Page 1606 – RTO Insider

November 25, 2014June 15, 2023

NERC Optimistic on Winter Prep as FERC Seeks Assurances on Fuel

By William Opalka

A repeat of last winter’s polar vortex should not imperil the nation’s power system, the North American Electric Reliability Corp. said last week. Lessons learned from last year’s extreme weather and subsequent operational reviews have left the U.S. better prepared compared to early 2014, NERC said in its 2014-2015 Winter Reliability Assessment.

“Last year, the system bent, it twisted, but it didn’t break,” John Moura, NERC’s director of reliability assessments, said in a press briefing Friday. He said various scenario analyses of weather, and fuel resource and plant availability, were run to recreate January’s polar vortex under current operational conditions.

NERC concluded that “all areas appear to have sufficient resources,” he said. Moura noted familiar themes: an increased reliance on natural gas could cause fuel constraints and limit the availability of some plants during cold snaps.

While New England is “at the forefront of concern” for areas with heavy reliance on gas, he said significant progress has been made in addressing that need through ISO-NE’s winter reliability program. (See ISO-NE in Precarious Position for Winter.)

Moura said that coal delivery and supplies have become concerns in the Midwest and elsewhere that require monitoring, but he characterized it as isolated to relatively few plants and a low risk to grid reliability.

New PJM Demand Record

Hints of the coming winter hit PJM Nov. 18 when unseasonably low temperatures pushed the RTO beyond its previous November demand record. The preliminary peak demand was 121,987 MW at 7 p.m. Real-time prices topped $200/MWh throughout much of PJM at 6 p.m., with the Dayton Power and Light zone highest at $287. The previous November record, set in 2013, was 114,699 MW.

New England got some good news last week from the latest National Oceanic and Atmospheric Administration 90-day forecast, which said that slightly higher temperatures than previously forecasted are expected in the region. Chances for slightly drier weather have increased along the Great Lakes and in the Ohio Valley. However, the probability of above-normal levels of precipitation along the eastern seaboard up to southern New England has increased.

FERC Query on RTO Fuel Assurance

Meanwhile, the Federal Energy Regulatory Commission on Nov. 20 ordered RTOs and ISOs to file reports within 90 days on their efforts to ensure generators have adequate fuel (AD13-7, AD14-8).

This topic has been on FERC’s radar since at least 2013 but became more acute after last winter, as natural gas generators faced price spikes and an inability to obtain fuel. The high prices meant dual-fuel capable plants in New York and New England burned unexpectedly large amounts of oil.

November 25, 2014

PJM MRC/MC Briefs

The following items were approved by members Thursday with little discussion or opposition:

Markets and Reliability Committee

Interchange Limits Approved

The MRC approved PJM’s proposal to limit interchange during emergency conditions by acclamation, with five objections. An MRC sector-weighted vote last month on the issue fell just short of a two-thirds approval. (See PJM MRC OKs Change on Reserves; Interchange Limit Falls Short.)

To address concerns raised by PJM’s Independent Market Monitor, the proposal was revised to include language to address hoarding and manipulation of interchange “room.” The rule is intended to prevent markets and operations from being whipsawed by large swings in imports.

In a related matter, the Members Committee approved revisions to Manual 11, Manual 28 and the Tariff concerning energy and reserve pricing.

Gas Unit Commitment Rules OK’d

Members approved changes to gas unit commitment rules, including a provision allowing generators to change their offers to reflect fluctuating fuel prices. Generators will be able to lock in their fuel prices three hours in advance of the operating hour. Officials said the increased flexibility will require software changes that should be complete in January.

The option will be available to resources that did not receive day-ahead commitments and were not picked up in the reliability assessment and commitment (RAC) run. Units with day-ahead commitments and those selected in the RAC run can switch prices after the end of their last committed hour. Units committed in real time will be unable to change their cost schedules until released. (See PJM Members Approve Intraday Updates to Generator Cost Schedules.)

PJM conducted training for system dispatchers yesterday on the changes.

Sampling to be used for Measuring Residential DR

Members approved a proposal allowing PJM to measure the demand response performance of some residential customers through sampling of interval-meter data. The new measurement method will replace outdated studies dating back to 2001.

The change won support of almost 81% of members on a sector-weighted vote. It was approved over opposition by Market Monitor Joe Bowring, who said sampling would not be as accurate as metered data. “We know when generators fail to respond because they are metered,” Bowring said. “The same will not be true here.”

PJM officials said sampling will improve accuracy without the cost of installing one-minute meters on every participating household. PJM’s Shira Horowitz said the new method builds on an “extremely successful” pilot program.

FirstEnergy’s Jim Benchek also opposed the change, saying it was a “carve out” for DR. He also said it was “inappropriate” to continue incorporating DR in the wholesale market in light of the D.C. Circuit Court of Appeals’ EPSA ruling, which concluded that DR in the energy market fell under the jurisdiction of the states and not under the Federal Energy Regulatory Commission’s authority over wholesale markets. (See New Measurement Rules for Residential DR OK’d; FirstEnergy Opposes.)

Seller Credit Eliminated

Members agreed to eliminate the “seller credit” provision from its credit policy, which RTO officials said was no longer needed. The provision was enacted when PJM still used monthly billing, to allow participants with consistent net sell positions some unsecured credit. Due to changes in credit policy and the 2009 switch to weekly billing, the need for seller credit is now addressed by the Reliability Pricing Model seller credit, a larger and less volatile credit, PJM said.

Manual Changes

Manual 3: Transmission Operations — Updates names; clarifies timing for load shed for post-contingency voltage collapse; updates several sections; adds procedures.
Manual 13: Emergency Operations — Clarifies actions taken prior to emergency procedures; adds Min Gen Advisory procedure; updates Cold/Hot Weather Alerts; revises geomagnetic disturbance procedure; condenses and consolidates Attachment A.
Manual 11: Energy & Ancillary Services Market Operations — The change will allow PJM to relieve demand response resources of their regulation and synchronized reserve responsibilities during Load Management Events. The change addresses the inability of DR resources to provide ancillary services and load management simultaneously.
Manual 14B: PJM Regional Transmission Planning Process — Changes made in accordance with North American Electric Reliability Corp. standards PRC-023-3 (Transmission Relay Loadability) and TPL-001-4.
Manual 28: Operating Agreement Accounting — Revised to include Load Reconciliation data in the settlement of emergency load response and emergency energy billing.
Manual 29: Billing — Changes method of reimbursing treatment of underpayments of miscellaneous items and special adjustments to avoid cost shifts. In cases of shortages those parties due payments would be “short paid” on a pro-rata basis. Shortages will not be socialized among all members.
Manual 13: Emergency Operations — Updates the 2015 day-ahead scheduling reserve requirement to 5.93%, down from 6.27% in 2014. The new requirement is based on a load forecast error of 2.15% (up 0.04% from 2014) and a forced outage rate of 3.78% (down 0.38%).

Members Committee

The committee approved:

Operating Agreement (OA) revisions to ease Transmission Owners’ access to generator data feeds.
Updated Installed Reserve Margins and related metrics for 2015/16 through 2018/19 delivery years.
Non-substantive revisions to definitions in the Tariff and OA, aimed at providing alignment of definitions between the documents.

November 25, 2014

Last-Ditch Effort to Break PJM Offer Cap Deadlock Fails

By Suzanne Herel

PJM stakeholders deadlocked for the third time Thursday on changes to the $1,000/MWh energy offer cap, leaving it to the Board of Managers to decide whether to seek Federal Energy Regulatory Commission approval of any changes.

Old Dominion Electric Cooperative’s Ed Tatum withdrew a compromise proposal to raise the cost-based offer cap to $1,800 in the face of opposition from load representatives following a lively Members Committee debate.

Members’ inability to reach consensus means the board would have to make a unilateral Section 206 filing to win FERC approval for any change.

PJM CEO Terry Boston expressed disappointment. “I was hopelessly optimistic that we could get to a [Section] 205 filing,” he said.

“There will be other times” when the cap is exceeded, Boston said. “I really don’t like the idea that we hold in abeyance until we have an emergency. … We don’t want to be in the position that we have to run to FERC and ask for a 24-hour decision.”

In January, FERC granted the RTO’s request for a waiver, allowing make-whole payments for generators with operating costs exceeding $1,000. PJM said the waiver was necessary to allow some gas-fired generators to cover costs above the cap, as spot gas prices spiked as high as $140/MMBtu.

Earlier this month, Calpine Energy Services requested that FERC allow it to recover about $3.3 million it said it spent on expensive gas for two generating units at PJM’s direction and was unable to burn when the RTO cancelled their plants’ dispatches (ER15-376). Calpine’s claim is similar to those filed earlier by Duke Energy, which is seeking $9.8 million for “stranded” gas (EL14-45) and Old Dominion, which is seeking $2.7 million (ER14-2242). (See PJM Backs Duke’s $9.8M ‘Stranded Gas’ Claim.)

In April, PJM members agreed to form a task force to consider changing the cap. The group was unable to reach consensus after nine meetings and has since disbanded.

The proposal presented Thursday resulted from negotiations led by Tatum and Mike Borgatti, of Gabel Associates, who represented generators. It would have allowed cost-based offers between $1,000/MWh and $1,800/MWh to set LMPs. Generation costs above that cap would be recovered through uplift.

Maximum market-based offers would be capped at $1,000 or the cost-based offer.

The majority of members who spoke Thursday strongly opposed the changes. Even those who encouraged the proposal’s passage conceded they supported it only as a better alternative to losing control over the matter to FERC. A 205 filing also would show a cohesiveness among the group, they said.

“This is not a proposal that Old Dominion would have come up with,” Tatum said in making his presentation. But, he said, “I think we’ve gone as far as we can go with this.”

Susan Bruce of the PJM Industrial Customer Coalition said her group opposed the proposal. “There is a lack of evidence of a systemic problem,” she said.

Market Monitor Joe Bowring said fewer than 25 offers breached $1,000 in January. While some of the proposed offers were in the $1,700/MWh range, Bowring said there were no legitimate offers greater than $1,400/ MWh.

Walter Hall, representing the Maryland Public Service Commission, said Tatum’s proposal represented not a “compromise” but a concession to generators’ attempts to profiteer.

“We fear this is a profit-making opportunity [for generators], not a cost-recovery opportunity,” he said. “Why should everyone profit from something of that nature?”

Jim Jablonski of the Public Power Association of New Jersey referred to the Market Monitor’s March 26 report to FERC, which concluded that only $9,118 of $583,774 in additional compensation sought by seven units in three PJM control zones when gas prices peaked in January was legitimate.

And, he said, “that was at the worst of times. I certainly don’t see the justification for above $1,000.”

Carl Johnson, representing the PJM Public Power Coalition, said approving the Tatum-Borgatti proposal would have been preferable to “throwing a jump ball at FERC.”

“It’s not perfect, but it is way better than that outcome,” he said.

J.P. Morgan Ventures Energy’s Bob O’Connell, who had debated Tatum over the issue at the October MC meeting, said he came into Thursday’s forum opposed to the newest proposal. (See Load, Supply Trade Blame over Offer Cap Impasse.)

But, he said, “the deal you see on the table is a deal that can get done. This is not about getting what you want — it’s about not getting what you don’t want.”

November 25, 2014June 15, 2023

PJM: Regional Approach the Cheapest Way to Comply with EPA Carbon Rule

State-by-state compliance with the Environmental Protection Agency’s (EPA’s) proposed carbon emission rule would be almost 30% more expensive than a regional approach, according to preliminary results of PJM analyses.

The analyses included eight scenarios requested by the Organization of PJM States (OPSI) and seven proposed by PJM.

One analysis (PJM scenario 4), which included existing fossil resources and planned resources with interconnection service agreements (ISAs) and facility study agreements (FSAs), estimated a 2020 carbon price of $11/ton under state compliance, compared with $2/ton under a regional approach.

PJM determined the CO₂ emissions prices based on the price differential needed to ensure the RTO’s economic dispatch displaced enough high-emitting generators with lower-emitting generation to reach the emissions targets.

The regional approach sets a single carbon price for all fossil fuel generators in PJM. Under state compliance, each state would have a different carbon price. Indiana and West Virginia would face the highest carbon prices under a state-by-state approach, with prices exceeding $14/ton, while it would cost Maryland and Virginia only about $5/ton.

Under a regional plan, “states have the ability to trade reductions among each other to achieve lower costs of compliance,” explained Chief Economist Paul Sotkiewicz. Sotkiewicz and PJM engineer Muhsin Abdur-Rahman presented the preliminary results of the analyses at the Members Committee webinar last week.

Total compliance costs would near $45 billion in 2020 under the state approach, versus $35 billion using regional compliance.

Mass-to-Rate Conversion

PJM initially did the analyses based on the implied mass-to-rate conversion in the EPA’s June 2 proposed rule. It redid the calculations based on revised guidance the agency provided Nov. 6, which sets a declining mass target over the interim compliance period (2020-2029) and does not credit new renewables and incremental energy efficiency.

Under the revised conversion, most of the scenarios estimated carbon prices of about $5 to $10 per ton in 2020, rising to $20 to $30 per ton in 2029.

One scenario (PJM #8) saw carbon prices starting at about $40/ton in 2020 and rising to almost $60/ton by 2029. The scenario adjusted planned natural gas capacity based on historic commercial probabilities (greater than 70% for projects with ISAs, greater than 50% for those with FSAs), reduced new combined-cycle capacity to not exceed the installed reserve margin target and assumed a 50% increase in gas prices.

The analyses found that a rate-based approach would result in lower LMPs than a mass-based measurement, meaning generators will need to collect more in capacity revenues. There were little or no increases in LMPs for many scenarios.

November 25, 2014June 15, 2023

Impatient FERC Orders Immediate PJM Action on Reactive Power Payments to Retired Plants

The Federal Energy Regulatory Commission won’t wait for PJM stakeholders to develop rules to prevent fleet owners from receiving reactive power payments for retired generators.

FERC last week ordered PJM to revise its Tariff to address the issue within 30 days or show cause why it should not be required to do so (EL15-15).

A frustrated Vince Duane, PJM general counsel, told members Thursday that FERC’s action appeared to be prompted by the “fairly contentious” process that preceded the Markets and Reliability Committee’s approval last month of a problem statement to address the issue. “They’re not prepared to wait for this group to go through those issues,” he said.

The problem statement included language suggested by Public Service Enterprise Group, which complained that the original statement assumed that fleet owners are being overpaid if they failed to file revised cost schedules with FERC after plant retirements. PJM officials said they did not know how much ratepayers might be overpaying. (See PJM Members Seek Fix for Payments to Retired Plants.)

Duane said it was not certain whether PJM will file proposed Tariff revisions within 30 days or seek more time. But he added that the issue was “not going to be addressed through the stakeholder community — at least not exclusively.”

The commission said it was acting because PJM’s Tariff lacks explicit provisions to end reactive power payments for generators that are retired or sold.

FERC said it also had asked its Office of Enforcement “for further examination and inquiry as may be appropriate” for owners that may have received payments for retired units. Any refunds resulting from the order will be dated from when the Nov. 20 order is published in the Federal Register.

The commission cited a filing in which FirstEnergy “asserted that the commission and the PJM Tariff are silent about updates to reactive service revenue requirements when units are deactivated or transferred out of a fleet, but that ‘parties may agree among themselves regarding the allocation of revenues with respect to changes in ownership.’”

FERC also cited the Sept. 24 request of Sunbury Generation to terminate the reactive service tariff for its retired 436-MW coal-fired facility in Snyder County, Pa. FERC noted that Sunbury had closed the plant more than two months before its filing. PJM told the commission it was still paying for reactive power on the retired plants.

The commission Thursday approved Sunbury’s cancellation request and required it to refund any payments received for the period after the plant deactivation (ER14-2936).

November 21, 2014

FERC Approves Exelon-Pepco Merger

By Michael Brooks

The Federal Energy Regulatory Commission yesterday approved Exelon’s proposed $6.8 billion acquisition of Pepco Holdings Inc., dismissing concerns from PJM stakeholders of increased market power, adverse effects on competition and increased rates.

With approvals from FERC and the Virginia State Corporation Commission in hand, Exelon still must win approval from regulators in D.C., Maryland, Delaware and New Jersey. “We did consider all of the issues that came in with respect to … the PJM stakeholder process. We felt it met the tests of [the Federal Power Act] with the effects on rates, the effects on regulation and the effects on competition,” FERC Chairman Cheryl LaFleur said after the commission’s monthly meeting yesterday.

FERC did not place any conditions on its approval of the merger, such as requiring that Exelon stay in PJM, as requested by the Independent Market Monitor, or that the companies not be allowed to recover any merger-related costs through rates, as the Delaware Public Service Commission requested.

FERC noted that Exelon committed to staying in PJM for 10 years after its 2012 merger with Constellation Energy Group as a condition of the Maryland Public Service Commission’s approval of that deal. The commission said it would address market power concerns if and when Exelon left PJM after 2022.

FERC also noted that the companies have committed to hold transmission customers harmless for any merger-related costs for five years after the merger is completed. After that, FERC said, the companies must file a request to recover these costs through rates, at which point “the commission will determine whether applicants have demonstrated offsetting savings to customers served under commission jurisdictional rate schedules such that recovery of merger-related costs would be appropriate.”

In its order approving the deal (EC14-96), FERC largely echoed the two companies’ rebuttals of protests from the Monitor, the Delaware PSC, Southern Maryland Electric Cooperative and other PJM stakeholders. (See Exelon, Pepco Reject Merger Objections.)

In its response to these rebuttals, the Market Monitor had argued in early September that FERC should require from the companies more information and analysis showing how the merger would not adversely affect competition in PJM’s capacity market through their combined demand response resources. It also said the companies did not address vertical market power concerns in their analyses.

FERC disagreed, however, saying that the information provided by the companies was sufficient. It said Pepco’s additional 700 MW of demand resources would be too small to affect competition in PJM’s capacity market, noting that Exelon already controls 26,000 MW of generation, DR and energy efficiency. The commission also pointed to a Sept. 19 filing from the companies in response to the Monitor’s claims, which the commission said “provided additional information regarding the limited ability of Pepco Holdings’ demand response resources to participate in the PJM energy market.”

“While we recognize that the combination of Exelon’s and Pepco Holdings’ capacity market-based demand response resources increases the market share owned by [the companies], we believe that the recent improvements to the dispatch and pricing of capacity market-based demand response resources will encourage competition among providers and lead to more efficient dispatch going forward,” FERC said.

FERC also agreed with the companies’ contention that the deal would not affect vertical competition, as Pepco owns only 17 MW of generation, and the only Pepco utility joining Exelon that distributes natural gas is Delmarva Power & Light, which does not supply any generation facility.

Both the D.C. Office of the People’s Counsel and the Delaware PSC had raised concerns about the potential adverse effects the merger would have on the PJM stakeholder process. The OPC worried that the new company’s subsidiaries would give it an increased influence on stakeholder decisions, while the PSC was concerned that PJM would lose a consistent consumer advocate in discussions (See Pepco to Lose its PJM Voice; Consumers Lose Frequent Ally.)

FERC disagreed, again echoing Exelon and Pepco. “While the commission is aware that Exelon will be a member with more assets after the merger, there is nothing in the record of this proceeding to indicate Exelon will have excessive influence over the stakeholder process or the independence of PJM,” the commission said. It noted that the new company would only have a single vote as a transmission owner in PJM’s senior committees.

The commission did not discuss the merger at its meeting. LaFleur said this was because the commissioners felt that other items on the agenda such as the North American Electric Reliability Corp. standards and the 2014 Report on Enforcement would benefit from discussion, while its decision on the merger was sufficiently explained in the order. She added that due to the packed schedule, she feared that the meeting would run late; it lasted an hour and a half after four discussions.

November 18, 2014June 15, 2023

PJM MRC/MC 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 (9:10-9:40)

Members will be asked to endorse the following manual changes:

Manual 3: Transmission Operations — Updates names; clarifies timing for load shed for post-contingency voltage collapse; updates several sections; adds procedures.
Manual 13: Emergency Operations — Clarifies actions taken prior to emergency procedures; adds Min Gen Advisory procedure; updates Cold/Hot Weather Alerts; revises geomagnetic disturbance procedure; condenses and consolidates Attachment A.
Manual 11: Energy & Ancillary Services Market Operations — The changes will allow PJM to relieve demand response resources of their regulation and synchronized reserve responsibilities during Load Management Events. The change addresses the inability of DR resources to provide ancillary services and load management simultaneously.
Manual 14B: PJM Regional Transmission Planning Process — Changes made in accordance with North American Electric Reliability Corp. standards PRC-023-3 (Transmission Relay Loadability) and TPL-001-4.
Manual 28: Operating Agreement Accounting — Revised to include Load Reconciliation data in the settlement of emergency load response and emergency energy billing.
Manual 29: Billing — Changes method of reimbursing treatment of underpayments of miscellaneous items and special adjustments to avoid cost shifts.
Manual 13: Emergency Operations — Updates the 2015 day-ahead scheduling reserve requirement to 5.93%, down from 6.27% in 2014. The new requirement is based on a load forecast error of 2.15% (up 0.04% from 2014) and a forced outage rate of 3.78% (down 0.38%).

3. ENERGY / RESERVE PRICING & INTERCHANGE VOLATILITY (ERPIV) UPDATE (9:40-10:00)

The MRC will be asked again to approve PJM’s proposal to limit interchange during emergency conditions. An MRC vote last month on the issue fell just short of a two-thirds approval. (See PJM MRC OKs Change on Reserves; Interchange Limit Falls Short.)

The proposal to be voted on includes language to address hoarding and manipulation of interchange “room,” in order to address concerns raised by the Market Monitor.

PJM officials said they intended to recommend operating under the new rules, which require only a manual change, with or without the two-thirds mandate. The rule is intended to prevent markets and operations from being whipsawed by large swings in imports.

4. GAS UNIT COMMITMENT (10:00-10:20)

Beginning in January, gas generators will be able to change their offers to reflect fluctuating fuel prices, under a proposal being brought to the MRC. The proposal would allow generators to lock in their fuel prices three hours in advance of the operating hour.

The option would be available to resources that did not receive day-ahead commitments and were not picked up in the reliability assessment and commitment (RAC) run. Units with day-ahead commitments and those selected in the RAC run can switch prices after the end of their last committed hour. Units committed in real time will be unable to change their cost schedules until released. (See PJM Members Approve Intraday Updates to Generator Cost Schedules.)

5. SELLER CREDIT (10:20-10:40)

Members will be asked to endorse PJM’s plan to eliminate the “seller credit” provision from its credit policy, which RTO officials said was unnecessary. The provision was enacted when PJM still used monthly billing, to allow participants with consistent net sell positions some unsecured credit. Due to changes in credit policy and the 2009 switch to weekly billing, the need for seller credit is now addressed by the Reliability Pricing Model seller credit, a larger and less volatile credit, PJM said.

6. RESIDENTIAL DEMAND RESPONSE: PARTICIPATION IN THE PJM SYNCHRONIZED RESERVE MARKET & MEASUREMENT AND VERIFICATION FOR ENERGY AND LOAD MANAGEMENT (10:40-10:55)

The committee will be asked to endorse a proposal that PJM begin measuring the demand response performance of some residential customers through sampling of interval-meter data. (See Operating Committee Briefs, Nov.11.)

7. DEFINITIONS IN GOVERNING DOCUMENTS (10:55-11:10)

Members will vote on non-substantive revisions to definitions in the Tariff, Operating Agreement, Reliability Assurance Agreement and Manual 35: Definitions and Acronyms. The changes are intended to align the documents.

Members Committee

2. CONSENT AGENDA (1:20-1:25)

The committee will be asked to approve the following:

Operating Agreement (OA) revisions to ease Transmission Owners’ access to generator data feeds.
Updated Installed Reserve Margins and related metrics for 2015/16 through 2018/19 delivery years.
Tariff revisions related to energy and reserve pricing. (See PJM MRC OKs Change on Reserves; Interchange Limit Falls Short.)
Approve/endorse proposed non-substantive revisions to definitions in the Tariff and OA, aimed at providing alignment of definitions between the documents.

3. ELECTIONS (1:25-1:30)

The committee will elect members to the 2015 Finance Committee and sector whips, and the Members Committee vice chair.

4. WINDOW PROPOSAL FEE (1:30-1:45)

The MC will vote on a proposed $30,000 fee for transmission developers making proposals under competitive windows. (See PJM Members Approve $30K Fee on ‘Greenfield’ Tx Proposals.)

6. ENERGY MARKET OFFER CAP (2:00-2:30)

Members will vote on Tariff and OA revisions regarding energy market offer price caps proposed by Old Dominion Electric Cooperative. (See Load, Supply Trade Blame over Offer Cap Impasse.)

November 11, 2014

PJM TEAC IDs 20 Market Efficiency Candidates

PJM has identified 20 candidates for “market efficiency” projects in the competitive window that opened Oct. 30.

The candidates, which were presented to the Transmission Expansion Advisory Committee this morning, were based on annual simulated congestion frequency of at least 25 hours in the 2019 and 2022 study years.

They include 17 lower voltage facilities with a minimum of $1 million congestion in the study years and two regional facilities — AP SOUTH Interface l/o Black Oak-Bedington and AEP-DOM Interface l/o Black Oak-Bedington — with at least $10 million in congestion.

PJM said facilities below the thresholds were not likely to pass the minimum 1.25:1 benefit-cost criteria.

The RTO will also accept proposals to address capacity import limitations and thermal overloads on the Roseland-Cedar Grove-Clifton 230-kV corridor.

Artificial Island Update

PJM staff plans to announce its revised recommendation on the Artificial Island stability project at the Jan. 8 TEAC meeting, prior to a February recommendation to the Board of Managers. PJM will allow the four finalists to make presentations at a special TEAC meeting to be scheduled the week of Dec. 8. (See Two of 4 Artificial Island Finalists Offer Cost Caps.)

November 11, 2014June 15, 2023

PJM MIC Briefs

PJM and NYISO last week successfully launched Coordinated Transaction Scheduling (CTS), an effort to reduce uneconomic interchange flows. “So far it’s going well,” PJM’s Stan Williams told the Market Implementation Committee last week.

The new product allows traders to submit bids that clear only when the price difference between New York and PJM exceeds a threshold set by the bidder.

CTS began Nov. 4, a day after PJM began implementing credit checks for all exports. Williams said 57 CTS transactions were consummated Nov. 4 and the volume has grown since. PJM said as much as one-third of exports from PJM to New York occur when PJM prices are higher. (See NYISO Scheduling Product Wins FERC OK.)

PJM will continue discussions on a similar product with MISO at today’s Joint Stakeholder meeting at MISO headquarters.

PJM, Members to Discuss Earlier Notice on Pricing Interfaces

Stakeholders agreed Thursday to consider whether PJM should be required to provide more notice to the market before introducing “closed loop” interfaces to capture operator actions in pricing.

The MIC approved a problem statement by DC Energy’s Bruce Bleiweis to consider if such pricing interfaces should be barred from taking effect until they are announced before the monthly Financial Transmission Rights or Balance of Planning Period FTR auction.

In the last year, PJM has created closed loop interfaces in at least four locations so that operator actions — such as sub-zonal dispatch of demand response — are captured in LMPs rather than uplift. PJM said it must use the interfaces to set prices because its modeling software can only set prices for thermal constraints, not voltage problems.

Bleiweis’ initiative follows objections he raised at the August MIC, in which he said PJM’s efforts to reduce uplift were exacerbating FTR underfunding. (See PJM: Can’t Delay Interface Postings for FTR Auctions.)

On Thursday, PJM’s Joe Ciabattoni said that PJM will attempt to provide one-day notice for subzonal DR but that such notice may not be available for pricing interfaces needed for other reasons. “The potential exists for [pricing interfaces] at all of the 6,000 active constraints,” he said.

Bleiweis said that he wants PJM to formalize its notification procedures in its manuals.

Path Set for Query on Synch Reserve Payments

The MIC agreed to host the initial education session on the Independent Market Monitor’s effort to change compensation for Tier 1 synchronized reserves. The MIC endorsed an issue charge that scheduled the first session as part of the regular MIC meeting and defers a decision on whether to create a subgroup to complete the inquiry.

The MIC approved Market Monitor Joe Bowring’s problem statement last month.

Tier 1 synchronized reserves — all on‐line resources following economic dispatch and able to ramp up at PJM’s request — are paid the Tier 2 synchronized reserve market clearing price whenever the non-synchronized reserve price is more than zero. Bowring said it’s wasteful to pay Tier 1 the same price as Tier 2, because only Tier 2 are subject to penalties for non-performance.

PJM officials said they will likely oppose Bowring’s proposed change, which they said could upset the balance of the RTO’s scarcity pricing scheme. (See Monitor: Cut Pay for Tier 1 Synchronized Reserves.)

Initiative on Replacement Capacity Transactions Set for January

Members approved an issue charge deferring until January the first meeting to discuss Citigroup Energy’s request to change rules regarding the timing for recording replacement capacity transactions. Citigroup’s Barry Trayers said the current procedures, which don’t allow recording of the transactions until after the third incremental auction, create administrative headaches.

The MIC approved Trayers’ problem statement last month. (See MIC Briefs.)

Members Endorse Change on DR Dual Role

Overlapping-Ancillary-Services-and-Load-Management-Example-(Source-PJM-Interconnection-LLC) — (Click to zoom.)

PJM will relieve DR resources of their regulation and synchronized reserve responsibilities during Load Management Events under a change to Manual 11 endorsed by the MIC. The change addresses the inability of DR resources to provide ancillary services and load management simultaneously.

Monthly Seller Credit Eliminated

Members endorsed PJM’s plan to eliminate the “seller credit” provision from its credit policy, which RTO officials said was unnecessary. The provision was begun under monthly billing to allow participants with consistent net sell positions some unsecured credit. Due to changes in credit policy and the 2009 switch to weekly billing, PJM said the need for seller credit is now addressed by the Reliability Pricing Model seller credit, a larger and less volatile credit.

AEP Asks to Split Zone into 4 Settlement Areas

AEP-Operating-Company-Territories-(Source-AEP) — The proposed change does not affect Wheeling Power or Kingsport Power. (Click to zoom.)

American Electric Power asked PJM to split its zone into four energy settlement areas, a change that will affect demand response pricing, real-time load, InSchedule load contracts and auction revenue rights (ARRs).

New aggregates representing the four operating company energy settlement areas will be created.

Hub and interface definitions will not be impacted and the AEP physical transmission zone pricing point will still exist. Capacity and network transmission service will continue to settle at the AEP zone.

AEP has not provided a list of buses defining each of the proposed settlement areas but is required to do so by Dec. 1.

PJM said the following changes will result:

InSchedule load contracts will need to be created identifying the new settlement area.
Any real-time load currently priced at the AEP physical transmission zone will shift to being priced at the applicable operating company load aggregate.
Effective with the 2015/2016 ARR Allocation, load serving entities (LSEs) in the AEP zone will be assigned into one of the four new operating companies based on the location of their load unless the LSE sinks at a nodal location. Each LSE will be assigned a pro-rata amount of capability from each historical generation resource based on its proportion of peak load in the AEP zone. ARR allocations for LSEs not sinking at a nodal location will be assigned as follows: Load in the Indiana Michigan Power, Kentucky Power and Appalachian Power areas will sink at their respective aggregates. Load in the Ohio Power area will sink at the Ohio Power aggregate for Stage 2 only. In Stage 1, load at Ohio Power area will sink at the Ohio Power without MON POWER and the MON POWER Aggregates. The Stage 1 configuration is needed to maintain ARR requests from historical generation for the AEP zone corresponding to the AEP integration reference year (2004).

November 11, 2014June 15, 2023

PJM Operating Committee Briefs

PJM will begin measuring the demand response performance of some residential customers through sampling of interval-meter data under a rule change approved by the Operating Committee Wednesday.

The new procedure will apply to residential customers on non-interval meters and under direct load control of a curtailment service provider. The measurements will be used to evaluate the performance of resources participating in synchronized reserve, economic energy and load management programs.

The sampling would replace outdated studies dating back to 2001. Sampling is a way to improve accuracy without the cost of installing one-minute meters on every participating household, PJM said. The rule would take effect June 1, 2015, with a transition mechanism for resources that cannot meet new requirements for delivery years 2016 through 2018. (See MIC Briefs, Sept. 9.)

The OC approved the proposal with 14 abstentions and 19 objections, 15 from FirstEnergy. FE’s Jim Benchek said PJM shouldn’t take action on the issue given the uncertainty over DR’s role in wholesale markets as a result of the EPSA ruling and FE’s complaint seeking to prevent DR from clearing in capacity markets. (See EPSA Stay Complicates PJM’s 2015 Capacity Auction Plans.)

Benchek said the change represents a “carve out” for residences while generators must use interval meters. “If we make an exception here, where does it stop?” he asked. “They should have interval metering like anyone else if they want to sell synchronized reserves.”

Consultant Tom Rutigliano of Achieving Equilibrium said the committee’s action will have no impact on the ultimate fate of DR in wholesale markets, which may be decided by the Supreme Court. To avoid legal problems, PJM has proposed eliminating DR as a capacity supply resource, suggesting load-serving entities instead offer DR and energy efficiency to reduce their capacity obligations.

“This is still just a good measurement technique, no matter who’s doing DR,” Rutigliano said.

Day-Ahead Scheduling Reserve Set at 5.93%; Winter Reserve: 27%

The OC endorsed PJM’s recommendation to set the 2015 day-ahead scheduling reserve requirement at 5.93%, down from 6.27% in 2014. The new requirement is based on a load forecast error of 2.15% (up 0.04% from 2014) and a forced outage rate of 3.78% (down 0.38%). The changes will be reflected in Manual 13: Emergency Operations.

The committee also endorsed PJM’s proposed 2014/15 winter reserve target of 27%, unchanged from last winter. The 27% target, a percentage of the forecasted weekly peak load, is based on unit summer ratings.

PJM’s Tom Falin said the target does not include data from January 2014. “When we get to extreme conditions, I don’t know how binding this is anyway,” Falin said, noting that PJM would cancel maintenance outages if it anticipated a generation shortage. He said there were about 1,000 MW on maintenance on PJM’s all-time winter peak day in January.

TOs Asked to Update Load Dump Ratings

PJM is asking transmission owners to revise their ratings methodology to address facilities for which the long-term emergency (LTE) ratings are equal to the load dump (LD) measures.

TOs that are unable to make the changes through PJM’s rating methodology guideline should reduce the LTE rating by 3% of the LD rating. PJM wants the changes made by Dec. 1 so that it can determine their impacts on markets and planning before the revised ratings take effect June 1.

Concern over facilities with identical ratings arose as a result of the September 2013 hot-weather event, when PJM discovered that the normal, emergency and LD ratings on the Industrial-Summit 138-kV line were the same. “The impact of all the ratings being the same is there is no time for the dispatcher to perform anything but the most extreme action that must be taken once the load dump rating is reached,” PJM said in its heat wave analysis.

No Votes Gained on Interchange Volatility

A working group meeting last week failed to win any converts to PJM’s plans to limit interchange volatility, OC Chairman Mike Bryson said.

A Markets and Reliability Committee vote last month on PJM’s proposal to limit interchange during emergency conditions fell just short of a two-thirds approval. (See PJM MRC OKs Change on Reserves; Interchange Limit Falls Short.)

The Energy and Reserve Pricing & Interchange Volatility Sub-Group met on the issue last Tuesday in an attempt to reach consensus. “We tried to beat some votes out of people, but it didn’t really work,” Bryson said.