Tag: FERC

FERC Redefines QF Eligibility Requirements

On September 1, 2020, the Federal Energy Regulatory Commission (“FERC” or “Commission”) issued an order breaking with decades of precedent regarding how it will determine whether a renewable resource is eligible for certification as a qualifying small power production facility (“QF”) pursuant to the Public Utility Regulatory Policies Act of 1978, as amended (“PURPA”).[1]  The result of the Commission’s order is that renewable resources will no longer have the ability to qualify for QF status by voluntarily limiting their output to comply with the 80 MW cap on small power production facilities.  Commissioner Richard Glick dissented and we anticipate that parties to the proceeding will seek rehearing and possibly appeal the order to federal court.  Bracewell will keep you updated on significant PURPA developments.

PURPA and the Commission’s implementing regulations limit a small power production QF’s capacity to a “power production capacity” of 80 MW.[2]  When evaluating whether a facility complied with this requirement, the Commission focused on the “maximum net output of the facility that can be safely and reliably achieved under the most favorable operating conditions likely to occur over a period of several years.”[3]  In practice, the Commission’s focus on the maximum net output of the facility—rather than the installed capacity of the equipment at the site—has meant that developers have been able to qualify for QF status by voluntarily installing control systems or taking other steps to limit the sustainable net output of the generation facility in any given hour to 80 MW or less, even if the installed generation capacity of the facility exceeded the 80 MW cap.

In the proceeding resulting in the September 1 Order, the Commission considered whether a combined solar and storage facility owned by Broadview Solar, LLC complied with the 80 MW cap.  The facility at issue consisted of a 160 MW solar array and a 50 MW battery storage system that would connect to 82.5 MW DC-to-AC invertors.  Because any energy produced by the solar array and battery storage system would need to be converted from DC power to AC power prior to the injection in the grid, the maximum achievable output from the facility in a given hour was 82.5 MW.  Thus, even though the installed capacity of the solar array and storage system exceeded the 80 MW cap, Broadview explained that the net output of the facility, taking into account losses and station load, could never exceed 80 MW.[4]

The Commission rejected Broadview’s arguments, however, and found that Broadview’s facility cannot meet the requirements for QF status.  The Commission acknowledged that previous orders had allowed “facilities with greater power production capacities to be certified as QFs when the net output was no more than 80 MW.”[5] The Commission found, however, that this interpretation was inconsistent with the plain language of PURPA limiting the “power production capacity” of QFs to 80 MW.  While the Commission recognized that the inverters were only capable of converting 80 MW into AC power, the Commission observed that this was merely a “conversion limit” and that the solar array alone had the capability to produce 160 MW of DC power.  According to the Commission, “[u]tilizing inverters to limit the output of an otherwise above-80 MW power production facility to 80 MW is . . . inconsistent with the type of facility that Congress specified can qualify as a small power production facility (i.e., a facility sized 80 MW or less).”[6]  For that reason, the Commission found that Broadview’s facility did not meet the requirements to qualify as a QF.

Recognizing the potential impact of its abrupt change in policy, the Commission explained that its finding would only be applied prospectively.[7]  As a result, the Commission’s order will not affect “QFs that have self-certified [through the submission of FERC Form 556] or have been granted Commission certification prior to the date of” the Commission’s order, even if the self-certification filed by the facility “included adjustments for inverters or other output-limiting devices to calculate its maximum net power production capacity as 80 MW or less.”[8]

The Commission’s order represents a marked departure from Commission precedent that  effectively eliminates the ability of renewable resources to meet the QF certification requirements by limiting the output of their facility so that it does not exceed 80 MW.[9]  Although the Commission indicated that it would only apply this determination prospectively, the Commission’s decision could have significant implications for projects that are in the final stage of development, but have not yet filed a notice of self-certification to FERC.[10]  The Commission emphasized, for example, that the owner of a facility with a legally enforceable obligation could not benefit from “grandfathered” status for the facility in the absence of a self-certification Form 556 submittal or FERC order granting certification before September 1, 2020.[11]  Also, the Commission’s order does not address whether the Commission would be willing to revisit the QF status of facilities that submit a notice of re-certification in order to report a change in the facts reported in its initial certification, including upgrading, modernizing or retrofitting existing facilities.[12]  The Commission did, however, clarify that load and line losses could continue to be factored in when measuring a facility’s 80 MW maximum net power production.

The Commission expressly declined to address how the capacity of an energy storage system should be taken into account for QF purposes – an aspect of the proceeding that many were following.[13]  In a number of recent proceedings, companies developing renewable resources combined with battery storage have taken the position that the capacity of a battery storage system should not be included when calculating the net capacity of the facility on the basis that the storage does not represent an additional source of independent power generation and merely allows the facility to shift the time of production; in those cases, however, the QF certification application was withdrawn before FERC made a substantive determination on the issue.[14]  Broadview took a similar position in this proceeding, arguing that aggregating the combined capacity of the solar array with the energy storage system would artificially inflate the aggregate capacity of the facility components.  The Commission found that it did not have to address that issue in this case because the 160 MW solar array on its own without considering the energy storage facilities was already double the 80 MW cap.[15]

 

[1] Broadview Solar, LLC, 172 FERC ¶ 61,194 (2020).

[2] 16 U.S.C. §§ 796(17), 824a-3; 18 C.F.R. § 292.204.

[3] Occidental Geothermal, Inc., 17 FERC ¶ 61,231, at 61,445 (1991).

[4] Id. at P 3.

[5] Id. at P 21.

[6] Id. at P 25.

[7] See id. at P 27.

[8] Id.

[9] See id. at P 27.

[10] Id.

[11] Id.

[12] See id.

[13] Id. at P 21 n. 57.

[14] See, e.g., NorthWestern Corp., 168 FERC ¶ 61,049 (2019).

[15] Broadview, 172 FERC ¶ 61,194, at P 21 n. 57.

© 2020 Bracewell LLP
For more articles on the environment, visit the National Law Review Environmental, Energy & Resources section.

Surprise! President Trump Nominates Democrat and Republican to FERC

On July 27, 2020, President Trump nominated two candidates to the Federal Energy Regulatory Commission (FERC), securing a Republican majority on the Commission through June 2021 while also ensuring a continued quorum.

Trump nominated Allison Clements, the Democrats’ top pick, alongside Republican Mark C. Christie. Clements currently serves as founder and president of Goodgrid, LLC, an energy policy and strategy consulting firm. She previously worked for over a decade at the Natural Resources Defense Council, and spent two years as director of the clean energy markets program at the Energy Foundation. Christie currently serves as chairman of the Virginia State Corporation Commission, having served for 16 years on the Virginia board that oversees utilities.

FERC is a five-member agency that should have no more than three members of any one party. For much of the past year it has been operating with three Republicans and one Democrat. FERC’s newest commissioner, James Danly, was confirmed in March despite requests from Democrats to pair his nomination with Clements. Clements would fill the seat left vacant by Commissioner Cheryl LaFleur in August 2019. If confirmed, Christie will take the seat of Republican Commissioner Bernard McNamee, whose tenure expired in June but who plans to stay on until his replacement is seated.

Republican Chairman Chatterjee has announced that he will remain on the Commission until the end of his term, which expires June 2021, although the next President will determine if he continues to serve as chairman. Trump’s appointment of Christie, paired with Chairman Chatterjee’s intention to fulfill his term, could secure a Republican-held Commission for the first months of a Biden presidency in the event the Democratic nominee is successful in November.

©2020 Pierce Atwood LLP. All rights reserved.

FERC Requires Public Utilities to Address Excess ADIT in Transmission Rates

On November 21, 2019, the Federal Energy Regulatory Commission (“FERC”) issued Order No. 864, a final rule on Public Utility Transmission Rate Changes to Address Accumulated Deferred Income Taxes. The new rule requires  public utilities with formula transmission rates to revise their formula rates to include a transparent methodology to address the impacts of the Tax Cuts and Jobs Act of 2017 (2017 Tax Act) and future tax law changes on customer rates by accounting for “excess” or “deficient” Accumulated Deferred Income Taxes (ADIT).  FERC also required transmission providers with stated rates to account for the ADIT impacts of the 2017 Tax Act in their next rate case.

Background

The 2017 Tax Act reduced the corporate income tax rate from 35 percent to 21 percent. The tax rate change will result in a reduction in a public utility’s future tax liabilities so that a portion of its ADIT balances (rate receipts collected in anticipation of future tax liability) will no longer be due to the IRS, and is thus considered excess ADIT.  This transmission-related excess ADIT must be returned to customers through a public utility’s transmission rates.

FERC issued a Notice of Proposed Rulemaking (NOPR) on ADIT issues on November 15, 2018.   In the NOPR, FERC proposed to require public utilities with formula rates to adjust their formula rates to include (i) a mechanism to reflect any excess or deficient ADIT resulting from the 2017 Tax Act, or any future tax rate change, in rate base; (ii) a mechanism to adjust income tax allowance to reflect amortization of excess or deficient ADIT; and (iii) a new worksheet in its transmission formula rate to track on an annual basis information related to excess/deficient ADIT.  FERC also proposed to require public utilities with stated rates to make a compliance filing to address excess ADIT resulting from the 2017 Tax Act.

Order No. 864 – Final Rule on ADIT Adjustments to Account for Tax Rate Changes

ADIT Adjustments in Formula Rates

In the final rule, FERC adopted each of its proposals to address ADIT adjustments for transmission providers with formula rates.

  • Rate Base Adjustment Mechanism.  FERC required public utilities with formula rates to include a mechanism by which excess ADIT is deducted from rate base, and deficient ADIT is added to rate base.  This mechanism must be broad enough to cover any future tax changes that might give rise to excess/deficient ADIT.  FERC did not require use of a specific mechanism, and instead will consider proposed changes on a case-by-case basis.  FERC noted that, consistent with its previous accounting guidance, public utilities are required to record a regulatory asset (Account 182.3) associated with deficient ADIT or a regulatory liability (Account 254) associated with excess ADIT.
  • Income Tax Allowance Adjustment Mechanism.  FERC required public utilities with formula rates to incorporate a mechanism to adjust income tax allowances to reflect amortized excess or deficient ADIT.  This mechanism must cover amortization of excess or deficient ADIT resulting from any future tax changes as well as the 2017 Tax Act.  FERC will consider proposed changes on a case-by-case basis.  FERC clarified that, consistent with guidance provided in the 2017 Tax Act, excess ADIT that is “protected” (i.e., plant-related) should be amortized no more rapidly than over the life of the underlying asset using the Average Rate Assumption Method (ARAM), or an alternative method if insufficient data is available to use ARAM.  FERC will evaluate proposed amortization methods for the return of excess ADIT that is “unprotected” (i.e., not plant-related) on a case-by-case basis. FERC clarified that regardless of the effective date of tariff changes submitted by a public utility, the full amount of excess ADIT resulting from the 2017 Tax Act must be returned to its customers.
  • New ADIT Worksheet.  FERC required public utilities to add a new permanent worksheet that will annually track information related to excess or deficient ADIT in their formula rates.  FERC required that the new ADIT worksheet address: (1) how any ADIT accounts were re-measured and the excess or deficient ADIT contained therein; (2) the accounting for any excess or deficient amounts in Accounts 182.3 (Other Regulatory Assets) and 254 (Other Regulatory Liabilities); (3) whether the excess or deficient ADIT is protected or unprotected; (4) the accounts to which the excess or deficient ADIT are amortized; and (5) the amortization period of the excess or deficient ADIT being returned or recovered through the rates. FERC expects public utilities to identify each specific source of excess/deficient ADIT, classify such excess/deficient ADIT as protected or unprotected, and list the proposed amortization period associated with each classification or source.  FERC also expects public utilities to provide supporting documentation in their compliance filings to justify the proposed amortization periods.  FERC did not require that use of a pro forma worksheet to convey such information, but did require that on compliance, public utilities populate the worksheets with excess/deficient ADIT resulting from the 2017 Tax Act to facilitate review by interested parties.

FERC clarified that given the formula rate changes required in the final rule, public utilities with formula rates would not be required to make subsequent FPA Section 205 filings to address rate impacts of excess/deficient ADIT associated with future tax rate changes.  FERC also stated that a public utility may show that existing ADIT-related mechanisms meet the requirements of this final rule.

ADIT in Stated Rates

FERC declined to adopt its proposal to require public utilities with stated rates to determine excess ADIT resulting from the 2017 Tax Act and return such amounts to customers in a single-issue filing responding to the final rule.  Instead, FERC stated it would maintain the status quo under its precedent, which requires public utilities with stated rates to address excess/deficient ADIT, including that caused by the 2017 Tax Act, in their next rate case.  FERC clarified it will address the timing of proposed excess ADIT amortization on a case-by-case basis, and that public utilities may propose to delay such amortization until its next rate case.

Compliance Filings 

FERC required that public utilities with formula rates submit a compliance filing by the later of 30 days after the effective date of the final rule (the effective date will be 60 days after publication of the rule in the Federal Register) or the public utility’s next annual informational filing. FERC stated that proposed tariff changes to address the final rule’s requirements should be made effective on the effective date of the final rule.

Several public utilities have already revised their formula rates to address excess ADIT resulting from the 2017 Tax Act.  These filings sought to implement the requirements proposed by FERC in the NOPR.  Under the final rule, these utilities will need to make a compliance filing, but can argue that the already-made changes satisfy the requirements of the final rule.  These past filings may serve as helpful models for compliance filings by other utilities, but must be considered in light of the requirements of the final rule.

Public utilities with stated rates are not required to make a compliance filing; excess/deficient ADIT issues will be considered in the next rate proceeding.

© 2019 Van Ness Feldman LLP

ARTICLE BY Van F. Smith and  Ani M. Esenyan of  Van Ness Feldman LLP.
Read more about utility tax regulation on the Environmental, Energy & Resource law page of the National Law Review.

FERC Staff’s White Paper on Manipulation Provides Insights on Commission’s Developing Manipulation Law

FERC Manipulation LawOn November 17, 2016, the Office of Enforcement (“FERC Staff”) of the Federal Energy Regulatory Commission (the “Commission” or “FERC”) issued a White Paper on Anti-Market Manipulation Enforcement Efforts Ten Years After EPAct 2005 (“Manipulation White Paper”) to “provide insight” on its ten years of experience investigating potentially manipulative conduct under the Anti-Manipulation Rule.1  During this period, FERC Staff has investigated over 100 matters, settled 24 proceedings resulting from those investigations, and pursued two matters in administrative proceedings.  In addition, FERC currently is litigating six penalty assessment orders in federal district courts.2  According to FERC Staff, through these investigations and proceedings, the Commission and the courts have “developed a body of law that, while still in its early stages and continuing to evolve, identifies and provides notice on specific types of conduct that can constitute market manipulation in the energy markets and factors that are indicative of such conduct.”3

In its Manipulation White Paper, FERC Staff largely restates its litigation positions – many of which currently are being challenged – and seeks to provide notice of: (1) factors that typically indicate manipulative conduct; (2) specific types of conduct that often constitute manipulation; (3) mitigating and aggravating factors affecting penalty amounts for manipulation violations; and (4) the types of investigations that it has closed without further action.

FERC Staff first provides the following non-exhaustive list of key elements emerging from FERC’s developing manipulation law:

  • Fraud is a question of fact;

  • Fraud includes open-market transactions (g., transactions executed with manipulative intent on exchanges or public trading platforms);

  • Fraud is not limited to violations of a tariff or other express rule;

  • A manipulation violation does not require a showing that the manipulative conduct resulted in artificial prices;

  • The Anti-Manipulation Rule includes attempted fraud;

  • Manipulative intent, even where it is combined with a legitimate purpose, establishes the scienter element of the Anti-Manipulation Rule;

  • Pursuant to its “in connection with” jurisdiction, the Commission has jurisdiction over conduct that affects jurisdictional transactions, including the “rates, terms, and conditions of service in a market”; and

  • Individuals constitute “entities” and, as such, are subject to the Anti-Manipulation Rule.4

Indicia of Fraud

Identifying what it characterizes as typical indicia of fraud, FERC Staff explains that the distinction between fraudulent and lawful market behavior can hinge on the underlying purpose of the behavior.5  For example, in three orders relating to Up-To Congestion (“UTC”) trades, the Commission compared the purpose of UTC trading against the purpose behind respondents’ UTC trades and determined that their trades “were neither consistent with how the UTC product historically traded nor aligned with the arbitrage purpose of those trades.”6  The Manipulation White Paper does not identify where market participants should look to understand what Staff will view as “the purpose” of particular products like UTCs.  Staff emphasizes, however, that the purpose driving a market participant’s behavior in the market is a “critical factor” in a manipulation determination.  FERC Staff recommends, therefore, that companies require employees to document the purpose behind conduct likely to raise red flags.7  In the right circumstances, market participants should also consider documenting their understanding of the purpose of the relevant products and why their trading aligns with those purposes.

Continue reading at the National Law Review

ARTICLE BY George D. Billinson, Mark R. Haskell, Thomas Reid Millar, Paul J. Pantano Jr. & Mary Treanor of Cadwalader, Wickersham & Taft LLP
© Copyright 2016 Cadwalader, Wickersham & Taft LLP

FERC Approves Fourth Settlement for 2011 Southwest Blackout Against Western Area Power Administration

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On November 24, 2014, FERC approved a settlement with Western Area Power Administration – Desert Southwest Region  (Western-DSW) related to its involvement in the blackout in the southwestern U.S. on September  8, 2011.  This blackout left more than 5 million people in Southern California, Arizona, and Baja California, Mexico without power for up to 12 hours.  According to FERC’s press release on the Western-DSW settlement, this is the fourth settlement arising out of this blackout.

We have reported on two prior settlements, one involving Arizona Public Service Company on July  7, 2014 and one involving Imperial Irrigation District. A third settlement involved Southern California Edison Company and was approved on October 21, 2014. Two other investigations involving the California Independent System Operator and Western Electric Coordinating Council  remain outstanding.

The settlement with Western-DSW is unique in that it involves no monetary penalty.  This is in keeping with the DC Circuit’s recent decision in Southwestern Power Administration et al. v. FERC, 763 F3d 27 (DC Cir 2014) (SWPA). As we previously reported, the Court in SWPA held that FERC could not impose monetary penalties on a federal power marketing administration for Reliability Standards violations. This is in marked contrast to the $650,000 monetary civil penalty assessed against Southern California Edison Company and the $2,000,000 monetary civil penalty assessed against Arizona Public Service Company.  Similarly, the settlement with Imperial Irrigation District involved a monetary civil penalty of $3,000,000. FERC reached this settlement with Imperial Irrigation District three weeks before the SWPA decision was issued, and it is not clear whether that decision, which was based on federal sovereign immunity precedent, would extend to state public power entities like Imperial Irrigation District. As with the other three settlements, the Western-DSW settlement provided for investment in significant reliability improvements, but unlike the other three settlements, the Western-DSW settlement does not identify a monetary value for Western-DSW’s reliability improvements.

The Western-DSW settlement involved four alleged violations involving three Reliability Standards. These alleged violations arose out of a fault on a major transmission line owned and operated by Arizona Public Service Company and Western-DSW’s inability to handle the resulting increased flows on parallel transmission paths in which Western-DSW owns and operates transmission facilities. These increased flows resulted in voltage deviations and overloads on Western-DSW’s system which in turn required load shedding. After its investigation, FERC and NERC staffs found that Western-DSW had violated the following requirements:

  • TOP-004-2 R1, because Western-DSW did not operate its system within established system operating limits

  • TOP-004-2 R2, because Western-DSW did not operate its system to prevent severe low voltage conditions and loss of load that resulted from the loss of the Arizona Public Service Company line

  • TOP-008-1 R2, because Western-DSW did not operate its system to prevent system operating limit violations by identifying and studying the contingency related to the loss of the Arizona Public Service Company line

  • VAR-001-1 R9 because Western-DSW did not maintain sufficient reactive resources to support its voltage in the event of a contingency related to the loss of the Arizona Public Service Company line

While stipulating to the facts surrounding the September 8, 2011 event, Western-DSW noted in the settlement that it neither admits nor denies that it violated any Reliability Standards.

Although as noted above the settlement does not identify any monetary penalties, the “Remedies and Sanctions” section of the settlement describes at length several reliability improvements instituted by Western-DSW. To improve its operations within established system operating limits, Western-DSW committed to perform seasonal, next-day and real time studies to verify its system operating limits and interconnection reliability operating limits, to coordinate with its neighboring transmission systems and with its reliability coordinator on any areas of concern related to those limits, and to establish alarms, procedures and trainings related to real-time study of these limits. Western-DSW also committed to similar efforts associated with monitoring real-time voltage and reactive power support, and it joined with other facility owners to install a total of 90 MVar of reactive support. As with the other settlements arising out of the September 8, 2011 Southwest Blackout, the Western-DSW settlement included reliability improvements that do not appear directly related to the underlying alleged violations; these improvements addressed areas such as: situational awareness, long term planning, enhancing operational studies to predict system performance within appropriate phase angle limits.

Although the settlement makes clear that many of the reliability improvements committed to by Western-DSW are complete, the settlement provides that Western–DSW will submit status two semi-annual reports to FERC and NERC staffs regarding its mitigation activities and its ongoing compliance with the Reliability Standards.

ARTICLE BY

Joel G. deJesus
OF
Schiff Hardin LLP

Shippers Rolling the Dice to Gain Oil Pipeline Capacity

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With the growing capacity constraints on oil pipelines, the Federal Energy Regulatory Commission (“Commission”) has recently extended the bounds of what it considers acceptable methods of apportioning limited capacity. In Seaway Crude Pipeline Company LLC, 143 FERC ¶ 61,036 (2013), the Commission approved a new lottery system that will select, at random, new shippers who will be permitted to tender the minimum monthly volume requirement. The catch, however, is that there are approximately 275 new shippers on the system, meaning a given shipper has roughly only a 5 percent chance of winning the lottery each month. And to achieve regular shipper status and thus gain access to the 90 percent of system capacity reserved for regular shippers, it must win that lottery twelve consecutive times.

After reversing flow on its Longhaul System and commencing north-to-south transportation service, Seaway saw the number of new shippers dramatic multiply from 5 (when to service commenced) to 275 by April, 2013. Seaway alleged that some of the proliferation was due to shippers attempting to game the system and broker capacity in the secondary market. Like other oil pipelines, Seaway dedicates 90 percent of the system capacity to regular shippers and 10 percent to new shippers, and to achieve regular shipper status, Seaway’s customers must tender the minimum volume (60,000 barrels per month) for 12 consecutive months. Before the lottery, Seaway allocated the 10 percent of capacity to new shippers on a pro rata basis, but with so many new shippers, none was able to meet the requirements to achieve regular shipper status because of the relatively high minimum tender requirement. As a result the number of new shippers multiplied with those shippers informally aggregating batches to meet Seaway’s minimum monthly tender requirement.

Seaway concluded that such a system was unworkable and proposed a lottery system to replace its existing pro rata system. The lottery system will use a software-generated random process to determine which new shippers will be allowed to tender the 60,000 barrel minimum each month, meaning about 13 new shippers will get capacity for a given month.

Despite several protests, the Commission approved Seaway’s lottery system for two main reasons. First, the Commission reasoned that the lottery system will deter manipulation during the nomination process and thus make capacity more readily available to legitimate new shippers; and second, the lottery would not be unduly discriminatory because the system would apply to all new shippers.

Although this is not the first time that the Commission has approved the use of a lottery system to award new shipper capacity when a pipeline faces apportionment problems, Seaway’s proposed lottery system, coupled with the requirement that new shippers must tender the minimum monthly volumes for 12 consecutive months, means that it will be highly improbable for new shippers to ever achieve regular shipper status, unless the number of new shippers dramatically decreases. Thus, the decision treads slightly new ground on what the Commission is willing to consider as a “reasonable” remedy to address the multiplication of new shippers and the vast over-nomination issues some crude pipelines are facing in the current environment.

Finally, the Seaway decision underscores the importance of open seasons as being the principle method of obtaining reliable transportation service on oil pipelines. For example, gaining access to the Longhaul System as a new shipper is difficult enough because a prospective new shipper will now have to win the lottery simply to tender the minimum amount requirement in one month. However, to gain access to the remaining 90 percent of system capacity, that prospective customer must win the new shipper lottery 12 consecutive times. By contrast, Seaway held two opens seasons for capacity on its Longhaul System and committed shippers were able to access the 90 percent of the system capacity reserved for regular shippers. Thus, shippers seeking access to reliable capacity might consider a commitment during an open season rather than gambling on a future—and perhaps unforeseen—lottery.

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Big Brother Gets Better Glasses: FERC Enhances Its Market Surveillance Tools

In a concerted effort to enhance its ability to monitor energy markets for possible anti-competitive or manipulative conduct, FERC has undertaken a number of separate initiatives to strengthen its market surveillance capabilities over electric power and natural gas markets.  Among the areas of focus, FERC has been especially keen on obtaining data and market information on a real-time, or near real-time, basis, which is in contrast to FERC’s traditional collection of data through quarterly or annual reports submitted well after-the-fact.  FERC has also been intent on gathering data outside of organized wholesale electric markets.

These initiatives include:

  • On February 16, 2012, FERC Chairman Jon Wellinghoff announced the creation of a new Division of Analytics and Surveillance to the Office of Enforcement.  Described by the Chairman as staffed with “geeks and wonks”, the Division is intended to provide continuous, real-time market surveillance and data analysis of physical gas and electric power markets and of related financial products.  The Division also is intended to develop and implement surveillance tools to detect potential market manipulation, anticompetitive behavior, and other anomalous activity.
  • Beginning in August 2012, FERC enacted a rule to require Regional Transmission Organizations (RTO) and Independent System Operators (ISO) to electronically deliver to FERC non-public data on a rolling basis, seven days after creation.  Specifically, FERC requires RTOs and ISOs to provide: market participant names and pricing points; virtual offers and bids; capacity market offers, awards, and prices; marginal cost estimates; financial transmission rights, or FTR, data; pricing data for interchange transactions; supply offers and demand bids; energy and ancillary services awards; resource output; day-ahead generation and load shift factors associated with constraints; internal bilateral contracts; and uplift charges and credits.  FERC allowed a phased implementation, with only certain data required August 2012, leading up to full implementation by February 2013.  This data collection is intended to supplement ongoing market monitoring efforts by the RTOs’ and ISOs’ market monitors.
  • FERC has also taken efforts to enhance its more traditional forms of reporting, including extending FERC’s Electric Quarterly Report (EQR) requirements to non-public utility entities that make sales above a 4,000,000 MWh threshold under Section 220 of the Federal Power Act (FPA).  These non-public utility entities—which generally consist of governmentally-owned entities, such as federal power marketing administrations, municipal utilities, public utility districts, and coops—have traditionally been exempt from FERC’s EQR filing requirements.  In the Energy Policy Act of 2005, Congress granted FERC increased authority over these entities in order to improve market transparency, as non-public utility entities represent large portions of the market, particularly in areas of the country outside of organized markets.  In the same order, FERC also increased the amount of data required of all EQR filers to include individual trade dates, whether a transaction was reported to an index publisher, the broker or exchange used for a transaction, and e-Tag IDs associated with individual transactions.  In a separate order issued in February 2012, FERC also indicated it will consider requiring EQR filers to report electric “buy-sell” transactions, termed by FERC as “simultaneous exchanges”.
  • FERC is also in the process of considering a rule that proposes to require theNorth American Electric Reliability Corporation (NERC) to provide FERC staff with access to the complete set of non-public e-Tag data.  (Notably, NERCresponded to the Commission’s proposal by noting that other entities, and not NERC, maintained the desired e-Tag information.)  When viewed in conjunction with the new requirement to report e-Tag IDs in the EQRs, it is clear that FERC intends to associate the broader set of e-Tag data with parties’ transaction reports in an effort to understand how power is transacted and scheduled.
  • Finally, on October 15, 2012, FERC Staff issued a set of proposed metrics that would compare the performance of market performance in areas outside of organized wholesale electric markets with performance in organized markets.  As part of this effort, FERC Staff issued a new report, FERC-922, that would collect information from utilities outside of organized markets.  Requested information includes price data and information relating to reliability, transmission planning, requests for service, and system capacity.  Staff stated it will use this information to help develop a common set of metrics for both RTO/ISO markets and non-RTO/ISO markets, and for evaluating market performance thereafter.  FERC Staff noted that it could not require many non-public utility entities to provide such information but requested such entities to comply as part of “a voluntary and collaborative process”.

Taken as a whole, these efforts show an agency intent on gaining a deeper and more granular perspective on energy markets and a better understanding of how those markets function day-to-day.

© 2012 Bracewell & Giuliani LLP

FERC Rules on Several Core Reliability Compliance Issues: New Orders Address Cybersecurity, Registration, and Contingency Planning

The National Law Review published an article recently by Stephen M. Spina, J. Daniel Skees, and John D. McGrane of Morgan, Lewis & Bockius LLP regarding New FERC Rules on Reliability Compliance:

At FERC’s open meeting on April 19, 2012, FERC approved several orders addressing core aspects of Reliability Standards compliance, including cybersecurity Reliability Standards, compliance registration, and contingency planning issues. The newly approved cybsersecurity Reliability Standards significantly increase the scope of facilities subject to those requirements, the compliance registration decisions clarify the jurisdictional boundary between distribution and transmission facilities, and the planning orders represent a rejection of NERC’s approach to planning for firm load loss following a single contingency.

Cybersecurity: FERC Approves Version 4 CIP Reliability Standards

In Order No. 761, FERC approved Version 4 of the Critical Infrastructure Protection (CIP) Reliability Standards. Under Version 4, the risk-based assessment methodology previously used to identify the Critical Assets that must be protected under the CIP Reliability Standards is replaced with a list of “bright-line” criteria for identifying Critical Assets, contained in Attachment 1 to CIP-002-4. These criteria, FERC concluded, “will offer an increase in the overall protection for bulk electric system components that clearly require protection, including control centers.” In the order, FERC established a deadline of March 31, 2013, for NERC to submit the Version 5 CIP Reliability Standards, which will address the remaining directives from Order No. 706, in which FERC approved the original CIP Reliability Standards. The project site for the Version 5 CIP Reliability Standards is located online.

Compliance Registration: FERC Addresses Distribution/Transmission Distinction

In City of Holland, 139 FERC ¶ 61, 055 (2012), FERC rejected the City of Holland, Michigan, Board of Public Works’ appeal of NERC’s decision to register the City of Holland as a Transmission Owner and Transmission Operator. In reaching this decision, FERC rejected the City of Holland’s assertion that its facilities are distribution facilities, and therefore not part of the definition of “Bulk Electric System” and not subject to registration. FERC explained that the City of Holland’s facilities perform a transmission function, transporting power from the City of Holland’s generation facilities or importing power from other sources over high-voltage lines before stepping the voltage down for distribution to end users. In reaching this decision, FERC also thought it relevant that the facilities at issue do not serve load from a single transmission source, can experience bi-directional flows, and are above the voltage level generally considered distribution voltage.

Commissioner Cheryl A. LaFleur dissented on the grounds that this order depends on the fundamental, yet unsettled question of what facilities are considered “local distribution” under Section 215 of the Federal Power Act (FPA) and therefore outside of FERC’s jurisdiction. As explained in Commissioner LaFleur’s dissent, FERC has in the past identified the criteria for identifying local distribution facilities under Section 201(b) of the FPA, which uses language identical to Section 215, but FERC chose not to apply the Section 201(b) criteria in addressing the City of Holland’s appeal. Commissioner LaFleur asserted that if FERC believes that Congress intended to create different classes of local distribution facilities, FERC has the “burden of demonstrating that this is a reasonable interpretation of the statute.”

In U.S. Department of Energy, Portsmouth/Paducah Project Office, 139 FERC ¶ 61,054 (2012), FERC granted the Portsmouth/Paducah Project Office’s appeal of its registration as a Load-Serving Entity (LSE). FERC had previously remanded this registration, and in ruling on NERC’s subsequent decision upholding the registration, concluded that NERC had failed to support registration as an LSE because NERC had not shown that the lessees and contractors working at the Portsmouth/Paducah Project Office are separate end-use customers to whom the Portsmouth/Paducah Project Office provides electricity. FERC explained that the Ohio Valley Electric Corporation, which sells to the Portsmouth/Paducah Project Office under a state retail tariff, is the appropriate LSE.

Contingency Planning: FERC Demands Stringent Criteria for Planned Load Loss Following a Single Contingency

In Order No. 762, FERC rejected NERC’s proposed revisions to “Note b” in TPL-002-0b, which explains when a Transmission Planner or Planning Authority can plan for the interruption of firm load to meet system reliability requirements following a single contingency. Under NERC’s proposal, these entities could plan for load shedding following a single contingency so long as they documented such planning and considered alternative solutions in an open and transparent stakeholder process. FERC concluded that the proposal failed to satisfy FERC’s earlier directives on this issue and did not present an “equally effective and efficient alternative.” According to FERC, the proposed Note b process “is vague, potentially unenforceable and may lack safeguards to produce consistent results.” The parameters for the proposed stakeholder process, FERC concluded, do not provide a meaningful limitation on the ability to curtail firm load following a single contingency. Furthermore, the conditions under which such interruptions are appropriate remain undefined, threatening the basic system performance objectives of the NERC Transmission Planning Reliability Standards, risking system reliability.

In Transmission Planning Reliability Standards, Notice of Proposed Rulemaking, 139 FERC ¶ 61,059 (2012), FERC proposed to remand NERC’s proposal to combine the four current Transmission Planning Reliability Standards into a single new standard, TPL-001-2. According to FERC, footnote 12 to Table 1 in this proposed standard, which governs planning for the interruption of firm load following a single contingency, presents the same concerns as the Note b issues that led FERC to reject a similar proposal in Order No. 762 (described above). This footnote, which only requires a documented plan developed through an open and transparent stakeholder process that considers alternatives, does not define the parameters governing the decision to plan for the loss of firm load following a single contingency. While FERC noted several improvements in the standard, because of concerns with footnote 12, FERC proposed to find that TPL-001-2 does not meet the statutory criteria for approval. Comments will be due 60 days after the Notice of Proposed Rulemaking is published in the Federal Register. In the Notice of Proposed Rulemaking, FERC requested comments on several transmission planning issues in addition to the core concern regarding planned load curtailments.

Copyright © 2012 by Morgan, Lewis & Bockius LLP

FERC Decides to Retain Existing Merger Review Policies

The National Law Review recently published an article by Daniel E. Hemli and Jacqueline R. Java of Bracewell & Giuliani LLP regarding a recent FERC Decision on Merger Reviews:

On February 16, 2012, FERC issued an order (February 16 Order) reaffirming its existing merger review policies under Section 203 of the Federal Power Act (FPA) and its current framework for analyzing requests for market-based rate authority under section 205 of the FPA. In March of last year, FERC had sought comment in a Notice of Inquiry (NOI) on whether it should amend its existing policies in these two areas in light of new Horizontal Merger Guidelines (2010 HMG) issued jointly by the Federal Trade Commission (FTC) and Department of Justice (DOJ) on August 19, 2010. The NOI explained that the 2010 HMG deemphasize market definition as a starting point for merger analysis and depart from the sequential analysis found in the prior 1992 version of the Horizontal Merger Guidelines (1992 HMG), and instead support the use of a fact-specific inquiry and greater analytical flexibility.

Section 203 of the FPA requires parties to public utility mergers and acquisitions involving jurisdictional facilities to seek FERC authorization before closing. Section 203(a) provides that FERC should approve such transactions if they are consistent with the public interest. As part of that determination, FERC must consider the proposed transaction’s effect on competition in the relevant market(s). FERC currently uses a five-step framework that was adopted from the 1992 HMG, as well as a Competitive Analysis Screen (CAS) which focuses on the first step of the analysis: whether the proposed transaction would significantly increase concentration and result in a concentrated market. One component of the CAS includes an analysis of market concentration using the Herfindahl-Hirschman Index (HHI). Under Section 205 of the FPA, parties that can demonstrate they do not have, or have adequately mitigated, their horizontal and vertical market power are granted authority to make sales of electric energy, capacity and ancillary services at market-based rates. FERC’s analysis under Section 205 includes the use of two indicative screens that rely on market share as well as market concentration as measured by HHI.

In its February 16 Order, FERC declined to follow the 2010 HMG’s approach as the framework for the Commission’s analysis of horizontal market power. The Commission explained that it would retain its five-step framework, including the CAS as part of its first step, as the CAS provides a useful conservative check to allow parties to quickly identify mergers unlikely to present competitive problems at a relatively low cost. The Commission stated that its current approach, which provides analytical and procedural certainty, is also flexible enough to incorporate theories outlined in the 2010 HMG, and that it has previously, and will continue to, look beyond the HHI screens in its review process when warranted.

The Commission also declined to adopt the revised, higher HHI thresholds presented in the 2010 HMG for use in its CAS. Noting its extensive experience with electrical markets and their distinct characteristics, as well as its intent to use the CAS to identify proposed transactions that clearly would have no adverse effect on competition, FERC stated that its current HHI thresholds are appropriate. The Commission also declined to initiate a more formal coordination process with the FTC and DOJ, as requested by one commenter. FERC stated that it will continue to coordinate with the federal antitrust agencies as appropriate, on a case-by-case basis.

Regarding its electric market-based rate program, FERC decided not to modify the current market power analysis and declined to alter the HHI threshold used in that screening process, noting that its current HHI threshold is already consistent with the 2010 HMG approach. With regard to the existing market share screen, FERC explained that, due to the physical and economic characteristics of electricity markets, including low elasticity of demand, market power is more likely to be present at lower market shares. Thus, FERC concluded that the current indicative screens used in its market-based rate analysis provide an appropriate balance between a “conservative but realistic screen” and imposing undue burdens on applicants. FERC also noted that its current analysis provides adequate flexibility to consider additional evidence when raised by an applicant or an intervenor.

© 2012 Bracewell & Giuliani LLP