FirstEnergy Solutions’ bankruptcy is creating repercussions that extend beyond the question of whether the merchant generator will survive.
While speculation had been swirling for months that FES, FirstEnergy’s generation arm, would soon go under, the company’s March 31 bankruptcy filing was overshadowed by its announcement that it was shuttering nearly 4,000 MW of nuclear generation and requesting an emergency order from the Department of Energy to keep its ailing fleet running. (See FES Seeks Bankruptcy, DOE Emergency Order.)
As part of its bankruptcy filing, FES requested the authority to end its long-held “sponsorship” of the Ohio Valley Energy Corp. (OVEC) and block FERC from making any ruling on the issue. FES requires FERC approval to void its inter-company power agreement (ICPA) with OVEC.
OVEC responded by petitioning the U.S District Court for the Northern District of Ohio to withdraw the request, contending that FERC has exclusive authority over wholesale power agreements that can’t be addressed by a bankruptcy court. The court denied that argument and found that FERC and the bankruptcy court have “concurrent jurisdiction” over the companies’ ICPA.
“Thus, FES must seek approval from both FERC and the Bankruptcy Court to reject the ICPA. FERC will apply the [Federal Power Act’s] public interest standard to determine if the rejection comports with federal law,” the court said.
Clifty Creek Power Plant Complex | Crowezr
OVEC, headquartered in Piketon, Ohio, is still awaiting FERC’s decision on a complaint (EL18-135) it filed on March 26 in anticipation of FES’ filing.
Under the current ICPA, which runs through June 30, 2040, OVEC provides power from its two coal-fired generating plants — the 1.1-GW Kyger Creek in Cheshire, Ohio, and 1.3-GW Clifty Creek in Madison, Ind. — to its eight corporate “sponsors” that include FES. The units are already pseudo-tied into PJM, and the sponsors can sell their portions of the output into the RTO’s markets.
Kyger Creek Power Plant
OVEC has been granted permission to join PJM as of June 1 but will have no load after a DOE contract ends sometime before 2023. The company was created in 1952 to service a uranium enrichment plant near Piketon that ceased operations in 2001. The department ended the 2,000-MW contract in 2003; it maintains a load that can be 45 MW at its maximum but is generally less than 30 MW.
While the sponsors are not required to sell their output, they are required to pay their portion of OVEC’s costs. There is no requirement for the other sponsors to make up for any shortfalls from companies that don’t pay. FES has a 4.85% stake, equating to about $30.1 million annually, according to OVEC’s federal court complaint (5:18-mc-00034-DAP).
PUCO Concerns
Separately, the Public Utilities Commission of Ohio has opened an investigation (18-569-EL-UNC) into FES’ retail sales and its future marketing plans in light of revelations that the company is still offering consumer contracts for up to three years. PUCO gave the company until May 4 to file a detailed explanation about whether it plans and is able to continue its retail sales business.
The order came a day after FES confirmed during its initial bankruptcy hearing on April 3 that it has contracts with more than 900,000 retail customers and plans to sell them to other suppliers. A day earlier, FES had filed a notice with PUCO in its relicensing case (00-1742-EL-CRS) that the bankruptcy wouldn’t affect its retail operations. The company must seek relicensing every two years to be a retail energy supplier.
Nuclear Energy Institute CEO Maria Korsnick on Thursday expressed support for FirstEnergy Solutions’ request that the Department of Energy declare an emergency in PJM to prevent the shutdown of the company’s three nuclear plants.
Korsnick | NEI
But she called the request — along with state zero-emission credit (ZEC) programs — a “bridging strategy” for the industry: temporary measures to keep the plants afloat until RTOs/ISOs and FERC reform wholesale market price formation.
“Ultimately, the fix that’s needed is that recognition [of nuclear’s emissions-free output] in the marketplace. That recognition has been a bit slow in coming, which is why you’re seeing the level of activity that you’re seeing at the state level,” Korsnick said. “The long-term answer is going to be one that’s market-driven.”
Korsnick was responding to a question submitted through a Facebook Live webcast of NEI’s Annual Briefing for the Financial Community. After giving a speech on the state of nuclear industry, she answered questions, which were also submitted by email, relayed to her by NEI spokeswoman Monica Trauzzi.
In both her speech and answers to questions — some submitted by NEI staff, Korsnick was nonspecific about the issue of price formation. She instead consistently came back to the value of nuclear as a contributor to states’ carbon-reduction goals and a “resilient” source of electricity. She praised ZEC as an example of good state policy and noted that Maryland and Washington are considering carbon taxes.
Monica Trauzzi (left), Nuclear Energy Institute senior director of external communications, relayed questions submitted by Facebook and email to CEO Maria Korsnick during a webcast. | NEI
“The pursuit of clean energy can threaten our nuclear plants if we don’t do it thoughtfully. If the goal is to reduce emissions, then all zero-emission technologies must be part of the solution. We must recognize what we already have in place and build on that. Replacing zero-emitting technology with other zero-emitting technology won’t help.”
She also applauded Congress’ extension of nuclear production tax credits to allow the construction of Georgia Power’s Plant Vogtle Units 3 and 4 to be completed.
But Korsnick warned that generation owners plan to prematurely close 12 reactors and that “if nothing is done to save these plants, the impacts will be devastating.”
“If all of these 12 plants close, we will lose over 120 million MWh [per year] of carbon-free generation,” she said. “That’s equal to half of all the megawatt-hours of wind electricity generated last year in the United States.
“We can stick with a myopic focus on short-term prices. Or we can strive to preserve a resilient, robust electricity system, jobs, tax revenues, clean air and healthy communities.”
To counter the grim warnings, Korsnick highlighted positive developments in the industry. She pointed to NuScale’s small modular reactor design, which she said is “progressing well” through the Nuclear Regulatory Commission, and to the Trump administration’s support for Saudi Arabia’s plans for as many as 16 nuclear reactors.
“The export market is growing, and our success there will strengthen the U.S. supply chain and its support of the existing U.S. fleet,” she said.
WASHINGTON — Panelists at day 2 of FERC’s technical conference on distributed energy resources (AD18-10, RM18-9) debated whether electric distribution companies (EDCs) should serve as gatekeepers or facilitators for resources seeking to participate in energy markets.
EDCs and their allies said they should have control over DERs on their systems, while DER supporters called for strict criteria on utilities’ ability to block DERs.
The first day of the conference focused on how RTOs and state regulators can craft policies that encourage DER to participate in wholesale markets while minimizing the burden on grid operators. (See RTOs, Regulators Set Course for DER Market Participation.)
Conflicts of Interest?
Audrey Lee, vice president of energy services for residential solar and storage provider Sunrun, said EDCs should only be allowed to block DERs through a showing that they would endanger system reliability.
“I think we need some specific examples [of problems] before creating any rules on this,” she said, adding that utilities seeking to install their own resources could have conflicts of interest. She noted that CAISO’s Tariff gives EDCs a deadline for reviewing DER applications and reserves the final decision for the ISO.
Maria Robinson, director of wholesale markets for Advanced Energy Economy, said distribution companies “should be facilitators, not a gatekeeper … preventing the ability of [DER] aggregators to enter.”
She suggested EDCs identify zones that can absorb DERs without reliability problems. If they are to review DER applications, EDCs should be given deadlines requiring them to act quickly, and rejected applicants should have the right to appeal to the RTO/ISO or FERC, she said.
“The vast majority of issues should be worked out with the interconnection agreement” between the resources and transmission operator, she said, adding that reviews should be done only once for each interconnection.
Pete Langbein, manager of demand response operations for PJM, also said interconnection studies should consider DERs once, as opposed to “iteratively.” The studies “may evolve over time” to provide the information needed to evaluate DERs’ impact, he acknowledged.
Interconnection Agreements not Enough
But David K. Owens, retired executive vice president of the Edison Electric Institute, said EDCs need to know DERs’ attributes to understand which ones could cause system disturbances. “Just having a list of aggregators is not sufficient,” he said. “[Distribution] utilities have to know when DERs are deployed. … Interconnection agreements alone will not do it.”
Jeff Taft, chief architect for Pacific Northwest National Laboratory, said DERs become potentially more disruptive as their density increases and that the effects are more significant on distribution lines. “The closer you get the edge of the distribution system, the more you see the volatility caused by DERs,” he said.
Taft said that although distribution lines are generally designed as radials rather than the “mesh” network of transmission, they are “dynamic” because EDCs reconfigure their systems daily. “A resource that may be running through substation A, a few minutes later may be running through substation B.”
State ‘Opt-out’
David Crews, senior vice president of power supply for East Kentucky Power Cooperative, said EDCs must have authority to protect their systems to avoid imbalances on distribution feeders. He disagreed with projections that DERs will be evenly distributed, saying they are more likely to be clustered in wealthier areas where residents can afford solar panels and storage. “It can cause problems; I’m not saying it will.”
Crews also said state regulators should have the ability to “opt out” from allowing retail customers to participate in wholesale markets. EKPC joined PJM in 2013 based on an agreement with Kentucky regulators that state residents would not be able to participate in the RTO’s markets, he noted.
Crews said there is little use of solar and storage among EKPC’s 16 distribution utilities, which use five different makes of meters. “For us to go through the administrative cost of developing a tariff is burdensome to our members” at current penetration levels, he said. “If our members have enough [resources] out there that they want it, we’ll do it.”
Cross Purposes
Mark Esguerra, director of integrated grid planning for Pacific Gas and Electric, warned of conflicts between DERs transacting with RTOs/ISOs and ones providing services to distribution companies. “You could have a situation that none of the parties — the ISO and the distribution utility — get the response they’re looking for.”
Esguerra said the 10-day EDC review deadline suggested by some “could be a challenge without more sophisticated modeling tools.”
Missouri Public Service Commission Chairman Daniel Hall, vice president of the Organization of MISO States, said state regulators should set criteria for DER registration and that EDCs must have authority to approve DERs on their systems. “All distribution systems are unique and the people who know them best are the people on the ground, which is the utility and the utility’s regulator.”
Hall said clear criteria on when EDCs can reject DERs will keep EDCs honest. “That gets us beyond the gatekeeper/facilitator” debate, he said.
There was general agreement that RTOs/ISOs, EDCs and aggregators will need to develop new communication protocols to manage higher levels of DERs. Hall urged FERC to allow regional differences by allowing each RTO and its stakeholders to develop their own rules, subject to commission approval.
Gerald Gray, the Electric Power Research Institute’s (EPRI) program manager for information and communication technology, said that although some utilities do not have supervisory control and data acquisition (SCADA) at all substations, the expansion of advanced metering infrastructure means “there is a lot of granular data providing visibility” on distribution systems.
But Matthew Glasser, a director at Consolidated Edison, said his company and other New York utilities do not have the visibility they need to manage DERs. “Communication with DERs now is low-tech. It’s phone and emails.”
Joseph Ciabattoni, PJM’s manager of markets coordination, said the RTO typically communicates — via phone — with transmission operators, which do the same with their DERs.
Brandon Middaugh, senior program manager for distributed energy for Microsoft, said ISOs and RTOs have “very limited visibility into distribution.”
Visibility also was the subject for the first panelists of the morning — five of eight of whom were from grid operators or utilities. As Portland General Electric Vice President of Transmission and Distribution Larry Bekkedahl put it, system operators “can’t manage what you don’t measure.”
Bekkedahl said the information would allow utilities to avoid overbuilding capacity to the “worst-case scenario,” as is done today, and instead “put in as much capacity as necessary.”
Jens Boemer, the principal technical leader of EPRI’s Transmission Operations and Planning Group, said he learned from experiences in his native Germany that any data that can be collected “relatively easily” should be done “as early as possible” because it becomes more expensive to do it later. He also said it’s important to stop combining DER performance with load because it masks the additional services it provides.
Clyde Loutan, a principal on renewable energy integration for CAISO, said DERs contribute to the unpredictability of load. “We have system operators trying to control a grid with unpredictable demand and variable supply, so we’re always in reactive mode,” he said.
Donnie Bielak, PJM’s manager of reliability engineering, called that “a scary thought,” because the RTO watches CAISO as a barometer of what’s to come on DER issues. “We need an absolutely accurate load forecast to operate the system and operate it economically,” he said.
Ganesh Velummylum, a senior manager of system analysis at NERC, placed the responsibility with transmission owners. He said they should ensure they have the necessary data before they agree to interconnect the resources.
“It starts with the TO,” he said. “Once we have the data, we can do studies. … We have to start with collecting the data through the interconnection process.”
Lack of data can create wider issues, as Boemer illustrated through what he called the “52-Hz problem” in Germany. Many DERs were programmed to trip off at frequency thresholds that are very close to normal frequency, which meant that small and normal frequency variations could cause widespread loss of DERs on the system.
It’s an issue PJM is currently looking at by increasing resources’ “ride-through” requirements. (See “Implementing DER Ride Through,” PJM Operating Committee Briefs: March 6, 2018.)
None of Germany’s transmission operators had modeled that problem in its studies, Boemer said. But the industry was able to identify the risk through published research and knowledge of system operations and operating standards. A catastrophic trip never occurred, but the German government set up a retrofit program to reprogram the trip settings for more than 400,000 distributed photovoltaic resources, he said.
Panelists also said DERs have the potential to benefit systems by addressing reliability issues and perform important grid services. In fact, the variability is useful, Bekkedahl said.
“What used to be very stable generation is moving on us,” he said. “Now that we’ve got variable generation going on, it’s really nice to have variable load.”
“The technology is there” to set up support for power, frequency ride-through and voltage support on the system, Velummylum said.
“They all interact,” he said. “I think it’s important that we look at the collective support DER can provide.”
DERs can also provide non-wires solutions, Bekkedahl said, noting their role in the cancellation of the Bonneville Power Administration’s I-5 Corridor Reinforcement Project. The 80-mile, $1.2 billion, 500-kV line would have helped Oregon utilities manage summer peaks when they were receiving no generation support from south of Portland.
“If Oregon was hot, California was hotter,” Bekkedahl said.
But subsequent DER development in California has changed the situation and eliminated the need for the transmission project. “Can we find non-wires solutions? I think absolutely,” he said.
Unlocking such solutions will require encouraging DERs to participate in wholesale markets so they are committed and required to provide information, Bielak said. “The only way you can determine if you can rely on them is with enough data,” he said.
FERC staff also asked panelists to discuss how to develop long-term projections, and many panelists looked to state policies because they drive development. Marcus Hawkins, the director of member services and advocacy for the Organization of MISO States, noted that a MISO study ended up relying on publicly available data because a voluntary survey of DER owners performed by a consultant received low participation.
“I think it starts with having a good understanding of the status quo” of what’s on the system today, Boemer said. He outlined “hosting capacity” studies that analyze distribution systems to identify potential thermal issues that could limit DER deployment on feeder lines. The analysis creates a heat map “that can indicate how much DER may be able to interconnect to certain areas on the distribution grid,” Boemer said.
The morning’s second panel focused on including DERs in system planning. Velummylum, who remained for the second panel, had a quick response. He held up two reliability guideline studies NERC has published that discuss DERs. “Folks, it’s out there,” he said.
Ning Kang, a staff scientist at Argonne National Laboratory, said the lab is working on improving its models through analysis it performed by studying smart inverter functions and focusing on how applicable standards impact performance.
Brant Werts, Duke Energy’s lead engineer for DER technical standards, said his company only considers the impact of losing DERs in specific areas. During the recent solar eclipse, he said the company lost a significant amount of DER but also knew it was coming and prepared for it. “We don’t believe that we would lose all of our DER at one time,” he said.
Delaware-based trading company ETRACOM agreed to pay $1.9 million to settle allegations that it manipulated CAISO markets in a scheme that netted the company $315,000 in profits.
But the company also issued a statement Tuesday dismissing the allegations by FERC’s Office of Enforcement as “absurd theories.”
An April 10 FERC order approving a consent agreement (IN16-2) with ETRACOM shows the company and principal trader Michael Rosenberg — also a respondent but not listed as paying the fine — neither admitted nor denied the accusations. ETRACOM agreed to pay the fine for submitting virtual supply transactions intended to reduce the day-ahead LMP and increase congestion at the New Melones intertie in 2011.
FERC in 2016 sought a $2.4 million civil penalty from the company and a $100,000 penalty from Rosenberg in addition to disgorging profits. (See FERC Seeks $2.5M Fine in CAISO Market Manipulation.) ETRACOM said Tuesday that FERC had “dropped its long-standing position that an individual trader in this case be assessed a civil penalty.”
The commission said the agreement “is a fair and equitable resolution of the matters concerned and is in the public interest, as it reflects the nature and seriousness of the conduct and recognizes the specific considerations” stated in the agreement, which is not subject to appeal.
The decision specifies disgorgement by ETRACOM of $315,000 plus interest of $84,000 to be paid to CAISO for distribution to market participants impacted by the company’s trading.
In the order, the commission noted it had filed a lawsuit in U.S. District Court for the Eastern District of California to request an order affirming the penalties. In its statement, ETRACOM said it had opposed the lawsuit and been victorious in winning full discovery rights under a de novo standard of review, entering mediation with FERC to produce the settlement.
ETRACOM said it “opposed Enforcement’s brazen misinterpretation and manipulation of the record; absurd theories which rest on reverse engineering of conclusions to produce a ‘fraud by hindsight;’ reliance on circumstantial inferences unhinged from the facts; ignoring of significant exculpatory evidence; and inappropriate ‘sandbagging’ in reply to ETRACOM filings.”
It added that “regardless of the outcome of our case, ETRACOM remains optimistic on the role of FERC in regulating and enforcing energy markets and on long-term reform of the enforcement process.” The company agreed to develop and implement a compliance program based on FERC’s November 2016 “Staff White Paper on Effective Energy Trading Compliance Practices.”
FERC Enforcement alleged that in May 2011, ETRACOM submitted and cleared uneconomic virtual supply transactions intended to artificially lower the day-ahead LMP and create import congestion at New Melones. ETRACOM’s virtual supply offers resulted in a $42,481 loss, while FERC staff estimate the company earned $315,000 in profits on its congestion revenue rights positions. Staff estimated the alleged scheme resulted in the market overpaying all New Melones CRR source holders, including ETRACOM, $1.5 million. The overpayment was funded by New Melones CRR sink holders and revenue inadequacy.
The company has long contended that the losses were because of market flaws and that it had rationally attempted to profit from a record hydro event in May 2011 that caused congestion at the New Melones intertie node. But FERC argued that market flaws were irrelevant to the case. (See FERC: Market Flaws Irrelevant to Case.)
FERC alleged manipulation at the New Melones intertie | Armin van Buuren/Wikimedia Commons
ETRACOM pointed to an investigation that “dragged on for over five years and which saw a kaleidoscope of lead attorneys and their bosses with the diffusion of individual responsibility becoming the norm at Enforcement.” The company’s legal and subject matter team was also extensive, including Robert Fleishman of Morrison & Foerster, Matthew Connolly of Nutter McClennen & Fish and former FERC Chairman William Massey, now of Covington & Burling.
The agreement represents one of a series of high-profile challenges by market participants to FERC Enforcement against alleged market manipulation, including a case against Powhatan Energy Fund that resulted in the agency having to conduct a de novo review. (See FERC Settlement Cuts Barclays Market Manipulation Fine.)
CRRs have been a major subject of debate in CAISO in recent years as the ISO moves to restructure its markets over what it says are hundreds of millions of dollars in payment deficiencies being footed by electricity consumers. CAISO’s Board of Directors approved one package of CRR reforms last month and the ISO has additional phases in development. (See CAISO Developing New CRR Proposal.)
RENSSELAER, N.Y. — NYISO power prices averaged $29.91/MWh in March, down from $33.83 in February, and $34.97 the same month a year ago, Nicole Bouchez, ISO principal economist, told the Business Issues Committee (BIC) on Wednesday.
The ISO’s year-to-date monthly energy prices averaged $60.06/MWh in February, up 59% from a year earlier. March’s average sendout was 413 GWh/day, down from 426 in February and 419 a year earlier.
NYC Power Station | janifest / 123RF Stock Photo
New York natural gas prices for the month averaged $2.85/MMBtu at the Transco Z6 hub, down from $3.14 in February and off 18.2% from a year ago.
Distillate prices were mixed compared to the previous month but gained 19.3% year over year. Jet Kerosene Gulf Coast averaged $13.76/MMBtu, up from $13.72 in February. Ultra Low Sulfur No. 2 Diesel NY Harbor averaged $13.78, down from $13.86 the previous month.
The ISO’s local reliability share was 19 cents/MWh, higher than 14 cents the previous month, while the statewide share of -51 cents/MWh was up from -64 cents. Total uplift costs were higher than in February.
Broader Regional Markets
Reviewing the Broader Regional Markets report, Bouchez highlighted two sections updated since the previous BIC meeting.
Item No. 23 covers a PJM proposal to develop pro forma pseudo-tie agreements that would apply to New York Control Area (NYCA) generators that sell all or a portion of their capacity to PJM. The agreements would provide commitment and dispatch instructions to those generators to meet PJM’s — rather than NYISO’s — needs.
NYISO has expressed concerns that the removal of an in-state generator from the ISO’s commitment and dispatch process limits its ability to manage the generator to ensure NYCA reliability. The removal also introduces compliance issues regarding New York State Reliability Council rules and decreases the efficiency of the ISO’s least-cost solution in its day-ahead and real-time markets.
The ISO is working with PJM to find solutions acceptable to both grid operators.
Item No. 27 concerns how NYISO determines locality exchange factors, which became an issue in 2015 when the ISO’s Market Monitor, Potomac Economics, raised concerns about the treatment of capacity exports from import-constrained localities.
The ISO in February 2017 deployed FERC-approved capacity market changes and asked General Electric to identify possible ways to refine the current methodology using a probabilistic approach. That effort proved unsatisfactory to stakeholders, and the ISO has engaged GE to work further on a formula-based methodology for determining locality exchange factors.
Public Website Redesign
Dave O’Brien, a NYISO project manager, provided an update on the project to redesign the ISO’s public website.
O’Brien said the new design will debut in the fourth quarter with a more intuitive layout and navigation, better mobile device interoperability and an improved search function.
| NYISO
Stakeholders also expressed hopes that the website would better meet their needs. Howard Fromer of PSEG Power New York noted an example of spending minutes locating a document, being asked to sign in for access, then being redirected back to the homepage and to restart his search from scratch.
The New York task force charged with determining how to price carbon emissions into NYISO’s markets on Monday tackled the complex issue of avoiding the pitfall of “carbon leakage.”
The term refers to when carbon market participants evade caps and prices by shifting electricity production to bordering areas outside the market.
The Integrating Public Policy Task Force (IPPTF) on April 9 heard two presentations on seams and leakage, part of issue “Track 2” in its five-track effort. The task force is jointly run by NYISO and the state’s Department of Public Service.
“It’s not an option at all to put a sizeable carbon charge on New York production and not do anything at the borders; that’s just not an option,” Brattle Group’s Sam Newell said during a presentation on applying carbon charge border adjustments to the ISO’s external transactions. “The reason you can’t is it creates a very unlevel playing field and would shift production to out of state in a very big way.”
Status Quo or Green Power
Newell presented two carbon pricing options to avoid market distortions. The “status quo” model would not consider carbon content in energy trades, while the second “green power” option would evaluate marginal emissions rates from out-of-state imports.
The status quo option could shift generation serving up to half New York’s load to out of state and also increase emissions regionally while only reducing them in state, Newell said.
| Brattle Group
“We’re talking about something that could be on the order of $50/ton, could be $20/MWh,” Newell said. “Imagine putting a $20 penalty on internal generation and not external. Again, you’ve really unleveled the playing field.”
The second option would factor into the prices for imported electricity the estimated difference in the carbon content of emissions based on the region (PJM versus Quebec, for example), “and it does think about carbon content in terms of exports and what are you displacing on the other side,” Newell said.
In response to questions from several stakeholders, Newell said the carbon charge on imports would not be unit-specific, noting that neighboring regions do not identify their exports by generating unit.
He contrasted New York’s situation with the Energy Imbalance Market (EIM) administered by CAISO.
“That’s an integrated market, and if you just said these units in California have to buy allowances and the others don’t, you’d have the same leakage problem,” Newell said. “They had to build into the [EIM] some sort of border treatment. … Unlike New York when it’s thinking about its neighbors, the EIM actually is dispatching the region on a unit-specific basis.”
Other stakeholders asked about charging imports from neighboring regions based on their average — rather than marginal — emissions rates.
“In economics, for price signals, marginal is what matters, not average,” Newell said. “This is a whole topic in ratemaking. If you charge based on average, you’ll have unintended consequences and inefficiencies.”
Marginal emissions rates differ from region to region, he said, but the types of marginal units may be more uniform across neighbors than assumed. For example, “energy limited resources” in Hydro-Quebec and Ontario (often limited to shorter run times because of local environmental restrictions) are more likely to produce and export at the margins of the market.
“If you get it right, you incentivize cost-effective abatement everywhere,” Newell said, noting that approach is consistent with New York’s objective to reduce global emissions.
Specifying Emissions and Costs
Julia Frayer and Gabriel Roumy of London Economics International (LEI) presented a study commissioned by Hydro-Quebec Energy Services (Hydro-Quebec’s U.S. subsidiary) on potential methodologies to address leakage of emissions to and from neighboring areas.
Like the Brattle report, LEI stated that improper implementation of a carbon charge mechanism could derail decarbonization objectives and distort underlying market signals.
| Brattle Group
LEI believes that a more granular approach to assessing carbon emissions rates for imports, based on resource- or area-specific emission rates, is superior in terms of economic efficiency, market impacts and reduction incentives.
“It’s all a matter of consistency, and it’s important when you look on the regional scale [that] you really need to look at unit-specific emission rates and what are these resources contributing to the overall Northeast markets,” Roumy said. “And the contribution is the lack of emissions that they are doing.”
Howard Fromer of PSEG Power New York said, “We want to know what the cost and price impacts are going to be to end-use consumers. If they’re a lot, then we’re probably not going to be very supportive. If they’re modest … then the next question we’re going to ask is: What are we getting for that extra cost? Are we getting significant carbon reductions, or are we just reshuffling the deck and making it look good?”
Warren Myers, DPS chief of regulatory economics, summed up the two political approaches represented in both the Brattle and LEI studies.
“One is keeping, as best as you can, interactions with other control areas on the same playing field that it’s currently on,” Myers said. “The other one is — do you want to take New York’s policy, or what the value of carbon is, and apply it beyond New York’s borders to address its consumption.”
In wrapping up the meeting, IPPTF co-chair Nicole Bouchez, NYISO principal economist, noted that the group will move a discussion on carbon charge implementation from May 7 to its next meeting on April 16 in response to stakeholder concerns.
MISO Chairman Michael Curran last week denied an RTO Insider story quoting him as saying that the RTO should “burn down” the 3,000-MW limit on flows between its North and South regions if necessary to prevent load shedding.
The comment — and one attributed by Megawatt Daily to MISO Independent Market Monitor David Patton — led to a series of tense communications between MISO and SPP and a request for FERC to intervene over how MISO managed a maximum generation event in MISO South on Jan. 17.
RTO Insider’s April 2 story reported on an exchange between Curran and Patton at MISO’s Board Week in New Orleans over the RTO’s actions to replace idled generation in its South region during the record cold on Jan. 17.
At a Markets Committee meeting March 27, Patton said if the RTO had not made emergency power purchases for South, regional supply would have dipped below load for several hours, referring to the possibility of the “lights going out in MISO South.”
RTO Insider reported that Curran “rebuked Patton’s use of such dramatic language, while also responding that MISO should ‘burn down’ SPP’s transmission on the contract path before it allows MISO South to shed load.” (See MISO Markets Committee Talks Winter, Spring — and Beyond.)
MISO agreed to the 3,000-MW Regional Dispatch Transfer (RDT) limit in a 2016 settlement agreement with SPP, the Tennessee Valley Authority (TVA), and Southern Co.
Denial
Kari Bennett, MISO executive director of stakeholder affairs and communications, asked RTO Insider for a retraction of the quote on April 6, saying Curran denies using the words “burn down.” She also denied Curran said that MISO would violate the SPP agreement to ensure sufficient power to meet South’s load, as RTO Insider reported.
Rather, she said, Curran was indicating the RTO would invoke a clause in the agreement allowing it to exceed the 3,000-MW North-South limit. The settlement, which was approved by FERC in May 2017, set a 2,500-MW South-North limit. (See FERC Greenlights MISO Cost Allocation for SPP Settlement.)
MISO exceeded the 3,000-MW limit on North-South transfers for more than an hour on Jan. 17 before emergency purchases from the South allowed it to reduce transmission to below the limit. | MISO
MISO’s load hit 106.1 GW on Jan. 17, its peak for the winter, with South setting a record winter peak of 32.1 GW. The RTO called a maximum generation event in South after outages there hit 17 GW.
The RTO compensated for South’s shortfall with generation from Midwest, exceeding the 3,000-MW limit for about an hour (see chart). MISO dropped below the limit after making emergency purchases of 1,100 MW — mostly from Southern Co. — south of the North-South constraint. It was the first such emergency purchase from Southern, Patton said.
Some stakeholders who attended the meeting said privately they considered Curran’s comments surprising and inflammatory, though they could not recall use of the phrase “burn down.”
RTO Insider requested to review a recording of the meeting to address the dispute over Curran’s words. However, MISO said although the meeting was webcast, it was not recorded.
‘Run Over’
Patton said Monday that neither he nor his staff who listened to the meeting recalled Curran using the term “burn down.” Based on notes made by his staff, Patton indicated Curran said “ … if we have to run over RDT, we will to prevent turning lights off in the South.” Patton said he interpreted Curran’s “run over the RDT” statement as meaning to schedule more transfers than 3,000 MW, which is allowed on a temporary basis.
Patton said the agreement allows MISO to exceed the limit for 30 minutes after a contingency and to request a longer waiver from the other parties to the agreement.
Patton said he agreed with Curran that avoiding load shedding in South must take precedence over exceeding the RDT, adding that “the idea that you would shed load [rather than exceed the limit is] just such an absurd outcome.”
SPP Letter
SPP declined to comment. But in an April 4 letter, SPP CEO Nick Brown complained about Curran’s comments, as reported by RTO Insider, and Patton’s comments as reported by Megawatt Daily.
The letter, which was obtained by RTO Insider, quoted Patton as saying, “SPP has been saying [MISO] created reliability problems on their [SPP] system. We don’t believe this is true.”
“I take these comments very seriously as they are totally false as SPP did face a significant reliability event and took actions necessary to preserve the integrity of our system and the bulk electric system as a whole,” wrote Brown, who said he was pleased that MISO President Clair Moeller had assured SPP that the RTO didn’t agree with Patton’s comments.
But Brown said he found Curran’s quote, as reported by RTO Insider, “very troubling.”
“I view this incident as a grave matter related to protecting the integrity and reliability of the bulk electric system,” Brown continued. “Rather than debating this incident in the press, I believe it best for the parties involved to elevate our discussions to FERC and NERC so [that] everyone can better understand what occurred on that day and why. Therefore, I have asked Paul Suskie, SPP general counsel and executive vice president for regulatory affairs, to contact FERC to request their scheduling of a meeting in Washington, D.C., to take place expeditiously.”
SPP spokesman Derek Wingfield said in a statement late Tuesday: “We disagree with the assessment of MISO’s Market Monitor, as reported in RTO Insider and Megawatt Daily, regarding the severity of MISO’s actions as they relate to the reliability of SPP’s system during the Jan. 17 event. To ensure the continued reliability of all our systems, we have asked for a meeting with principals from MISO and the joint parties to clarify the parameters by which we coordinate operations, as defined in our settlement agreement.”
MISO’s Bennett said Tuesday, “MISO system operators were in constant contact with real-time operators from all of our neighboring systems regarding system conditions on Jan. 17, including the transfer limits per the settlement agreement as well as our request for emergency purchases per MISO’s emergency protocols.
“The settlement agreement between MISO, the Southern Companies, SPP, and TVA establishes a Regional Transfer Directional Transfer Limit (RDTL) of 3,000 MW (north to south) and allows for temporary changes (increases or decreases) to the RDTL to avoid a system emergency, so long as the change does not create a system emergency for SPP, the Southern Companies or TVA.”
Grid operators and regulators on Tuesday hashed out the complexities of integrating distributed energy resources (DER) during the first session of a two-day FERC technical conference on boosting the role of energy storage in wholesale electricity markets.
FERC ordered the conference in February after issuing Order 841, which requires each RTO/ISO to develop a “participation model” allowing storage resources to provide any energy, capacity and ancillary services of which they are capable and be eligible to set clearing prices as both buyers and sellers. (See FERC Rules to Boost Storage Role in Markets.)
A morning panel brought together RTO/ISO representatives who discussed the operational intricacies of integrating DER into wholesale markets, focusing on approaches to aggregating the market participation of the small-scale resources to make them manageable for grid operators.
“DER aggregation requires a level of cooperation you don’t see to this point, not even in demand response, because of the impact DER can have on the system,” said John Goodin, CAISO manager of infrastructure and regulatory policy. “It’s important if you’re going to establish DER aggregation, that you impose both size and boundary constraints; that’s something that the ISO has done.”
University of Delaware Vehicle to Grid (V2G) cars parked at the Science, Technology, and Advanced Research (STAR) Campus. 15 V2G vehicles act as a mini power plant, drawing energy during off-peak times and delivering it back to the grid when it’s most needed. In partnership with NRG Energy, the university has created the world’s first revenue-generating vehicle-to-grid project using technology developed by Professor Willett Kempton of UD’s College of Earth, Ocean and Environment. | University of Delaware
CAISO set a 20-MW size limit on aggregations participating in its market, although individual resources can range from 0.5 to 1 MW. Any resource exceeding 20 MW becomes a participating generator subject to a different set of requirements, Goodin noted.
Nodal vs. Zonal
Pointing to the dual nature of DER as both transmission and distribution resources, Jeff Bladen, MISO executive director for market services, said it’s important to distinguish between the challenges of taking load off the system and putting supply onto the system.
“As we think about aggregation groups, it needs to be more than how do we do security-constrained aggregations for the transmission system, but how are we going to manage potential restraints at the distribution level,” Bladen said.
“Let’s remember we are a nodal system,” cautioned Joe Bowring, president of Monitoring Analytics, PJM’s Independent Market Monitor. He encouraged industry stakeholders to think about developing a sustainable model for significant expansion of DER.
“It’s critical to think about how [aggregation] works in a nodal system,” Bowring said. “It’s not possible to predict congestion; it’s not possible to predefine constraints that exist or don’t exist in a zone.” Any configuration larger than a node is “way too big for aggregation,” he said.
| NYISO
Michael DeSocio, NYISO senior manager for market design, said while New York does allow zonal aggregations, none is participating in the market today.
“So as much as we hear it’s important, we don’t see much of that actually occurring in New York,” DeSocio said. “As we thought about making sure the values were there for DER and making sure the price signals incentivize DER to locate in the right places, it occurred to us that nodal made the most sense.”
| FLS Solar
Henry Yoshimura, ISO-NE director of demand resource strategy, noted resources coming into the New England system are primarily solar and energy efficiency and the RTO’s settlement-only construct allows any resource up to 5 MW to participate in the wholesale market. “Because there’s no size limitation, there’s no real need for aggregation,” he said.
Goodin said CAISO sees significant benefits to aggregation.
“We don’t have a single node,” Goodin said. “You can have an aggregation across the [sub-load aggregation point], across multiple nodes, and why is it advantageous? One, it allows for the providers to actually go out and solicit and pull together, aggregate, meaningful-sized customers, meaningful from the ISO’s perspective … the key thing is that aggregations allow for the right sized resource.”
Andrew Levitt, PJM senior market strategist, said, “We think there are benefits to aggregation in ensuring open market access to resources of all sizes, including resources smaller than our 100-kW minimum highest threshold.”
National Solutions?
Commissioner Cheryl LaFleur asked why there should be different processes among the different regions.
“Shouldn’t we try to solve the coordination process once and then sort of spread that, as opposed to developing six ways to do it?” LaFleur asked. “Maybe we should standardize more. Can we skip a step and figure it out?”
“I don’t know that the rules are the issue,” DeSocio said. “I think really what the main difference that we’ve observed in New York is what is the posture of each of the different distribution utilities, what is their ability to actually see into their own grids.”
Goodin added, “If we are going to enable DER to really flourish, you have to address some of the things that are outside the walls of the ISO and the authority of an ISO through FERC.”
He enumerated three priorities: access to capacity markets and capacity payments; reducing interconnection barriers and cost; and creating more clarity around allowing DER to tap multiple value streams and simultaneously provide grid services to the both ISO and distribution domains.
“In my opinion, those are the much more weighty issues — resource questions, interconnection, multiuse — than sort of the day-to-day functionality of managing these DER and settling these DER resources in the wholesale market,” he said.
Yoshimura said the primary issue is a lack of “consensus in the industry as to how distributed energy resources ought to be operated, if at all. And the struggle that any ISO would have is, whereas we model transmission constraints, I don’t think any of us model distribution constraints.”
MISO’s Bladen said, “We like to think of ourselves as a service provider, to the states in many respects, that our job is to take the fleet that regulators are designing and implementing through their integrated resource plans and to optimize that, to get the most value you possibly can out of that fleet across a broad region.”
“We don’t know yet what best practices are going to look like, don’t know what the dominant DER technologies will be, and that what you have in front of you are a number of companies interested in identifying best practices,” Bladen said.
Bowring said: “We should have the same rules. The fact there’s all this complexity doesn’t mean we shouldn’t have the same set of rules. They will evolve, but we to need start in the same place where everyone is facing the same issues.”
Head Banging
During the afternoon panel, regulators from California, Ohio, Pennsylvania and D.C., as well as others, carried on the discussion of DER aggregation, including issues around reliability and markets. The conversation illustrated the newness of the technology and the many challenges of coordinating state regulations, markets, and the requirements for utilities.
FERC commissioners noted the difficulties for states developing separate policies and approaches that will need to be integrated into wholesale and retail markets. The panel covered how federal and state regulators — and others — can better coordinate on the issue.
“This is a case where all the technology might be ahead of the regulators,” LaFleur said.
FERC Chairman Kevin McIntrye put it simply, telling the state regulators, “We want to avoid messing anything up.” He asked about the negative impacts of individual and aggregated DER on states and said the discussion should help build a robust evidentiary record.
California Public Utilities Commission (CPUC) President Michael Picker recommended a “DER roadmap” similar to one developed by his agency, which looks at grid architecture, DER planning, and developing appropriate rates and tariffs. California is a leading state in DER integration, including efforts by the CPUC and CAISO.
UC San Diego Microgrid | UC San Diego
“There are a lot of challenges here,” Picker said, adding that the CPUC’s effort has uncovered issues around safety for workers and emergency responders who have to deal with DER equipment. The effort has also identified operational issues around DER integration, including congestion in the distribution system, and is mapping the distribution system similar to how RTOs map transmission systems.
“We have a grid system that was never designed for a lot of two-way flow,” Picker said. The CPUC effort is “acknowledging that these are trends that are going to happen,” he said. He noted that other states will be able to learn from and “leapfrog” California’s efforts.
Invenergy’s 31.5 MW Grand Ridge Energy Storage project | Invenergy
“I would recommend you let us bang our heads against those brick walls,” he told FERC, pointing to CAISO’s Energy Storage and Distributed Energy Resources program, now in its third phase. (See CAISO Storage, DER Plans Progressing.)
Different States, Different Rules
The regulators noted their states have different policies with different cost impacts that will need to be integrated into markets. They also hold differing views on allowing DER to participate in wholesale and retail markets.
Public Utilities Commission of Ohio Chairman Asim Haque discussed an issue raised by several regulators: that DER should not be compensated twice — in retail and wholesale markets — for providing the same services.
But Haque added that DER owners and operators should be left to decide how they choose to be compensated for behind-the-meter DER, such as staying on a net metering tariff or participating in the wholesale market through aggregation if that is more profitable.
“Their goal is to maximize the value of that resource,” he said. “That is acceptable to us as well.”
Ben D’Antonio, counsel for the New England States Committee on Electricity, said distribution utilities in New England are going to drive many of the outcomes as DER resources are added, but “the operational impacts are not known at this time.”
“We are actively working on it, but some of ours states have some pretty ambitious goals and others do not,” D’Antonio said. He said it’s unclear how quickly DER will grow in New England, but he thinks the integration effort will need to be consistent with the integration and interconnection requirements of the distribution utilities, who have a “critical gatekeeping role.” Utility decisions will be driven by the tariffs, requirements, and incentives that federal and state regulators put in place, he said.
”We support the idea of DER being able to take part in both wholesale and retail markets,” said Tammy Mitchell, deputy director of the New York State Department of Public Service. But she thinks much work remains to develop the rules and protocols, including the double-payment issue, which could increase ratepayer costs.
D.C. Public Service Commissioner Willie Phillips said he thinks the city can benefit from DER, but “it’s really a resource-by-resource analysis.” The city has seen no negative impact from its load control programs, for example, he said.
“Here in the district, people are dying to get at this,” but the compensation issue must be solved first, Phillips said.
VALLEY FORGE, Pa. — PJM stakeholders are questioning the process for how a transmission development proposal will proceed following a debate at last week’s Planning Committee meeting.
The issue arose during a discussion of the effort to incorporate cost containment into transmission project proposals. A series of events at January’s Markets and Reliability Committee meeting culminated in the issue going back to the PC for additional consideration. A PJM proposal was voted down, and the RTO’s Suzanne Daugherty, who chairs the MRC, then determined that an alternate proposal from LS Power, which didn’t receive a vote, would be the main proposal the committee considers when the issue returns.
But a gas-fired generation representative who asked not to be named questioned whether Daugherty had the authority to make that determination. Stakeholders who supported his assessment pointed out that the MRC directed the PC to give the issue additional consideration. The PC could vote on any proposals that come out of that reconsideration to determine the order in which they’re presented at the MRC, they argued.
Other stakeholders, including Calpine’s David “Scarp” Scarpignato, were hesitant to accept that interpretation of the rules, arguing that they had acted at the MRC under the expectation that the appropriate outcome had occurred.
Stakeholders have been considering the issue through special sessions of the PC and working under the belief that LS has control of what the primary proposal will say. Under the MRC’s rules, the committee doesn’t consider alternate proposals if the primary proposal is endorsed. (See PJM Stakeholders Explore Cost Containment Complexities.)
PJM staff agreed to consider the process questions and make a determination, but they also questioned the usefulness of focusing on that rather than trying to find stakeholder consensus.
“This is largely academic,” PJM’s Steve Herling said.
“We can as a group figure out what’s giving everybody the most heartburn and try to work on those” issues, PJM’s Sue Glatz said.
Market Efficiency Charter
Stakeholders endorsed the charter for the Market Efficiency Process Enhancement Task Force (MEPETF), which has been stood up to consider ways to improve the process for developing market efficiency projects. It will analyze seven processes:
How the benefit-to-cost ratio is calculated;
How facility service agreements (FSAs) are modeled;
The process for proposal windows;
How interregional market efficiency projects (IMEPs) are selected;
How projects are re-evaluated;
The process for regional targeted market efficiency projects (TMEPs); and
The process for updating assumptions about the system in the middle of the proposal cycle.
The group has met three times, with the next meeting planned for April 20.
Reactive Transfer
The RTO plans to revise two of its reactive transfer interface definitions effective June 1, PJM’s Yuri Smolanitsky said. Staff will add the 5059 Breinigsville-Alburtis No. 1 500-kV line to the eastern interface. The new line is expected to be in service by next spring.
Three 345-kV lines — Hanna-Chamberlin, Star-N. Medina and Monroe-Lallendorf — are being added to the Cleveland interface to extend it further south and east. Staff expects “minimal” operational impacts, Smolanitsky said.
“One of the reasons we’re trying to expand the definition [is] so we have more options” to address operational contingencies, PJM’s Aaron Berner explained.
Facility Rating Concerns
Ryan Dolan of American Municipal Power highlighted concerns his organization and the PJM Industrial Customer Coalition have with how transmission owners calculate facility ratings. Dolan said the methodologies used by TOs to file facility ratings in compliance with NERC reliability standard FAC-008-3 aren’t made available to stakeholders, so it’s impossible to independently verify them.
The same issue is at the heart of a ruling made in January by a FERC administrative law judge that PJM’s system impact study (SIS) process is unjust and unreasonable because of a lack of transparency. In that case, merchant transmission developer TranSource brought a complaint that it wasn’t able to accurately assess cost estimates prior to paying significant filing fees for line upgrades it proposed because PJM uses confidential information in the estimates. The RTO vowed to challenge the ruling, and parties in the case have submitted comments. (See FERC Judge Faults PJM, TOs on Transmission Upgrade Process.)
AMP says it wants to discuss better tracking of changes to facility ratings and development of a publicly available ratings database to help stakeholders determine factors that are limiting facilities’ performance.
Order 1000 Filing Catches Up
Staff plan to file for FERC approval later this month process revisions related to Order 1000 that stakeholders endorsed in February 2016, PJM assistant general counsel Pauline Foley said. The revisions will require renewal every three years of transmission developers’ prequalified status to be named the designated entity for a project. They also clarify that the deadline for designated entities to submit their agreement and credit paperwork is 60 days after PJM provides it to them.
The filing was postponed while FERC was without a quorum and ran into unforeseen staff delays subsequent to the quorum returning, Foley said. PJM will be contacting the prequalified entities to update their prequalification status.
Nuclear Deactivations
Staff have begun the analysis of whether the four nuclear plant closures announced by First Energy Solutions in March will create reliability concerns. Calpine’s Scarp said the main question is whether PJM will be offering the units reliability-must-run contracts.
“Really, that’s the only information out of this we’re trying to get,” he said.
Staff said that determination would be based on an analysis that hadn’t been completed yet. FES has requested to deactivate Davis-Besse in the ATSI transmission zone in Ohio by June 1, 2020. Perry, which is also in ATSI, and Unit 1 of the Beaver Valley facility in Duquesne Power and Light’s zone would be deactivated by June 1, 2021, and the second unit by Nov. 1, 2021.
VALLEY FORGE, Pa. — With the exception of three nor’easters, system operations in March were relatively uneventful, PJM’s Chris Pilong told attendees at last week’s Operating Committee meeting.
Pilong reviewed the monthly operations report, noting there were no spinning reserve events during the month. The load forecasting error was 1.53% overall. The error during off-peak hours was 1.48%, 0.1% above the same metric in March 2017, but the on-peak error was 1.58%, down 0.16% from a year ago.
There were 45 excursions for a total of 99 minutes outside PJM’s frequency target range, down from 106 excursions for 257 minutes in March 2017. Unplanned outages, planned emergencies and the total outage average by percentage were all lower than the same period a year ago. The forced outage average by percentage, along with the forced and total outage averages by megawatts, were up slightly.
“We’re starting to ratchet up the planned outages,” Pilong said. In previous years, April and May have been the second- and third-highest months for outages, behind only October.
PJM estimates production-cost savings of more than $11 million in 2018, almost all of which occurred in March.
Gen Transfer Vote Postponed
PJM postponed a planned vote on approving stricter requirements for notifying the RTO about generation ownership transfers, but the RTO’s Rebecca Stadelmeyer said ongoing discussions with owners remain productive. The two sides hope to have a mutually acceptable proposal prepared for a vote at May’s OC.
Both sides recently engaged in a four-hour discussion, and a final call is scheduled for this month, Stadelmeyer said. Generation owners in February objected to rules proposed by PJM that they felt were too onerous, but at last week’s meeting, they appeared to agree that the consensus was likely. (See “Generation Transfer,” PJM MRC/MC Briefs: March 22, 2018.)
Storage
PJM’s Scott Baker highlighted progress being made by the Distributed Energy Resources Subcommittee on determining how combined storage and generation resources should measure and account for the differences between wholesale and retail power sales. The subcommittee has developed potential definitions for wholesale-retail delineations during complicated transactions, such as when a storage resource is charging from both the grid and a co-located resource and discharging to the grid while the generation resource is also injecting directly to the grid.
Baker also outlined the non-wholesale information PJM believes it needs from DERs and the communication and data-validation channels that will likely be necessary to properly oversee storage resources.
Black Start Fuel Assurance
As part of the current black start procurement, PJM is looking to add rules that ensure plants have fuel when needed. The RTO’s David Schweizer introduced a plan for “restoration fuel assurance,” which it hopes to implement in the third quarter of this year and apply to any black start resource procured after 2018.
The changes would include a transition plan for existing units, including those picked up in the current procurement. The plan will also address fuel-assurance issues — including dual-fuel capability, onsite fuel storage and units having connections to multiple gas lines — and compensation mechanisms.
Schweizer said he received preliminary proposals from 90 different sites in its current procurement, which PJM undertakes every five years. Staff have sent notifications for detailed proposals to about 25 of the 90. PJM is planning to award contracts to any successful proposals by the end of May. There are currently about 150 black start units RTO-wide.
Schweizer said the new rules are in response to the fleet becoming significantly more gas-heavy. He noted that the current rules require that black start units be back online within three hours, and that gas travels in pipelines at 20 mph on average. Gas pipeline operators have assured the RTO that the lines are packed sufficiently to supply black start units if necessary, but “increased reliance on natural gas means increased need for black start ability,” he said.
CIR Revisions
PJM’s Jerry Bell presented additional analysis on summer performance of wind and solar units and how that relates to providing capacity injection rights (CIRs). The work is part of PJM’s ongoing effort to revise Manual 21, which covers procedures for determining changes to generators’ capability. (See “Limiting Meetings Causing Stakeholder Strain,” PJM PC/TEAC Briefs: March 8, 2018.)
Bell said staff analysis found that the average peak hour, which is used for determining capability, is a good approximation of the median for solar units but not for wind. The study found that average wind performance during the peak hour of demand is likely to reflect the actual amount of production only 36% of the time. The median was about half as much, and wind production was zero in two of every seven peak summer hours, Bell said.
For the May OC meeting, PJM plans to provide more analysis on whether the current June-August testing period is appropriate, and if simultaneous testing would be more indicative of the true capability of plants that have common load spread across multiple units.
Stakeholders remained skeptical of the potential changes, noting concerns that ranged from how unit testing will be conducted, to whether there’s an appeals process for PJM’s determinations, to how the rights planned for units in the interconnection queue would be handled if they are not brought online before the rules change.
PMUs to Monitor IROLs
PJM is considering using its growing synchrophasor network to monitor interconnection reliability operating limits (IROLs). The RTO’s Shaun Murphy explained that phasor measurement units (PMUs) could offer redundant monitoring of the IROL interfaces. Past issues with PJM’s emergency management system have required manual monitoring of IROLs. Implementing the plan would require installing 14 PMUs and modifying four.
The proposal is the most recent initiative in PJM’s effort to exploit the opportunities created by its synchrophasor network. (See “Synchrophasors Backup,” PJM Operating Committee Briefs: Sept. 12, 2017.)
University Park RAS Done
Commonwealth Edison’s Alan Engelmann announced plans to end the company’s remedial action scheme at its University Park North Energy Center. The RAS will be disabled by July 1 and physically removed by the end of the year.
The plan trips generators for certain delayed-clearing multi-phase and single-phase faults to prevent instability, Engelmann said. Incremental reinforcements, such as circuit breaker replacements and protection system redundancy, have made the plan unnecessary.
