RENSSELAER, N.Y. — NYISO’s Management Committee on Wednesday approved Tariff revisions intended to provide external resources with Rest of State (ROS) deliverability rights to improve their ability to participate in the ISO’s capacity market.
The March 28 vote recommended that the ISO’s Board of Directors authorize staff to file the revisions with FERC under Federal Power Act Section 205.
Ethan Avallone, NYISO senior market design specialist, said Hydro-Quebec US (HQUS) proposed the ISO develop a method for awarding capacity resource interconnection service (CRIS) to entities that create increased transfer capability through transmission upgrades over external interfaces. (See “External Deliverability Rights,” NYISO Business Issues Committee Briefs: March 15, 2018.)
| NYSEG
FERC last year granted HQUS eligibility to receive CRIS in proportion to the incremental transfer capability created by its Cedars Rapids Transmission intertie project (ER17-505). National Grid also stands to benefit from the change after it completes upgrades on its 115-kV Dennison-Alcoa line in Zone D in Q4 2019.
2017 CARIS Report Moves to Board
The committee also approved the 2017 Congestion Assessment and Resource Integration Study (CARIS) Phase 1 draft report on the potential costs and benefits of relieving congestion on the transmission system through generic transmission, generation, demand response and energy-efficiency solutions. (See “2017 Congestion Assessment and Resource Integration Study,” NYISO Business Issues Committee Briefs: March 15, 2018.)
Tim Duffy, economic planning manager, said NYISO has identified three main areas of the state where transmission congestion is: Edic-Marcy, Central East and New Scotland-Pleasant Valley.
To provide additional value to stakeholders, Duffy said the ISO developed a system resource shift case, which assumed retirement of the Indian Point nuclear plant by 2020/2021 and all coal units in the state by 2020, and a resource mix consistent with attaining Clean Energy Standard targets by 2026.
Pacific Gas & Electric is requesting proposals for the development of up to 45 MW of “clean energy” resources including at least 10 MW of energy storage, as the centerpiece of its plans to replace the aging Dynegy Oakland jet fuel-fired power plant.
The utility said it will open a two-month request for offers process in spring, inviting “innovative and competitive solutions for the portfolio.” It hopes to bring the new mix of resources online in mid-2022; the procurement total will depend on the exact resource mix, the company said.
A historical photo of the Oakland Power Plant, which went into operation in 1888. The current jet-fueled generators, owned by Dynegy, went into service 40 years ago. | PG&E
The 165-MW Dynegy plant currently operates under a CAISO reliability-must-run contract to meet local reliability needs.
CAISO identified PG&E’s proposal, the Oakland Clean Energy Initiative, as a preferred solution in CAISO’s 2017/18 transmission plan approved by the ISO’s Board of Governors last week. (See CAISO Moves Ahead With Market Changes.)
The plan includes:
transmission line rerates and system upgrades to remove limiting elements;
at least 10 MW of 4-hour utility-owned in-front-of-the-meter storage in the Oakland C and Oakland L 115-kV substation pocket;
competitive procurement of 10 to 24 MW of “preferred resources” — energy efficiency, demand response, renewable generation and storage — in the substation pocket, at least 19.2 MW of which is “load modifying in nature;”
continuing to rely on transferring Alameda Municipal Power load from Cartwright (North) to Jenny (south) during peak load conditions and after an N-1 contingency, in preparation for an N-1-1.
The project marks the first time that clean energy resources would be deployed as an alternative to fossil fuels for transmission reliability in the PG&E area. It will be working with local community choice aggregator East Bay Community Energy to determine the clean energy and reliability solution.
“PG&E and the system operator worked collaboratively over the last several transmission planning cycles to study how distributed clean energy resources could become part of the solution,” the company said in a news release. The utility said it will seek cost recovery for the battery storage facility from FERC and for distributed energy resources from the California Public Utilities Commission. It expects to file with the PUC by the end of the year.
Since 2010, CAISO has increasingly focused on non-transmission alternatives in its planning. The ISO cannot specifically approve non-transmission alternatives part of its annual plan, but it can identify them as preferred solutions, as it did with the PG&E proposal.
CAISO’s transmission plan said the closing of the 40-year-old generator would cause thermal overloads on the Oakland 115-kV system without new local generation. The estimated cost of the PG&E proposal is about $102 million (2022 dollars), while other alternatives, including transmission lines and generation, ranged from $367 million to $574 million.
Forecast load in PG&E Transmission Access Charge Area 2011-2017 | CAISO
The Dynegy plant’s RMR agreement with CAISO was renewed in September 2017, based on local reliability analysis. The ISO said that based on real-time operations data for 2015 and 2016 there is a need for at least 98 MW for a one-in-three heatwave scenario that would cause heavy loads. It also cited instances where all three 55-MW Oakland units were running for local reliability. A 2018 forecast showed a need of 56 MW because of a discrepancy in substation load forecast distribution that the ISO said it would work with PG&E to correct.
AUSTIN, Texas — ERCOT’s Technical Advisory Committee last week approved staff’s recommendation to remove reliability unit commitment (RUC) capacity from the grid operator’s operating reserve demand curve (ORDC), passing a revision request with minimal discussion.
Staff’s other binding document revision request (OBDRR) revises the online and offline capacity reserves for those resources online during a RUC instruction, and meets the Public Utility Commission of Texas’ directive to remove RUC capacity from the ORDC as part of its project assessing the Texas market’s price formation rules (No. 47199). (See “Commission Directs ERCOT to Revise ORDC,” Marquez to Depart Texas PUC.)
The OBDRR, which passed unanimously, will go to a vote of the Board of Directors during its April 10 meeting. Kenan Ogelman, ERCOT vice president of commercial operations, said staff will work “expeditiously” to get the change made by July 1.
“We’ve committed to the PUC that we would implement this as early as possible,” Ogelman said during the TAC’s March 22 meeting.
The ORDC creates a real-time price adder to reflect the value of available reserves and is meant to incentivize resources to produce more energy and reserves. PUC staff recommended removing both RUC and reliability-must-run capacity from the ORDC, saying it would ensure that scarcity pricing is accurate and reflective of market dynamics.
ERCOT staff said it would take two or three months and $30,000 to $40,000 to make the software changes, an increase from the $15,000 to $25,000 estimate ERCOT gave the PUC earlier this month. The affected systems include Market Management Systems, data and information products, and analytic data.
ERCOT’s legal staff said they need a two-month delay to complete changes to the grid operator’s bylaws and articles of incorporation to include additional feedback from stakeholders. Staff was to share with the TAC comments and its recommendations for the board’s April 10 meeting but will now not make a final recommendation until the June board meeting.
Vickie Leady, ERCOT’s assistant general counsel and assistant corporate secretary, said staff have received “extraordinarily helpful” comments from stakeholders on issues such as definitions of affiliates and membership segments. The bylaws were last revised in 2000.
Some of the market’s largest players — American Electric Power, CenterPoint Energy, Exelon, Oncor and Luminant Generation — banded together to provide joint comments.
The delay puts a hold on Southern Cross Transmission’s (SCT) bid to become ERCOT’s first merchant DC tie operator. (See “Members Debate Southern Cross’ Bid to be Merchant DC Tie Operator,” ERCOT Technical Advisory Committee Briefs: Feb. 22, 2018.)
Oncor and Texas Industrial Energy Customers filed comments recommending SCT be placed in the independent power market segment, while SCT reiterated that it should be placed in the investor-owned utility segment. ERCOT continues to believe that those are the two most appropriate segments for SCT.
ERCOT procured 9.17 MW of weather-sensitive emergency response service (ERS) last summer, about half the amount procured in each of the two previous summers, despite the disruptions caused by Hurricane Harvey.
Weather-sensitive ERS was implemented in 2014 to capture the demand response potential of summer residential and commercial air conditioning loads.
Mark Patterson, manager of market operations support, said the decrease resulted because several transmission and distribution service providers recently modified their standard-offer programs to allow more participation from residential loads — reducing the load that bid to serve as weather-sensitive ERS.
Patterson said on Harvey’s worst day, Aug. 29, the hurricane only reduced 20 MW of capacity obligated to provide service from the 2,300 ERS sites in the storm’s area.
The grid operator projected it will have spent $49.4 million procuring ERS during the year, leaving more than $577,000 unspent.
TAC Unanimously Approves Protocol Changes
Members unanimously endorsed a nodal protocol revision request (NPRR868) that modifies the hub bus and load zone definitions and price calculations to account for the current usage of power flow buses — as opposed to electrical buses — in the day-ahead market and congestion revenue rights auction systems.
Staff sponsored the NPRR, noting there can be differences between power flow buses and electrical buses, making it more suitable to use power flow buses.
Electrical buses — physical transmission elements that use breakers and switches to connect loads, lines, transformers, generators and related infrastructure — are defined statically. A power flow bus — a collection of points on the system that are electrically connected and have zero impedance between them — is identified dynamically based on the status of transmission equipment.
However, electrical buses are used for real-time hub and load zone calculations.
The rewritten formulas will clarify the scenario when buses are de-energized in contingency analyses and align the protocols with ERCOT systems. For the day-ahead and CRR calculations, the LMP of the hub bus is the simple average of the LMPs for each energized power flow bus in the hub. If all power flow buses within a hub bus are de-energized, the LMP does not include the de-energized hub bus. If power flow buses are de-energized under a contingency, the disconnected megawatts are redistributed among the remaining energized buses.
Staff designated the NPRR as urgent and said it would be implemented as soon as possible following board approval.
The TAC also unanimously approved three other NPRRs, two system-change requests (SCRs) and a change to the retail market guide (RMGRR):
NPRR858: Requires ERCOT to publish all current operating plans (COPS) data that are submitted by generators, once its confidentiality has expired, a change from the limited subset currently available. The change provides transparency into all intra-hour updates to COPS data, as generators can update them at any time and change aggregate information available to the market.
NPRR864: Modifies the RUC engine to scale down commitment costs of fast-start resources with less than one-hour starts. Following the change, the RUC engine will recommend slow-start resource commitments only if redispatching online resources and market-based self-commitments of fast-start resources will not resolve the reliability issue. With the change in the generation portfolio, market-based commitment decisions could be made much closer to real time than in the past, allowing more self-commitments to materialize in real time than is reflected in COPS many hours earlier.
NPRR865: Requires ERCOT to publish shift factors for hubs, load zones and DC ties for the real-time market, mimicking the day-ahead market’s current practice and providing more information on the inputs used to calculate pricing aggregations.
SCR793: Gives transmission service providers access to the same ERCOT-generated status telemetry as the ISO’s operators in monitoring line outages with calculated subsynchronous resonance condition monitoring points.
SCR795: Updates the resource limit calculator’s formula for calculating dispatched generation by including the addition of a predicted five-minute wind ramp (PWRR). The PWRR will be calculated from the intra-hour wind forecast and a configurable factor to capture the forecasted five-minute wind ramp, relieving regulation service’s burden to cover the five-minute gain or loss of generation from variations in wind, and instead dispatch this energy economically.
RMGRRR0150: Clarifies the content and format of the competitive retailer safety net spreadsheet within the market guide and removes Section 9, Appendix A1: Competitive Retailer Safety Net Request, which eliminates conflicts between the appendix and language found in Sections 7.4 (Safety Nets) and 7.10 (Emergency Operating Procedures for Extended Unplanned System Outages).
PJM is at odds with some stakeholders over whether existing units should be under the same obligation to provide primary frequency response (PFR) that FERC ordered for new units in February.
Sides clashed at last week’s meeting of the Primary Frequency Response Senior Task Force (PFRSTF) over what Order 842 actually requires.
Though it has evolved since Order 842 came out in February, the debate has been raging in PJM since the commission issued a Notice of Proposed Rulemaking on the topic in November 2016. Staff want to require PFR from all units capable of providing it, but some stakeholders believe PJM is overreaching. (See FERC Finalizes Frequency Response Requirement.)
PJM argues it doesn’t preclude being applied to existing units, while generation owners say it doesn’t explicitly order it either. Stakeholders questioned the RTO’s confidence in its stance, given that staff have filed a request with FERC to clarify the order. Jim Burlew, a PJM attorney, said staff is confident but made the request “out of an abundance of caution.” He said the RTO’s position is that FERC felt the issue was addressed by ordering new units to provide PFR because it assumed current units are already providing it.
Staff attempted to counteract an argument that PJM would be shouldering others’ frequency response responsibilities by showing how other balancing authorities are handling FERC’s order. However, the presentation seemed only to strengthen some stakeholders’ belief that it’s unnecessary for existing units to have the capability.
PJM’s presentation showed that surrounding BAs maintain some PFR requirement for existing units, but stakeholders argued those procedures were more collaborative than the RTO’s plan, which includes referrals to FERC’s Office of Enforcement for units that don’t measure up.
“They’re not looking at a FERC hammer” in the other BAs, GT Power Group’s Dave Pratzon said.
AEP Energy, a subsidiary of American Electric Power, presented a proposal that would maintain the status quo for existing units to provide PFR if they are capable. It would also allow for seeking cost-of-service revenues from FERC for providing the service. A PFR performance evaluation like one that PJM has proposed would go into effect in 2021, and there would be a recommendation that transmission owners and the RTO study localized restoration-related issues.
Jim Fletcher with American Municipal Power pointed out that several of the other BAs are regulated utilities that can unilaterally implement changes — unlike PJM, where individual unit owners will need to make economic decisions.
“They seem to have an advantage about how they optimize frequency response,” he said. “I think it’s important that we continue to keep some form of compensation in the mix here as we talk about [implementation].”
Howard Haas with the Independent Market Monitor noted that regulated utilities have a different cost-recovery model than ISO/RTO markets. Regulated utilities have cost-of-service arrangements subject to regulators’ approval or rejection while PJM’s approach uses markets, where recovery is possible but not guaranteed, he said. The Monitor’s position is that units are already compensated to have and provide PFR through PJM markets and that the cost of new entry (CONE) unit includes the costs of having the capability because the service is a requirement of new units.
“PJM’s markets provide opportunities to recover these costs; and if you don’t, you have to make a business decision about whether or not to exit,” Haas said.
A stakeholder who asked not to be identified asked whether PJM was implying that units that can’t provide PFR should retire.
“That’s the IMM’s position. I don’t think PJM has ever said that,” PJM’s Dave Souder said.
However, Haas noted after the meeting that PJM’s proposal for exemptions from offering PFR specifically states that “economics cannot be used as exemption criteria.”
Pratzon called it “a bit of a stretch … to lay a sidebar obligation” of PFR on a resource that was designed and built for “the primary value” of producing energy, but Haas argued that if it’s a rational decision within PJM’s markets for new units, it’s a “rational decision for existing resources as well.”
Where to Recover?
Pratzon noted concerns that recovering the costs of PFR was also affected by another ongoing stakeholder discussion about variable operations and maintenance (VOM) costs. Stakeholders will vote at the April meeting of the Market Implementation Committee on three proposals that revise how cost-based offers can be submitted. (See “Maintenance in Cost-Based Offers,” PJM Market Implementation Committee Briefs: March 7, 2018.)
PJM’s Tom Hauske assured stakeholders that none of the proposals disallows including PFR costs in offers, but Pratzon noted they differ with whether they are recovered through the capacity or energy market.
“Some generators might think they have more certainty recovering [the costs] in [the energy market] than [in the capacity market],” he said.
Pratzon also questioned PJM’s plan to exempt units that have wholesale market participation agreements (WMPAs) rather than interconnection service agreements. WMPAs are for resources that are governed by state tariffs and aren’t under FERC’s jurisdiction.
“By doing what you’re doing, you’re setting up a system where people who are first in get a break that nobody else gets,” he said.
Pratzon also had concerns with parts of PJM’s proposal to assess PFR performance. Staff will be able to perform assessments up to 30 times per year but would aim for two or three events per month. Staff agreed to accommodate an AEP request to make the factors triggering an event less sensitive, which would reduce the number of events to assess, but said they would need at least three quarterly events for the assessment.
Pratzon argued that it was unfair to allow units that lack real-time telemetry capability to submit data from a selected event because they could cherry-pick their best performance.
Units would receive a pass/fail grade, and PJM would discuss the issue with failing units. If units that fail are intentionally not responding, they could be referred to FERC. PJM plans to put the details in its operating manuals so they can be revised as necessary; the requirement to provide PFR will be in its Tariff so units are required to respond.
Stakeholders agreed to update their proposals based on feedback and have them prepared for a nonbinding poll that will be open between April 4 and 11. The results will be reviewed at the task force’s next meeting on April 26.
Berkeley, Calif. — Electric vehicles are increasing on California highways, but future growth is dependent on solving critical issues around standardization of charging infrastructure, a state regulator said last week.
“The electric vehicle market is transforming on a daily basis,” California Public Utilities Commissioner Carla Peterman said on Friday at the annual POWER Conference at University of California Berkeley. There are about 376,000 light duty EVs, 43 models and 22,000 public charging stations in the state, she said.
“Our investor-owned utilities have a critical role to play in this market,” Peterman said, noting that utilities provide EVs fuel, manage the electric distribution system and help build related infrastructure. The vast majority of charging in California happens at home, she said.
Correctly addressing the standardization of charging infrastructure is extremely important, Peterman said, and there are often worries of stifling innovation because of regulations and cybersecurity, she said. (See Visibility Key as EVs Seek Growth Beyond Early Adopters.)
Gov. Jerry Brown in January issued an executive order to pursue 5 million zero-emission vehicles in the state by 2030, including 250,000 plug-in EV chargers and 10,000 DC fast-chargers. A 2013 executive order encouraged development of dual-compatibility charging infrastructure using the two main types of charger connections.
“We are scaling at the rate that we see some benefits of standardization,” Peterman said.
Peterman discussed an issue paper on EV charging standards presented at the conference by Massachusetts Institute of Technology researcher Jing Li. The research showed that under mandatory compatibility standards, companies would reduce duplicative investment in charging infrastructure, but the size of the electric vehicle market would expand.
Peterman, who has been on the CPUC since 2012, holds a doctorate in energy and resources from Berkeley and is also a former member of the California Energy Commission.
The CPUC in January approved 15 utility projects designed to speed EV adoption, including the installation of fast-charging infrastructure and electrification of school buses and delivery vehicles.
Former FERC Chairman Norman Bay also spoke Friday, commenting on a paper by researchers at the University of Maryland College Park and Harvard University on the role of energy markets and environmental regulations in reducing coal-fired power plant profits and electricity emissions.
“Energy policy can really drive environmental objectives,” Bay said, mentioning FERC rulemakings on transmission planning, energy storage, distributed energy resources, demand response and competitive wholesale markets. Well-functioning markets send the signals needed for investment and retirement, reducing the curtailment of renewables, he said.
Bay also discussed how CAISO’s Energy Imbalance Market (EIM) is growing and helping to address the state’s “duck curve.” Obstacles to expanding markets includes their voluntary nature, getting governance correct, jobs, energy costs and reservations about markets in the West.
“I think there is some residual fear of markets, so thank you Enron and the Western electricity crisis,” Bay said, adding that educating people on the benefits of markets is key to their growth.
At the conference, Matthew Zaragoza-Watkins of Vanderbilt University discussed his research into what he said was withholding behavior by natural gas pipeline operators in New England. The research showed that some nodes were disproportionately served by specialized types of contracts that allow firms to call for gas on demand and to make large adjustments without notice in the last few hours of the day.
The behavior strongly affected gas and electricity prices, he said, and transferred $3.6 billion from ratepayers to generators and fuel suppliers over a three-year period, about half of which occurred in the winter of 2013-2014, he alleged.
FERC staff looked into the allegations, after the research was presented by the Environmental Defense Fund in an August 2017 paper. There was no withholding of pipeline capacity, and the EDF study was flawed and led to incorrect conclusions, FERC said on Feb. 27.
An energy consulting firm thinks MISO has the potential for several gigawatts of demand-side energy savings by 2038, stakeholders learned Thursday.
The 20-year estimates of MISO’s future demand response, energy efficiency and distributed generation were produced by Applied Energy Group (AEG), with near final results presented to stakeholders at a special March 22 conference call. The commissioned study will inform the RTO’s 2019 Transmission Expansion Plan, with researchers using the conditions from four MTEP future predictions to project likely demand-side management.
By 2038, total demand-side management could reduce MISO peak summer demand by 22.5 GW, or about 15%, with 11.3 GW of the energy savings from energy efficiency, 7.2 GW from DR and 4 GW from distributed generation. Next year, AEG predicts MISO will save about 8.2 GW on summer peak demand from demand-side management.
Summer peak demand savings | Applied Energy Group
In two decades, energy efficiency will be responsible for a 69,899-GWh annual energy savings in MISO; distributed generation will account for a 19,566-GWh annual savings; and DR programs will yield a 539-GWh annual savings. The 89,971-GWh savings total by 2038 is a more than seven-fold increase from AEG’s expected 12,764-GWh savings in 2019.
AEG predicts that Michigan, Minnesota, Iowa and Wisconsin have the most potential for energy savings through the next 20 years.
Annual energy savings | Applied Energy Group
Some stakeholders commented that there was virtually no way to verify AEG’s forecasted values with what transpires because behind-the-meter activity is expected to remain largely undocumented.
AEG Managing Director Michael Daukoru said his firm examined both regional and state-specific customer adoption trends along with various state incentives, costs of programs, utility-provided forecasts and capacity growth rates in the study.
MISO staff have said the trickiest part of load forecasting is capturing and projecting the footprint’s unknown amount of demand-side management. (See MISO Looks to Align Load Forecasting, Tx Planning.)
The study found that energy efficiency provides the most significant magnitude of demand and energy savings resources.
“Energy efficiency in our view will continue to play a critical role in demand-side management,” Daukoru said. “EE is quite significant in terms of savings.”
Daukoru predicted that residential behavioral programs that encourage improvements in energy efficiency and home weatherization programs will continue to gain popularity within MISO. New federal lighting standards in 2020 and efficiency upgrades to existing buildings and equipment will also play a role in energy efficiency, the study found.
Distributed resources, driven by rooftop solar, will impact peak loads. MISO will continue to see rapid adoption of distributed generation with the rapidly declining cost of residential rooftop solar, Daukoru said. Distributed wind, on the other hand, is expected to remain prohibitively expensive for most residents.
Combined heat and power is already at high saturation point in parts of MISO, including Texas, Louisiana and Michigan. Expensive installation costs limit more adoption, Daukoru said.
The study found that MISO has room for “significant” DR opportunities, despite “several mature” programs in certain states. AEG expects residents in the footprint to participate in expanded direct load control programs within two decades, installing connected thermostats and smart water heaters that can be automated to turn off in response to reliability threats or energy price spikes.
AEG said utility-led dynamic pricing programs will be emerging only “from isolated pilots.”
“There is enormous potential for dynamic pricing, but it requires political will,” said AEG Senior Vice President Ingrid Rohmund.
Customized Energy Solutions’ David Sapper asked if AEG considered how the federal push to value resilience might affect the adoption of demand-side management in MISO.
“I have not given that much thought,” Daukoru said. “That was not accounted for in our analysis.”
Daukoru added that demand-side resources could be valuable to resilience given their ability to deliver energy savings and render loads more flexible.
AEG’s study will be finalized in June and included in the MTEP studies. MISO and AEG will continue to refine study assumptions for behind-the-meter participation and the potential impact of electric vehicle adoption over the next few weeks.
Moments after stakeholders approved the charter for the Energy Price Formation Senior Task Force (EPFSTF) without comment at last week’s Markets and Reliability Committee, PJM moved to revise the issue charge on which it’s based to also address concerns about insufficient secondary reserves.
“The topic of potential new reserve products has been raised in our discussion around energy price formation,” PJM’s Dave Anders explained. “We realized that it would really be beneficial for the Operating Committee to provide some input to those considerations around reserve products.”
The EPFSTF decided that the first step is for the OC to define the “reliability-related aspects” that need to be addressed so they can be incorporated into the market-structure changes the task force is contemplating. To include that, they recommended adding a “key work activity” to the task force’s issue charge and assigning it to the OC.
The initial proposal tasked the OC with identifying the factors a 30-minute real-time product should have and how it would interact with synchronized reserves. However, stakeholders — led by the Independent Market Monitor Joe Bowring — eventually replaced that with a more generalized task to analyze secondary reserves and any “interdependencies” it would have with primary reserves.
Calpine’s David “Scarp” Scarpignato asked that the discussion include any reserve requirement changes that would interact with the reliability assessment and commitment (RAC) process and the day-ahead and real-time markets. Anders said the language had been added to the EPFSTF’s charter.
PJM’s Dave Souder said the reserve considerations are an extension of the gas-electric coordination and pipeline-contingency initiative that he has been leading since late last year. He said he plans to “set aside an hour” at each monthly OC meeting to create a recommendation on the appropriate inputs and what revisions might need to happen in real time. (See “Resilience Update,” PJM Operating Committee Briefs: March 6, 2018.)
“I think it’s within our purview at the OC to see if we have reliability need, and we can recommend that the product be developed, but how that’s developed would be through the [EPFSTF],” Souder said. “There may be times where the gas contingency is larger than our largest 30-minute requirement. Under those conditions, we may need to ensure we have sufficient 30-minute reserves.”
Stakeholders endorsed the second phase of an initiative with MISO to address overlapping congestion. The first phase was filed with FERC in December, but PJM had to respond to a deficiency notice in January and it was not approved by the proposed March 1 implementation date. With the endorsement of the second phase, staff hope that both phases can be approved for implementation by June 1, PJM’s Tim Horger said.
The proposal addresses the potential for pseudo-tied resources to pay twice for congestion charges as their energy crosses the market borders. The first phase eliminated the charges, and the second phase allows hedging of potential congestion charges through day-ahead transactions, auction revenue rights and financial transmission rights. Owners will be refunded or charged for deviations between day-ahead submittals and real-time operations. (See MISO, PJM Pursue Pseudo-Tie Double-Charge Relief.)
Solution to congestion overlap | PJM
Generation Transfer
Concerns with PJM’s proposed deadlines for notifying the RTO of generation transfers are being ironed out, PJM’s Rebecca Stadelmeyer said. A vote on the issue was deferred at February’s MRC meeting because some generation owners felt PJM’s timeline was too onerous. (See “Generators Hesitate on Ownership Transfer Rules,” PJM Markets and Reliability Committee Briefs: Feb. 22, 2018.)
Stadelmeyer said stakeholders have sent in redlines, and a group of generation owners, coordinated by GT Power Group’s Dave Pratzon, are engaged on the issue.
“It definitely appears PJM and the generator owners are coming to a mutual understanding,” she said.
The group has another call scheduled for March 28.
Stakeholders Approve Variety of Actions
Stakeholders endorsed by acclamation several manual revisions and other operational changes:
Manual 1: Control Center and Data Exchange Requirements. The revisions were developed as part of a periodic review and encompass real-time system monitoring and communication requirements, including external resources.
Manual 14A: New Services Request Process and Manual 14E: Additional Information for Upgrade and Transmission Interconnection Projects. Revisions developed to implement previously approved revisions to PJM’s transmission service and upgrade requests. (See “Transmission Issues,” PJM PC/TEAC Briefs: Feb. 8, 2018.)
Manual 37: Reliability Coordination. Revisions developed to clarify language and simplify references to NERC standards.
Members Committee
Overlapping Congestion Endorsed Through Consent Agenda
The Tariff and OA revisions to address the overlapping congestion issue were added to the consent agenda, which stakeholders endorsed by acclamation without comment.
The issue was brought for a vote at both committees on the same day because stakeholders agreed to that arrangement when they deferred the vote at February’s MRC. The dual vote allows PJM to maintain its preferred timeline for filing and implementation.
Monitor Recommends Redrawing Market Lines
Monitor Bowring believes the lines that define regional price separations within the RTO in the capacity market are antiquated and that price separation should be dynamic based on the actual characteristics of the market. He discussed the recommendation while briefing members on the 2017 State of the Market report. (See IMM Report Says PJM Prices Sufficient.)
Bowring’s thoughts on redefining locational deliverability areas (LDAs) in the capacity market came in response to a question from Ruth Ann Price of the Delaware Division of the Public Advocate. She had asked him to expound on his recommendation that LDA definitions be dynamic and market based.
“We think that it should be based on a nodal definition so that the price separation is a function of the actual transmission characteristics of the system as well as the relative offer prices of the system,” Bowring said. “LDAs are arbitrary lines … [that are] almost without exception the old-fashioned transmission zones. There’s no reason to believe that those are the right way to have prices separate.”
He said the first step to addressing the issue is modeling every LDA to see if any prices separate. He said he hasn’t done the analysis to determine how many LDAs would price separately, but that he would investigate it.
Bowring said another “work in progress” is examining the nature of the competition to provide transmission upgrades and expansions.
FERC on Friday accepted ISO-NE’s request to terminate 11 MW of the capacity supply obligations (CSOs) for a Maine wind farm that delayed its commercial operation and reduced its planned output.
However, FERC said the RTO was wrong in executing the termination before commission approval, delaying the effective date to March 24 (ER18-704).
The RTO filed its termination request on Jan. 23, asserting that developer Blue Sky West had delayed its original 2015 commercial operation date multiple times before achieving partial operation in March 2017.
Bingham Wind Project | NovatusEnergy
In Forward Capacity Auction 6, the Bingham wind project in Somerset and Piscataquis counties won CSOs of 42.3 MW for summer and 87.3 for winter, beginning with the 2015/16 capacity commitment periods (CCP).
The company agreed to voluntarily relinquish about 20 MW of summer and 22 MW of winter CSOs based on its decision to reduce the number of turbines in the project and change the turbines to a design with a lower capacity. But the company disputed ISO-NE’s demand to reduce the summer CSO by 10.3 MW and winter by 0.79 MW following the RTO’s audits of the farm’s actual output.
The RTO filed to terminate immediately that portion of the resource’s CSOs in the 2017/18 through 2020/21 capacity years, and to adjust the facility’s qualified capacity for future capacity auctions.
Blue Sky West filed an emergency motion asking the commission to order reinstatement of the disputed CSOs, arguing the grid operator must receive commission approval before the termination could become effective. On Feb. 2, 2018, the commission granted the motion, ruling that the termination could not be made effective prior to March 24, the end of the 60-day notice period.
The RTO’s Tariff allows termination of CSOs if a new facility covers its capacity shortfalls through bilateral trades or the reconfiguration auctions for two capacity commitment periods. The developer claimed the audits should not be justification for reducing the CSOs because they are not listed as “critical path” schedule requirements in the RTO’s Tariff.
The commission disagreed, saying, “Neither achieving ‘commercial operation’ nor fulfilling ‘critical path schedule milestones’ precludes ISO-NE from terminating a resource’s CSO under” the Tariff.
The RTO said that if it did not perform terminations in advance of the FCA, a resource that is not fulfilling its CSO could obtain one for another year and potentially suppress auction clearing prices and provide the region with phantom megawatts that cannot produce energy.
FERC agreed with the grid operator’s right to manage its capacity resources but departed with it regarding its termination rights. “While the [Tariff] language is ambiguous, we find that under a sensible reading of the provision and as a practical matter, [a Federal Power Act] Section 205 filing is necessary to obtain a ‘commission ruling’ on any aspect of an involuntary termination,” the commission said.
Requiring such approval of involuntary terminations “should not impede the grid operator’s administration of the Forward Capacity Auction,” FERC said.
“Given that the [FCA] takes place in February of each year, the [RTO] usually submits termination filing in October of the prior year, giving the commission enough time to rule on the termination filing before the Forward Capacity Auction is conducted,” the commission said.
Could PJM’s Artificial Island project get any more complicated? Apparently, yes.
A Delaware demand-side group has asked the PJM Board of Managers to again suspend the project because of announcements from Exelon and Public Service Enterprise Group that that they will cancel future capital investments at the two Salem nuclear units they co-own and shut the plants down if New Jersey doesn’t provide them $300 million annually in subsidies to keep the plants open. (See NJ Lawmakers Advance Latest Nuke Subsidy Bills.)
The project was developed to address transmission stability problems at the Hope Creek and Salem nuclear units in southern New Jersey and allow them to operate at full power without a book-size compilation of operating constraints.
The Hope Creek and Salem nuclear units on Artificial Island in southern New Jersey | BHI Energy
PJM’s first competitive solicitation under Order 1000, the Artificial Island project has long been mired in controversy. In June, the RTO announced several cost allocation alternatives that would shift much of the $280 million price tag from Delaware ratepayers to those in New Jersey and Pennsylvania. (See PJM: AI Costs Would Shift to NJ, PA Under New Allocations.)
The Board of Managers had two months earlier restarted the project and ordered the analysis of alternative allocation methods. It also re-awarded the project to LS Power, which was selected when the board approved the project in July 2015. Complaints over mounting costs, scope changes and a cost allocation that Delaware felt was unduly burdensome caused the board to suspend it in August 2016.
But the announcements from Exelon and PSEG in February cast doubt over whether the plants are long for this world. PSEG said it might also cancel spending on the Hope Creek reactor, which shares Artificial Island with the Salem units.
“These actions call into question the long-term operational viability of the Salem and Hope Creek plants,” wrote Michael K. Messer, president of the Delaware Energy Users Group, noting that Delaware consumers stand to pay “a significant share” of the project’s cost. “The cost increase is at a level that will severely impair the competitiveness of Delaware businesses. This scenario becomes far worse should the driving reason for the transmission project, Salem and Hope Creek reliability, cease to exist.”
He asked the board to consider whether the project is necessary or if its scope changes if any or all of the plants close and whether the project’s timeline should be delayed “to minimize expenditures until a long-term commitment is established for the Salem and Hope Creek plants.” LS Power’s award has an in-service date of June 1, 2020.
PJM’s Dave Anders, who oversees stakeholder relations, said it’s unclear what the board’s response will be. “At this point, I do not have a sense for when/if there will be a formal response,” he said in an email.
SPP said last week that its Board of Directors has created a Holistic Integrated Tariff Team (HITT) comprising directors, regulators, staff and stakeholders to take an all-encompassing look at the different challenges facing its footprint and develop a set of high-level recommendations in response.
The team is hoping to replicate the success of a “synergistic” planning project team created nine years ago. That team produced a report that led to SPP’s integrated transmission planning process and the “highway/byway” cost allocation methodology for new transmission upgrades.
Transmission lines | Wind Energy Transmission Texas
The 16-member HITT includes Directors Larry Altenbaumer and Graham Edwards and state commissioners Shari Feist Albrecht (Kansas Corporation Commission) and Dennis Grennan (Nebraska Power Review Board).
The Nebraska Public Power District’s Tom Kent will serve as chair of the team and Dogwood Energy’s Rob Janssen as vice chair. SPP Legal Counsel Paul Suskie will serve as the team’s staff secretary.
Kansas City Power & Light’s Denise Buffington said she is looking forward to being one of four investor-owned utility representatives on the team. Buffington chaired a task force that was unable to reach consensus on improvements to SPP’s methodology for assigning financial credits and obligations for sponsored transmission upgrades under Attachment Z2 of its Tariff.
“Based on my experience with the Z2 task force, I anticipate there will be a lot to learn and it will be a multiyear process,” Buffington said.
The 16-person HITT will assess:
SPP’s transmission planning and study processes, including generation interconnections, the interconnection queue, energy resource and network resource interconnection service, aggregate studies, capacity requirements, and related FERC planning requirements.
Transmission cost allocation issues, including regional and zonal funding, directly assigned costs, Attachment Z2 credits, cost allocation impacts on transmission pricing zones with large wind resources, and state-by-state supply resource mix requirements and goals.
Effects on the Integrated Marketplace from a changing resource mix, access to lower cost generation and potential changes in production tax credits.
Disconnects or potential synergies between transmission planning and real-time reliability and economic operations.
Any other areas and issues seen as appropriate and reasonably related to the scope of work.
The HITT will report to the board’s Members Committee and provide status reports to the Regional State Committee, Markets and Operations Policy Committee and Strategic Planning Committee. SPP expects the team to complete its work with a written report by April 2019. It can request additional time, if needed.
AEP’s Wind Catcher project, with its GE turbines, has a potential 2 GW of energy-only resources. | GE
SPP stakeholders will be able to listen to the meetings and discussion through teleconference.
The group’s creation was approved during a board executive session March 13. During that same meeting, the board approved 18 policy statements that will guide Mountain West’s pending membership into SPP. (See SPP Begins Work of Integrating Mountain West.)
Joint Petition on SPP RE’s Dissolution Filed with FERC
NERC, the Midwest Reliability Organization and SERC Reliability Corp. have submitted to FERC a joint petition in connection with the SPP Regional Entity’s dissolution.
The filing follows the NERC Board of Trustees’ February vote to dissolve the SPP RE by terminating the RTO’s regional delegation agreement, ending a reliability oversight role that concerned both the reliability organization and FERC. (See NERC Board Approves Dissolving SPP Regional Entity.)
The petition requests FERC approval of:
The termination of the amended and restated delegation agreement (RDA) between NERC and SPP.
The proposed transfers of SPP RE registered entities to MRO and SERC by July 1, 2018.
The amendments to RDAs between NERC and MRO and between NERC and SERC to reflect the changed geographic footprint resulting from the transfer.
NERC requested that the commission expedite consideration of the petition and shorten the comment period to no more than 14 days “to allow a timely transition of registered entities from SPP RE to MRO and SERC with minimal disruption.”
