TULSA, Okla. — SPP’s Holistic Integrated Tariff Team (HITT) last week shared with stakeholders the result of a year’s worth of work: a draft report of high-level recommendations addressing the footprint’s many challenges.
Now comes the hard part: taking action on the recommendations.
“There’s a heck of a lot of work that’s left,” HITT Chair Tom Kent said during SPP’s April 29 joint quarterly stakeholder briefing. “The working groups will have a lot of effort to put these [recommendations] into actual action.”
Kent, COO for Nebraska Public Power District, said the HITT report makes 21 recommendations in four categories: reliability, marketplace, planning and cost allocation, and strategy. Thirteen of the recommendations, some of which are already in progress, are planned for implementation; the other eight require further study.
The big-ticket cost-allocation recommendations include decoupling Schedule 9 and Schedule 11 transmission pricing zones and allowing the creation of larger Schedule 11 pricing zones and/or Schedule 9 sub-zones. The HITT proposes that if the Regional State Committee adopts a policy to reallocate existing costs within the new pricing zones, it should be done over a five- to 10-year transition period to mitigate cost shifts.
The HITT is also recommending SPP determine whether transmission projects below 300 kV can be fully allocated on a regionwide basis; use incremental long-term congestion rights instead of Attachment Z2 credits as compensation for new sponsored upgrade projects; and evaluate whether it can establish cost allocation and rates under the Tariff for energy storage resources.
The team also recommends SPP continue to improve the Integrated Marketplace by including fast-start resource logic, ramping capability and a multiday, longer-term market product, and to continue developing a market mechanism to hedge load against congestion charges.
Kent said the report is a “tribute to the team working hard and working together, and coming to a strong consensus on the recommendations.”
HITT’s recommendations | SPP
A proposed action plan assigns the recommendations to various stakeholder groups. A timeline anticipates the work being completed by mid-2021.
Larry Altenbaumer, chair of SPP’s Board of Directors, called the HITT’s work “an example of the very best of SPP.”
“We fully recognize 85% of the work is in front of us,” he said. “It’s an exciting beginning of a very important next step for us. I think HITT’s going to be a good thing for us.”
“The industry is changing as rapidly as many of us who’ve been around for a long time have seen it change,” said HITT member Dennis Grennan, a commissioner with the Nebraska Power Review Board. “We must prepare for major changes coming in the next five to 10 years. It’s a real challenge, but it needs to be done so that our consumers back home truly benefit from belonging to SPP and all that comes with it.”
Kent promised a final report by the end of June and said that a final product will be brought to the July stakeholder meetings. He said it will be discussed in detail with the Strategic Planning Committee during its May 9 planning retreat.
The RSC has scheduled in-person meetings with the HITT on May 30 and June 24, and Altenbaumer asked for a workshop to be scheduled where stakeholders can participate in a “top-to-bottom” discussion of the report.
The SPP board charged the HITT with developing recommendations for holistic improvements within the system. The team is composed of 15 board members, state regulators and SPP members. (See SPP’s Tariff Team Begins Carving up the Elephant.)
FERC is re-evaluating how its 2018 decision on transmission owners’ return on equity might affect Entergy Arkansas’ unit power sales tariff from 2013.
The commission April 30 said it could determine a new ROE for Entergy Arkansas and issued an order directing submission of briefs and additional written evidence (ER13-1508-001).
| Entergy Arkansas
The issue dates back six years, when Entergy Arkansas decided to leave the Entergy System Agreement and join MISO. As a result, Entergy Arkansas created a unit power sales tariff that passed through MISO’s ancillary and uplift charges and credits, along with the RTO’s 11% ROE for TOs. Both the Louisiana Public Service Commission and the city of New Orleans protested Entergy Arkansas’ use of the rate. Using the 2014 Opinion 531 that set the ROE for transmission owners in New England, an administrative law judge in 2015 found that 9.01% was reasonable in Entergy Arkansas’ case.
But with Opinion 531 vacated in 2017 and no longer serving as precedent, FERC wants a fresh look at Entergy Arkansas’ ROE. As of last year, the commission said it will no longer rely only on the discounted cash flow (DCF) model, instead using a combination of DCF and the capital asset pricing, expected earnings and risk premium models. (See FERC Changing ROE Rules; Higher Rates Likely.)
“Accordingly, we direct the participants to this proceeding to submit briefs regarding the proposed new methodology for determining just and reasonable ROEs … and whether and how to apply it to the unit power sales tariff,” FERC said.
The commission added that participants in the case “are free to present evidence supporting the proposed new methodology or supporting a different or revised new methodology.” Briefs are due in two months.
NYISO’s electricity markets have reached an “inflection point” as new technologies and “ambitious” public policy goals require the ISO to develop measures to manage the grid’s “next evolution,” according to the ISO’s annual Power Trends report released Thursday.
Last year’s report covered the implications of state policies calling for 50% of the electricity consumed by New Yorkers to come from renewable sources by 2030.
“A year later, however, policymakers seek even more aggressive goals of 70% renewable energy by 2030 and 100% clean energy sources by 2040,” NYISO Executive Vice President Rich Dewey said in a press briefing to discuss this year’s report. The report noted that the ISO is working with stakeholders and policymakers to finish a plan to price CO2 into wholesale markets to support the state’s goal of reducing emissions. (See More Details Divulged on New NYISO Carbon Pricing Study.)
Annual electric energy usage trends in New York from 2000 to 2018 | NYISO
Dewey also highlighted a February proposal by the state’s Department of Environmental Conservation to require peaking units to reduce their emissions of smog-forming pollutants.
“The proposed new rule, which calls for phasing in compliance obligations between 2023 and 2025, could impact approximately 3,300 MW of simple cycle turbines in New York City and Long Island,” he said.
The ISO is engaged in the rule development process and will work to inform policymakers, market participants and investors of the rule’s implications for bulk and local system reliability, but it had no plans to testify at a Tuesday DEC hearing on the subject in Albany, Dewey said.
NYISO has initiated the second phase of its 2018/19 Comprehensive Reliability Plan, which includes a study scenario evaluating the reliability impacts of a potential retirement of all 3,300 MW of peaking units impacted by the DEC’s proposal.
Changing Grid and Goals
“Another trend is the recognition of the need to pay attention to the power transmission infrastructure within New York, both from a transmission and from a generation standpoint, which is aging and needs to be reinvested in to ensure we maintain reliable operation of the system,” Dewey said.
He also highlighted the need to maintain a resilient grid “in light of an uptick in severe storms” and other issues related to climate change.
The Power Trends report also points to a 10-year trend of declining electricity demand in New York, partly because of economic changes, but also increased energy efficiency. The ISO sees demand continuing to decline on EE and behind-the-meter resources, predominantly solar, Dewey said.
“When we look at peak demand, the impact of energy efficiency and behind-the-meter solar will continue to flatten and slightly decrease the need for peak as we move forward into the future,” he said.
Dewey also pointed to the opportunity for storage to become a valuable resource for grid management. The Public Service Commission in December doubled New York’s storage goal to 3,000 MW by 2030 and required the state’s utilities to reduce building energy use by an additional 31 TBtu to meet an EE target of 185 TBtu by 2025. (See NYPSC Expands Storage, Energy Efficiency Programs.)
Forcast electric vehicle energy and peak impacts | NYISO
A countertrend to EE is the increasing adoption of electric vehicles, which will put upward pressure on peaks, with a greater impact in winter than in summer because the peak occurs in the evening, which coincides with consumer EV charging habits, Dewey said. The new report takes its load data from the 2019 Gold Book, NYISO’s annual load and capacity forecast, which this year shows EV usage driving a 66% increase in New York’s projected baseline peak demand growth rate over the next two decades. (See NYISO Draft Gold Book Shows EVs Driving Load Growth.)
The report emphasized the ISO’s faith in competitive markets to provide incentives for investment in renewable resources and finance a more robust transmission system to move power to load.
Absent such infrastructure upgrades, investment in upstate New York renewables could yield diminishing returns for the state’s effort to boost renewable energy output and reduce carbon emissions, Dewey said.
“The NYISO believes that competitive wholesale electricity markets remain central to facilitating the accelerated changes policymakers have proposed in a way that will support system reliability and economic efficiency,” the report said.
TULSA, Okla. — SPP is stepping up its bid to offer market services in the Western Interconnection, with interested participants approaching the RTO for more details on its proposal.
CEO Nick Brown told the RTO’s Board of Directors and Members Committee on Tuesday that “many” Western entities have asked SPP “to put very specific proposals on the table.” He said the requests are based on the RTO’s experience operating energy imbalance service and day-ahead markets.
“We have a model we believe is in the best interest of parties in the West,” Brown said. “Rather than go out and say, ‘OK folks, what is it that you want?’ — we’re going to take a much stronger leadership role to put a proposal on the table.”
The board and members took up the Z2 and exit fee discussions during its executive session.
Brown said the Corporate Governance Committee will take up the exit fee issue “in greater detail” in the weeks to come. FERC on May 1 granted SPP’s request to extend the compliance deadline from June 17 to Aug. 1 (EL19-11).
General Counsel Paul Suskie told the Regional State Committee on Monday that two members have filed Section 206 complaints with FERC alleging SPP incorrectly calculated Z2 payments. Suskie said four additional TOs have told him they plan to file complaints because the RTO is not issuing refunds.
SPP MMU: Competitive Markets, Prices Up $2/MWh
A draft version of the Market Monitoring Unit’s 2018 State of the Market report finds the RTO’s markets are competitive, with average energy prices of $28/MWh, about $2/MWh higher than 2017 because of increased loads, transmission expansion, lower wind capacity factors and increased generator outages that offset lower gas prices and a “large and increasing” reserve margin.
The MMU has relied on a peak available capacity metric instead of a reserve margin in its last two reports. The metric uses a percentage of each resource’s average maximum capacity during July and August, divided by the resource’s nameplate capacity. For 2018, the peak available capacity percentage was 35%, up from 33% in 2017, nearly three times higher than SPP’s minimum required planning reserve margin of 12%.
MMU Executive Director Keith Collins has compared SPP to a “wind store,” it having added almost 7 GW of wind capacity over the past three years and expecting another 6 GW to come online over the next few years. SPP has more than 20 GW of available wind capacity.
Wind additions continue to outpace generator retirements, Collins said. He said members retired 1.9 GW of coal and gas capacity in 2018.
Collins said while the MMU is not making recommendations to address “imminent” issues, it is advising “more of a prepared approach” for future events.
“Be prepared and assess what the world will look like with changing prices, especially with transmission expansion,” he said.
The MMU is recommending parameter changes (ramp rates, run time, down time, etc.) to limit market power, improving credit rules to account for known information in assessments, developing a mechanism or product to pay for capacity that covers uncertainties, and improving the ability to assess a range of potential outcomes in transmission planning.
The report will be shared with FERC by mid-May, Collins said. A conference call to further discuss the report will be held shortly before the end of May.
2018 Annual Report, ‘Balance,’ Available
SPP distributed copies of its 2018 annual report, “Balance,” during the board meeting. The title alludes to the task of managing real-time operations, reliability, compliance, financials and developing carbon-free resources.
“We hold to a belief that reliability and economics are inseparable,” Brown writes in the report. “It’s our duty to ensure the reliable delivery of electricity to millions of people across our footprint, and every decision along the way has a financial impact to our members and their end-use customers.”
Directors, Members Recognize Retiring Stakeholders
Directors and members paid tribute to several retiring stakeholders who were attending their last board meeting: Mike Risan, Basin Electric Power Cooperative’s senior vice president of transmission; Jerry Peace, Oklahoma Gas & Electric’s vice president of integrated planning and development; and FERC’s Darrell Piatt, with the Office of Electric Reliability.
Brown said he goes back 30 years with Risan and credited him with helping drive the 2015 integration of the Integrated System.
The board’s consent agenda, which passed with the Members Committee’s unanimous consent, approved several new stakeholder group members and handed GridLiance High Plains the assignment of a notice-to-construct for a Kansas Power Pool 69-kV rebuild project. The NTC’s potential assignment was the subject of some contention during the April Markets and Operations Policy Committee meeting but remained on the consent agenda. (See “SPP Proposing to Assign Kansas NTC to GridLiance,” SPP MOPC Briefs: April 16-17, 2019.)
The $3.6 million project, which would rebuild 4 miles of 69-kV lines in Winfield, Kan., is waiting on approval from the Kansas Corporation Commission (19-GLPE-338-ACQ). GridLiance and Winfield have agreed to a long-term partnership that includes investments in “reliability upgrade(s).”
GridLiance High Plains President Brett Hooton said the company is excited about the board’s approval. “We look forward to working through the Kansas Corporation Commission’s regulatory process,” he said.
The consent agenda’s approval also resulted in the withdrawal of several NTCs issued to Westar Farmers Electric Cooperative in 2008 and 2009. The proposed 69-kV upgrades are no longer needed because of subsequent 138-kV upgrades in the area.
Two other NTCs, previously awarded to Southwestern Public Service, were withdrawn in a separate vote following an out-of-cycle reevaluation of SPS’ Lamb County project. The project was identified as a regional reliability effort in the 2014 Integrated Transmission Planning near-term assessment, but SPS said it believes the project is no longer needed. Staff found no adverse effects by removing the project from the 2020 ITP, generator interconnection or transmission-service processes.
The board approved:
Tri-State Generation and Transmission’s Duane Highley to the Human Resources Committee. Highley replaces himself after formally resigning from the committee when he left Arkansas Electric Cooperative Corp. to become Tri-State’s CEO.
OG&E Controller Sarah Stafford’s appointment to the Finance Committee, replacing the retiring Peace.
The Model Development Working Group’s charter revision that expands voting membership from 14 members to “up to” 24, allowing NERC-registered transmission planners to join.
The board also approved two revision requests:
ORWG RR349: Requires responsible entities to use the reliability communications tool (R-comm) instead of telephones to communicate with the SPP balancing authority.
TWG RR350: Eliminates language in the criteria that is already covered by NERC standards or other SPP standalone documents, minimizing inconsistencies or conflict with current and future NERC standards and revisions.
FERC on Wednesday rejected Pacific Gas and Electric’s request to rehear a January ruling in which the commission asserted that it shares authority with a federal bankruptcy judge over any power purchase agreements the utility might seek to modify after filing for Chapter 11 protection.
The commission’s order also consolidated separate petitions by NextEra Energy (EL19-35) and Exelon (EL19-36) for declaratory orders preventing PG&E from reneging on high-cost contracts with renewable generators.
As part of its January Chapter 11 filing, PG&E asked the U.S. Bankruptcy Court in San Francisco to issue an injunction confirming its exclusive jurisdiction over the utility’s right to reject PPAs and other FERC-regulated agreements.
At a hearing April 10, PG&E attorney Theodore Tsekerides strenuously argued for Bankruptcy Judge Dennis Montali to impose a permanent injunction preventing FERC from interfering with the bankruptcy case. But Montali declined to make an immediate decision, instead asking lawyers to reach a compromise. (See Judge Puts off Decision in PG&E v. FERC.)
In arguing against an injunction, FERC’s lawyer told Montali that a compromise was possible but would be subject to commission approval. Wednesday’s decision suggests the commission is prepared to give little ground over the matter.
In its rehearing request, PG&E contended that FERC’s initial order failed to acknowledge Congress’ intent in enacting the bankruptcy code, specifically “to permit the successful rehabilitation of debtors” and “prevent a debtor from going into liquidation, with an attendant loss of jobs and possible misuse of economic resources.”
The utility further argued that debtor-in-possession status provides the flexibility to assume or reject any contracts until a reorganization plan is established, and that the law does not exempt wholesale power contracts from that process.
PG&E also asserted that the commission’s requirement that it approve contract changes could prevent the utility from abrogating contracts despite bankruptcy court approval, depriving the utility of the flexibility intended by Section 365 of the bankruptcy code.
In rejecting rehearing, FERC insisted that it holds joint authority over the fate of the PPAs.
The commission said the Supreme Court has “long recognized” that the Federal Power Act “is designed to protect consumers” and that the commission protects the public interest in evaluating the rates, terms and conditions of PPAs.
“By contrast, the purpose of the bankruptcy code, as PG&E acknowledges, is to provide a path to rehabilitate bankrupt debtors,” the commission wrote. “These are two distinct, yet vitally important, roles, and we conclude that it is necessary to give effect to both.”
FERC said wholesale power agreements are not “simple run-of-the-mill” contracts between private parties. Instead, they “implicate the public’s interest in the orderly production of plentiful supplies of electricity at just and reasonable rates and, as filed rates, carry the force of law binding sellers and purchasers alike.”
“Whether a wholesale rate is just and reasonable — and whether the abrogation or modification of a wholesale power contract is necessary to protect the public interest — is a question that the commission is statutorily obligated — and exclusively authorized — to consider,” the commission said.
The commission’s “unique role” in making such determinations regarding contracts “neither subsumes nor is subsumed by” bankruptcy law, FERC said. The seeking of bankruptcy protection “does not transform commission-jurisdictional contracts into non-jurisdictional ones … and it does not divest the commission of its statutory mandate to protect the public interest by examining the ramifications of unilateral changes to wholesale power contracts, a highly technical analysis that the bankruptcy process is not designed to consider.”
On Thursday, Justice Department lawyers filed the FERC decision with the bankruptcy court and requested Montali take judicial notice of the decision, establishing it as evidence in the case. It remains unclear when Montali might rule on PG&E’s petition for an injunction against FERC. The next hearing in PG&E’s bankruptcy is scheduled for May 8 at 9:30 a.m.
Eversource Energy’s earnings jumped nearly 15% to $308.7 million ($0.97/share) in the first quarter, driven by strong gains in its electric transmission, distribution and natural gas delivery businesses.
“Our Eversource team has gotten off to a tremendous start in 2019,” CEO Jim Judge said in a statement.
As New England’s largest utility company, Eversource’s regulated subsidiaries offer retail electricity, natural gas service and water service to approximately 3.6 million customers in Connecticut, Massachusetts and New Hampshire.
| Eversource
The company said its transmission segment earned $118.2 million in the quarter, up 10% over last year, while electric distribution took in $120.1 million, up 15.2%. The improved results for the electric business were “due primarily to higher distribution revenues, partially offset by the absence of New Hampshire generation earnings in 2019 and higher depreciation expense,” Eversource said. The company last year sold off the last of its New Hampshire generating capacity as part of the state’s deregulation effort.
The natural gas distribution segment earned $76.5 million in the first quarter, up 32% from a year ago, mostly because of “the timing of distribution revenues under the recently approved decoupling mechanism for Eversource’s Connecticut natural gas business,” the company said.
The gas segment additionally benefited from capital tracking mechanisms on higher levels of investment, partially offset by higher operations and maintenance, property tax and depreciation expense, Eversource noted.
The water distribution segment earned $0.9 million in the quarter, compared with earnings of $1.5 million a year ago. “The modest decline was due primarily to higher pension costs,” the company said.
Judge noted that Eversource is “executing on a nearly $13 billion, five-year core business capital plan that will greatly help our region address its long-term infrastructure and clean energy needs.” The plan projects continued strong spending on electric distribution, solar and natural gas delivery, with steadily declining outlays for transmission heading to 2023.
PJM’s Independent Market Monitor said the RTO’s updated simulation results for energy price formation understimate the impact of its operating reserve demand curve (ORDC).
In its own analysis released Friday, the Monitor said PJM’s decision to rely on dispatch conditions that allow the software to decommit resources otherwise required for reliability “presents a significant departure from reality” and results in understated market impacts.
At an April 10 Market Implementation Committee meeting, PJM’s Adam Keech said changing unit commitment based on real-time instead of day-ahead market runs — otherwise known as “Case C” in simulations — increased LMPs, boosted energy revenues and cut uplift by more than 80% compared with the status quo, which staff referred to as “Case A” in simulations. (See “ORDCs Shrink in Updated Energy Price Formation Simulation,” PJM MIC Briefs: April 10, 2019.)
By applying PJM’s proposed ORDC and 30-minute reserve market to conditions set in “Case B,” the simulation increased LMPs by an average of 46 cents/MWh, assigned an additional 1,350 MWh of synchronized reserves and 3,337 MWh of secondary reserves, and generated $550 million more in total energy and reserve market revenues, Keech said.
“If it is the case, and PJM implies that it is, that the ORDC would replace manual operator commitments with market commitments, the relevant comparison is Case A to Case C, because Case A contains the steam unit commitments made by operators,” the Monitor said. “Case B removes all uneconomic operator commitments.”
Summary results for the five simulation cases | Monitoring Analytics
The Monitor’s simulation compared Case C to Case A — defined as PJM’s optimal dispatch conditions — to get what it considers a better measure of real-life market impacts. The comparison shows less uplift, higher LMPs and revenues, with larger impacts than PJM’s Case B to Case C comparison.
The Monitor further cautioned that even Case A conditions do not represent the “actual status quo,” and using it as a benchmark still underestimates real-world costs of PJM’s proposed ORDC approach.
The Monitor’s simulation of an ORDC based on 15-minute forecast errors, compared to PJM’s 30 minutes, resulted in lower price and revenue differences.
“The Market Monitor disagrees with PJM’s conclusion that a 30-minute time horizon is appropriate for the 10-minute reserve products,” the Monitor said. “Case C 15-minute presents a case where the ORDC is shifted inward using a 15-minute forecast time horizon for the synchronized and primary reserve demand curves.”
On Monday, PJM spokesperson Jeff Shields said the RTO stands by its filing and disagrees with the Monitor’s opinion.
“PJM’s simulation analysis was intended to reflect and isolate the impacts of implementing the enhanced ORDCs,” he said. “While PJM acknowledges that there will also be benefits in the form of more optimal commitment and dispatch solutions, PJM does not agree that the entire difference between Cases A and C in the IMM report reflect the anticipated impact of the changes PJM filed on March 29.”
(Updated to reflect that the Monitor’s analysis compared Case A to Case C and found PJM’s simulation underestimates ORDC impact. A previous version of this story said the simulation results were overestimated.)
FERC said Monday that the Independent Market Monitor’s filing of complaints regarding PJM’s fuel-cost policies doesn’t violate Tariff conditions or commission rulings, ending — for now, at least — a long-simmering debate over the extent of the IMM’s authority (ER16-372).
The commission denied the RTO’s request for clarification regarding the Monitor’s ability to file complaints regarding issues besides market seller offers in capacity auctions.
The Monitor had protested PJM’s August 2016 proposed Tariff revision regarding the fuel-cost policies that generators submit showing how they calculated their cost-based offers. It said the RTO was trying to usurp its authority to regulate the policies. (See PJM Attempting to Usurp Market Mitigation Role, Monitor Says.)
FERC ultimately sided with PJM in February 2017, saying the changes didn’t alter the fundamental roles of the RTO and the Monitor, “but rather [they] codify the role of the IMM in advising and providing input to PJM in its determination of whether to approve a fuel-cost policy submitted by a market seller.”
But FERC also rejected PJM’s proposal that any disputes between PJM and the Monitor be referred to the commission’s Office of Enforcement, saying that was the province of its administrative law judges.
When the RTO filed further changes on compliance in March, it also filed the clarification request, questioning whether the commission intended “to enable the IMM to initiate a complaint against PJM” when they disagreed over the policies.
“Although PJM is correct that its Tariff explicitly delineates one instance in which the IMM has the right to file a complaint with the commission, the inclusion of an express right to bring a complaint does not necessarily foreclose an entity’s general right to file complaints under Section 206 of the [Federal Power Act],” the commission said. “In any case, we need not reach that issue here because we are unpersuaded by PJM’s narrow reading of Attachment M” of its Tariff.
Clearly specifying when a penalty for noncompliance with a fuel-cost policy would be terminated by PJM.
Allowing a new resource a 90-day time period before it submits its fuel-cost policy.
Specifying that a market seller may only update its minimum run time for the uncommitted hours in real time and that a market seller’s make-whole payment be based on the minimum run time specified at the time of commitment.
The Tariff and Operating Agreement revisions for the penalty structure became effective May 15, 2017, and the rest of the provisions Nov. 1, 2017.
The Northeast Power Coordinating Council (NPCC) is projecting a summer peak demand of 103,548 MW in the week of July 28, a 0.6% reduction (589 MW) from last year, despite growth in Ontario.
NPCC is the NERC regional entity for New England, New York, Ontario, Québec, New Brunswick and Nova Scotia. | NERC
“This continues an almost decade-long trend of overall flat or declining peak demand forecast due to energy efficiency and conservation initiatives, as well as the significantly increasing role of behind-the-meter PV resources in New England and New York,” NPCC CEO Edward Schwerdt said in a May 2 press release announcing the summer Reliability Assessment.
With the addition of 2,855 MW of net new capacity since summer 2018, NPCC forecasts a minimum operable capacity margin (spare operable capacity less transfer capability limitations) of 12,545 MW (12.2%) for the summer.
NPCC is the NERC regional entity for New England, New York, Ontario, Québec, New Brunswick and Nova Scotia. The U.S. represents 46% of NPCC’s net energy for load with Canada accounting for 54%. NPCC represents about 70% of Canada’s electric demand.
While New England and New York often hit their summer peaks together because of the proximity of their load centers, “there is some potential” for Ontario’s summer peak to occur at the same time, the report said. “Ambient weather conditions remain the most important variable in forecasting peak demand during the summer months,” it said.
The report included regional snapshots of the changes in generation since summer 2018 and the projected peaks for this year:
New York added a net 127 MW, including 158 MW of wind, with 167 MW of coal generation retirements and 446 MW restored with the withdrawal of Selkirk 1 and 2’s mothball notice. NYISO projects a peak of 32,382 MW, a 522-MW drop from the summer 2018 forecast, because of state energy efficiency programs and the growth of BTM, including retail PV, combined heat and power, anaerobic digester gas, fuel cells and energy storage.
New England added a net of 568 MW, including the dual-fuel Bridgeport Harbor expansion (510 MW), Canal 3 (333 MW) and Medway Peaker (208 MW). Wind and solar generation increased by 135 MW. Entergy’s Pilgrim nuclear plant (680 MW), Massachusetts’ only nuclear unit, is expected to retire by June 1. ISO-NE’s forecast peak is 25,323 MW, 406 MW below last year’s projection. The RTO cited demand reductions from energy efficiency, load management, passive demand response, distributed generation and BTM PV.
Ontario’s generation increased by a net of 1,418 MW, including the Napanee gas-fired generator (985 MW), wind (375 MW), solar (98 MW) and hydro (16.4 MW). About 56 MW of gas-fired generation is retiring. Ontario’s Independent Electricity System Operator forecast a 103-MW increase in peak demand, to 22,105 MW. Conservation savings and distribution-connected generation are expected to partially offset increased demand from economic and population growth.
Québec and the Maritimes, both winter-peaking areas, will see a slight increase, with Québec adding 38 MW of biomass and losing 8 MW of other generation for a net change of 30 MW. Québec is forecasting a 471-MW increase in the peak, to 21,005 MW. The Maritimes expect a peak of 3,255 MW, up 20 MW from last summer.
Entergy’s 680-MW Pilgrim nuclear plant will shut down by June 1. | Entergy
Transmission, Pipelines
Although NPCC expects spare operable capacity (capacity above reserve requirements) of 19,884 MW during its coincident peak the week of July 28, limited transfer capability from Québec and the Maritimes will reduce the amount available to the rest of its territory to 14,954 MW.
Since last summer, NYISO has added the Cricket Valley 345-kV substation — on the Pleasant Valley-Long Mountain 345-kV tie line with New England — to serve the new Cricket Valley combined cycle generating station expected to begin operation after the summer.
Unlike in winter, ISO-NE does not expect natural gas deliverability issues to affect generation. The RTO also can call on 340 MW of active demand resources on the peak.
The RE said it foresees “no significant likelihood” of implementing operating procedures for resource shortages (voltage reductions, and reductions of 10- and 30-minute reserves) during the summer for the expected peak load, a forecast based on the probability-weighted average of seven load levels simulated.
NPCC said operating procedures are available if needed to maintain reliability during severe system conditions and extreme heat simultaneously. The assessment also considered scenarios with extended unit maintenance; reductions in DR; reductions in the ability to import power from neighboring regions; transmission constraints; and widespread and prolonged heat waves with high humidity.
Geomagnetic Disturbances
The RE, which has had operating procedures since 1989 to respond to geomagnetically induced currents (GICs) from solar storms, said it expects “quiet levels” of solar activity for the summer.
“The solar coronal regions are stabilizing as the next solar minimum approaches, with fewer coronal holes and fewer extensions to lower solar latitudes that can sweep higher velocity solar winds toward the Earth,” NPCC said, while acknowledging that sunspot formations are difficult to predict.
While “these rogue events can and do occur,” the report said, “the odds of such an event during any particular week of the coming summer are very low.”
MISO’s Board of Directors will hold a special vote to fill the seat of former Director Thomas Rainwater, who left last month to serve on the board of a for-profit energy company outside the RTO’s footprint.
Rainwater was re-elected to the MISO board late last year after having served since early 2015. His new term was set to expire at the end of 2020.
Reached by telephone, Rainwater said he preferred not to reveal the name of the New England waste-to-energy company where he will assume his new role. MISO viewed the two board positions as possibly conflicting.
“Because this opportunity is in a similar or related industry, he is precluded from also continuing as a MISO board member,” the RTO said in a release. It has removed Rainwater’s entry from its leadership webpage.
MISO bylaws stipulate that the board must hold a special vote to fill a vacancy stemming from a director departing before their term expires. Directors will evaluate a pool of candidates provided by an outside executive search firm. Candidates must have the same type of qualifications as the departing board member, and the selected candidate will serve out the remainder of their predecessor’s term.
The special board vote has not yet been scheduled.
Rainwater has 30 years of experience in both the electricity and natural gas sectors and has chaired the board’s Corporate Governance and Strategic Planning Committee and the Audit and Finance Committee.
“Tom has been very generous in sharing his broad experience with the board, MISO staff and our stakeholders over the last four years,” Chair Phyllis Currie said.
Rainwater said he enjoyed his time on the on the board and was leaving with “nothing but praise” for MISO and its work.
Rainwater’s exit comes as a special Advisory Committee task team is re-examining the RTO’s board qualifications, including the possibility of requiring departing directors to observe a “cooling-off” period before joining a MISO-related organization. (See related story, Task Team Begins Look at MISO Board Rules.) Directors drawn from MISO-related companies are already subject to a yearlong industry moratorium before taking a seat on the board.
