Page 1673 – RTO Insider

August 27, 2013

Settlement on FE Coal Plant Still a Bad Deal: Consumer Group

FirstEnergy Corp. reached a settlement last week in a controversial bid to shift a coal-fired generator from its unregulated subsidiary to regulated utility Monongahela Power, but a consumer group says the reduced price is still a bad deal for ratepayers.

Harrison Power Plant (Source: FirstEnergy)

Under the settlement, Mon Power ratepayers would pay Allegheny Energy Supply Company about $800 million for the 80% of the 1,984 MW Harrison plant it doesn’t already own, a reduction from AE’s original asking price of $1.1 billion. The revised deal was signed by the staff of the West Virginia Public Service Commission, the Consumer Advocate Division, the West Virginia Energy Users Group and several trade unions.

FirstEnergy said the deal will provide rate stability by shielding Mon Power customers from “unpredictable spot market prices.” Residential customers would receive a 1.5% rate cut, the company said.

But the West Virginia Citizen Action Group filed a challenge to the settlement Friday, saying the purchase price is still far more than the $554 million value that Allegheny Energy assigned to Harrison before the company’s acquisition by FE in 2011. The acquisition also would leave Mon Power dependent on Harrison and a second coal generator — the 1,107 MW Fort Martin station, which was built five years before Harrison — for 90% of its power.

“West Virginia rate payers will be stuck with obsolete, highly expensive coal-fired electricity long after the market has moved on, thereby locking an already burdened industrial base into the least competitive fuel source on the planet,” CAG’s attorney wrote. The group said it would be cheaper and less risky for ratepayers to purchase power from the PJM market. (See: Natural Gas Group Seeks Voice in West Virginia Coal Plant Acquisition)

On July 31, Virginia regulators cited a lack of fuel diversity for rejecting AEP’s request to transfer a coal-fired plant from an unregulated subsidiary to its Appalachian Power utility.

Byron Harris, director of the West Virginia state Consumer Advocate, acknowledged that the FirstEnergy settlement did not give his office all that it sought. “Any settlement is by its nature a compromise,” he told The State Journal. “There are what we believe are benefits in the settlement.”

The West Virginia commission yesterday ordered parties in the case to agree by Thursday on a hearing date to review the settlement.

More: StopPATH WV, Daily Mail

August 27, 2013

PJM MRC Preview

Below is a summary of the issues scheduled to be brought to a vote at the Markets and Reliability Committee Thursday. (There is no Members Committee meeting this month.) 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.

2. PJM Manuals (9:10-9:25)

A. 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.

PJM contact: Stan Williams

B. Manual 14B: PJM Region Transmission Planning Process

Reason for changes: Updates to reflect changes from FERC Order 1000, switch to two-year planning cycle and revised benefit/cost test for Market Efficiency projects.

Impact:

Separates Reliability and Market Efficiency into subsections
Adds a new section (2.1.2) to explain two-year planning cycle on Market Efficiency projects.
Changes to reflect Order 1000.
Changes energy market benefit calculation component of benefit/cost ratio for Market Efficiency projects eligible for regional cost allocation. The change in total energy production cost and change in load energy payments (previously weighted .70/.30) will be equally weighted.

PJM contact: Tim Horger

3. CETL Stability– Easily Resolved Constraints (9:25-9:45)

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

Impact: Before posting the planning parameters for each Base Residual Auction, PJM staff would be required to identify 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 115% would be added to the RTEP if they:

Cost less than $5 million;
Can be completed within 36 months or prior to June 1 of the Delivery Year; and
Does not duplicate customer-funded upgrades already in the transmission queue (e.g., one whose cost is assigned to an interconnection customer).

4. Parameter limited schedules (pls) revisions (9:45-10:00)

PJM will add new processes for generators seeking exemptions from operating parameters under changes endorsed by the Market Implementation Committee Aug. 7.

Reason for change: PJM’s generation parameters set defaults for different types and sizes of generators. The parameters cover 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.

Impact: The proposed change would create three types of exemptions:

Temporary Exception: A one-time exception of 30 days or less.
Period Exception: An exception lasting for at least 31 days but no more than one year during the 12 months between June 1 and May 31.
Persistent Exception: An exception lasting for at least one year.

The changes will require revisions to Attachment K of the OATT, Schedule 1 of the Operating Agreement and section 2.3.4 of Manual 11: Energy & Ancillary Services Market Operations.

Assuming FERC approval, the changes will be effective Oct. 1.

PJM contact: Jacqui Hugee

5. Stakeholder Process on Triennial CONE Review (10:00-10:15)

MRC members will be asked to consider changes to the Cost of New Entry (CONE) triennial review process. CONE values are used in PJM’s Reliability Price Model (RPM) to obtain capacity resources.

Reason for problem statement: PJM and members agreed to explore changes in the review process in a settlement approved by the Federal Energy Regulatory Commission in January (Docket No. ER12-513).

Impact of problem statement: The inquiry will assess the use of the Handy-Whitman Index of public utility construction costs for adjusting CONE and other potential changes.

PJM is required to file Tariff changes with FERC in time for the 2014 triennial review or a status report if stakeholders are unable to reach consensus on changes.

PJM contact: Paul Sotkiewicz

August 27, 2013

Market Monitor’s Recommendations

Below are the new recommendations included in the Market Monitor’s State of the Market report for the first half of 2013.

HIGH PRIORITY

Addresses a market design issue that creates significant market inefficiencies and/or long lasting negative market effects.

Operating Reserve — Reexamine allocation of operating reserve charges to participants to ensure payment by all whose market actions result in the incurrence of such charges:
- Eliminate the use of internal bilateral transactions (IBTs) in the calculation of deviations used to allocate balancing operating reserve charges.
- Reallocate the operating reserve credits paid to units supporting the Con Edison – PSEG wheeling contracts.
FTRs — Fix the Financial Transmission Rights overallocation issue:
- Eliminate cross geographic subsidies.
- Improve transmission outage modeling in the FTR auction models.
- Reduce FTR sales on paths with persistent underfunding including clear rules for what defines persistent underfunding and how the reduction will be applied.

MEDIUM PRIORITY

Addresses a market design issue that creates intermediate market inefficiencies and/or near term negative market effects.

Ancillary Services — Remove the distinction between Tier 1 and Tier 2 synchronized reserve, remove the ability to offer MW of synchronized reserve capability, remove the ability to make reserve unavailable, and automatically dispatch primary reserve co-optimized with energy. In the interim, enforce a must-offer requirement for synchronized reserve based on physical capability and increase penalties for non-compliance during spinning events.

LOW PRIORITY

Addresses a market design issue that creates smaller market inefficiencies and/or more limited market effects.

Energy Market — When generator is offline, treat as load (not negative generation) the energy drawn from PJM by those generators for calculating average hourly real-time and day-ahead load.
Demand Response — Load management resources whose load drop method is designated as “Other” should explicitly record the method of load drop.

August 13, 2013

PJM Considers Expanding Seasonal Verification for Generators

All generators would be required to verify their capacity under a problem statement approved by the Planning Committee Thursday.

PJM Manual 21 currently requires only combustion turbines and combined cycle generators to adjust their capacity ratings based on temperatures.

Some operators of other types of generation do not adjust their test results for seasonal conditions. In addition, hydroelectric units are permitted to perform their verification tests at any time during the year.

As a result, PJM’s Tom Falin told the committee, some generator ratings may overstate actual output under peak summer conditions.

In response to a question from Frank Francis, director of regulatory affairs for hydroelectric generator Brookfield Energy Marketing, L.P., Falin acknowledged PJM was unaware of any instances in which hydro units had overstated their capacity.

“We’re looking for a holistic solution,” said Steve Herling, PJM vice president of planning.

The problem statement was approved by acclimation. The lone no vote was cast by Francis, who said he opposed the inquiry because PJM has not shown a problem with hydro units.

“This is to see whether a change needs to be made,” responded Herling.

August 13, 2013

Manual 1: Data Submittals for NERC Compliance

The Operating Committee heard first reading last week on changes to Manual 1, Attachment B: Schedule of Data Submittals. The committee will be asked to endorse the changes at its next meeting.

Reason for change: The North American Electric Reliability Corp. requires PJM to provide evidence to demonstrate compliance with reliability standards.

Impact: Specifies method of submittal. Adds new requirement. (See table)

PJM contact: Chris Smart

August 13, 2013

Bid to Boost Synch Reserve Penalties Stalls at OC

A proposal to boost penalties for resources that fall short of their synchronized reserve commitments stalled at the Operating Committee last week as utilities called for more details.

The proposal by PJM and the Market Monitor failed on a tie 38-38 vote, with utilities including PSEG, PPL, AEP and Dayton Power and Light voting in opposition. Industrial users and other utilities, including FirstEnergy and UGI abstained.

Performance Lagging

The proposal was meant to address concerns over the lack of a qualification process for participation as Tier 2 Synchronized Reserve resources and the increased participation of demand response. Officials said the current penalty structure was insufficient to ensure compliance.

SR resources provided only 73% of the megawatts they were assigned, with less than one-third of units proving 100% or more of their assignments, said PJM’s Kim Warshel, who presented the issue to the committee.

The analysis found that the increase in demand response from 25% to 33% of SR resources had not hurt overall performance.

Penalties Lack Teeth

PJM and the monitor also concluded the current penalties are insufficient because of the decrease in the number of events of 10 minutes or longer (for which performance measurement applies), and the increase in days between events — currently 13 days. “It doesn’t have a lot of teeth anymore,” said Warshel.

Under current rules, if a resource fails to perform in one hour it doesn’t affect its credit for performing in another hour during the same day.

Dave Pratzon, who represents independent generators, said generators could be inadvertently penalized if plant operators fail to update their availability during the day when they are temporarily unable to perform. “I think more needs to be done before we take a vote on this,” he said.

Shortage Pricing Restriction

Other RTOs have qualification standards for resources seeking to offer in the SR market and conduct random tests to validate capability. The “must offer” requirement accompanying PJM’s Shortage Pricing limits its ability to implement similar procedures.

As a result, PJM and the monitor concluded that the best solution was to increase penalties.

The current language of Manual 11 states that:

The resource is credited for Tier 2 synchronized reserve capacity in the amount that actually responded for the contiguous hours the resource was assigned Tier 2 synchronized reserve during which the event occurred, and;

The owner of the resource incurs a synchronized reserve obligation in the amount of the shortfall for the three consecutive, same-peak days occurring at least three business days following the event.

(Emphasis added.)

The proposed change would remove the “contiguous” hours statement from the same-day penalty, meaning the resource’s credit will be reduced for the entire day if there is a shortfall in any hours. “You can’t stop and come back in and your penalty is erased,” explained Stu Bresler, PJM vice president of market operations.

“I can’t support that,” responded Brad Weghorst, market & regulatory policy manager for PPL Energy Plus.

The proposal also would increase the duration of the following-days’ penalty from three to the average number of days between events, as determined by an annual review.

August 13, 2013

Improved DR Baseline Processes OKd

PJM briefed members Wednesday on manual changes documenting two improved methods for verifying demand response providers’ customer baselines (CBL).

The CBL is used to forecast how much power a resource would have used absent DR. The two methods being added to Manual 11 are already permitted and one is in limited use.

The Same Day (3 + 2) method bases the CBL on the average of three hours before event (after skipping one hour) and two hours after event (after skipping one hour). For an event occurring in hours ending 13-17, for example, PJM would average hours ending 9-11 and 19-20.

The Match Day (3-day average) method uses an average of the three non-event days with the most similar load to the non-event hours on the event day. The hour before and after the event are excluded from the “non-event” hours.

August 13, 2013

PJM Briefs TEAC on Artificial Island Proposals

PJM officials gave the Transmission Expansion Advisory Committee a status report Thursday on their analysis of the 26 proposals for correcting stability problems at Artificial Island in South Jersey.

PJM’s first competitive transmission project under FERC Order 1000 attracted proposals from five utilities and three independent developers. The proposals ranged from $116 million to $1.5 billion. (Eight Companies Vie for Artificial Island Project)

Salem and Hope Creek Nuclear Reactors on Artificial Island. Photo Taken By Peretz Partensky from San Francisco, USA [CC-BY-2.0 (http://creativecommons.org/licenses/by/2.0)], via Wikimedia Commons

PJM’s Mark Sims told the TEAC that PJM planners wouldn’t be judging them on a “pass-fail” system but “don’t have the ability to analyze each one in excruciating detail.”

Sims said planners were conducting short circuit and thermal studies and hoped to have some initial findings at the next TEAC meeting. “We’re looking at projects as proposed” at this stage and not considering modifications to improve them, he added.

Sims also said PJM is seeking an outside engineer to help with the analysis. The consultant will help vet the developers’ cost estimates as well as providing “higher level information” for comparing the proposals, including issues such as line and river crossings.

In response to a question, Steve Herling, PJM vice president of planning, said public policy benefits of the proposals “can only be entertained if those states are on board to pay for those benefits.”

Sharon Segner, of LS Power, said one of her company’s two proposals includes at least $265 million in market efficiency benefits as a potential “tiebreaker” in the evaluations. The proposal, which envisions a new 230 kV line, has an estimated cost of $116 to $148 million.

Artificial Island is the home of the Salem and Hope Creek nuclear plants in Hancocks Bridge N.J.

August 13, 2013

Planning Committee OKs Relief for Wind Generators

The Planning Committee approved 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, the hour is excluded from the generator’s capacity credit calculation. (See Alternative Wind Capacity Calculations Yield Murky Results.)

Under Alternative 2, state estimator data would be used to interpolate output for each five-minute period with curtailments.

Under Alternative 3, forecast data from PJM operations — which is currently used for lost opportunity cost calculations — would be used for hours with curtailments.

Metered data would be used for all hours without curtailments under both options. Units with no curtailments over peak summer hours would not be affected by either option.

Alternative 2 was approved by a 101-23 margin and will be the primary option considered by the Markets and Reliability Committee. The MRC also can select Alternative 3, which was approved by a narrower 68-40 margin.

Assuming MRC approval, the new procedure would be applied to summer 2013 when capacity credit calculations are finalized in December 2013.

August 13, 2013

Manual 28: Operating Agreement Accounting

The Market Implementation Committee Thursday endorsed changes to 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.

PJM Contact: Suzanne Coyne