MRC / MC Approvals

The following issues were approved by the Markets and Reliability and Members committees Thursday with little discussion. Each item is listed by agenda number, followed by a summary of the issue and links to prior coverage in RTO Insider.

Markets and Reliability Committee

2. PJM MANUALS

Members endorsed manual changes implementing PJM’s revised black start procedures (see FERC Docket ER13-1911). The changes affect M27 Section 7 and M12 Section 4.6.
Members endorsed changes to Manual 01: Control Center and Data Exchange Requirements to incorporate updated telemetry and EOP requirements.

3. COORDINATED TRANSACTION SCHEDULING

Members approved a new scheduling product intended to reduce uneconomic power flows between PJM and NYISO.

The Market Implementation Committee on Sept. 11 approved the Coordinated Transaction Scheduling product after amending it to address member concerns about the reliability of PJM’s price projection algorithm — on which CTS trades will be based.

The revised proposal would allow CTS to begin no sooner than September 2014 — later if MRC is not satisfied with the accuracy of the forecasts generated by PJM’s Intermediate Term Security Constrained Economic Dispatch (IT SCED) application.

See New NYISO Product OKd

4. SYNCHRONIZED RESERVE (SR) PERFORMANCE

MRC approved increased penalties for under-performing Tier 2 synchronized reserve providers.

The committee approved a proposal introduced by Dave Pratzon, of GT Power Group, (Package B) after the Operating Committee selected it over a proposal from PJM and the Market Monitor (Package A).

Pratzon said his proposal was tougher than the current penalty but less severe than the PJM-Market Monitor proposal, which he called overly punitive.

The proposal was approved 3.6 to 1.4.

See OC Hears New Proposal on Synchronized Reserve Penalty; Delays Vote

5. CAPACITY CREDIT CALCULATION FOR WIND RESOURCES

Members approved new rules to protect wind generators from being assigned artificially depressed capacity values due to curtailments ordered by PJM.

Under current policy, when wind generators are curtailed by PJM for any portion of a peak summer hour (2-6 p.m.), the entire hour is excluded from the generator’s capacity calculation.

The MRC selected Alternative 2 under which state estimator data would be used to interpolate output for each five-minute period with curtailments.

See MRC Considers Changes to Wind Capacity Calculations

6. EFFICIENCY OF DEMAND RESPONSE REGISTRATION PROCESS

Members approved two proposals to streamline the demand response registration process.

Current rules require curtailment service providers to submit customer names to both the electric distribution company and load serving entity.

The MRC approved the following changes:

Emergency Registration: The LSE will be removed from the review and notification process; EDCs will continue to do reviews under “Relevant Electric Retail Regulatory Authority” rules.
Economic Registration: The LSE will remain involved but PJM will make administrative changes to simplify the review process. The EDC and LSE review process will be separated to eliminate unnecessary reviews.

The changes are motivated in part by FERC Order 745, which reduced the LSE’s role in the registration process.

See Simplified Demand Response Registration OKd

7. ENERGY MARKET UP-LIFT SENIOR TASK FORCE (EMUSTF) CHARTER

Members approved the charter for the Energy Market Uplift Senior Task Force (EMUSTF). The MRC approved the creation of the task force in May to take a broad review of its method of providing Operating Reserve payments.

PJM said the changes were needed to reduce growing uplift costs resulting from Operating Reserves, “make whole” payments that ensure generators dispatched out of merit for system reliability don’t operate at a loss.

See PJM Proposes Operating Reserve Changes to Cut Uplift

Members Committee

3. CETL STABILITY– EASILY RESOLVED CONSTRAINTS

Constraints that can be quickly and cheaply resolved would be included in the Regional Transmission Expansion Plan (RTEP) under a proposal approved by the MC.

The new rules require PJM staff to identify — before posting the planning parameters for each Base Residual Auction — Locational Deliverability Areas in which the Capacity Emergency Transfer Limit is less than 1.15 times the Capacity Emergency Transfer Objective.

Upgrades that raise the ratio above 1.15 would be added to the RTEP if they cost less than $5 million and can be completed within 36 months or prior to June 1 of the Delivery Year. Projects that duplicate upgrades whose cost is already assigned to an interconnection customer would be excluded.

See Quick-Fix Transmission Upgrades OKd

4. PARAMETER LIMITED SCHEDULES (PLS) REVISIONS

PJM will add new processes for generators seeking exemptions from operating parameters under Tariff changes endorsed by the MC.

The parameters are defaults for different types and sizes of generators, covering minimum run and down times, maximum daily and weekly starts and turn down ratios (Eco Max/Eco Min). They were initiated in 2008 to ensure lower make whole payments for generators whose entire offers were not covered by Locational Marginal Pricing revenues.

See: MRC Actions

October 1, 2013

Bid to Relax Switching Rules Falls Short

A proposal to allow intra-year switching to nodal pricing failed at the Members Committee Thursday, falling just short of the two-thirds vote needed for approval.

The proposal by retail marketer Direct Energy, which would have allowed a limited number of such switches monthly, was opposed by members who said it would create administrative problems for electric distribution companies (EDCs) and potential losses for Financial Transmission Rights holders. The sector-weighted vote was 3.3 in favor and 1.7 against, short of the 3.34 total needed for passage.

It was the second loss for Direct Energy, which failed to win more than 35% support for its bid at the Market Implementation Committee (MIC) in August. (See TOs Flex Muscles, Reject Retailer’s Nodal Pricing Bid)

David Scarpignato, head of PJM regulatory affairs for Direct Energy, said the changes would allow retail marketers to offer more innovative products. He said it would not have significant impact on EDCs or other market participants because it would cap switches at to 5% of the EDC network service peak load.

The Members Committee in 2005 unanimously endorsed a Tariff change allowing the switch to nodal pricing. But after more than seven years under the new rules, all but 15% of PJM load is still using zonal pricing.

The rules give customers one chance a year to switch to nodal pricing, effective June 1 in alignment with the planning year. Customers must provide notice of their intention to switch by October or January depending on type of service.

Scarpignato said the annual window for switching has limited retail marketers’ ability to provide innovative products such as price responsive demand, which he said is most attractive to those with nodal pricing.

The current rules mean it can take a customer up to 17 months to make the switch after deciding to do so — “major barrier” to adoption, Scarpignato said.

Scarpignato said the change would also help reduce congestion costs across PJM and assist PJM operations, which has said it would like more “granular” dispatch of demand response resources. Under the current zonal dispatch, Scarpignato said, “some of the DR in that zone is actually hurting” PJM’s attempts to relieve constraints.

Scarpignato’s argument won support from representatives for Old Dominion Electric Cooperative and Dominion, as well as from Howard Haas of Monitoring Analytics, PJM’s independent Market Monitor. “Nodal pricing is the way to go,” Haas said. “Unequivocally it is the way to go.”

Representatives from Exelon Corp. and Pepco Holdings spoke in opposition.

Jason Barker, of Exelon, said his company saw little “utility” to allowing intra-year switching and significant financial risk to the remaining zonal customers, who could see their costs increase.

“As the operator of three EDCs we do see substantial downside,” he said. “We’re disappointed that it’s come before the Members Committee after being roundly defeated at the MIC.”

Gloria Godson, of Pepco, said the change would be a “significant burden” on EDCs. “We will have to add additional staff to manage this.”

Scarpignato said the intra-year switches would have minimal financial impact on FTR holders and others in the zone. He said new customers connect to the grid year-round without major impacts.

In answer to a question from Godson, PJM’s Tom Zadlo said the change could impact FTRS. “It is potentially possible that there are some impacts on FTRs but it’s impossible to quantify.” The impact would depend on the size of the loads that switched, he said.

Marji Philips, representing Hess Corp., said economists’ preference for nodal pricing is similar to their support for energy–only markets in lieu of a capacity market. “It’s good in theory. As a practical reality it stinks.”

Philips said that PJM’s hedging tools are based on zones and hubs. If many customers switch to nodal pricing in mid-year, she said, it could create “ghettos” where customers will have to pay more of a risk premium because suppliers can’t hedge their loads.

Fourteen of 16 public power members voting supported the change along with three-quarters of 20 other suppliers and all eight end use customers. Transmission companies voted 7-2 against while generation owners split 5-5.

Scarpignato said after the meeting that his company was not giving up. “It was an extremely close vote,” he said. “We’re considering our options.”

October 1, 2013

Company Briefs

The volume of data generated by the smart grid threatens to drown utilities, who have yet to figure out what to do with the information or how to store it, according to industry experts. “It’s generating terabytes of data,” said a representative of the Electric Power Research Institute at a panel discussion at the Illinois Institute of Technology.

More: Forbes

PPL to Sell Montana Hydro Plants

NorthWestern Energy will buy 11 hydroelectric plants from PPL Montana – the same power-producing dams that NorthWestern’s predecessor, Montana Power Co., sold in the wake of deregulation almost 15 years ago. NorthWestern said it agreed to buy the 11 dams along five separate Montana rivers for $900 million, subject to approval by state and federal regulators.

More: Missoulian

FirstEnergy Slates Major Work at PA, OH Nuclear Plants

FirstEnergy Corp. plans to spend several hundred million dollars to replace the steam generator and reactor vessel head at its Beaver Valley Unit 2 reactor, in Pennsylvania, in 2017. It also plans to replace the two steam generators at its Davis-Besse plant in Ohio in February during a longer-than-normal refueling outage.

More: Pittsburgh Post-Gazette

Barbas Joins Pepco Board

Pepco Holdings Inc. named former Dayton Power and Light Co. CEO Paul M. Barbas to its board of directors. Barbas is also a former chief operating officer of Chesapeake Utilities Corp. and executive vice president of Allegheny Power.

More: Pepco Holdings Inc.

October 1, 2013

PJM to Consider Storage as Capacity

Members agreed Thursday to consider new rules to allow batteries, flywheels and other advanced storage technologies to bid in the capacity market.

The Market and Reliability Committee approved a problem statement and issue charge with only two no votes despite some wariness from some members.

The proposal was sponsored by Demansys Energy LLC, which aggregates commercial and industrial customers for participation in the regulation market.

Janette Kessler Dudley, vice president of business development and regulatory affairs, noted that PJM currently has no rules allowing batteries or other advanced storage resources to participate in the Reliability Pricing Model. “What my company is interested in is parity,” she said.

Steve Lieberman, of Old Dominion Electric Cooperative, said he was not convinced storage is compatible with other capacity resources.

He said the issue should receive a lower priority than those currently before the Capacity Senior Task Force. “We should proceed carefully as far as expectations go,” he said.

Members ultimately decided the move the issue from the CSTF to the Planning Committee.

Gloria Godson, of Pepco, said she supported the inquiry but that PJM shouldn’t approve new rules until it fully understands the technologies. She noted the amount of “retooling” the RTO has done to address problems with the integration of demand response.

Raghu Sudhakara, of Rockland Electric Co., noted that NYISO already allows four hour resources to participate in its capacity market. “There’s no reason PJM, being as sophisticated as it is, can’t accommodate new technologies,” he said.

PJM currently has about 56 MW of non-pump storage.

See Energy Storage: Ready for its Close-Up?

October 1, 2013

Current Capacity Imports OK: Study

PJM should be able to absorb the more than 7,400 MW of imports that cleared in May’s capacity auction for 2016-17, officials told a special meeting of the Planning Committee Friday.

Officials said that their initial review found PJM can import 11,000 to 12,000 MW. “We may have gotten close to what our limit would be, but we haven’t gotten to it yet,” said Stu Bresler, PJM vice president of market operations.

Officials cautioned that their results were preliminary and subject to change with further analysis.

Friday’s meeting was prompted by a problem statement approved by the Planning Committee Sept. 12.

The committee will seek to adopt a methodology for determining an RTO import limit that can be applied in the PJM planning process as well as included in next year’s Base Residual Auction. “It would function much like a CETL (Capacity Emergency Transfer Limit) for the entire RTO,” Bresler told the Markets and Reliability Committee in a brief discussion Thursday.

In addition to ensuring space for capacity, PJM must account for long term transmission contracts and 3,500 MW for the RTO’s Capacity Benefit Margin, which is reserved for importing capacity from external areas in emergencies.

Officials said their initial review identified a 500/230 kV transformer in the Duke Energy Carolinas zone as the limiting facility.

Bresler said PJM likely will propose a combination of path-specific limits with an overall RTO import cap. “The sum of the path-by-path limits could exceed what an overall limit would be,” he said.

Officials were unable to say Friday how much of the RTO’s total import capacity is to PJM’s west, the source of most of the imports that cleared in the May auction.

October 1, 2013

Bowring: UTCs Boost FTR Shortfalls

Market Monitor Joseph Bowring last week released an analysis that he said proves his contention that up-to congestion (UTC) transactions are increasing shortfalls in Financial Transmission Rights funding.

Day-Ahead Congestion & Binding Constraints (Source: Monitoring Analytics LLC)

“There’s no reason to believe up-to congestion transactions help price convergence,” Bowring said in presenting his monthly report to the Members Committee webinar. “But they do increase day-ahead congestion.”

The monitor’s analysis was based on a simulation of market results with and without UTC bids for a five-day sample in May.

The analysis found that UTCs affect unit commitment and dispatch in the day-ahead market, increasing the number of binding constraints and negative balancing congestion.

For the five days examined, the FTR funding deficit was $4.4 million with UTCs versus a surplus of $22,000 with UTCs removed — a difference of $4.6 million.

In its 2012 State of the Market report, the monitor called for eliminating UTC transactions or making them responsible for day-ahead and balancing operating reserve charges.

The monitor said the RTO deviation rate for 2012 would have been reduced by 59% percent if UTC transactions had been included in the calculation of operating reserve charges.

The average cleared volume of UTC trades increased 73% between 2011 and 2012.

September 24, 2013

Frequency Regulation: The `Wedge’ for Energy Storage

A 2010 white paper by the Electric Power Research Institute (EPRI) identified 10 applications for energy storage across the entire electricity supply chain, including end-users. Below are some of the most promising:

Frequency Response: While large scale use is a long term ambition for storage, “frequency response is the wedge into actual utility application in the field,” says Imre Gyuk, manager of the Department of Energy’s energy storage research program. Storage can provide much quicker performance than fossil fuel plants, which can take five minutes to respond. “In these five minutes the need may already be in the opposite direction,” Gyuk noted. Beacon Power, for example, says its 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 as a 100 MW combustion turbine.
Back-up Power: Researchers see large end users purchasing storage for backup power during grid interruptions. EPRI reports that diesel generators have a failure rate of more than 20%. A White House report released in August recommended that energy storage systems be a top priority for new investments to modernize the grid and improve reliability.
Support for Intermittent Resources: Wind power produces only 10% of nameplate capacity in peak hours. “That alone is practically a mandate for storage,” said Gyuk. A 2010 study estimated a need of 0.8 to 1.5 MW of intra-hour balancing for every 10 MW of wind.
Delaying Transmission and Distribution Upgrades: Storage can provide alternatives to grid upgrades in locations with slow load growth and infrequent maximum load days. These benefits could range from $150,000 – $1,000,000/MW-year, according to EPRI.

September 24, 2013

EPA GHG Rule May Turn on Viability of Carbon Capture

Analysis

By Rich Heidorn Jr.

Gina McCarthy at the National Press Club

WASHINGTON — The coal industry has been advertising the notion of “Clean Coal” for years. Now that the EPA has issued rules limiting carbon emissions from new coal generators, however, the industry says “Clean Coal” is neither feasible nor economical.

And they’re right.

In announcing the new greenhouse gas rules at the National Press Club here Friday, EPA Administrator Gina McCarthy was effusive in her enthusiasm for carbon capture and sequestration (CCS) — the technology coal will need to build new plants.

“It’s been demonstrated to be effective,” McCarthy said. “It’s being constructed on real facilities today.”

That’s true. But McCarthy will be long gone from EPA by the time CCS becomes inexpensive enough to make coal a viable alternative to natural gas. And it may never happen.

This matters. The Clean Air Act requires the EPA base its pollution standards on the “best system of emission reduction” with technology that has been “adequately demonstrated.”

How those terms are decided will determine whether the GHG rules survive the certain court challenge to come.

EPA’s proposal limits new large natural gas-fired turbines to 1,000 pounds of CO₂ per MWh, easily achievable with current technology. New coal-fired units would need to meet a limit of 1,100 pounds per MWh, far below the emission levels of the most efficient coal plants without CCS, which range from 1,700 to 1,900 lbs./MWh.

The American Public Power Association, which represents 2,000 not-for-profit electric utilities, said EPA’s identification of CCS as the technology required for new coal generation is “unrealistic” and does not comply with the New Source Performance Standard (NSPS) requirements under the Clean Air Act.

The group said neither of the two CCS demonstration projects cited by EPA — Plant Ratcliffe in Kemper County, Miss., and the SaskPower plant in Canada — has demonstrated the commercially viability of the technology.

Both sites plan to inject CO₂into nearby oil fields, and both received government subsidies. “For a project to become commercially viable, it must be financed on its own and given the high risk of financing such unproven technology, it is extremely unclear where the funding would come from,” the group said in a statement.

A recently-released report funded by the Department of Energy concluded that, even if CCS becomes economical, the higher capital costs of coal generators means CCS “may be first deployed on natural gas plants before coal-fired plants, if natural gas prices remain low.”

“… Incentives to support coal mining and encourage the use of coal face an uphill battle in contending with these challenges,” the report said. (See DOE Study: Carbon Capture No Salvation for Coal )

Joseph Stanko, head of government relations for law firm Hunton & Williams, said the standard should be overturned by the appellate courts because EPA’s reliance on the two projects “doesn’t ‘adequately demonstrate’ technology for normal use.”

“NASA sent men to the moon with federal funds,” he told The Washington Post. “That doesn’t mean municipalities and companies can do it.”

McCarthy insisted in Friday’s briefing that the rule was “clearly not” an effective ban on new coal plants. “CCS is a technology that is feasible and it’s available today,” she insisted. “I believe this proposal sets out a certain path forward … Over time, you’ll be able to see there’s a reasonable, cost-effective strategy to keep coal in the energy mix.”

September 24, 2013

MC MRC Preview

Below is a summary of the issues scheduled to be brought to a vote at the Markets and Reliability and Members committees 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.

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 (9:10-9:20)

A. Members will be asked to endorse manual changes implementing PJM’s revised black start procedures (see FERC Docket ER13-1911). The changes affect M27 Section 7 and M12 Section 4.6.

B. Members will be asked to endorse changes to Manual 01: Control Center and Data Exchange Requirements to incorporate updated telemetry and EOP requirements.

3. COORDINATED TRANSACTION SCHEDULING (9:20-9:50)

Members will be asked to approve a new scheduling product intended to reduce uneconomic power flows between PJM and NYISO.

See New NYISO Product OKd

4. SYNCHRONIZED RESERVE (SR) PERFORMANCE (9:50-10:20)

MRC will be asked to approve increased penalties for under-performing Tier 2 synchronized reserve providers.

At a special Operating Committee meeting yesterday, members rejected a proposal from PJM and the Market Monitor (Package A) in favor of one introduced by Dave Pratzon, of GT Power Group, who represents generation owners (Package B).

Pratzon said his proposal was tougher than the current penalty but less severe than the PJM-Market Monitor proposal, which he called overly punitive.

The current penalty is to take away revenue for the hour when the resource did not perform and also require the resource to provide Tier 2 reserves without compensation when needed for three days. If a resource fails to perform in one hour it doesn’t affect its credit for performing in another hour during the same day.

Because Tier 2 SR calls have declined to about once every 10 days from one in every three days, the three-day penalty has lost its bite.

The proposal to be considered by the MRC Thursday removes the “contiguous” hours statement from the same-day penalty and creates a retroactive obligation to refund the shortfall for all of the hours the resource was assigned over the immediate past interval (i.e., 10 days currently). It also increases the penalty by eliminating the conversion of shortfall MW to MWh.

Package B was supported by almost three-quarters of those voting yesterday, with heavy backing from generator representatives. Package A won only 18% support. Package C, which would have added a 25% additional penalty to Pratzon’s proposal, won less than 27% support.

See OC Hears New Proposal on Synchronized Reserve Penalty; Delays Vote

5. CAPACITY CREDIT CALCULATION FOR WIND RESOURCES (10:20-10:45)

Members will be asked to choose one of two alternatives to protect wind generators from being assigned artificially depressed capacity values due to curtailments ordered by PJM.

Under current policy, when wind generators are curtailed by PJM for any portion of a peak summer hour (2-6 p.m.), the entire hour is excluded from the generator’s capacity calculation.

The Planning Committee last month recommended a proposal (Alternative 2) under which state estimator data would be used to interpolate output for each five-minute period with curtailments. MRC also may consider a second option (Alternative 3), which was approved more narrowly by the PC. It would substitute forecast data from PJM operations — which is currently used for lost opportunity cost calculations — for curtailment periods.

See MRC Considers Changes to Wind Capacity Calculations

6. EFFICIENCY OF DEMAND RESPONSE REGISTRATION PROCESS (10:45-11:00)

Members will vote on two proposals approved this month by the Market Implementation Committee to streamline the demand response registration process.

Current rules require curtailment service providers to submit customer names to both the electric distribution company and load serving entity.

The MIC approved the following changes:

Emergency Registration: The LSE will be removed from the review and notification process; EDCs will continue to do reviews under “Relevant Electric Retail Regulatory Authority” rules.
Economic Registration: The LSE will remain involved but PJM will make administrative changes to simplify the review process. The EDC and LSE review process will be separated to eliminate unnecessary reviews.

The changes are motivated in part by FERC Order 745, which reduced the LSE’s role in the registration process.

See Simplified Demand Response Registration OKd

7. ENERGY MARKET UP-LIFT SENIOR TASK FORCE (EMUSTF) Charter (11:00-11:10)

Members will be asked to approve the charter for the Energy Market Uplift Senior Task Force (EMUSTF). The MRC approved the creation of the task force in May to take a broad review of its method of providing Operating Reserve payments.

See PJM Proposes Operating Reserve Changes to Cut Uplift

8. ENERGY STORAGE RESOURCES (11:10-11:25)

Members will be asked to approve a proposed problem statement allowing batteries, flywheels and other advanced energy storage technologies to participate in its capacity market.

See Energy Storage: Ready for its Close-up? p. 1; Energy Storage Vies for Capacity Role

Members Committee

3. CETL STABILITY– EASILY RESOLVED CONSTRAINTS (1:25-1:45)

Constraints that can be quickly and cheaply resolved would be included in the Regional Transmission Expansion Plan (RTEP) under a proposal the MC will be asked to endorse. The proposal was approved by the MRC in August.

See Quick-Fix Transmission Upgrades OKd

4. PARAMETER LIMITED SCHEDULES (PLS) REVISIONS (1:45-10:00)

PJM will add new processes for generators seeking exemptions from operating parameters under Tariff changes the MC will be asked to endorse.

See: MRC Actions

5. NODAL SETTLEMENTS (2:00-2:20)

Retail marketer Direct Energy will attempt to win Members Committee approval for Tariff revisions that would allow network load customers more frequent opportunities to switch to nodal pricing.

The Market Implementation Committee in August rejected the company’s proposals after utility representatives said the changes would create administrative problems for their electric distribution companies (EDCs).

The company said the changes would allow retail marketers to offer more innovative products but would not have significant impact on EDCs or other market participants because it would cap switches at 5% of the EDC network service peak load.

See TOs Flex Muscles, Reject Retailer’s Nodal Pricing Bid

September 24, 2013

Big To-Do List from September Heat Wave

More conservative reserve calculations, quicker and more granular demand response and optimizing trades with neighboring regions: These are some of the changes PJM is considering in the wake of September’s unexpected heat wave, officials told the Members Committee webinar yesterday.

PJM gave a detailed presentation on the events of Sept. 9-11, when PJM was forced to shed load during unseasonably high temperatures at a time when large numbers of transmission and generation resources were out of service for planned maintenance.

The September events added urgency to concerns that arose after the heat wave of mid-July (see Focus on AEP Transformer, Prices in Heat Wave Review) as well as adding some new ones.

Yesterday’s briefing lasted about two hours, and the lessons learned will likely consume many more hours of stakeholder meetings.

Seeking a Nimbler DR

Stu Bresler, PJM vice president of market operations, told the committee that the September episode illustrated the need to give operators the ability to make quicker and more targeted use of demand response.

The Capacity Senior Task Force, which is meeting today, is considering reducing DR’s minimum lead and run times. Also under discussion will be changes to rules limiting operators’ ability to target DR calls geographically.

Almost 6,000 MW of demand response was dispatched on Sept. 11 — an all-time record that underscored its increasing importance to the RTO. “We’re going to have to get used to DR as an operational tool being used outside of the June-July-August period,” Bresler said.

Conservative Reserve Estimates

The CSTF isn’t the only stakeholder group that will be discussing the fallout from the heat spike. The Operating Committee will be discussing improving generator data to more accurately calculate reserve quantities after a poor synchronized reserve response led to an unusually long spinning event Sept. 10.

Adam Keech, director of wholesale market operations, said operators will likely be using “more conservative” RTO reserve calculations in the future.

The newly-formed Energy Market Uplift Senior Task Force will be discussing changes to rules allowing emergency DR to set prices, as it did in some areas during both the July and September events.

Officials are having second thoughts about the price cap on demand response — now effectively $1,800 per MWh but scheduled to increase to $2,700. “Are we comfortable with $2,700?” asked PJM’s Becky Carroll.

In addition, PJM may seek to create a product to reduce interchange volatility along its seam with MISO similar to the Coordinated Transaction Scheduling product with NYISO. Members will vote on CTS Thursday (see MRC/MC Preview).

Load Sheds Hit 44,000

In addition to the presentation, PJM yesterday also released a 21-page report providing officials’ preliminary analysis of the events of Sept. 9-11.

PJM cut power to 44,000 customers in southern Michigan, northern Ohio and northwest Pennsylvania Sept. 9 and 10 as temperatures unexpectedly hit the mid-90s and the RTO found itself without enough transmission or generation.

Although the cuts were relatively small — the 154 MW in total load shed was less than 0.1% of Sept. 10’s peak load — the situation could have been far worse.

When a 345/138 kV transformer in AEP’s South Canton area tripped Sept. 9, four 345 kV lines were lost, leading PJM operators to fear it could worsen to a cascading outage.

There were also concerns of a widespread blackout Sept. 10, when a 345 kV line near Erie, Pa., was lost. PJM ordered FirstEnergy to drop 70 MW of load at 17:41. When that did not alleviate concerns, PJM ordered the cut of an additional 35 MW.

Conditions were exacerbated by weather forecasts that missed peak temperatures by up to 5 degrees — leading PJM to under-forecast loads. Balancing congestion, which results when day-ahead loads differ from real-time, totaled $23.1 million in the ATSI zone over Sept. 10 and 11.

The Cavalry Fails to Arrive

Generator Response During 9/10/13 SR Event (Source: PJM Interconnection, LLC) — (Source: PJM Interconnection, LLC)

One major concern was the failure of generating resources to provide Tier 1 synchronized reserves as loads steadily climbed on Sept. 10. When PJM called a spinning event at 15:48, it showed reserves of about 2,000 MW. Yet only 130 MW of additional generation responded within 10 minutes, leading PJM to call on 800 MW from NPCC as the RTO’s area control error (ACE) fell to a deficit of 1,600 MW.

At the peak, synchronized reserve response totaled only 350 MW. The spinning event lasted an unusually long 68 minutes. “The [synchronized reserve] response clearly was not there,” said PJM’s Chris Pilong.

As a result, Pilong said, operators felt they had to dispatch demand response for support the following day. PJM called on a record of almost 6,000 MW of demand response in the AEP, ATSI, Dominion and Duquesne zones on Sept. 11. “The operators didn’t have a lot of confidence in the numbers reported” as reserves, he said.

Operators also declared a Transmission Loading Relief 5 on Sept. 11, cutting 100 MW of firm transactions on the Neptune DC tie to New York.

Next Steps

Officials said they will produce a “Frequently Asked Questions” document in response to members’ inquiries, as they did after the July event. Stu Bresler, Adam Keech, and Dave Anders will be receiving queries.

For More Information: Initial Analysis of Operational Events during the September 2013 Heat Wave