Page 1637 – RTO Insider

May 20, 2014

Monitor Suggests Price Gouging by Generators

Some generators may have taken advantage of January’s weather to boost their prices, the Market Monitor said in its quarterly State of the Market report Friday.

“The behavior of some participants during the high demand periods in January raises concerns about economic withholding,” the monitor said. “In particular, there are issues related to the ability to increase markups substantially in tight market conditions.”

The Monitor’s report cites the “markup index,” a measure of participant offer behavior. In the real-time energy market, 58% of marginal units had an average markup index at less than or equal to zero in the first quarter. But 14% of marginal units had average markups at or exceeding $150/MWh, compared to only 4% in the first three months of 2013.

In the day-ahead energy market, almost 87% of marginal units had average markups less than zero and an average markup index less than or equal to 0.03. “Nonetheless, some marginal units do have substantial markups,” the report said. Markups increased on days in January when demand was highest.

The markup index is calculated as (Price – Cost)/Price. The index ranges from -1.00, when the offer price is less than marginal cost, to 1.00, when the offer price is higher than marginal cost.

Competitive Offers Required

The Monitor said capacity resources should be required to make “competitive” offers into the energy market, an obligation that is not clear under current Tariff language.

“Selling capacity into the PJM capacity market but making energy offers daily of $999 per MWh would not fulfill the requirements of a capacity resource to make a competitive offer but would constitute economic withholding,” the Monitor explained in the 2013 State of the Market report. “This is one of the reasons that the rules governing the obligation to make a competitive offer in the Day-Ahead Energy Market should be clarified for both internal and external resources.”

The Monitor’s suggestion of economic withholding came a day after Federal Energy Regulatory Commissioner Tony Clark told PJM members that the commission had seen no evidence that market manipulation played a role in the high natural gas and electric prices in January.

In an interview yesterday, Market Monitor Joe Bowring said his staff will be interviewing generators with high markups and may refer the matter to FERC’s enforcement unit if it doesn’t receive satisfactory answers. “The Tariff requires us to refer potential enforcement matters to the commission,” he said.

January 2014 Outage Rates, Morning Peak (Source: PJM Interconnection, LLC)

Bowring said his staff is also investigating whether any generators engaged in physical withholding by improperly claiming outages. PJM saw as much as 22% of its generation out of service in early January, three times the normal winter outage rate.

Bowring said some gas-fired units took losses to operate in January. “We want to make sure that others also followed through” on their obligations, he said.

Inadequate Incentives

The Monitor’s report said the high generation outage rate in early January was an indication that the current balance of incentives and penalties is inadequate. “At present only half of capacity market revenues are at risk for failure to perform on high demand days. Gas-fired units with a single fuel are exempt from any capacity market revenue impact that results from lack of fuel outages on high demand days,” the report said.

The obligation of capacity resources to offer into the day-ahead energy market “exists regardless of whether gas procurement is difficult, regardless of whether gas prices are high and regardless of whether gas procurement is risky,” the Monitor said.

Stakeholders this month began work on developing potential winter testing requirements for generators. Consideration of incentives for generator performance and penalties for failures will be considered in a separate initiative, PJM said. (See PJM Seeks Action on Winter Lessons.)

Day-Ahead Scheduling Reserves

The Monitor also reported withholding in the day-ahead scheduling reserve (DASR) market, a problem it has cited before which worsened in 2014.

PJM uses the market to acquire supplemental, 30-minute reserves. Because the direct marginal cost of providing DASR is zero, offers greater than zero constitute economic withholding, the Monitor said.

In 2013, 12% of offers in the market exhibited evidence of withholding. The clearing price in the first three months of 2014 was $0.06 per MW, double the price for the first quarter of 2013.

About 74% of resources offered at less than $1 in the first quarter, with 11.5% of resources offered at more than $5 per MW.

The 2013 SOM report recommended incorporating the “three pivotal supplier” test in the market to prevent the exercise of market power during times of system stress, ranking it as a low priority item. PJM said it does not believe the change is warranted given the minimal impact of the market on consumer costs.

May 20, 2014

Exelon Sells Its Share of Safe Harbor Hydro

Exelon last week sold its 67% interest in Safe Harbor Hydroelectric Project, one of four run-of-the-river hydro facilities on the lower Susquehanna River, to Brookfield Renewable Energy Partners, L.P. for $613 million.

Brookfield operates 6,000 MW of generation, primarily hydro, in the United States, Canada and Brazil. It will be sole owner of the facility when the deal closes.

The deal is supposed to be finalized by the third quarter of this year, subject to regulatory approval.

Exelon inherited two-thirds ownership of Safe Harbor when it bought Constellation, parent company of Baltimore Gas & Electric. It still owns and operates Conowingo Hydroelectric Generating Station, the last dam on the Susquehanna River before it empties into the Chesapeake Bay, and Muddy Run Pumped Storage Facility, which is perched on the banks of the Susquehanna upstream from Conowingo.

Safe Harbor went into operation in 1931. It was a joint project of the two companies that would become PPL and BG&E. An affiliate of the LS Power Group purchased PPL’s share in 2011, and Brookfield bought it from LS Power in March of this year.

There are three other power-producing dams on the lower Susquehanna in Pennsylvania and Maryland. Furthest upstream is York Haven Dam, a small, 20-MW facility south of Harrisburg, Pa., owned by Olympus Power. Next is Safe Harbor followed by Holtwood Hydroelectric Plant, both between Lancaster and York Counties in Pennsylvania. Originally a 108-MW plant, PPL completed an expansion of Holtwood in 2013 that added another 125 MW.

The Conowingo dam is a 630-MW facility on the Susquehanna, between Harford and Cecil Counties in Maryland.

May 20, 2014

Members Re-elect Three to Board

The Members Committee re-elected Ake Almgren, Susan J. Riley and Charles F. Robinson to the Board of Managers, a formality given that the three were running unopposed.

The three were recommended by the Nominating Committee, which includes Board Chairman Howard Schneider, Board Member Jean Kinsey and representatives of each of the five voting sectors.

Almgren, a PhD in Engineering Sciences who joined the board in 2003, is the former president of ABB Power T&D Co. Inc. Riley, an MBA and a former finance executive for The Children’s Place, has served since 2005. Robinson, a lawyer and general counsel for the University of California system, joined the board in 2011.

The committee also approved the following:

Revisions to Manual 34: Stakeholder Process — Changes to voting methods at the Standing Committees, and posting and notice requirements.

Section 8.4: Voting Method:The voting procedures were changed to allow members to indicate their preference for the status quo over proposed rule changes.
Section 10.4: Posting Process Timelines: Members will have five business days to comment on proposed revisions to governing documents before votes of the Markets and Reliability or Members committees (down from the current 10-day requirement).
Section 11.13: Consultation with Transmission Owners and Members: Except in emergencies requiring immediate action, PJM will be required to provide Transmission Owners and PJM members 30 days’ notice before making a Section 205 filing to change the creditworthiness provisions of the Tariff. The notice time for making Section 205 filings on other matters will remain seven days.

Settlement Formulation Review – Phase II initiative — Clarifications to the Tariff and Operating Agreement (OA) on regulation shoulder hour lost opportunity costs (LOCs). As a result of a review, PJM discovered that the documents didn’t adequately describe the calculation of the deviation between the regulation set point and the expected output of each regulation resource.

Credit Available for Virtual Transactions — Revisions to the Tariff to reflect current PJM practices regarding credit available for virtual transactions. PJM instituted the policy as the result of a FERC Order in 2004 but failed to make accompanying changes to the Tariff. These revisions also correct for changes in credit policy since 2004 (e.g., working credit limit discount is now 25%, not 15%).

Synchronized Reserve penalty charges for Tier 2 resources — Clarifications to the Tariff and OA giving generators providing Tier 2 synchronized resources the ability to aggregate these resources in order to avoid retroactive penalties for failing to respond appropriately when called. New language will also be added to Manual 11: Energy & Ancillary Services and Manual 28: Operating Agreement Accounting. Aggregation will not be used in calculating Tier 2 Synchronized Reserve credits; each resource will continue to be credited independently.

PJM’s change of mailing address — Changes to the Tariff and Operating Agreement to reflect PJM’s new mailing address to: 2750 Monroe Blvd., Audubon, PA 19403.

May 19, 2014

PJM Differs with Most IMM Recommendations

PJM said last week it agrees with about one-quarter of the recommendations in the Independent Market Monitor’s 2013 State of the Market report.

PJM’s response to the Monitor’s annual review disagreed with about 40% of the recommendations. The RTO was noncommittal, or said it was unable to act, on about 35% of the more than 70 recommendations.

PJM agreed with about the same share of the IMM’s recommendations in its 2012 report but directly disagreed with about half of them.

The RTO’s 2012 response urged the Monitor to focus its findings on those with the biggest potential payback, noting that more than 90% of the suggestions pertained to subjects comprising less than 20% of total wholesale power market costs. The RTO said it was happy, however, that the Monitor had begun prioritizing the recommendations in the 2012 report.

In the 2013 report, the IMM prioritized only the new recommendations.

“Given the scope of issues to be considered in the stakeholder process, evaluation of priority and materiality of recommendations is an important consideration,” PJM said in its response. “PJM encourages the IMM to include consideration of priority and materiality in discussion and development of all recommendations along with associated detailed rationales for suggested changes to market rules.”

May 12, 2014

PJM Wins on DR, Loses on Arbitrage Fix in Late FERC Rulings

Acting on the eve of PJM’s base capacity auction, the Federal Energy Regulatory Commission Friday approved most of PJM’s new dispatch rules for demand response but rejected a plan to curb speculation in the auction, saying it created undue barriers to entry.

Instead, the commission ordered a technical conference to develop solutions to eliminate arbitrage opportunities between the base residual auction (BRA) and incremental auctions (IAs). It approved all but one of the major provisions of PJM’s DR proposal, rejecting the ability of the RTO to dispatch resources on a subzonal basis.

The commission said PJM’s proposed arbitrage fix — which the RTO proposed unilaterally after failing to obtain stakeholder consensus — “will simultaneously increase risk to suppliers and costs to load, without guaranteeing equally offsetting benefits to the PJM grid as a whole” (ER14-1461).

PJM proposed the arbitrage fix in March after the Markets and Reliability Committee failed for a second time to reach consensus. (See Second Time Not the Charm.)

No Consensus

Because clearing prices in IAs are usually lower than those in the BRA, participants can profit by selling capacity in the BRA and buying out their commitments in the IAs. PJM and the Market Monitor say such buyouts are suppressing capacity prices and could undermine system reliability.

PJM’s solution would have reduced the number of IAs (currently three) and set conditions eliminating the potential to arbitrage between the BRA and IAs.

Generators, including AEP, Calpine, PSEG, LS Power, Exelon, the PJM Power Providers and the Electric Power Supply Association, submitted interventions backing the PJM proposal. The Maryland Public Service Commission, Brookfield Energy Marketing LP, demand response provider Comverge, Old Dominion Electric Cooperative and American Municipal Power, Inc. were among those filing in opposition.

‘Disruptive’ Proposal

The commission said PJM’s “disruptive” proposal would increase risks for capacity sellers, creating undue barriers to entry, and increase costs to load through the acquisition of excess capacity. The commission was also unpersuaded by PJM’s “limited demonstration of the presence of speculative sell offers.”

“PJM has not demonstrated the degree to which purchases of replacement capacity are, in fact, the result of resources’ inability to meet their capacity obligations for non-speculative reasons, or resources submitting physical offers and responding to subsequent economic signals, or overly-optimistic offers `insured’ by consistent price spreads, or speculators looking to profit from consistent price spreads,” the commission wrote.

“Even existing generation resources, typically the most `physical’ of all resources, may seek to purchase replacement capacity as a result of unforeseen circumstances. More generally, both existing as well as planned capacity resources face a chance of being unable to meet their delivery year obligations due to unforeseen problems with a resource, or a resource’s development, and thus may reasonably wish to recoup certain sunk costs.”

The commission said the proposal could also increase costs for load by limiting the ability of the RTO to sell excess capacity back to the market.

The revised rule would have allowed PJM to sell into the IAs only if the clearing price equaled or exceeded the original BRA price. The commission said PJM had already taken steps to prevent capacity sellers from profiting from the purchase of cheap replacement capacity through a provision to recapture any such profits.

While it ruled PJM’s proposal not just and reasonable, the commission said it agrees “that PJM has identified a reliability issue that merits consideration.”

The commission said FERC staff will convene a technical conference to help develop a solution. The proceeding will be conducted in a new docket (EL14-48) using the procedures spelled out in Section 206 of the Federal Power Act.

DR Dispatch Proposal

PJM fared better in its proposal to increase its options for dispatching demand response. The commission voted 3-1 to approve all but one of PJM’s rule changes, with Commissioner John Norris dissenting.

The order (ER14-822) allows PJM to dispatch DR before emergencies, reduce default notice times to 30 minutes from as long as two hours and reduce minimum run times to one hour from two. However, the commission ordered PJM to allow small commercial customers to be eligible for the “mass market” exemption from the 30-minute notice.

It also approved an escalating price cap based on notice requirements:

30 minutes: $1,000/MWh, plus the primary reserve penalty factor, minus $1.
60 minutes: $1,000/MWh, plus the primary reserve penalty factor divided by two.
120 minutes: $1,100/MWh.

The previous rules capped DR at $1,000/MWh plus two times the applicable primary reserve penalty factor, for a total of $1,800/MWh. With rising penalty factors, the offer caps would have risen to $2,700/MWh over the next two years.

PJM’s proposed changes to measurement and verification rules were also approved, but FERC required a revision to allow DR providers to aggregate their performance for dispatches on the same operating day and within the same zone. The commission also ordered PJM to produce reports documenting its implementation of the new rules.

Sub-Zonal Dispatch Rejected

The commission rejected PJM’s call for sub-zonal dispatch inside an operating day. The commission ruled that PJM failed to show that DR providers which provide day-ahead sub-zonal dispatch can comply with sub-zonal dispatch on the operating day within 30 minutes without suffering “prohibitive costs.”

The commission said complying with the rule could be “difficult and costly” for curtailment service providers with customers in multiple locations and for individual customers with a footprint larger than a sub-zone.

“The necessary technology for demand resources to comply with this provision of PJM’s proposal is not widely available today,” the commission said. “If it becomes more widely available in the future, that change could enable PJM to show that this aspect of the proposal is just and reasonable.”

Norris Dissents

Commissioner Norris issued a dissent arguing that the 30-minute notice requirement imposed “a significant barrier” on DR participation in the capacity market that would undermine reliability and increase costs for consumers.

“I am particularly troubled because PJM’s proposal represents the third major tariff filing recently approved by this Commission that collectively will have the impact of reducing demand response participation in PJM capacity markets,” Norris wrote, referring to earlier rule changes that capped capacity offers for limited and extended summer DR (ER14-504) and required DR providers to give more assurances in their offers (ER13-2108).

“Demand response has repeatedly demonstrated its value in helping PJM meet system needs, but because some resources will be unable to meet the new performance requirement, such demand response will now be valued at zero and driven out of the market,” Norris continued. “As was made clear from this past winter’s polar vortex weather events, PJM needs all the resources it can get to help ensure reliability, particularly during times of system stress. I fail to understand why the Commission through today’s order would sanction efforts to unnecessarily reduce the pool of potential resources at PJM’s disposal.”

May 12, 2014

RTEP Proposal Window About a Month from Opening

The first project window for the 2019 Regional Transmission Expansion Plan will open in about a month, PJM told the Planning Committee last week.

PJM has posted results of its baseline N-1 study and expects to post its generation deliverability study in about a week, PJM’s Mark Sims said. The window will open when PJM completes a load deliverability study. “We’re looking at at least a month [to complete the third study]. It’s not going to be three months,” Sims said.

The window, which will be open for about 30 days, is unlikely to result in a large number of opportunities for non-incumbent transmission developers. Paul McGlynn, general manager of system planning, said “95% of projects in RTEP are upgrades to existing facilities,” which are assigned to incumbent transmission operators under FERC Order 1000.

McGlynn added that PJM is considering creation of a template for “no brainer” RTEP upgrades, to simplify and standardize the process for those submitting such projects.

PJM will open a second proposal window after completing its study of 2019 N-1-1 violations this summer. Approved projects will be submitted to the PJM Board of Managers in the fall.

May 12, 2014

Winter Report Recommendations

Below is a summary of the recommendations from PJM’s report on the operational challenges from January 2014. Recommendations new to the report are marked.

Unit Performance (NEW): Improve unit performance through incentives for performance and penalties for non-performance. Investigate unit testing, including testing dual-fuel capability. Improve preparation in advance of winter operations.
Unit Characteristics: Improve information sharing with generation owners, including fuel source and emission limitations. Improve specificity of the outage cause types in eDart and consider methods for validation. Clarify the rules for claiming an “Outside Management Control” event for taking an outage.
Gas/Electric Coordination: Improve harmonization of the timing of the gas and electric operating days. Allow generators to better include natural gas costs in their energy and capacity offers. Consider a review of offer caps and allowing generators to make changes to offers during the operating day. Consider allowing generators to reflect fuel availability in start-up and notification times.
Fuel Limited Resources (NEW): Improve information sharing for fuel-limited resources (those with less than 72 hours’ worth of fuel at maximum capacity).
Fuel-Specific Limitations (NEW): Consider methods for calling on long-lead generation based on fuel procurement limitations.
Energy Market Uplift: Review the cost allocation of energy market uplift.
Interregional Coordination (NEW): Increase situational awareness with the VACAR Reserve Sharing Group and Reliability Coordinator.
Unit Commitment (NEW): Clarify rules and conduct training regarding start-up costs and cancelled dispatch provisions.
Voltage Reduction Emergency Procedure: Review the voltage-reduction capabilities of transmission owners, particularly those without SCADA control.
Emergency Energy Bids: Enhance the tools and processes for accepting Emergency Energy Bids.
Regulation Market Rules (NEW): Reexamine the performance of the Regulation Market and investigate whether current rules are adequate. Consider going short regulation during system peaks.
External Capacity (NEW): Develop ways to confirm that external capacity resources either bid into the day-ahead market or submit eDart tickets indicating that they are unavailable. Ensure external resources are not declaring outages and selling energy into a different market.
Communications & Procedures (NEW): Improve how the Emergency Procedures tool is used to communicate. Consider adjustments to the roles and responsibilities for communications during emergency procedures. Refine training to reinforce processes and tools.
Public Appeals (NEW): Collect data on the impact of calls for conservation and improve processes for public notification during emergency procedures. Review triggers for public notifications.

May 12, 2014

Transmission Briefs

PJM approved the removal of a special protection scheme (SPS) on Conemaugh Unit 2 on Sept. 1.

The SPS was designed to mitigate transient instability conditions arising from an outage of the Conemaugh–Juniata 500-kV line, #5005. When enabled during an outage of the line, the SPS trips Conemaugh unit 2 if the Keystone-Conemaugh 500-kV line, #5003, is lost. Without the SPS, both the Conemaugh and Hunterstown generators would have had to reduce output in such a scenario.

The SPS hasn’t been used since 2011. The new Conemaugh 500/230-kV transformer and Conemaugh–Seward 230-kV line, which were placed in service in March, provide an additional outlet for Conemaugh and Hunterstown generation, rendering the SPS unnecessary.

The removal of the SPS is currently under review by Reliability First Corp.

New Mosby–BrambletonLine to Fix Overloads

Dominion Resources is adding a 500-kV line parallel to an existing 500-kV line between Mosby and Brambleton.

The new 500-kV Mosby–Brambleton line will be designated #546. The 2013 RTEP study identified overload violations on the Loudoun 500/230-kV transformers #1 or #2 for loss of the #590 Mosby–Brambleton 500-kV line. The new 500-kV line would be placed in an existing right-of-way and resolve this issue. The line (RTEP project #B2373) is expected to be in service by May 2018.

May 12, 2014

New BES Definition Takes Effect July 1

PJM transmission owners must notify the RTO when elements of their operations are reclassified as part of the North American Electric Reliability Corp.’s new Bulk Electric System (BES) definition.

The Federal Energy Regulatory Commission approved NERC’s revised BES definition in Orders 773 and 773-A. (See Bulk Electric Systems (BES) Inclusions and Exclusions.)

Beginning July 1, TOs have two years to inventory their assets to determine which should be included in the BES, PJM told the Operating Committee last week.

Under a PJM compliance bulletin, notification is also necessary when TOs request an exemption from BES status and when they receive a ruling on the request.

The definition focuses on equipment rated 100 kV or higher, although it also includes some equipment rated below 100 kV.

May 12, 2014

PJM Seeks Action on Winter Lessons

By Rich Heidorn Jr. and David Jwanier

Two weeks before Memorial Day, PJM and stakeholders are already worrying about next winter.

On Friday, PJM issued a comprehensive report on its response to the historic power demand during January’s deep freeze, adding nine proposed recommendations for action to five initiatives already underway.

Members began work on one of the new proposals last week, as the Operating Committee approved a problem statement and issue charge to consider resuming winter testing of generators. The testing would attempt to prevent a repeat of the poor generator performance in early January, when PJM saw a 22% forced outage rate, about three times its historic 7% average.

New Recommendations

The new recommendations in the 69-page report on January’s operational challenges focus on improving generator performance; handling of fuel-limited units; interregional coordination; unit commitment procedures; regulation market rules; and communications. (See Winter Report Recommendations.)

PJM executives Mike Kormos and Andy Ott answered questions about the report at the Capacity Senior Task Force meeting Friday.

Kormos, executive vice president of operations, said PJM staff is working on ways to quantify the risks identified in the report in order to prioritize the recommendations. “Is it a hair-on-fire, we-need-to-take-action-really-really-quick [issue] or is there more time?”

A common theme in the recommendations was the need to improve information-sharing to ensure operators know what generators have sufficient fuel and can be counted on to run. In tracking external resources, Kormos said, “we were doing a lot of things on spreadsheets and Post-it notes.”

Kormos also talked of the difficulty forecasting load on days when the weather made a big transition from one day to the next. “I don’t think any of us knew where load was going to end up,” he said.

Ott, executive vice president for markets, said PJM will also reconsider the way it schedules units. Because of restrictive gas pipeline rules, the RTO was often paying the most to run the least flexible units, an “inversion” of the normal situation.

“This is stuff we had never seen before and we didn’t necessarily have procedures for everything we saw,” he said.

“We’re used to calling every steam unit on during peak conditions,” added Kormos. “That may not have been the right answer.”

Testing

The Operating Committee unanimously approved the initiative to consider winter generator testing.

Mike Bryson, executive director of system operations, said designing a test that will be effective will be a challenge. PJM had winter testing until 2010, when the RTO decided to defer to new regional Reliability First Corp. standards, which were less burdensome and less costly.

The former rules allowed generators to test as late as February, which was often too late to address extreme cold conditions, officials said. Some stakeholders have questioned whether testing in December would truly help improve conditions at -10 degrees.

“I want to make sure we’re not doing testing for optics,” Bryson said. “Let’s take the 22% [outage rate] and find a way to improve it to a level that’s more typical of winter.”

Bryson said consideration of incentives for generator performance and penalties for failures would be considered in a separate initiative.