Members voted Thursday to approve a problem statement to consider modifying the design of the Reliability Pricing Model to ensure physical delivery of resources that clear the capacity auction.
Jason Barker, of Exelon, proposed the inquiry, saying it was needed to prevent potential reliability issues because PJM is becoming increasingly reliant on proposed new generation to maintain its reserve margin. Some planned generators that cleared for delivery two years from now “haven’t broken ground yet,” he said.
“While there doesn’t appear to be any reliability threat imminently, we believe this issue is pressing,” he said.
Some players may be speculating without any intention of bringing physical capacity by bidding into the base auction and then buying replacement capacity at a discount in the interim auctions. Barker said one goal of the inquiry would be to “parse speculation from legitimate covering” of shortfalls and increasing penalties for those who offer capacity resources but fail to produce them in the delivery year.
The problem statement was approved by a 4.15 to 0.85 vote but not before several members expressed concerns over the inquiry.
“We could potentially create more problems than we’re solving,” said Frank Francis, director of regulatory affairs for Brookfield Energy Marketing LP,
Gloria Godson, vice president federal regulatory policy for Pepco Holdings Inc., said her company has legitimate reasons for buying in the incremental auction. “How can you define intent?” she asked.
Dan Griffiths, of demand response aggregator Comverge, said his company doesn’t speculate but needs to use the incremental auction to respond to changes in market rules. “Every year the rules change. That forces us to reevaluate our needs.” “We don’t have regulatory certainty.”
Susan Bruce, an attorney representing the PJM Industrial Customer Coalition, said the initiative should not quash competition: “I want to make sure we are keeping the welcome mat out for new resources and that we don’t discriminate.”
Barker insisted, “It is not our intent to create barriers to competitive entry.” Any increase in deficiency penalties would apply to all resources, he said.
PJM Executive Vice President for Markets Andy Ott said the issue would be assigned to either the Capacity Senior Task Force or the Market Implementation Committee.
Saying it has a “moral obligation” to do more to combat climate change, Maryland Gov. Martin O’Malley last week called on the state to get one-quarter of its electricity from renewable sources by 2022, a 25% increase from the current Renewable Portfolio Standard.
O’Malley also restated his support for a regional cap-and-trade program to cut carbon dioxide emissions and pledged to improve the state’s lagging energy efficiency programs.
The governor, who will leave office in 2015, wants to strengthen his environmental credentials as he prepares for a possible presidential run.
The state has reduced its greenhouse gas emissions by 8% since 2006. But current efforts are likely to result in only a 17% cut by 2020, short of its 25% reduction target.
Renewable Portfolio Standard
Electricity consumption is responsible for about 41% of the state’s emissions. Thus boosting the RPS goal to 25% would make up a large part of the gap in GHG reductions, O’Malley said.
Renewable power provides almost 8% of Maryland’s electricity, up from less than 6% in 2007. Increasing the state’s RPS targets — currently 18% by 2020 and 20% 2022 — would require the support of lawmakers, who doubled the state’s original RPS goal in 2008.
Doing so would be a boon for renewable generators both in the state and — because the state imports 28% of its electricity — elsewhere in PJM.
Energy Efficiency
The 2008 EmPOWER Maryland Energy Efficiency Act pledged to reduce Maryland’s per capita electricity consumption and peak load demand by 15% below 2007 levels by 2015. Thus far, peak electricity demand has declined by nearly 11% and per capita consumption is down by more than 9%.
More than 430,000 households and businesses have participated in EmPOWER programs, putting the state on track to exceed its 15% peak demand reduction goal. But it is likely to reach only a 14% reduction in per capita usage based on current policies. O’Malley said the state can improve its performance with lessons from states that are reducing consumption faster.
Cap-and-Trade
O’Malley also reiterated the state’s commitment to the Regional Greenhouse Gas Initiative (RGGI). In February, Maryland and the eight other Northeast and Mid-Atlantic states in RGGI pledged to lower their 2014 carbon dioxide emissions to 91 million tons and to reduce the cap by 2.5% annually between 2015 and 2020.
Carbon emissions from power plants subject to RGGI declined from 165 million tons to 92 million tons between 2008 and 2012. Most of the reduction is the result of the 2008 recession, milder weather and the rise of natural gas at the expense of coal with the remainder coming from energy efficiency and renewable energy programs funded by auction revenues.
O’Malley’s support of RGGI is in contrast with that of New Jersey Republican Gov. Chris Christie, another potential presidential candidate, who pulled his state from the program in 2011, saying it was expensive and ineffective.
O’Malley’s call for an increase in RPS standards also contrasts with the policy of many Republicans. Twenty nine states and Washington, D.C. have RPS standards. In 2011 and 2012, at least 14 states considered 50 bills to lower or weaken RPS standards, five of which succeeded.
The Members Committee Thursday approved the following four issues by acclimation:
Proposed errata revisions to the OA and Tariff
Reason for change: The committee approved corrections to errors inserted in Schedule 1 of the PJM Operating Agreement and Attachment K of the Tariff in 2008 and 2009. One correction will clarify how deviations occurring within one zone are associated with PJM’s Eastern or Western region for purposes of Operating Reserve charges. The other will insert a cross reference to tie language concerning forgiveness of positive demand deviations to the shortage pricing “trigger.”
FTR modeling changes developed by the FTR Task Force
The committee approved two proposals for lowering the risk of Financial Transmission Rights revenue shortfalls. The two proposals were developed by the FTR Task Force and approved May 8 by the Market Implementation Committee.
Reason for changes: The two proposals reduce or remove infeasibilities in the FTR model and may allow increased counterflow FTRs to clear.
Impact: Under the first option (FTR Task Force option 2J), PJM “may model normal facility capability limits, if possible, for all Stage 1A over allocated facilities in FTR Auctions.” The second option (option 3G), would allow PJM to “model normal facility capability limits, if possible, on facilities which are infeasible as a result of modeled transmission outages in monthly FTR Auctions.”
Suspension of the day-ahead market after loss of Internet
PJM will suspend its Day Ahead market if it loses Internet service under a contingency plan the committee approved.
Reason for change: PJM’s Tariff and Operating Agreement do not specify procedures for responding to an extraordinary event, such as an Internet failure, that disables the RTO’s eMKT application.
Impact: Under the tariff changes approved in July by the Markets and Reliability Committee, all market settlements would be done in real time in such circumstances. (See MRC OKs Contingency Plan for Loss of Internet.)
New benefit test for market efficiency projects
The committee approved changes to the way PJM determines beneficiaries of market efficiency transmission projects and how PJM planners add generation in market efficiency simulations.
Reason for change: The changes, which were approved by MRC in July, were developed by the Regional Planning Process Task Force to align modeling and beneficiary determinations with the revised cost allocation formula approved by the Federal Energy Regulatory Commission in PJM’s Order 1000 compliance filing.
Impact: Benefits of regional projects will be calculated on a 50/50 ratio based on their impact on production costs and net load payments (energy benefits) or impact on capacity costs and net capacity payments (capacity benefits). Benefits of local, low-voltage projects will be determined entirely on the change in net load or capacity payments for zones that experience decreases.
Under the previous method for both regional and local projects, 70% of benefits were calculated based on production or capacity cost savings, with the remainder based on change in net load or capacity payments.
Below is a summary of the issues scheduled to be brought to a vote at the Markets and Reliability Committee and Members Committee meetings Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider (previously PJM Insider).
RTO Insider will be in Wilmington covering the discussions and votes. See next Tuesday’s newsletter for a full report.
Markets and Reliability Committee
2. PJM MANUALS (9:10-9:25)
A. Manual 12: Balancing Operations
Reason for change: PJM is changing the regulation requirement to align it with operational needs and address volatility in light load periods.
Impacts:
Changes On-peak (05:00-23:59) requirement to 700 effective MW, a decrease in the requirement for 52% of days, an increase for 48% of days. Net daily decrease of about 60 MW (section 4.4.3).
Changes Off-peak (00:00-04:59) requirement to 525 effective MW, an increase for 66% of days and a decrease for 34% of days. Net daily increase of about 20 MW (section 4.4.3).
Changes regulation scoring methods:
Performance scoring for small regulation allocation: Historical performance scores will be used if the control signal has an average absolute value less than 1% of the regulation assignment (section 4.5.6);
Performance scores when data is not available: Historical performance scores will be used if data is not available and for intervals less than 15 contiguous minutes (adds section 4.5.9);
Regulation Assignments: Scoring will be suspended for 10 minutes after assignment to allow time to ramp into position (adds section 4.5.10).
PJM contact: Rus Ogborn
B. Manual 19: Load Forecasting and Analysis.
Reason for changes: Integration of East Kentucky Power Cooperative (EKPC), addition of annual demand resources and need to ensure accuracy of load shed programs.
Impacts:
Adds EKPC to load forecast model;
Revises assumption for winter load management;
Makes minor typo fixes and clarifications for NERC audits;
Changes demand resources available in winter months due to addition of annual DR product;
Codifies guidelines for switch operability studies for load management programs. The guidelines are designed to ensure the accuracy of load shed estimates for participants in direct load control programs. The study must be designed for a minimum 90% confidence level and based on a randomly selected sample from the entire population of participating customers. No customers can be excluded.
PJM contact: JohnReynolds
C. Manual 20: PJM Resource Adequacy Analysis
Codifying procedure approved by FERC. The changes were endorsed by the Planning Committee in October 2012.
Impact: Revises section 5 to add Test 2 for the six-hour duration requirement for the Limited DR Product. The Test 2 procedure is effective with the 2016/17 Delivery Year.
PJM contact: Tom Falin
D. Manual 1: Control Center and Data Exchange Requirements
Reason for change: New rules for access to PJM Energy Management System (EMS).
Impacts:
Added new section 2.5.7 detailing rules for transmission owner read-only access to PJM’s EMS. No screen scraping is allowed;
Modified section 3.2.3 to clarify procedures for data communication outages;
Modified section 4.2.4 to clarify repeating of All Call messages;
Adds details to Information Access Matrix in Attachment A.
Wind farms that fail to follow PJM’s electronic dispatch signals will no longer receive lost opportunity cost payments under a tariff amendment the MRC will be asked to approve.
Reason for change: Some wind generators are not following their economic basepoint, requiring PJM to issue manual dispatch instructions. This delays generators’ responses, causing less efficient market operations and a potential risk to system reliability, PJM says.
PJM proposed the new language as a Tariff change in response to a May 29 Federal Energy Regulatory Commission order that rejected its earlier proposal to incorporate the new rules in the Operating Agreement. The commission said the OA language “failed to provide any detail or tariff language describing the specific circumstances under which compensation would be reduced or how the compensation would be reduced.”
Impact: Would add language to section 3.2.3 of Tariff Schedule 1 to deny lost opportunity credits to pool-scheduled or self-scheduled wind generators that fail to follow PJM dispatchers’ electronic instructions to reduce output. (See PJM to Tighten Penalties on Wayward Wind.)
4. MUST-OFFER EXCEPTION DEADLINE (9:45-10:00)
Hatfield’s Ferry Power Plant (Source: FirstEnergy)
To overcome generators’ objections, PJM and the Market Monitor have modified this proposal, which would set earlier deadlines for power plants seeking exemptions from participation in PJM’s capacity market auctions.
Reason for change: PJM says the current rules, which require 120 days’ notice before the opening of the auction, don’t give it enough time to analyze the impact of plant retirements on system operations.
Impact: The proposal would require generators seeking exemption from the “must-offer” requirement to file notice by Sept. 1 for the annual base residual auction (BRA) and 120 days before incremental auctions. The exemptions apply to generators that will be unable to provide capacity because they plan to retire.
In response, PJM and the monitor changed the proposal to provide generators more flexibility and to mask the identities of individual power plants. Under changes announced yesterday at the Members Committee Information Webinar:
Retirement requests must be made by September 1 but can be based on a conditional deactivation analysis. The submission would specify the conditions that are creating uncertainty, such as pending negotiations on fuel or labor contracts. The finalized deactivation plan would be required by December 1 unless the request is withdrawn.
PJM will post information on pending plant retirements in the first week of September but will do so using zonal aggregation rather than identifying individual generators. For each transmission zone, PJM will specify the amount of capacity scheduled to retire within one of the following ranges:
Less than 100 MW
100 MW to 500 MW
500 MW to 1000 MW
Total capacity to be retired will be specified if a zonal total exceeds 1,000 MW.
5. CSTF CHARTER UPDATES (10:00-10:15)
MRC will be asked to approve changes to the charter of the Capacity Senior Task Force.
Reason for change: Recently approved problem statements require a change in work scope.
Impact: The charter will be changed to reflect two recent problem statements:
Demand Response as an Operational Capacity Resource – A problem statement approved by MRC June 27 charges the CSTF to investigate and develop recommended solutions on the following issues: Changes to DR obligations to move from administrative procedures to economic dispatch; diversifying notification time requirements based on physical response capability, similar to current requirements for generators; allowing DR to operate with a dispatchable range; caps on the amount of Limited DR that can be cleared above the quantity specified in the reliability analysis and changes in the way DR is modeled in PJM planning studies. The task force is expected to complete its work in time for a December 1, 2013 filing for implementation in the 2014/15 Delivery Year. (See PJM Demand Response Providers Decry Scrutiny, “Freight Train” of Changes.)
Unit-specific review process under Minimum Offer Price Rule (MOPR) – MRC instructed CSTF to research this issue on May 23 in response to a FERC Order (docket ER13-535) which suggested PJM conduct a stakeholder process to consider revisions to standardize the unit specific review process. The task force will consider changes to financial modeling assumptions and ways to increase the transparency of the process. The task force is expected to complete its work in time for a December 1, 2013 filing for implementation in the 2014/15 Delivery Year. (See PJM, Monitor Push New MOPR Changes.)
Jason Barker, of Exelon, will seek MRC approval of a problem statement to consider modifying the design of the Reliability Pricing Model to ensure physical delivery of resources that clear the capacity auction.
Reason for Change: Barker told the MRC in July that the current design lacks sufficient penalties for those who offer capacity resources but fail to produce them in the delivery year.
He said the problem statement was needed to address reliability concerns caused by the increase in non-firm, planned resources clearing in the past three base residual auctions — including uncontracted demand response, planned internal generation, and existing and planned external generation that lacks firm transmission service.
Reason for change: The committee will be asked to approve corrections to errors inserted in Schedule 1 of the PJM Operating Agreement and Attachment K of the Tariff in 2008 and 2009. One correction will clarify how deviations occurring within one zone are associated with PJM’s Eastern or Western region for purposes of Operating Reserve charges. The other will insert a cross reference to tie language concerning forgiveness of positive demand deviations to the shortage pricing “trigger.”
C. FTR modeling changes developed by the FTR Task Force
The committee will be asked to approve two proposals for lowering the risk of Financial Transmission Rights revenue shortfalls. The two proposals were developed by the FTR Task Force and approved May 8 by the Market Implementation Committee.
Reason for changes: The two proposals reduce or remove infeasibilities in the FTR model and may allow increased counterflow FTRs to clear.
Impact: Under the first option (FTR Task Force option 2J), PJM “may model normal facility capability limits, if possible, for all Stage 1A over allocated facilities in FTR Auctions.” The second option (option 3G), would allow PJM to “model normal facility capability limits, if possible, on facilities which are infeasible as a result of modeled transmission outages in monthly FTR Auctions.”
D. Suspension of the day-ahead market after loss of Internet
PJM will suspend its Day Ahead market if it loses Internet service under a contingency plan the committee will be asked to approve.
Reason for change: PJM’s Tariff and Operating Agreement do not specify procedures for responding to an extraordinary event, such as an Internet failure, that disables the RTO’s eMKT application.
Impact: Under the tariff changes approved in July by the Markets and Reliability Committee, all market settlements would be done in real time in such circumstances. (See MRC OKs Contingency Plan for Loss of Internet.)
E. New benefit test for market efficiency projects
The committee will consider changes to the way PJM determines beneficiaries of market efficiency transmission projects and how PJM planners add generation in market efficiency simulations.
Reason for change: The changes, which were approved by MRC in July, were developed by the Regional Planning Process Task Force to align modeling and beneficiary determinations with the revised cost allocation formula approved by the Federal Energy Regulatory Commission in PJM’s Order 1000 compliance filing.
Impact: Benefits of regional projects will be calculated on a 50/50 ratio based on their impact on production costs and net load payments (energy benefits) or impact on capacity costs and net capacity payments (capacity benefits). Benefits of local, low-voltage projects will be determined entirely on the change in net load or capacity payments for zones that experience decreases. (See chart.)
Under the previous method for both regional and local projects, 70% of benefits were calculated based on production or capacity cost savings, with the remainder based on change in net load or capacity payments.
The Federal Energy Regulatory Commission last week accepted PJM’s revised plan for compensating frequency response providers, rejecting a rehearing request from PSEG Companies.
The commission’s order concerned PJM’s January 15 compliance filing in response to Order 755, which required regional transmission operators (RTOs) and independent system operators (ISOs) to institute a two-part payment method for compensating frequency regulation resources. The order required RTOs and ISOs to make a capacity payment for making the resource available when needed and a performance payment based on the amount of work performed in response to the system operator’s dispatch signal.
PJM’s January 15 submission — its third compliance filing in response to Order 755 — addressed FERC’s November 16 ruling that PJM’s methodology would allow resources to be paid differently even when their performance is comparable.
PSEG asked the commission to reconsider the November order, arguing that PJM’s use of a “benefits factor” in determining compensation was unjust and unreasonable. The commission rejected PSEG’s challenge on procedural grounds Thursday, saying it raised issues settled in a previous order.
The commission also said PSEG failed to support its argument that PJM’s methodology would lead to overpayments to regulation resources, saying the company “has neither demonstrated when overcompensation occurs nor how it ought to be measured.”
The commission decided in PSEG’s favor on one point, saying PJM had failed to fully comply with its November order. The commission ordered PJM to make an additional compliance filing within 90 days that revises a section of its Operating Agreement.
The Federal Energy Regulatory Commission (FERC) Thursday endorsed revised business practices and communication standards to comply with commission Orders 890 and 676.
The Notice of Proposed Rulemaking (RM05-5-022) would accept version 3 of the standards, which were drafted by the North American Energy Standards Board (NAESB).
In Order 890 and companion orders (order 890-A through 890-C), the commission added greater specificity and transparency to the pro forma Open Access Transmission Tariff (OATT) created in Order 888.
Order 676 adopted business practices and communication protocols as well as creating a process for reviewing and upgrading the Commission’s OASIS rules and other wholesale electric industry business practices.
Among the topics covered in version 3 are: Service across multiple transmission systems (SAMTS); network integration transmission service (NITS); rollover rights for redirects and available transfer capacity (ATC) credits; gas/electric coordination and smart grid standards (defining use cases, data requirements, and a common model to represent customer energy usage).
Comments on the proposals will be accepted for 60 days after publication in the Federal Register.
Federal regulators moved Thursday to give gas pipeline operators explicit permission to exchange non-public operational information with PJM and other RTOs.
The Federal Energy Regulatory Commission approved a Notice of Proposed Rulemaking (RM13-17) that it said would improve planning and reliability by revising the commission’s Standards of Conduct.
The proposed rule is the first regulatory change by FERC since it began an inquiry on gas-electric interdependence in February 2012 (AD12-12-000) due to concerns over gas-fired generators obtaining reliable fuel supply during the winter heating season.
While the commission has urged increased communication between gas pipelines and electric grid operators, numerous parties filed written comments or told FERC at regional conferences that they feared sharing operational information would run afoul of commission rules.
The Interstate Natural Gas Association of America (INGAA), for example, told FERC that pipelines could be accused of violating the Natural Gas Act’s prohibitions against undue discrimination for providing a grid operator with non-public transmission information without simultaneously disclosing that information to all other shippers or potential shippers.
Communication Permitted
As a result, the commission said last week, it was proposing revisions to its Standards of Conduct rules to provide assurances. “This is just to clarify that this [communication] is permitted under our current regulations,” said Commissioner Cheryl LaFleur.
Natural gas generation provided nearly 19% of PJM’s electricity in 2012, a nearly 40% jump over its production in 2011. In ISO-NE, natural gas’ share has increased ten-fold in 20 years, from 5% in 1990 to 51% in 2011.
Commissioners said they expect to take additional actions to prevent a collision between the needs of gas heating customers and gas-fired electric generators.
“We’re going to get a cold winter one of these years and we have to make sure we have enough energy to go around,” said Commissioner Philip Moeller.
The new regulations, (proposed sections 38.3(a) and 284.12(b)(4) of the commission’s regulations) would allow electric grid operators and gas pipelines to share non-public information for reliability and operational planning. In a presentation, commission staff said information sharing should be the rule “not just during emergencies, but also for day-to-day operations, planned outages, and scheduled maintenance.”
No List
The NOPR does not propose a list of non-public, operational information that can be shared, but gives examples, including:
real-time and anticipated system conditions with potential to change gas flows;
actual and anticipated electric service interruptions to gas compressor locations;
actual and projected gas transportation restrictions to electric generators;
real-time flow and operational capacity data at receipt and delivery points;
nominated and scheduled quantities of shippers who are or who supply gas-fired generators; and,
scheduled dates and duration of generator, pipeline, and transmission maintenance and planned outages.
Assurances
Much of the NOPR explains why communications between the two industries does not violate applicable rules and laws.
It notes, for example, that the commission’s Standards of Conduct apply to communications only within the same organization and do not limit communications between unaffiliated pipelines and electric transmission providers.
It also notes that the Federal Power and Natural Gas acts only prohibit “undue” preferences, advantages and prejudices. “A difference in treatment is not unduly discriminatory when the difference is justified,” the commission said.
The undue discrimination provisions are intended to ensure equal treatment for “similarly situated” customers.
“Transmission operators are not similarly situated to other customers because they require access to non-public scheduling and other types of information from a variety of sources to help them ensure the reliability and integrity of the transportation and transmission systems. In addition, natural gas pipelines are generally not customers of electric transmission operators. Likewise, in the case of RTOs/ISOs, they are not shippers on pipelines,” the commission said.
The commission also noted that gas pipelines and electric transmission operators have long shared non-public information with their counterparts. “For example, pipeline operators routinely exchange nomination and scheduling information with other pipeline operators and with upstream and downstream entities (that may be shippers on the pipeline) to confirm transportation nomination requests and to coordinate flows between the parties. Transmitting electric utilities similarly coordinate the sharing of non-public interchange schedule information on a routine basis through mechanisms such as, for example, e-Tags.”
No-Conduit Rule
The NOPR includes a “No-Conduit Rule” to prohibit recipients of non-public information from relaying that information to marketing employees or others who could profit from it.
Comments will be accepted for 30 days after posting of the NOPR in the Federal Register.
FERC contacts:
Technical Information: Caroline Daly, Office of Energy Policy & Innovation, (202) 502-8931, caroline.daly@ferc.gov
Legal Information: Anna Fernandez, Office of the General Counsel, (202) 502-6682, anna.fernandez@ferc.gov
The Federal Energy Regulatory Commission Thursday rejected PSEG’s challenge to PJM’s procedure for selecting new transmission projects, saying the company had failed to prove that PJM’s methodology was “tantamount to black box decision-making.”
PSEG had asked the commission to reconsider its November 29 order accepting revisions to PJM’s Operating Agreement that clarified how the RTO will use sensitivity studies, modeling assumptions and scenario planning analyses in developing its Regional Transmission Expansion Plan (RTEP).
PSEG asked FERC to require PJM to provide more details on how it will decide what scenarios to utilize and how to weight them.
The commission said, however, that PJM’s revisions “strike an appropriate balance between the need for PJM to maintain some flexibility … and the need for sufficient detail in the tariff to allow stakeholders to participate in the planning process.
“The process is not a `black box’ but an open and transparent process into which PSEG and all PJM stakeholders have the opportunity to provide input,” the commission ruled.
FERC also rejected PSEG’s request for additional safeguards to maintain cost controls market efficiency transmission projects modified as a result of sensitivity and scenario analyses. The commission noted that the revised agreement did not eliminate the cost benefit test that such projects must pass before approval.
PSEG did “not provide any concrete examples of how a lack of `limits to the extent to which an existing reliability or market efficiency project may be modified as a result of sensitivity and scenario studies’ puts PJM’s cost control measures at risk,” the commission said.
PSEG also requested that PJM align its RTEP process with the design of its forward capacity market, saying PJM’s “generation-related assumptions” in the RTEP should “be the same as the assumptions underlying the various [capacity] auctions.”
The commission rejected that request as outside the scope of the proceeding. It said PSEG should raise such questions within PJM’s stakeholder process or through a separate section 206 complaint to the commission.
The Federal Energy Regulatory Commission Thursday gave final approval to one reliability standard and opened for comment two others.
The commission issued a final rule on the North American Electric Reliability Corp.’s Modeling, Data, and Analysis standard (MOD-028-2; Docket No. RM12-19-000). The rule clarifies the timing and frequency of total transfer capability measurements, which are needed to calculate a transmission provider’s available transfer capability.
In addition, the commission issued Notices of Proposed Rulemaking for two proposed NERC standards: Frequency Response and Frequency Bias Setting (BAL-003-1; Docket No. RM13-11-000) and Protection System Maintenance Reliability Standard (PRC-005-2; Docket No. RM13-7-000), in compliance with directives from FERC Order 693.
Frequency Response
The BAL standard includes requirements for the measurement and provision of frequency response, filling a gap in current standards.
The rule will establish a minimum frequency response obligation for each Balancing Authority, provides a uniform calculation of frequency response, establishes frequency bias settings that establish values closer to actual Balancing Authority frequency response, and encourages coordinated automatic generation control (AGC) operation.
The commission said it will require NERC to submit an analysis of the availability of frequency response resources during the first year of the rule’s implementation. If Balancing Authorities are unable to meet their obligations, NERC will be required to recommend changes to improve compliance.
The commission also said it will require NERC to revise the standard to address concerns over the withdrawal of primary frequency response before activation of secondary frequency response. The premature withdrawal can lead to under-frequency load shedding and possible cascading outages.
Protection System Maintenance
The proposed PRC standard details required maintenance and maintenance schedules for protection systems and load shedding equipment.
It will supersede four existing standards, PRC-005-1.1b (Transmission and Generation Protection System Maintenance and Testing), PRC-008-0 (Underfrequency Load Shedding Equipment Maintenance), PRC-011-0 (Undervoltage Load Shedding Equipment Maintenance) and PRC-017-0 (Special Protection System Maintenance and Testing).
It was one step forward and one step back for PJM’s offshore wind hopes as federal officials announced the auction of 112,800 acres off Virginia while New Jersey regulators rejected a deal with developers of a proposed Atlantic City wind farm.
VA’s Wind Energy Area (Source: BOEM)
The Interior Department’s Bureau of Ocean Energy Management said yesterday it will conduct an auction Sept. 4 for an area 23.5 nautical miles off Virginia Beach with potential wind generation of more than 2,000 megawatts. The online auction will use an ‘‘ascending clock’’ format in which BOEM sets an asking price and increases it in steps until only one bidder remains.
Eight companies have been prequalified to bid: Apex Virginia Offshore Wind, LLC; Virginia Electric and Power Company (“Dominion Virginia Power”); Energy Management, Inc.; EDF Renewable Development, Inc.; Iberdrola Renewables, Inc.; Sea Breeze Energy, LLC; Orisol Energy U.S., Inc. and Fisherman’s Energy, LLC.
Interior Secretary Sally Jewell said the Virginia lease marks the “transition from planning to action when it comes to capturing” offshore wind’s potential.
Exhibit A is Fishermen’s Energy’s proposed 25 MW pilot project off Atlantic City.
On Friday, the New Jersey Board of Public Utilities voted unanimously to reject a proposed deal between the developer and the Division of Rate Counsel to allow the project to proceed.
In 2010, New Jersey enacted a law committing the state to purchase 1,100 MW of offshore wind by 2020. Ratepayers would subsidize the cost of the above-market energy from the plant through Offshore Renewable Energy Certificates (OREC).
‘Net Benefits’ Test
BPU won’t award ORECs, however, unless it is convinced that a wind farm’s economic and environmental benefits exceed its costs.
The Rate Counsel, which represents ratepayers before the BPU, previously had opposed the Fishermen’s project for failing to meet the “net economic benefit” test. But Rate Counsel dropped its opposition after negotiating reductions in the projected rates from the project.
The board rejected the Rate Counsel’s deal with the developers Friday, saying that a proposed $19 million contingency fund — which would have made ratepayers liable if the project failed to receive $100 million in potential federal grants and tax incentives — violated state law.
“The only way ratepayers …can be at risk of paying for the cost of the project is through the ORECs,” BPU spokesman J. Gregory Reinert told RTO Insider.
Rate Counsel Director Stefanie Brand told RTO Insider she disagrees with BPU’s legal analysis. She said the stipulation reduced the projected ratepayer costs of the project by 40%. “It went from being one of the most expensive offshore wind projects [in the U.S.] to one of the cheapest,” she said.
The board’s action is not the final word on the project. If developers and Rate Counsel cannot reach agreement with the BPU, the case could go to an evidentiary hearing later this year.
