Page 1884 – RTO Insider

July 23, 2013

FERC Proposes Revised Communication, Business Rules

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.

July 23, 2013April 10, 2025

Talk among Yourselves: FERC Urges Gas-Electric Communication

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

July 23, 2013

FERC Rebuffs PSEG on PJM Transmission Modeling

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.

July 23, 2013

FERC OKs Reliability Standard, Proposes Two Others

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).

July 23, 2013

Offshore Wind: Lease Sale Set for VA; Setback for NJ Project

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.

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.

But as RTO Insider pointed out in a June 25 Special Report, the high cost of offshore wind means PJM is unlikely to see any turbines in the water without significant changes in state and federal energy policy. Report (See The Siren Song of Offshore Wind: Cost, Political Obstacles Slow Progress Despite Huge 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.

July 23, 2013

FERC Rule Boosts Storage, Renewables

By Rich Heidorn Jr.

Renewable generators will have more sources of balancing services and electric storage providers will be more competitive in the regulation market under a final rule approved by the Federal Energy Regulatory Commission Thursday.

The commission said the new rule (Order 784, Docket Nos. RM11-24, AD10-13) will improve competition and transparency in ancillary services markets at a time when the growth of wind power and other intermittent sources is increasing the need for imbalance services. The commission said the new rule “enhances the overall opportunities for third-parties to compete to make sales of ancillary services while continuing to limit the exercise of market power.”

The rule requires PJM and other transmission providers to consider speed and accuracy in acquiring regulation resources, removes obstacles to selling such services at market-based rates and creates new accounting categories for tracking investments in electric storage.

The ruling, which takes effect 120 days after publication in the Federal Register, will make it easier for batteries, flywheels and other emerging technologies to compete against slower-responding gas- and coal-fired generators to provide regulation and other services.

In addition, “Because most generation-based ancillary services can be provided by many of the generators connected to the transmission system, some customers may be able to provide or procure such services more economically than the transmission provider can,” the commission said.

The Electricity Storage Association hailed the rule as a “major victory.”

“The effects of this rule are simple – there will be more deployment of technology, stronger investments in projects, and a broader demonstration of the benefits of energy storage to the grid,” Judith Judson, chair of the trade group’s Advocacy Council and director of emerging technologies at Customized Energy Solutions, said in a statement.

FERC Chairman Jon Wellinghoff told reporters in a press briefing the rule is designed to increase “efficiency and opportunity” and is “extremely important” to wind generators, which need imbalance services to compensate for their fluctuations in output.

“Our job isn’t to incent any particular technologies,” Wellinghoff said. “Our job is to ensure that markets are open and transparent and fair to all technologies.”

Impact on Frequency Regulation

FERC’s pro forma OATT requires transmission customers to purchase regulation and frequency response service at cost-based rates from the public utility transmission provider or to “make alternative comparable arrangements” to self-supply the service, either through their own resources or purchases from third-parties.

The new ruling builds on FERC’s 2011 Order 755, which increased the pay for fast responding frequency regulation sources such as batteries and flywheels in PJM and other regions with independent system operators.

The rule requires transmission providers, including those outside of ISO regions, to share with customers their reasoning and any related data used to determine whether the customer has made “alternative comparable arrangements.” To ensure “apples-to-apples” comparison of regulation resources, the rule also requires transmission providers to post on OASIS historical one-minute and ten-minute Area Control Error data for the most recent calendar year, and update this posting annually.

The commission said the changes were needed to prevent transmission providers from requiring customers to purchase more regulation reserves than necessary.

The changes are good news to companies such as Beacon Power, LLC, which says its storage flywheels can respond nearly instantaneously to operator control signals — up to 100 times faster than traditional generators. Beacon cited a recent study for the California Energy Commission which found that a 30-50 MW fast-response storage device could provide as much or more regulation capability than a 100 MW combustion turbine.

Beacon last month announced the beginning of construction on a 20-megawatt flywheel energy storage plant in Hazle Township, Pennsylvania that will compete in PJM’s regulation market. The company expects to put 4 MW into commercial operation in September, with the full 20 MW plant operational in the second quarter of 2014. The company’s 20 MW plant in in Stephentown, New York, competes in NYISO’s regulation market.

Avista Policy Revised

In addition to attempting to level the playing field in the regulation market, the order eliminates barriers to competition for several other ancillary services by revising the commission’s Avista policy.

The Avista policy allowed third-party ancillary service providers to sell regulation and frequency response, energy imbalance service and operating reserves at market-based rates without performing a market power study. The policy was based on preventing market power through the “backstop” of cost-based ancillary services from transmission providers; thus market-based sales to PJM and other regional transmission organizations and independent system operators which have no ability to self-supply were prohibited.

The commission said it now concludes that the Avista rule created unreasonable barriers to entry by potential suppliers. The new order allows resources with market-based rate authority for sales of energy and capacity to sell the following ancillary services at market-based rates:

Energy imbalance service: Can sell at market-based rates to transmission providers with intra-hour scheduling (Paragraph 31 of the order). Transmission providers are required by Order 764 to offer intra-hour scheduling by Nov. 12, 2013.

Operating Reserve – Spinning Reserve and Supplemental Reserve services: Can sell at market-based rates to transmission providers with intra-hour scheduling that supports delivery of operating reserves from one Balancing Authority to another. (P 54)

Reactive supply and voltage control: The commission said it could not allow such market-based sales of regulation and frequency response service and reactive supply and voltage control, however, because the resources capable of providing those services are more limited than those supplying energy and capacity, leaving those markets more at risk to market power. The commission said it will continue to study ways to further open these markets to competition in a new proceeding. (P 55)

Competitive solicitations

In the meantime, the commission said sales of such services can be made at or below the transmission provider’s OATT rate, or at market-based rates resulting from a competitive solicitation. (P 13)

Such solicitations must be transparent (“open and fair”) and competitive (“adequate seller interest”), with precise definitions of the products sought. (P 95) The solicitation will be subject to an independent third-party review if the buyer solicits offers from one or more of its affiliates. (P 100)

Accounting Rules for Energy Storage

The third major component of the new rule was FERC’s addition of new electric plant and operation and maintenance expense accounts for energy storage devices.

The commission said the new accounts will help state and federal regulators ensure that utilities don’t obtain excessive rate recovery by seeking reimbursements under both cost-based and market-based rates for a single energy storage asset.

July 16, 2013

PJM to Invite Market Efficiency Transmission Projects

PJM expects to open a proposal window for market efficiency transmission projects later this year, PJM officials told members last week.

Steve Herling, PJM vice president of planning, said the window would allow transmission developers to propose cost-saving solutions to congestion issues identified by PJM staff. PJM officials said the window would be opened after PJM staff completes its analysis of public policy transmission needs.

“We may not open a window for another month and a half,” Herling told the Transmission Expansion Advisory Committee. “That doesn’t mean you can’t start working now.”

In an earlier meeting with the Planning Committee, Herling said that the window “will be less focused than” that opened earlier this year to address stability problems at Artificial Island in New Jersey. (See related article.)

Location of High Voltage Problems Identified by PJM (Source: PJM Interconnection, LLC; p. 11, RTEP Reliability Analysis, TEAC 7-10-13)

In 2012, PJM identified $718.6 million in gross congestion, $347 million of which was unhedgeable, a reduction from the $998 million in market congestion for 2011. (See Table.)

Fifteen monitored facilities were responsible for at least $10 million each in gross congestion, led by APSOUTH with $126 million of gross congestion, almost one-fifth of the total.

Proposals must meet or exceed a 1.25 benefit-to-cost threshold to be considered by the Board of Managers for inclusion in the Regional Transmission Expansion Plan.

The Market Efficiency case files are available to those with a Ventyx database license and clearance to view Critical Energy Infrastructure Information (CEII).

In a related matter, Herling said PJM has completed its review of applications from most of the 12 companies that sought prequalification as transmission developers under FERC Order 1000, which reduced transmission owners’ historic Rights of First Refusal and opened transmission projects to competition. PJM will post the results of its reviews within two weeks, Herling said.

July 16, 2013

Manual Changes: Manual 1, 12, 21, 28

The Operating Committee last week approved changes to manuals 1 and 12, while the Planning Committee received a presentation on proposed changes to Manual 21 and the Market Implementation Committee heard a first reading on changes to Manual 28.

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.

Next Step: Vote by Markets and Reliability Committee.

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).

Next Step: Vote by Markets and Reliability Committee.

PJM contact: Rus Ogborn

Manual 21: Rules and Procedures for Determination of Generating Capability

Reason for change: Clarifying ambiguous language, updating terms.

Impacts:

Clarifies that intermittent resources (wind, solar) are not required to perform seasonal verification tests because their capacity credit calculation is used in place of a ratings test.
Clarifies that all generators, except hydro, pumped storage and diesel units, are required to adjust rating test results for expected cooling water and ambient air conditions.
Hydro and pumped storage units must perform their annual ratings test during the summer verification window and are not required to perform a winter test.

Next Step: Vote at next Planning Committee meeting.

PJM contact: Tom Falin

Manual 28: Operating Agreement Accounting

Reason for change: Incorporating changes to lost opportunity cost compensation as approved by FERC.

Impacts:

Changes sections 5.2.6 and 5.2.8 (Operating Reserve & Reactive Services Lost Opportunity Cost Credits) to limit lost opportunity cost compensation to the lesser of a unit’s economic maximum or maximum facility output as approved in FERC Docket ER13-1200.
Section 7.2 (Shortage Pricing) amended to incorporate calculation details for non-synchronized reserve market lost opportunity costs.
Modifies section 5.3 (Operating Reserve) to correct errors and provide clarifications on exempting deviations during shortage conditions and revisions for associating interfaces to the East or West BOR regions.
Modifies sections: 5.2.3 to incorporate details of Lost Opportunity Cost Credit for Synchronous Condensing; 5.2.6 (Wind Lost Opportunity Cost) to align language with Tariff; 17.3 (Allocation of Annual and Monthly FTR Auction Revenues) to correct section reference.

Next Step: Vote at next MIC meeting.

PJM contact: Suzanne Coyne

July 16, 2013

Reliability Projects in 2013 RTEP Likely to Exceed $1B

PJM transmission planners have identified more than $800 million in reliability upgrades for inclusion in the Regional Transmission Expansion Plan (RTEP), officials told members last week. Costs are likely to exceed $1 billion once all projects are tallied.

The upgrades, outlined to the Transmission Expansion Advisory Committee Thursday, include 26 projects to address high voltage problems, 10 to fix load deliverability problems and four areas with short circuit problems.

Short Circuit Upgrades

The biggest single reliability project is likely to be one addressing the short circuit problem in the PSE&G transmission zone outside New York City.

The 2012 PJM RTEP identified several buses in the PSEG zone where the fault currents exceed 80 kA. Potential solutions include upgrading stations to 90 kA and installing current limiting reactors.

Another possible solution being reviewed by PJM is to isolate the Hudson 230 kV from the 138 kV at Marion and 345 kV at Farragut. The 138 kV buses and transmission facilities on the path from Linden to Bergen would be converted to double circuit 230 kV or 345 kV lines. The 345 kV proposal is estimated to cost $1.1 billion but eliminates the need for $588 million of approved RTEP projects, resulting in a net cost of $515 million.

Also under consideration is a proposal to build parallel 700 MW high voltage DC converter stations, estimated at $800 million to $1.1 billion.

One member said PJM should open a proposal window to solve the issue. But PJM officials said they were unlikely to do so — meaning PSEG would have the right to construct the solution — because of the urgency of the problem.

“We will be hard pressed to get any solution by 2015,” said Paul McGlynn, general manager of system planning. “It doesn’t really lend itself to a proposal window.”

“The board has been concerned that this [problem] has been hanging on for quite a while,” added Steve Herling, PJM vice president for planning.

PJM staff is refining its cost analyses and performing additional load flow analyses. Any solution will have to accommodate PJM’s contract with NYISO for the so-called Consolidated Edison “wheel.” The wheel funnels 1000 MW from NYISO through PSEG and into New York City.

In addition to the PSEG short circuit project planners also identified “overstressed” circuit breakers in the Duke Energy Ohio and Kentucky (cost to be determined), Duquesne Light (cost TBD) and Jersey Central Power and Light Co. transmission areas (estimated cost $360,000).

High Voltage

PSEG also figures prominently in upgrades to fix high voltage problems, with 13 projects with a total cost of $122 million. AEP had five projects totaling $17 million while AEC had two projects totaling almost $30 million. PEPCO, PPL, Jersey Central Power and Light, Allegheny Power System and PECO had upgrades ranging from $16 million to $4 million.

PJM’s Board of Managers will be asked to approve the high voltage projects in October, PJM officials said.

Load Deliverability

Twenty-five of 27 Locational Deliverability Areas (LDAs) passed the load deliverability test with no thermal or voltage issues while voltage violations were identified in the Penelec transmission zone resulting from the Penelec and Western MAAC load deliverability tests.

Planners identified 10 projects to solve the problems. One in PPL is estimated at $84.5 million and another in Atlantic City Electric Co. at $11.2 million. Costs of the remaining projects, one in Delmarva Power and Light and seven in PEPCO, have not been estimated.

July 16, 2013

PJM OASIS Adds Temporary Transmission Ratings Info

Responding to marketers’ requests, PJM has begun posting temporary ratings changes from all transmission owners on its OASIS System Information page.

PJM spokeswoman Paula DuPont-Kidd said the RTO began posting the information in response to frequent requests from members. PJM decided to make the information publically available because releasing it to individual companies would provide them a competitive advantage. “It’s mostly for marketers who use it for the day ahead and real-time markets,” she said.

Temporary rating changes are made throughout the day, most of them resulting from system conditions and having operational impacts. The expanded information included details to indicate the provisional status of requests. A list of reasons for ratings changes also was posted.

Beginning July 31, the postings will be updated at 11 a.m. and 1 p.m. daily.

PJM contact: Michael Zhang, PJM Operations Support