regional transmission organizations

Introduction

FERC’s September 17, 2015 notice of proposed rulemaking (NOPR) in Docket No. RM15-23-000 would impose significant information-gathering requirements on participants in markets operated by Regional Transmission Organizations (RTOs) and Independent System Operators (ISOs). The rule would require each market participant to obtain a Legal Entity Identifier (LEI) and to report its LEI and extensive additional information about itself and its Connected Entities to its RTO/ISO who would submit it to FERC. FERC has designed the information requirement, which applies on a regular ongoing basis and must be updated as facts and circumstances change, to reveal direct as well as indirect, third party links between market participants that could afford the incentive and ability to engage in joint action to manipulate and defraud the markets.
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On January 2, 2014, the Federal Energy Regulatory Commission (FERC) and the Commodity Futures Trading Commission (CFTC) executed two Memoranda of Understanding (MOU) addressing issues concerning overlapping jurisdiction and information sharing procedures regarding their respective anti-manipulation enforcement powers. The agencies signed the memoranda to satisfy a mandate in the Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank) that required the negotiation of an MOU within 180 days of the July 24, 2010 enactment of Dodd-Frank. The CFTC and FERC had been operating under a 2005 MOU that provided for coordination of investigative and enforcement activities but did not specifically reference any overlapping anti-manipulation authority. FERC Acting Chairman Cheryl LaFleur and former CFTC Chairman Gary Gensler pledged that the agencies would work together to better protect the nation’s energy markets based on each agency’s market oversight and enforcement responsibilities.
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The D.C. Circuit has granted a petition for review filed by the Southwest Power Pool (SPP) regarding two orders of the Federal Energy Regulatory Commission (FERC) addressing a dispute between SPP and the Midwest Independent System Operator (MISO) regarding the terms upon which SPP and MISO may use “shared contract path” transmission capacity.  The D.C. Circuit found that FERC “failed to give a reasoned explanation for its decision” supporting MISO’s view in the dispute,   Southwest Power Pool, Inc. v. FERC, D.C. Cir. Case No. 12-1158, slip op. (Dec. 3, 2013).
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On August 6, 2013, FERC Administrative Law Judge Michael J. Cianci issued an initial decision on the complaint filed against the New England Transmission Owners (NETOs) seeking to reduce their currently effective 11.14% base return on equity (ROE) (FERC Docket Nos. EL11-66-000, et al.). Applying FERC’s traditional discounted cash flow (DCF) analysis to financial data largely for the period May 2012 – October 2012, Judge Cianci would require the NETOs to use a 10.6% base ROE to make refunds for transmission service provided between October 1, 2011 and December 31, 2012. Applying the same DCF analysis to financial data largely for the period October 2012 – March 2013, Judge Cianci would allow the NETOs a 9.7% ROE that would apply prospectively once FERC ultimately issues its order in the case (assuming FERC sustains Judge Cianci’s rulings; see PP* 544, 559-560). These rulings undoubtedly are disappointing both to the NETOs, who opposed any reduction in the 11.14% base ROE, and the complainants, who advocated substantially lower ROEs (8.3% to 8.9%) than Judge Cianci would allow.
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The Federal Energy Regulatory Commission (FERC) announced this week that it will hold a technical conference on centralized capacity markets in Regional Transmission Organizations (RTOs) and Independent System Operators (ISOs). The purpose of the technical conference is to consider how current centralized capacity market rules and structures are supporting the procurement and retention of resources necessary to meet future reliability and operational needs. In its Notice, FERC pointed out that since their establishment, centralized capacity markets have continued to evolve. Meanwhile, the mix of resources is also evolving in response to changing market conditions, including low natural gas prices, state and federal policies encouraging the entry of renewable resources and other specific technologies, and the retirement of aging generation resources. This changing resource mix, according to FERC, may result in future reliability and operational needs that are different than those of the past. In addition, some states have pursued individual resource adequacy policies to ensure the development of new resources in particular areas or with particular characteristics, and questions have been raised as to how those individual policies can be accommodated in centralized capacity markets.
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Introduction

On October 5, 2012, the Midwest Independent Transmission System Operator, Inc. (“MISO”) and the City of Escanaba, Michigan (“Escanaba”) filed with the Federal Energy Regulatory Commission (“FERC” or “Commission”) MISO’s first-ever System Support Resources (“SSR”) Agreement. The SSR Agreement is MISO’s mechanism to deal with the reliability concerns surrounding the decision to retire a generating unit. FERC’s decision is pending and it will have important implications for other retirement decisions and load-serving entities (“LSEs”) within MISO’s region (as well as for the retirement decisions and LSEs in the regions of other Independent System Operators (“ISOs”) and Regional Transmission Organizations (“RTOs”)).
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On October 18, 2012, the Federal Energy Regulatory Commission (“FERC” or “Commission”) issued Order No. 1000-B. Transmission Planning and Cost Allocation by Transmission Owning and Operating Public Utilities, Order No. 1000-B, 141 FERC ¶ 61,044 (2012). The Commission affirmed the determinations made in Order No. 1000-A, but granted clarifications on certain issues.
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On August 21, 2012, the Commodity Futures Trading Commission (“CFTC”) and Securities Exchange Commission (“SEC”) published a proposal [PDF] to exempt certain independent system operator (“ISO”) and regional transmission operator (“RTO”) related transactions from the Commodity Exchange Act’s (“CEA”) obligations.  The California ISO, ERCOT, ISO New England, Midwest ISO, NYISO, and PJM had filed petitions seeking exemptions for transactions entered into pursuant to their organized markets regulated by FERC or the Public Utilities Commission of Texas.
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On August 20, 2012, FERC continued its series of regional technical conferences to explore ways to improve coordination between the electricity and natural gas markets. The first conference was held on August 6 in St. Louis, Missouri, and covered issues specific to the Midwest Region. The August 20 conference, held in Boston, addressed issues specific to the New England Independent System Operator Inc. (“ISO”) area.
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On June 18, 2012, multiple parties filed requests for rehearing of FERC’s Order No. 1000-A [PDF], which is the order on rehearing of FERC’s landmark Order No. 1000 [PDF] order on transmission planning and cost allocation. Transmission dependent utilities (“TDUs”) argued that in Order No. 1000-A the Commission erred by determining that unless public utility transmission providers elect to make provision in their Order No. 1000 compliance filings for Federal Power Act Section 205 filing of specific applications of the region’s cost allocation methodology, the only means to challenge the project-specific application of an Order No. 1000 cost allocation methodology would be by filing a Section 206 complaint. Instead, TDUs argue that the Commission should require the Section 205 filing of project-specific applications of the regional cost allocation methodology, or leave to the compliance filing process the determination (in response to requests of transmission providers or other stakeholders) as to whether such filing is required. TDUs further argue that Order 1000-A erred by altering or limiting Order No. 681’s [PDF] preference for load serving entities’ (“LSE”) long-term rights. According to TDUs, Order No. 681 extended the preference to be afforded LSEs to long-term rights from existing capacity to new transmission capacity, with one limited exception – where a transmission upgrade is funded by “direct cost assignment,” i.e., participant-funded. They argue that the exception is inapplicable to the new transmission facilities at issue in the transmission planning and cost allocation proceeding, as Order No. 1000 specifically ruled that participant funding will not comply with the regional or interregional cost allocation principles adopted by Order No. 1000.
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