The Missouri Supreme Court ruled Tuesday that the state Public Service Commission can issue the Grain Belt Express transmission project a certificate of convenience and necessity (CCN) without obtaining consent from each impacted county (SC96993).
The unanimous decision cleared one obstacle hindering Clean Line Energy Partners’ embattled, $2.3 billion, 780-mile line, which would transmit Kansas wind generation through Missouri and Illinois to PJM at the western border of Indiana.
“We think this is obviously a huge step forward,” Clean Line President Michael Skelly said in an interview.
Missouri regulators rejected Grain Belt Express in 2017, citing precedent from a state Court of Appeals’ decision that certificates require consent from each county affected by the proposed construction.
Although four of the five commissioners said they found the project worthy, they said their hands were tied by precedent, as the Caldwell County Commission refused to allow the transmission line to cross public roads. (See New Midwest Infrastructure Must Respect Trends, Experts Say.)
But the Supreme Court said the commission confused a line CCN — which does not require prior county assent — with an area CCN, which does. An area CCN would have been necessary if the Grain Belt Express was intended to supply retail service.
It concluded that the commission mistakenly analyzed the application under the wrong subsection of rules.
The court reversed the PSC’s decision and remanded the case back to the commission to issue a new order.
County Opposition Remains
The Supreme Court acknowledged that Clean Line will still need county assent to construct facilities impacting publicly owned roads under state law. “But such assent is not relevant to the commission’s decision in issuing a line CCN,” the court said.
The project would cross 206 miles through eight Missouri counties.
Landowner group Block Grain Belt Express Missouri said Tuesday that it will continue to lobby county commissioners to withhold approval. The group said the ruling was an “empty victory” and maintains that the line has little chance of success.
“We disagree with the decision of the Supreme Court and are disappointed by it. A ruling requiring county consent prior to approval by the PSC would have likely been the end of the road for Grain Belt Express. However, Grain Belt is still far from being approved and built. We will continue to fight for our farms and property rights and against unnecessary use of eminent domain,” the group’s Russ Pisciotta said in a statement.
Clean Line Optimistic
Clean Line’s Skelly told RTO Insider he didn’t expect problems winning counties’ approvals for road crossings. “We’ll work with the counties to figure that out,” he said. “You always have to have road-crossing agreements.”
Skelly said the company, which already has CCNs from Kansas and Indiana, is planning to refile its application in Illinois, where its certificate was rescinded by a state appellate court in March because it did not qualify as a public utility in the state. Illinois law requires that a public utility “owns, controls, operates or manages, within this state, directly or indirectly, for public use, any plant, equipment or property used or to be used for” public utility purposes.
“We believe that the Illinois commission recognized the need for new transmission, and we believe we will be able to craft a successful application in Illinois,” Skelly said.
“The courts have laid out a pretty clear path” for overcoming their objections, Skelly added. “It could be as simple as owning land. It could be teaming up with an Illinois-based utility. It could be owning a substation.”
Grain Belt’s DC-AC converter station is slated to be attached to American Electric Power’s Sullivan 765-kV substation in Illinois, near the Indiana border. “A lot of that power is going to end up in Illinois,” Skelly said.
FERC on Thursday ordered expanded reporting of cybersecurity incidents, saying attempts not currently reported could lead to bigger, more successful attacks.
The commission gave NERC six months to revise its critical infrastructure protection (CIP) reliability standards to mandate reporting of incidents that compromise, or attempt to compromise, a responsible entity’s electronic security perimeter (ESP) or associated electronic access control or monitoring systems (EACMS) (RM18-2).
FERC said the new rules will improve threat awareness by covering the installation of malware and other “incidents that might facilitate subsequent efforts to harm the reliable operation of the [bulk electric system].”
Under the current CIP-008-5 (Cyber Security – Incident Reporting and Response Planning), incidents must be reported only if they “compromised or disrupted one or more reliability tasks.”
The final rule adopts the Notice of Proposed Rulemaking the commission issued in December, which concluded that “the current reporting threshold may understate the true scope of cyber-related threats facing the bulk power system, particularly given the lack of any reportable incidents in 2015 and 2016.” (See FERC Orders Tightened Cyber Reporting Rules.)
The commission’s order also calls for standardizing cybersecurity incident reports to improve the quality of reporting and allow easier comparisons and analyses. The reports will require information on the impact, or intended impact, of the intrusion; the attack “vector” used; and the level of intrusion achieved or attempted.
In addition to continuing to send the reports to the Department of Energy’s Electricity Information Sharing and Analysis Center (E-ISAC), the reports would also be distributed to the Department of Homeland Security’s Industrial Control Systems Cyber Emergency Response Team (ICS-CERT). NERC will be required to file an annual report with the commission with anonymized summaries of the reports.
Seeking Balance
In its 2017 State of Reliability Report, NERC recommended redefining reportable incidents “to be more granular and include zero-consequence incidents that might be precursors to something more serious.” Although NERC received no reports of cybersecurity incidents during 2016, it noted that DOE’s Electric Disturbance Reporting Form OE-417 included two suspected cyberattacks and two actual attacks for the same period and that ICS-CERT responded to 59 cybersecurity incidents in the energy sector in 2016.
“Our directive is intended to result in a measured broadening of the existing reporting requirement in reliability standard CIP-008-5, consistent with NERC’s recommendation, rather than a wholesale change in cyber incident reporting that supplants or otherwise chills voluntary reporting, as some commenters maintain,” the commission wrote. “Indeed, as NERC contends, we believe that the new ‘baseline understanding, coupled with the additional context from voluntary reports received by the E-ISAC, [will] allow NERC and the E-ISAC to share that information broadly through the electric industry to better prepare entities to protect their critical infrastructure.’”
The ESP is defined by NERC as the “logical border surrounding a network to which BES cyber systems are connected using a routable protocol.” EACMS include firewalls, authentication servers, security event monitoring systems, intrusion detection systems and alerting systems.
“Since responsible entities are already required to monitor and log system activity under reliability standard CIP-007-6, the incremental burden of reporting of the compromise or attempted compromise of an EACMS that performs the identified functions should be limited, especially when compared to the benefit of the enhanced situational awareness that such reporting will provide,” the commission said.
Report Preferable to Data Request
The commission concluded a reporting requirement is preferable to a “perpetual” data request to collect the same information, saying it is “more aligned with the seriousness and magnitude of the current threat environment, and more likely to improve awareness of existing and future cybersecurity threats and potential vulnerabilities.”
It noted that “the commission will have the ability to review and ultimately approve the standard, as opposed to the opportunity for informal review that the commission would have of a data request.”
Timelines
The commission told NERC that it should consider the threat posed by attacks in developing its reporting thresholds and timelines.
“Higher risk incidents, such as detecting malware within the ESP and associated EACMS or an incident that disrupted one or more reliability tasks, could trigger the report to be submitted to the E-ISAC and ICS-CERT within a more urgent time frame, such as within one hour, similar to the current reporting deadline in reliability standard CIP-008-5. For lower risk incidents, such as the detection of attempts at unauthorized access to the responsible entity’s ESP or associated EACMS, an initial reporting time frame between eight and 24 hours would provide an early indication of potential cyberattacks. For situations where a responsible entity identifies other suspicious activity associated with an ESP or associated EACMS, a monthly report could, as NERC states, assist in the analysis of trends in activity over time.”
Top Challenge
Commissioner Neil Chatterjee said protecting the grid from cybersecurity threats is one of FERC’s top challenges. “Both the Department of Homeland Security and Federal Bureau of Investigation have issued multiple public reports describing intrusion campaigns by Russian government cyber actors against our critical infrastructure, including the electric grid,” he said in a statement. “While thankfully none of these intrusions have resulted in an actual power outage, they do represent an unsettling uptick in attempts to undermine America’s critical infrastructure systems.”
“Cyber threats to the bulk power system are ever changing, and they are a matter that commands constant vigilance,” added Chairman Kevin McIntyre.
Split Ruling on NERC Rules of Procedure
In a separate order, FERC also approved in part and denied in part NERC’s proposed revisions to its Rules of Procedure (RR17-6).
The commission approved NERC’s proposed revisions to Section 900 to clarify the scope and governance structure of its training and continuing education programs.
But it ordered NERC to restore sections of its personnel certification rules the safety organization had proposed for deletion from Section 300. The commission said it disagreed with NERC’s contention that the sections, pertaining to procedures for suspending an operator’s certification, dispute resolution and disciplinary action were “programmatic detail” that can be transferred to NERC manuals.
“If these provisions were removed from the NERC Rules of Procedure and remain only in a NERC manual, they would be subject to further change with minimal, if any, stakeholder input and without commission review,” FERC said. “This is not appropriate because changes in the provisions for suspension, dispute resolution or disciplinary actions could have a significant impact on a stakeholder’s or individual’s rights and obligations.”
Peak Reliability shook the West on Wednesday, saying it will wind down its role as a reliability coordinator (RC) and withdraw from an effort to develop a regional electricity market competing with CAISO.
The Vancouver, Wash.-based company said it expects to shut its doors as early as Dec. 31, 2019, after transitioning its customers to other RCs. It was feedback from those customers commenting on Peak’s budget discussions that prompted the move to cease operations, according to CEO Marie Jordan.
“At this point, we’ve received overwhelming feedback from a supermajority of our funders that there’s more support for the wind-down budget scenario and the wind-down of Peak,” Jordan said during a call to announce the decision.
Jordan said it was in the best interest of reliability “that we respond sooner than later and begin planning now for that orderly transition from Peak as the RC.”
“I have therefore engaged executive leadership within the interconnection to begin discussions on what an orderly transition for Peak would look like in a wind-down scenario,” she said.
Jordan noted that funder support for an alternative budget scenario outlining a slimmed-down “transitional” RC was “almost non-existent at this time.” The transitional RC plan Peak floated in May would have cut executive jobs, reduced the size of the board of directors and eliminated some administrative processes in an effort to keep the organization afloat past 2019. (See CAISO Puts $18.5 million Price Tag on RC Services.)
By Wednesday, only two of Peak’s 52 funders had submitted letters of intent (LOIs) indicating their support for the transitional proposal. Still, Peak said it will continue to accept funder comments on the transitional RC draft funding amount until July 30 and post its proposed budget and “strategic direction” Aug. 6, as scheduled.
Picking up the Pieces
Peak’s decision marks a rapid turnabout for an organization that just months ago was pushing ahead with plans to develop a “marketplace built by and for the West” in partnership with PJM subsidiary PJM Connext. (See Peak, PJM Pitch “Marketplace for the West.)
Jordan said Peak would be ending its relationship with PJM “to prevent the wind-down of Peak from creating an unnecessary distraction to the PJM Connext initiative, which has over the past several months gained traction among the Western entities.”
While that effort may be hobbled by the absence of Peak, PJM said in a statement that it will “continue conversations” with potential participants to develop a “member-owned market for the West.”
“While some revision of the business plan will be required to describe how the business will be organized in the absence of Peak, the fundamental nature of the proposition and its value remain unchanged,” the RTO said.
Peak’s fall could spell opportunity for yet another RC service provider looking to expand into the West.
“Peak’s announcement comes at a time when SPP is devoting significant effort to developing plans to provide unparalleled reliability coordinator services in the West,” SPP COO Carl Monroe told RTO Insider. “We are appreciative for Peak’s commitment to ensure an orderly transition of RC services to other providers, and hope their customers and others see this as an opportunity to partner with SPP as we bring new levels of value and reliability to the Western Interconnection, just as we have done in the Eastern Interconnection since 1941.”
During Wednesday’s call, Jordan said she saw the potential for an RC competitor to CAISO.
“I think it would be foolish of me to assume that there’s just one option,” she said. “It’s my personal belief [that] there is room for more than one RC in the Western Interconnection.”
Failed Gamble?
In some ways, Peak may have been undone by its own ambitions. Within weeks of the company’s announcement that it planned to develop market services in conjunction with PJM — putting it in direct conflict with CAISO’s regionalization aspirations — CAISO declared that it was “reluctantly” leaving Peak to itself become an RC. It said it could provide RC services “at significantly reduced costs.”
In April, shortly after Peak and PJM entered the “commitment phase” of their proposed market effort and issued an abstract of their business plan, CAISO divulged that most of the Western Interconnection had signed nonbinding LOIs for its RC services after it proposed to charge rates dramatically undercutting Peak’s. By early May, Peak’s vulnerability had become more apparent when it issued the transitional RC plan, what looked like a last-ditch effort to stem the loss of most its funding base.
In June 2017, Jordan testified along with Monroe before the Colorado Public Utilities Commission to keep Mountain West Transmission Group from defecting to SPP for RC services. (See SPP, Peak Reliability Pitch RC Services for Mountain West.)
“A single RC has been a very important piece of the vision for reliability in the West,” Jordan told the PUC. “Based on feedback I get from our funding members, our model is becoming so much more reliable for them, from the time we started … to where we are today. It’s been tremendous growth.”
A year later Peak said it would close its doors.
For its part, CAISO was diplomatic about Wednesday’s development and said Peak’s decision has “little direct impact” on its plans to offer RC services.
“Our design of the RC function is scalable and has always incorporated the ability to serve a significant portion of the load in the Western Interconnection,” ISO spokesperson Anne Gonzales said in an email. “The ISO is committed to working with Peak and others in the West on a transition that focuses on reliability, as balancing authorities and transmission operators make their selection of an RC service provider.”
More than 170 staff in Peak’s Vancouver and Salt Lake City offices will lose their jobs as the company winds down its operations. Jordan said Peak will offer six months of severance to every employee to retain them, pointing out they will still be needed to run the organization into 2020 to perform close-out audits and wrap up other business.
“It’s been a challenging time for all of us and our employees, so I appreciate everyone’s interest in Peak and the support that you’ll give us going forward,” Jordan told stakeholders on the call.
RENSSELAER, NY – NYISO said Monday it could implement carbon pricing in New York’s wholesale electricity markets no earlier than the second quarter of 2021.
That “date is intended to provide certainty to energy trading markets that are currently pricing power prior to Q2 2021,” Michael DeSocio, senior manager for market design, told a July 16 meeting of the state’s Integrating Public Policy Task Force (IPPTF), the group exploring how to incorporate the cost of CO2 emissions into NYISO’s markets.
Con Edison’s East River Generating Plant emitted 2,261,240.56 tons of CO2 in 2016 according to NYSDEC.
The ISO also proposed wholesale market suppliers with active renewable energy credit (REC) contracts dated prior to Jan. 1, 2020, not be eligible to receive the carbon pricing portion of the market’s locational based marginal prices (LBMP) as part of their payment for supplying energy.
The cutoff date would help reduce or eliminate the potential for double payments to resources eligible for REC payments, DeSocio said.
Emissions Reporting
Speaking at the meeting, Ethan Avallone, NYISO senior market design specialist, presented proposals on emissions reporting, billing and bilateral transactions under a carbon pricing scheme.
The ISO is proposing to develop a process for generators to report how much carbon they are emitting and later true-up their data based on actual emissions. The ISO would issue applicable charges or credits to adjust payments based on reported actual emissions.
Representing New York City, Couch White attorney Kevin Lang asked, “If what they’re reporting is their actual emissions, what is the true-up?”
“In some cases, the initial reporting could be an estimate of emissions,” Avallone said.
“Our understanding also is that there’s a lot of validation that happens to some of this data, so it’s allowing for that validation process to happen,” added IPPTF Chair Nicole Bouchez, the ISO’s principal economist.
Talen’s Athens generating plant in Greene County emitted 1,308,259.69 tons of CO2 in 2016, according to NYSDEC. | Talen Energy
Some CO2-emitting resources submit emissions data to EPA, while others provide data to the state’s Department of Environmental Conservation. Some resources submit no data at all. But the majority of emitting resources should already have processes in place enabling them to provide emissions data to the ISO, Avallone said.
Billing Overview
The proposal calls for emitting resources to provide the ISO with weekly emissions data estimates during the billing month, while also providing updated emissions data when available. Bills from the ISO become final roughly eight months after the initial monthly invoice.
NYISO envisions that adjustments to the carbon charge would be paid to or collected from emitting resources that provide emissions data updates before a specified deadline for emissions reporting, which could be consistent with the current billing challenge period of up to five months after the initial invoice.
Resources that report to the ISO that they are subject to the Regional Greenhous Gas Initiative would be charged the gross social cost of carbon (SCC) minus the most recently posted quarterly RGGI price. Suppliers not covered by RGGI would incur a carbon price equal to the gross SCC.
Lang suggested greater granularity in the RGGI price calculation could help the ISO minimize the risk of over- or underpaying generators.
He said previous RGGI prices have fluctuated and future price estimates vary significantly, adding that generators purchase RGGI allowances at different times and in multiple ways.
For those reasons, Lang said he was concerned about basing the carbon price adjustment solely on a quarterly auction price.
In response to a request to use the actual RGGI price paid by the resource instead of the quarterly price, Bouchez said such a move would shift the risk from asset owners to consumers.
“In our markets we push that risk onto the asset owners,” Bouchez said. “They’re the ones best suited to manage that, and the consumers shouldn’t have to pay for that risk.”
The ISO additionally proposed that CO2-emitting resources injecting into the grid to fulfill a bilateral transaction would also be subject to the carbon charge.
| NYISO
Transmission customers purchasing energy through bilateral transactions would receive an allocation of the carbon residual. This treatment would be similar to how other billing residuals are allocated to transmission customers’ actual energy withdrawal, Avallone said.
The plan calls for the IPPTF to deliver draft recommendations by Aug. 1, including suggestions regarding additional meetings or work anticipated by the task force. The group will finalize recommendations by the end of October and issue the proposal by the end of December 2018.
“We would request that when NYISO issues its straw proposal August 1, [New York Department of Public Service (DPS)] staff at the same time give a status update on how the process is going and whether or not it’s still supported. It would be helpful to understand DPS’s plans with regard to timeline and decision points on issues that are within its control, as in the setting of the carbon price,” said Ben Carron, National Grid’s senior analyst for regulatory strategy and integrated analytics.
“We’re still as committed as we were day one to review pricing carbon and determine whether or not it’s cost effective,” DPS Manager Alan Michaels responded.
The IPPTF said it foresees no changes to the concept of carbon pricing, and the analysis will use the gross SCC as recommended by DPS staff in April, which was based on a value already adopted by the Public Service Commission using the figure from the Interagency Working Group (IWG) on Social Cost of Greenhouse Gases.
The PSC’s March 2017 Value of Distributed Energy Resources (VDER) Order (15-E-0751) set the compensation value at the higher of the Tier 1 REC or SCC minus RGGI. Converted by DPS to dollars per ton, the latter figure would gradually increase over the coming decade from $40.74/ton in 2020 to $56.77/ton in 2030.
The carbon charge will be applied to internal suppliers, and the task force will add more details to the emissions reporting proposal and also consider that emitting resources might only report EPA-accepted data.
The task force’s remaining work includes adding details to the proposal to estimate the carbon component of the LBMP for transparency, and application of the carbon charge to external transactions, which will reflect the July 9 presentation on benefits and drawbacks of the two options considered. (See New York Looks at Carbon Price Impact on LBMPs.)
Regarding allocation of the carbon charge residuals to loads, issue Track 5 of the carbon pricing initiative will report the allocations of all three possible methodologies, as well as changes to other ISO markets and planning processes, Bouchez said.
The task force next meets Aug. 6 at NYISO headquarters to review draft recommendations for issue Track 5 regarding customer impacts, especially the assumptions used in modeling a dynamic change case.
VALLEY FORGE, Pa. — Stakeholders at last week’s Planning Committee meeting endorsed PJM’s recommended load model for the 2018 reserve requirement study, which uses data from 2003 through 2012.
The study was adjusted to reflect the fact that load within the RTO’s footprint peaks during a different week than the area outside the footprint included in the model.
PJM selects a model for the study because the coincident peak distributions from the load forecast can’t be used directly in the PRISM modeling software, the RTO’s Patricio Rocha-Garrido said.
American Municipal Power’s Ryan Dolan asked why staff chose not to use the best-performing model from 2004 to 2012.
“We prefer more data to less data,” Rocha-Garrido replied, adding that the extra year “is a close second.”
“What’s the point of doing the test if we’re not going to accept the result?” Dolan asked.
“The test informs the decision,” Rocha-Garrido said.
CETL Changes
The complex interdependency of PJM’s procedures was on display when a presentation on proposed revisions to Attachment C of Manual 14B — billed as improving transparency and clarity — evolved into a discussion on potential impacts to capacity emergency transfer limits (CETLs) and concerns about how that might affect zonal capacity requirements.
The RTO’s Jonathan Kern presented the proposal, which would also “correct any conflicts between how the procedures are described and how PJM actually implements them” and include “a few minor procedural changes.” Many of the revisions focus on procedures for the load deliverability test or calculating CETLs.
Several stakeholders asked PJM to delineate how each revision might potentially affect CETL calculations. Kern said staff could provide all the distribution factors but that it was “premature” to perform full CETL analyses because the RTO hasn’t yet decided to include any of the external facilities. Staff believe considering them is “prudent” to ensure they’re not “turning a blind eye” to the potential impact of external systems if PJM analyses don’t account for them.
Market Efficiency
It appears the toil at a July 5 meeting of the Market Efficiency Process Enhancement Task Force has paid off. PJM’s Brian Chmielewski reviewed results of a last-minute poll that was requested to be completed in the few days between the task force’s meeting and the PC. (See PJM Market Efficiency Project Rules Could Slip Deadline.)
At issue was a set of six proposals to address how PJM evaluates and selects discretionary transmission projects. The poll showed majority support for Package G, which would exclude from the base case those units with facility study agreements (FSAs) and suspended interconnection service agreements and their associated network upgrades at the time of case build, unless they are needed for reliability.
Energy benefits of projects that are proposed to be in service later than the Regional Transmission Expansion Planning year would be adjusted to account for any savings forgone because of the later in-service date. Annual mandatory sensitivity studies would include FSA units only if they were excluded from the base case analysis. Sensitivities would be used for evaluation of a proposals’ robustness and sizing, but not for benefit-to-cost ratio tests. Parameters would be decided prior to the beginning of the project proposal window. In all simulated years, generation and transmission topology would be set at the RTEP-year level.
LS Power’s Sharon Segner asked that the proposed Tariff language be ready to review at the task force’s next meeting on July 20 so it can be discussed prior to the July meeting of the Markets and Reliability Committee.
Greg Poulos, executive director of the Consumer Advocates of the PJM States, asked for more clarity on FSA issues because they are “certainly of concern” to some advocates.
Segner and Public Service Electric and Gas’ Alex Stern, who had requested the fast turnaround on the poll, praised Chmielewski and other staff on the task force for compiling it so quickly.
Cascading Trees
PJM’s Aaron Berner reviewed staff’s efforts to incorporate resilience objectives into transmission planning. As part of that initiative, staff have developed a visualization tool called “Cascading Trees” that considers the potential impact to the grid of “more extreme” events and analyzes probabilities of what issues such events could cause.
“That will play an important piece in how we develop plans,” Berner said. He clarified that the current analyses assume the trigger event has occurred and said it’s unclear whether staff will consider calculating the probability of the triggering event happening in the first place.
Stakeholders seized on the analysis with questions about PJM’s plans for addressing resilience. Berner turned many of those questions away, emphasizing that the analysis remains in its infancy.
“That’s more in depth than I planned on going into today,” Berner said.
In response to a question from Dolan, Berner confirmed that staff are working with TOs, many of which already have resilience factors included in their internal planning assumptions.
“We do not intend to move forward in isolation. We are having conversations with the transmission owners on how this might work,” Berner said.
PJM’s Steve Herling reminded stakeholders that staff are simply acting on their marching orders.
“The direction we’re taking to pursue resilience is coming from the board,” he said.
RTEP Processes
Berner and PPL’s Frank “Chip” Richardson presented plans for reorganizing the processes for reviewing transmission projects. Berner covered plans for the sub-regional RTEP and Transmission Expansion Advisory Committee. Richardson explained TOs’ plan for supplemental projects.
The process designs are similar and stick to the requirements outlined in FERC’s ruling that TOs weren’t properly complying with their obligations under Order 890 to involve stakeholders early enough to solicit their needs and provide required information before making decisions to proceed with “supplemental” projects — transmission expansions or enhancements not required for compliance with PJM reliability, operational performance or economic criteria. TOs describe them as projects planned by each company individually to address items not addressed by PJM, such as customer service, replacement of failing, poor performing or antiquated equipment and enhancements to the security of their transmission system. (See Group Contests ‘Supplementals’ Ruling as PJM, TOs Advance.)
Stakeholders pressed TOs for more detail on how they plan to engage in the meetings, but Richardson emphasized the TOs’ focus on implementing the changes.
“Certainly, as we implement this, people will be able to voice opinions about what they think … but we’re not focused on changes right now. We’re focused on getting it implemented,” he said. “When we’re ready to have you take a look at it, we’ll let you know. … We’ll think about [feedback] after we get through a few cycles.”
VALLEY FORGE, Pa. — PJM’s Ray Fernandez told attendees at last week’s Market Implementation Committee meeting that his staff are still completing calculations for part of FERC’s ruling on retroactively reallocating costs for certain transmission projects in the RTO’s territory (EL05-121).
Staff have requested to extend the compliance filing deadline until July 30, Fernandez said. In May, FERC issued an order approving a settlement on the RTO’s procedure for allocating the costs of major transmission projects. The settlement 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. (See “Response to FERC’s Cost Allocation Order,” PJM Market Implementation Committee Briefs: June 6, 2018.)
Staff are revising the allocations on 14 technical worksheets to reflect the approved split of 50% on the original annual load-ratio share basis and 50% on the solution-based distribution factor (DFAX) method. Market participants will need to review all the worksheets to understand the full implications of the revisions, Fernandez said. He hopes to have them completed within two weeks.
The order also includes a “black box” settlement for projects from 2007 through 2015 that will be rebilled over the next 10 years. Fernandez said those reallocation amounts were published as part of the settlement.
Stakeholders unanimously endorsed proposed revisions for aggregating seasonal resources. PJM’s Andrea Yeaton presented the proposal, which is designed to better account for the resources’ accumulated capability. (See “Seasonal Aggregation,” PJM Market Implementation Committee Briefs: June 6, 2018.)
Independent Market Monitor Joe Bowring questioned staff’s planned procedure for day-ahead notification because PJM continues to use demand response as an emergency resource.
“Typically, you don’t have a day’s notice; you have an emergency,” he said.
PJM’s Pete Langbein said grid operators will continue to dispatch DR as necessary during emergencies but will use this approach “if we have the luxury” of receiving notification the day before. He said operators will continue the practice of dispatching resources with registration-level granularity, which is usually limited to a single customer.
Credit Requirements
Stakeholders resoundingly endorsed PJM’s recommended revisions to the financial transmission rights credit policy, rejecting both a pre-existing alternative and a proposal offered by DC Energy’s Bruce Bleiweis during discussion. Stakeholders also indicated that they strongly preferred the endorsed revisions to the status quo in a sector-weighted vote, with 193 (or 0.92) voting in favor of the changes, with 16 opposed and 11 abstentions. The votes had an endorsement threshold of 0.5.
PJM wants to implement a per-megawatt-hour minimum credit requirement to address potentially large FTR positions that have little or no credit requirements. (See “DC Energy FTR Credit Policy Complaint to FERC,” PJM Market Implementation Committee Briefs: June 6, 2018.)
The endorsed proposal, which PJM recommended, would implement a 10-cent/MWh minimum monthly credit requirement applicable to both FTR bids submitted in auctions and cleared positions held in FTR portfolios. It received 208 votes (0.95) in favor, with 12 opposed and 21 abstentions.
The alternative proposal, which would implement a 5-cent/MWh requirement, received 77 votes (0.35) in favor, with 141 opposed and 15 abstentions.
DC Energy’s proposal received 51 votes (0.44) in favor, with 66 opposed and 119 abstentions. The proposal would have required the credit calculation to account for profits or losses in the market. For example, if PJM calculated a $10 credit requirement and the market participant gained $2 in profit from market positions, the participant would submit $8 in collateral to the RTO. If the participant lost $2, collateral necessary would increase to $12.
Bleiweis said he was supportive of the endorsed proposal but hoped for additional revisions. That his proposal progressed to a vote was itself dramatic, as it appeared to have died without being seconded. However, it was announced during voting on the endorsed proposal that Panda Power Funds’ Bob O’Connell had seconded the proposal from the phone, and it was allowed to receive a vote.
PJM’s Bridgid Cummings also reviewed the results of a Credit Subcommittee poll on additional proposals the subcommittee hadn’t endorsed, which found 2% support for a 1- to 5-cent minimum monthly credit requirement on a declining tiered scale based on megawatt-hour volume; 25% support for a $50 million cap on the total minimum monthly credit requirement; 20% support for a $100,000 deductible applicable to the current undiversified adder; and 28% support for status quo.
Balancing Ratio
For anyone confused by the complexities of balancing ratio calculations and performance assessment intervals (PAIs), staff and stakeholders have agreed to develop a presentation for next month’s meeting to compare the proposals on the issue. Currently, there are four.
Bruno said the first proposal was “straightforward” because it would calculate the balancing ratio using the average balancing ratios from the three delivery years that immediately precede the base residual auction or, for years that don’t have at least 30 hours of PAIs, supplementing the actual number of PAIs with estimated balancing ratios calculated during the intervals of the highest RTO peak loads that do not overlap a PAI. PAIs are five minutes apiece.
The second proposal would estimate the number of PAIs expected in the delivery year using the past three years of data, but floored at five hours for calculating the default market seller offer cap (MSOC) and 15 hours for calculating the nonperformance charge rate in Capacity Performance. The proposals would include revisions to the formulas for the nonperformance charge and the MSOC.
Exelon’s Jason Barker noted the proposed MSOC formula wouldn’t always arrive at net cost of new entry multiplied by the balancing ratio if different assumptions for the expected number of penalty hours is employed.
He argued that FERC specifically approved a formula that uses a single assumption about the expected penalty hours and pegs the default offer cap to net CONE. Bruno contended that the commission approved the methodology to arrive at the formula rather than the result itself.
In response to a question by Barker, Bruno said staff “didn’t really have a formulaic approach” for choosing the 15-hour floor for the nonperformance charge, and that they “looked at the data” and came up with “what we thought was a reasonable estimate.”
David Mabry, representing the PJM Industrial Customer Coalition, called it “a balanced proposal.”
Additional proposals from Exelon and Calpine differed with PJM on the PAI calculations for the MSOC and nonperformance charge rate formulas. Calpine’s would floor both at 10 hours and calculate a number based on the past 10 years of data. Exelon’s would use a probabilistic model to look forward. Both would keep constant the number of PAIs used in the two formulas.
Energy Market Caps
PJM’s Susan Kenney reviewed staff’s two-phase plan for addressing issues with Order 831. The proposal offers a short-term fix to address conflicts in PJM’s governing documents, along with a more comprehensive long-term solution. The long-term solution will be less cumbersome than the short-term fix but will require more time to develop. The updated proposal comes after PJM’s short-term proposal failed to receive stakeholder endorsement at the May meeting of the Markets and Reliability Committee. (See “Offer Cap Revisions Stalled Again,” PJM Markets and Reliability Committee Briefs: May 24, 2018.)
PJM is hoping to have the long-term solution ready by Nov. 1, so it should be available several weeks ahead of that so stakeholders can familiarize themselves with the changes prior to implementation, Kenney said.
She outlined some “risks” of the short-term proposal, which would cap all offers at $1,000/MWh by default and allow higher offers to submit a request for verification. The Monitor’s Catherine Tyler said those concerns are the basis for the Monitor’s preference for the “switch to cost” method, which would provide generators the option to exclude price schedules from dispatch. Otherwise, generators can request the ability to submit price-based offers in line with verified cost-based offers, but they are then on the hook to ensure price-based offers at each segment remain compliant with verified cost-based offer caps.
The long-term solution will automate the process.
VRR Curve Update
PJM’s Jeff Bastian reviewed the RTO’s proposed revisions for its quadrennial review of the variable resource requirement (VRR) curve in its Reliability Pricing Model capacity market construct, including a table comparing how the different revisions would impact the gross CONE calculation.
Based on an analysis it commissioned from the Brattle Group, PJM is recommending switching its reference resource from the Frame F to the Frame H of a General Electric turbine and updating the unit heat rate, Bastian said. The frame switch would reduce the net CONE from $405/MW-day of unforced capacity to $308. Some generators have argued against the recommendation. (See Factors in New PJM VRR Curve Still in Question.)
In the table, PJM estimated the gross CONE for 2019 by escalating the 2018 figure by nearly 3%. Bastian said PJM believes it’s important to get the 10% cost adder into the dispatch cost of the reference resource. Overall, PJM’s recommendations would reduce the energy and ancillary service offset by 22% from $72/MW-day of unforced capacity to $56 and reduce the net CONE from $333 to $251.
PJM is targeting Oct. 12 to file for FERC approval, and seeking endorsement votes by the Markets and Reliability Committee on Aug. 23 and the Members Committee during an Aug. 31 teleconference.
VOM Update
As time runs out to square away where generators can recover variable operations and maintenance (VOM) costs, stakeholders remain separated on the issue. PJM is attempting to resolve those differences prior to concluding its quadrennial review of the VRR curve since the costs could be recoverable in either the capacity or the energy market.
There are four proposals set for a vote at the July meeting of the MRC, and while the voting order on the proposals is set, a recent submission from Orange and Rockland Utilities/Rockland Electric Co. has threatened to upset the likely voting. A proposal from American Electric Power that allows use of default U.S. Energy Information Administration calculations will be up first, followed by PJM’s proposal, a proposal from the Monitor and finally RECO’s offering.
AEP’s Brock Ondayko walked through the default proposal, which includes a friendly amendment introduced at the June meeting of the MRC that would prohibit units that failed to clear in the year’s capacity auction from including fixed costs in their energy offers. (See “Variable Operations & Maintenance Packages,” PJM MRC/MC Briefs: June 21, 2018.)
PJM’s Melissa Pilong reviewed the RTO’s package, which remains unchanged from past discussions. It’s the only proposal that would allow units to include fixed costs in their energy offers if they failed to clear in the year’s capacity auction.
Tyler presented the Monitor’s proposal, which would limit costs allowed in energy offers to short-run marginal costs.
“The governing documents are just not clear on these costs and only the IMM package would clean up the definitions,” she said.
Stakeholders have been reluctant to support the Monitor’s proposal because of concern about the definition.
“Part of our disagreement comes down to the definition of short-run marginal costs,” Pratzon said.
RECO’s Brian Wilkie said his proposal was meant to strike a compromise between the generator-friendly and load-friendly proposals to ensure that stakeholders wouldn’t be stuck with the status quo if coalitions stood their ground and those proposals failed to win endorsement. RECO’s proposal would allow generators to recover VOM costs up to limits that would be posted into Manual 15. Almost all unit types would be capped at $3.50/MWh for the costs. Sub- and super-critical coal and biomass would be capped at $4/MWh; nuclear at $3/MWh; and wind, solar and hydro at $0/MWh.
“We agree with the IMM’s definition of VOM is the simplest way to put it,” Wilkie said.
He said PJM staff told him there could be “exponential” cost increases for load if either the PJM or AEP proposal is implemented and later combined with the fast-start or convex hull revisions being considered in PJM’s Energy Price Formation Senior Task Force. (See PJM Board Seeks Reserve Pricing Changes for Winter.)
Generation representatives criticized Wilkie’s use of the term “exponential,” arguing that characterization was validated by estimates. Gary Greiner of Public Service Electric and Gas said it’s unfair to group in various issues when considering isolated proposals.
“I guess that depends on what you throw into the toy box,” he said. “The proper way to do it is to look at this issue [individually] and see what impacts it would have on price.”
“Exponential implies a big change,” Barker said. “To date, I don’t know what that value is.”
The Monitor supported the proposal, along with Mabry and Greg Poulos, executive director of the Consumer Advocates of the PJM States (CAPS).
“It’s not our proposal,” Tyler said of RECO’s caps, but “we believe it is better than the status quo.”
PJM attorney Chenchao Lu expressed concern about whether it would be permissible to ask FERC to approve rules that would potentially cap cost recovery below actual operating costs. Wilkie had said earlier that he was not an attorney and therefore wasn’t sure whether FERC would accept the proposal.
Wilkie said he was willing to revise the proposal to incorporate feedback from generators. Greiner had noted the changes could create a “cycling nightmare for our ops people,” and Wilkie said he would consider how to address the concerns. Pratzon said more discussion might be necessary.
Wilkie agreed to let PJM know on Thursday — before the agenda is published for the July meeting of the MRC — whether they have received much engagement on their proposal. PJM will decide, depending on that update, whether to put the issue for a vote on the agenda.
Must-offer Revisions
Bruno presented a proposal on revising the rules for what units must offer into capacity auctions. The proposal addresses many of the concerns Exelon expressed when it proposed investigating the issue. (See “Exelon-backed Analyses Approved,” PJM Market Implementation Committee Briefs: March 7, 2018.)
Bowring criticized the proposal, specifically noting his concern that this could allow hoarding of capacity injection rights and block new entry when a unit is uneconomic. He said units should offer their costs in the auction and if they do not clear, the market message is that the units are not needed and not wanted by the market at that price.
VALLEY FORGE, Pa. — Grid operators faced several high load forecasts and hot weather alerts last month but never had to take emergency procedures, PJM’s Chris Pilong told attendees at last week’s Operating Committee meeting.
Pilong reviewed five hot-weather alerts for the month, along with several that were called for early July, in his system operations report. On July 2, for example, the load forecast called for a roughly 152-GW peak, but several factors mitigated the actual demand to about 140 GW, he said, including showers in the RTO’s western region and the fact that date fell on a Monday going into a holiday.
“We were on track for 152 [GW]. Had we gotten there, we would have been OK, but that western rain did bring the loads down,” he said.
PJM’s Stephanie Monzon detailed the operations report for June, which included three spin events. David Mabry, who represents the PJM Industrial Customers Coalition, requested more detail on a June 4 event, caused by a trip loss of 1,210 MW from Unit 1 of the Braidwood nuclear plant. He said it seemed “unusual” the event was resolved in six minutes when the estimate for Tier 1 response was more than 1,000 MW higher than what actually responded. Monzon agreed to investigate and report back.
Real-time 30-minute Reserves
Stakeholders endorsed PJM’s proposal to create a real-time 30-minute reserve product along with a methodology for how to calculate a procurement objective for each year. PJM’s Vince Stefanowicz reviewed the proposal, which has remained consistent throughout the stakeholder process. (See “30-Minute Reserves Target Set,” PJM Operating Committee Briefs: May 1, 2018.)
Mabry urged staff to send the proposal to the Energy Price Formation Senior Task Force, which is focused on revisions to PJM’s energy market. He said working through it there would help him become more “comfortable” with the methodology and the justifications for the target procurement, which would be 3,784 MW for 2018.
While the proposal was endorsed with no objections, there were 48 abstentions that included Mabry’s coalition.
Black Start Fuel Assurance
PJM’s Glen Boyle outlined revisions to the issue charge for setting black start fuel requirements, which include pushing the anticipated start date for the stakeholder group back a month to September.
Staff also added “critical non-fuel consumables” to the list of requirements to develop and minimum tank suction level to compensation-related issues to hash out.
Load Shed Details
Pilong presented a detailed review of the May 29 load shed event in northwest Indiana. The event was short and the impact localized, but it was the first such event that might trigger the financial penalties implemented as part of Capacity Performance.
The incident analysis found that the Twin Branch-Jackson Road 138-kV line and the Jackson Road 345/138-kV transformer 3 tripped after the line contacted a tree around 12:30 p.m. Five other lines in the area were already offline for maintenance.
A contingency analysis found that if the South Bend-Twin Branch line or transformers at Twin Branch also went out, the Edison-Kankakee line might trip offline and potentially cause a cascading failure. To address this, PJM recalled two of the lines on planned outages and ordered the local utility, American Electric Power, to shed approximately 21 MW of load to relieve the Edison-Kankakee line.
About 15 minutes later, the transformer was restored to service, allowing PJM to end the load shed. The recalled lines didn’t come back online for at least another 90 minutes. The tripped line was back online slightly less than 12 hours after it tripped.
GT Power Group’s Dave Pratzon asked about a sixth line in the area that was also on a planned outage. Pilong said recalling it wouldn’t have relieved the situation because it’s on the western side of the Edison-Kankakee line and the issue was on power flowing from west to east, so it couldn’t have pushed power into the area.
“There were a lot of outages this day. That [one] didn’t have any impact,” Pilong said.
He said one of the lines had been on a planned outage since April 18, while the two lines that were recalled had started outages that day. Because the situation was resolved so quickly, operators never got the point of dispatching DR but might have if the situation had persisted, he said.
Regulation Update
PJM’s Eric Endress reviewed performance of the RTO’s regulation signal, which changed in January 2017. FERC has since rejected the compensation portion of PJM’s plan to revise its regulation market, but the signal has remained the same. (See FERC Postpones Tech Conference on PJM Regulation Market.)
Endress showed that the marginal benefits factor, which PJM has argued to use and FERC has repeatedly denied, has stayed fairly consistent since May 2017, ranging between 1.01 and 1.33 each month.
Combustion turbines have consistently been top performers in both the slower, sustained-output RegA signal and the faster, dynamic RegD signal. Hydro was also a top RegA performer, followed by demand response and steam. Storage was a top RegD performer, followed by DR and hydro.
RegD units were pegged for more than 30 minutes no more than four times in a given month, reaching that rate only in March 2017. The RegD signal is meant to peg unit response for short durations. RegA resources, which don’t have response limitations, were generally pegged more often and for longer periods.
Resilience
PJM’s Dean Manno announced that the RTO plans to substantially expand its procedures for addressing cyberattacks. The details came as part of a presentation on operational changes planned to increase system resilience, which include a procedure to freeze system changes and requiring transmission owners to inform PJM when they disable the auto-reclose feature on any transmission facilities.
The procedures will address responses to cyberattacks against PJM or its members, as well as the telecommunications network between them.
FERC last week authorized Dominion Energy’s proposed acquisition of SCANA and its South Carolina Electric & Gas subsidiary, saying the transaction was consistent with the public interest (EC18-60).
Dominion CEO Tom Farrell II
“We are pleased by the FERC’s considered and timely action,” Dominion Energy CEO Thomas Farrell II said in a statement. “We will continue working toward achieving the other required regulatory approvals and completing our transaction by the end of this year.”
The deal has been approved by the Georgia Public Service Commission and federal antitrust regulators. It still requires approval by SCANA shareholders, the North Carolina and South Carolina public service commissions, and the Nuclear Regulatory Commission.
Dominion offered to buy SCANA on Jan. 3 for $7.9 billion in stock and the assumption of $6.7 billion in SCANA debt. (See Dominion to Buy Distressed SCANA for $8B.) SCANA became an acquisition target after its failed attempt to add two reactors to the V.C. Summer nuclear plant. The company and its partner on the project, Santee Cooper, which is owned by the state of South Carolina, spent $9 billion on the expansion before pulling the plug on it last summer.
The decision created a firestorm in South Carolina, where SCE&G and Santee Cooper ratepayers have been shouldering the project’s cost. The state late last month enacted a law directing the Public Service Commission to cut SCE&G’s rates by an amount that would cover nearly all the portion of the rates that go to covering the failed nuclear project’s cost. SCE&G responded with a lawsuit challenging the law’s constitutionality in federal court.
FERC cleared the way for South Carolina Electric & Gas to become part of Dominion. | SCE&G
SCE&G has been sued by its customers over the project, which is being investigated by the FBI, the South Carolina State Law Enforcement Division and the Securities and Exchange Commission, none of which has filed any charges.
SCANA said Friday it has added two independent directors to its board and appointed them to a Special Litigation Committee charged with investigating claims alleged against some of its current and former directors in shareholder lawsuits against it in federal and South Carolina courts.
MISO’s proposal to allow merchant HVDC lines to connect to its system is incomplete, FERC informed the RTO last week in a deficiency letter.
In its filing with the commission, MISO said it based the proposed merchant agreement on its existing generator interconnection agreement and procedures, but FERC on July 12 asked it to explain why it was appropriate to do so — among other questions (ER18-1410). The commission gave MISO 30 days to file a response.
HVDC lines in MISO footprint | MISO
The RTO’s proposal involves treating merchant HVDC as transmission rather than generation, and requires merchant developers to acquire MISO injection rights or a precertification that the system will be able to reliably manage the capacity and energy from proposed lines at the point of connection. (See MISO Plan Provides Tx Treatment for HVDC Lines.)
FERC asked MISO why the timeline and termination provisions for the proposed agreement differ from those in the GIA, given the RTO’s claim that the former is based on the latter.
The proposed HVDC agreement stipulates that if injection rights are not converted to external network resource interconnection service within three years of a line’s commercial operation date, MISO will terminate interconnection service. With the RTO’s GIA — which doesn’t include the concept of injection rights — an interconnection customer can extend its commercial operating date for up to three years without risking queue withdrawal. MISO had said the termination provision matched that of its GIA because in both cases, the “underlying agreement may be terminated if commercial operation is not achieved within three years of the commercial operation date.”
FERC also asked MISO to clarify whether it plans to simultaneously update its merchant HVDC connection agreement when it proposes to make changes to its GIA.
The HVDC agreement also includes a provision stating that transmission owners will be able to review any modifications to a connection facility that affects them, but FERC asked MISO how it would move forward with a HVDC connection request if a party to the connection agreement does not accept a modification.
The commission also asked MISO to describe the processes behind examining injection rights and its proposed merchant HVDC connection service study.
SPP’s Market Monitoring Unit said last week that energy prices averaged about $23/MWh in the spring, despite higher loads.
The MMU’s quarterly State of the Market report also highlighted the recent merger between Westar Energy and Great Plains Energy, the parent company of Kansas City Power and Light, although its completion happened outside the report’s March-May range. (See Westar-Great Plains Merger Wins Final Approval.)
The Monitor said the combined company would have accounted for 19.2% of total system load over the period, making it the largest energy user in SPP’s market footprint. Additional information will likely be included in the summer report, MMU Executive Director Keith Collins said.
The report indicates that spring hourly average load was up 8% from 2017 — and 14% for May alone — as a result of abnormally high temperatures. Average day-ahead prices increased 13% to $23/MWh over last spring, while average real-time prices gained 10% to $22/MWh.
| SPP MMU
Spring’s average monthly gas price at the Panhandle Eastern hub was $2.14/MMBtu, down from $2.70/MMBtu in 2017. Gas prices in spring 2016 were $1.68/MMBtu.
Coal-fired resources continued to account for a smaller share of the RTO’s energy production at 37%. Wind resources accounted for almost 29% of generation, with nameplate wind capacity increasing to 17.7 GW by June, up from 12.8 GW at the end of May 2016.
The Monitor said occurrences of negative price intervals decreased from the winter period and last spring. This spring, prices were negative in just over 5% of real-time intervals, and just under 2% of day-ahead hours.
| SPP MMU
According to the report, overall congestion in the footprint has declined, with real-time intervals with a breached or binding flowgate dropping from 40% last spring to 20% this spring.
The Monitor recently conducted a study of day-ahead market congestion and auction revenue rights bidding behavior following complaints by market participants that were unable to obtain hedges in the ARR process. The study led to three main conclusions, the MMU said: Successful ARR nominations have decreased; the market’s overall need for hedges has increased; and nomination behavior has remained relatively consistent.
The growth in day-ahead congestion correlates with the overall increase in wind production, the Monitor said. It said the 28 GW of additional wind capacity planned in the generation interconnection queue will likely increase the need for hedging.
The MMU recommends “further review and consideration of the auction revenue right process by the RTO and stakeholders” going forward. It will host a webinar July 25 to discuss the spring report.
SPP Preps AECI Seams Project for 2nd Crack at FERC
David Kelley, SPP’s director of seams and market design, told the Seams Steering Committee on Friday that the RTO has performed additional analysis in order to gain FERC approval of a seams project with Missouri-based Associated Electric Cooperative Inc.
Kelley said staff intends to present “new evidence” on regional cost allocation to FERC in July or August. He said SPP will be presenting the avoided costs of regional projects — a metric the commission has already approved — and the reduced regional costs of day-ahead market uplift.
“We’re thinking we’re in really good shape,” said Kelley, who last met with FERC on July 12. “It’s been a little challenging to figure out a way to do regional cost allocation for a single project.”
SPP is trying to reverse FERC’s October rejection of cost allocation for the Morgan project, one of two potential seams projects with AECI. It consists of a new 345/161-kV transformer at AECI’s Morgan Substation near Springfield and the rebuild of a 161-kV line.
The other project, a 345-kV, 50-MVAR reactor at City Utilities of Springfield’s existing Brookline substation, has been included in SPP’s Integrated Transmission Planning Near-Term assessment that will be presented to the Markets and Operations Policy Committee and Board of Directors/Members Committee this month.
The Brookline project’s costs will be allocated under SPP’s normal processes, but Kelley said AECI wants to pick up its share. The two projects have a combined estimated engineering and construction cost of more than $18 million.
The SSC agreed to take a crack at developing a Tariff mechanism to allocate costs for seams projects. With no such mechanism in place, SPP has to take seams projects to FERC on a case-by-case basis.
SPP, MISO Discuss Jan. 17 ‘Big Chill’
The Regional Transfers Operating Committee (RTOC), a six-person committee that includes two representatives from SPP and MISO, met twice in June to discuss what Kelley called “The Big Chill,” the Jan. 17 event when unusually frigid weather forced MISO to initiate a maximum generation alert for its South region.
MISO exceeded its 3,000-MW regional dispatch limit on transfers between its North and South regions over the SPP transmission system for an hour and was forced to make emergency purchases from Southern Co.
Kelley said the RTOC reviewed the use of NERC’s transmission loading relief process during the event and processes for acquiring and delivering emergency energy. He said improved communications will be the key to preventing a recurrence and improving operations and reliability.
“Situations like Jan. 17 don’t just show up without advance warning,” he said. “We and MISO had multiple warnings days before. We feel, and MISO feels, we can do a better job of communicating in advance.”
The RTOC is an operating committee created by a 2016 settlement agreement between SPP, MISO, Southern and the Tennessee Valley Authority. (See SPP, MISO Reach Deal to End Transmission Dispute.) It will meet again in late July.
M2M Generates $397,428 in Payments to SPP in May
Market-to-market (M2M) payments between SPP and MISO dropped to $397,428 in May, the lowest amount since last August. However, it was also the 10th straight month, and the 18th of the last 20, in which the payments have been in SPP’s favor.
| SPP
The RTO has incurred $53.7 million in M2M payments from MISO since the two began the process in March 2015.
Current and temporary flowgates were binding for 254 hours in May, SPP staff told the SSC.
