.  Despite these objections, FERC approved the criteria with minor modification.  Although NERC had proposed criteria for activities that “involve and support” standards development, enforcement and other identified functions, FERC required NERC to  replace the “involve and support” language with stronger language  that would make a NERC activity eligible for statutory funding only if it was “necessary and appropriate” for a statutory function.

Additional links:

CFTC Grants No-Action Relief for End Users from Swap Reporting Requirements

By Laura R. Chipkin and Noy S. Davis on Posted in Regulatory

On April 9, 2013, the Division of Market Oversight of the U.S. Commodity Futures Trading Commission (CFTC) issued a no-action letter delaying the swap reporting compliance deadlines for end users and other swap counterparties that are not swap dealers or major swap participants (non-SD/MSP counterparties).  The relief provided to market participants is effective immediately.

The CFTC had issued regulations setting forth various reporting requirements for swap transactions (Part 43 — real-time reporting for swap transactions, Part 45 — transactional data reporting to a registered swap data repository, and Part 46 — historical swap data reporting) of the CFTC’s regulations. The rules had established a deadline of April 10, 2013 for swap counterparties that are not swap dealers or major swap participants (non SD/MSP counterparties). Citing implementation concerns involving technological and operational capabilities, a number of market participants requested that the Division of Market Oversight provide a six-month extension of the compliance deadline.  The CFTC’s April 9 no-action  letter does not grant the full six-month extension requested, but provides certain time-limited no action relief to nonSD/MSP swap counterparties as described below.

1          No-Action Relief for Reporting of Interest Rate and Credit Swaps

The letter extends no-action relief for end users’ interest and credit swaps reporting until July 1, 2013.  However, non SD/MSP swap counterparties that are “financial entities,” as defined in Section 2(h)(7)(C), must comply with reporting requirements under Part 43 and 45 on April 10, 2013.

2.         No-Action Relief for Reporting of Equity, Foreign Exchange and other Commodity Swaps

The no-action relief for end users who engage in swaps in other asset classes (e.g., equity, foreign exchange, and other commodities) is extended until August 19, 2013.  For non-SD/MSP swap counterparties that are “financial entities,” as defined in Section 2(h)(7)(C), the no-action relief extends until May 29, 2013.

3.         No-Action Relief for Historical Swap Data Reporting Under Part 46

The letter also extends no-action relief to end users’ Part 46 historical swap data reporting for all swap asset classes until October 31, 2013.  For non SD/MSP swap counterparties that are “financial entities,” as defined in Section 2(h)(7)(C), the Part 46 no-action relief extends until September 30, 2013.  Any pre-enactment or transition swap entered into prior to 12:01 a.m. on April 10, 2013 is reportable as a historical swap.

4.         Compliance Date for Recordkeeping Obligations has not been Extended

The letter also confirms that the no-action relief provided for reporting requirements does not impact any Dodd-Frank-related recordkeeping obligations applicable to SDs, MSPs or end users.  Thus, for historical swaps, end users must maintain records under the Part 46 rules for any such swaps entered into prior to April 10, 2013.   With respect to swaps entered into on or after April 10, end users must maintain records under the Part 43 and 45 rules, and obtain a CFTC Interim Compliant Identifier for this purpose by April 10, 2013.

Fourth Circuit Decides Key CERCLA Allocation and Liability Case

By Ashley L. Thompson and J. Michael Showalter on Posted in Land/Waste

The Comprehensive Environmental Response, Compensation, and Liability Act (CERCLA) is a federal statute that, among other things, allows parties to allocate environmental remediation costs among parties whose operations may have resulted in environmental contamination.  CERCLA cases with multiple potentially responsible parties (PRPs) generally proceed in two phases.  During the first phase — the “liability” phase — the court addresses whether each individual PRP fits within the statutory definition of a liable party under CERCLA.  During the second phase — the “allocation” phase — the court allocates the cost of environmental remediation among all of the parties that were found to be liable during the first phase.  CERCLA decisions before the appellate courts tend to focus on liability issues in part because parties often settle after the liability phase.  As a result, appellate decisions offering guidance on allocation are rare, but important to CERCLA practitioners.

In PCS Nitrogen Inc. v. Ashley II of Charleston, No. 11-1662 (4th Cir. Apr. 4, 2013) (hereinafter “Ashley II”), the Fourth Circuit affirmed the district court’s allocation of costs among various PRPs at a site located in Charleston, South Carolina.  This decision is likely to impact parties who are involved at large CERCLA Superfund sites, and is particularly important for “Brownfield” redevelopers who are seeking to avoid CERCLA liability through the Bona Fide Prospective Purchaser (BFPP) exemption.  Indeed, Ashley II is the first appellate decision to substantively address what “reasonable steps” a party seeking to meet the BFPP exemption must take when it purchases contaminated property.

The BFPP exemption allows qualified buyers protection from CERCLA liability.  42 U.S.C.A. § 9601(40).  In Ashley II, one PRP argued that it qualified as a BFPP and should therefore be exempt from liability.  Id. at *29.  The district court disagreed and found that the PRP failed to meet various requirements necessary to establish its status as a BFPP.  Id. at *30.  As one example, the district court held that the PRP did not “exercise[] appropriate care with respect to hazardous substances found at the facility by taking reasonable steps to “(i) stop any continuing release; (ii) prevent any threatened future release; and (iii) prevent or limit human, environmental, or natural resource exposure to any previously released hazardous substance.”  42 U.S.C.A. § 9601(40)(D).  The Fourth Circuit affirmed and noted that the standard of “appropriate care” “is at least as stringent as ‘due care’ under” the third party defense, and “should be higher.” Id. at *31 (emphasis in original).  The PRP did not meet this requirement because it “failed to clean out and fill in sumps that should have been capped, filled, or removed when related above-ground structures were demolished, and …  did not monitor and adequately address conditions relating to a debris pile and the limestone run of crusher cover on the site.”  Id. at *30.

In another important holding, the Ashley II opinion addressed the definition of “facility” under CERCLA.  Throughout the Ashley II litigation, one PRP argued that it was not liable because its leased property was not “part of the property” undergoing remediation.  Id. at *27.  The Court rejected this argument as “irrelevant” because the “question is whether [the PRP’s] leasehold is part of a ‘facility’ as defined by CERCLA,” not whether the property has been “targeted for remediation.”  Id.  CERCLA defines “facility” as “any site or area where a hazardous substance has been deposited, stored, disposed of, or placed, or otherwise come to be located.”  42 U.S.C.A. § 9601(9).  Because the leased property at issue in Ashley II was “contaminated as part of a pattern of widespread contamination across the entire site,” it was part of the facility as defined by CERCLA.  Id.  The Court further noted that to hold otherwise would allow the owner or operator of a “less-contaminated” area of the property to “avoid liability for CERCLA response costs for the rest of the facility merely by demonstrating less pollution-sensitive land use.”  Id. at *28.  According to the Court, such a result would run contrary to CERCLA’s strict liability scheme and the limited exceptions to liability under the statute.  This holding may have important implications for large Superfund sites where PRPs attempt to divide the site by operating areas because investigation, remediation, and characterization activities at different portions of the site proceed on separate timelines over decades.

Finally, in Ashley II, the Fourth Circuit declined to answer an interesting question related to the reasonable basis for apportionment analysis.  Under CERCLA, there are two separate inquiries — apportionment and allocation — that allow a court to divvy up costs among parties.  Apportionment occurs during the liability phase.  Through apportionment, a party argues that it should not be held joint and severally liable for the environmental harm because the harm can be reasonably apportioned.  If a party is successful in making this showing, the court then declines to impose joint and several liability, and instead apportions the environmental remediation costs among potentially liable parties.  Allocation, on the other hand, is the process of dividing up costs among all the liable parties, after the parties have all been held joint and severally liable for an environmental harm.

In Ashley II, two PRPs sought to “maintain that they established a reasonable basis for apportioning at least their individual shares of the harm.”  Id. at *37 (emphasis in original).  The Court, however, declined to address whether a PRP “must provide a reasonable basis to apportion all of the harm, or only its share of the harm, to avoid joint and several liability.”  Id. at *37 (emphasis in original).  One PRP did not provide a reasonable basis for apportionment, and therefore the question was moot.  Id. at *38.  The second PRP argued that it was not liable because as a current operator at the facility, “no disposal of hazardous substances ha[d] occurred during its operation of the facility.”  Id. at *39.  The Fourth Circuit rejected this argument holding that a zero-share of liability to a current owner or operator would negate the limited defenses and exemptions for innocent owners and operators contained in the statute.  Id. at *39.

The Ashley II decision is especially relevant for large CERCLA Superfund sites with a number of PRPs, and for any owner or operator seeking to establish BFPP status.  Please contact an environmental attorney from Schiff Hardin if you have any questions about the BFPP exemption or any other issue related to CERCLA liability.

Ninth Circuit Holds that In-Use Utility Poles Not Subject to the Clean Water Act or the Resource Conservation and Recovery Act

By Russel B. Selman, Bradley S. Rochlen, and J. Michael Showalter on Posted in Electric, Land/Waste, Products, Water

On April 3, 2013, in Ecological Rights Foundation v. Pacific Gas and Electric Company (ERF v. PG&E), the Ninth Circuit upheld the dismissal with prejudice of a case where an environmental group using statutory “citizen suit” provisions alleged that wood-treated utility poles are subject to the federal Clean Water Act (CWA) and Resource Conservation and Recovery Act (RCRA).  Schiff Hardin represented PG&E in this matter.

Wooden utility poles, of which there are over 100 million in use across the United States, are treated with biocides such as pentachlorophenol to preserve their strength and increase their longevity. Wooden utility poles have long been the industry standard. They are used by virtually every electric and communications utility that operates in the United States and are a ubiquitous part of every urban and roadside landscape.

This suit stems from a long-running dispute between various environmental groups and the USEPA over whether treating utility poles with wood treatment preservative should be permitted.  USEPA last approved the continued use of the involved wood preservative – pentachlorophenol – in 2008.  In ERF v. PG&E, which was filed a year later, ERF claimed that each utility pole used by PG&E (and Pacific Bell Telephone, which was added to the Complaint after it was initially filed) in a four-county area of California was a CWA “point source” which required federal permits, and that wood treatment preservative released from the poles was a RCRA waste posing an “imminent and substantial endangerment to the environment.”

The Ninth Circuit held that neither CWA nor RCRA was applicable to in-use utility poles. The three-judge panel found that utility poles were neither “point sources” as the term is defined under CWA nor were “associated with industrial activity,” as would be required to trigger federal permitting obligations.  Poles are not “point sources,” in the Ninth Circuit’s view, because they do not “discretely collect[] and convey[] to the waters of the United States” CWA “pollutants.” In concluding that utility poles were not “associated with industrial activity,” the Ninth Circuit relied on evidence including that USEPA had explicitly excluded “major electrical powerline corridors” from stormwater regulation, as well as the wording of 40 C.F.R. § 122.26(b)(14), the regulation that defines “associated with industrial activity” for CWA.

RCRA is a statute which is designed to provide a “cradle-to-grave” framework for the regulation of waste products.  “RCRA’s ‘primary purpose’ is ‘to reduce the generation of hazardous waste and to ensure the proper treatment, storage, and disposal of waste which is nonetheless generated, ‘so as to minimize the present and future threat of harm to human health and the environment.’” RCRA’s applicability hinges on something being “abandoned” or “discarded.” Here, even though ERF’s lawsuit was focused on in-use utility poles, ERF alleged that the pentachlorophenol treatment from the poles tended to “leak” as part of its intended function as a preservative.

ERF alleged that the “leakage” of pentachlorophenol from the poles constituted a RCRA “imminent and substantial endangerment.”  The Ninth Circuit explicitly rejected that “leakage” from poles resulted in “waste” being “discarded.” Instead, the court found that “escaping” pentachlorophenol from in-use poles is “neither a manufacturing waste by-product nor a material that the consumer . . . no longer wants and has disposed of or thrown away.” Any “leakage” was a residue from an EPA-approved pesticide which is released as a part of its intended use.

This case was a test case on expanding the reach of RCRA and CWA to undercut EPA’s continued approval of a wood treatment preservative, which environmental groups were previously unsuccessful in doing directly. This decision comes on the heels of the Supreme Court’s Decker v. Northwest Environmental Defense Center decision, which arguably opens the door to environmental groups being able to use “citizen suits” to undercut long-standing agency decisions of their statutory mandates. The Ninth Circuit’s decision in ERF v. PG&E reflects that EPA’s reasoned interpretation of its rules should be respected and ERF’s interpretation of how CWA and RCRA apply to these facts was unsupportable.

CFTC Issues Two Final Orders on Dodd-Frank Exemptions

By Laura R. Chipkin and Roger E. Smith on Posted in Electric

On March 28, 2013, the CFTC issued two final orders, providing exemptive relief to certain energy-related transactions between municipals and electric cooperatives and to certain transactions that are offered or sold in Regional Transmission Organizations (RTO) or Independent System Operators (ISO).  Notwithstanding the relief granted through each of the final orders, the CFTC has reserved its general anti-fraud and anti-manipulation authority.

1.         CFTC issues Final Order Exempting Certain Transactions between Entities Described in Section 201(f) of the Federal Power Act and Other Electric Cooperatives 

The CFTC’s final order exempts certain transactions between entities described in Section 201(f) of the FPA and other electric cooperatives from the CFTC’s requirements under Dodd Frank.   Under the order, “Exempt Entities” include:

(1) any entity under Section 201(f) of the FPA, which includes government-owned electric utilities and electric cooperatives that receive financing from the Rural Utilities Service or that sell less than four million megawatt hours of electric energy in a given year;

(2) the small number of electric cooperatives that do not qualify under Section 201(f) in a given year (either because they sell in excess of four million megawatt hours of electricity in a given year or do not receive funding from the Rural Utilities Service);

(3) federally-recognized Indian tribes; and

(4) any other entity that is wholly owned, directly or indirectly, by any of the foregoing.

The Final Order defines an “Exempt Non-Financial Energy Transaction” as a transaction between any of the above Exempt Entities that would not have been entered into, but for an Exempt Entity’s need to manage supply and/or price risks arising from its existing or anticipated public service obligations to physically generate, transmit and/or deliver electric service to customers.  The “but-for” test is the result of the CFTC’s recognition that not all Exempt Non-Financial Energy Transactions will result in making or taking physical delivery of the commodity.  In other words, while some Exempt Non-Financial Energy Transactions may not result in physical delivery, all such transactions must result from the public service role an Exempt Entity has in physical electricity markets.  The CFTC stressed that the definition of an Exempt Non- Financial Energy Transaction does not allow for transactions that are purely financial arrangements lacking any essential relationship to a physical generation, transmission, and/or delivery obligation of electric energy service to customers.

The CFTC described six categories of energy transactions that would meet this but-for test.  The categories are: Electric Energy Delivered transactions; Generation Capacity transactions; Transmission Services transactions; Fuel Delivered transactions, Cross-Commodity Pricing transactions, and Other Goods and Services transactions.

2.         CFTC issues final order exempting certain transactions in ISOs/RTOs  

The CFTC’s final order exempts four classes of ISO/RTO transactions from the CFTC’s requirements under Dodd Frank, including:  (1) financial transmission rights; (2) energy transactions in day-ahead and real time markets; (3) forward capacity transactions; and (4) reserve or regulation transactions.  The transactions will qualify for exemptive relief if they are entered into between eligible parties pursuant to tariffs, rate schedules or protocols approved by FERC or, in the case of the Electric Reliability Council of Texas, the Public Utility Commission of Texas.

Please feel free to contact us with any questions you or your company may have.

FERC Imposes a $975,000 Civil Penalty against Entergy for 27 Violations of Reliability Standard

By Joel deJesus and Jesse Halpern on Posted in Electric

On March 28, 2013, the Federal Energy Regulatory Commission (FERC) issued an order approving a stipulation and consent agreement between FERC’s Office of Enforcement (OE) and Entergy Services, Inc. (Entergy) to settle violations of various North American Electric Reliability Corporation (NERC) Reliability Standards.  Although the basic terms of this settlement are largely unremarkable, there are unique aspects of this case to note.

Basic Terms

To recap briefly the settlement’s basic terms, OE found after an investigation into Entergy’s compliance with the Reliability Standards that Entergy violated 27 requirements of 15 Reliability Standards.  Specifically, OE alleged that:

  • Entergy did not account for protection system maintenance outages in its long term planning studies, and it allowed field technicians to disable protection systems without conducting prior operational planning studies.
  • Entergy did not have a facilities rating methodology for all of its transmission facilities, but instead relied on “vintage” line ratings for lines built before 1994 and put into service before the independent operating companies were consolidated into Entergy.
  • Entergy did not have a formal system operator training for its transmission operations center (TOC) staff.
  • Entergy failed to maintain accurate models for its operations and operational planning because it failed to update its models to reflect certain transmission lines placed in service or to account for auxiliary loads at its nuclear generation sites.
  • As evidenced in a number of communications outages affecting Entergy’s operations, Entergy failed to have required redundancy in its communications systems and backup power supplies, and it failed to adequately test for, plan for and respond to these communications outages.

The settlement provides that Entergy neither admits nor denies these violations, but Entergy agreed to pay a civil penalty of $975,000 and to undertake various activities to mitigate the alleged violations.  Such activities included revamping its protection system maintenance process; adopting a new facilities rating methodology and undertaking costly Light Detection and Ranging (LiDAR) studies of all 13,669 miles of its transmission lines operated at or above 100kv; clarifying the role of its TOC staff and implementing a formal training and certification program for them; and strengthening its communications infrastructure and procedures related to communications outages.  Entergy will also be obligated for the next year to make semiannual reports on its progress on these mitigation measures, investments to improve reliability and any additional violations that may occur.  The settlement also provides that OE may extend this reporting requirement for another year.

FERC’s Independent Enforcement of NERC Reliability Standards

Although OE’s findings (taken at face value) and the civil penalty do not appear to be unusual at first blush, this case is unique in that it is the first time FERC has independently assessed a civil penalty for Reliability Standards violations without direct involvement by NERC or its regional entities.  Unlike other civil penalty assessments for reliability standards violations, which have all previously arisen out of a joint investigation by FERC and NERC staffs and which have resulted in settlements among the registered entity, FERC, and NERC, this settlement only involved OE and Entergy and contains no reference to NERC’s participation or that of NERC’s regional entity with compliance enforcement authority over Entergy (SERC Reliability Corporation).

As reflected in FERC’s order approving this settlement, this case arose out of an investigation that was prompted by a referral by FERC audit staff after a 2009 audit of Entergy’s compliance with its open access transmission tariff and the Reliability Standards.  The audit was initiated by FERC staff, independently of NERC and SERC, and while NERC and SERC staff may have been invited to observe FERC’s audit, the 2010 audit report gives no information about the level of involvement NERC and SERC may have had in the findings and recommendations contained in that audit report.

Looking back at the 2010 Audit Report, there was no indication that FERC would pursue this present enforcement action.  The 2010 Audit Report included two findings by the FERC staff with respect to reliability (concerning planning for and operation during single-contingency events), and it offered three recommendations related to those finding.  However, the 2010 Audit Report made no reference to any possible violations, nor did it disclose the intent of FERC audit staff to refer the case to FERC’s investigators.

From a process and timing standpoint, FERC’s audits of compliance with Reliability Standards are very different from audits conducted by  NERC and its regional entities.  NERC and the regional entities typically conclude their audits and begin processing enforcement matters for any possible violations identified in those audits within a weeks of the commencement of the audit.  In contrast, FERC’s audit of Entergy took a little over a year to conclude, and the conclusion of the FERC audit did not finalize FERC’s review of Entergy’s compliance or give a complete picture of that Entergy’s exposure to civil penalties.  In fact, even with the audit in 2009 and this settlement in 2013, there is no indication whether NERC and SERC will conduct further investigation or enforcement actions against Entergy for this time period.

To date, FERC staff’s auditing of compliance with Reliability Standards independent of NERC and the regional entities has been relatively rare.  FERC staff has issued notices in 2011 for three other audits: PJM, Salt River Project, and Bonneville Power Administration.  Of these, only the PJM audit has reached the stage of an audit report, which FERC approved in November 2012.  Like Entergy’s audit report, the PJM audit report identifies no specific Reliability Standards violations, and it  only provides  28 “recommendations” in eight “areas in which PJM could improve performance” (related to cybersecurity, accuracy of operational models, and PJM’s contingency plan) and three “areas of interest” (related to PJM’s establishment of system operating limits and interconnection reliability operating limits and to PJM’s role as transmission operator).  If Entergy’s experience is an indication of how FERC will proceed in similar cases, PJM may soon be or may currently be subject to an investigation that could lead to findings of Reliability Standards violations and civil penalties.

Civil Penalty

Aside from the process by which FERC audited Entergy and ultimately settled this case, the $975,000 civil penalty is worth some discussion.  Compared to the $25 million civil penalty levied against Florida Power and Light and the $3.9 million civil penalty against PacifiCorp, Entergy’s civil penalty is the lowest FERC has assessed against an investor owned utility for Reliability Standards violations.  This may be a function of the fact that Entergy’s investigation was initiated by a referral from an audit and was not initiated as a result of a loss of load event, like the ones that prompted the Florida Power and Light and PacifiCorp investigations.

Still, Entergy’s civil penalty is higher than the highest penalty NERC and its regional entities have ever assessed independently of FERC.  In December 2012, FERC approved a $950,000 settlement between SERC and an “unidentified registered entity” for several violations related to the Reliability Standards governing cybersecurity.

FERC’s order approving the settlement provides little guidance as to how OE and Entergy arrived at the stipulated civil penalty.  In a single paragraph, FERC stated:

The civil penalty amount is consistent with the Penalty Guidelines. Enforcement considered that, given the size and complexity of Entergy’s system, its violations posed a high risk that it would be unable to prevent, contain, or control a disturbance that could lead to substantial harm. Entergy also has a history of past violations of the Reliability Standards, including violations of the BAL- and FAC- Reliability Standards.  The civil penalty amount reflects credit for Entergy’s full cooperation during the course of the investigation as well as a credit for avoiding a trial-type hearing.

Other than generally citing to risk, compliance history, cooperation and the fact that OE and Entergy reached a settlement, FERC does not provide any guidance as to how it applied the various formulas in its Penalty Guidelines, how much discretion FERC staff exercised in weighing the aggravating and mitigating factors in this case, or ultimately how these factors translated to a $975,000 civil penalty.  There is also little guidance on how FERC will determine civil penalty amounts in future enforcement actions related to noncompliance with Reliability Standards.

Other Items of Note

There are two other items of note about the Entergy settlement.  The first is that the settlement explicitly calls out a cybersecurity violation.  FERC staff found that Entergy violated Reliability Standard CIP-007-1 R1 because Entergy failed to test a firmware upgrade for a network switch prior to applying it in the production environment and because Entergy could not assess whether significant configuration changes to critical cyber assets would compromise its cybersecurity controls or those assets.  Stating this finding in the public settlement departs from FERC’s and NERC’s typical practice of masking the identity of entities who have committed cybersecurity violations.  The rationale for this practice is that public disclosure of information about cybersecurity violations could identify to the public (and potential cyber terrorists) weaknesses in the industry’s cybersecurity protections.  Although FERC has departed from this practice once before (in a case involving questions about FERC’s jurisdiction to assess a penalty against a federal entity for cybersecurity violations), FERC does not explain why it chose to disclose this particular cybersecurity violation or why the security concerns related to this particular disclosure are minimal.

Finally, Entergy’s reporting obligations under the settlement are notable because they go beyond reporting on Entergy’s compliance with the terms of the settlement and progress in mitigating the alleged violations.  Paragraph 44 of the stipulation and consent agreement specifically includes an obligation to report “any additional violations of Reliability Standards that have occurred and whether and how Entergy has addressed those new violations.”  Although this a mandatory self-reporting provision is common in settlements of FERC investigations, it raises significant issues in this context given the breadth of obligations under the Reliability Standards.  While entities should provide complete and accurate reports about their implementation of stipulations and consent agreements (including reports on whether they have identified violations in the course of such implementation), there is a question as to whether an entity should be required to self-report “any” Reliability Standard violation.  The settlement offers no guidance as to how certain Entergy must be about whether a new violation has occurred before it must self-report that new violation.  Also given that the settlement requires such self-reporting, there is a question whether the Entergy would be accorded self-reporting credit in any future penalty assessments that may result from such self-report.

* * *

In short, the Entergy settlement raises many questions about FERC’s ongoing implementation of Reliability Standards, the process by which FERC will identify Reliability Standards violations, and the application of FERC’s Penalty Guidelines in enforcement proceedings related to Reliability Standards.

Upcoming Deadlines – Dodd-Frank Reporting and Recordkeeping

By Debra Ann Palmer, Matthew Kluchenek, and Laura R. Chipkin on Posted in Electric, Natural Gas, Regulatory

On April 10, 2013, certain reporting and recordkeeping requirements imposed by the CFTC pursuant to the Dodd-Frank Wall Street Reform and Consumer Protection Act (“Dodd-Frank Act”) will become effective.[1]  Although some electric and gas utilities, cooperative or municipal utilities, or other similar energy companies that engage in hedging activities with financial entities may not be directly affected by these obligations, companies that engage in swaps with nonfinancial companies may be required to meet the reporting requirements.

A.        Swap Reporting Obligations

To enhance swap market transparency to regulators and the public, the Dodd-Frank Act establishes a comprehensive swap reporting regime.  Under the regime, the “reporting counterparty” to a swap is required to report information about swaps to a swap data repository (“SDR”).

Most electric and gas utilities (including cooperatives and municipals) are not likely to be considered “reporting counterparties” because they are not financial entities as defined in CEA § 2(h)(7)(C).[2]  Under the Dodd-Frank Act, nonfinancial entities do not have any reporting obligations for swap transactions in which the counterparty is a swap dealer, major swap participant (“MSP”) or a financial entity as defined in CEA § 2(h)(7)(C).  However, the utility or other nonfinancial company must provide the swap dealer, MSP or financial entity counterparty with all necessary information to meet the reporting requirements, but in most instances, the swap dealer, MSP or financial entity counterparty will have all the information needed to meet its reporting obligations.  If the non-reporting counterparty becomes aware of any errors or omissions in the data reported, the non-reporting party must notify the reporting party of the error or omission.

Where, however, a nonfinancial company enters into a swap with another nonfinancial company (including inter-affiliate swaps), the counterparties must elect which one of them will report the swap data to the SDR.  The information that must be reported includes data on the primary economic terms of the swap, as well as confirmation, valuation and continuation data.  If the swap is cleared through a regulated clearinghouse, neither party will be subject to reporting obligations because the required data will flow from the clearinghouse to the SDR.

B.        Swap Recordkeeping Obligations

All parties to swap transactions will be required to keep “full, complete and systematic records” records of their swap transactions.  These records, which must be made available to the CFTC, SEC and U.S. Department of Justice for inspection, must be maintained for at least five years after termination of a swap and must be retrievable within five business days.

Recordkeeping obligations differ depending on whether a swap is a “new” swap or a “historical” swap.  Historical swaps include so-called “pre-enactment” and “transition” swaps. Pre-enactment swaps are swaps in existence on July 21, 2010—the date upon which the Dodd-Frank Act became law.  Transition swaps are swaps entered into on or after that date but before the April 10, 2013 date for implementation of the recordkeeping requirements.

Counterparties to historical swaps that terminated before April 25, 2011 are required to keep all information and documents relating to the terms of the transactions that they possessed as of October 14, 2010 (for pre-enactment swaps) and December 17, 2010 (for transition swaps). Counterparties to these swaps are not required to recreate documentation or to alter the method by which the information they have is organized and stored.

Counterparties to historical swaps in existence on or after April 25, 2011, however, must keep records of certain minimum primary economic terms, as well as additional documentation, to the extent it has been in the counterparty’s possession at any time after April 25, 2011.  The additional documentation includes, for example, confirmations, master agreements and credit support agreements.

All information relevant to new swaps (i.e., non-historical swaps) must be retained, including all records demonstrating that a counterparty is entitled to elect the end user exception with respect to any particular swap.


[1] While some parties have asked the CFTC to delay implementation of these rules, the CFTC has not yet acted on that request.


[2] The Commodity Exchange Act, as amended, generally defines a “financial entity” to include banks, swap dealers, major swap participants, private funds, employee benefit plans, and persons predominantly engaged in activities that are financial in nature.  See CEA § 2(h)(7)(C).

Sixth Circuit Court of Appeals Rules that USEPA May Proceed with an Enforcement Action against DTE Energy

By David M. Loring on Posted in Air

On March 28, 2013, the Sixth Circuit Court of Appeals ruled that the U.S. Environmental Protection Agency (USEPA) did not need to wait until post-construction emissions data became available to challenge DTE Energy Corp.’s projection that a construction project was not a “major modification,” and, thus, did not require a New Source Review (NSR) construction permit under USEPA’s Clean Air Act regulations.  (United States v. DTE Energy Co., 6th Cir., No. 11-2328).  In so ruling, the Sixth Circuit reversed a district court order that provided a safe harbor for owners and operators of sources that complied with pre-project recordkeeping and reporting requirements from USEPA enforcement until and unless post-project emissions data demonstrated that the projection was incorrect.

In 2010, DTE undertook construction on a project at its Monroe Power Plant in Monroe, Michigan.  Prior to initiating construction, DTE performed the required pre-project emission projections and determined that the project would not increase emissions sufficient to require a permit under the NSR regulations.  In accordance with state and federal regulations, DTE submitted its projections to the state permitting agency and began construction.  A few months later, USEPA challenged DTE’s pre-project projection in federal court, alleging that the project resulted in a “significant net emissions increase” and required a NSR construction permit.

On appeal, the Sixth Circuit confirmed that the NSR regulations cannot be read to provide USEPA with the authority to “second-guess” a source’s pre-project projections.  Such an interpretation would effectively transform a “project-and-report scheme … into a [required] prior approval scheme,” which the court noted was inconsistent with the plain language of the regulations.  Nonetheless, the Sixth Circuit found that contrary to the district court’s ruling, nothing under the regulations precluded USEPA from bringing an enforcement action at any time to “ensure that the [pre-]project projection [was] made pursuant to the requirements of the regulations.”  In other words, USEPA does not need to wait until post-construction emissions data becomes available to challenge a source’s pre-project emission projections.  It is worth noting, however, that the dissent called the majority opinion “logically flawed and … legally incorrect” on grounds that the court’s opinion was inherently contradictory.  As the dissent explained, the NSR regulations do not require pre-construction approval from USEPA, but “if the USEPA can challenge the operator’s scientific preconstruction emission projections in court … that is the exact same thing as requiring prior approval.

Notably, the Sixth Circuit did not side with USEPA carte blanche.  The court was quick to point out that its reversal did “not constitute endorsement of USEPA’s suggestion[]” that DTE’s pre-project projection should have demonstrated that the project constituted a major modification and required an NSR permit.  And the court challenged USEPA’s suggestion that a source could not intentionally limit generation to limit its post-project emissions that otherwise could retroactively require a NSR permit.

The Sixth Circuit remanded the case to the district court for further proceedings on whether the DTE project did or did not constitute a major modification and require a NSR construction permit.