FERC ruled Friday that the developer of a proposed 1,500-MW Indiana wind farm must go to the end of the interconnection queue to move its point of interconnection (POI) 2.9 miles.
The commission’s Feb. 9 order rejected Harvest Wind’s request for a waiver allowing it to change the POI without triggering the “material modification” language under PJM’s Tariff. FERC sided with PJM in requiring a new queue application and facilities study (ER18-615).
Colorado-based Renewable Energy Systems Americas acquired the Harvest Wind project after the previous developer agreed in late 2016 to move to a second POI after AEP Indiana Michigan Transmission said the original was not a suitable spot for the wind farm’s 765-kV switchyard.
RES Americas said it learned in fall 2017 that the new location, POI 2, had some of the same problems as the original location, including wetlands and endangered species concerns. In addition, noise from the switchyard’s transformers would be too loud because of nearby houses, the company said in its Jan. 5 waiver request.
The developer said its proposed interconnection, POI 3, is “electrically identical” to the current location because it is just 2.9 miles away on the same 765-kV transmission line.
PJM opposed the request, arguing that the waiver would delay other projects in the queue because of the size of the wind project and the need for transmission restudies.
The commission agreed with PJM, finding that “Harvest Wind has not sufficiently demonstrated that it acted in good faith. Harvest Wind states that it became aware in September 2016 that both POI 1 and POI 2 presented some complicating factors due to site topology, but at that time it did not believe these factors were insurmountable. … Moreover, Harvest Wind fails to explain why it did not discover these additional complications for almost a year after initially being put on notice that complications existed at POI 1 and POI 2, demonstrating a lack of due diligence on Harvest Wind’s part.
“Harvest Wind has not sufficiently demonstrated that granting the waiver request will not have undesirable consequences or harm third parties,” the commission continued. “We agree with PJM that changing the point of interconnection at this late stage would introduce uncertainty that could well impact other lower-queued interconnection customers and that such restudy of the point of interconnection would require reassessment of protection, requiring the expenditure of time and resources, thus burdening and harming other parties.”
RES Americas said in its waiver request that it might be forced to abandon the project if the waiver were not approved.
An RES Americas spokesman said the company was “planning to proceed with the project” but did not say why a delay might force it to abandon it.
FERC approved PJM Tariff and Operating Agreement revisions incorporating two pro forma pseudo-tie agreements and a pro forma reimbursement agreement effective Nov. 9, 2017.
The commission’s Feb. 5 order rejected protests by MISO’s Independent Market Monitor, NYISO, American Municipal Power, Illinois Municipal Electric Agency and North Carolina Electric Membership Corp. (ER17-2291). (See Critics Protest PJM Dynamic Transfers Plan.)
| MISO, PJM
In its protest, NYISO said PJM’s rules will likely cause “adverse reliability impacts” and “exacerbate interregional seams.” But PJM pointed out that there are no resources currently pseudo-tied into PJM from NYISO.
The MISO Monitor David Patton contended FERC should not consider PJM’s proposal separately from other pending pseudo-tie proceedings. The plan creates “substantial economic and reliability harm to the customers in [the MISO and PJM] area,” he said.
The commission was unpersuaded, saying: “The terms of the proposed revisions and pseudo-tie agreements are not unjust and unreasonable merely because the commission has not yet acted in the other proceedings.” FERC also rejected the Monitor’s request for a technical conference.
“We agree with PJM that the pseudo-tie agreements and corresponding Tariff and Operating Agreement revisions promote uniformity among the pseudo-tie and dynamic schedule requirements and increase the transparency and efficiency of the implementation process,” the commission said.
California regulators on Thursday approved an order putting new requirements on community choice aggregators (CCAs), saying the decision did not come easily.
At the same time, CCAs and their supporters are arguing for more transparency and control over resource adequacy (RA) procurement.
“I just have overwhelming anxiety about the purpose of resource adequacy,” California Public Utilities Commission President Michael Picker said, addressing a crowded hearing room at commission headquarters in San Francisco after a public comment period. “It seems as if people have forgotten the energy crisis of 2001 and 2002.”
The State Legislature authorized the creation of CCAs in 2002 in response to the energy crisis, allowing local governments to directly contract for energy services to serve their residents. CCAs did not begin appearing until 2010 but have since grown rapidly.
Until now, CCAs have avoided the requirement to carry RA reserves, even as they’ve taken on a greater share of California load. Instead, customers of investor-owned utilities have been left with stranded costs because of the timing of load forecast submissions and RA allocations, in some cases procuring RA for customers about to be served by CCAs. Cost-shifting can run into the tens of millions of dollars annually, the CPUC said.
Picker struck an assertive tone on the RA issue, saying that grid reliability is at stake as procurement of electricity disaggregates through CCAs, which he’s unsure could meet critical grid needs.
“It really makes me nervous and it makes me wonder if people are really prepared to embrace this opportunity to serve as [load-serving entities],” Picker said, adding that the CPUC made reasonable efforts to accommodate the concerns of CCA supporters.
The CPUC made changes to its initial RA proposal in response to written comments, including extending the deadline for CCAs to submit their RA implementation plans until March 1 in order to allow several of them to begin serving their new customers in 2019. The CPUC also created two waiver options, one in which CCAs and IOUs can agree on the CCA’s RA requirements and cost responsibility, and another stipulating that if agreement was not reached, the CCA agrees to be bound by a future CPUC determination in the RA proceeding regarding its RA cost responsibility.
Many of the more than 40 registered speakers attending the CPUC hearing were there to speak against the CCA ruling. West Hollywood City Councilmember Lindsey Horvath told the CPUC that CCA customer energy costs must be determined in a fair and open process.
“How can we properly determine our fair share without access to contracts we’re being asked to account for?” Horvath asked. “We are glad to see the direction the commission is moving with in the current form of its resolution, but we’re not there yet.”
The CPUC introduced the proposal in December with a comment period near the holidays, leaving CCA representatives saying the expedited order did not give them time to provide input. (See California Proposes Resource Adequacy Obligations for CCAs.) Other proponents said it would delay CCA creation and slow achievement of climate goals. CCAs have grown rapidly and are popular as a way for localities to take control of energy consumption, with many marketed as green energy options.
But Picker said that if the decision delays the implementation of CCAs, “we are just going to have to live with that.” The consequences of having grid failure “can wipe the slate clean,” he said, again invoking the reliability crisis of the early 2000s.
Commissioners appeared sympathetic to CCA supporters, but Martha Guzman Aceves said that issues with the RA program have led to more procurement of natural gas generation.
“This is a problem to reaching our climate goals,” she said. “This is actually an environmental justice issue for me.” She added that, “Sometimes we don’t use the best process, I totally acknowledge that. But we need to deal with this problem now.”
“There has got to be good dialogue, there has to be trust,” Commissioner Carla Peterman said. “The last thing I want is to exacerbate tension between the CCAs, the utilities and the commission.”
In its order, the CPUC said: “Numerous commenters assert that the resolution violates their due process rights. We disagree. The changes in the CCA timeline made by this resolution are an exercise of authority the commission has had since 2002.”
Decision Adopts IRP Process
Another decision approved by the CPUC on Thursday sets RA requirements for all California LSEs. It institutes a two-year integrated resource planning process including electrical cooperatives, IOUs, CCAs and electric service providers.
The decision also recommends the state’s Air Resources Board adopt a greenhouse gas emissions target for the electric sector of 42 million metric tons by 2030, a 50% reduction from 2015 levels.
CPUC Delays Gas Moratorium Vote
In other items on the CPUC decision list, the commission tabled a proposal to require Southern California Gas to enact a moratorium on new commercial and industrial natural gas connections in Los Angeles County because of supply issues.
The CPUC said that while conservation measures by customers in response to the Aliso Canyon storage facility have helped, “significant new reliability challenges on the SoCalGas system exist due to a series of major unplanned outages and maintenance issues. The Los Angeles region faces greater uncertainty than a year ago with respect to the ability of SoCalGas to meet customer demand this winter.”
FORT LAUDERDALE, Fla. — The chairman of NERC’s Board of Trustees said last week the organization hopes to have a new CEO in place by the summer.
Roy Thilly told the Member Representatives Committee (MRC) during its Feb. 7 quarterly meeting that the selection process is “well underway,” with a goal for this spring.
“This is an important decision the full board needs to be involved in,” he said.
Russell Reynolds Associates has been conducting the executive search. Thilly said the board will select a group of about eight potential candidates, with a small group of trustees whittling that list down to two or three final candidates. The board will interview each of the finalists.
“Essentially, we want to be enthusiastic about the final candidate and have no hesitation that we have the right person for this job,” Thilly said. “If we don’t, then it’s important that we step back and take the time to do so.”
NERC has been without a CEO since Gerry Cauley resigned in November following his arrest for domestic abuse. General Counsel Charlie Berardesco stepped into the CEO role on an interim basis. (See Cauley Resigns; NERC Launches Search for Replacement.)
Thilly complimented NERC’s management team and staff for “really stepping up,” along with the Regional Entity CEOs.
“We feel like we’re in a good place right now,” he said. “The feedback I’ve gotten is that Charlie has stepped into the job in a seamless way and pulled the organization together.”
NERC also needs to hire a new chief security officer to replace Marcus Sachs, who resigned shortly after Cauley. (See NERC Parts Ways with Chief Security Officer.) Thilly said candidates have been “assembled,” but the agency won’t move forward until the new CEO is in place.
“It’s essential the new CEO participate in that hiring process and be very comfortable with the selection,” he said.
FERC’s McIntyre Says Resiliency Still of Interest in DC
FERC Chairman Kevin McIntyre told NERC trustees and stakeholders that the federal government still remains focused on grid resiliency, despite the commission’s rejection of the Department of Energy’s Notice of Proposed Rulemaking meant to address the issue. FERC launched a new resiliency initiative Jan. 8 after declining to take up the department’s proposal.
“Interest in that subject is not waning on [Capitol Hill], and it is not waning in the administration,” McIntyre said. “When real-world engagements occur with resiliency, like it’s old-fashioned cousin, reliability, we should use that as a teachable moment, and take lessons forward into the game plan and be better prepared for future events.”
McIntyre said the commission looks forward to working with NERC, and that it must remain “vigilant” in ensuring the grid’s resiliency, “a phrase you’ve no doubt heard.”
McIntyre and Berardesco were among several industry witnesses who recently testified before the Senate Energy and Natural Resources Committee about the January “cold-weather bomb.” (See FERC, RTOs: Grid Performed Better in Jan. Cold Snap vs. 2014.)
“Hanging in the air was the broader overall topic of grid resiliency,” McIntyre said. “I was very glad to be in a position to report that, based on various analyses, the bulk power system operated very reliably. My general impression was that my report, and those of the other witnesses, was well-received and appreciated in how well the grid performed.”
Resiliency is a priority at FERC, McIntyre said, and he expressed his gratitude to NERC for its work on the issue. He referenced the MRC’s Reliability Issues Steering Committee, which, at the trustees’ request, is developing a framework for resiliency.
The committee told stakeholders that most resilience definitions have two common elements: that it is “time-dependent” and differs from business-as-usual operations, and that it cannot be measured in a single-unit metric. It said the National Infrastructure Advisory Council’s framework for establishing critical infrastructure goals is a “credible source for further understanding and defining resilience.”
Bruce Walker, assistant secretary of the Energy Department’s Office of Electricity Delivery and Energy Reliability, said the department’s goal is to develop partnerships within the industry and provide resources to move issues forward.
“We have the opportunity to see the results of real work being done by FERC and NERC, and to shape policy through our coordination with both of these agencies,” said Walker, whose nomination was approved in October. “The [DOE] has stepped back to take a look at what our mission really is. It is … our mission-critical focus across the energy sector.”
Walker, formerly a deputy executive for Putnam County, N.Y., ran a boutique consulting firm focused on risk management at investor-owned utilities and served in leadership positions at National Grid and Consolidated Edison. He said his first goal is to develop a North American energy model “that integrates all different forms of energy so that we can run, like we do on our transmission system, a load flow.”
He said the bulk power system’s interdependencies will identify “those assets than can be enhanced, replaced or installed” to improve the system’s “affordability” as “we start moving forward” with the administration’s proposed $1.5 trillion infrastructure bill.
Other goals will focus on cyber and physical security, rapidly moving forward storage technologies, making use of sensing technologies and developing hardening strategies that add “some resiliency in a viable way.”
Jim Robb, CEO for the Western Electricity Coordinating Council, said recent developments within the Western Interconnection have put “substantial financial pressure” on Peak Reliability, the region’s delegated reliability coordinator (RC).
Within the past few months, Peak has announced it would team up with PJM Connext to attract participants to a new Western energy market. (See Peak, PJM Pitch ‘Marketplace for the West’.)
“Obviously, significant changes are going on that create a lot of uncertainty about how the ultimate reliability landscape will play out,” Robb said. He thanked FERC staff for working with WECC staff “as we move to a multiple RC model.”
NERC, WECC, British Columbia Agree to MOU
The board unanimously approved a memorandum of understanding between the British Columbia Utilities Commission (BCUC), WECC and NERC.
Modeled on recent MOUs with other Canadian jurisdictions, the agreement recognizes the parties’ roles under existing laws and authorities, maintains the status quo on funding arrangements, and provides for sharing of confidential and compliance-related information. WECC will periodically provide information on the Canadian province’s noncompliance for NERC’s review.
WECC General Counsel Steve Goodwill said a fully executed MOU should be in place in March, pending board approval from NERC and WECC.
NERC began formal correspondence with British Columbian authorities in 2006, while WECC has provided compliance monitoring for BCUC since 2009 through an administration agreement.
Goodwill said WECC is also negotiating similar terms with Mexico that recognize the changes in that country’s regulatory structure.
“Like the MOU with British Columbia, it will openly recognize for the first time the ability to share critical information on compliance enforcement in Mexico with NERC,” Goodwill said. “This is an all-around good story. The ability to share data among ourselves is critical.”
The MRC approved two new members and re-elected two incumbents to the board. Suzanne Keenan was elected to a two-year term expiring in 2020 and Rob Manning to a three-year term expiring in 2021, while George Hawkins and Jan Schori were re-elected to three-year terms also expiring in 2021.
Keenan served as CIO and senior vice president of process improvement for Wawa from 2008 to 2017. Her industry experience includes field services, re-engineering and performance, regulatory performance, and emergency preparedness experience with PECO Energy.
Hawkins, CEO of the D.C. Water and Sewer Authority, was first elected to the board in 2015. He serves on the Standards Oversight & Technology and Corporate Governance & Human Resources committees.
Manning was involved in transmission and distribution infrastructure research for the Electric Power Research Institute but will give up those duties with his election. He also spent six years with the Tennessee Valley Authority.
Schori, former CEO of the Sacramento Municipal Utility District for more than 14 years, was elected to the board in February 2009. She chairs the Finance and Audit Committee and serves on the Compliance and Enterprise-wide Risk committees.
The D.C. Circuit Court of Appeals last week dismissed the Kansas Corporation Commission’s appeal of a 2015 FERC ruling over formula rates, saying it lacked standing in the case (No. 16-1093, 16-1164).
The KCC argued before the court in November that FERC acted unlawfully by approving formula rates for future public utilities to use in operating electric transmission facilities. The Kansas commission asserted that FERC couldn’t determine that the formula rates for “not-yet-existing entities to implement at some point in the future” are just and reasonable.
D.C. Circuit Courthouse | U.S. Court of Appeals
Writing for the three-judge panel on Feb. 6, Judge Karen Henderson said the KCC had not suffered harm sufficient to establish standing. “A harm that will not occur unless a series of contingencies occurs at some unknown future time is not concrete, particularized, actual and imminent,” she said.
The Kansas commission was appealing a 2015 FERC decision, in which the agency granted Transource Energy’s request for formula rates for future affiliates by replicating approved rates for Transource Kansas. Transource formed the wholly owned subsidiary to compete for Kansas-based transmission projects in SPP and said it expected to create additional subsidiaries in the future.
FERC rejected the KCC’s rehearing request in 2016, ruling that preapproving a formula rate for Transource Kansas, which did not operate any active transmission facilities, was “no different” from preapproving a formula rate for future Transource affiliates.
The KCC’s appeal to the D.C. Circuit also included a similar FERC proceeding involving MPT Heartland Development, which formed Kanstar to compete for Kansas-specific projects. The federal agency in 2015 approved Kanstar’s request for a formula rate for its own use and that of future affiliates and later denied the KCC’s rehearing request.
The court consolidated the two appeals.
In November, the KCC lost another appeal in the D.C. Circuit when it attempted to challenge a 2014 FERC order approving SPP’s merger with the Integrated System. (See Court Rejects Challenge to SPP-Integrated System Merger.)
CARMEL, Ind. — MISO maintained reliable operations in its South region during a record January cold snap that saw the area’s peak loads approach summertime highs, the RTO said last week.
Tim Aliff, MISO director of system operations, provided a post-mortem of the event at a Feb. 8 Market Subcommittee meeting. He recounted that a second blast of arctic air hit MISO South in mid-January, less than two weeks after extreme cold had gripped most of the RTO’s footprint and sent peak demand well above 100 GW. (See MISO Breaks down Recent Cold Snap.)
| MISO
Uncharacteristically frigid weather prompted MISO to initiate a maximum generation alert for the South region for Jan. 17-18, when the region’s peak loads were hovering above 31 GW. With low temperatures averaging 13 degrees Fahrenheit on Jan. 17, MISO South’s peak load hit 32.1 GW, just short of the region’s all-time high of 32.7 GW set in August 2015.
Throughout the day on Jan. 17, MISO South temperatures remained about 20 to 25 degrees lower than normal. MISO committed all available resources in the region, compelling load-serving entities to make emergency energy purchases from neighboring balancing authorities between about 7:25 a.m. and 12:55 p.m., with purchases topping at about 1.1 GW around 8 a.m. Aliff said MISO’s emergency pricing floors worked as designed when initiated on Jan. 17, with average LMPs spiking just above $1,000/MWh during the peak of buying.
| MISO
MISO South analysts also reported about 17 GW of generation outages and derates that day, including nearly 10 GW in forced generation outages, further stressing the region’s system, Aliff said. By then, Louisiana and the Gulf Coast were ensnared in what the Weather Channel would dub Winter Storm Inga.
MISO asked for South utilities to undertake load management measures, prompting Louisiana state regulators to question the need for conservation. (See Louisiana Regulators Question MISO South Max Gen Event.) MISO South has no registered emergency demand response resources within its boundaries.
Aliff said MISO will continue to review the event to determine what process improvements it could make as it heads into summer, when more emergency conditions are likely to occur. He said MISO has yet to analyze the load-modifying resource performance in MISO South during the weather event.
The staff of the Texas Public Utility Commission last week recommended that it require Vistra Energy and Dynegy to divest at least 1,281 MW of generation to secure approval of their merger.
Vistra’s power generation subsidiary, Luminant Generation, challenged the staff recommendation, assuring the PUC that market power would not be an issue (Docket No. 47801).
PUC staff filed the recommendation on Feb. 5, calling for approving the merger conditioned on Vistra and Dynegy divesting themselves of enough Texas generation to stay below the statutory cap of 20% of ERCOT installed capacity.
Staff said the two companies exceeded the limit because Dynegy owns 820 MW of generation in the Eastern Interconnection “capable of delivering electricity to ERCOT” over DC ties. Staff ruled that capacity should be included in Luminant’s market share calculation.
Dynegy’s Morro Bay Plant in California
Together, Luminant and Dynegy own almost 18 GW of generation in Texas. Dynegy also owns 21.6 GW outside the state that isn’t deliverable to ERCOT. Including the 820 MW of generation deliverable over the DC ties would give the companies 21.46% of the Texas ISO’s capacity.
Staff said in their memo that Luminant and Dynegy have committed not to import power over the DC ties. However, they said, the arrangement “fails to satisfy the statutory language, because a commitment on [their] part to not import power … does not negate their capability of doing so.”
In its response filed Friday, Luminant asked the PUC to exclude the 820 MW, based on the entities’ commitment to not import power. The generation firm said a “reasonable mitigation” would be acceptance of the companies’ commitment not to import power and allow the transaction to close without any divesting generation.
Luminant’s Forney Plant | Energy Future Holdings
Luminant also requested its 915-MW Lake Hubbard gas-fired plant be excluded from the market power analysis, saying it was grandfathered as part of a 2000 agreement with the PUC (Docket No. 28081).
The company told the commissioners it is working with staff on a proposed order. The PUC has an open meeting Feb. 15, but the agenda has not yet been posted.
In their filing, staff recommended several changes to the proposed transaction:
Divesting the generation should the commission find the combined installed capacity exceeds the 20% cap;
Termination of a 2015 voluntary mitigation plan (Docket No. 44635);
Self-monitoring compliance with the cap;
Filing quarterly compliance reports for two years or until the combined company falls below 18.5% of ERCOT’s total; and
Filing a written report with the PUC within 30 days on noncompliance with the 20% cap.
Vistra announced its $1.7 billion acquisition of Dynegy in October. The all-stock deal will create a generation and retail giant owning 40 GW of capacity and serving nearly 3 million customers, mainly in ERCOT, PJM and ISO-NE. The proposed acquisition requires regulatory approvals from FERC, the PUC and the New York Public Service Commission. (See Vistra Energy Swallowing Dynegy in $1.7B Deal.)
Xcel Energy last week reported fourth-quarter earnings of $189 million ($0.37/share), down 16.7% from the same period last year.
But for the year, the Minneapolis-based company reported earnings of $1.15 billion ($2.25/share), up from $1.12 billion ($2.21/share) in 2016.
Colorado wind farm | Xcel Energy
Both quarterly and yearly earnings dropped 5 cents because of a one-time expense related to the federal Tax Cuts and Jobs Act passed in December.
CEO Ben Fowke said during Xcel’s earnings call that the tax bill “provides the opportunity” to lower consumers’ bills and make additional investments “in areas that are important for our customers.”
The company is involved in pending rate cases in several of the states in which it operates, all of which were filed before the new tax legislation was proposed.
“In these cases, and in other jurisdictions, we’re having active discussions and formal proceedings with our regulators regarding the impacts of the Tax Cuts and Jobs Act and how we will provide the expected benefits to our customers,” CFO Bob Frenzel said. “Ultimately, tax reform results in lower taxes, lower deferred taxes and, correspondingly, lower cash flow metrics.”
The company said it expects to “moderate” its five-year capital expenditure plan by $500 million and issue up to $300 million of additional equity. It said it successfully completed CapEx 2020, a 13-year project involving more than 800 miles of transmission lines, $2 billion of investment and working with 11 different utilities.
The American Wind Energy Association’s top utility wind-energy provider for the 12th straight year, Xcel said its “Steel-for-Fuel” strategy — which replaces fossil fuel plants with wind turbines — resulted in regulatory approval for 1,550 MW of new wind resources in the Upper Midwest, a proposed 300-MW wind farm in South Dakota, and settlements in principle for 1,230 MW of wind in Texas and New Mexico during 2017.
Pacific Gas and Electric CEO Geisha Williams said Friday that the utility will fight for the right to recover costs stemming from California wildfires “in the legal, regulatory and legislative arenas.”
San Francisco-based PG&E and other investor-owned utilities are being investigated for causing the devastating fires that wracked the state last year. Investigators for the California Department of Forestry and Fire Protection have not yet found evidence indicating the fires were caused by IOU infrastructure.
Williams said PG&E will seek a rehearing of the California Public Utilities Commission’s decision to deny San Diego Gas & Electric’s request to recover from ratepayers $379 million in costs related to the 2007 Southern California wildfires. (See Besieged CPUC Denies SDG&E Wildfire Recovery.) Heavy winds exacerbated the effects of the deadly infernos that swept across the region.
“It’s bigger than just PG&E and the other California IOUs, and much bigger than just this past year’s fires,” Williams said of the wildfires, drawing a link between them and climate change. “This is a collective societal challenge.”
PG&E reported $13 billion in electric operating revenues in 2017 and associated operating expenses of $4.3 billion. Net income was $1.6 billion after taxes, compared with $1.4 billion in 2016 and $861 million in 2015.
The 2017 Tubbs and Pocket Fires in Northern California
The company had earlier announced a suspension of dividends amid uncertainty over its liability associated with last year’s Northern California fires. For the fourth quarter of 2017, GAAP results were $114 million ($0.02/share) compared with $692 million ($1.36/share) for the same quarter in 2016.
No Challenge to Diablo Canyon Decision
PG&E also said it will not contest a CPUC ruling that granted the utility just a fraction of the cost recovery it had requested for retiring the Diablo Canyon nuclear power plant, the last remaining nuke in a state where more than 60 such plants were proposed in the 1970s.
Diablo Canyon Nuclear Power Plant | PG&E
PG&E said “today’s announcement comes after all the parties had the opportunity to confer” following the CPUC’s Jan. 11 decision on the joint proposal agreement. (See PG&E Disputes ALJ’s Diablo Canyon Recommendation.)
CARMEL, Ind. — Market participants have united to develop a trio of alternatives to MISO’s plan to crack down on generators that fail to follow dispatch instructions, while the RTO has softened its position on moving ahead with a nearly final proposal.
Stakeholders representing 13 member companies began meeting to address the issue after MISO last November revealed its plan to tighten tolerances for uninstructed deviations based on a generator’s ramp rate. MISO currently flags generators that deviate from dispatch by more than an 8% over four consecutive intervals.
During a Feb. 8 Market Subcommittee meeting, DTE Energy’s Nick Griffin said informal meetings with MISO staff and the Independent Market Monitor to “brainstorm” on the topic have produced three proposals to curb deviations:
Rely on MISO’s proposal requiring a generator to move at least half its offered ramp rate, but use a more generous ramp rate multiplier;
Use a standard 6% deviation tolerance from dispatch signals; or
Employ an “energy mileage” concept that would set a tolerance based on how much electricity a unit actually moved over a one-hour period compared to how much it was asked to move.
Griffin said all three encourage generators to follow dispatch signals.
“We don’t want units to drag on the system and be paid for dragging on the system,” he said.
However, Griffin said MISO’s solution must consider the “operational limits of resources, including wind forecasting and coal mill and boiler feed pump limits.”
Stakeholders have repeatedly called for a softer uninstructed deviation threshold than what MISO is proposing.
Before this month, MISO was close to wrapping up a final approach on stricter rules using Monitor David Patton’s proposal requiring generators to move at half their offered ramp rate, with a 20-minute grace period before being flagged and possibly losing make-whole payments. Last fall, Ameren Missouri urged MISO to keep the percentage threshold, saying it could be constricted to 7 or 6% over time. The company also asked the RTO to focus only on generators that fail to move for an hour after dispatch instructions. (See Ameren Calls for Milder MISO Response to Uninstructed Deviations.)
MISO staff are now offering two new proposals developed after the informal stakeholder meetings. The first is a slightly modified approach of the RTO’s original proposal, with a cap of 12% of the dispatch level instead of the previously proposed 10%, leaving more tolerance for fast-ramping units.
The second is a performance-based approach similar to the “energy mileage” concept that partly decouples MISO’s uninstructed deviation rules from price volatility make-whole payments, preventing a generator’s deviation from immediately triggering ineligibility for those payments. In those instances, MISO would rely on an hourly price volatility make-whole payment calculation based on generator performance, ensuring that unit owners are incentivized to submit accurate ramp rates and then perform to them. The payments are designed for resources that either fail to cover production costs in the market, or have their day-ahead margins eroded by intra-hour price spikes.
MISO Market Quality Manager Jason Howard said the RTO still plans to have a final proposal readied for filing in time for the April subcommittee meeting, and that he would return to the subcommittee in March after gauging stakeholder reception to the two new proposals. MISO is also considering holding a workshop to ensure stakeholders understand what it is proposing, Howard said, although no date has been set.
