CAISO will make permanent a once-temporary practice of boosting its power reserves to account for utility-scale solar tripping offline because of an inverters problem, something NERC has identified as a major reliability issue.
When solar generation is at its peak, CAISO will set the operating reserve target at either 15% of the total solar production forecast or the maximum NERC/Western Electricity Coordination Council requirement, whichever is greater.
CAISO says the inverter problem affects utility-scale solar, not rooftop systems | Sarah Swenty/USFWS
The ISO has worked with solar operators to reprogram inverters since last year, CAISO Shift Supervisor John Phipps said Monday at a Market Performance and Planning Forum. Some of the inverters began working properly after reprogramming, but others are hard-wired and still subject to tripping. Phipps said 2,700-2,800 MW of generation across the whole ISO system cannot be reprogrammed.
“They are not in any one regional area; they are spread out across all the plants in California,” Phipps said during a presentation, adding that the issue is not affecting behind-the-meter or storage resources.
The inverters, which convert photovoltaic DC output to utility frequency AC, sometimes trip offline to protect the systems during voltage fluctuations. CAISO began procuring additional reserves a year ago, after the problem occurred in August 2016 because the Blue Cut fire in Cajon Pass caused transmission line faults and disconnected 1,200 MW of solar. (See CAISO Boosts Reserves After August Event Report.)
CAISO CEO Steve Berberich last month cautioned the ISO’s Board of Governors about the seriousness of the problem, which caused the loss of 860 MW of solar resources on April 20. (See CAISO Board Approves Forecast Error Measures.)
The inverter problems have so far triggered two NERC alerts, one on June 20, 2017, and the other on May 1 of this year. NERC said the problem could also affect non-bulk power systems and recommended all operators follow recommendations spelled out in the more recent alert.
“While this NERC alert focuses on solar PV, we encourage similar activities for other inverter-based resources such as, but not limited to, battery energy storage and wind resources,” the agency said in the May 1 alert.
Ancillary Service Scarcity Increases
CAISO has seen an increase in ancillary service scarcity events in the real-time market, Director of Market Analysis and Forecasting Guillermo Bautista Alderete told the forum. He said while the number of incidents has increased, the magnitudes are small, with about 75% of the scarcities at fewer than 10 MW. The increased incidents stem from a confluence of factors and changes in the market, he said, including the solar operating reserve requirement.
Sources of 2018 ancillary service scarcity events | CAISO
Most recently, CAISO issued three notices of ancillary service scarcity events for May 3-6, May 15 and May 23-28, nearly all of which were associated with regulation up service and mostly in the SP26_EXP region in Southern California. In 2018, 46% of the scarcities happened in SP26_EXP, 35% in NP26_EXP and 19% in CAISO_EXP.
CAISO pays an ancillary services scarcity price when it is unable to procure the target quantity of one or more ancillary services in the integrated forward market or real-time market runs. About 52% of the scarcities are due to limits in generator telemetry, which is the process whereby a generator supplies the ISO with real-time data. Mismatches between telemetry and real-time needs require the ISO to procure additional capacity in the real-time market. About 33% are due to generator outages and re-rates, and 15% are categorized as “other.”
CAISO’s Market Monitor in its 2017 State of the Market report noted that scarcity events in the real-time market “increased significantly” from 26 in 2016 to 54 in 2017.
ISO-NE said last week it has become the first U.S. grid operator to put demand response into its energy dispatch along with generating resources.
The RTO’s price-responsive demand (PRD) structure, which took effect June 1, enables full integration of DR into its energy, reserves and capacity markets.
Like generators, active DR is now eligible to submit day-ahead and real-time energy offers and receive wholesale market payments for energy, operating reserves and capacity. DR resources can be co-optimized in the RTO’s economic dispatch, committed by the RTO a day ahead and dispatched in real time.
“The new thing is that active demand response resources can participate by submitting price and amount offers in the day-ahead and real-time energy markets, and they can set price,” said ISO-NE spokeswoman Marcia Blomberg.
Modest Impact
Blomberg said the impact of the changes on the markets has been modest thus far.
“On several hours on several days, we’ve seen small amounts [of DR] clearing,” she said of the RTO’s experience since the beginning of the month. “On other days, no DR cleared.”
Active DR resources are dispatchable because they can reduce consumption at will by reducing industrial production or switching to on-site generators or storage. Passive DR — energy efficiency and distributed solar generation, for example — are not dispatchable.
Potential Peak Reduction from U.S. ISO and RTO Demand Response Programs | Assessment of Demand Response and Advanced Metering Staff Report, FERC, December 2015
Active DR was previously able to offer load reductions at a price in the day-ahead energy market, but their offers were administratively evaluated after the market had cleared. DR offers were not used to determine the optimal dispatch of resources or to set price.
Both active and passive DR have been able to participate in the capacity market since 2006. Participating DR was dispatched only during grid emergencies, Blomberg said.
In March 2011, FERC Order 745 required RTOs/ISOs to pay active demand resources the market price for helping to balance real-time supply and demand.
‘Enormous Project’
Integrating active DR into the markets “has been an enormous project, requiring the ISO to not only develop and implement extensive market rule changes, but to update computer systems and processes related to grid operations and market settlement,” Henry Yoshimura, director of demand resource strategy, explained in the RTO’s newsletter. “Consequently, the full integration of active demand resources was achieved in a staged approach.”
| ISO-NE
Facilities that reduce their consumption of electricity are known as demand response assets (DRAs). DRAs under 5 MW can be mapped to a DR resource that participates in the energy and reserve markets. A DRA that is 5 MW or larger must participate individually as its own resource.
DR resources can be mapped to an active demand capacity resource (ADCR) for participation in the capacity market. Passive DR resources may only participate in the capacity market.
VALLEY FORGE, Pa. — PJM is planning to add another volume to its Manual 14 series by splitting out the requirements for generation interconnection from Manual 14A into a separate Manual 14G, staff told attendees at last week’s Planning Committee meeting.
PJM’s Lisa Krizenoskas walked through the separation, noting that the new manual will be organized by generators under 20 MW, over 20 MW and other types of generation.
Staff said that rules for handling multiple generators behind the same point of interconnection will be addressed after the manual split is endorsed, but Ryan Dolan from American Municipal Power questioned why they wouldn’t try to sort out both issues simultaneously. Krizenoskas said the new rules might delay the separation, which is meant to provide clarity for generators.
Load Model Selection
PJM’s Patricio Rocha-Garrido presented PJM’s proposed load model for the 2018 reserve requirement study focused on the 2022/23 delivery year. Staff recommend the same model used last year, along with again switching the peak week for regions external to PJM, known as the “world” in the analysis, to a week that doesn’t coincide with PJM’s peak.
Staff used 18 years of load history, 23 years of weather history and at least seven years of hourly loads to develop 78 model candidates. The candidates were compared to PJM’s “coincidental peak 1” distribution analysis, which represents the highest load forecasted for the summer of the forecast year, using two separate approaches. The comparisons found that the 10-year model from 2003 to 2012 used in 2016 and 2017 remains the best choice because it was a close second to a nine-year model in the comparisons but includes an extra year of load data.
The “world” peak week was again switched to not coincide with PJM’s because the peaks haven’t coincided in 11 of the past 19 years.
Dolan questioned why PJM doesn’t use more-recent data to reflect changes in demand-side activity.
“The world is changing, and I think … [the] ability to control our load is much different from what it was in the earlier years of your data set,” he said.
Facility Ratings Fine
PJM’s Mark Kuras discussed staff’s process for confirming transmission owners’ facility ratings, concluding that “TOs have demonstrated that strict processes and controls are already in place to ensure facility ratings used in PJM operation are determined based on technically sound principles” and that “there are no requirements for PJM to approve or verify a TO’s ratings or do any kind of consistency check.”
The discussion came after AMP and the PJM Industrial Customer Coalition criticized how TOs calculate the ratings. (See “Facility Rating Concerns,” PJM PC/TEAC Briefs: April 5, 2018.)
TOs are required by NERC Standard FAC-008-3 to develop and adhere to a methodology for developing facility ratings, but they aren’t required to publish it. Kuras noted that PJM publishes the final facility ratings on a public page.
“I think this presentation shows that, in and of itself, there are no issues with FAC-08” and how it’s implemented, PJM’s Aaron Berner said. “If that continues to be a concern, we can have those further discussions” about specific projects with proposing entities, he said.
Dolan said part of the concern is that in the process for determining whether they can develop a successful project bid, prospective developers must seek information that could make the incumbent TO aware of the potential proposal in a competitive window, which creates competition issues.
TO Planning Criteria Updates
Both Public Service Electric and Gas and American Electric Power provided updates to their planning criteria filed earlier this year with FERC.
AEP announced it will no longer use Rate A for category P1 contingencies for lines above 345 kV and instead evaluate those facilities using Rate B for P1 through P7 contingencies.
PSE&G’s Glenn Catenacci presented his company’s updates, which modify pre-fault voltages, certain contingencies and other definitions. Dolan noted that several of the changes create requirements for building additional system infrastructure.
Among the changes was including non-firm transfers in models when considering common-mode outages. The presentation to stakeholders of the change comes after FERC rejected a complaint from the New Jersey Board of Public Utilities seeking to revise how infrastructure costs are allocated, and that would have included several merchant lines into New York City that have changed their transmission rights to non-firm transfers. (See PSE&G on the Hook for Bergen-Linden Costs.)
Dolan questioned including non-firm transfers in the calculations because they wouldn’t be included in allocating any costs for any system upgrades that subsequently become necessary.
“We think the people driving the need for transmission should be paying for it; however, there is a reliability issue,” PSE&G’s Esam Khadr said. “We need to address that reliability issue.”
Khadr said he can’t terminate non-firm transmission service, which hadn’t been planned for previously because “it was not as prevalent as it is today.”
“We have an obligation to all of our neighbors … to maintain reliability to the bulk power system,” said PJM’s Ken Seiler, who chairs the PC.
Staff haven’t engaged with NYISO on non-firm transfers in planning criteria, but he said, “We’ll evaluate it and certainly make any recommendations back to the Planning Committee.”
Dolan and Khadr also sparred on whether to use breakers as an option for maintaining system reliability. The discussion came as part of PSE&G’s clarification of how it will handle N-1-1 situations and its decision to not permit opening breakers.
“We’re not going to plan a system by further degrading the system by opening breakers,” Khadr said. “You’re taking away that redundancy by taking away that breaker.”
PJM’s Phil Yum presented attendees at the Transmission Expansion Advisory Committee meeting 23 baseline projects sparked by FirstEnergy Solutions’ announcement in April that it plans to shutter its three nuclear facilities within three years. (See FES Seeks Bankruptcy, DOE Emergency Order.)
The projects would cost upward of $190 million combined, and because they are all within the three-year window for “immediate need” projects, they would all be assigned to the incumbent TO. PJM’s Jason Connell confirmed that was the reason they can’t be opened to a competitive bidding window. The projects are in the transmission zones of AEP, Duquesne, and FirstEnergy subsidiaries Allegheny Power Systems and Penelec.
Several of the projects are associated with the closure of the Davis-Besse nuclear plant, which is scheduled to deactivate on June 1, 2020. The projects can’t be implemented until a year later, but PJM’s planning group has discussed the issue with RTO operations and found operating measures that can mitigate the reliability impacts in the interim.
AMP’s Ed Tatum questioned why PJM didn’t include more details in the project descriptions. Connell said, “Certainly the scope of the timing is a little different” because of the deactivations. “We were on a very, very accelerated timeline” to determine “as best was we could do in the time frame that we had,” he said.
Dolan questioned what might happen to the projects if FES ultimately decided not to deactivate the plants. Seiler dismissed the implication, saying, “Folks don’t play games with this type of thing” because it includes jobs, communities and other large-scale factors. However, he acknowledged, “I’m not saying it couldn’t happen in the future” based on a federal mandate or policy changes.
“We’ve never had any situation like this before. I agree it’s not gamesmanship or anything like that, but things could change very quickly,” Tatum said.
Seiler said money is already being spent on the engineering portions of the projects but said that if the decisions are reversed, “I think that would happen sooner rather than later.”
VALLEY FORGE, Pa. — PJM experienced 77 emergency procedures in May, staff told attendees at last week’s Operating Committee meeting.
Calling it a “busy month,” PJM’s Chris Pilong said the emergency procedures included the first time the RTO has had to order load shedding since implementing its Capacity Performance rules in 2015. (See PJM Experiences First Load Shed in the CP Era.)
The events resulted in a portion of the load forecasting error exceeding its 3% target for the first time since July. The on-peak forecasting error was 3.08%, and the off-peak 1.69%, putting the overall error at 2.38%.
While the error increased in some transmission zones, East Kentucky Power Cooperative posted a 3.3% error, the lowest level in the past 10 quarters.
Load Shed Event
Pilong explained that five facilities were involved in the event. Three 138-kV lines in the area were on planned outages that day. A transformer and additional line tripping out of service triggered “multiple” contingency overloads, which potentially could have resulted in a cascading outage if another facility was lost, Pilong said. Based on that analysis, PJM ordered a pre-emptive load shed to reduce the contingency flow on the Edison-Kankakee line. Within 15 minutes of issuing the order, the transformer was restored, and PJM canceled the load shed nine minutes later.
Twin Branch Load Shed Map | PJM
“Given the timeline, we didn’t need to, but we were definitely looking at [dispatching demand response or behind-the-meter generation in area] and considering those as well,” Pilong said.
The load shed triggered performance assessment intervals (PAIs) that lasted about 30 minutes. While PAIs can trigger significant nonperformance penalties or performance bonuses, none resulted from the event, staff said. The incident was isolated to a small area of northwest Indiana that includes fewer than four generation owners, so PJM’s confidentiality rules prevent staff from releasing any additional information without the owners’ agreement. PJM’s Adam Keech said staff are working with owners to see if they can agree on releasing anything else.
Keech said PJM determined which units were involved by looking at any units that could have increased output to help alleviate the constraint for which the load was shed.
Event Analysis to Follow
While he couldn’t provide specifics on why the event yielded no penalties or bonuses, Keech advised stakeholders to “just remember we are in a year where we are not 100% CP,” referring to the interim base capacity designation PJM implemented as it transitions to the CP requirement that a resource always be available. Base capacity doesn’t have that requirement.
GT Power Group’s Dave Pratzon asked that staff analyze why the three 138-kV lines were allowed to be on planned outages simultaneously because it potentially puts “a few unlucky generators” at financial risk for something they can’t control.
“That’s potentially a large dollar impact for something that potentially has nothing to do at all with generator issues,” he said.
That question and the cause of the facilities tripping are “exactly what we’re looking at as part of the follow up,” Pilong said.
Several stakeholders asked PJM to find better ways to communicate the extent of the incident. RTO staff said they can only target messaging to the level of the transmission zone, even though the event affected a much smaller area, causing many stakeholders to wonder whether they were involved or not. Pilong said the conditions would have to be exactly the same for any refinement of the communication to be more selective, and that’s “probably unlikely.”
Besides, response to the event was unexpectedly quiet, despite the potential confusion.
“Oddly, we only got one phone call,” Pilong said. “It was, to be honest, a little bit surprising.”
Beyond that call, “there was no other anomalous behavior that was obvious or impactful,” he said, adding that system operators’ advice was the same as it would have been for any unit: follow the dispatch signal PJM provides.
Related Updates
Later in the meeting, PJM’s Alpa Jani explained that the load-shed directive was posted at 1:34 p.m. and was effective for 1:22 p.m. Any units that receive system notifications for the AEP transmission zone received the message because the area around the Edison substation where the equipment tripped is not defined as a subzone.
In another presentation, PJM’s Pete Langbein discussed how better “coordination” with behind-the-meter generation, also known as non-wholesale distributed energy resources, could help decrease load forecast errors or mitigate load sheds.
PJM is proposing to identify all such non-wholesale DER of greater than 1 MW on an annual basis, primarily through public Energy Information Administration data. Transmission owners would verify the data and include additions as available so they can be modeled in PJM’s planning and operations tools. The TOs would communicate downstream to the resources as necessary during events to avoid load sheds or dumps. Langbein said draft manual and Tariff language is being introduced in the DER Subcommittee and will move through stakeholder endorsement from there.
Security Initiatives
PJM’s Colin Brisson reviewed security initiatives planned for the RTO this year.
“Critical infrastructure in geopolitics is becoming a higher-priority target” and has hit the energy sector, he said. “We’re actually catching up to the curve where many companies are at.”
PJM is implementing geo-IP blocking, which blocks outside computers from interacting with the RTO’s network if its unique digital signature (or IP address) originates from “high-risk countries,” which Brisson didn’t identify. The technology will be rolled out “increasingly” throughout the year, he said.
The RTO is also implementing two-step verification, which means that along with providing the right password, users will have to tie their accounts to their devices using a “token” to log onto PJM’s network. Once a token is verified, users will be able to log on from that device without going through the process again. Training will begin on Aug. 15 and “full production” to members is scheduled for Oct. 10.
DMS
PJM’s Maria Baptiste announced the Data Management Subcommittee has decided to stop scheduling DMS-Joint meetings and instead hold them on an ad hoc basis as needed to address issues because of “very limited participation.” DMS-Confidential meetings will continue on their existing schedule, and several parts of the DMS-Joint will transition to the Confidential group, including reviewing NERC lessons learned.
The subcommittee will still have work to do. PJM’s Shaun Murphy announced that staff plan to ask the DMS to investigate why the quality of phasor measurement unit (PMU) data has been degrading. He presented a graph showing spikes in error percentages in various transmission zones through the RTO since February 2017. The issues include time, synch and drop errors, planned outages, missing samples and issues with engineering limits, such as threshold, noise and topology.
“On average, we’re starting to see they typical error rate starting to climb,” he said.
The DMS will investigate the impact of the data quality on applications that use the PMU data, enhancing the definition of “data quality,” improving real-time data quality monitoring, reviewing data quality requirements in manuals and guidelines for device outages.
30-Minute Reserve Vote Deferred
PJM had hoped to receive OC endorsement for its planned procurement of 3,784 MW for real-time 30-minute operating reserves, but the vote was deferred because the topic wasn’t included as a voting item on the agenda and came near the end of the three-hour meeting. Based on an analysis of potential reserve shortages, PJM estimates it should secure nearly 3,800 MW of a new 30-minute real-time reserve product. (See “30-Minute Reserves Target Set,” PJM Operating Committee Briefs: May 1, 2018.)
Synch Reserve Response
The RTO experienced one synchronized reserve event of more than 10 minutes in the first quarter, PJM’s David Kimmel said. Of the 1,897 MW estimated for the Tier 1 response, 510 MW responded, or 27%. Demand-side response was assigned all of the Tier 2 response. Of the 113 MW assigned, 58 MW responded, or 51%.
There were three events altogether, all of which occurred in January. Overall, 37% of Tier 1 estimates actually responded, or 2,029 MW. All of the 933 MW of generation assigned Tier 2 response responded, while 341 MW responded of the 397 MW of demand-side response assigned to Tier 2, or 86%.
The events resulted in $1.15 million of Tier 1 credits and $6,666 of Tier 2 penalties.
Stakeholders remain skeptical of PJM’s plan to revise procedures for generators’ capability testing requirements, which has the potential to reduce generators’ capacity injection rights (CIRs). For several months, PJM’s Jerry Bell has been presenting data analyses to justify the changes to using median capacity factors, arguing that the RTO’s current methods using average capacity factors overestimate what units can realistically be expected to provide. But stakeholders have been concerned about losing value they’ve already paid for. (See “CIR Questions,” PJM Operating Committee Briefs: May 1, 2018.)
Generators are concerned that some existing or planned CIRs could be potentially stranded through PJM’s proposal because it would reduce how a plant’s output is measured for the purposes of qualifying for CIRs.
“PJM is being kind of cavalier with other people’s investments. … There are other ways to do this,” Dayton Power and Light’s John Horstmann said. “I don’t think you’ve addressed the transition nor the compensation adequately. … These interconnection investment costs are not linear.”
Data Quality Trending | PJM
He reiterated a request for a special session to discuss the implication of the proposed changes, to which PJM staff ultimately agreed.
Bell’s presentation last week focused on the relationship between summer weather and production from hydroelectric dams. Among PJM’s proposed changes is limiting facility testing to July and August and eliminating June from the testing window. Bell’s analysis showed that hydro capability dips in July and August compared to June.
“As river temperature increases, generator capability wanes, but the majority of the capability decrease can be attributed to the cooling towers that are placed in service incrementally as river temperature increases and control of thermal discharge is needed,” Bell said. “These are the kinds of issues I’m having and why I want to see full plant testing.”
Net Generation/Capability vs. River Temperature | PJM
He said a “blanket” RTO calculation is infeasible because conditions vary throughout the RTO’s footprint and there will always be a situation where the analysis won’t be applicable, “so I’d rather just have everybody test in July or August.”
Several generation owners expressed concerns with the plan, such as the constraints of being able to test during a more compressed timeline.
“We just don’t know how we would get this done in two months,” Exelon’s Sharon Midgley said.
“PJM is kind of cavalier with other people’s investments. … There are other ways to do this,” Horstmann said. “I don’t think you’ve addressed it adequately. … The investments are not linear.”
“I’m open to suggestions, but … I want to make sure that everybody understands that when you use the average capacity factor, you are overstating your ability to meet load during peaks and we need to rectify that situation,” Bell said.
Some stakeholders suggested tailoring the requirements to specific unit characteristics, though Bell envisioned some concerns with that.
“Then it becomes somewhat discriminatory to some folks … but if we can work that out, I don’t have a problem at all,” he said.
He said units with “questionable test” results would likely be the first asked to retest under the new rules, but “there will probably be some folks that I would never even look at them.” Other units likely to be contacted are those whose ambient conditions change during the season.
John Brodbeck of EDP Renewables said the plan creates CIR issues for generation in the interconnection queue that will fund network upgrades and “it sort of cries out for a problem statement.” PJM staff did not respond to the suggestion.
VALLEY FORGE, Pa. — At PJM’s Market Implementation Committee meeting last week, RTO staff outlined their proposal for registering aggregations of seasonal demand response resources that can’t comply with the year-round requirements of Capacity Performance. The current process fails to account for some of the resources’ overall capability depending on how they are aggregated.
PJM’s Andrea Yeaton and Terri Esterly explained the proposed revisions, which would dispatch resources individually based on their seasonal ability but account for them cumulatively for the purposes of CP. They said the changes provide greater dispatch flexibility while also reducing the administrative burden and minimizing unaccounted-for capability.
Joe Bowring, PJM’s Independent Market Monitor, expressed concerns about the proposal, notably in how it allows resources to aggregate across zones when the resources should be accounted for on a nodal basis as other resources are.
The proposal will be discussed at next month’s meeting to provide more clarity. Staff want it to become effective for the 2019/20 delivery year.
Response to FERC’s Cost Allocation Order
PJM’s Ray Fernandez outlined staff’s plans to address FERC’s order on the RTO’s procedure for allocating the costs of major transmission projects. The issue had dragged on for more than a decade in court orders and disputes between stakeholders, but after more than a year of negotiations, FERC last month approved a settlement agreement filed in June 2016 (EL05-121).
A large majority of stakeholders agreed to the settlement, which created a cost allocation formula for projects approved prior to Feb. 1, 2013, when PJM abandoned a “postage-stamp” method that billed all utilities in proportion to their load, regardless of where the projects were located. Several stakeholders, including Direct Energy and the Retail Energy Supply Association, had protested the agreement. (See Despite Lengthy Negotiations, PJM Cost Allocation Settlement Still Finds Detractors.)
Fernandez said staff were considering requesting a 30-day extension, which they filed later that afternoon. The motion requests an extension of the RTO’s compliance filing deadline to July 30, seeking a FERC response by June 14. PJM said in the request that it would affect the allocations for more than 100 baseline transmission projects.
The settlement revises the allocation for certain projects, effective back to Jan. 1, 2016, for which costs were assigned under the 100% load-ratio share method FERC had previously approved. Affected projects include those that are 500 kV or above and any associated “necessary lower-voltage facilities” as defined in PJM’s Tariff. The allocation for all such projects will be split 50% on the original annual load-ratio share basis and 50% on the solution-based distribution factor (DFAX) method.
There is also a “black-box” settlement for projects from 2007 through 2015 that will have billing credits or charges based on revisions to Appendix C of Schedule 12-C in the Tariff that will be allocated over the next 10 years.
The revisions will show up in resettlements of wholesale bills: line 1108 for the reallocations and a new charge on line 1115 for the black-box settlement, Fernandez said. The reallocation charge will have to fit 30 months of resettlements into 12 months of billing.
“That’s the way the settlement agreement is defined,” Fernandez said.
GT Power Group’s Jeff Whitehead asked whether the resettlements would be accounted for as adjustments going back to 2016 or a one-time current resettlement.
“If it’s an adjustment going back to 2016, it’s going to be challenging to pass that through” to customers, he said. Retail energy suppliers “can probably only pass that through to customers you still have from 2016, which might be unlikely.”
PAI Fallout
PJM’s Adam Keech provided more information on the performance assessment intervals (PAIs) that occurred on May 29. PJM experienced its first PAIs — along with its first load shed — since implementing them as part of its major Capacity Performance overhaul in 2015. The incident occurred after a transmission line and a transformer at the Jackson Road substation in American Electric Power’s transmission zone tripped out of service, which — combined with three other transmission lines that were on planned outages — caused concerns about being able to deliver power in a section of northwestern Indiana. (See related story, “Load Shed Event,” PJM Operating Committee Briefs: June 5, 2018.)
A PAI is triggered when PJM determines a supply reliability issue exists, and provides credits for generators that overperform their capacity commitments and penalties for those who underperform. No credits or penalties were assessed in the incident, which Keech noted was at least partly because PJM still has “base capacity” in this delivery year. Base capacity was developed as part of the transition to CP and doesn’t have the same always-available requirements as CP resources. Because the event was localized to a small area that included less than four generation owners, Keech said PJM’s confidentiality rules prevented him from releasing more information.
Direct Energy’s Marji Philips voiced concern that how PJM assesses PAIs appeared “extremely discretionary.” Keech disagreed, saying “there was no ambiguity on” the assessment and that the lack of charges or credits was “not because we exempted people arbitrarily.”
“I think until we get more clarity, that’s the only reasonable assumption,” Philips said.
Citigroup Energy’s Barry Trayers said that reporting the calculated bonuses and penalties shouldn’t be a market-sensitive issue.
“I don’t see the market gain or loss by reporting … winners or losers,” he said. “I just don’t see the results of this being a market-sensitive” issue.
Accounting for Maintenance Costs in Cost-Based Offers
It remains unclear what package of revisions stakeholders are likely to endorse regarding whether maintenance costs are includable in cost-based energy offers. PJM believes they belong in plants’ variable operations and maintenance (VOM) costs that are part of energy-market offers, while the Monitor argues they are not short-run marginal costs that belong in energy offers but instead avoidable costs that are includable in the in a unit’s capacity offer. The issue was set to receive an endorsement vote at the May Markets and Reliability Committee meeting, but stakeholders instead agreed to kick it back to the MIC for further discussion. (See “VOM Remanded,” PJM Markets and Reliability Committee Briefs: May 24, 2018.)
PJM’s Tom Hauske presented an analysis that suggested the RTI’s proposal would raise costs by $8.1 million per year. He argued the Monitor’s assumptions on the issue were the worst case, short-term and low-probability. The Monitor’s Catherine Tyler and Joel Romero Luna presented an analysis arguing that PJM’s analysis misses the effect of higher unmitigated offers, fails to account for start-up and no-load costs and ignores cyclic starting and peaking factors.
They said 61% of combustion turbines they reviewed already have maintenance adders higher than the Energy Information Administration’s benchmarks, as do 19% of the combined cycle gas-fired turbines. They pointed to 2017 data that shows a $1/MWh increase in energy offers equates to a $14 million increase in uplift. Their proposal would lower cost-based energy offers from the status quo, while the PJM proposal would raise them, the noted.
Currently, an AEP proposal that used default EIA data is the main motion that was endorsed by the MIC for consideration at the June MRC. Greg Poulos, the executive director of the Consumer Advocates of the PJM States (CAPS), said one of his members plans to move the Monitor’s proposal for an endorsement vote at the meeting.
Long-term FTRs Undercut Annual FTRs
Despite an impassioned argument from the Monitor’s Howard Haas, stakeholders voted to endorse PJM’s plan for revising its long-term financial transmission rights market. PJM’s proposal received 178 votes in favor, 13 opposed and 53 abstentions for a favorability of 93%. The Monitor had offered as many as three proposals but dropped it to one for the vote. That proposal received 40 votes in favor, 147 opposed and 58 abstentions for a favorability of 21%. PJM’s proposal was preferred over the status quo by 79%, or 131 votes in favor, 35 opposed and 77 abstentions.
Haas had argued that PJM’s plan still gives away some of the transmission system capability that belongs to auction revenue rights holders because “there shouldn’t be any residual revenue allocation” left to offer into the long-term auction and “the fact that some participants aren’t taking advantage of the ARRs as they should be” shouldn’t preclude them from receiving the full benefits available. The Monitor’s plan would require market participants to find someone willing to take the opposite flow of the sought position. (See “Long-term FTRs,” PJM Markets and Reliability Committee Briefs: May 24, 2018.)
“The problem is you’re still selling capability that belongs to the load,” he said.
Calpine’s David “Scarp” Scarpignato said it’s not PJM’s place to choose the best decisions for ARR holders and that “centralized planning” like that doesn’t work.
“You have to allow that some market participants are going to make good decisions and others are going to make less-than-optimal decisions,” he said.
Exelon’s Sharon Midgley said her company’s strategy to hedge its transmission costs “would be severely limited” under the Monitor’s proposal because the company would “have to hope someone wants to take a completely opposite position … which is unlikely.”
Black Start Fuel Security Sent to Problem Statement
PJM’s David Schweizer announced that staff’s proposal to develop fuel security requirements for black start units will be transitioned to the problem statement and issue charge structure. The RTO has been attempting to develop requirements for black start units that ensure fuel security, such as connection to multiple pipelines for gas-fired units or on-site storage. (See “Black Start Fuel Assurance,” PJM Operating Committee Briefs: May 1, 2018.)
“PJM considers fuel assurance to be the ability of a unit to maintain full output during periods of fuel limitations caused by events such as seasonal weather extremes and high-impact, low-frequency events. Examples of high-impact, low-frequency events include pipeline failures or physical and cybersecurity events on a critical portion of a gas pipeline upon which black start resources may depend for fuel,” PJM said in the problem statement. “Initial analysis of PJM’s existing black start fleet indicates that approximately half of the units demonstrate fuel assurance, through dual-fuel capability, on-site fuel storage or multiple gas pipeline connections.”
The discussion will be split between the Operating Committee and the MIC. The OC will cover fuel assurance requirements, testing requirements and transition process while the MIC will address compensation issues. PJM expects the issues to take six months and be implemented by August.
Balancing Ratio Recalculation
PJM’s Pat Bruno presented two proposals for revising how the balancing ratio is calculated, recommending a more sophisticated fix but offering another in recognition of potential time constraints for having a solution implemented in time for next year’s Base Residual Auction.
The simpler option would use the balancing ratios from actual PAIs whenever possible and estimate them from the remaining intervals with the highest peak loads until there are 360 intervals, or 30 hours, total. The more complex solution would revise the formulas that use the balancing ratio — the CP nonperformance charge rate, or performance penalty rate (PPR), and the market seller offer cap (MSOC) — to include “projected performance assessment intervals,” which would be calculated for the delivery year as the average number of PAIs from the previous three delivery years. The MSOC would have a floor of 60 PAIs, or five hours, and the PPR would have floor of 180 PAIs, or 15 hours.
PPR & MSOC Proposal Examples | PJM
“It seems like you’re picking numbers that feel good rather than backing into something from an empirical basis,” Exelon’s Jason Barker said.
Scarp and GT Power Group’s Tom Hyzinski agreed that having different floors for the MSOC and PPR calculations was problematic.
“It’s not a little bit off. It’s off by a large amount, and it’s highly problematic for operators looking to put competitive offers into the market. I understand you wanting to put them in, but they need to match,” Scarp said.
As the discussion progressed, Scarp offered his own proposal that largely mirrored PJM’s except in how many PAI events are used in the calculation. PJM agreed to organize a special session on the issue for June 19.
Stakeholders expressed concerns that PJM’s formula could cause generators to lose all their annual capacity revenue in a short period. GT Power Group’s Dave Pratzon said the estimates seem excessive, particularly in light of the recent PAI event, in which generators were on the hook despite the cause being a transmission constraint.
EnerNOC’s Katie Guerry was concerned that, depending on the number of PAIs that occur, the PPR can double from $3,650/hour to $7,300/hour, while the MSOC would get smaller, starting at $255/MW-day with more PAIs and falling to $85/MW-day when there are none.
“I appreciate that you guys were trying to find a number that’s not excessively high [and] … did a lot of work [in a short time period], but it was all internal,” she said.
Bruno mentioned that FERC approved ISO-NE’s hourly penalty rate of about $5,500/hour but noted that staff are open to feedback on the proposals.
DC Energy FTR Credit Policy Complaint to FERC
PJM’s Bridgid Cummings explained the RTO’s proposed revisions to its FTR credit policy, and CFO Suzanne Daugherty explained how its position related to a complaint on the topic that DC Energy filed at FERC (EL18-170).
PJM wants to implement a per-megawatt-hour minimum credit requirement to address potentially large FTR positions that have little or no credit requirements. It’s also considering a monthly $100,000 deductible to the existing undiversified adder to address uncertainty and auction clearing disruption.
The per-megawatt-hour credit requirement dovetails with DC Energy’s request for a 5 cent/MWh requirement, which Daugherty said is the minimum PJM is seeking.
“We think that is an improvement to the credit policy that we can absolutely support,” she said.
She said staff are “not convinced yet” of DC’s second request, a mark-to-auction requirement.
“I think some of the concern is … auctions are only once a month,” so “clearing prices seem to jump around.” Sometimes they would match, she said, but other times not, particularly closer to delivery. She acknowledged some market participants have high megawatt volumes in their portfolios, but none is in collateral default. Staff are targeting a July filing to respond.
The adder deductible would be used to reduce collateral calls that create credit uncertainty and potential delay of the market clearing, as they can’t be applied until the auction is in the process of clearing. Cummings noted that 56 undiversified collateral calls were made from June 2016 to March 2018.
PJM is not recommending a deductible but wouldn’t oppose it if stakeholders endorse the idea. Staff hope to have approved revisions implemented by this fall.
FTR Forfeiture
Midgley and Gabel Associates’ Travis Stewart, representing NextEra Energy, presented specific examples of their concerns about FTR forfeitures. The analysis follows disputes with the Monitor at last month’s meeting about whether current rules were having the intended effect of discouraging illegitimate activity or unreasonably harming market participants who are trying to make appropriate business decisions. (See “FTR Forfeitures,” PJM Market Implementation Committee Briefs: May 2, 2018.)
“I would like to be able to use virtual transactions in the marketplace and at the same time use FTRs to hedge congestion risk,” Midgley said. “The rule is doing more than it intended to do.”
She provided an example of one hour in which Exelon was required to forfeit $47,000 in FTR revenue because a 200-MW virtual trade exceeded the testing thresholds for forfeiture on 18 FTR paths.
The forfeiture happened at 7 p.m. on Sept. 21, 2017. Six days later, NextEra experienced a similar issue with an 800-MW virtual trade at PJM’s West Hub that created $2,078 in forfeitures. Stewart said that similar incidents across the month accumulated to a total forfeiture for NextEra comparable to Exelon’s $47,000.
“There’s a lesson there, and it’s not that we need to reduce the effectiveness of the rule. It’s meant to change behavior,” Bowring said. “The only impact of the rule is to take away your profits on an hourly basis. The point of the rule is not to be punitive.”
Midgley argued that it also devalues FTRs subject to forfeitures and potentially requires load-serving entities to put risk premiums in customer rates, but Bowring said the fact that the forfeitures might cause Exelon or NextEra to devalue FTRs doesn’t mean other market participants will.
“You suggested that load will be worse off from this, but you haven’t demonstrated that, and I don’t think it’s true,” he said.
PJM’s Brian Chmielewski discussed the results of additional sensitivity analyses on the current forfeiture trigger from greater than or equal to 1 cent, to greater or equal to net 10% distribution factor. He found that forfeiture dollars would have been reduced by approximately 97% in September 2017 and 18 market participants would have received forfeitures instead of the 67 who did.
He concluded that the majority of constraints were “far away” from impacted FTRs, but Haas said that doesn’t mean anything unless there’s a “material impact.” PJM is performing additional analysis on market-to-market flowgate virtual testing that it plans to present at next month’s meeting.
“We are seeing a reduction in activity that is consistent with FTR forfeiture. That is a good thing,” Haas said.
More than a week after President Trump directed Energy Secretary Rick Perry to prevent additional coal and nuclear plant retirements, the administration has provided no additional details on how it plans to implement the bailouts or how much they will cost.
With no answers coming from D.C., analysts and others have been left to speculate on the bailout’s potential impact. Here’s five important questions and possible answers.
Can the Trump/Perry Plan Survive Legal Challenges?
Trump’s directive came after the leak of a 40-page draft Department of Energy memorandum that said coal and nuclear plant retirements are a threat to national security, in part because natural gas pipelines could be subject to terrorist attacks. It called for keeping at-risk plants alive through capacity and energy payments for at least two years while the department studies the risks and then creates a “Strategic Electric Generation Reserve.”
The memo cited the Defense Production Act of 1950 (DPA) — enacted to aid the nation’s civil defenses and war mobilization at the beginning of the Korean War — and Section 202c of the Federal Power Act, which allows the energy secretary to issue emergency orders during energy shortages.
The DOE memo said the retirements threaten the electric supplies for the nation’s military bases, citing a 2008 Defense Science Board report that noted virtually all of the electricity supplying the nation’s more than 500 military installations is generated outside the facilities. “Backup power at military installations is based on assumptions of a more resilient grid than exists and much shorter outages than may occur and is not sized to accommodate new homeland defense missions,” the report said.
At the time, the bases’ backup power was almost entirely diesel generators. Since then, the Defense Department has begun investing in microgrids and solar generation to allow their critical operations to continue operating during grid outages.
Preview?
Attorneys general from nine states and D.C. offered a preview of legal arguments against the DOE plan in challenging FirstEnergy Solutions’ March 29 request to invoke 202c to prevent retirements of its coal and nuclear generation in PJM.
In a May 9 letter to Perry, attorneys general for Massachusetts, Connecticut, Illinois, Maryland, North Carolina, Oregon, Rhode Island, Virginia, Washington state and D.C. said 202c was never intended to rescue “inefficient generators.”
“Section 202c explicitly authorizes the secretary to issue temporary orders only in wartime or other ‘emergency’ situations resulting from ‘sudden’ electricity demand spikes or supply shortages,” they wrote. “Though the Federal Power Act does not define the terms ‘emergency’ or ‘sudden,’ the plain meaning of these terms indicates that Congress intended Section 202c authority to be invoked rarely, in response to acute events that demand immediate response.”
DOE says it has deployed Section 202c on eight occasions, all in response to regional energy challenges. It has not previously been applied nationwide.
The department’s memo contends that “Congress contemplated the use of the provision not merely to react to actual disasters, but to act in a preventive manner. A variety of man-made and natural threat conditions require … a federal agency ready to do all that can be done in order to prevent a breakdown in electric supply.”
The AGs cited statements by FERC and PJM that potential plant closures do not pose an emergency. They also rejected a National Energy Technology Laboratory study cited by FirstEnergy that concluded PJM’s demand during the December 2017-January 2018 cold snap “could not have been met without coal.”
The study “mistakenly concludes that coal-fired generation was critical to reliability because coal-fired generation disproportionately increased during the cold snap,” the AGs said. The extreme cold caused a spike in natural gas prices, briefly making coal generators more competitive.
“That certain resources were dispatched is not evidence the system lacked (or will lack during future events) other resources that could have been called upon instead to meet market demand and maintain reliability,” the AGs said. “PJM has more than enough capacity to meet demand, even in extreme weather.”
FAST Act
In addition to the DPA and FPA, the memo cites a third law as apparent authority, the 2015 Fixing America’s Surface Transportation Act (FAST) Act, which amends the FPA to authorize DOE to order emergency measures to protect “defense critical electric infrastructure” following a presidential declaration of an imminent grid security emergency.
“Citing these three laws implicitly concedes that there is no single law that provides DOE with the authority to do what it wants to do,” Ari Peskoe, director of the Electricity Initiative at Harvard Law School’s Environmental & Energy Law Program, said in a podcast last week. “DOE’s argument is that the whole is greater than the sum of its parts.”
Peskoe said there are three paths opponents could take to attempt to block the bailouts, including a federal court suit to overturn the eventual DOE order and FERC complaints challenging individual wholesale contracts compensating the at-risk plants as not just and reasonable. “And separately you could also have more action at FERC arguing that these contracts are disrupting the larger market,” he added.
Prior 202c Invocations
DOE’s most recent invocations of 202c were limited to single generating plants and local reliability problems.
In December 2005, DOE granted the D.C. Public Service Commission’s request to order Mirant Corp. to continue running its Potomac River Generating Station despite its inability to meet EPA’s National Ambient Air Quality Standards, finding that the region otherwise faced a “reasonable possibility” of extended blackouts.
DOE noted that much of the district, including the FBI, State Department and other federal government agencies, were supplied only by the Mirant plant and two 230-kV lines connected to other generation. The loss of those sources also would threaten the city’s water treatment center, which would be forced to release untreated sewage into the Potomac River if it lost power for more than a day, the department said.
The order required Mirant to keep the plant operating at a low level that allowed a quick start-up if either of the lines were lost. “Mirant and its customers should agree to mutually satisfactory terms for any costs incurred by Mirant under this order,” the department said. “lf no agreement can be reached, just and reasonable terms shall be established by a supplemental order.”
Originally set to expire in 10 months, the order was twice extended for two months and once for five months. It was terminated on July 1, 2007, after the completion of new transmission.
Most recently, DOE in June 2016 granted PJM’s request to order Dominion Energy Virginia to continue running its coal-fired Yorktown Power Station for 90 days despite its violation of EPA’s Mercury and Air Toxics Standards. The department found that reliability in the Hampton Roads area of Virginia could otherwise be at risk during summer peaks.
PJM said it needed to keep the plant available because of delays in construction of the 500-kV Skiffes Creek transmission project, the subject of court fights because of the proximity of its James River crossing near historic sites.
DOE extended the 90-day order four times thereafter, most recently on June 8, 2018. That order expires on Sept. 9. PJM’s most recent extension request estimated the transmission project will be complete in August 2019 and that Yorktown will not be dispatched after May 2019.
What’s FERC’s Role?
The five FERC commissioners are due to testify Tuesday before the Senate Energy and Natural Resources Committee in a previously scheduled oversight hearing. But it is unclear how much they will say about the proposed bailouts.
FERC was given no advance notice of the Trump directive and had received no additional information on it as of last Tuesday, when Chairman Kevin McIntyre met with reporters after speaking at the Energy Information Administration’s Energy Conference. (See related story, FERC Blindsided by Half-Baked Trump Order.)
The draft memo had been prepared in advance of a June 1 meeting of the National Security Council, and DOE’s plan will be reviewed by the NSC’s Policy Coordinating Committees. FERC is not a principal in the process.
Tezak | ClearView Energy Partners
Although FERC has been excluded from policy deliberations thus far, the resilience docket the commission opened in January could play a role in any litigation, Christine Tezak of ClearView Energy Partners said in an analysis for clients Friday (AD18-7). FERC opened the docket after rejecting DOE’s Notice of Proposed Rulemaking calling for price supports for coal and nuclear plants with on-site fuel. (See FERC Rejects DOE Rule, Opens RTO ‘Resilience’ Inquiry.)
Evidence that FERC, RTOs and states are moving aggressively on resilience could undercut DOE’s legal standing, Tezak said. “We would expect the opponents of action … to reference the contents of this proceeding before FERC as evidence that the DOE’s conclusions regarding resiliency are misplaced or in error.”
If DOE’s order survives legal challenges, the FERC proceeding could provide a path forward after the two-year study, Tezak said. “We think there is the potential for the FERC’s resilience docket to provide information that could lead to DOE winding down if not ending altogether its potential market intervention.”
In addition, FERC will hear testimony at its annual technical conference on reliability July 31 to consider whether new NERC standards are needed to ensure “essential reliability services” (AD18-11). NERC has identified those services as including frequency and voltage support, ramping capability, operating reserves and reactive power. (See NERC Report Urges Preserving Coal, Nuke ‘Attributes’.)
Chatterjee, Glick Call for Mandatory PL Standards
In a perhaps unlikely pairing, Commissioners Neil Chatterjee, a coal-state Republican, and Richard Glick, a carbon-conscious Democrat, joined Monday in an apparent effort to reassert FERC’s role in the debate. In a joint op-ed, they called for mandatory reliability standards for natural gas pipelines like those FERC and NERC enforce on the grid.
They noted that the Transportation Security Administration, which has responsibility for securing natural gas, oil and hazardous liquid pipelines, relies on voluntary cybersecurity standards. “In May 2017, TSA confirmed that it had just six full-time employees” overseeing pipeline security, they wrote.
“Given the high stakes, Congress should vest responsibility for pipeline security with an agency that fully comprehends the energy sector and has sufficient resources to address this growing threat,” they continued. “The Department of Energy could be an appropriate choice: It is the sector-specific agency for energy security and recently created its own cybersecurity office.”
How Will it Affect Emissions?
Because the bailout would cover both coal and nuclear plants, there is disagreement on how it would affect carbon emissions.
As of March, according to EIA, 21.2 GW of coal generation and 6.2 GW of nuclear capacity were scheduled to retire through 2027. EIA’s list does not include FirstEnergy’s announcement in late March that it will close its Davis-Besse, Perry and Beaver Valley nuclear plants, which total about 3.9 GW, by 2021.
About 21.2 GW of coal generation and 10.1 GW of nuclear capacity are at risk of retirement through 2027 | FirstEnergy Solutions, Energy Information Administration Electric Power Monthly, March 2018
Bloomberg New Energy Finance said in a report last week that emissions might be lower than the status quo if at-risk nuclear plants are kept running. It said that although capacity payments would keep coal plants available for backup, they may not actually run more under the Trump plan. Thus, the nuclear plants “could displace millions of tons of carbon dioxide a year” from coal plants, analyst Will Nelson said.
While nuclear plants have capacity factors of more than 90%, many at-risk coal plants operate less than 50% of the time.
But Varun Sivaram, fellow for science and technology at the Council on Foreign Relations, told Axios last week that freezing coal and nuclear generation at their 2017 levels — preventing them from the drops forecast by EIA — would mean coal-fired production would be 24% more than the additional nuclear generation in 2025. That would translate to between 0 and 5% higher emissions in 2025 relative to 2017, depending on the relative displacement of gas and renewables, he said.
“We don’t know if it will be a week, two weeks or months” before DOE acts, said one RTO official.
Craig Glazer, PJM’s vice president of federal government policy, told the EIA conference last week that Trump’s directive will “probably complicate” his RTO’s struggle to deal with state nuclear subsidies. He said he fears a “half slave/half free” industry in which generators dependent on market revenues increasingly compete with those receiving cost-of-service payments or subsidies.
While RTO officials may not lead the legal challenges, their insistence that there is no emergency won’t help DOE’s defense. They point out that they have been successful in keeping plants running temporarily beyond their retirement dates when needed to prevent reliability problems. ISO-NE, for example, has asked FERC to waive its Tariff to keep Exelon’s Mystic generating station running to address fuel security concerns. (See Mystic Waiver Request Spurs Strong Opposition.)
Prest | Resources for the FuturePalmer | Resources for the Future
Brian C. Prest and Karen L. Palmer, fellows with nonpartisan think tank Resources for the Future, wrote last week about the questions raised by DOE’s proposed Strategic Electric Generation Reserve. Among them: the size of the reserve, how generators would be procured and whether those selected be permitted to participate in or return to the energy markets.
Although the DOE memo provided no details, the fellows looked to the strategic reserve Germany is considering as it continues its phase out of nuclear power. The country has retired more than half of its nuclear generation since 2008 while more than tripling its non-hydro renewable capacity. It now gets half its capacity from non-hydro renewables versus 27% coal and nuclear and 14% gas.
Germany’s reserve will be initially capped at 2 GW, about 2% of peak load, rising to as much as 5 GW (5%) after 2020. The reserve capacity will be procured through technology-neutral competitive auctions and open to demand response. The capacity would be used only as a last resort.
“It is not clear from the scant description in the memo how the SEGR would be procured, but the heavy-handed approach for the electricity purchase mandates suggests that competitive auctions are probably not under consideration,” they wrote. “It seems more likely that plants would be chosen in the same way that they would be chosen for the electricity purchase mandates — based on a federally determined list of ‘fuel-secure’ generators (best interpreted as coal and nuclear plants).”
They note that Germany plans to address concerns the reserve will discourage new capacity investment by prohibiting reserve generators from re-entering the market. “Unfortunately, DOE’s proposed order is specifically designed to send the message that government policy will find a way for unprofitable plants to return to the market, even calling its own order a ‘stop-gap measure.’”
How Much Will it Cost?
Because so many details about the administration’s plan are unknown, no one has produced an analysis of how much it will cost — including DOE itself. (See related story, Dems Hit Coal, Nuke Bailout at House Hearing.)
But some analysts produced estimates on the DOE NOPR rejected by FERC. It would have given cost-of-service payments to coal and nuclear plants in RTOs with capacity markets if they have 90 days of fuel on site.
ICF estimated the NOPR would cost ratepayers $1 billion to $4 billion per year between 2018 and 2030. The estimate was based on contracts for differences bringing money-losing generators to break even.
ICF caveated that the analysis might have underestimated the cost because it did not include recovery of and on capital. But it said the analysis also didn’t account for the likelihood that wholesale electricity and natural gas prices will be lower than they would have been had the plants retired.
Orvis | Energy Innovation Policy & Technology
Energy Innovation Policy & Technology, which supports policies reducing greenhouse gas emissions, said the NOPR would have cost from $311 million to $900 million annually in PJM, ISO-NE, NYISO and MISO alone. The low estimate represents the out-of-market payments needed to bring units with negative net cash flows up to zero. The upper limit adds capital recovery and a rate of return on undepreciated capital and future capital expenditures.
“There are, of course, important differences between the resilience NOPR and the 202c actions being discussed by the Trump administration, but our study is a good rough estimate of the cost to keep the same group of uneconomic plants online,” said Robbie Orvis, director of energy policy design for the group.
BOSTON — Competition among states to set the highest offshore wind energy targets and to secure supply chain jobs is gradually giving way to a regional cooperation, the head of the Bureau of Ocean Energy Management said last week.
“In our view, all of the federal leases, they don’t belong to any particular state, and we need to be thinking about how to manage those assets on a regional community basis,” acting BOEM Director Walter Cruickshank said at New Energy Update’s U.S. Offshore Wind Conference, held June 7-8.
“And we’re certainly seeing that already,” Cruickshank added. “We’ve seen projects that were leased off of one state getting agreements with neighboring states.”
He cited the collaborative development efforts of Massachusetts and Rhode Island, of “Virginia and the Carolinas, and obviously in the New York Bight, where there are a lot of states that have stakeholder interest.”
In May, Vineyard Wind, a partnership between Avangrid Renewables and Copenhagen Infrastructure Partners, won a contract to supply Massachusetts with 800 MW of offshore wind energy. In the same solicitation, Rhode Island picked Deepwater Wind to build a 400-MW version of its Revolution Wind proposal. (See Mass., R.I. Pick 1,200 MW in Offshore Wind Bids.)
Picking up the Pace
Panelists at the conference also discussed ways to reduce costs and speed up permitting.
The Department of Energy’s 2015 Wind Vision report set a goal of deploying 86 GW of offshore wind by 2050. The U.S. would need to use about 4.2% of the total technical resource area to reach the goal, according to the National Renewable Energy Laboratory’s September 2016 Offshore Wind Energy Resource Assessment. The technical resource area includes areas of the Great Lakes and the Atlantic and Pacific coasts with wind speeds of at least 7 meters/second and water depths of less than 60 meters (Great Lakes) or 1,000 meters (the oceans).
The 11 BOEM leases issued so far could produce 20 GW by 2030 “based on the physical capacity of these leases,” said Tom Harries of Bloomberg New Energy Finance. The typical timeline from lease to operation is five to seven years.
Stephen Bull, senior vice president at Norway-based Equinor (formerly Statoil), said he’d like “to see BOEM interact more at the state level, to really try to fast-track or work quicker to get wind energy areas out there.” Conference chair Stephen Pike, CEO of the Massachusetts Clean Energy Center, a state agency in charge of offshore wind development, asked about having BOEM pre-permit the leases to speed up development, as is done in Europe.
“That’s not the way the federal government works,” said Cruickshank, explaining that the bureau has no funding for capital-intensive marine surveys.
Floating Turbines
Although BOEM’s leases to date have been off the Atlantic Coast, BOEM is also looking to the Pacific, which will require floating wind technology because of the much greater water depths, Cruickshank said.
“We’re cautiously optimistic we’ll be able to move ahead with some of those leases later this year.”
Daniel Simmons, principal deputy assistant secretary for DOE’s Office of Energy Efficiency and Renewable Energy, said improving floating platforms “is an important area for us just because so much of our wind resources offshore is in deep water.”
Walter Musial, manager of offshore wind at the National Renewable Energy Laboratory, who explored the levelized cost of energy for floating turbines, said about 58% of potential offshore wind areas are deeper than 60 meters.
“Floating obviously starts out a bit more expensive, but it’s a maturity thing, so fixed and floating turbine costs converge over time,” Musial said. “Actual costs are confidential — they don’t report them in the newspaper.”
Manufacturers need to see the market demand in order to develop optimized turbine systems for floating platforms, he said. “Up till now, every single deployment has been with a turbine that was actually designed for a fixed bottom system, so we’re sub-optimum,” he said.
But the industry is now moving beyond the floating prototype phase. “I’ve counted about 11 projects totaling 229 MW,” Musial said. “These are going in with some subsidies, but also with regular financing, and they’re going in all over the world.”
NREL wind analyst Garrett Barter agreed, saying the current design paradigm of offshore turbines “won’t give you a cost-competitive floating system.”
Engineering and design are just a fraction of the total cost for a floating wind turbine. Most of the costs are the operational expenses, logistics, assembly and installation, and financing, he said.
“So you really need a systems approach that can tackle all these complexities at the same time, and not just focus on the turbine itself,” Barter said. He recommended multidisciplinary analysis and optimization, which is “a tool and also a state of mind where you connect the whole power production process, the whole load path, the controls that sit in between those two, and the whole balance sheet over the lifecycle of the plant.”
He said the offshore industry may have to evolve into a structure like that of the aerospace industry, where a global supply chain serves a system owned by the prime contractor.
Driving Down Costs
Experts say it will take several years for the U.S. market to mature before it matches the separate cost curves for the established European market
“We think the transition happens around 3 to 4 GW of installed capacity, which should be in 2028 in the U.S., and the industry will move onto the established cost curve and really see price reductions,” Harries said. “The regulatory route gets simplified, and then gradually you build your experience and you move down this cost curve. Supply chains gain experience, and routes to market become very clear.”
Jonathan Cole, managing director of offshore for Avangrid parent Iberdrola’s renewable business, wants to see nearly that much capacity entering the pipeline each year.
“As soon as possible, get to a place where this market is being fed with 2 to 3 GW of new projects every year, which means you’ve got enough volume to support a local supply chain,” Cole said. “That’s when you’ll truly see cost reductions and the industrialization happening.”
Cole said that so far, they’ve been able to lower development costs through tax credits, which are now being phased out.
“We’re hoping that the downside of removing the tax credits is going to be more than compensated by the positive … making a more efficient and optimized installation,” he said.
Vineyard Wind CEO Lars Thaaning Pedersen said tax credits are an important part of the price structure in Massachusetts, but “the benefits … these projects will bring to the southeast coast” of New England may be more important, such as avoiding the high cost of building transmission lines to bring hydropower from Canada.
The state “has taken a bold step already … and I’m confident that Massachusetts will be at the center of the industry,” Pedersen said.
Francis Slingsby, head of strategic partnerships at Orsted, congratulated Pedersen. Despite not winning the first round of the Massachusetts-Rhode Island solicitation, Slingsby said Orsted is committed to developing its Massachusetts lease areas, “which in our estimation are superb.”
Massachusetts Energy Secretary Matthew Beaton referred to the previous day’s tour of the New Bedford Marine Commerce Terminal, which was built for the deployment of offshore wind, as evidence of the state’s chance to lead the industry.
“To see international companies come in with Massachusetts companies made me realize … this thing’s for real, this thing’s happening, and we have all the pieces that we need,” Beaton said. “Eight hundred megawatts is just the starting point.”
John B. Lavelle, head of offshore wind for GE Renewable Energy, said volume will be the biggest driver of cost reductions. Lavelle said GE will “compete in the U.S. with our 12-MW platform that we just announced.”
Operating costs will come down partially through “a lot of automation,” Lavelle said. “You don’t want to send people 15 miles off the coast if you don’t have to.”
NY, NJ, Md. Moving Forward
Elisabeth Treseder, senior regulatory adviser for Orsted, said New Jersey’s commitment in May to build 3,500 MW of offshore wind by 2030 — surpassing New York’s target of 2,400 MW — “provides a lot of certainty and reassurance” to the market. (See Gov. Signs NJ Nuke Subsidy, Renewables Bills.)
“We’re still waiting for the New Jersey Board of Public Utilities to finish its plan, which for us means focusing on the local supply chain and workforce development,” Treseder said. “New Jersey was very wise in passing a $100 million tax break for offshore wind manufacturing, which left them an additional pool [of incentives] for suppliers.”
Kenneth J. Sheehan, director of economic development and emerging technologies at the BPU, said the state is working to develop its master plan and its first solicitation.
“We are looking for suppliers, transmission, for all the factors that go into it, and the OREC [offshore wind renewable energy credit], the single price, up-front method of funding, takes all this into consideration,” Sheehan said.
Jim Lanard, CEO of Magellan Wind, asked Sheehan what his state’s position is regarding wind energy areas that could serve both New York and New Jersey.
“Half the New York Bight is in New Jersey, so we’re not practically upset about additional project development off our shore,” Sheehan said, referring to the Atlantic Coast region between Cape May, N.J., and Montauk Point on Long Island. “At the start, it’s every state for itself. … Everything could be supplied from New Jersey. And New York thinks the same of itself.”
Kevin Knobloch, president of transmission developer Anbaric’s New York Ocean Grid, said that particularly with New Jersey’s goal of 3,500 MW, there’s a sense of great urgency to get the first turbines in the water.
“We believe the wise approach is from the very first solicitations to separate generation from transmission, and open it up to competition,” Knobloch said. “In so doing, the state decision-makers still reserve the right to go with an offer that’s bidding on both attributes.”
Doreen Harris, director of large-scale renewables at the New York State Energy Research and Development Authority, said the agency is also identifying new wind energy areas off New York City. There is a proceeding before state regulators now “to make the first utility-scale procurement later this year,” she said.
Christer Geijerstam, director of the Empire Wind project for Equinor, which bought the first New York lease in 2016, said that aside from preparing for a state bid, the company is “focused on project technical issues to reduce asset risks” prior to the hoped-for start of construction.
John Hartnett, business opportunity manager of U.S. offshore wind for Shell Wind Energy, said his company “had really jumped into the U.S. markets driven by the evidence of the northeast. Right now, we are investigating the upcoming lease opportunities, both in Massachusetts and New York, and are very hopeful to have site control in time to participate in the upcoming auctions.”
The Maryland Public Service Commission approved two offshore wind projects totaling 368 MW in May 2017, allowing the developers to receive ORECs. The projects are estimated to create 9,700 full time equivalent jobs and result in more than $2 billion of economic activity in Maryland, including $120 million of investments in port infrastructure and steel fabrication facilities.
Samuel Beirne, wind energy program manager for the Maryland Energy Administration, said that “most offshore wind developers have to contract through the state Public Service Commission [to obtain ORECs] … and most use a third-party consultant to help them.”
Aileen Kenney, senior vice president of development for Deepwater Wind, said the company’s 120-MW Skipjack project off Maryland will start construction in 2021 and go online the following year.
“Right now we’re mapping all the seafloor, doing bathymetry analysis,” Kenney said.
Production Tax Credit
According to DOE, the federal renewable electricity production tax credit is an inflation-adjusted 1.9 cent/kWh tax credit for wind for the 2017 calendar year. The credit lasts 10 years after the date the facility is placed in service.
The tax credit is phased down for wind facilities as a percentage reduction: for wind facilities beginning construction in 2017, the PTC amount is reduced by 20%; for 2018, 40%; and for 2019, 60%.
FERC last week approved SPP’s May 2016 proposal to change how it measures the net benefits of demand response under Order 745 (ER12-1179).
Inside SPP’s control room | SPP
The 2011 order requires grid operators to pay DR resources full LMPs when they are able to reduce demand and their dispatch is more cost-effective than generation, as determined by a net benefits test.
SPP’s footprint | SPP
SPP’s May 2016 compliance filing came in response to an April 2014 FERC order requiring the RTO to re-evaluate its net benefits test methodology using Integrated Marketplace data. The commission also asked SPP to propose any necessary changes to make its methodology compliant with Order 745 and to re-evaluate the appropriateness of its systemwide DR cost allocation mechanism.
The RTO proposed adjusting its net benefits test to use all available offer data and include non-peak hour data in the construction of supply curves. It said it would first average supply curves and then smooth the resulting average curve when performing the net benefits test.
“We agree with SPP that these two design changes to SPP’s net benefits test methodology are appropriate given the greater availability of offer data in the Integrated Marketplace,” the commission said. It ordered SPP to file Tariff revisions by July 5 implementing the two changes.
FERC also accepted SPP’s explanation that it did not need to adjust its DR cost allocation provisions, given there had not been any load-reduction activity in its footprint.
PORTLAND, Ore. — Two months after making a smooth integration into the Western Energy Imbalance Market, Canada-based Powerex now finds itself navigating a turbulent relationship with market rules the company says undercut the value of its hydroelectric resources, company officials said last week.
At issue for Powerex is the frequency with which transmission constraints at the U.S.-Canada border trigger CAISO’s local market power mitigation (LMPM) process in the EIM, which mandates use of default energy bids (DEBs) to settle transactions. Inflexibility in the formulas underpinning the DEBs often leave Powerex market operations out of the money, the company says.
“The LMPM processes and the DEB options are not workable for Powerex or for external hydro more generally,” Powerex Director of Power Jeff Spires said during a presentation at a June 6 meeting of the EIM Regional Issues Forum meeting at Bonneville Power Administration offices.
Powerex, which markets surplus power for the government-owned BC Hydro utility, began transacting in the EIM on April 4. As part of its membership, Powerex has volunteered about 300 MW of its transfer capacity into the market, half of which links British Columbia with the Puget Sound Energy balancing authority area (BAA) near Seattle. The other half allows transfers into CAISO via the Malin delivery point on the California-Oregon Intertie.
“We participate with large-scale hydro that’s very fast-ramping,” Mike Goodenough, Powerex trading manager, told the forum. “Often times we’re in a ‘buy’ mode, and particularly when the market is in oversupply, we’re buying, and the transmission can become constrained because we ramp so fast during the market power mitigation market run [that] the ties fill. And at that point, there’s a constraint and market power [mitigation] kicks in. The default bids then kick in and override all of our bids and offers.”
DEB Options ‘Formulaic’
The problem in those instances, Goodenough said, is that the EIM’s DEB options are “more or less formulaic” and “often very wrong” with respect to Powerex’s opportunity costs during a trading interval.
The result is “very frequent mitigation” that forces Powerex to sell below its opportunity costs when it intends to be purchasing in the market to take advantage of arbitrage, Goodenough said.
During these periods, Powerex’s traders seek to raise their sell offers upward to avoid sales but are prevented from doing so when mitigation kicks in, defaulting the market to rely on DEBs.
“And because the default bids are wrong, where we would be a buyer, we are now in the dispatch run as a seller,” he said. “And so, there’s obviously two problems there. One is, we’re now selling into a market in which there might already be in oversupply. But more importantly for us, we’re now depleting energy-limited resources at the wrong time.”
In an April 30 presentation to a CAISO workshop on broader DEB issues, Powerex described the shortcomings of each default bid option available to EIM market participants heavily reliant on hydro assets:
The “variable cost” option, based on heat rates, fuel price and greenhouse gas costs, is “not relevant” for hydro resources that are more driven by opportunity costs than variable production costs.
The “backward-looking” LMP option — based on the on the lowest 25th percentile of LMPs at which a resource has been dispatched during the previous 90 days — is “not workable” for hydro resources whose opportunity costs “are driven by current and expected future conditions.”
The “negotiated rate” option, in which a formula is negotiated between a resource’s scheduling coordinator and CAISO and its Department of Market Monitoring, is “theoretically workable” for all resources but “not workable in practice” for hydro resources outside the CAISO BAA. This option requires the ability to determine a methodology to estimate expected marginal costs, “which are complex, dynamic, and involve both objective and subjective factors,” Powerex said.
“You can’t precisely estimate costs for hydro,” Spires told the forum. “External [to the CAISO BAA] hydro in particular has multiple bilateral opportunities. We have a myriad of constraints within the BC network,” including seasonal monthly, weekly and daily storage requirements, as well as recreational constraints.
“There’s so many different things and they can change at the drop of a hat and you need to be able to respond to that, and so we really support flexibility in determining what your marginal opportunity costs are,” Spires said. He said the flexibility is required to avoid “forced sales.”
Spires said that the EIM’s LMPM process functions as if the supplier conduct threshold for triggering mitigation is zero, meaning that “as soon as your bid or offer price is even a penny above the reference price, then you’re subject to potential mitigation if the transmission is constrained.”
“It goes beyond the commercial impact — it’s an operation impact as well,” Spires said. “And it’s a loss of control of being able to decide what to do with your resources in light of the information that you have at the time.”
Unlike other EIM members, Powerex functions only as a marketing operation and not as a balancing authority or load-serving entity, which means it has no ratepayers exposed to EIM prices.
Thus, the company says its import transfer path into British Columbia is used primarily for “economic displacement” (importing low-priced power to displace use of internal generation) and doesn’t serve any retail customers. In its April 30 presentation, the company questioned whether it was appropriate to apply LMPM to transfer paths where “there is no potential for market power.”
Spires said the situation is discouraging Powerex’s participation in the EIM.
“It’s frankly less attractive than the existing real-time market — the intertie bidding framework where we don’t face these issues, [and] particularly for us, because we have transmission access to the CAISO and so we’ve got the opportunity to deliver a clean supply into that market,” he said. “And so the EIM is a step backwards from that perspective.”
Spires concluded his presentation by expressing appreciation for CAISO’s support in transitioning Powerex into the EIM, but he also urged the ISO to address the company’s dilemma soon.
“We think that it is important to others, and we’re looking forward to working on these issues, but we need a resolution quickly.”
Interim Solution?
In April, CAISO asked FERC to approve a Tariff waiver to alleviate the impact of LMPM on Powerex’s operations by reducing the number of intervals for which mitigation applies after being triggered (ER13-1889).
“The interim solution consists of an automated process by which Powerex’s EIM transfers will be restricted only during intervals in which this condition [producing forced sales] occurs, as well as limiting mitigation of Powerex’s aggregated participating resource to the market interval in which the mitigation of that resource is triggered,” CAISO said in its filing.
The ISO said the interim solution “will apply solely to Powerex’s aggregated participating resource operating under the unique Canadian EIM entity arrangements.”
But while the potential Tariff waiver would partially alleviate the LMPM issue for Powerex, the company has noted it would not address the company’s underlying concerns about the DEB calculation options or the fact that its sales prices would be mitigated to uneconomic levels when LMPM is triggered.
During the April 30 workshop, CAISO Vice President for Market Quality and Renewable Integration Mark Rothleder acknowledged “there is a gap” between what some stakeholders “feel their ultimate opportunity costs are and what they believe a calculated DEB under the existing mechanisms can achieve.”
“This may be the fundamental issue in terms of continuing the EIM and the success of the EIM, so we have to get this right,” Rothleder said, adding that the ISO must receive comments from stakeholders before kicking off an initiative to address the DEB issue.
While time might be of the essence for Powerex, CAISO told RTO Insider on Monday that “no time frame has been set for this miscellaneous stakeholder process as of this time, although we do plan to have a second workshop in July to further discuss the concerns and some ideas for addressing them.”
SPP said last week it is accepting applications for industry experts to serve on a fourth independent panel to review Order 1000 transmission proposals in 2019.
The RTO forms the pool each year to manage competitive projects. A panel composed of experts from the pool will review, rank and score proposals for competitive projects approved for construction by the Board of Directors.
Interested candidates must have expertise in at least one of the following transmission-related areas:
Engineering design
Project management and construction
Operations
Rate design and analysis
Finance
Applications will be accepted through Aug. 31. Panelists will be selected based on a recommendation by SPP’s Oversight Committee and approved by the board later this year. Those serving on the panel will be considered contractors and will be compensated through a monthly retainer and hourly rate.
More information can be found on SPP’s website. Interested parties may also contact regulatory analyst Aaron Shipley.
For the ninth straight month and 17th of the last 19, SPP amassed market-to-market (M2M) payments in its favor from MISO during April.
| SPP
SPP staff said during its Seams Steering Committee meeting last week that MISO incurred $1.97 million in charges, increasing its total payments to SPP to $53.3 million since the two neighbors began the process in March 2015.
The main cause of charges in April was the Nebraska City temporary flowgate in Omaha Public Power District’s control zone. The constraint was binding for only 30 hours during April but racked up more than $717,000 in charges because of area outages, combined with lower wind generation and high south-to-north flows.
SPP’s Nashua-Hawthorn permanent flowgate in Kansas was binding for 142 hours and accumulated more than $427,000 in M2M charges.
The committee met June 6 at Southwestern Public Service’s offices in Amarillo, Texas.
