FERC last week accepted settlements with Duquesne Light Co. and an unnamed municipal utility in the Western Electricity Coordinating Council for violations of NERC reliability standards. The commission filed a notice Friday that it would not review the penalties, leaving NERC’s settlements intact (NP19-6).
NERC reported the settlements in a spreadsheet notice of penalty on March 28.
$40,000 Penalty for Duquesne Light
Duquesne agreed to a $40,000 penalty for inaccurate ratings of some substation conductors and a 138-kV circuit, violations of FAC-008-3 R6.
The substation inaccuracy — caused by entering an incorrect input value into one of the rating equations — resulted in a reduction of the overall facility rating for three transformers.
The violation extended for more than two years because Duquesne “lacked an effective verification control” to quickly detect and correct the error, NERC said. The company alerted regional entity ReliabilityFirst of the problem in a self-report in August 2017, after completing its mitigation plan.
| Duquesne Light Co.
NERC said the violation did not indicate a systemic issue with Duquesne’s FAC-008 program because only about 3% of the company’s bulk electric system (BES) transmission facilities were affected.
NERC determined the violation posed a moderate risk and could lead to equipment failure. “The risk is increased because of the long multiyear duration of the violation, but the risk is lessened (and not serious) because only one of the incorrect substation conductor ratings [was] the most limiting factor for these facilities,” NERC said. “The changes that did result in a facility ratings change did not impact the load dump ratings at any ambient temperature set but did impact the normal and emergency ratings.”
The second violation, involving the Clairton‐West Mifflin 138-kV circuit, was discovered during a compliance audit in December 2017. NERC said a section of overhead stranded conductor was not shown in Duquesne’s circuit map. After updating the map, Duquesne conducted a new analysis that resulted in reducing the summer 95 degrees Fahrenheit continuous rating from 932 amperes to 919 amperes.
The violation resulted in ratings reductions for three of Duquesne’s 85 BES transmission circuits (4%).
Although the incorrect ratings were in place for more than three years, NERC characterized the risk as minor “because the change in rating on the 138-kV circuit was minimal: just 13 amperes.”
NERC credited Duquesne for its cooperation in the investigation but said the company’s FAC-008/FAC-009 compliance history was an aggravating factor in determining the penalty.
Muni Lacked Familiarity with NERC Standards
FERC also chose not to review NERC’s settlement with an unnamed municipal utility over six violations of critical infrastructure protection (CIP) standards. NERC redacted some details of the violations and the utility’s name to protect critical energy/electric infrastructure information (CEII).
NERC’s filing said the utility:
Mischaracterized cyber systems at a substation as low-impact BES cyber systems (LIBCS) that should have been considered medium-impact BES cyber systems (MIBCS). An incorrect analysis found the systems connected to only two other substations when they were actually connected to four other transmission assets and had ties to two different entities, NERC said.
Failed to eliminate unneeded network accessible ports from an engineering workstation in a data center.
Failed to conduct an adequate security patch management program, including a requirement to check for new security patches every 35 days. NERC cited the entity’s “lack of knowledge and understanding of CIP standards.”
Gave five employees electronic or unescorted physical access to its MIBCS without having completed access request forms.
Failed to identify in its baseline configuration all of its network accessible ports and security patches applied to assets.
Failed to perform required change management activities for BES assets, electronic access control monitoring systems and physical access control systems.
Failed to provide evidence that it removed the ability of employees to access its systems within 24 hours of a termination.
NERC imposed no financial penalties for the violations and said none of them posed a “serious or substantial risk” to the reliability of the BES. The entity is a “very small municipal power company that employs few staff and has an extremely low turnover,” NERC said.
Staff are currently drafting three Nodal Protocol revision requests (NPRRs) with the hopes of presenting them to the Technical Advisory Committee in May.
During a Wednesday workshop on outage activity related to ERCOT’s operating condition notice (OCN) ahead of the event, Luminant’s Ian Haley shared a proposal for an “outage reliability unit commitment” (ORUC) process — though the name is up for debate. Units subject to the ORUC wouldn’t be allowed to self-commit, giving the market 24 hours to “perform.”
Under the proposal, ERCOT would provide 24-hour notice that it will run ORUC, along with a time frame and reliability justification. Units would be committed by the hourly and day-ahead RUC processes during the outage delay period and settled with a make-whole payment floor.
The goal is to optimize outages, Haley said. “If you’re ORUC’ed, think of it as [a reliability-must-run agreement] for capacity,” he said.
Luminant’s ORUC process would be incorporated into NPRR930, which includes a pricing make-whole payment. The change requires ERCOT to use a weekly RUC that can commit resources with an approved outage. Committed units would be made whole with respect to the actual costs and cancellation of the outage. The NPRR also sets an offer floor for the resource at the systemwide offer cap.
“There are still outstanding questions, but I didn’t really feel I lost the room,” Haley said. “If we get into this situation again, we should all be able to look into the protocols and see how this will work.”
ERCOT Senior Director of System Operations Dan Woodfin said the ORUC process could also be a sub-routine within NPRR934, which creates a new OCN type — an advance action notice — that alerts qualified scheduling entities and transmission service providers to modify their outage plans.
Staff is also developing NPRR935, which would require ERCOT to post wind and solar forecasts and indicate which model is being used for each of the forecasts. Market participants complained about a lack of transparency into which forecasts were being used in late February before the event.
“We know ERCOT will develop more forecasts, so I’d like [the NPRR] to say all forecasts are published,” Citigroup Energy’s Eric Goff said.
“We’re posting the information, but I can’t make anyone drink the water,” Woodfin said. “We’ll go back and look to see if there’s a mechanism to build more flexibility into the OCN process.”
ERCOT has scheduled a second workshop on the OCN issue for this Wednesday in order to stay on track for presenting the information to the TAC during its May 22 meeting. The workshop will take the place of an urgent Protocol Revision Subcommittee meeting that was to take up OCN issues. The PRS will meet as regularly scheduled on May 9.
The OCN workshop was just one of three held in Austin last week. Warren Lasher, ERCOT’s senior director of system planning, opened an April 23 standing room-only workshop on energy storage by saying, “It’s a great day.
“We get to talk about and identify issues, and talk about who fixes those issues,” he said. “We don’t have to solve them here.”
Lasher said energy storage is a growing resource in the ERCOT market, with about 100 MW available now and an additional 70 MW expected before summer begins. He said another 3 GW, “maybe more,” of energy storage is under study in the interconnection queue.
ERCOT sees batteries as “limited duration” resources that can charge from the grid or discharge onto it. Attendees heard presentations from staff and from E.ON Climate & Renewables North America’s Andrea Bianco, who explained the various available storage technologies.
Discussion topics included how to address hybrid units, communicating resource status and desired operational constraints, reliability requirements, outage evaluation topics, and storage resources’ bids and offers.
The storage workshop served as a lead-in to a Wednesday workshop on transmission-connected inverter-based resources. That workshop’s agenda was highly technical and designed for transmission service providers, resource entities and their vendors.
VALLEY FORGE, Pa. — Denise Foster, PJM’s vice president of state and members services, chaired her first Markets and Reliability Committee meeting on Thursday, replacing retired CFO Suzanne Daugherty.
Foster came to PJM not once, but twice throughout her two-decade career as an attorney and consumer advocate: first in 2000 as counsel and regulatory affairs manager, and again in 2009 as her current role managing members services, a position that has evolved as PJM’s membership has swelled.
Foster prides herself on building relationships and encouraging positive discourse. “I want to ensure that everyone’s voice is heard, and that the information needed is presented and discussed so good decisions may be made,” she said in a PJM press release April 23. “We are first, people, and second, business representatives.”
Load Interests Block FTR Rule Changes
The Electric Distributor and End-Use Customer sectors blocked a proposed revision to PJM’s rules about when financial transmission rights profits should be forfeited.
All but one of the voting members in both sectors rejected the joint plan developed by Exelon, NextEra Energy and VECO Power Trading and approved by stakeholders at the Market Implementation Committee in November. The proposal would replace the RTO’s existing “penny test” for a threshold of FTR flows of 10% or more across a constraint.
“Stakeholders like Exelon have stopped participating both in virtual activity and FTR markets [at the same time] because existing rules are over burdensome,” said Sharon Midgley, director of wholesale market development for Exelon. “The current FTR forfeiture rule is too restrictive for competitive suppliers, prevents legitimate business activities and increases costs to customers.”
“We’re a large load-serving entity,” Exelon’s Jason Barker added. “This is increasing risk premiums. It’s another example of over-mitigation in PJM’s markets.”
Stakeholders deferred a vote on the plan at the December MRC after some expressed fear it could unintentionally create exploitable market loopholes. (See “FTR Forfeiture Rule Deferred,” PJM MRC/MC Briefs: Dec. 20. 2019.)
The Independent Market Monitor also expressed reservations about changing the status quo. It has argued that the penny test is better at catching manipulative behavior. (See “FTR Forfeiture Proposal Endorsed,” PJM MIC Briefs: Nov. 7, 2018.)
A second FTR rule change that would adjust calculations to account for on-peak and off-peak FTRs was endorsed by acclimation. (See “First Read on Change to FTR Forfeiture Calculations,” PJM MIC Briefs: March 6, 2019.)
Carbon Pricing Talks Move Forward
PJM will soon assemble a task force dedicated to studying the impacts of carbon pricing throughout the RTO’s 13-state footprint.
Stakeholders approved the problem statement and issue charge in a sector-weighted vote of 3.92 to 1.08 on Thursday. The new group will report findings to the MRC over the next 18 months.
“I think it’s important to get the ball rolling, but this isn’t a fast-track item,” said Michael Borgatti of Gabel Associates.
Borgatti presented a first read of the problem statement and issue charge at the March 21 MRC that would task stakeholders with creating rules to address carbon leakage and help states meet greenhouse gas reduction policies. Borgatti made the presentation on behalf of the Independent Energy Producers of New Jersey, which includes NextEra and PSEG Power.
Dana Horton, of American Electric Power, and Chuck Dugan, of East Kentucky Power Cooperative, two utilities with substantial coal-fired generation, opposed the initiative.
“If we were talking about a nationwide carbon adder, we’d be all in,” said Horton, who said he feared the initiative could lead to higher prices for AEP customers in states that have not joined Illinois and New Jersey in approving nuclear subsidies. “But we disagree that this is the right time to do this.”
Dugan echoed Horton’s sentiments. “We’re a state that’s a coal state,” he said. A carbon adder “is not required, and we are very busy in the stakeholder process [with other issues]. We should hold off.”
Marji Philips of Direct Energy, however, said Borgatti’s proposal is the “best solution to deal with externalities that the states say PJM is not dealing with.”
“Ohio’s going to have a [zero-emission credit] program soon if their utilities have their way,” she added, referring to legislation under debate in the state legislature.
RTEP Removal Language Vote Deferred, Again
After a bit of procedural skirmishing, members agreed to delay a vote on LS Power’s proposal to amend Manual 14B for another 60 days while stakeholders continue talks about the intersection of supplemental and regional project planning.
Sharon Segner, vice president of LS Power, offered the revisions at the January MRC after expressing concern over the growing number of supplemental projects languishing in the Regional Transmission Expansion Plan. Supplemental projects are proposed by TOs and are not required for compliance with PJM’s reliability, operational performance or economic criteria.
Segner’s proposed language specifies that a transmission owner’s supplemental project “will generally be removed from the RTEP” following a final order by a state siting agency rejecting the project. A special session of the Planning Committee has been meeting over the last 60 days to review a variety of legal issues related to FERC Orders 890 and 1000 — meetings that PJM staff said are narrowing their differences. (See “LS Power will Seek 2nd Deferral on Transmission Replacement Language,” PJM PC/TEAC Briefs: April 11, 2019.)
When Segner presented specific topics for the special PC session to discuss during the deferral period — including possible Operating Agreement revisions — Chair Foster intervened.
“Adding all these items to the discussion that has been assigned to the lower committee is out of order,” she said. “The expansion [into OA revisions] is what I particularly take issue with.”
Segner argued against Foster’s interpretation of committee rules, noting that any revisions to rules relating to Order 1000 need inclusion in the OA, per FERC precedent. After nearly an hour of debate with other stakeholders about the appropriate scope of the motion, she agreed to proceed with only the 60-day deferral.
“I request in the minutes for today it is specifically outlined that in 60 days, when this issue comes back before the MRC, if a friendly amendment that reflects OA language that is germane to the main motion is offered, I may deem it as friendly,” Segner said.
The California Public Utilities Commission hosted a forum Friday where some experts urged it to break up Pacific Gas and Electric despite the challenges attending that move, while others favored keeping the troubled utility intact.
Whatever the outcome, PUC President Michael Picker said, the solution is likely to seem as bad as the problem to many people.
“It’s not a question of ‘out of the frying pan and into the fire,’” Picker said. “It’s ‘which fire are we going to pick?’”
Friday’s forum was the second in a series of public meetings on PG&E held by the PUC.
State regulators and other authorities have been discussing PG&E’s future with greater urgency since it filed for Chapter 11 bankruptcy reorganization Jan. 29. The utility cited billions of dollars in potential wildfire liability for its bankruptcy and said it might seek to rescind hundreds of costly power purchase agreements entered into when prices for renewable energy were higher than they are today. (See PG&E Wants to Undo Contracts, Revamp Biz in Bankruptcy.)
Recent disasters blamed on PG&E have increased public and political antipathy toward the 114-year-old utility, headquartered in San Francisco.
State investigators have concluded PG&E equipment started wildfires that killed at least 22 people in 2017 and 2018. Not included in that total is the Camp Fire, the deadliest in state history, which killed 85 residents and destroyed most of Paradise, a town of 27,000 in the Sierra Nevada Foothills. Investigators have yet to determine the cause of the fire, but PG&E said its equipment is likely to blame.
After “so much death and destruction,” the utility faces an unprecedented turning point, said David J. Hayes, executive director of the State Energy & Environmental Impact Center at the New York University School of Law. “You’re never going to have a time, I think, when the public is more supportive of extraordinary steps than you have right now,” he told PUC commissioners.
Hayes and others suggested that breaking up PG&E into smaller entities could accomplish several goals, including reducing the risk of cyberattacks. If attackers took down PG&E, it would eliminate gas and electric service for much of California, he noted. But “the system becomes more resilient” if PG&E is separated into smaller units, he said.
‘Culture of Entitlement’
The arbiters of PG&E’s fate go beyond the PUC. They currently include a federal bankruptcy judge and another federal judge overseeing PG&E’s criminal probation in the 2010 San Bruno gas pipeline explosion that killed eight residents of a suburban San Francisco neighborhood. (See Federal Judge to Review PG&E’s Wildfire Plan.)
Gov. Gavin Newsom, state lawmakers and the state attorney general’s office have weighed in. (See Calif. Must Limit Wildfire Liability, Governor Says.) So has FERC, along with ratepayer advocates, fire victims and generators that sell electricity to PG&E. (See Judge Puts Off Decision in PG&E v. FERC.) The FBI is helping local authorities conduct a criminal investigation of PG&E’s involvement in the Camp Fire, according to some news reports.
At stake in all this activity is the future of the state’s largest utility, which supplies electricity and gas to 16 million residents across 70,000 square miles of Northern and Central California, or about 42% of the state.
PG&E’s critics contend the public’s safety hangs in the balance, and that the utility’s finances must not take precedence. The utility is irredeemably flawed, some say.
“No amount of incentives, CEO compensation or board member replacement can fix a company infected with a culture of entitlement,” said Scott Hempling, a regulatory adviser and adjunct professor at Georgetown University Law Center.
PG&E believes it’s entitled “to remain the monopoly franchisee indefinitely, no matter how many rules you break, how much evidence you hide, how many felonies you commit [or] how much damage you do,” Hempling told the PUC.
To stand up to PG&E, state officials must be ready to adopt alternatives to the monopoly, investor-owned utility, he said. “We need to show that ‘too big to fail’ is a myth.”
PG&E insists it’s taking safety concerns seriously and trying to change. It announced plans this month to install a new chief executive and 11 new board members out of 13, touting the new members’ utility and safety experience. (See Former FERC Commissioner Brownell Named PG&E Chair.)
On April 22, however, PG&E provoked more public outrage by asking the PUC to increase its return on equity — a major source of profits — from 10.25% to 16% to help pay for $28 billion in fire safety and other upgrades over the next four years. (Southern California Edison, also blamed for deadly wildfires, recently requested that FERC approve a higher ROE for safety-related transmission line investments.)
“PG&E is proposing a $1.2 billion increase in its currently approved cost of capital, based on a 16% return on equity,” the utility said in a news release. The proposed increase is meant to ensure access to capital markets and would raise an average customer’s electricity bill by about 7%, it said.
“Investors must continue to play a vital role in providing the capital necessary to fund essential safety and reliability infrastructure upgrades,” CFO Jason Wells said in the statement. “These investments allow PG&E to offset the upfront, immediate costs of these long-term projects to our customers.”
Travis Kavulla, director of energy and environmental policy at the R Street Institute, a D.C. think tank, and a member of the Western Energy Imbalance Market’s Governing Body, said the applications for higher returns on equity filed by PG&E and SCE would base a quarter to a third of the companies’ future profits on predicted fire liabilities.
The utilities, especially PG&E, “have already made in essence an opening bid to say what amount of their profit is guided by wildfire-related risk,” Kavulla said. Instead, he said, profits should be connected to measurable results.
“A significant amount of this firm’s profits … should be tied explicitly to achievement of safety outcomes rather than simply being earned as a return paid on capital investments,” Kavulla said.
IOU vs. POU
In the debate about breaking up PG&E, Bere Lindley, assistant general manager of the South San Joaquin Irrigation District, a publicly owned utility, said it would make sense for some areas of PG&E’s territory to become municipal utilities. Publicly owned utilities (POUs) are governed by elected officials and responsible to customers, not shareholders, he said.
POUs have been shown, on average, to lower rates and increase reliability, he argued.
“Customers, owners and the public are the same people in the POU model. They have the same interests,” Lindley said. “The POU structure provides an elegantly simple solution to align natural stakeholder interests for a monopoly business.”
The Los Angeles Department of Water and Power, the Sacramento Municipal Utility District (SMUD) and 39 other public entities provide electric service in California. LADWP — the largest POU in the country — has 3.9 million customers; the smallest POUs serve fewer than 400 residents, according to the California Energy Commission.
Currently, only San Francisco, one of the nation’s wealthiest cities, is seriously considering acquiring PG&E’s equipment and forming a municipal utility, Commissioner Martha Guzman Aceves said. Other communities would likely lack the means, she said, leading to disparities in electric service based on wealth.
Susan Mac Cormac, a partner at corporate law firm Morrison & Foerster, moderated the panel. She said municipal utilities don’t have the resources to cover the billions of dollars in capital expenditures that PG&E likely faces to upgrade its infrastructure and cover wildfire costs. She recommended keeping the utility intact.
John Di Stasio, president of the Large Public Power Council and former CEO of SMUD, said municipal utilities often have top credit ratings and access to capital. Still, he acknowledged, local governments would face significant challenges in trying to take over from PG&E. SMUD faced difficult hurdles in attempting to annex outlying areas of Sacramento from the utility.
“This is a significant hill to climb,” he said.
One example of those challenges came from Sam Weaver, the mayor pro tempore of Boulder, Colo., who participated in the PUC forum by telephone.
Boulder has spent years battling Xcel Energy, the large IOU that serves the city, to take over its poles and lines and create a municipal utility. The results of that effort remain uncertain, and Boulder will likely pursue condemnation proceedings, Weaver said.
Even if Boulder’s municipalization effort ultimately fails, it may still achieve positive results in terms of rates and quality of service, he said.
Xcel committed in December to providing its customers with carbon-free energy by 2050, becoming the first large IOU to make such a pledge. The move was likely a response to Boulder’s pledge to provide all-renewable energy by 2030 if it created its own utility. (See Xcel Pledges to Go 100% Carbon Free.)
“It applies pressure to the [investor-owned] utility because you establish yourself as a customer, and not just as a captive ratepayer,” Weaver said.
CARMEL, Ind. — MISO is accepting proposals for projects designed to relieve its increasingly costly North-South transmission constraint, but it is still zeroing in on an approach to evaluate submissions.
During a Thursday conference call to inform stakeholders about MISO’s expectations of design parameters, staff expressed hope that a viable candidate could emerge from a second round of proposals to relieve the constraint given recent changes to the RTO’s own outlook and the way it values the monetary benefits of large transmission projects.
The submission window for proposals will remain open until June 21. Once ideas are submitted, MISO will perform screening analyses through July to identify possible candidates. After performing more in-depth analysis and cost estimates, the RTO could announce a viable candidate by August.
MISO has added the Midwest-South interface as a constraint to be evaluated under its ongoing Market Congestion Planning Study (MCPS). (See MISO Takes Second Look at North-South Constraint.) Planning Manager Matt Ellis said the constraint was added at stakeholder request.
Ellis said the second look comes as MISO seeks to add a new benefit metric for market efficiency projects that reduce the costs of its settlement with MISO MEP Cost Allocation Plan Goes to FERC.) Ellis said the new metric could render some project candidates more beneficial than they appeared when MISO last studied the constraint in 2017.
The transfer constraints between MISO’s Midwest and South regions contributed to the RTO’s September and January emergency events, CEO John Bear said at an April 23 Informational Forum. He said MISO had adequate resources during both emergencies, but transmission constraints kept it from accessing them to relieve emergency conditions. He said a project could strengthen the RTO’s greatest asset: its footprint diversity. (See MISO Claims up to $3.9B in 2018 Benefits.)
Under the MISO-SPP settlement agreement, MISO pays SPP between $16 million and $38 million in base annual payments based on an annual available system capacity usage factor. Beginning next February, that amount is subject to a 2 to 4% escalation rate, depending on use.
“Fifteen years out, those payments could get pretty high,” Principal Transmission Planning Engineer Shane O’Brien told stakeholders.
O’Brien also said the agreement itself will soon be less certain. Starting Jan. 31, 2021, it may be terminated by any party with a year’s notice. Without a replacement settlement in place, flows would be limited to MISO’s original contract path.
“We could potentially have to revert back to 1,000 MW in the earlier direction,” O’Brien said.
MISO has also said that growing renewable use is set to increase flows on the contract path. By 2033, the RTO has found that interface flows could reach 8,000 MW north to south based on data from its Transmission Expansion Plan (MTEP) futures. Using the accelerated fleet change MTEP future, MISO estimates that its annual settlement payments might reach $70 million, although the other three futures limit costs to below $40 million per year.
In response to stakeholder questions, Ellis said MISO would evaluate the value of avoiding emergency declarations as an additional benefit metric for a Midwest-South transmission solution, even though emergency event reduction is not a Tariff-defined benefit metric.
Design Criteria
The RTO has said proposed projects must terminate on either side of the footprint at facilities owned by MISO transmission owners. However, solutions can have midpoints outside of the MISO system, O’Brien said. Transmission solutions can either increase capacity beyond MISO’s current regional directional transfer limits or eliminate portions of the contract path.
Transmission solutions can also address other transmission constraints in addition to the North-South interface to increase the overall benefits of a project and increase the odds of approval.
“Certainly, if folks are able to provide other benefits in addition to increasing capacity between the regions, that will make a project more beneficial,” O’Brien said.
MISO North-South interface region | MISO
However, MISO is not yet discussing how the costs of projects might be allocated.
WPPI Energy’s Steve Leovy asked if MISO would consider a transmission solution that might be shared with the neighboring Tennessee Valley Authority.
While Ellis said MISO would not foreclose on considering such an idea, he reminded stakeholders that it’s more difficult to evaluate hypothetical agreements against a solution wholly owned by a MISO member.
“We’d have to have some sort of more assurances. What that looks like, I don’t know,” Ellis said.
Missouri Public Service Commission economist Adam McKinnie asked how MISO’s special project submission window might interact with its ongoing interregional coordinated system plan (CSP) with SPP.
“I just don’t want people to have to submit projects twice,” McKinnie said.
Ellis said any projects submitted under the CSP will be evaluated separately by the RTOs first. In the unlikely scenario that a North-South transmission project also qualifies as an interregional project, it will not be overlooked, he said.
CARMEL, Ind. — MISO is seeking to fine-tune its forecasting of wind generation as it faces the prospect of immense volumes of new capacity coming onto its system by 2023.
Speaking at an April 23 wind forecasting workshop, MISO forecast engineer Blagoy Borissov said the event was a “first step” in the RTO’s attempt to be transparent about its forecasting procedures and how it can improve the process.
“The timing for us is right to start having a conversation about wind forecast accuracy,” Borissov said. “In just four short years, we’re going to go from 19,000 MW to 29,000 MW of wind generation.”
He also pointed to the frequency of MISO setting new wind output records: The latest, 16.3 GW, was set on March 15.
The RTO predicts it will have more than 22 GW of wind in its system by the end of the year, rising to 29 GW by 2023. It had just 5 GW when it began its wind forecasting process in 2008.
Borissov stressed that the accuracy of MISO’s intermittent forecasts is imperative to ensuring that committed generation can meet expected load. When forecasted wind generation doesn’t materialize, the RTO must make additional commitments.
Under current practice, market participants can employ their own wind forecasts or rely on MISO. The RTO’s short-term wind forecast is updated both hourly and during every dispatch interval using five independent weather prediction models and detailed unit information that owners submit. The RTO uses the hourly forecast to satisfy must-offer requirements in the day-ahead market, while it uses the five-minute forecast for dispatch.
Where wind generators create their own forecasts, MISO incorporates that data into its models instead of filling in its own. If a resource owner fails to update its wind forecasts at least every 30 minutes, MISO reverts to using its own data in the forecast.
But MISO said it sometimes receives inaccurate forecast data from wind operators, hampering predictions of the actual generation capability of wind units.
“It definitely impacts how our wind forecasts are produced,” MISO forecasting engineer Dorsana Desai said.
Comparisons have shown that MISO’s forecasts are more accurate than those of operators, Desai said. The RTO creates standby forecasts for wind units even when they elect to furnish their own forecast data.
Market participant forecasts also suffer from a positive bias, with unit operators tending to over-forecast their generation. MISO also said it sometimes receives imprecise commercial operation dates from wind operators, compounding forecast inaccuracies.
MISO will begin performing a quarterly study to identify forecasting inaccuracies, Desai said, and email unit operators that repeatedly forecast output outside of a band of reasonableness determined by the RTO.
For its part, MISO is working to improve a time lag in its forecast algorithm, Desai said.
| Madison Gas and Electric
The forecasting workshop is in part a response to the RTO’s most recent maximum generation event, in which an inaccurate wind forecast contributed to an emergency declaration. During the Jan. 30 event, wind generation stayed well above its 2.3-GW capacity requirement that day based on Planning Resource Auction clearing. However, the RTO’s wind forecast had predicted many more wind offers into the market.
Wind output during the morning peak was about 4 GW below forecast as the worst of the cold struck the Midwest. It averaged 4.3 and 4.7 GW on Jan. 30 and 31, respectively, compared with about 13 GW for the two days prior to the event. MISO said the missed wind forecast was likely because the RTO did not factor in extreme weather cutoffs. (See MISO Details ‘Uncertainty’ Behind Winter Max Gen Event.)
“MISO has never experienced these extremely cold temperatures with the amount of wind generation we have today,” Ron Arness, the RTO’s director of central region operations, explained at a Market Subcommittee meeting in March.
In response, MISO is seeking to update the operational details of wind units by reaching out to generation owners to learn what might have changed. It will also evaluate how extreme events affects wind forecasting.
“Some of these wind units were registered eight, 10 years ago. … Maybe the information we got from the wind farms is no longer accurate,” Desai said, adding that wind operators could have since installed new technology that might affect operation of their units. She said MISO plans to reach out to all wind operators.
Beyond that, MISO is also examining using entirely new models or research to alter its wind forecasting process. Desai said such changes would represent a long-term effort, and stakeholders shouldn’t expect a major proposal any time soon.
FERC last week accepted settlements with Duquesne Light Co. and an unnamed municipal utility in the Western Electricity Coordinating Council for violations of NERC reliability standards. The commission filed a notice Friday that it would not review the penalties, leaving NERC’s settlements intact (NP19-6).
NERC reported the settlements in a spreadsheet notice of penalty on March 28.
$40,000 Penalty for Duquesne Light
Duquesne agreed to a $40,000 penalty for inaccurate ratings of some substation conductors and a 138-kV circuit, violations of FAC-008-3 R6.
The substation inaccuracy — caused by entering an incorrect input value into one of the rating equations — resulted in a reduction of the overall facility rating for three transformers.
The violation extended for more than two years because Duquesne “lacked an effective verification control” to quickly detect and correct the error, NERC said. The company alerted regional entity ReliabilityFirst of the problem in a self-report in August 2017, after completing its mitigation plan.
NERC said the violation did not indicate a systemic issue with Duquesne’s FAC-008 program because only about 3% of the company’s bulk electric system (BES) transmission facilities were affected.
NERC determined the violation posed a moderate risk and could lead to equipment failure. “The risk is increased because of the long multiyear duration of the violation, but the risk is lessened (and not serious) because only one of the incorrect substation conductor ratings [was] the most limiting factor for these facilities,” NERC said. “The changes that did result in a facility ratings change did not impact the load dump ratings at any ambient temperature set but did impact the normal and emergency ratings.”
The second violation, involving the Clairton‐West Mifflin 138-kV circuit, was discovered during a compliance audit in December 2017. NERC said a section of overhead stranded conductor was not shown in Duquesne’s circuit map. After updating the map, Duquesne conducted a new analysis that resulted in reducing the summer 95 degrees Fahrenheit continuous rating from 932 amperes to 919 amperes.
The violation resulted in ratings reductions for three of Duquesne’s 85 BES transmission circuits (4%).
Although the incorrect ratings were in place for more than three years, NERC characterized the risk as minor “because the change in rating on the 138-kV circuit was minimal: just 13 amperes.”
NERC credited Duquesne for its cooperation in the investigation but said the company’s FAC-008/FAC-009 compliance history was an aggravating factor in determining the penalty.
Muni Lacked Familiarity with NERC Standards
FERC also chose not to review NERC’s settlement with an unnamed municipal utility over six violations of critical infrastructure protection (CIP) standards. NERC redacted some details of the violations and the utility’s name to protect critical energy/electric infrastructure information (CEII).
NERC’s filing said the utility:
Mischaracterized cyber systems at a substation as low-impact BES cyber systems (LIBCS) that should have been considered medium-impact BES cyber systems (MIBCS). An incorrect analysis found the systems connected to only two other substations when they were actually connected to four other transmission assets and had ties to two different entities, NERC said.
Failed to eliminate unneeded network accessible ports from an engineering workstation in a data center.
Failed to conduct an adequate security patch management program, including a requirement to check for new security patches every 35 days. NERC cited the entity’s “lack of knowledge and understanding of CIP standards.”
Gave five employees electronic or unescorted physical access to its MIBCS without having completed access request forms.
Failed to identify in its baseline configuration all of its network accessible ports and security patches applied to assets.
Failed to perform required change management activities for BES assets, electronic access control monitoring systems and physical access control systems.
Failed to provide evidence that it removed the ability of employees to access its systems within 24 hours of a termination.
NERC imposed no financial penalties for the violations and said none of them posed a “serious or substantial risk” to the reliability of the BES. The entity is a “very small municipal power company that employs few staff and has an extremely low turnover,” NERC said.
WESTBOROUGH, Mass. — Two of three economic study requests presented at ISO-NE’s Planning Advisory Committee meeting Thursday pertained to offshore wind development, while the other concerned transmission upgrades needed to accommodate onshore wind resources in Maine.
The New England States Committee on Electricity (NESCOE) requested that the RTO analyze various scenarios of the integration of OSW of up to 4,000 MW by 2030 and 7,000 MW by 2035.
“We’re trying to figure out the best place for these [offshore projects] to interconnect,” said Dorothy Capra, NESCOE director of regulatory services.
Transmission developer Anbaric Development Partners requested a study to review the impacts of OSW on energy market prices, emissions and regional fuel security in 2030.
Theodore Paradise, senior vice president of transmission strategy and counsel at Anbaric, predicted there will be between 8,000 and 12,000 MW of OSW nameplate capacity in New England by 2030, not including the current 9 GW target to serve New York loads.
“One of the great things we’ve done in New England over the past decade or so is spend $13 billion to $14 billion on infrastructure … so it looks like the system can handle the extra generation,” Paradise said.
One stakeholder, however, wondered whether the industry is reaching a level of irrational exuberance, with several parties potentially relying on the same resources for reliability.
RENEW Northeast Executive Director Francis Pullaro presented a request to evaluate the economic impact of two conceptual alternate transmission upgrades that would increase the hourly operating limits of the Orrington South interface in Maine.
If the study shows the expected production cost savings from one of the scenarios exceeds the expected cost of the upgrade, RENEW will ask the RTO to identify the project as a possible market efficiency transmission upgrade.
Eversource to Rebuild Conn. 69-kV Line
Eversource Energy is completely rebuilding 6.1 miles of the 69-kV 667 transmission line from the Falls Village substation to the Salisbury substation in Connecticut, with completion expected by year-end.
Eversource transmission hardware dating back to 1926 | Eversource Energy
Eversource planning engineer John Case detailed the estimated $24 million project to replace 51 lattice towers, and one wood tower, with 18 engineered and 35 light-duty weathered steel structures. The line, designed for 115 kV, was built in 1926.
The project will also add one light-duty structure outside the Falls Village substation to improve clearances, replace steel-reinforced aluminum conductor with steel-supported aluminum conductor and replace existing shield wire with new optical ground wire.
Final 2019 Load Forecast
ISO-NE’s 2019 Capacity, Energy, Loads and Transmission (CELT) winter forecasts are slightly higher relative to last year, with the 2027 winter 50/50 gross demand forecast up about 1.1% and the net demand forecast for that year about 1.2% higher.
ISO-NE implemented monthly energy modeling for this year’s forecast, rather than annual, Manager of Load Forecasting Jon Black said.
“We did that intentionally so that we could capture seasonal trends as they diverge,” Black said.
The RTO revised and updated the winter demand models, replacing dry-bulb temperature with effective temperature — to include the effect of wind on heating demand — and incorporating heating degree days as a second weather variable.
2019 New England gross 50/50 winter peak forecast | ISO-NE
The historical weather period used to generate a probabilistic forecast was shortened from 40 to 25 years, now covering 1991-2015.
Black said the 2019 model demonstrates improved performance relative to 2018 based on a comparison of mean absolute percentage errors: 1.1% during January 2019 non-holiday weekdays from 2.2% a year earlier.
“So this is really good feedback and shows we’re on the right track,” Black said. “If batteries come into our market, that’s not a load forecasting problem. All indicators suggest that the outlook for out-of-market batteries across the region are still too small to be a significant forecasting influence.”
Cutting Tx Review Periods to Save Time
ISO-NE will shave two months from its typically yearlong — and sometimes much longer — transmission planning process by halving the typical stakeholder review period for the Needs Assessment and Solutions Study documents.
“Stakeholders have said the transmission planning process takes far too long,” said Director of Transmission Planning Brent Oberlin, presenting a summary of the changes.
“Previous comments from stakeholders were to automate, automate, automate … which has been helped by a move to cloud computing,” Oberlin said.
Reducing the time for document review will provide further time savings. The RTO currently allows for 120 days of stakeholder document review in the planning process: 30 days for the draft scope of each document, followed by 30 days to review each final draft. But staff have determined that neither the Tariff nor the Transmission Planning Process Guide specify a duration requirement for the two review periods, enabling it to reduce those periods by half, in part because of redundancies within the documents.
The RTO expects to use similar time periods for stakeholder review of public policy and competitive solicitation materials generated by ISO-NE, unless otherwise mandated by the Tariff.
Tx Opportunity Reminder
Oberlin also reminded stakeholders of the qualified transmission project sponsor (QTPS) application process ahead of the release of ISO-NE’s first RFP in late 2019 or early 2020 for a competitive transmission solution based on the Boston Needs Assessment.
The RTO attempts to complete its review of QTPS applications within 90 days of the application being deemed complete, so any company planning to participate in the potential Boston RFP — or any other future competitive solution RFP — should apply soon, Oberlin said.
Eastern Conn. 2029 Needs Assessment Scope
ISO-NE Transmission Planning Engineer Jon Breard explained the changes between the 2027 and 2029 Eastern Connecticut (ECT) Assessments, noting that the RTO suspended the ECT 2027 Solutions Study process because of the changes in the 2019 CELT data.
Breard said the net load being used in the 2027 Solutions Study was too high given the change in estimated load, energy efficiency and solar PV from the 2017 CELT to the 2019 forecast.
The ECT 2029 Needs Assessment notably includes a scenario to capture stakeholder feedback on the 800-MW offshore Vineyard Wind project interconnecting to Southeast Massachusetts and the 1,090-MW New England Clean Energy Connect project interconnecting to the Larrabee Road substation in Maine, both selected in state-sponsored solicitations.
Stakeholders must submit comments on the ECT 2029 Needs Assessment to pacmatters@iso-ne.com by May 12. ISO-NE will post the assessment’s intermediate study files in the second quarter and post the report in the third or fourth quarter this year.
VALLEY FORGE, Pa. — Load interests last week backed a joint proposal from PJM and the Independent Market Monitor that would strip capacity interconnection rights (CIRs) from generators seeking must-offer exceptions without a plan to become capable of meeting Capacity Performance requirements.
The Markets and Reliability Committee approved the proposal in a sector-weighted vote of 3.74 to 1.26 on Thursday, with unanimous support from both electric distributors and end-use customers. The two sectors shot down PJM’s original plan to take CIRs from resources after a three-year period of lost CP capability that was approved by 79% of the Market Implementation Committee in November, as well as an alternative from Exelon that would have allowed capacity resources to switch voluntarily to energy-only status and disallowed PJM to force such a switch.
The PJM-Monitor proposal requires existing capacity resources not offered in three consecutive auctions to change to energy-only status. A resource receiving a must-offer exception must also file a plan showing how it will become able to satisfy CP requirements in order to retain capacity status or else forfeit its CIRs. The requirement would be effective with the 2023/24 delivery year. Resources would be granted exceptions for no more than two auctions.
“The main motion would permit hoarding of CIRs inappropriately,” Monitor Joe Bowring said. “We continue to believe the compromise we worked out with PJM makes the most sense.”
The votes represent an about-face for stakeholders, who threw 61% support behind Exelon’s plan at the March 6 MIC meeting. Only 35% preferred the PJM-Monitor plan at the time. (See Showdown Set on PJM Must-offer Exceptions.)
“We realize the CIR issue has been very charged, but the conversation has lacked data and facts,” said Sharon Midgley, Exelon’s director of wholesale development. “The PJM-IMM proposal would create an unlevel playing field.”
Traditional generation owners balked at the notion that resources exempted from the must-offer requirement, including renewables, don’t face the same possibility of losing CIRs.
David “Scarp” Scarpignato of Calpine called the rules “discriminatory” and warned PJM of moving forward with the package, noting it would exacerbate problems in the future.
“PJM itself should be weary of putting forth a proposal like that,” he said. “I don’t think you are supposed to put forward discriminatory rules, and these are very discriminatory. This is a critical issue to us, and quite frankly it’s becoming more and more apparent in the stakeholder process that some resources get preferred treatment.”
Stu Bresler, PJM’s senior vice president of operations and markets, argued that the disparity is a result of the market rules created by stakeholders and ultimately approved by FERC.
Susan Bruce, representing the PJM Industrial Customer Coalition, suggested the MIC continue discussion about CIR inequities in future meetings. Staff agreed to review the original problem statement and issue charge for further Manual 18 revisions and return to the May 15 MIC meeting with a path forward. The PJM-Monitor proposal has not yet been scheduled for endorsement by the Members Committee.
Declining wind output drove down Avangrid’s first-quarter earnings by 11% compared to a year earlier, company officials said last week.
Avangrid posted net income of $217 million ($0.70/share), down from $244 million ($0.79/share) in the same quarter a year ago. The drop was driven primarily by a $46 million decrease in the company’s Renewables business, from $50 million in Q1 2018 to $4 million this year. Wind production during the period averaged 14% below 2018 levels, reflecting “the impacts of storms and severe weather,” CFO Doug Stuver said in an earnings call Thursday.
BOEM map shows Vineyard Wind wind energy lease area offshore Martha’s Vineyard and Nantucket. | BOEM
The drop in the Renewables business was partially offset by an $18 million increase in the company’s Corporate segment “due to favorable tax impacts,” Stuver said.
Total revenue for the quarter was down by 1.2%, from $1.865 billion in 2018 to $1.842 billion.
CEO James Torgerson told analysts that despite the hiccup in wind output, Avangrid expects nearly 1 GW of renewables under construction to come online this year and has increased its pipeline by 1.6 GW to 15.4 GW, which includes 4.4 GW of solar.
Its Vineyard Wind offshore project, a joint venture with Copenhagen Infrastructure Partners, is on track, “with nearly 70% of the supply chain secured,” Torgerson said. The project’s contracts with the electric distribution companies recently received Massachusetts Department of Public Utilities approval. “Now, we are targeting to have all 800 MW in operation by the end of 2021,” he said.
With their Liberty Wind project, Avangrid and Copenhagen also submitted a bid in New York’s first offshore wind solicitation, with options for 400, 800 and 1,200 MW. (See Four Bidders Vie for NY Offshore Wind Project.) The New York State Energy Research and Development Authority is expected to announce the winner this spring.
The companies also submitted to Rhode Island two proposals of 200 MW and 300 MW each, with the selection of bidders expected in May.
