Page 1895 – RTO Insider

April 30, 2013

PJM Proposes Operating Reserve Changes to Cut Uplift

PJM called Thursday for a broad review of its method of providing Operating Reserve payments, saying changes were needed to reduce growing uplift costs.

Operating Reserves are “make whole” payments that ensure generators dispatched out of merit for system reliability don’t operate at a loss. Because they are collected through uplift charges and not reflected in day-ahead or real-time locational marginal prices, they cannot be hedged.

In 2012, operating reserve payments totaled a near record $649 million, 2.2% of total billing. Day-ahead operating reserve charges increased by about 90% in 2012, spiking in September after PJM increased the number of “must run” units dispatched in the day-ahead market.

PJM told the Markets and Reliability Committee it should consider an overhaul that incorporates more of the charges into LMPs.

MRC will be asked to vote on a proposed problem statement at its May 30 meeting. The effort, which would create a senior task force reporting to MRC, is expected to take at least a year.

PJM Senior Vice President of Markets Andy Ott said the focus should be a broad “re-look at the whole concept of uplift charges.”

Uplift charges often result from units that may be economic for two hours but must run for longer periods because of minimum run and ramping constraints. “It’s not an unusual circumstance. It happens every day, every hour,” Ott said.

Noha Sidhom, general counsel for Vel Energy, LLC, said her traders have reduced trading of increments and decrements because of price uncertainty. Incs and decs paid an average of about $2.50/MWh in operating reserve charges in 2012, with charges ranging from 20 cents to almost $18/MWh.

Ott said imposing fixed fees on virtual transactions to reflect their administrative costs and contribution to operating reserve charges would result in “a much more robust market.”

The Market Monitor’s State of the Markets report included a dozen recommendations on operating reserves. Among them were a review of the allocation of operating reserve charges to ensure that such charges are paid by all responsible for incurring them, including those making up-to congestion (UTC) transactions. (See “MRC Defines UTCs”)

The monitor estimated the number of UTC transactions would have been cut by two-thirds if they were subject to operating reserve charges.

PJM contact: Lynn Horning

April 25, 2013

PJM Working on New Deal with Monitor

WILMINGTON (April 25, 2013) – PJM announced today it is negotiating a new contract with its independent market monitor, Monitoring Analytics LLC, dropping plans to put the contract out for bid.

PJM General Counsel Vince Duane told the Markets and Reliability Committee that the RTO and Monitoring Analytics have agreed to extend the company’s current contract — due to expire in mid-2014 — through the end of next year.

Duane said PJM would issue a request for proposals (RFP) for monitoring services only if it cannot reach agreement with Monitoring Analytics on a new three-year contract beginning in 2015. Such an impasse “doesn’t seem terribly likely,” Duane said.

Duane said the PJM board made the decision to renew the Monitoring Analytics contract in the interests of “continuity” after receiving feedback from stakeholders.

In March, state regulators, industrial consumers and cooperatives sent the PJM board letters protesting its draft RFP, saying it contained terms that would undermine the independence and quality of the monitoring function.

Duane said yesterday that the new contract would include “reasonable measures” for the board to exercise oversight ensuring the monitor’s “accountability.” Duane promised to update members on the status of negotiations within two months, adding, “What we’d ask for at this time is some breathing room.”

Jeff Mayes, general counsel of Monitoring Analytics, said the company was confident that the two parties would reach agreement.

“We recognize the board’s important role in promoting an independent and capable monitoring function,” Mayes said in a statement. “We appreciate the board’s interest in fulfilling its responsibilities related to market monitoring under the tariff and FERC (Federal Energy Regulatory Commission) rules.”

A new contract with the monitoring firm would allow the board to avert another showdown with stakeholders over the monitor’s role.

Monitoring Analytics is headed by Joseph Bowring, a Ph.D. economist who has served as PJM’s market monitor since 1999. In April 2007, Bowring sparked a firestorm at a FERC technical conference when he accused then-PJM President Phil Harris and his allies of attempting to muzzle him by squelching his reports and cutting his budget.

Under the terms of a settlement approved by FERC, Bowring formed Monitoring Analytics to create an independent monitoring function (EL07-56-000) and was awarded a six-year contract.

April 23, 2013

Electric Industry Leads U.S. in Cybersecurity Protections

The North American Electric Reliability Corp. (NERC) issued $9.2 million in fines for violations of its cybersecurity rules between 2008 and October 2012, half of all fines issued over that period.

Violations of NERC’s Critical Infrastructure Protection (CIP) rules were involved in six of the top 10 penalties, including a $725,000 fine in October.

At a time when Congress has been unable to agree on cybersecurity legislation to protect the rest of the U.S. economy, there’s no doubt that NERC and the Federal Energy Regulatory Commission take the cyber threat seriously.

The industry has come a long way in the three years since I was sitting in on NERC audits as a member of the FERC enforcement staff. The new CIP rules approved by FERC last week will cover more assets and add more controls. They’ll no doubt be good for the business of IT consultants. Regulated utilities that are allowed to put the costs in rate base will be more than happy to spend the money.

But will it be enough to prevent the potential for what former Defense Secretary Leon Panetta called a “cyber Pearl Harbor”?

While Congress gave FERC authority to issue fines of up to $1 million per day per violation, the fines issued to date have been puny relative to the earnings of the companies involved — less than one-tenth of one percent of the companies’ net income (see table)

Meanwhile, a decision by NERC and FERC to stop disclosing the identities of CIP violators — so as not to expose the violators’ vulnerabilities — has removed any reputational risk that companies might fear. Since September 2011, virtually none of those penalized for CIP violations has been named.

In announcing the new CIP rules last week, FERC commissioners emphasized their desire to emphasize compliance over punishment. That’s a reasonable approach, especially when the rules are new.

But if there is no reputational risk and the financial penalties are not material, don’t be surprised if some companies decide that it’s better business to cut corners on cybersecurity.

Rich Heidorn Jr.

April 23, 2013

FERC Remands DR Information Requirements

FERC ruled Friday that PJM must seek commission approval for new rules requiring demand response providers to provide officer certifications and additional information on their customers.

Acting on a complaint by three demand response providers, FERC said the changes required amendments to the PJM tariff and not just its manuals. Tariff changes require commission approval while manual changes don’t.

The rules, implemented March 28, 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 demand response providers filed the complaint April 3, saying the rules create unnecessary barriers to demand response participation in PJM’s capacity markets.

The plaintiffs’ procedural victory may be short-lived, however. In a statement concurring with the order, Commissioners Philip Moeller and Tony Clark indicated they would look favorably on the changes when PJM files them with the commission. “It appears that PJM has a legitimate need to require that demand resources provide certain information to substantiate offers to supply capacity,” the commissioners wrote.

The commissioners said the information was needed to prevent uncertainty that could “degrade the very purpose of PJM’s capacity market.”

April 23, 2013

Bulk Electric Systems (BES) Inclusions and Exclusions

I1 – Transformers with the primary terminal and at least one secondary terminal operated at 100 kV or higher unless excluded under Exclusion E1 or E3.
I2 – Generating resource(s) with gross individual nameplate rating greater than 20 MVA or gross plant/facility aggregate nameplate rating greater than 75 MVA including the generator terminals through the highside of the step-up transformer(s) connected at a voltage of 100 kV or above.
I3 – Black start Resources identified in the Transmission Operator’s restoration plan.
I4 – Dispersed power producing resources with aggregate capacity greater than 75 MVA (gross aggregate nameplate rating) utilizing a system designed primarily for aggregating capacity, connected at a common point at a voltage of 100 kV or above.
I5 – Static or dynamic devices (excluding generators) dedicated to supplying or absorbing Reactive Power that are connected at 100 kV or higher, or through a dedicated transformer with a high-side voltage of 100 kV or higher, or through a transformer that is designated in Inclusion I1.

Exclusions:

E1 – Radial systems: A group of contiguous transmission Elements that emanates from a single point of connection of 100 kV or higher and: a) Only serves Load. Or, b) Only includes generation resources, not identified in Inclusion I3, with an aggregate capacity less than or equal to 75 MVA (gross nameplate rating). Or, c) Where the radial system serves Load and includes generation resources, not identified in Inclusion I3, with an aggregate capacity of non-retail generation less than or equal to 75 MVA (gross nameplate rating).
E2 – A generating unit or multiple generating units on the customer’s side of the retail meter that serve all or part of the retail Load with electric energy if: (i) the net capacity provided to the BES does not exceed 75 MVA; and (ii) standby, back-up, and maintenance power services are provided to the generating unit or multiple generating units or to the retail Load by a Balancing Authority, or provided pursuant to a binding obligation with a Generator Owner or Generator Operator, or under terms approved by the applicable regulatory authority.
E3 – Local networks (LN): A group of contiguous transmission Elements operated at or above 100 kV but less than 300 kV that distribute power to Load rather than transfer bulk-power across the interconnected system. LN’s emanate from multiple points of connection at 100 kV or higher to improve the level of service to retail customer Load and not to accommodate bulk-power transfer across the interconnected system. The LN is characterized by all of the following:
- Limits on connected generation: The LN and its underlying Elements do not include generation resources identified in Inclusion I3 and do not have an aggregate capacity of non-retail generation greater than 75 MVA (gross nameplate rating);
- Power flows only into the LN and the LN does not transfer energy originating outside the LN for delivery through the LN; and
- Not part of a Flowgate or transfer path: The LN does not contain a monitored Facility of a permanent Flowgate in the Eastern Interconnection, a major transfer path within the Western Interconnection, or a comparable monitored Facility in the ERCOT or Quebec Interconnections, and is not a monitored Facility included in an Interconnection Reliability Operating Limit (IROL).
E4 – Reactive Power devices owned and operated by the retail customer solely for its own use.

April 23, 2013

What You Need To Know About CIP Version 5

NERC’s version 5 Critical Infrastructure Protection (CIP) rules include 10 standards, two of them new.

The commission’s conditional approval of version 5 came in the form of a Notice of Proposed Rulemaking. The commission will accept comments on the new rules for 60 days after their publication in the Federal Register.

The commission said NERC had not provided justification for setting a 24-month implementation period for High Impact and Medium Impact BES Cyber Systems, and a 36-month implementation period for Low Impact systems.

CIP version 3 (CIP-002-3 through CIP-009-3) will remain in effect until the effective date of version 5. Version 4 (CIP-002-4 through CIP-009-4) will not take effect as originally planned.

Version 5 requires registered entities to classify all of their Bulk Electric System (BES) facilities based on their impact on reliability. The Low, Medium or High impact categories replace the previous approach, in which facilities were either covered or not covered by CIP standards.

NERC Critical Infrastructure Protection Violations 2008-2012

Reason for Change:

Version 5 adds new cybersecurity controls and extends the scope of the systems protected by them. Many of the changes were directed by the Commission in Order 706 (Jan. 18, 2008).

The shift to identifying and categorizing high, medium and low impact systems was based on a review of the National Institute of Standards and Technology (NIST) risk management framework for categorizing and applying security controls.

Impact:

Version 5 is comprised of 10 standards, one covering the categorization of assets and nine mitigating their risk of being compromised (see Highlights of CIP Version 5). It includes 15 newly defined terms, modifications to four existing terms and retires two terms: Critical Assets and Critical Cyber Assets.

Systems at all impact levels must be within a security zone that provides protection from outside influences using a posture of “mutual distrust.” No communications crossing the perimeter is trusted, regardless of where the communication originates.

To Be Determined:

The commission approved most of NERC’s proposals but said it may require NERC to change requirements that entities “identify, assess, and correct” deficiencies. The commission said it was concerned that the phrase was “unclear with respect to the compliance obligations it places on regulated entities and … too vague to audit and enforce compliance.”

The commission said it may require NERC to either change the language or provide details for how it would be applied and how compliance could be audited.

The commission also said NERC had not provided a “clear roadmap” for what operators of low impact facilities must do to achieve compliance.

NERC proposed an implementation period of 24 months for all but those regarding low impact systems, which would have 36 months to comply. The commission said NERC had not explained its rationale for the implementation plan and said it will order quicker compliance unless NERC or other commenters “provide reasonable justification” for the proposed time frame.

(For a full list of what’s included in CIP Version 5, click here.)

April 23, 2013

Cost Recovery Criteria OK’d

The Commission approved criteria for determining which NERC activities are eligible for cost recovery under section 215 of the Federal Power Act.

Reason for change:

A FERC audit issued last year recommended the development of the criteria.

Impact:

The criteria restrict funding to “statutory” activities such as those involving the development, monitoring and enforcement of reliability standards, along with related training.

FERC will use the criteria in approving NERC’s annual budgets. Expenses approved by FERC are eligible for cost recovery from end users.

The commission ruled that the proposed criteria were generally acceptable but required replacement of the term “involve or support” with the term “necessary or appropriate” as the basis for funding. The commission said the former term was too broad and provided no practical limitation on funding.

April 23, 2013

Cyber Asset Definitions

Programmable electronic devices and communication networks including hardware, software and data.

Bulk Electric System (BES) Cyber Asset

A cyber asset which, if lost, damaged or misused would within 15 minutes affect the reliable operation of the grid. Redundancy of affected facilities is not considered when determining adverse impact. The definition excludes assets connected to the grid for 30 consecutive days or less that are used for data transfer, vulnerability assessments, maintenance, or troubleshooting.

April 23, 2013

FERC OKs New Reliability Standards

Expanded Cybersecurity Focus

New Approach for Generators

WASHINGTON — The Federal Energy Regulatory Commission gave preliminary approval Thursday to a rewrite of cybersecurity rules and set a “bright line” requiring most facilities at 100 kV or higher to abide by them.

The commission issued four orders approving proposals by the North American Electric Reliability Corp. (NERC). Included were:

A new definition of transmission facilities covered by NERC reliability rules that upgrades the longstanding 100 kV threshold from a guideline to a directive. Regional discretion on the definition of Bulk Electric Systems (BES) is eliminated. (more)
Version 5 Critical Infrastructure Protection (CIP) standards, which replace the current “in or out” designations with a tiered approach which classify assets as high, medium or low impact. The commission said version 5’s improvements were important enough that companies now operating under CIP version 3 will skip CIP Version 4, due to take effect date, April 1, 2014, and transition directly to version 5. (more)
New rules for generator interconnections that will eliminate the need for most generators to register as transmission operators. (more)
Criteria for determining which NERC activities are eligible for cost recovery. (more)

April 23, 2013

New Reliability Rules for Generator Interconnections

The commission issued a Notice of Proposed Rulemaking for four new reliability standards addressing vegetation management and facility connection requirements for generator interconnection facilities (also known as generator tie lines).

Reason for Changes:

FERC had encouraged NERC to identify reliability standards specific to generator owners and operators with interconnection facilities including transmission lines. Eliminating the need for generators to register under the transmission function will allow them to focus on reliability standards specific to them, NERC said.

Impact:

FAC-001-1 requires a Generator Owner to publish facility connection requirements when it executes an agreement to evaluate the reliability impact of interconnecting a third party facility to its tie line.
FAC-003-3 requires a Generator Owner to perform vegetation management on its tie line.

Standards PRC-004-2.1a (Analysis and Mitigation of Transmission and Generation Protection System Misoperations) and PRC-005-1.1b (Transmission and Generation Protection System Maintenance and Testing) establish generation owners’ responsibility for the FAC requirements as they apply to tie lines.

In most cases, NERC said, these are the only reliability standards that apply to generator interconnection facilities. The changes do not affect the requirement that generators comply with other reliability standards unrelated to tie lines, such as those covering system restoration plans and notification of equipment failures.

Generators currently registered under transmission functions will have to apply to change their certifications under the NERC Rules of Procedure.