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December 3, 2024

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FERC Stands Firm on Reporting Requirements – UPDATE

By Rich Heidorn Jr.
PJM Insider

WASHINGTON – Large electric cooperatives and public power agencies must begin reporting their “surplus” power trades to the Federal Energy Regulatory Commission, the agency said today, standing firm on an order it issued in September.

The new reporting requirements apply to more than 50 cooperatives and public power agencies otherwise exempt from FERC authority that have “more than a de minimis market presence” – defined as more than 4 million MWh in annual wholesale sales.

The newly-affected entities must begin recording their transactions in Electric Quarterly Reports (EQRs) for the third quarter of 2013.

In denying a request for reconsideration, the commission also reiterated its requirement that all EQR filers begin including electronic tag (e-Tag) data in reporting their transactions.

Reason for change: 

Order 768, issued Sept. 21, is a response to Congress’ command in the 2005 Energy Policy Act to improve price transparency in wholesale electric markets.

The commission said the reporting requirements were necessary because non-public utilities are responsible for about 29% of wholesale sales in the 48 contiguous states (excluding ERCOT).  They represent 60% or more of sales within the Western Electric Coordinating Council (WECC), SERC Reliability Corp. and Florida Reliability Coordinating Council (FRCC) FERC said.

The American Public Power Association said the commission’s estimate overstates the role of non-public utilities, which it estimated at 19% of sales nationally. APPA said the data FERC used, from the Energy Information Administration’s (EIA’s) Form 861, are inaccurate because EIA reports a power marketer’s sales as being from a single region although it may make sales in several regions.

Impact:

The reporting requirements cover only “surplus” sales. Excluded from reporting are cooperative and joint agency sales to members or long-term, cost-based sales required by state or federal law.

The order may affect more than 40 public power utilities whose sales top 4 million MWh, according to data compiled by the American Public Power Association.  Among the largest agencies are several PJM members, including American Municipal Power, Inc., North Carolina Municipal Power Agency No. 1, Indiana Municipal Power Agency and WPPI Energy. (To help PJM market participants in their data gathering, the Market Settlements Reporting System (MSRS) provides reports formatted to match the EQR structure.)

About half of the 60 largest generation and transmission cooperatives also are likely to be covered by the new rule, according to a former FERC staff attorney who had analyzed the order’s impact.

FERC estimated in Order 768 that the rule would cover about 53 non-public utilities above the threshold.

The order also added new fields in the EQR for:

  • reporting the trade date and the type of rate;
  • identifying the exchange used for a sales transaction, if applicable;
  • reporting whether a broker was involved; and
  • reporting electronic tag (e-Tag) ID data.

It also standardized reporting of prices and quantities for energy, capacity and booked out transactions and requires entities to disclose whether they report their sales transactions to an index publisher.

The Commission did cut two requirements, eliminating reporting on time zones and Data Universal Numbering System (DUNS) information.

Industry Reaction:

The National Rural Electric Cooperative Association said that FERC overestimated the impact of its members on wholesale markets and that the EQR expansion would not improve transparency.

However, the Pennsylvania Public Utility Commission supported the reporting requirement, saying it will help its ability to monitor retail markets for anti-competitive behavior. Pennsylvania has 13 rural electric cooperatives and about 35 municipal electric utilities.

Market monitors for PJM, MISO, NYISO, ISO-NE SPP, and California ISO also supported the requirement. The monitors noted that the commission’s market-based rate program is based on “regulation through competition,” and is thus dependent on mitigating market power.

FERC contacts:

Maria Vouras, Office of Enforcement, (202) 502-8062, Maria.Vouras@ferc.gov
Christina Switzer, Office of the General Counsel, (202) 502-6379, Christina.Switzer@ferc.gov

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PJM to Alter Practice on Billing Transfers

In response to recent bankruptcy court rulings, PJM will no longer incorporate billing line item transfers when calculating member credit requirements, RTO officials told the Market Implementation Committee last week.

A billing line item transfer allows a member to partially offset its accounts payable with a receivable owed them by another member. The netting of charges from these counterparty transactions are reflected in PJM’s invoices: one invoice increases by the same amount as the second decreases.

Reason for Change: Because PJM uses net invoice values in determining credit requirements, the practice can create a “three-party setoff” between PJM and the two members involved in the transfer. Recent bankruptcy court rulings have restricted the allowance of three-party setoffs, meaning PJM might be precluded from seizing assets in the event of a member bankruptcy.

Impact: PJM will continue to allow line item transfers but will exclude the netting from credit calculations in cases that could increase the RTO’s credit exposure. The change will be effective late in the second quarter. Recalculation of credit requirements will be prospective only.

PJM contact: Hal Loomis

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Demand Response Calls Expected to Grow in 2014

PJM expects to call on its demand response resources from five to nine times per year starting in the 2014/15 delivery year, up from an expected one to five calls in 2013/14.

The projection reflects the increasing volume of DR clearing in PJM capacity auctions and the impact of plant retirements, which are expected to reduce the Installed Generation Reserve Margin (IGRM) to 9% in 2014 from the current 13%.Projected-DR-calls-base-case-bar-chart

PJM briefed the Planning and Market Implementation committees last week on the projections, the results of a GE-MARS Monte Carlo loss of load probability model. The simulations used 2002 data for a “typical” load shape (the same year used in the recent NERC Probabilistic Assessment report).

Likely DR calls are highest in Southwest MAAC and lowest in the Dominion zone (see previous chart).

Projected-DR-calls-scenario-analysisScenario analyses showed the results were highly dependent on the amount of generation reserves assumed, that is, whether uncleared internal generation will be available to serve PJM load. Assumed emergency import capabilities, particularly into SWMAAC, also had a significant impact. The results were not affected much by the assumed DR triggers.

Since the 2010/11 delivery year (June 1 – May 31), PJM has declared 11 Emergency DR events, resulting in nine Energy Emergency Alert (EEA) 2s. EEA2s, called to implement load management procedures, are posted on the Reliability Coordinator Information System (RCIS) and on the PJM Emergency Procedures site.

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Transmission System Briefs

In an effort to improve data collection, PJM will soon begin testing a new method for making interconnection applications.

Reason for Change: PJM engineers have to request additional information on half of the applications made using the current method.

Impact: The new method will use a question-and-answer process to guide applicants. PJM will be seeking a half-dozen volunteers to test the system in June and July before it is deployed. Those interested in volunteering should contact PJM through RTEP@PJM.com.

New Network Protocol for Small Generators

Small generators using public-domain Internet for access to PJM’s SCADA system will be switching to a new system intended to improve security and reliability.

The change affects load response and renewable generation assets under 100 MW not ‘sponsored’ by a generation company, aggregator or marketer.

The current system employs asymmetric “Shared Secret” encryption and uses the public-domain Internet. The new system, which uses “Public Key” encryption based on open standards, is favored by auditors and is considered close to industry best practice, PJM said.

The transition will take three to four years.

PJM contact: Ryan Nice

Dominion Adding Four New 500 kV Line Designations

Dominion’s interconnection of the Brunswick Power Station, a 1,551 MW combined cycle plant, will result in the creation of four new 500 kV line designations.

Dominion is building two new 500kV substations at Rawlings and Brunswick which will require the split of the two existing 500 kV lines: 511 Clover – Carson and 570 Wake – Carson.  The two will be split into four lines: 511 Carson – Rawlings; 585 Carson – Brunswick; 591 Brunswick – Rawlings, a new 14-mile line; and 509 Brunswick – Brunswick Power Station, a new one-mile line. The work is targeted for completion in 2016.

FirstEnergy Shutting Reading Control Center

FirstEnergy will shut down its Reading, Pa., transmission control center and move operations to its Wadsworth, Ohio, center on April 29th. The phone numbers will remain the same.

The Wadsworth facility will itself be replaced by a $45 million control center planned for FirstEnergy’s West Akron campus.  The new facility is expected to be complete by the end of 2013.  It will oversee transmission operations for all of FirstEnergy’s  utilities excluding Mon Power, Potomac Edison and West Penn Power, which will continue to be run from the company’s Fairmont, W. Va., center. The Wadsworth location will be used as a back-up and training facility.

Revised Transmission Matrix Approved

The Operating Committee last week approved revisions to the Transmission Owner/Transmission Operator matrix, an index between NERC reliability standards and PJM manuals.

Reason for change: The matrix is used as a tool during TO/TOP audits. The changes incorporate standards becoming effective this year.

Impact: The changes go next to the Transmission Owner Agreement Administrative Committee for approval.

PJM contact: Mark Kuras

Transient Security Assessment Coming to Real-Time Ops

PJM has begun testing Transient Security Assessments in real-time operations in preparation for a scheduled for June 1 deployment.

Reason for Change: The tool will monitor the transient stability of the PJM system and compute stability limits through real-time data input and network models. The system will collect data every 15 to 20 minutes, allowing PJM operators to implement controls to prevent generators from becoming unstable. PJM has been using the tool in near-term outage studies since the end of 2012.

Impact: Operators will switch from using stability limits found in Manual 3 to those coming from the TSA. PJM’s Dave Souder said the new tool should be more accurate because it is based on real-time conditions as opposed to the light load, conservative case, in Manual 3. The market impact should be “very minor,” said PJM’s Liem Hoang.

The deployment will require completion of benchmarking with ComEd and AEP, updates to Manual 3 and 3A and additional training for PJM operators. Immediately after deployment, operators will monitor only known stability concerns identified in M-03.

PJM contacts: Jianzhong Tong (tongji@pjm.com), Liem Hoang (hoangl@pjm.com)

Removal of Edison Mission Energy SPS in ComEd Zone

A Special Protection System activated to allow an Edison Mission Energy merchant interconnection in the ComEd zone (V3-052 and W2-038) will be removed on August 15. The SPS was used regularly and was still providing congestion relief after the completion of the required upgrades. Economic upgrades for the area have not passed PJM’s cost-benefit screens.

Baltimore Gas & Electric Activating SPS

Baltimore Gas & Electric will activate a Special Protection System for its Concord Street and Mount Washington 115kV lines on June 1 to allow for baseline system upgrades. The Concord Street SPS, designed to alleviate thermal overloads, will be removed with the completion of baseline upgrade b1086, expected in June 2014.  The Mt. Washington SPS, intended to correct voltage drop violations, will be removed on the completion of baseline upgrades b1267 and b1267.1 in about June 2018.

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EPA Delays GHG Limits for New Generators

The Environmental Protection Agency has delayed indefinitely its proposed greenhouse gas limits on new power plants.

EPA last year proposed a rule that would bar new generators from emitting more than 1,000 pounds of carbon dioxide per megawatt hour of electricity production.

An EPA spokeswoman told The Washington Post Friday that the agency could not complete review of the more than 2 million comments in time for an April 13 deadline for finalizing the rule. The spokeswoman said no new timetable had been set.

The Post reported that EPA is considering changes to improve the regulation’s chances of surviving a legal challenge. Read more in the Post.

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MIC to Probe ‘Sham Scheduling’

The Market Implementation Committee approved a request by Market Monitor Joseph Bowring to investigate whether traders could be manipulating PJM’s interface pricing points by breaking schedules into multiple “back-to-back” transactions.

In the 2012 State of the Market report, the monitor described the practice as “sham scheduling,” in which he said traders were hiding the actual source of generation.

PJM prices transactions with external balancing authorities based on the source and sink identified on the NERC eTag. Breaking the transaction into portions with separate eTags can lead to loop flows and incorrect pricing.

A trade from NYISO into PJM, for example, should be priced at the PJM/NYIS Interface. But if a trader breaks the transaction into one trade from NYIS to Ontario and a second on the ONT-MISO-PJM market path, PJM would price the transaction at the ONT Interface price, which is often higher. The monitor recommended that PJM work with NYISO, MISO and Ontario to prevent the practice.

“It’s not a huge problem but we’re worried about the potential of the problem,” Bowring told the committee.

One member representing a Midwestern utility affiliate, was skeptical. “I don’t see how logically you could break up transactions to game the system,” he said. (NOTE: PJM Insider is withholding the speaker’s name and company affiliation in accordance with the PJM Code of Conduct. The rules require the media to obtain a speaker’s permission before quoting him by name at all meetings except those of the Members and Markets and Reliability committees.)

In response to questions from PJM vice president of market operations Stu Bresler, Bowring said that he had contacted traders making back-to-back trades but that it had not changed their behavior.

“Did they say it’s not parking and hubbing?” Bresler asked.

Bowring said he could not discuss specifics of his conversations but added, “We have not been satisfied there was a satisfactory explanation.”

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DR Providers Cry Foul on Information Requirements

Three demand response providers asked the Federal Energy Regulatory Commission April 2 to block new PJM rules requiring them to provide officer certifications and additional information on their customers.

Comverge, Inc., Viridity Energy and Energy Curtailment Specialists said the rules create unnecessary barriers to demand response participation in PJM’s capacity markets, in violation of the Energy Policy Act of 2005. The companies also said the rules, which PJM made effective immediately after their approval by the Markets and Reliability Committee March 28, should have been submitted to FERC for review.  (See previous story.)

The rules require Curtailment Service Providers seeking to participate in capacity auctions to file “Sell Offer Plans,” including information about the provider’s customers. CSPs also must have a company officer sign a certification attesting to the company’s intent to physically deliver MWs.

The group, filing as the Demand Response Coalition, asked FERC to rule by April 19, the deadline for DR providers to file Sell Offer Plans for consideration in the 2016-17 Base Residual Auction (see EL13-57).

The coalition said the Sell Offer Plan requirement is “unduly burdensome and fails to take into account the dynamic nature of these customers and their respective demand resources.”

The officer certification requirement, the group said, “ignores the right of all capacity providers to plan to meet their capacity obligations with multiple capacity products through market mechanisms specifically enabled by the PJM tariff.”

The Ohio Public Utilities Commission filed an intervention in the case on Thursday, saying the new rules were necessary to ensure PJM’s reliability. “The issue is simple, whether a DR provider should be afforded the potential for unwarranted profits for undeliverable or overcounted DR resources to the detriment of PJM’s obligation to ensure reliability,” the commission wrote.

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PJM Reconsiders Adders on Cost-Capped Generators

PJM will evaluate whether it’s time to end extra compensation for generators that frequently run on cost-based offers under market power mitigation rules.

The Market Implementation Committee approved an issue charge by Market Monitor Joseph Bowring to review the “adders” for frequently mitigated units (FMU). Bowring said the adders are no longer needed because of the introduction of the capacity market in 2007 and changes to scarcity pricing rules in 2012.

FMUs were allowed adders in 2006 to ensure that they cover their avoidable costs. The adders are graduated: Generators that are cost capped for 60% of their running hours receive an adder of either 10% of their cost-based offer or $20 per MWh; those capped for 80% or more of their hours can receive $40 per MWh. Similar rules apply to “associated units,” which share physical and economic characteristics to FMUs.

Bowring acknowledged that less than 1% of megawatts sold last year were offer capped. But Bowring said that because the affected units are concentrated in load pockets “it can have more significant impacts locally.” Of the 133 units eligible for FMU or AU status in at least one month during 2012, 25 (19%) were FMUs or AUs for all months.

The monitor won support for the issue charge after agreeing to modify it so that it won’t be pursued until the fourth quarter; some members wanted time to evaluate the impact of scarcity pricing during this summer. Bowring also agreed to remove from the issue charge his conclusion that the reasons for the creation of the adders no longer exists.

Dave Pratzon, who represents generators, said he believed the issue would prove more complicated and time consuming than Bowring suggested. “I think this issue has a lot more hair on it,” Pratzon said.

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CIP Audit Has No Findings

ReliabilityFirst Corp. completed its Critical Infrastructure Protection (CIP) audit of PJM last week with no findings. The audit covered 29 standards, Mark Kuras, PJM Senior Lead Engineer for NERC and Regional Coordination, told the Planning Committee.

Kuras said auditors had seven recommendations, most related to a lack of clarity in PJM’s manuals regarding control room operators’ responsibility for reliability functions.

They also indicated that the transmission line naming conventions used by transmission owners could result in violations in a future audit, Kuras said. NERC names lines based on voltage levels and the substations at either end; transmission owners identify lines by numbers.

“It’s an easy fix for PJM but there will be a lot of pushback from TOs,” Kuras said.

Kuras also said PJM and NERC are still in settlement discussions over violations resulting from the 2010 CIP spot check and Order 693 audit.

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New Modeling OK’d for Combined Cycle Plants

PJM will change the way it models combined cycle generators in its least cost dispatch.

The Operating Committee voted overwhelmingly last week to switch to a “composite” model. This will allow combined cycle owners to bid their units in multiple configurations, including duct firing, that reflect the flexibility of the units (i.e., 1×0, 1×1, 2×1, 3×1). Each configuration will have its own parameters (i.e., start time, minimum run time and startup cost).

Under PJM’s current modeling, combined cycle operators must bid as either a combustion turbine or steam unit.

Dave Pratzon, who represents generators, said the change was necessary because combined cycle units have become more prevalent and are more often setting prices. “To my clients the status quo is not a reasonable alternative,” he said.

John Citrolo, of PSEG, also supported the change, saying the current model doesn’t properly compensate generators for combustion turbines starts and stops. “It models the units’ parameters more accurately, gives PJM [dispatchers] more flexibility and compensates owners more fairly,” he said.

The committee chose the composite model over an alternate “additive (pseudo)” option. The additive option would allow combustion turbines to be modeled as separate market units, with the steam turbine modeled as part of the combustion turbines. Pratzon said the additive model was “just a Band-Aid” and was inferior to the composite model.

The proposed change, which will be considered next by the Markets and Reliability Committee, will require software development by PJM’s vendor, Alstom, and changes by generators. The changes are not expected to be implemented before summer 2014.