PJM Members Still Split on Incremental Auctions

By Rory D. Sweeney

VALLEY FORGE, Pa. — While stakeholders remain divided on changes to PJM’s Incremental Auctions, hope remains for reaching a compromise that can be implemented in time for next year’s Base Residual Auction. (See Consensus Fades on PJM Incremental Auction Solution.)

Stakeholders at Tuesday’s meeting of the Incremental Auction Senior Task Force defined where they will and will not budge on their positions. The three main sticking points are the number of IAs per delivery year, at what price PJM should sell excess capacity and what to do about excess commitment credits (ECCs).

Number of Auctions

PJM BRA Incremental Auction excess capacity — Chmielewski | © *RTO Insider*

Stakeholders appear closest to consensus and willing to negotiate regarding the number of auctions. PJM’s Brian Chmielewski presented the results of a recent poll that found more than two-thirds of voters strongly supported the status quo of an IA for each of the three years between the BRA and the delivery year.

However, most respondents were willing to consider proposals to reduce the number to two. A majority of voters were neutral about an option to have PJM sell capacity in either IA, with 41% opposed. A proposal to limit PJM to selling capacity in the final IA was strongly supported by 38% and opposed by 44%, with 18% neutral.

James Wilson of Wilson Energy Economics, a consultant to consumer advocates for several PJM states, said there’s no reason to reduce the number of IAs, but reducing to two could be acceptable. Carl Johnson, who represents the PJM Public Power Coalition, agreed that his membership was “not willing to fall on our sword” over the issue.

Sell-Back Price

Stakeholders remain divided over the sell-back pricing approach. PJM’s Jeff Bastian argued that the price must be at least what the RTO paid for it in the BRA. “If I’m going to excuse someone from a BRA commitment, why should I pay them?” he asked.

Calpine’s David “Scarp” Scarpignato agreed it must be at “or close to” the BRA price. It is a position on which “we can’t move,” he said.

Wilson and Jeff Whitehead of GT Power Group argued PJM should sell for whatever the market will bear. “You may sell some capacity [at the BRA price], but you’re basically pricing yourself out of the market,” Whitehead said.

PJM’s position “doesn’t make much sense,” Wilson said, because the capacity is not as valuable in the IA if the load forecast has been reduced following the BRA. He has argued that PJM needs more accurate load forecasts prior to the BRA.

Bastian later floated an idea that was developed during a meeting break to allow market participants out of their capacity obligations but not excuse them from the daily capacity-shortfall penalties, which equal 120% of the capacity payments. Wilson and Adrien Ford of Old Dominion Electric Cooperative pointed out that the idea is analogous to selling the capacity at the BRA clearing price. Bastian agreed, adding, “you’d have a cleaner settlement report.”

EnerNOC’s Katie Guerry was concerned the idea would reduce liquidity in the IAs because those with capacity obligations could walk away and decide they “won’t even bother” attempting to replace them in the IAs.

Whitehead said the IAs would have to clear above the BRA price for load to benefit. “I think, mathematically, load is better off under what [Bastian] just described,” Whitehead said.

Split over Excess Commitments

Stakeholders were also split on what to do with ECCs, which are allocated to load-serving entities when reliability requirements decrease below commitments. Currently, LSEs can use ECCs to replace resource commitments. Load has proposed eliminating the ECCs so that the excess committed megawatts, if not otherwise sold in an IA, are retained. The proposal also removes an opportunity for market participants to bypass the intent of any new IA sellback-pricing approach, Susan Bruce, who represents the PJM Industrial Customer Coalition, told RTO Insider in an email.

Johnson said public power organizations “feel entitled” to the ECCs and find them “helpful” for covering EFORd (equivalent forced outage rate – demand) deficiencies while adhering to their business models. As nonprofit entities, public power has a “distaste” for “making money” on the commitments by selling them back, Johnson said. Ford said she agreed with Johnson.

Guerry said that LSEs incur costs to secure commitments. “It’s not all necessarily profit” when they are sold back, she said.

Bruce said she “can appreciate [public power’s] perspective when you have self-supply obligations,” but that “load is getting the short end of the stick.” She also questioned how auditable ECCs would be if customers attempted to negotiate for their proportionate share of them in a retail transaction. She acknowledged some “wiggle room here” to negotiate a different solution but said the “status quo is not an option from a load perspective.”

Chmielewski asked stakeholders to develop new proposals for the task force’s next meeting on Nov. 10.

The IASTF is also charged with resolving a second problem statement and issue charge on the potential for profiting off of replacement capacity. Chmielewski said the issue will be a focus of the next meeting as well. (See “Stakeholders Quibble with, but Eventually Endorse, Replacement Capacity Investigation,” PJM Markets and Reliability and Members Committees Briefs.)

To get the proposals implemented in time for the next BRA in May, they will need to be presented at the January meeting of the Markets and Reliability Committee, he said.

November 2, 2017

ERCOT: Sufficient Capacity for Winter, Spring

By Tom Kleckner

Despite the retirement of more than 3.5 GW of generation, ERCOT said Wednesday it has enough installed capacity available to meet forecasted peak demand through May 2018.

The ISO expects to have almost 81 GW of total capacity available this winter, more than enough to meet a projected peak of more than 61 GW. That would break the winter peak demand record of 59.75 GW, set last January.

ERCOT installed Capacity Coal Plant Retirements — ERCOT operators monitor the Texas grid. | © *RTO Insider*

ERCOT removed 3,551 MW of recently announced generation retirements from the final seasonal assessment of resource adequacy (SARA) report for the winter season (December-February). That includes 1,200 MW of capacity still being studied to determine whether it is needed to maintain system reliability.

Luminant accounted for most of the retired resources. The company said last month it will shut down three coal plants totaling 4.2 GW by the end of February. (See Vistra Energy to Close 2 More Coal Plants.)

“ERCOT still expects to have sufficient systemwide operating reserves for the winter season,” Pete Warnken, the ISO’s manager of resource adequacy, said Wednesday. “Our studies show this would be the case even with a much higher-than-expected peak demand.”

The winter SARA includes nearly 1.4 GW of mostly renewable capacity. The wind and solar projects are expected to contribute 209 MW to the winter peak.

ERCOT Senior Meteorologist Chris Coleman said he expects a mild winter overall, with some very cold periods in mid-winter.

The ISO’s preliminary assessment for the spring months (March-May) was equally optimistic. Staff projects a season peak of more than 59 GW, and expects to have 80.7 GW of capacity available.

The final spring SARA report will be released in early March.

ERCOT’s most recent Capacity, Demand and Reserves report indicated the ISO had an 18.9% reserve margin for next summer, with margins remaining above 18% the following three years. A revised CDR report incorporating the latest retirements will be released in December.

November 2, 2017

Calpine Profits down 24% in Q3

By Jason Fordney

Calpine reported Wednesday that it earned $225 million in the third quarter ($0.63/share), down 24% from $295 million ($0.83/share) a year earlier.

The decrease was primarily due to “an unfavorable variance in mark-to-market gain/loss, net, and increases in plant operating expense and depreciation and amortization expense,” Calpine said. The decline was partially offset by a higher commodity margin, which the company said was driven by hedge revenues from retail operations and higher regulated capacity revenue.

calpine earnings profits q3 — Calpine’s Sonoma Geothermal Plant north of San Francisco, Calif.

The company, which has agreed to go private in a $5.6 billion deal with Energy Capital Partners and an investors group, lost $47 million in the first nine months of this year, compared with a profit of $68 million in the same period a year ago. Company officials issued the earnings with no previous public notice and no conference call to take questions from analysts. (See Calpine Going Private in $5.6B Deal.)

In a news release announcing the results, CEO Thad Hill said the merger is on track to be completed in the first quarter of 2018. He focused on the company’s response to natural disasters in California and Texas.

“Since our last earnings call, we endured Hurricane Harvey in Texas and the wildfires in Northern California safely and without any material damage to our facilities,” Hill said. “I am particularly proud of team members on the front lines who kept our plants and operations going in the face of adversity.”

Operating revenues were $2.6 billion for the quarter, compared with about $2.4 billion in the same quarter last year. Operating revenues in the first nine months of 2017 were nearly $7 billion, compared with about $5.1 billion in the same period last year.

The company said cash from operating activities rose 21% to $807 million over the first three quarters, “primarily due to a decrease in working capital employed resulting from the period-over-period change in net margining requirements associated with our commodity hedging activity, partially offset by a decrease in income from operations, adjusted for non-cash items.”

November 1, 2017

Profits up, Edison International Talks Clean Energy Goals

By Jason Fordney

Edison International says its grid will help California meet its clean energy goals, but infrastructure and market improvements are still needed.

The company, parent of utility Southern California Edison (SCE), “must be a key enabler of California’s ambitious renewable policies,” CEO Pedro Pizarro said during an earnings call Monday. He mentioned renewable integration, customer technology choice, adoption of distributed energy, vehicle electrification and energy efficiency. Achieving those goals will require strengthening the existing electricity grid, he said.

Edison International clean energy — Edison International Is the Parent Company of Utility Southern California Edison (who’s control room is shown) | *SCE*

Edison said it would soon issue a whitepaper on a framework for the state to meet its energy goals, building on existing policies and summary results of different scenarios. The paper will discuss carbon-free electricity with storage, increased electric vehicle integration and improved building efficiency.

The company earned $470 million ($1.44/share) during the third quarter, compared to $421 million ($1.29/share) a year earlier. Net income for the nine months ending Sept. 30 came in at $1.1 billion ($3.41/share), compared to $982 million ($3.01/share) during the same period last year.

SCE’s net income through Sept. 30 increased by $73 million, or 23 cents/share, from the same period in 2016, primarily because of an earlier rate case decision, the company said.

The utility is in the midst of its 2018 rate case with the California Public Utilities Commission, having recently filed reply briefs, with public hearings slated for November. It does not expect a decision from the commission this year. Another proceeding with the PUC regarding electric vehicles and energy storage could increase SCE’s investment forecast by $1 billion, Edison said during the earnings release.

Company executives said Monday they continue to support the existing settlement over the San Onofre Nuclear Generating Station. SCE has been unable to reach agreement with settling parties and recently urged the PUC to support the existing settlement. (See CPUC Orders Renegotiation of San Onofre Settlement.)

“Folks have different ideas as we walk down the pathway here,” Pizzaro said of the proceeding.

November 1, 2017

FERC Clarifies Ruling on NYISO Capacity Change

By Michael Kuser

FERC last week denied NRG Energy’s request for rehearing of a January order concerning NYISO Tariff revisions intended to correct a pricing inefficiency in the ISO’s capacity market (ER17-446-003).

NYISO proposed the revisions last November to address situations in which a generator exports power out of an import-constrained locality, creating increased counter-flow on the transmission constraints between that locality and other zones in the New York Control Area (Rest of State).

FERC NYISO capacity tariff revisions — NRG Headquarters in Princeton, NJ. | *NRG*

The ISO proposed to use a locality exchange factor, reflected as a percentage, to calculate the amount of Rest of State generation that can be imported into the locality to replace a portion of the exported capacity. The ISO would multiply this factor — 47.8% for the G-J locality — by the amount of exported capacity to determine the additional capacity that can be procured from outside the locality as a result of the export.

NRG protested the Tariff changes, expressing concerns about NYISO’s “apparent” assumption that an exporting resource would indefinitely continue to provide capacity benefits to its locality through counter-flows produced by its exports. The company noted that, under the Tariff, any resource that ceases to participate in the capacity market — by continuously exporting for three years — loses its capacity resource interconnection service (CRIS) rights and therefore can no longer provide a capacity discount to the locality in which it resides.

In its January order, FERC rejected NRG’s protest, but the company’s request for rehearing alleged that the commission erred in approving NYISO’s filing without fully addressing its concerns on how a generator that loses its CRIS rights should be considered for purposes of the locality exchange factor methodology.

NRG also asked FERC to clarify that a resource cannot claim resource adequacy benefits once it loses its injection rights in New York. In the alternative, the company sought clarification that a continuously exporting unit that loses its CRIS rights cannot be counted in the ISO’s installed reserve margin modeling.

Clarifying Order Language

FERC’s Oct. 25 order denied NRG’s rehearing request, but granted — in part — what NRG was seeking.

“The express relief [NRG] seeks is for the commission to clarify a statement in the Jan. 27 order rather than to change the commission’s determination,” the commission said.

FERC acknowledged that its Jan. 27 order “may cause confusion” in how it addresses the relationship between the locality exchange factor and CRIS rights. That order meant to convey that, under the existing NYISO Tariff, the locality exchange factor does not apply to the exported capacity of a generator that has failed to maintain its CRIS rights, the commission said. The factor should be applied only to locational export capacity, and by definition would not apply to exports from a resource that has lost its CRIS rights.

But the commission demurred on NRG’s alternative request for clarification.

“It is our understanding that a unit that exports and loses its CRIS rights after three years would not be counted in installed reserve margin modeling,” the commission said. “However, installed reserve margin modeling is performed by the New York State Reliability Council, not NYISO, and we find questions regarding the establishment of the installed reserve margin to be beyond the scope of this proceeding regarding NYISO’s proposed revisions to its [capacity] market design.”

November 1, 2017February 19, 2025

Federal Trade Panel Recommends Solar PV Quotas

By Michael Kuser

The U.S. International Trade Commission on Tuesday recommended that President Trump impose import duties as high as 35% on solar cells and modules.

USITC Building in Washington, DC | USITC

The independent panel announced the recommendations following its unanimous ruling in September that increased imports of solar cells and components are harming domestic manufacturers, which supported the claims of solar manufacturers Suniva and SolarWorld under Section 201 of the 1974 Trade Act.

The commission will forward its injury determination, remedy recommendations, any additional findings and the basis for them to Trump by Nov. 13. The president will then have 60 days to decide on what, if any, measures he will take. (See Trade Panel Rules PV Imports Hurting Domestic Manufacturers.)

Three of the four commissioners recommended imposition of tariff-rate quotas. The fourth, Meredith Broadbent, recommended that the president impose a hard annual quantitative restriction on imports of crystalline silicon photovoltaic (CSPV) products into the U.S. for a four-year period. That restriction would be set at 8.9 GW in the first year, increasing by 1.4 GW each subsequent year.

Tariffs and Quotas

Chair Rhonda Schmidtlein sought tariffs as high as 30% on imports of cells that exceed annual quotas of 0.5 GW, recommending that in-quota levels be incrementally raised and the tariff rate incrementally reduced during a four-year remedy period.

For CSPV modules, Schmidtlein recommended a 35% duty to be incrementally reduced during a four-year remedy period.

| USITC

Vice Chair David Johanson and Commissioner Irving Williamson joined in recommending measures similar to Schmidtlein’s: “For imports of CSPV products in cell form, we recommend an additional 30% ad valorem tariff on imports in excess of 1 GW. In each subsequent year, we recommend that this tariff rate decrease by 5 percentage points and that the in-quota amount increase by 0.2 GW. The rate of duty on in-quota CSPV products in cell form will remain unchanged. For imports of CSPV products in module form, we recommend an additional 30% ad valorem tariff, to be phased down by 5 percentage points per year in each of the subsequent years.”

Who to Blame?

Schmidtlein also recommended that Trump initiate international negotiations to address the underlying cause of the increase in imports of CSPV products.

Broadbent said that surging imports and a global oversupply of CSPV products resulted “from the subsidization of manufacturers in China in the context of targeted industrial policy programs. I believe the president intends to address China’s non-market economic policies that have contributed to global oversupply as part of broader bilateral negotiations with the government of China, and I support those efforts.”

She said her recommended quotas “are consistent with the market share held by imports in 2016, adjusted to reflect projected changes in demand for photovoltaic products over the next four years. Therefore, they are set at levels that will not disrupt expected growth in CSPV demand but will help address the serious injury to the domestic industry by preventing further surges in imports.”

Where the Buck Stops

Timothy Fox of ClearView Energy Partners said in a statement that the commission’s recommendations for trade remedies represent another step toward final action, not final action itself.

“We regard today’s vote as another significant step towards trade action likely to raise the cost of solar domestically, potentially blunting solar power deployment over the next four years,” Fox said, adding that Trump’s decision could be driven more by politics than by economics.

“President Trump measures economic success in terms of bilateral trade balances and manufacturing jobs,” Fox said. “This solar trade proceeding could give President Trump a way to ‘win’ on both fronts. Economic nationalism appears alive and well within the White House, including in renegotiations of the North American Free Trade Agreement and Korea-U.S. Free Trade Agreement. As such, we think this solar proceeding could serve as a prototype for future protectionist efforts, including those concerning aluminum and steel (especially steel).”

November 1, 2017

SDGE’s Wildfire Costs Undercut Sempra Profits

By Jason Fordney

Sempra Energy’s third-quarter financial results were hobbled by an administrative law judge’s preliminary decision to deny subsidiary San Diego Gas & Electric’s request to recoup losses stemming from wildfires a decade ago.

A California Public Utilities Commission ALJ in August recommended the commission deny SDG&E’s request to recover $208 million in costs related to the 2007 Witch, Guejito and Rice wildfires, ruling that prior to the fires, the utility “did not reasonably manage and operate its facilities.” The ALJ decision is not binding, and the PUC is due to vote Nov. 9 on SDG&E’s request to recover the costs.

During an earnings call Monday, Sempra executives said they are prepared to take the matter to court if they are not allowed to recover the money.

Traditional accounting measures require the company to reflect the preliminary decision in its financial results, but Sempra said that on an adjusted basis, earnings increased to $265 million ($1.04/share), from $259 million ($1.02/share) a year ago. Unadjusted earnings came in at $57 million, compared with $622 million last year.

Sempra Energy earnings — Sempra Energy Is The Parent Company of San Diego Gas & Electric, Southern California Gas And Others | *SDG&E*

For the first nine months of the year, Sempra’s earnings were $757 million, compared with $991 million over the same period last year.

Sempra is also attempting to acquire Texas-based utility Oncor in a deal worth nearly $10 billion. The Public Utility Commission of Texas last week issued a preliminary order that calls for Sempra to prove it is financially fit to own the state’s largest utility. (See Texas Regulators Seek More Details on Sempra Oncor Bid.)

SDG&E recorded a net loss of $28 million in the third quarter, compared with earnings of $183 million a year earlier, “due primarily to the $208 million after-tax impairment related to cost recovery for the 2007 San Diego wildfires.”

The utility’s earnings were $276 million for the first nine months of 2017, compared with $419 million in the same period last year. Earnings for the first nine months of 2017 included the third-quarter 2017 wildfire-related impairment. In last year’s second quarter, SDG&E recorded an after-tax charge of $31 million, refunding to ratepayers the benefits from tax deductions related to the final 2016 rate case decision.

October 31, 2017

IMM, Consumers Miffed over PJM Plans for Checking Energy Offers

By Rich Heidorn Jr.

WILMINGTON, Del. — Consumer representatives and the Independent Market Monitor expressed concern Thursday over PJM’s plans for vetting energy offers exceeding $1,000/MWh, with the Monitor seeking manual changes and consumer groups fearing excessive demand response costs.

The issues arose during a discussion at the Markets and Reliability Committee meeting on changes to Manual 11: Energy & Ancillary Services.

PJM FERC Market Monitor Consumers Energy — Tyler | © *RTO Insider*

The manual changes, part of PJM’s implementation of FERC Order 831 (RM16-5), passed with 13 objections and two abstentions after Catherine Tyler, senior economist for Monitoring Analytics, reiterated complaints the Monitor filed with the commission in response to the RTO’s May 8 compliance filing on the order.

The order doubled the “hard” offer cap for day-ahead and real-time markets from $2,000/MWh — a response to the 2014 polar vortex, which caused natural gas price spikes that left some generators in the Northeast complaining they were unable to recover their costs. Incremental energy offers must be capped at the higher of $1,000/MWh or a resource’s cost-based energy offer, with $2,000/MWh being the maximum offer eligible for setting LMPs; approved offers over $2,000 are eligible for uplift payments.

The Monitor said PJM’s plan does not follow the order’s requirement that RTOs build on existing mitigation processes in verifying that offers above $1,000 are based on actual or expected costs and does not mention the Monitor’s role in that process.

“We will review offers over $1,000,” said Tyler. “The manual should make that clear.”

The Monitor told FERC that PJM instead “proposes to create a new cost-based offer verification process,” does not provide a way for verifying cost-based offers that fail its automated screen and lacks a process for verifying DR offers over $1,000. It said the commission should require “a new proposal that builds on existing cost verification processes, including the Market Monitor’s cost verification process and fuel cost policies.”

Greg Poulos, executive director of the Consumer Advocates of PJM States, requested the vote on Manual 11 be conducted separately from three other manual changes, saying the Monitor should have joint approval with PJM of energy offers over $1,000.

It was the DR issue that concerned Susan Bruce, of the PJM Industrial Customers Coalition. She said although her group is “a big supporter of demand response … we’re concerned we don’t have the same rigor” in ensuring the cost inputs in DR offers as for generation.

The lack of rules creates “opportunities for strategic behavior,” Bruce said.

PJM’s Pete Langbein said that although the RTO has considerable experience in verifying generation offers, “we’re a little bit in uncharted territory” for DR. He said PJM wants to analyze “what costs we see from DR in the next six to 12 months” before creating rules.

Bruce agreed it would be difficult to guess what costs DR providers will file but said that during the interim, “customers will be vulnerable” to potentially inflated and improper costs.

Langbein said PJM will address the issue in the stakeholder process and deal with offers in the interim on a “case-by-case basis.”

Bruce Campbell of CPower said he supported the RTO’s approach. “It’s difficult for me to imagine a standard that would be workable at this point beyond what PJM has outlined.”

PJM’s Chantal Hendrzak added that the RTO wants to wait for FERC’s response to its compliance filing before implementing standards. The rules will not go into effect until the RTO receives the commission’s response, she said.

Manual 11 also had been the subject of debate at the Market Implementation Committee meeting earlier in the month. (See “Debate Continues on Intraday Offers,” PJM Market Implementation Committee Briefs: Oct. 11, 2017.)

The New Jersey Board of Public Utilities filed comments supporting the Monitor, saying, “PJM’s filing appears to be yet another attempt by PJM to minimize the role of the IMM.” The Delaware Public Service Commission called on FERC to reject PJM’s filing, saying its formulaic screen is unsupported and would result in higher prices than verifying all offers above $1,000.

PJM responded to the Monitor’s comments in June, reassuring FERC that all cost-based offers must be in accordance with the market seller’s RTO-approved fuel-cost policy, “including the IMM’s review of such policies.” The RTO said the proposed screen is “an additional safeguard” to ensure only legitimate generation offers greater than $1,000 are eligible to set LMPs.

October 31, 2017

PJM Grilled on Price-Responsive Demand Rule Changes

By Rich Heidorn Jr.

WILMINGTON, Del. — State and consumer representatives grilled PJM officials Thursday over proposed changes to price-responsive demand (PRD) bids, with the head of the Organization of PJM States Inc. accusing the RTO of flouting the 2005 Energy Policy Act.

PJM says PRD bids should be available year-round, the same as generation resources under Capacity Performance rules. But OPSI argues they should be allowed the option to make only seasonal contributions because PJM’s summer peak loads exceed winter peaks by more than 20,000 MW.

“What problem are you trying to solve?” asked OPSI Executive Director Gregory Carmean at Thursday’s Markets and Reliability Committee meeting. “The states obviously would like to see the effectiveness of their demand-side programs reflected in PJM’s load forecasts.”

PRD — a program that lets customers agree to reduce their loads in response to energy prices in exchange for reduced capacity requirements — was developed during 2010-12, before CP rules changed the requirements for demand response. It requires dynamic retail rate structures and advanced metering. PRD providers — electric distribution companies, load-serving entities or curtailment service providers — must be able to remotely curtail load when a PJM maximum emergency event has been declared and LMPs exceed trigger prices.

Because PJM approved its first PRD plans for the 2020/21 delivery year, it must now bring the rules in line with CP, the RTO says.

Thursday’s discussion came during a first reading of three proposals developed by the Demand Response Subcommittee.

The RTO’s proposal would extend DR’s annual requirements to PRD. A second proposal would limit the triggers for assessing CP penalties to just penalty assessment intervals. The third, from DR-participant Whisker Labs, would extend the existing PRD rules to the winter, create a summer-only product and allow it to be aggregated with a winter resource for an annual CP resource.

Carmean said PJM was acting in “direct contradiction of Congress’ intent” in the Energy Policy Act of 2005, which said that DR “shall be encouraged” and “unnecessary barriers to demand response participation in energy … markets shall be eliminated.”

PJM MOPR Demand Response PJM Insider — Langbein | © *RTO Insider*

“I have not gone back to read the law,” said PJM’s Pete Langbein, who presented the proposals, which the RTO plans to bring to an MRC vote next month. But he said PJM had made modifications to its monitoring and verification rules and expanded regions to ease requirements for DR. “We are continuing to work on this in the seasonal task force,” he said, referring to the group being created as a result of a problem statement and issue charge approved by the MRC in August.

Greg Poulos, executive director of the Consumer Advocates of PJM States, said he shared Carmean’s concerns. “Residential customers can no longer participate in this program,” he said. “Customers are kind of getting the short end [of the stick].”

“It seems to be a different product now,” added Morris Schreim, senior adviser to the Maryland Public Service Commission.

Carmean said the changes could mean “stranding hundreds of millions spent on [advanced metering infrastructure] meters. … OPSI believe the PRD program as it exists today should be allowed to continue.”

Earlier this month, OPSI drafted a resolution calling on PJM to postpone the imposition of annual resource requirements on PRD “until it has implemented an improved mechanism for summer seasonal resource participation in excess of winter seasonal resource participation, or until such time that winter reliability requirements equal or exceed summer reliability requirements.” (See “OPSI, PJM at Odds over PRD,” PJM Market Implementation Committee Briefs: Oct. 11, 2017.)

On Friday, PJM CEO Andy Ott responded with a letter to OPSI. “PJM agrees demand response resources are valuable, and we seek ways to have them receive compensation in accordance with their contribution to reliability,” Ott said. “For seasonal resources that do not participate as Capacity Performance resources, the new stakeholder group will explore measures to value their contribution to grid reliability.”

October 31, 2017

PJM MRC/MC Briefs 10-26-17

Markets and Reliability Committee

Stopgap Balancing Ratio OK’d Despite Questions

WILMINGTON, Del. — PJM members approved a Tariff revision setting 78.5% as the balancing ratio to be used in calculating the default market seller offer cap (MSOC) for the 2021/22 Base Residual Auction next May.

PJM said the change was a stopgap measure required for next year’s BRA because there have been no penalty assessment hours (PAHs) since 2015. PAHs are one factor used to calculate MSOC for Capacity Performance resources. (See “Give me a B…,” PJM MRC/MC Briefs.)

The Tariff change passed with no opposition but 10 abstentions.

default market seller offer cap pjm — Greiner | © *RTO Insider*

The MSOC is the product of the net cost of new entry (CONE) and the average of the balancing ratios for the three years preceding the delivery year. PJM proposed using 78.5% because it was used for the 2020/21 BRA earlier this year.

“I’m not sure how you got here,” said Gary Greiner of PSEG Energy Resources & Trade. “I do know 78.5 is not the right number.”

Susan Bruce of the PJM Industrial Customers Coalition agreed that the stopgap number was not correct. “I think there’s something to be said for the fact that there have been no performance assessment hours. That should be telling us something, but that’s part of a larger conversation,” she said.

default market seller offer cap — Tyler | © *RTO Insider*

The Independent Market Monitor’s Catherine Tyler also criticized the number as incorrect. She said PJM should instead rely on its avoidable cost rates, which she said is “already well defined in the Tariff.”

With one abstention, members also approved a problem statement and issue charge to develop a long-term solution. The issue was assigned to the Market Implementation Committee with a target of developing a solution in time for the 2022/23 BRA.

Bruce asked that PJM make clear in its FERC filing that the 78.5% balancing ratio is “not to be precedential in any fashion.”

DER Subcommittee Charter Sent Back to MIC

The MRC postponed voting on a draft charter to transfer all work on distributed energy resources into a subcommittee because of a disagreement over a proposed amendment by FirstEnergy.

The charter would create the Distributed Energy Resources Subcommittee, reporting to the MRC. It arose from concerns that the current problem statement and issue charge on DER is overly narrow and inhibited discussions that should include markets, operations and planning implications. The talks had been taking place in special sessions of the MIC.

FirstEnergy sought to add an amendment saying “Market rules must respect the distribution system and state/local jurisdictional agency standards and protocols to ensure safety and reliability. Rules should adhere to all pertinent jurisdictions and respect the relevant electric retail regulatory authority (RERRA).” (See “Amendment on DER Charter Sparks Debate,” PJM MRC/MC Briefs.)

MRC Secretary Dave Anders said that some stakeholders thought the amendment had been considered in the draft that came out of the MIC-DER group and others did not. The MIC did not formally vote on the measure.

As a result, the charter will be returned to the MIC, which will vote on versions with and without the amendment, with the winner brought to an MRC vote next month.

MRC OKs Sharing Generator Data for Restoration Planning

Members approved Operating Agreement revisions governing PJM’s sharing of restoration planning generator data with transmission owners. (See “TOs to Receive Confidential Generation Data for System Restoration,” PJM Operating Committee Briefs: Sept. 12, 2017.)

The changes will allow PJM to provide confidential generator data for any unit:

that is or will be modeled in TO energy management system; and
that is or will be identified in a TO restoration plan.

The second reference to “or will be” was added as a correction between the first read and Thursday’s vote. The corrected version was endorsed with no objections or abstentions.

PJM Consulting with Chinese on Real-Time Market

PJM REV Market Monitor market seller — Daugherty | © *RTO Insider*

PJM Chief Financial Officer and MRC Chair Suzanne Daugherty informed members that the RTO’s consulting subsidiary, PJM Technologies, has signed a contract to help the Chinese province of Zhejiang develop a real-time energy market.

Daugherty declined to share financial details of the contract but said it will involve three to four full-time equivalent PJM staffers for 18 months. The province, south of Shanghai, has a load equal to almost half of PJM’s.

For security, the PJM employees will be working on dedicated computers separate from the RTO’s network, Daugherty said.

IRM, Manuals Endorsed

The Markets and Reliability Committee unanimously approved the 2017 installed reserve margin (IRM) study results. (See “IRM Reductions,” PJM PC/TEAC Briefs: Sept. 14, 2017.)

The IRM dropped nearly 1 percentage point, from 16.6% to 15.8%, for delivery year 2021/22, thanks largely to an anticipated fleet-wide EFORd (equivalent forced outage rate – demand) reduction from 6.59% to 5.89%. EFORd measures the probability a generator will fail completely or in part when needed.

The reduced EFORd is the result of 7,150 MW in planned retirements with a 14.56% weighted average EFORd, and the anticipated entry of 16,980 MW of new generation with a 4.42% EFORd.

The IRM will be 16.1% for 2018/19 and 15.9% for 2019/20.

The MRC also endorsed the following proposed manual changes with one abstention and no objections:

Manual 11: Energy & Ancillary Services. Revisions, which also include changes to the OA and Tariff, were developed to address capping of intraday offers. The current rule offer caps units that fail the three-pivotal-supplier test, but prohibits reapplying the cap during the unit’s day-ahead commitment or minimum run time. The changes would re-evaluate capped units when offers are updated. The changes would also apply to self-scheduled resources. (See “Debate Continues on Intraday Offers,” PJM Market Implementation Committee Briefs: Oct. 11, 2017.)
Manual 14B: Regional Transmission Planning Process. Revisions developed to add information related to contingency definitions.
Manual 19: Load Forecasting and Analysis. Clarifies when load drop estimates are produced and includes updates from a periodic review of the manual. (See “Cleared PRD Forces Manual Revisions,” PJM PC/TEAC Briefs: Sept. 14, 2017.)

Members Committee

The Members Committee unanimously approved the IRM study results, the Tariff changes for the balancing ratio, and changes to Manuals 11, 14B and 19 approved earlier by the MRC. (See descriptions in MRC briefs above.)

The committee also approved Tariff and Operating Agreement revisions to clarify definitions, as recommended by the Governing Document Enhancement & Clarification Subcommittee.

— Rich Heidorn Jr.