Page 1184 – RTO Insider

June 14, 2018

ERCOT Board of Directors Briefs: June 12, 2018

ERCOT CEO Bill Magness assured his Board of Directors on Tuesday that the grid operator is prepared for the summer heat, despite the retirement of 4 GW of coal-fired capacity since last summer.

Magness highlighted a plethora of meetings staff have held in recent weeks with regulators, media, information officers from state utilities, pipeline and gas companies, transmission owners and other stakeholders. He also noted new demand records set in May and June, which the ISO managed without emergency alerts or conservation appeals.

ERCOT Senior Meteorologist Chris Coleman checks his mike with CEO Bill Magness looking on at the June ERCOT Board of Directors meeting. | *AdminMonitor*

ERCOT recorded new monthly demand records of 67.3 GW on May 29 and 67.9 GW on June 1. Magness told the directors May was the hottest ever recorded in the United States, and the second-hottest in Texas.

“We saw it on the system,” he said. “We’re just getting into summer. Here we go!”

Staff has projected a new summer peak of 72.8 GW in August. It says it has 78.2 GW of capacity available and continues to expect to have enough resources to serve load. (See ERCOT Gains Additional Capacity to Meet Summer Demand.)

Senior Meteorologist Chris Coleman pointed out that heat records in May don’t necessarily equate to a “blazing” summer. He said Texas’ hottest May in 1996 was followed by the 76th hottest summer on record. Of the 20 hottest Mays dating back to 1895, only five were followed by one of the 20 hottest summers.

“We’ll be hotter than last summer, which won’t take a lot,” Coleman said, referring to the 50th hottest summer on record.

Coleman said the expected rains from Gulf of Mexico and Pacific storms over the next week will help tamp down temperatures in the weeks that follow.

“We’ll always take more rain, but substantial rain leads to soil moisture and water in the reservoirs,” he explained. “That will tone down the extreme heat this summer. That’s the type of thing that prevents 2011 from happening again.”

That year remains the state’s hottest on record. The Dallas-Fort Worth Metroplex recorded 40 straight days of 100-degree temperatures — and 71 overall — in 2011.

Coleman is looking at 2013 and 2006 — Texas’ 21st and 42nd hottest summers — as indications of what to expect this summer, and he said there is a two-in-three chance that temperatures will end up between those two years.

He also predicted less hurricane activity than last year, when Hurricane Harvey dumped 52 inches of rain on the Houston area. Coleman said without the La Nina of 2017 or an El Nino, overall activity will probably be at the lower end of the National Oceanic and Atmospheric Administration’s predicted range of 10 to 16 named storms and five to nine hurricanes.

The good news with May’s summer heat?

ERCOT’s year-to-date net revenues have a favorable variance of $8.3 million, and a favorable year-end forecast of $12.3 million.

IMM’s Garza Calls for Evaluation of Local Signals

Beth Garza, director of ERCOT’s Independent Market Monitor, said the ISO should evaluate the market’s ability to send local signals.

IMM Director Beth Garza | *AdminMonitor*

As she reviewed the Monitor’s annual State of the Market report, Garza reminded the board that price signals that incent new generation are a fundamental aspect of a “sustainable, ongoing market.” She said that net revenues (revenues in excess of assumed production costs) over the past six years are far less than the costs of building a new peaking unit, a result of the market’s capacity surplus.

“We have a market that continues to grow and with requirements continuing to increase, which requires sufficient resources to meet those,” Garza said. “But since the start of the nodal market in 2011, the net revenues have not been sufficient to pay the fixed costs of new generation.”

Net revenues in the market were around $110/kW in 2011, but only broke $40/kW last year — and only in the Houston region. The Monitor has estimated the cost of new entry between $80 and $95/kW, based on the value of simple cycle gas turbines.

ERCOT summer peak bill magness — Net Revenues by Year and ERCOT Zone | *Potomac Economics*

“I don’t have a lot of precision, hence the range,” Garza told the board. “We’ve been so far under for so long, it’s hard to get focused on whether [the point of entry] should be $82/kW or $95/kW. I don’t know what that ratio is, but we have certainly seen a half-dozen years or so of very low contributions toward net revenues.”

Garza said congestion costs increased 95% to $967 million over 2016 because of wind generation exports from the Texas Panhandle, construction of the Houston Import projects and Harvey’s aftermath. She expects the Panhandle congestion costs to continue to increase as more wind is built in West Texas without a commensurate addition of transmission infrastructure.

“The Panhandle … contributes to those high costs because of the large differential in generation costs on either side of that constraint,” Garza said. “Wind generation in the Panhandle is at zero or below. The average cost on the ERCOT side is at 20, 30, 40 dollars. That spread is much higher than other constraints.”

The Monitor again included real-time co-optimization on its annual list of market improvement recommendations. (See “Monitor Says Wholesale Market ‘Performed Competitively’ in 2017,” ERCOT Briefs.)

Garza said that real-time co-optimization would make better use of the system’s resources, lower costs, allow for efficient shortage pricing when the market can’t satisfy any of its energy or reserve needs, and allow all supply to participate in the ancillary services markets.

$327M in Tx Projects will Meet Permian Basin’s Load Growth

The board unanimously approved $327.5 million in West Texas transmission projects to address congestion from increasing oilfield load growth in the Permian Basin.

The Far West Texas Regional Planning Group Projects include new construction and upgrades of three 345-kV lines — Riverton-Sand Lake, Sand Lake-Solstice and Solstice-Bakersfield — that staff recommended be designated as critical to system reliability. The board agreed with the recommendation.

Jeff Billo, ERCOT’s senior manager of transmission planning, told directors the projects will allow the region to handle up to 1.7 GW of load. Staff’s independent review of the two Oncor projects indicated local load projections of 880 MW and 1,013 MW for 2019 and 2022, respectively. A year ago, load projections for 2021 came in at 553 MW.

Billo said the region has added 80 rigs in the last year. “It’s the hot spot of hot spots,” he said.

IHS Markit, a global data firm, has predicted the Permian Basin in Texas and New Mexico will become the world’s third-largest producer of oil, behind only Saudi Arabia and Russia. The firm projects production will double to almost 5.4 million barrels a day between 2017 and 2023.

Construction on the Far West Texas projects is expected to begin next year, with completion in 2023.

Board Approves 8 Change Requests

The board remanded back to the Technical Advisory Committee a nodal protocol revision request (NPRR) incorporating an intraday or same-day weighted average fuel price into the mitigated offer cap.

The City of Dallas’ Nick Fehrenbach, representing the commercial consumer segment, had the change pulled off the consent agenda, saying its language was unclear. “I think at best the language is vague and confusing. At worst, it’s an unenforceable clause,” he said.

Fehrenbach said he was unable to come up with a solution with ERCOT staff. Market participants won’t be harmed, he said, because the ISO already uses a manual workaround for exceptional fuel prices.

NPRR847, which cleared the TAC unanimously, is meant to ensure resources are capped at the appropriate cost during high fuel-price events and that LMPs reflect the true incremental cost of fuel.

The board also tabled an accompanying verifiable cost manual revision request (VCMRR021), which aligns the manual with NPRR847 by removing language providing for make-whole payments for exceptional fuel costs.

The board approved four other NPRRs, a pair of other binding document revisions (OBDRRs) and two changes to the Planning Guide (PGRRs):

NPRR837: Updates the Regional Planning Groups’ tier classification rules, among other related improvements and clarifications, to ensure the RPG and ERCOT are reviewing the most appropriate subset of transmission projects.
NPRR851: Establishes a clearly defined disconnection process within the market rules applicable to a transmission voltage connection to the grid that uses one electrical connection for both generation and load services.
NPRR867: Caps the amount of each counterparty’s available credit limit locked for congestion revenue rights auctions at the pre-auction screening credit exposure amount.
NPRR870: Deletes the gray-boxed requirement for ERCOT to post a forward adjustment factors summary report on the Market Information System’s certified area. The information in this report is already provided on each counterparty’s estimated aggregate liability summary report.
OBDRR004: Revises the risk-weighting factors available for assignment to each emergency response service (ERS) time period; describes the process for updating the ERS time period expenditure limits for any subsequent standard contract terms (if money is needed to fund) and the ERS renewal contract period; and updates a table to reflect the risk-weighting factors’ proposed changes.
OBDRR005: Revises the generic transmission constraint (GTC) shadow price cap that is used in security-constrained economic dispatch for base case constraints from $5,000/MWh to $9,251/MWh. The revision also updates the associated examples in SCED and makes an administrative edit to a protocol reference.
PGRR059: Includes RPG-related changes intended to improve and clarify existing processes.
PGRR060: Updates the reliability performance criteria by defining a DC tie’s unavailability as a new contingency and clarifies the voltage level of transformers referred to in the reliability performance criteria.

— Tom Kleckner

June 14, 2018

Conn. Awards 200-MW OSW, 50-MW Fuel Cell Deals

By Rich Heidorn Jr.

New England’s offshore wind industry got another boost Wednesday as Connecticut officials announced they will purchase 200 MW of output from Deepwater Wind’s Revolution Wind project, adding to Rhode Island’s 400-MW procurement.

Rhode Island announced its selection of Revolution last month at the same time Massachusetts agreed to procure 800 MW from Vineyard Wind. (See Mass., R.I. Pick 1,200 MW in Offshore Wind Bids.)

“With demand for 1,400 MW of U.S. offshore wind announced in less than a month, there’s a golden opportunity for heavy manufacturing companies and shipbuilders to invest in American jobs, factories and infrastructure,” said Nancy Sopko, director of offshore wind for the American Wind Energy Association.

The Connecticut Department of Energy and Environmental Protection also announced awards for 52 MW of fuel cells and a 1.6-MW anaerobic digestion project Wednesday.

Maxed out on Offshore Wind

The 200 MW in offshore wind is equal to 3% of Connecticut’s load, the maximum officials were permitted to procure under state law. Combined, the renewable energy procurements are equal to 4.7% of Connecticut’s load.

The selected projects will seek to reach agreements on 20-year contracts with the state’s electric distribution utilities, Eversource Energy and United Illuminating. The contracts will be subject to approval by the Public Utilities Regulatory Authority.

The Revolution project will be in federal waters about halfway between Montauk, N.Y., and Martha’s Vineyard, Mass. Deepwater, majority owned by The D.E. Shaw Group, also is the owner of the 30-MW Block Island Wind Farm, the first U.S. offshore wind project. The company also is pursuing a project off New Jersey in a partnership with Public Service Enterprise Group.

As part of the Connecticut procurement, Deepwater agreed to economic development commitments in New London, including the investment of at least $15 million in the New London State Pier to allow “substantial” portions of the project to be constructed and assembled in the city. It also agreed to contract with a Connecticut-based boat builder to construct one of the project’s crew transfer vessels in the state. This project is expected to spur more than 1,400 direct, indirect and induced jobs, officials said.

Vineyard Wind, which had also bid into the Connecticut procurement, said it will continue work on its Massachusetts project, with construction projected for 2019 and full operations in 2021. “We also will continue to develop the remainder of our commercial lease site with the goal of providing New England states with additional wind energy solutions in the near future,” the company said in a statement.

Fuel Cells

Wednesday’s announcement will double the installed capacity of fuel cells in Connecticut to about 100 MW. State officials said the addition will put the state in the forefront of fuel cell adoption, along with California (210 MW installed capacity) and New York (20 MW).

Deepwater Wind fuel cell Revolution Wind project — Doosan fuel cell | *Doosan Fuel Cell America*

The largest fuel cell (19.98 MW) selected was Doosan Fuel Cell America’s for the Energy and Innovation Park in New Britain. The project, the first phase of an economic development project, will use combined heat and power for heating and cooling businesses, including a Stanley Black & Decker manufacturing plant.

Others selected were Bloom Energy (a 10-MW project in Colchester) and FuelCell Energy (a 7.4-MW project in Hartford and a 14.8-MW project in Derby).

DEEP noted the average price in the fuel cell procurements was 11.6 cents/kWh, down from 15.6 cents/kWh in its 2011/12 procurement.

The Turning Earth Anaerobic Digestion Project in Southington will convert 54,000 tons of food waste and 15,000 tons of yard and woody waste into 90,000 cubic yards of compost and mulch annually.

June 14, 2018May 31, 2024

DC Circuit Upholds FERC Order on PJM FTRs

By Rory D. Sweeney

FERC sufficiently justified its decision to revise how PJM allocates revenues from transmission congestion and its subsequent move to reject requests to rehear the issue, the D.C. Circuit Court of Appeals ruled Tuesday (17-1101).

Several PJM stakeholders had petitioned the court to overturn FERC’s January 2017 order that upheld a September 2016 ruling that modeling assumptions the RTO adopted to address financial transmission rights revenue inadequacy had resulted in unwarranted cost shifts between auction revenue rights holders and FTR holders.

The D.C. Circuit Court meets in the E. Barrett Prettyman Federal Courthouse | HSU Builders

FERC had also accepted PJM’s compliance filing in response to a requirement that it develop a method for allocating ARRs that doesn’t consider extinct generators (EL16-6). (See FERC Accepts PJM’s FTR Plan, Rejects Rehearing Requests.)

The petitioners included Old Dominion Electric Cooperative, American Municipal Power, PJM’s Independent Market Monitor, the New Jersey Board of Public Utilities and the Delaware Public Service Commission. PJM and several stakeholders involved in its FTR markets intervened, including Exelon, Elliott Bay Energy Trading, several Public Service Enterprise Group companies, Appian Way Energy Partners, NRG Power Marketing, DC Energy, Boston Energy Trading and Marketing, Vitol and J. Aron & Co.

The court noted in its decision that between 2010 and 2014, PJM could only fund between 69 and 85% of the prevailing-flow FTRs, so FTR payments were reduced pro rata. That, in turn, reduced the value of ARRs because FTRs were worth less at auction.

PJM’s stakeholders were unable to find consensus on how to address the issue, so the RTO asked FERC to settle it by declaring the current market design unjust and unreasonable. FERC held a technical conference in 2016 and granted PJM’s request, ordering several design modifications. After FERC rejected a request for rehearing, the petitioners appealed the decision to the D.C. Circuit.

The court sided with FERC on all three of the petitioner’s challenges. It ruled that excluding balancing congestion from the funding formula for FTRs was reasonable because including it “reduces the efficacy of FTRs as a hedge.” FERC was also reasonable in requiring the entire market, rather than FTR holders, to bear the costs of the congestion because “FTR holders do not cause and cannot predict the level of balancing congestion” and “are not the sole beneficiaries of balancing congestion,” the court said.

Additionally, the court decided petitioners provided no support for their view that FERC’s actions might endanger FTRs’ exemption at the Commodity Futures Trading Commission.

FERC’s rationale for continuing to net prevailing-flow and counterflow FTRs was also sufficient, the court said. The commission had doubted that “the elimination of netting would improve FTR funding” because that would simply “reallocate FTR revenue inadequacy among various market participants without actually addressing the fundamental issues associated with FTR revenue inadequacy.” The commission also reasoned that netting is “the functional equivalent of applying the same payout ratio to both prevailing-flow and counterflow FTRs,” so all FTRs are treated equally.

Finally, the court rejected the argument that FERC should not have eliminated outdated transmission paths from the formula used to allocate ARRs. While petitioners instead wanted FERC to artificially increase growth forecasts, the commission “adequately explained why it preferred to rectify the root cause of the problem rather than pursue a remedy that could distort the planning process, such that transmission planning is not based on expected system conditions,” the court said.

The court also said it saw “no cause to displace FERC’s considered policy judgment on this matter.”

June 13, 2018

FERC: No Emergency on Grid

By Rich Heidorn Jr.

WASHINGTON — FERC commissioners told Congress yesterday the grid is not facing a national security emergency, as the Trump administration has claimed in its call for saving at-risk coal and nuclear generation.

national security emergency ferc coal nuclear trump — The Senate Energy and Natural Resources Committee held its first oversight hearing with all five FERC commissioners in a decade | © *RTO Insider*

At an oversight hearing before the Senate Energy and Natural Resources Committee, Sen. Martin Heinrich (D-N.M.) asked the five commissioners whether any of them believed there is a national security emergency in the wholesale power markets.

“I do not, senator,” Commissioner Cheryl LaFleur responded.

“Anyone answer that with a yes?” Heinrich asked. None of the other commissioners spoke.

But coal-state senators also got commissioners to offer soundbites supporting their positions.

When Sen. John Barrasso (R-Wyo.) asked whether the commissioners agreed on the need to keep coal in the generation mix, Chairman Kevin McIntyre responded by reiterating his support for “an all-of-the-above strategy.”

McIntyre also agreed under questioning from Sen. Joe Manchin (D-W.V.) that Energy Secretary Rick Perry has the authority to issue emergency orders under the Federal Power Act and Defense Production Act of 1950. “There’s no question that the secretary does,” McIntyre said.

The two and a half-hour hearing — the first Senate oversight hearing involving all the FERC commissioners in a decade, according to Chair Lisa Murkowski (R-Alaska) — also touched on LNG and pipeline project licensing and the Public Utility Regulatory Policies Act (PURPA).

But President Trump’s June 1 directive that Perry prevent additional coal and nuclear plant retirements dominated the discussions. (See Trump Orders Coal, Nuke Bailout, Citing National Security.)

Most Democrats, led by ranking member Maria Cantwell (D-Wash.), blasted the proposal. LaFleur and Commissioners Richard Glick and Rob Powelson were the most outspoken in their opposition to the subsidies.

Commissioner Neil Chatterjee was somewhat more sympathetic, saying some critics had been too quick to dismiss DOE’s draft memo, which seeks to justify capacity and energy payments to prevent plant retirements.

“There are a number of points in the memo that are thoroughly well cited and researched,” he said. “I think we can have disagreements about what the remedy may be, but I think they raise a real issue … that we need to look at.”

While acknowledging the vast majority of outages are the result of distribution and transmission failures rather than losses of generation, Chatterjee added, “We shouldn’t assume that that good fortune will continue.”

‘Policy Vacuum’

Murkowski acknowledged, “I have my concerns with the steps the Department of Energy is reported to be considering.” But she said DOE was trying to fill a “policy vacuum” created by FERC’s failure to act more quickly on resiliency concerns.

“In my view, FERC should be pointing the way on policy improvements that address grid vulnerabilities, while reaffirming our commitment to competition in wholesale power markets. Frankly, as one who has been concerned about this issue for years now, I find it unfortunate that prior commissions did not lead more effectively,” she said. “We must increase the light and lower the heat in policy debates about price formation, state resource preferences and subsidies.”

LaFleur, the commission’s longest-serving member, defended the commission’s work in navigating the shift to more gas and renewable generation.

“We work to ensure resilience by overseeing market changes to increase compensation to resources that are on line in times of system stress and extreme weather, including baseload resources. In the energy market, we [have] worked on a number of steps since 2014 to improve price formation to make sure the markets send the correct price signals,” she said.

LaFleur said the commission should continue to craft “tailored regional solutions” to address tensions between wholesale markets and state policy favoring certain generators.

“Indeed, I believe the resource turnover we’re experiencing is an expected consequence of markets and technological change, and the lower prices that result from well-functioning markets are a benefit to consumers — not a problem to be solved, unless reliability is compromised,” she said.

“We cannot try to stop the natural evolution of this industry by claims there’s a national security emergency unless there is evidence to suggest an emergency actually exists,” said Glick. “… We need to keep on being vigilant and keep monitoring the situation. But we also need to be wary of people using the situation — or the potential situation — as an excuse to achieve market changes they haven’t been able to achieve otherwise.”

Cantwell said the administration’s “radical” plan could cost consumers billions, telling the commissioners that maintaining “‘just and reasonable’ [rates is] your job … That is why we have a FERC.”

But Sen. Joe Manchin (D-W.V.) dismissed concerns that the subsidies would raise prices. He noted that the draft DOE memo envisioned subsidies for two years while the agency studies grid risks. “You’re acting like it’s going to be forever,” he told the commissioners.

When he pressed the commissioners to identify any generation sources other than coal and nuclear that can provide 24/7 “baseload” power, Glick mentioned “some hydropower,” while Powelson volunteered natural gas.

‘Human Impact’

Sen. Shelley Moore Capito (R-W.V.) complained that renewable subsidies and environmental regulations had “led to a failure that has been punishing” coal generation and the communities that depend on them.

Glick and Chatterjee expressed sympathy for those who have lost their jobs due to coal and nuclear plant closures. But they said providing relief to such workers is the job of Congress and state legislators, not FERC.

Chatterjee said he understood the “human impact” of plant closures because of his visits to West Virginia coal country with Capito and the Colstrip coal plant with Sen. Steve Daines (R-Mont.).

“That is not something that we factor into our record. We will look at plants like Colstrip and make a determination based on … whether there would be threats to reliability in the event the plants shut down,” he told Daines. “But that’s certainly something that’s well within your purview.”

June 13, 2018

ERCOT’s Botkin Named to Texas PUC

Texas Governor Greg Abbott on Monday appointed ERCOT Director of Communications and Government Affairs Shelly Botkin to fill the final vacancy on the state’s Public Utility Commission. Her term expires Sept. 1, 2019.

Shelly Botkin ERCOT PUC of Texas — Botkin

Botkin’s appointment will bring the three-person commission back to full strength. She will fill the position vacated by Brandy Marty Marquez’ departure in March. (See Marquez to Depart Texas PUC.)

Botkin will be sworn in Wednesday and attend her first PUC open meeting Thursday.

The 46-year-old Botkin has been with ERCOT since 2010. She spent the previous 10 years as a senior policy analyst in the Texas Senate and House of Representatives.

ERCOT CEO Bill Magness said in the statement the ISO looks forward to working with Botkin.

“Shelly’s knowledge of electric market policy and the regulatory and legislative process has been a tremendous asset to ERCOT over the last eight years,” he said.

Shelly Botkin ERCOT PUCT — The Texas Governor’s Office is in the state capitol building, constructed from 1882 to 1888.

The PUC has seen a complete turnover of commissioners in little more than a year. Donna Nelson and Ken Anderson, the two longest-serving commissioners, both left the agency last year. They were replaced by Chair DeAnn Walker and Arthur D’Andrea, respectively.

— Tom Kleckner

June 13, 2018

Solar Inverter Problem Leads CAISO to Boost Reserves

By Jason Fordney

CAISO will make permanent a once-temporary practice of boosting its power reserves to account for utility-scale solar tripping offline because of an inverters problem, something NERC has identified as a major reliability issue.

When solar generation is at its peak, CAISO will set the operating reserve target at either 15% of the total solar production forecast or the maximum NERC/Western Electricity Coordination Council requirement, whichever is greater.

caiso utility-scale solar inverters power reserves — CAISO says the inverter problem affects utility-scale solar, not rooftop systems | *Sarah Swenty/USFWS*

The ISO has worked with solar operators to reprogram inverters since last year, CAISO Shift Supervisor John Phipps said Monday at a Market Performance and Planning Forum. Some of the inverters began working properly after reprogramming, but others are hard-wired and still subject to tripping. Phipps said 2,700-2,800 MW of generation across the whole ISO system cannot be reprogrammed.

“They are not in any one regional area; they are spread out across all the plants in California,” Phipps said during a presentation, adding that the issue is not affecting behind-the-meter or storage resources.

The inverters, which convert photovoltaic DC output to utility frequency AC, sometimes trip offline to protect the systems during voltage fluctuations. CAISO began procuring additional reserves a year ago, after the problem occurred in August 2016 because the Blue Cut fire in Cajon Pass caused transmission line faults and disconnected 1,200 MW of solar. (See CAISO Boosts Reserves After August Event Report.)

CAISO CEO Steve Berberich last month cautioned the ISO’s Board of Governors about the seriousness of the problem, which caused the loss of 860 MW of solar resources on April 20. (See CAISO Board Approves Forecast Error Measures.)

The inverter problems have so far triggered two NERC alerts, one on June 20, 2017, and the other on May 1 of this year. NERC said the problem could also affect non-bulk power systems and recommended all operators follow recommendations spelled out in the more recent alert.

“While this NERC alert focuses on solar PV, we encourage similar activities for other inverter-based resources such as, but not limited to, battery energy storage and wind resources,” the agency said in the May 1 alert.

Ancillary Service Scarcity Increases

CAISO has seen an increase in ancillary service scarcity events in the real-time market, Director of Market Analysis and Forecasting Guillermo Bautista Alderete told the forum. He said while the number of incidents has increased, the magnitudes are small, with about 75% of the scarcities at fewer than 10 MW. The increased incidents stem from a confluence of factors and changes in the market, he said, including the solar operating reserve requirement.

Most recently, CAISO issued three notices of ancillary service scarcity events for May 3-6, May 15 and May 23-28, nearly all of which were associated with regulation up service and mostly in the SP26_EXP region in Southern California. In 2018, 46% of the scarcities happened in SP26_EXP, 35% in NP26_EXP and 19% in CAISO_EXP.

CAISO pays an ancillary services scarcity price when it is unable to procure the target quantity of one or more ancillary services in the integrated forward market or real-time market runs. About 52% of the scarcities are due to limits in generator telemetry, which is the process whereby a generator supplies the ISO with real-time data. Mismatches between telemetry and real-time needs require the ISO to procure additional capacity in the real-time market. About 33% are due to generator outages and re-rates, and 15% are categorized as “other.”

CAISO’s Market Monitor in its 2017 State of the Market report noted that scarcity events in the real-time market “increased significantly” from 26 in 2016 to 54 in 2017.

June 12, 2018

ISO-NE Begins Real-time Dispatch of Demand Response

By Michael Kuser

ISO-NE said last week it has become the first U.S. grid operator to put demand response into its energy dispatch along with generating resources.

The RTO’s price-responsive demand (PRD) structure, which took effect June 1, enables full integration of DR into its energy, reserves and capacity markets.

Like generators, active DR is now eligible to submit day-ahead and real-time energy offers and receive wholesale market payments for energy, operating reserves and capacity. DR resources can be co-optimized in the RTO’s economic dispatch, committed by the RTO a day ahead and dispatched in real time.

“The new thing is that active demand response resources can participate by submitting price and amount offers in the day-ahead and real-time energy markets, and they can set price,” said ISO-NE spokeswoman Marcia Blomberg.

Modest Impact

Blomberg said the impact of the changes on the markets has been modest thus far.

“On several hours on several days, we’ve seen small amounts [of DR] clearing,” she said of the RTO’s experience since the beginning of the month. “On other days, no DR cleared.”

Active DR resources are dispatchable because they can reduce consumption at will by reducing industrial production or switching to on-site generators or storage. Passive DR — energy efficiency and distributed solar generation, for example — are not dispatchable.

iso ne active demand response — Potential Peak Reduction from U.S. ISO and RTO Demand Response Programs | *Assessment of Demand Response and Advanced Metering Staff Report, FERC, December 2015*

Active DR was previously able to offer load reductions at a price in the day-ahead energy market, but their offers were administratively evaluated after the market had cleared. DR offers were not used to determine the optimal dispatch of resources or to set price.

Both active and passive DR have been able to participate in the capacity market since 2006. Participating DR was dispatched only during grid emergencies, Blomberg said.

In March 2011, FERC Order 745 required RTOs/ISOs to pay active demand resources the market price for helping to balance real-time supply and demand.

‘Enormous Project’

Integrating active DR into the markets “has been an enormous project, requiring the ISO to not only develop and implement extensive market rule changes, but to update computer systems and processes related to grid operations and market settlement,” Henry Yoshimura, director of demand resource strategy, explained in the RTO’s newsletter. “Consequently, the full integration of active demand resources was achieved in a staged approach.”

Facilities that reduce their consumption of electricity are known as demand response assets (DRAs). DRAs under 5 MW can be mapped to a DR resource that participates in the energy and reserve markets. A DRA that is 5 MW or larger must participate individually as its own resource.

DR resources can be mapped to an active demand capacity resource (ADCR) for participation in the capacity market. Passive DR resources may only participate in the capacity market.

June 12, 2018

PJM PC/TEAC Briefs: June 7, 2018

VALLEY FORGE, Pa. — PJM is planning to add another volume to its Manual 14 series by splitting out the requirements for generation interconnection from Manual 14A into a separate Manual 14G, staff told attendees at last week’s Planning Committee meeting.

PJM’s Lisa Krizenoskas walked through the separation, noting that the new manual will be organized by generators under 20 MW, over 20 MW and other types of generation.

Staff said that rules for handling multiple generators behind the same point of interconnection will be addressed after the manual split is endorsed, but Ryan Dolan from American Municipal Power questioned why they wouldn’t try to sort out both issues simultaneously. Krizenoskas said the new rules might delay the separation, which is meant to provide clarity for generators.

Load Model Selection

PJM’s Patricio Rocha-Garrido presented PJM’s proposed load model for the 2018 reserve requirement study focused on the 2022/23 delivery year. Staff recommend the same model used last year, along with again switching the peak week for regions external to PJM, known as the “world” in the analysis, to a week that doesn’t coincide with PJM’s peak.

Left to right: Jason Shoemaker, Ken Seiler and Anisha Fernandez | © *RTO Insider*

Staff used 18 years of load history, 23 years of weather history and at least seven years of hourly loads to develop 78 model candidates. The candidates were compared to PJM’s “coincidental peak 1” distribution analysis, which represents the highest load forecasted for the summer of the forecast year, using two separate approaches. The comparisons found that the 10-year model from 2003 to 2012 used in 2016 and 2017 remains the best choice because it was a close second to a nine-year model in the comparisons but includes an extra year of load data.

The “world” peak week was again switched to not coincide with PJM’s because the peaks haven’t coincided in 11 of the past 19 years.

Dolan questioned why PJM doesn’t use more-recent data to reflect changes in demand-side activity.

“The world is changing, and I think … [the] ability to control our load is much different from what it was in the earlier years of your data set,” he said.

Facility Ratings Fine

PJM’s Mark Kuras discussed staff’s process for confirming transmission owners’ facility ratings, concluding that “TOs have demonstrated that strict processes and controls are already in place to ensure facility ratings used in PJM operation are determined based on technically sound principles” and that “there are no requirements for PJM to approve or verify a TO’s ratings or do any kind of consistency check.”

The discussion came after AMP and the PJM Industrial Customer Coalition criticized how TOs calculate the ratings. (See “Facility Rating Concerns,” PJM PC/TEAC Briefs: April 5, 2018.)

TOs are required by NERC Standard FAC-008-3 to develop and adhere to a methodology for developing facility ratings, but they aren’t required to publish it. Kuras noted that PJM publishes the final facility ratings on a public page.

“I think this presentation shows that, in and of itself, there are no issues with FAC-08” and how it’s implemented, PJM’s Aaron Berner said. “If that continues to be a concern, we can have those further discussions” about specific projects with proposing entities, he said.

Dolan said part of the concern is that in the process for determining whether they can develop a successful project bid, prospective developers must seek information that could make the incumbent TO aware of the potential proposal in a competitive window, which creates competition issues.

TO Planning Criteria Updates

Both Public Service Electric and Gas and American Electric Power provided updates to their planning criteria filed earlier this year with FERC.

AEP announced it will no longer use Rate A for category P1 contingencies for lines above 345 kV and instead evaluate those facilities using Rate B for P1 through P7 contingencies.

PSE&G’s Glenn Catenacci presented his company’s updates, which modify pre-fault voltages, certain contingencies and other definitions. Dolan noted that several of the changes create requirements for building additional system infrastructure.

Among the changes was including non-firm transfers in models when considering common-mode outages. The presentation to stakeholders of the change comes after FERC rejected a complaint from the New Jersey Board of Public Utilities seeking to revise how infrastructure costs are allocated, and that would have included several merchant lines into New York City that have changed their transmission rights to non-firm transfers. (See PSE&G on the Hook for Bergen-Linden Costs.)

Dolan questioned including non-firm transfers in the calculations because they wouldn’t be included in allocating any costs for any system upgrades that subsequently become necessary.

“We think the people driving the need for transmission should be paying for it; however, there is a reliability issue,” PSE&G’s Esam Khadr said. “We need to address that reliability issue.”

Khadr said he can’t terminate non-firm transmission service, which hadn’t been planned for previously because “it was not as prevalent as it is today.”

“We have an obligation to all of our neighbors … to maintain reliability to the bulk power system,” said PJM’s Ken Seiler, who chairs the PC.

Staff haven’t engaged with NYISO on non-firm transfers in planning criteria, but he said, “We’ll evaluate it and certainly make any recommendations back to the Planning Committee.”

Dolan and Khadr also sparred on whether to use breakers as an option for maintaining system reliability. The discussion came as part of PSE&G’s clarification of how it will handle N-1-1 situations and its decision to not permit opening breakers.

“We’re not going to plan a system by further degrading the system by opening breakers,” Khadr said. “You’re taking away that redundancy by taking away that breaker.”

“Or utilizing its flexibility,” Dolan pressed.

“We disagree,” Khadr responded.

Nuke Closures Spark Transmission Upgrades

PJM’s Phil Yum presented attendees at the Transmission Expansion Advisory Committee meeting 23 baseline projects sparked by FirstEnergy Solutions’ announcement in April that it plans to shutter its three nuclear facilities within three years. (See FES Seeks Bankruptcy, DOE Emergency Order.)

The projects would cost upward of $190 million combined, and because they are all within the three-year window for “immediate need” projects, they would all be assigned to the incumbent TO. PJM’s Jason Connell confirmed that was the reason they can’t be opened to a competitive bidding window. The projects are in the transmission zones of AEP, Duquesne, and FirstEnergy subsidiaries Allegheny Power Systems and Penelec.

Several of the projects are associated with the closure of the Davis-Besse nuclear plant, which is scheduled to deactivate on June 1, 2020. The projects can’t be implemented until a year later, but PJM’s planning group has discussed the issue with RTO operations and found operating measures that can mitigate the reliability impacts in the interim.

AMP’s Ed Tatum questioned why PJM didn’t include more details in the project descriptions. Connell said, “Certainly the scope of the timing is a little different” because of the deactivations. “We were on a very, very accelerated timeline” to determine “as best was we could do in the time frame that we had,” he said.

Dolan questioned what might happen to the projects if FES ultimately decided not to deactivate the plants. Seiler dismissed the implication, saying, “Folks don’t play games with this type of thing” because it includes jobs, communities and other large-scale factors. However, he acknowledged, “I’m not saying it couldn’t happen in the future” based on a federal mandate or policy changes.

“We’ve never had any situation like this before. I agree it’s not gamesmanship or anything like that, but things could change very quickly,” Tatum said.

Seiler said money is already being spent on the engineering portions of the projects but said that if the decisions are reversed, “I think that would happen sooner rather than later.”

— Rory D. Sweeney

June 12, 2018

PJM Operating Committee Briefs: June 5, 2018

VALLEY FORGE, Pa. — PJM experienced 77 emergency procedures in May, staff told attendees at last week’s Operating Committee meeting.

Calling it a “busy month,” PJM’s Chris Pilong said the emergency procedures included the first time the RTO has had to order load shedding since implementing its Capacity Performance rules in 2015. (See PJM Experiences First Load Shed in the CP Era.)

The events resulted in a portion of the load forecasting error exceeding its 3% target for the first time since July. The on-peak forecasting error was 3.08%, and the off-peak 1.69%, putting the overall error at 2.38%.

While the error increased in some transmission zones, East Kentucky Power Cooperative posted a 3.3% error, the lowest level in the past 10 quarters.

Load Shed Event

Pilong explained that five facilities were involved in the event. Three 138-kV lines in the area were on planned outages that day. A transformer and additional line tripping out of service triggered “multiple” contingency overloads, which potentially could have resulted in a cascading outage if another facility was lost, Pilong said. Based on that analysis, PJM ordered a pre-emptive load shed to reduce the contingency flow on the Edison-Kankakee line. Within 15 minutes of issuing the order, the transformer was restored, and PJM canceled the load shed nine minutes later.

“Given the timeline, we didn’t need to, but we were definitely looking at [dispatching demand response or behind-the-meter generation in area] and considering those as well,” Pilong said.

The load shed triggered performance assessment intervals (PAIs) that lasted about 30 minutes. While PAIs can trigger significant nonperformance penalties or performance bonuses, none resulted from the event, staff said. The incident was isolated to a small area of northwest Indiana that includes fewer than four generation owners, so PJM’s confidentiality rules prevent staff from releasing any additional information without the owners’ agreement. PJM’s Adam Keech said staff are working with owners to see if they can agree on releasing anything else.

Keech said PJM determined which units were involved by looking at any units that could have increased output to help alleviate the constraint for which the load was shed.

Event Analysis to Follow

While he couldn’t provide specifics on why the event yielded no penalties or bonuses, Keech advised stakeholders to “just remember we are in a year where we are not 100% CP,” referring to the interim base capacity designation PJM implemented as it transitions to the CP requirement that a resource always be available. Base capacity doesn’t have that requirement.

Left to right: Bob O’Connell, Panda Power Funds; John Horstmann, Dayton Power and Light; Dave Pratzon, GT Power Group | © *RTO Insider*

GT Power Group’s Dave Pratzon asked that staff analyze why the three 138-kV lines were allowed to be on planned outages simultaneously because it potentially puts “a few unlucky generators” at financial risk for something they can’t control.

“That’s potentially a large dollar impact for something that potentially has nothing to do at all with generator issues,” he said.

That question and the cause of the facilities tripping are “exactly what we’re looking at as part of the follow up,” Pilong said.

Several stakeholders asked PJM to find better ways to communicate the extent of the incident. RTO staff said they can only target messaging to the level of the transmission zone, even though the event affected a much smaller area, causing many stakeholders to wonder whether they were involved or not. Pilong said the conditions would have to be exactly the same for any refinement of the communication to be more selective, and that’s “probably unlikely.”

Besides, response to the event was unexpectedly quiet, despite the potential confusion.

“Oddly, we only got one phone call,” Pilong said. “It was, to be honest, a little bit surprising.”

Beyond that call, “there was no other anomalous behavior that was obvious or impactful,” he said, adding that system operators’ advice was the same as it would have been for any unit: follow the dispatch signal PJM provides.

Related Updates

Later in the meeting, PJM’s Alpa Jani explained that the load-shed directive was posted at 1:34 p.m. and was effective for 1:22 p.m. Any units that receive system notifications for the AEP transmission zone received the message because the area around the Edison substation where the equipment tripped is not defined as a subzone.

In another presentation, PJM’s Pete Langbein discussed how better “coordination” with behind-the-meter generation, also known as non-wholesale distributed energy resources, could help decrease load forecast errors or mitigate load sheds.

PJM is proposing to identify all such non-wholesale DER of greater than 1 MW on an annual basis, primarily through public Energy Information Administration data. Transmission owners would verify the data and include additions as available so they can be modeled in PJM’s planning and operations tools. The TOs would communicate downstream to the resources as necessary during events to avoid load sheds or dumps. Langbein said draft manual and Tariff language is being introduced in the DER Subcommittee and will move through stakeholder endorsement from there.

Security Initiatives

PJM’s Colin Brisson reviewed security initiatives planned for the RTO this year.

“Critical infrastructure in geopolitics is becoming a higher-priority target” and has hit the energy sector, he said. “We’re actually catching up to the curve where many companies are at.”

PJM is implementing geo-IP blocking, which blocks outside computers from interacting with the RTO’s network if its unique digital signature (or IP address) originates from “high-risk countries,” which Brisson didn’t identify. The technology will be rolled out “increasingly” throughout the year, he said.

The RTO is also implementing two-step verification, which means that along with providing the right password, users will have to tie their accounts to their devices using a “token” to log onto PJM’s network. Once a token is verified, users will be able to log on from that device without going through the process again. Training will begin on Aug. 15 and “full production” to members is scheduled for Oct. 10.

DMS

PJM’s Maria Baptiste announced the Data Management Subcommittee has decided to stop scheduling DMS-Joint meetings and instead hold them on an ad hoc basis as needed to address issues because of “very limited participation.” DMS-Confidential meetings will continue on their existing schedule, and several parts of the DMS-Joint will transition to the Confidential group, including reviewing NERC lessons learned.

The subcommittee will still have work to do. PJM’s Shaun Murphy announced that staff plan to ask the DMS to investigate why the quality of phasor measurement unit (PMU) data has been degrading. He presented a graph showing spikes in error percentages in various transmission zones through the RTO since February 2017. The issues include time, synch and drop errors, planned outages, missing samples and issues with engineering limits, such as threshold, noise and topology.

“On average, we’re starting to see they typical error rate starting to climb,” he said.

The DMS will investigate the impact of the data quality on applications that use the PMU data, enhancing the definition of “data quality,” improving real-time data quality monitoring, reviewing data quality requirements in manuals and guidelines for device outages.

30-Minute Reserve Vote Deferred

PJM had hoped to receive OC endorsement for its planned procurement of 3,784 MW for real-time 30-minute operating reserves, but the vote was deferred because the topic wasn’t included as a voting item on the agenda and came near the end of the three-hour meeting. Based on an analysis of potential reserve shortages, PJM estimates it should secure nearly 3,800 MW of a new 30-minute real-time reserve product. (See “30-Minute Reserves Target Set,” PJM Operating Committee Briefs: May 1, 2018.)

Synch Reserve Response

The RTO experienced one synchronized reserve event of more than 10 minutes in the first quarter, PJM’s David Kimmel said. Of the 1,897 MW estimated for the Tier 1 response, 510 MW responded, or 27%. Demand-side response was assigned all of the Tier 2 response. Of the 113 MW assigned, 58 MW responded, or 51%.

There were three events altogether, all of which occurred in January. Overall, 37% of Tier 1 estimates actually responded, or 2,029 MW. All of the 933 MW of generation assigned Tier 2 response responded, while 341 MW responded of the 397 MW of demand-side response assigned to Tier 2, or 86%.

The events resulted in $1.15 million of Tier 1 credits and $6,666 of Tier 2 penalties.

Skepticism of Gen Capability Changes Continues

Stakeholders remain skeptical of PJM’s plan to revise procedures for generators’ capability testing requirements, which has the potential to reduce generators’ capacity injection rights (CIRs). For several months, PJM’s Jerry Bell has been presenting data analyses to justify the changes to using median capacity factors, arguing that the RTO’s current methods using average capacity factors overestimate what units can realistically be expected to provide. But stakeholders have been concerned about losing value they’ve already paid for. (See “CIR Questions,” PJM Operating Committee Briefs: May 1, 2018.)

Generators are concerned that some existing or planned CIRs could be potentially stranded through PJM’s proposal because it would reduce how a plant’s output is measured for the purposes of qualifying for CIRs.

“PJM is being kind of cavalier with other people’s investments. … There are other ways to do this,” Dayton Power and Light’s John Horstmann said. “I don’t think you’ve addressed the transition nor the compensation adequately. … These interconnection investment costs are not linear.”

He reiterated a request for a special session to discuss the implication of the proposed changes, to which PJM staff ultimately agreed.

Bell’s presentation last week focused on the relationship between summer weather and production from hydroelectric dams. Among PJM’s proposed changes is limiting facility testing to July and August and eliminating June from the testing window. Bell’s analysis showed that hydro capability dips in July and August compared to June.

“As river temperature increases, generator capability wanes, but the majority of the capability decrease can be attributed to the cooling towers that are placed in service incrementally as river temperature increases and control of thermal discharge is needed,” Bell said. “These are the kinds of issues I’m having and why I want to see full plant testing.”

Net Generation/Capability vs. River Temperature | *PJM*

He said a “blanket” RTO calculation is infeasible because conditions vary throughout the RTO’s footprint and there will always be a situation where the analysis won’t be applicable, “so I’d rather just have everybody test in July or August.”

Several generation owners expressed concerns with the plan, such as the constraints of being able to test during a more compressed timeline.

“We just don’t know how we would get this done in two months,” Exelon’s Sharon Midgley said.

“PJM is kind of cavalier with other people’s investments. … There are other ways to do this,” Horstmann said. “I don’t think you’ve addressed it adequately. … The investments are not linear.”

“I’m open to suggestions, but … I want to make sure that everybody understands that when you use the average capacity factor, you are overstating your ability to meet load during peaks and we need to rectify that situation,” Bell said.

Some stakeholders suggested tailoring the requirements to specific unit characteristics, though Bell envisioned some concerns with that.

“Then it becomes somewhat discriminatory to some folks … but if we can work that out, I don’t have a problem at all,” he said.

He said units with “questionable test” results would likely be the first asked to retest under the new rules, but “there will probably be some folks that I would never even look at them.” Other units likely to be contacted are those whose ambient conditions change during the season.

John Brodbeck of EDP Renewables said the plan creates CIR issues for generation in the interconnection queue that will fund network upgrades and “it sort of cries out for a problem statement.” PJM staff did not respond to the suggestion.

— Rory D. Sweeney

June 12, 2018

PJM Market Implementation Committee Briefs: June 6, 2018

VALLEY FORGE, Pa. — At PJM’s Market Implementation Committee meeting last week, RTO staff outlined their proposal for registering aggregations of seasonal demand response resources that can’t comply with the year-round requirements of Capacity Performance. The current process fails to account for some of the resources’ overall capability depending on how they are aggregated.

PJM’s Andrea Yeaton and Terri Esterly explained the proposed revisions, which would dispatch resources individually based on their seasonal ability but account for them cumulatively for the purposes of CP. They said the changes provide greater dispatch flexibility while also reducing the administrative burden and minimizing unaccounted-for capability.

Joe Bowring, PJM’s Independent Market Monitor, expressed concerns about the proposal, notably in how it allows resources to aggregate across zones when the resources should be accounted for on a nodal basis as other resources are.

The proposal will be discussed at next month’s meeting to provide more clarity. Staff want it to become effective for the 2019/20 delivery year.

Response to FERC’s Cost Allocation Order

PJM’s Ray Fernandez outlined staff’s plans to address FERC’s order on the RTO’s procedure for allocating the costs of major transmission projects. The issue had dragged on for more than a decade in court orders and disputes between stakeholders, but after more than a year of negotiations, FERC last month approved a settlement agreement filed in June 2016 (EL05-121).

A large majority of stakeholders agreed to the settlement, which created a cost allocation formula for projects approved prior to Feb. 1, 2013, when PJM abandoned a “postage-stamp” method that billed all utilities in proportion to their load, regardless of where the projects were located. Several stakeholders, including Direct Energy and the Retail Energy Supply Association, had protested the agreement. (See Despite Lengthy Negotiations, PJM Cost Allocation Settlement Still Finds Detractors.)

Fernandez said staff were considering requesting a 30-day extension, which they filed later that afternoon. The motion requests an extension of the RTO’s compliance filing deadline to July 30, seeking a FERC response by June 14. PJM said in the request that it would affect the allocations for more than 100 baseline transmission projects.

The settlement revises the allocation for certain projects, effective back to Jan. 1, 2016, for which costs were assigned under the 100% load-ratio share method FERC had previously approved. Affected projects include those that are 500 kV or above and any associated “necessary lower-voltage facilities” as defined in PJM’s Tariff. The allocation for all such projects will be split 50% on the original annual load-ratio share basis and 50% on the solution-based distribution factor (DFAX) method.

There is also a “black-box” settlement for projects from 2007 through 2015 that will have billing credits or charges based on revisions to Appendix C of Schedule 12-C in the Tariff that will be allocated over the next 10 years.

The revisions will show up in resettlements of wholesale bills: line 1108 for the reallocations and a new charge on line 1115 for the black-box settlement, Fernandez said. The reallocation charge will have to fit 30 months of resettlements into 12 months of billing.

“That’s the way the settlement agreement is defined,” Fernandez said.

GT Power Group’s Jeff Whitehead asked whether the resettlements would be accounted for as adjustments going back to 2016 or a one-time current resettlement.

“If it’s an adjustment going back to 2016, it’s going to be challenging to pass that through” to customers, he said. Retail energy suppliers “can probably only pass that through to customers you still have from 2016, which might be unlikely.”

PAI Fallout

PJM’s Adam Keech provided more information on the performance assessment intervals (PAIs) that occurred on May 29. PJM experienced its first PAIs — along with its first load shed — since implementing them as part of its major Capacity Performance overhaul in 2015. The incident occurred after a transmission line and a transformer at the Jackson Road substation in American Electric Power’s transmission zone tripped out of service, which — combined with three other transmission lines that were on planned outages — caused concerns about being able to deliver power in a section of northwestern Indiana. (See related story, “Load Shed Event,” PJM Operating Committee Briefs: June 5, 2018.)

A PAI is triggered when PJM determines a supply reliability issue exists, and provides credits for generators that overperform their capacity commitments and penalties for those who underperform. No credits or penalties were assessed in the incident, which Keech noted was at least partly because PJM still has “base capacity” in this delivery year. Base capacity was developed as part of the transition to CP and doesn’t have the same always-available requirements as CP resources. Because the event was localized to a small area that included less than four generation owners, Keech said PJM’s confidentiality rules prevented him from releasing more information.

Direct Energy’s Marji Philips voiced concern that how PJM assesses PAIs appeared “extremely discretionary.” Keech disagreed, saying “there was no ambiguity on” the assessment and that the lack of charges or credits was “not because we exempted people arbitrarily.”

“I think until we get more clarity, that’s the only reasonable assumption,” Philips said.

Citigroup Energy’s Barry Trayers said that reporting the calculated bonuses and penalties shouldn’t be a market-sensitive issue.

“I don’t see the market gain or loss by reporting … winners or losers,” he said. “I just don’t see the results of this being a market-sensitive” issue.

Accounting for Maintenance Costs in Cost-Based Offers

It remains unclear what package of revisions stakeholders are likely to endorse regarding whether maintenance costs are includable in cost-based energy offers. PJM believes they belong in plants’ variable operations and maintenance (VOM) costs that are part of energy-market offers, while the Monitor argues they are not short-run marginal costs that belong in energy offers but instead avoidable costs that are includable in the in a unit’s capacity offer. The issue was set to receive an endorsement vote at the May Markets and Reliability Committee meeting, but stakeholders instead agreed to kick it back to the MIC for further discussion. (See “VOM Remanded,” PJM Markets and Reliability Committee Briefs: May 24, 2018.)

PJM’s Tom Hauske presented an analysis that suggested the RTI’s proposal would raise costs by $8.1 million per year. He argued the Monitor’s assumptions on the issue were the worst case, short-term and low-probability. The Monitor’s Catherine Tyler and Joel Romero Luna presented an analysis arguing that PJM’s analysis misses the effect of higher unmitigated offers, fails to account for start-up and no-load costs and ignores cyclic starting and peaking factors.

They said 61% of combustion turbines they reviewed already have maintenance adders higher than the Energy Information Administration’s benchmarks, as do 19% of the combined cycle gas-fired turbines. They pointed to 2017 data that shows a $1/MWh increase in energy offers equates to a $14 million increase in uplift. Their proposal would lower cost-based energy offers from the status quo, while the PJM proposal would raise them, the noted.

Currently, an AEP proposal that used default EIA data is the main motion that was endorsed by the MIC for consideration at the June MRC. Greg Poulos, the executive director of the Consumer Advocates of the PJM States (CAPS), said one of his members plans to move the Monitor’s proposal for an endorsement vote at the meeting.

Long-term FTRs Undercut Annual FTRs

Despite an impassioned argument from the Monitor’s Howard Haas, stakeholders voted to endorse PJM’s plan for revising its long-term financial transmission rights market. PJM’s proposal received 178 votes in favor, 13 opposed and 53 abstentions for a favorability of 93%. The Monitor had offered as many as three proposals but dropped it to one for the vote. That proposal received 40 votes in favor, 147 opposed and 58 abstentions for a favorability of 21%. PJM’s proposal was preferred over the status quo by 79%, or 131 votes in favor, 35 opposed and 77 abstentions.

Haas had argued that PJM’s plan still gives away some of the transmission system capability that belongs to auction revenue rights holders because “there shouldn’t be any residual revenue allocation” left to offer into the long-term auction and “the fact that some participants aren’t taking advantage of the ARRs as they should be” shouldn’t preclude them from receiving the full benefits available. The Monitor’s plan would require market participants to find someone willing to take the opposite flow of the sought position. (See “Long-term FTRs,” PJM Markets and Reliability Committee Briefs: May 24, 2018.)

“The problem is you’re still selling capability that belongs to the load,” he said.

Calpine’s David “Scarp” Scarpignato said it’s not PJM’s place to choose the best decisions for ARR holders and that “centralized planning” like that doesn’t work.

“You have to allow that some market participants are going to make good decisions and others are going to make less-than-optimal decisions,” he said.

Exelon’s Sharon Midgley said her company’s strategy to hedge its transmission costs “would be severely limited” under the Monitor’s proposal because the company would “have to hope someone wants to take a completely opposite position … which is unlikely.”

Black Start Fuel Security Sent to Problem Statement

PJM’s David Schweizer announced that staff’s proposal to develop fuel security requirements for black start units will be transitioned to the problem statement and issue charge structure. The RTO has been attempting to develop requirements for black start units that ensure fuel security, such as connection to multiple pipelines for gas-fired units or on-site storage. (See “Black Start Fuel Assurance,” PJM Operating Committee Briefs: May 1, 2018.)

“PJM considers fuel assurance to be the ability of a unit to maintain full output during periods of fuel limitations caused by events such as seasonal weather extremes and high-impact, low-frequency events. Examples of high-impact, low-frequency events include pipeline failures or physical and cybersecurity events on a critical portion of a gas pipeline upon which black start resources may depend for fuel,” PJM said in the problem statement. “Initial analysis of PJM’s existing black start fleet indicates that approximately half of the units demonstrate fuel assurance, through dual-fuel capability, on-site fuel storage or multiple gas pipeline connections.”

The discussion will be split between the Operating Committee and the MIC. The OC will cover fuel assurance requirements, testing requirements and transition process while the MIC will address compensation issues. PJM expects the issues to take six months and be implemented by August.

Balancing Ratio Recalculation

PJM’s Pat Bruno presented two proposals for revising how the balancing ratio is calculated, recommending a more sophisticated fix but offering another in recognition of potential time constraints for having a solution implemented in time for next year’s Base Residual Auction.

PJM Staff left to right: Pat Bruno; Chrissie Stotesbury and Chantal Hendrzak | © *RTO Insider*

The simpler option would use the balancing ratios from actual PAIs whenever possible and estimate them from the remaining intervals with the highest peak loads until there are 360 intervals, or 30 hours, total. The more complex solution would revise the formulas that use the balancing ratio — the CP nonperformance charge rate, or performance penalty rate (PPR), and the market seller offer cap (MSOC) — to include “projected performance assessment intervals,” which would be calculated for the delivery year as the average number of PAIs from the previous three delivery years. The MSOC would have a floor of 60 PAIs, or five hours, and the PPR would have floor of 180 PAIs, or 15 hours.

“It seems like you’re picking numbers that feel good rather than backing into something from an empirical basis,” Exelon’s Jason Barker said.

Scarp and GT Power Group’s Tom Hyzinski agreed that having different floors for the MSOC and PPR calculations was problematic.

“It’s not a little bit off. It’s off by a large amount, and it’s highly problematic for operators looking to put competitive offers into the market. I understand you wanting to put them in, but they need to match,” Scarp said.

As the discussion progressed, Scarp offered his own proposal that largely mirrored PJM’s except in how many PAI events are used in the calculation. PJM agreed to organize a special session on the issue for June 19.

Stakeholders expressed concerns that PJM’s formula could cause generators to lose all their annual capacity revenue in a short period. GT Power Group’s Dave Pratzon said the estimates seem excessive, particularly in light of the recent PAI event, in which generators were on the hook despite the cause being a transmission constraint.

EnerNOC’s Katie Guerry was concerned that, depending on the number of PAIs that occur, the PPR can double from $3,650/hour to $7,300/hour, while the MSOC would get smaller, starting at $255/MW-day with more PAIs and falling to $85/MW-day when there are none.

“I appreciate that you guys were trying to find a number that’s not excessively high [and] … did a lot of work [in a short time period], but it was all internal,” she said.

Bruno mentioned that FERC approved ISO-NE’s hourly penalty rate of about $5,500/hour but noted that staff are open to feedback on the proposals.

DC Energy FTR Credit Policy Complaint to FERC

PJM’s Bridgid Cummings explained the RTO’s proposed revisions to its FTR credit policy, and CFO Suzanne Daugherty explained how its position related to a complaint on the topic that DC Energy filed at FERC (EL18-170).

PJM wants to implement a per-megawatt-hour minimum credit requirement to address potentially large FTR positions that have little or no credit requirements. It’s also considering a monthly $100,000 deductible to the existing undiversified adder to address uncertainty and auction clearing disruption.

The per-megawatt-hour credit requirement dovetails with DC Energy’s request for a 5 cent/MWh requirement, which Daugherty said is the minimum PJM is seeking.

“We think that is an improvement to the credit policy that we can absolutely support,” she said.

She said staff are “not convinced yet” of DC’s second request, a mark-to-auction requirement.

“I think some of the concern is … auctions are only once a month,” so “clearing prices seem to jump around.” Sometimes they would match, she said, but other times not, particularly closer to delivery. She acknowledged some market participants have high megawatt volumes in their portfolios, but none is in collateral default. Staff are targeting a July filing to respond.

The adder deductible would be used to reduce collateral calls that create credit uncertainty and potential delay of the market clearing, as they can’t be applied until the auction is in the process of clearing. Cummings noted that 56 undiversified collateral calls were made from June 2016 to March 2018.

PJM is not recommending a deductible but wouldn’t oppose it if stakeholders endorse the idea. Staff hope to have approved revisions implemented by this fall.

FTR Forfeiture

Midgley and Gabel Associates’ Travis Stewart, representing NextEra Energy, presented specific examples of their concerns about FTR forfeitures. The analysis follows disputes with the Monitor at last month’s meeting about whether current rules were having the intended effect of discouraging illegitimate activity or unreasonably harming market participants who are trying to make appropriate business decisions. (See “FTR Forfeitures,” PJM Market Implementation Committee Briefs: May 2, 2018.)

Stewart (left seated) and Midgely | © *RTO Insider*

“I would like to be able to use virtual transactions in the marketplace and at the same time use FTRs to hedge congestion risk,” Midgley said. “The rule is doing more than it intended to do.”

She provided an example of one hour in which Exelon was required to forfeit $47,000 in FTR revenue because a 200-MW virtual trade exceeded the testing thresholds for forfeiture on 18 FTR paths.

The forfeiture happened at 7 p.m. on Sept. 21, 2017. Six days later, NextEra experienced a similar issue with an 800-MW virtual trade at PJM’s West Hub that created $2,078 in forfeitures. Stewart said that similar incidents across the month accumulated to a total forfeiture for NextEra comparable to Exelon’s $47,000.

“There’s a lesson there, and it’s not that we need to reduce the effectiveness of the rule. It’s meant to change behavior,” Bowring said. “The only impact of the rule is to take away your profits on an hourly basis. The point of the rule is not to be punitive.”

Midgley argued that it also devalues FTRs subject to forfeitures and potentially requires load-serving entities to put risk premiums in customer rates, but Bowring said the fact that the forfeitures might cause Exelon or NextEra to devalue FTRs doesn’t mean other market participants will.

“You suggested that load will be worse off from this, but you haven’t demonstrated that, and I don’t think it’s true,” he said.

PJM’s Brian Chmielewski discussed the results of additional sensitivity analyses on the current forfeiture trigger from greater than or equal to 1 cent, to greater or equal to net 10% distribution factor. He found that forfeiture dollars would have been reduced by approximately 97% in September 2017 and 18 market participants would have received forfeitures instead of the 67 who did.

He concluded that the majority of constraints were “far away” from impacted FTRs, but Haas said that doesn’t mean anything unless there’s a “material impact.” PJM is performing additional analysis on market-to-market flowgate virtual testing that it plans to present at next month’s meeting.

“We are seeing a reduction in activity that is consistent with FTR forfeiture. That is a good thing,” Haas said.

— Rory D. Sweeney