PJM stakeholders unanimously endorsed deadline changes for adjustments associated with finalizing the zonal network service peak load (NSPL) values in Manual 14D and Manual 27.
Ray Fernandez, PJM manager for market settlements development, reviewed updates to the generator operational requirements in Manual 14D and the Open Access Transmission Tariff Accounting section of Manual 27. The Manual 27 revisions were endorsed at Wednesday’s Market Implementation Committee meeting, while the related Manual 14D revisions were endorsed the following day at the Operating Committee meeting.
The revisions are related to the border yearly charge (BYC) — the charge for long- and short-term point-to-point transmission service for points of delivery at PJM’s border, which goes into effect on Jan. 1 of each year.
Fernandez said deadline dates in both manuals conflicted with the deadline dates of the BYC, including ones for the NSPL verification and zonal adjustments.
In Manual 14D, the behind-the-meter generation business rules had a Dec. 1 deadline for a load-serving entity to request a downward adjustment to its NSPL or obligation peak load. PJM proposed revising the deadline from Dec. 1 to Oct. 31.
Changes in Manual 27 included adding clauses to section 5.2 stipulating adjustments that need to be provided to PJM Market Settlements by Nov. 10. Any adjustments provided after the deadline will not be included in the NSPLs for the next calendar year and won’t be used in the BYC calculation.
The manual changes were originally up for endorsement at the July MIC meeting, but Fernandez said stakeholders raised objections with language contained in Manual 14D relating to BTM generation. Fernandez said PJM met with stakeholders to address the issue and were able to reach an agreement on compromise language.
ARR/FTR Market Task Force Poll
Members voted to put the ARR/FTR Market Task Force on hiatus until an independent consultant completes a review of PJM’s auction revenue rights and financial transmission rights market constructs.
Dave Anders, PJM director of stakeholder affairs, reviewed the results of the task force poll taken in July and discussed its recommendation to go on hiatus.
The nonbinding poll had 140 respondents, with 124 voting (89%) to put the group on hiatus until the consultant completes its work.
Anders said PJM is “in the final throes” of awarding the contract for the consultant and close to completing the final negotiation for the scope of work. He said stakeholders should expect an announcement “shortly” on the hiring.
Erik Heinle, of the D.C. Office of the People’s Counsel, asked Anders if stakeholders will have an opportunity to meet with the consultant as they’re working on the report or after it’s completed. Anders said plans are being finalized, but he expects there will be some interaction between the consultant and stakeholders.
Market Suspension Settlements
PJM is exploring the development of business rules to address a market suspension from an emergency or some other incident.
Tim Horger of PJM provided a first read of a problem statement and issue charge to develop business rules. The RTO is looking for approval of the issue charge at the September MIC meeting.
Horger said PJM has been contemplating scenarios of a market suspension with no day-ahead or real-time LMP results and realized that it had limited guidance on how to handle settlements during a suspension.
PJM has never experienced a market suspension event and doesn’t anticipate that it would occur, Horger said, but the RTO feels it needs to create business rules to apply to all possible scenarios.
The key work activities and scope for the issue include:
reviewing instances for which a market suspension may occur;
reviewing consequences to the market associated with a suspension;
reviewing PJM’s existing business rules, along with procedures of other RTOs/ISOs in the event of a suspension; and
reviewing options for how settlements can be determined in the event of a suspension.
Horger said work on the issue is estimated to take about three months and could start as early as October if the issue charge is approved next month.
Sharon Midgley of Exelon asked if the problem statement and issue charge only relate to the energy market or if it could also apply to all of PJM’s markets.
Horger said the “obvious” market seemed to be energy, but it could apply to all markets and would be determined in the key work activities.
Midgley said she thought the duration of the work needs to be considered because of the complexity of the issue. “I don’t think it’s going to get done in three months unless there’s already a solution in mind,” she said.
WEC Energy Group managed a 2-cent earnings per share improvement in the second quarter over last year, with several factors offsetting the COVID-19 pandemic’s economic consequences.
The Wisconsin utility recorded net income of $241.6 million ($0.76/share) compared to $235.7 million ($0.74/share) in the same period in 2019.
“Despite the negative margin impact in this year’s second quarter related to the pandemic, we were still able to achieve quarter-over-quarter earnings-per-share growth,” WEC CFO Xia Liu said during an Aug. 4 earnings call. She said “significantly warmer-than-normal weather,” an increase in the return on equity for WEC’s American Transmission Co. and execution of the utility’s five-year capital spending plan helped blunt the impacts of lower energy demand.
“We remain optimistic and confident in our ability to create value despite the challenges presented by the pandemic,” Executive Chairman Gale Klappa said.
WEC said it has about 11,000 more electric and 27,000 more natural gas customers compared to a year ago. The utility serves 4.5 million customers in Wisconsin, Illinois, Michigan and Minnesota. Compared to the second quarter of 2019, residential electricity sales were up 17.1%, small commercial industrial electric sales were down 8.6% and large commercial and industrial sales were down 12.9%.
WEC predicts continued economic recovery through the end of the year; however, COO Scott Lauber said the company has a plan in place if recovery proves more sluggish.
“We are prepared if the level of recovery would drop back to what we saw in the second quarter. We estimate that the additional impact to the pre-tax margin would be approximately $10 million to $15 million. We believe we could absorb this margin compression through efficiency measures already in place,” he said.
Lauber also said that the Wisconsin Public Service Commission’s April decision to allow utilities to track and defer uncollectible expenses and pandemic-related costs helps the company’s bottom line.
Tatanka Ridge wind farm | Acciona
Klappa said WEC’s $15 billion capital investment plan from 2020 through 2024 remains unchanged.
“We have ample liquidity and no need to issue new equity,” he told investors.
Klappa said WEC’s announcement late last month that it will pay $235 million to acquire an 85% ownership interest in the 155-MW Tatanka Ridge wind farm in South Dakota is part of the capital plan.
However, he reported that construction at the 300-MW Thunderhead Wind Farm in Nebraska hit a snag that will likely delay it “several months” beyond its 2020 year-end in service date. WEC will have a 90% stake in the project.
“We now project a several-month delay because the local utility has paused construction of a substation that’s needed to connect the Thunderhead project to the transmission network. We continue to work with all the relevant parties to minimize the delay,” Klappa said.
CEO Kevin Fletcher said WEC still has designs on more utility-scale solar generation. He said work continues on two solar projects totaling 200 MW for Wisconsin Public Service.
In addition, subsidiary We Energies will still invest — along with Madison Gas and Electric — in construction of the delayed $194.9 million Badger Hollow II solar farm, which is now expected to be in service by the end of 2022.
A month into his new job, CenterPoint Energy CEO David Lesar said in his first quarterly earnings call with financial analysts last week that the company will “simplify the story” as it attempts to overcome recent bad news.
The former Halliburton CEO said CenterPoint would focus on cost management, rebuilding regulatory relationships, evaluating options for its Enable Midstream Partners with OGE Energy and properly aligning its businesses. The Texas Public Utility Commission in February approved a settlement that cut the company’s proposed rate increase for its Houston Electric utility from $161 million to $13 million.
Days before the earnings call Thursday, CenterPoint announced it was immediately merging Houston Electric and Indiana Electric into one organization, saying “the alignment of CenterPoint Energy’s generation, transmission, distribution and engineering areas into one organization” will improve efficiency, operations and reliability.
CenterPoint CEO David Lesar | CenterPoint Energy
“When we say ‘simplify the story,’ as I sort of look back at how we’ve communicated with shareholders over the past several years, we really have not had a consistent message,” Lesar said during the call. “We’ve had a relatively complicated story. We’ve had a lot of [mergers and acquisitions]. We’ve had regulated versus nonregulated.
“A simple message to shareholders consistently executed quarter after quarter will, I think, help regain confidence that shareholders have in us. … Give me some time. Thirty days is not enough time to give you a complete answer, but we’re definitely headed in that direction,” he said.
The road will be a steep one, as CenterPoint reported second-quarter earnings of $59 million ($0.11/diluted share), driven by customer growth, rate relief and “disciplined” operations and maintenance management. A year ago, the company delivered quarterly earnings of $165 million ($0.33/diluted share).
Still, that was better than CenterPoint’s first-quarter report, when it took a $1.2 billion loss after writing off $1.6 billion in losses from Enable. (See Enable Losses Slam CenterPoint, OGE Energy.)
CenterPoint’s stock price closed Friday at $20.41, up $1.36 (7.1%) from its open before the earnings announcement.
“I believe our share price is too low and trades at an unreasonable discount,” Lesar said. “After speaking with many of you in the short time I’ve been here, I believe I have a better understanding for the reasons why this discount exists. You believe we have let you down, and it’s certainly my job to address those issues that concern you as we move forward.”
Lesar joined CenterPoint’s board of directors in May and is leading a Business Review and Evaluation Committee (BREC) conducting a comprehensive, five-month review of CenterPoint businesses, assets and ownership interest.
“I can clearly tell you that nothing is off the table in the BREC review process,” he said.
A CenterPoint Energy serviceman checks a gas meter | CenterPoint Energy
Lesar replaced interim CEO John Somerhalder in July. Somerhalder replaced Scott Prochazka, who resigned after seven years at the helm in February. (See Prochazka Steps down as CenterPoint CEO.)
Lesar left Halliburton in 2018 when he hit the oilfield-service giant’s mandatory retirement age of 65 for executives, a policy he helped install.
Asked about his age, Lesar said, “I see myself as 67 going on 50. I’ve got a lot of energy; I like being a CEO; I like being a leader. I have not set a timeline on my tenure here, but I’ll know it, [and] the board will know it, when it’s right for me to move on. I’m raring to go.”
OGE Survives ‘Challenging Times’
OGE also reported second-quarter earnings on Thursday of $85.9 million ($0.43/diluted share) during what CEO Sean Trauschke called “challenging times.” A year ago, the Oklahoma City-based company reported quarterly earnings of $100.2 million ($0.50/diluted share).
Earnings adjusted for nonrecurring costs came in at 51 cents/share, beating analysts’ expectations of 49 cents.
The ongoing earnings exclude a non-cash charge of $780 million associated with OGE’s impaired investment in Enable. The natural gas midstream company contributed $19 million to OGE’s net income and $18 million in cash distributions, down from last year’s second quarter of $27 million and $35 million, respectively.
“When we created Enable, our goal was to turn it into a standalone entity. From that perspective, it has worked very well,” Trauschke said. “We are always evaluating the value of all of our assets, including Enable. We’re not going to talk publicly about strategic alternatives, because that does not help increase value.”
Like many utilities, OGE subsidiary Oklahoma Gas & Electric has seen its energy usage shift from commercial and industrial consumers to residential during the COVID-19 pandemic. Weather-adjusted residential sales were up 2.3% in the first six months of 2020, while commercial and industrial were both down, 5.6% and 7.6%, respectively. Total weather-adjusted sales are approaching pre-COVID 19 levels but still down 3.2% through June.
OGE’s stock price gained 31 cents after the announcement, finishing the week at $33.28.
WECC waded into California’s wildfire troubles Thursday in an effort to understand how catastrophic blazes could affect regional grid stability and what can be done to protect the bulk power system.
In the first in a series of webinars planned this month, major utilities and transmission operators, including Southern California Edison and Pacific Gas and Electric, briefed WECC stakeholders on fire-prevention planning.
The state’s summer and fall fire season has begun, with several large wildfires burning in Southern California. The largest, the Apple Fire, had burned more than 32,000 acres and was 40% contained as of Sunday afternoon, the California Department of Forestry and Fire Protection reported.
Massive fires sparked by utility equipment killed dozens of people and destroyed thousands of homes in Northern and Southern California during fire seasons in the past three years.
“The timing of this presentation is such that I don’t need to spend a lot of time explaining the risk or the severity,” said Tom Brady, senior manager of emergency response at SCE. “We know that California does have a serious wildfire problem, and it’s something that continues to get worse.
“I recall growing up and remembering a time when there was a start and an end to fire season,” Brady said. But “it seems with today’s current events, that window is extending, and it’s really difficult to say there’s a fire season anymore because there’s always a risk for ignition and spread.”
Ten of the state’s 20 most destructive wildfires have happened in the past five years, posing an “existential crisis” for investor-owned utilities, he said.
WECC should “prepare for and evaluate impacts on the bulk power system caused by extreme natural events,” such as wildfires, drought, flooding and earthquakes, it said, with an emphasis on sharing best practices and lessons learned from individual state and utility experiences across the Western Interconnection.
On Thursday, utility representatives described efforts to head off wildfires, starting this fall.
Brady said SCE had installed 650 miles of insulated wire in the areas at highest risk of fire in its sprawling service territory. The utility plans to install a total of 1,200 miles of covered conductor by the end of this year, he said.
A smoke plume from the Apple Fire, burning in Southern California, rises behind transmission towers. | U.S. Forest Service
SCE also placed 1,200 fuses and remote-controlled sectionalizing devices on its system to interrupt power more quickly and prevent ignitions.
Sectioning off its grid also allows SCE to limit the extent of public safety power shutoffs (PSPS) — the intentional blackouts California IOUs use to keep electrical equipment from starting fires during dry windy conditions.
“We’re able to minimalize, sectionalize and isolate the smallest footprint possible so that we’re not interrupting a lot of customers,” he said.
During a weather event the weekend of Aug. 1, SCE warned hundreds of customers in Kern County they might be subject to power shutoffs. Sectionalizing allowed the utility to limit the number of affected customers to 17, Brady said.
PG&E said it is following the lead of SCE and San Diego Gas & Electric by installing hundreds of weather stations and hilltop cameras in its high-risk fire zones, which make up about half the utility’s 70,000-square-mile service territory.
Matt Pender, director of PG&E’s community wildfire safety program, told the WECC audience that 70% of ignitions in its territory resulted from vegetation contacting power lines (48%) or equipment failure (22%).
The November 2018 Camp Fire, the deadliest in state history, started when a PG&E conductor fell, igniting dry vegetation below. Investigators determined a 100-year-old C-hook had broken after decades of wear, dropping the high-voltage line. (See Ancient C Hook, Financial Manipulation Caused Camp Fire.)
Pender said PG&E had inspected every asset in its high-risk fire areas during six months in 2019. The work, helped by drones and machine learning, might have taken five years under PG&E’s “old regime” of line inspections, he said.
Planes equipped with infrared sensors can now inspect lines at night, he said.
The utility also is using sectionalizing devices, as well as placing generators at substations, to limit the scope and duration of PSPS events this fall. Last year, PG&E blacked out hundreds of thousands of customers for up to a week at a time during multiple events. (See California PUC Approves Microgrids, Fire Plans.)
The company’s goal with PSPS is to “to make them smaller, shorter and smarter this year,” Pender said.
Upcoming Webinars
WECC said its next wildfire webinar, on Aug. 13, will be an in-depth “technical exploration into wildfire preparedness and the bulk power system, including system hardening, technology deployment, advanced weather modeling, weather stations, predictive fire spread modeling and high-definition camera installations.”
A third webinar Aug. 20 will examine the “mitigation, right-of-way and vegetation-management aspects of wildfire preparedness. The webinar will explore actions that entities may take to stay compliant and assist in the preparation and prevention of wildfires.”
Mid-century economy-wide GHG emission reduction targets in New England | E3/EFI
NEPOOL’s Participants Committee on Thursday began taking a new look at how it can adapt market rules to reach New England states’ decarbonization goals with educational presentations on two potential “pathways”: carbon pricing and a forward clean energy market (FCEM).
The pathways discussion — and planning for a parallel “Future Grid” study — resulted from requests by the New England Power Generators Association (NEPGA), New England States Committee on Electricity (NESCOE) and other stakeholders for the region to plot a path toward reaching states’ 2050 decarbonization goals. (See NEPOOL Reviews ‘Future Grid’ Study Requests.)
At the March PC meeting, NESCOE Executive Director Heather Hunt said the organization’s request was intended “to initiate proactive and actionable discussion on the future grid and potential market changes to achieve states’ goals other than through the reactionary changes that have been directed by the FERC and driven the region’s efforts in past years,” according to NEPOOL meeting minutes.
IMAPP Redux?
Carbon pricing and the FCEM were among four long-term proposals considered in detail by stakeholders in the Integrating Markets and Public Policy (IMAPP) initiative in 2016. Carbon pricing foundered because of differing ambitions among the states, with New Hampshire balking at the more ambitious goals of Massachusetts and Connecticut. (See ISO-NE Two-Tier Auction Proposal Gets FERC Airing.)
ISO-NE ultimately adopted a two-tiered capacity construct, the Competitive Auctions with Sponsored Policy Resources (CASPR) to prevent consumers from paying twice for the same capacity through both the Forward Capacity Market (FCM) and subsidies for new, state-mandated supply resources.
CASPR is intended to allow state-sponsored resources to enter the FCM while maintaining competitive prices in the Forward Capacity Auction (FCA). In a substitution auction after the primary FCA, existing capacity resources may transfer their obligations to new resources that did not clear in that first stage because of the minimum offer price rule.
The CASPR substitution auction cleared 54 MW in 2019 and none in 2020. That led some observers to label CASPR a failure, with others calling for it to be redesigned. (See NEPOOL Markets Committee Briefs: May 12, 2020.)
ISO-NE CEO Gordon van Welie has urged patience, telling the PC in March that CASPR is the “next best solution” if the region can’t adopt effective carbon pricing.
“Resource substitution via CASPR will depend on the build-up of economic pressures over time,” he said. He acknowledged CASPR’s performance thus far “has caused concern among some stakeholders that the transition may not occur swiftly enough, or that the lack of substitution may lead to a costly overbuild, leading to a discussion about alternative market designs or structures.”
Forward Clean Energy Market
Kathleen Spees, Brattle Group | The Brattle Group
At Thursday’s PC meeting, Kathleen Spees of The Brattle Group briefed members on its FCEM proposal, which she said could help states achieve their goals without demanding that those goals be uniform. “We developed the Forward Clean Energy Market as one tool that states could use for mobilizing private investment to meet their goals through a competitive market,” Brattle said.
The Brattle proposal resulted from a study funded by the Conservation Law Foundation, Brookfield Renewable Partners, NextEra Energy Resources and National Grid, and one funded by NRG Energy, Spees said.
The proposal acknowledges states’ desire to move from a wholesale market that delivers “reliable, low-cost electricity” to one in which the power is also carbon-free, Spees said.
[Note: Although NEPOOL rules prohibit quoting speakers at meetings, those quoted in this article approved their remarks afterward to clarify their presentations.]
The FCEM would be a centralized, three-year forward auction in which buyers and sellers could voluntarily exchange clean energy attribute credits (CEACs) — a product Spees likened to a renewable energy credit.
Brattle’s proposed Forward Clean Energy Market would be a centralized auction in which buyers and sellers could voluntarily exchange clean energy attribute credits (CEACs). | The Brattle Group
There are two optional variations: One for a “dynamic” CEAC would award more credits to resources that displace more carbon emissions, which would benefit batteries “and focus incentives toward achieving more carbon abatement faster,” Brattle said.
A second option would allow buyers to register a preference for “targeted” resource types to meet carve-outs for preferred technologies such as storage or offshore wind.
The FCEM would assign most fundamentals-based and asset-specific risks to sellers, with features to mitigate regulatory risks and support financeability:
a multiyear commitment period of about seven to 12 years to lock in prices for new resources;
a multiyear forward period to support development and financing of new resources;
a sloped demand curve to reduce year-to-year price volatility and improve revenue certainty; and
the ability for states to make commitments to rely on the market for a minimum time frame and quantity to ensure confidence in the construct.
Spees indicated a willingness to discuss a forward period shorter than three years, which could benefit some renewable developers. But she noted that some clean resources such as offshore wind may also have longer development time frames. She recommended that the FCM and FCEM both be conducted at the same forward period to minimize clearing risks for new resources that seek financing.
Brattle said its simulations estimated that FCEM could save customers $3.60/MWh — or $4.5 billion over 10 years — compared to states’ current practices for bringing clean resources and storage online, including competitive solicitations.
Spees said the FCEM offers several benefits over carbon pricing and traditional RECs.
Carbon pricing maximizes benefits if implemented regionally and economy-wide, which may not be politically feasible in the near term; carbon prices acceptable to all states would likely be too low to achieve the carbon-reduction goals. The FCEM, by contrast, would not require states, cities or companies to agree on a common price or policy goal: States and customers pay to meet their own goals with no cost-shifting to nonparticipants.
Brattle says traditional RECs offer flat incentives over every hour and incentives to offer at negative energy prices during excess energy hours when displacing other clean supply.
“Dynamic” CEACs would scale payments in proportion to marginal CO2 displacement by time and location, incenting the production of clean energy when and where it is most effective in reducing emissions, Spees said. There would be no incentive to offer at negative prices.
Spees said she was uncertain whether the plan would be subject to FERC jurisdiction or outside it like the REC market and the Regional Greenhouse Gas Initiative. Either way, she said, “it’s critical that states have control over their participation. States were very clear when we went through the IMAPP that they want that flexibility.”
Carbon Pricing
Joe Cavicchi of Analysis Group also gave a presentation on the NEPGA-funded carbon pricing study it released in June.
Joe Cavicchi, Analysis Group | Analysis Group
Cavicchi began his presentation with a look at Western Europe, where carbon spot prices, which he said had been ineffectual at about 5 euros/metric ton in 2017 ($5.89), have generally traded between 20 and 25 euros since 2018 ($23.57 to $29.47).
Analysis Group’s study concluded that New England needs a CO2 price of $25 to $35/short ton by 2025, rising to $55 to $70 by 2030, to meet states’ carbon emissions goals. (See Study: $25 Carbon Price Needed to Meet Goals.)
The Analysis Group’s study concluded that New England needs a carbon price of $25 to $35/short ton by 2025, rising to $55 to $70 by 2030, to meet New England states’ carbon emissions goals. | Analysis Group
Cavicchi said a multisector price on carbon could help the transformation to electrification, allowing “a more accurate assessment of the trade-offs when assessing electricity as a fuel for transportation and heating as opposed to fossil fuels.”
It also would allow technology-neutral competition among existing and new zero-emission resources in the electric sector, incentivizing cost reductions and innovation while reducing the need for future state-directed investments. It would additionally reduce the risk of stranded investments that can result when the costs of power from new technologies drop below long-term contract prices.
The study assumed light-duty electric vehicle penetration of 25% in 2025, 60% in 2030 and 90% in 2035. Similarly, it assumed 25% of homes heating with oil, propane or natural gas would switch to electric by 2025, rising to 50% by 2030 and 75% in 2035.
Although a carbon price would increase wholesale power prices, it would not increase consumer costs materially if states rebate the carbon revenues, the study said.
Next Steps
The PC next month will receive education on energy-only markets, such as ERCOT, and alternative approaches to the region’s existing reliance on the FCM for resource adequacy.
The committee expects to begin discussing the pros and cons of the potential solutions in October.
Consent Agenda
Earlier in the meeting, the PC approved the following on the consent agenda:
The amended and restated Services Agreement between NEPOOL and ISO-NE reflecting the evolution in the roles of ISO-NE, NEPOOL and the NEPOOL Generation Information System Administrator, as recommended by the Markets Committee at its July 14-15 meeting.
Revisions to metering requirements for DC-coupled assets: Manual M-28 (Market Rule 1 Accounting) and Manual M-RPA (Registration and Performance Auditing), as recommended by the MC in July.
Revisions to OP-18 (Metering and Telemetering Criteria), which adds requirements for DC-coupled assets, as recommended by the Reliability Committee at its June 16 meeting.
Revisions to Planning Procedure No. 5-1 (Procedure for Review of Market Participant’s or Transmission Owner’s Proposed Plans) in response to the significant increase of proposed plan applications and generator notification forms being processed monthly. Submittals will be required 10 business days before the monthly RC meeting date. Generator application forms have been updated to enable bulk review and summarization, and information regarding the storage component of co-located facilities will be collected to enable improved summarization. The change was recommended by the RC in June.
Experts last week said it’s mostly policy — not technology — holding back widespread adoption of distributed energy resources supported by smart technology.
Those opinions were on display during Austin, Texas-based electricity data research organization Pecan Street’s “Smart DERs — The Missing Link” webinar Friday.
Eaton Research Lab Engineering Specialist Hossein Ghassempour Aghamolki said there’s still a long way to go in smart DER adoption and that the lack of clear, uniform rules is partly to blame.
“We don’t have a universal strategy. … Every market, region [and] state has its own policy,” he said. Part of the problem is that utilities see DERs as a barrier rather than a tool that can be leveraged through smart meters and load forecasting, he said.
“If the business model is there, the technology can catch up,” Ghassempour Aghamolki said.
| Pecan Street
Arnela Smajlovic, manager of Siemens’ Microgrid Management System, said microgrids are already able to bid into markets for dispatch instructions on behalf of the DERs they manage. She said that scenario can be realized today, but it lacks a business model for commercial use and monetized incentives.
“This concept is all well ahead of its time technology-wise. … We need to get over this limited use of microgrids,” Smajlovic said. “We’re waiting for the business model to catch up. … It’s the [state] commissions that have to agree on how we use this technology.”
Shashank Pande, a Siemens product manager, said smart DER controllers have improved drastically over the last seven years but are still somewhat limited in their capabilities.
“There’s a lot of room to grow in the future,” he said, noting that while inverters improve continuously, constraints involving data sharing and a lack of real-time control still hinder widespread DER systems.
In the meantime, Pande said utilities could do more to expand demand response and time-of-use programs.
Bandera Electric Cooperative CEO William Hetherington said his co-op near San Antonio is focused on incorporating DERs in a rural setting, a completely different challenge.
Hetherington said the co-op began offering rooftop solar installations and programs after getting tired of third-party solar companies hoodwinking members by overcharging and underperforming on generation programs.
The result is Tesla Powerwall solar batteries “scattered throughout the hills of Texas,” he said. Hetherington said Bandera uses the Apolloware DER management system to analyze energy use and avoid overloading inverters.
The co-op has installed about 200 Apolloware systems and hopes to add another 1,000 by the end of 2021, he said. So far, the co-op simply monitors and provides pricing signals and doesn’t perform load control. Hetherington said the idea is that customers get to choose when to respond to price incentives.
“For some reason, people get really upset when you turn their AC off,” he joked.
MISO is once again evaluating the effectiveness of the rules behind its scarcity pricing just three years after shelving a similar effort.
Market Design Adviser Michaela Flagg said the RTO will analyze whether to up its value of lost load (VOLL) and change the shape of the operating reserve demand curve. It would likely file revisions in the second quarter of 2021.
“Shortage conditions are not appropriately priced,” she told stakeholders at during a Market Subcommittee teleconference Thursday.
MISO has said it needs to re-evaluate its scarcity and emergency pricing and is exploring a different cost structure under its yearslong resource availability and need (RAN) project. Shortage and emergency pricing has generally been inefficiently low, the grid operator says. (See MISO Exploring Emergency Pricing, Forward Market.)
The current $3,500/MWh VOLL could be understating the value of involuntary load shedding, and the administratively set price doesn’t account for congestion, generation losses or other reserve shortages, MISO contends.
Principal Adviser of Market Design Michael Robinson said MISO first set the VOLL in 2009 based on the class of customers who value uninterrupted electrical service the least and consider shedding load at that price.
“It’s a little bit dated here,” he said. “We established the price that people weren’t willing to pay, and that’s $3.50/kWh. Now, they’re not going to shed hospitals; they’re not going to shed entities that value uninterrupted electric energy service. They’re going to shed customers that value it less … and prefer interruption to those rates. That was the thinking back then.”
MISO’s Independent Market Monitor recommended it ratchet up the VOLL three years ago when it was implementing MISO, IMM Differ over Scarcity Pricing Changes.) Ultimately, MISO didn’t pursue a higher VOLL.
The RTO must consider the consequences to different market segments when adjusting the VOLL, Robinson said, whether that be inconvenience or ruining leisure, to property damage or spoilage of food and other perishables. He said residential and light industrial customers typically suffer the least from load shedding.
Robinson said MISO has never shed firm load because of a capacity emergency since the rollout of the wholesale markets, although it has experienced local load shedding because of transmission outages.
MISO could use a price index or economic research to update the VOLL, Robinson said. “There are a lot of potential approaches.”
However, while MISO could perform its own analysis of end-use customers to establish a price, it would likely be prohibitively expensive and too labor-intensive, he said.
WPPI Energy economist Valy Goepfrich suggested MISO research the retail rates of customers getting paid to interrupt their load. “It might be interesting what you find,” she said.
Monitor David Patton said the understated VOLL means MISO generation still exports to neighboring PJM during shortage conditions. “It creates a mess when you have two [RTOs] valuing electricity at very different levels. … We view this as the No. 1 item for achieving MISO’s RAN initiative,” he said.
MISO’s operating reserve demand curve stays at $2,100/MWh for most scarcity conditions. | MISO
Additionally, MISO’s operating reserve demand curve (ORDC) isn’t nuanced enough to “differentiate shortage severities, especially above minimum requirements,” Flagg said. “A very large portion of the curve is flat.”
The ORDC curve, based on the VOLL, begins at $3,300/MWh, dropping to $2,100/MWh when the RTO clears 8% of its requirement level. At 89%, the level falls to the original $1,100, remaining there until 96% or more of the requirement is cleared, when the curve flattens at $200.
MISO is also reassessing a five-year-old Monitor recommendation that the RTO stop allowing offline resources to set prices. Currently, offline fast-start resources can set extended LMPs during a shortage. The Monitor contends that allowing offline units to set prices artificially suppresses scarcity prices.
Emergency Pricing Fixes on the Way
MISO Research and Development Adviser Yonghong Chen said the RTO will most likely file with FERC before the end of the year to improve its emergency pricing. Chen said that for now, MISO is pursuing a few “simple” fixes that have high impact:
expanding extended LMP eligibility to allow online units with start-up times of four hours or less to set prices during emergencies and emergency alerts;
taking the Monitor’s advice to set an administrative emergency offer floor for emergency resources that respond without an offer; and
updating the emergency pricing structure to reflect the costs of managing congestion on the regional directional transfer limit linking MISO Midwest and South.
Chen said MISO will work on a conceptual design and a benefits evaluation in the fall.
Restoration Energy Pricing Approved
Meanwhile, FERC last month authorized MISO’s new plan to compensate generators that re-energize the grid following a blackout (ER20-1673).
MISO’s compensation for restoration energy relies on last-submitted offers before a blackout as a starting point for pricing, resulting in unique costs based on resource. The RTO will allow for the recovery of start-up costs, emergency purchases and resource-specific energy costs. It would also include recovery for any unusual costs incurred during operation, provided they can be verified by the Monitor. It would also accept after-the-fact updates of offers. (See “Restoration Energy Design Nears Completion,” MISO Market Subcommittee Briefs: Dec. 3, 2019.)
FERC Commissioner Bernard McNamee announced Wednesday he will leave the commission on Sept. 4, reducing the current four-member panel to three pending the confirmation of his replacement, Virginia State Corporation Commission Chair Mark Christie.
President Trump last month nominated Christie, a Republican, and clean energy activist Allison Clements, a Democrat, to the commission. Clements would fill the seat left vacant by Cheryl LaFleur, who departed nearly a year ago. (See Trump to Nominate Christie, Clements to FERC.)
McNamee, whose term expired on June 30, announced in January that he would not seek a second term but agreed to remain on the commission pending his replacement. He is allowed to remain until the end of the current Congress at the end of the year. (See McNamee Declines to Seek Reappointment.)
“I intend for Sept. 4, 2020, to be my last day serving on the commission,” he said in a statement Wednesday. “Since I announced at our January meeting that I would not be seeking another term, I have continued to work diligently and tirelessly on the important work of the commission. After I leave, I will take some time off and search for a job. Serving as a commissioner has been an incredible honor and an experience for which I am extremely grateful. I thank President Trump for having nominated me and the Senate for having confirmed me. I will have more to say before I leave, but needless to say, I thank the chairman, my fellow commissioners, my advisers and staff, the staff of the commission and all of the FERC community for their support and friendship.”
McNamee was confirmed by the Senate in December 2018. The commissioner, who has been commuting weekly to D.C. from his home near Richmond, Va., has said he is eager to spend more time with his wife and teenage son.
Sen. Joe Manchin (D-W.Va.), ranking member on the Senate Energy and Natural Resources Committee, said the panel has not received the paperwork to hold confirmation hearings on the FERC nominees.
“Commissioner McNamee’s announcement that he will be stepping down in a month’s time means FERC will be operating with only three commissioners as opposed to five. This was not the intention of Congress when the commission was created,” Manchin said in a statement. “I am hopeful the committee will act quickly to restore a fully seated FERC once we have the necessary paperwork.”
The commission will maintain its quorum after McNamee’s departure with Chair Neil Chatterjee and Commissioner James Danly, both Republicans, and Democrat Richard Glick.
The MISO stakeholder community appears to support the RTO’s plan to extend the current arrangement on transmission flows between its Midwest and South regions.
Jeremiah Doner, MISO’s director of seams coordination, told stakeholders during a Market Subcommittee teleconference Thursday that the grid operator will file by Nov. 1 to add two years to a cost allocation agreement with SPP and six other parties. MISO agreed to a settlement, which manages the regional directional flows over SPP’s system to connect the Midwest and South regions, with the seven parties in 2016.
MISO Midwest and South | MISO
Doner said the agreement’s extension was generally well received by stakeholders.
But not all were happy.
MidAmerican Energy’s Greg Schaefer said he was disappointed because his company’s location in Iowa means it is shouldering a heavy financial burden for MISO’s use of SPP’s system above its 1,000-MW contract path.
“All the costs are being loaded onto a relatively small number of parties,” Schaefer said. “It’s not surprising that there is a consensus here.”
MISO’s payments to the other parties for regional flows above the contract path are recovered from its market participants using a special rate schedule, which increasingly has put emphasis on a flow-based beneficiary allocation over a load ratio calculation. The current calculation is 90% flow-based and 10% load-based, which will continue into 2023. (See MISO Seeks Extension on Midwest-South Tx Limit.)
The 2016 agreement can be terminated by any party with a year’s notice beginning Jan. 31, 2021. Without an extension or alternative solution, MISO’s flows would be limited to its original 1,000-MW contract path in either direction. The agreement limits MISO to 3,000 MW of flows in the north-to-south direction and 2,500 MW in the other direction.
MISO has said a two-year extension of the original terms will buy time for it, SPP and the other parties to explore eventually reopening the agreement’s terms. MISO has also said it may revisit the idea of constructing new transmission capacity to supplant the agreement. (See “No Midwest-South Tx Solution this Year,” Price Tag Rising for MTEP 20.)
MISO last week said it will begin hunting for solutions to mitigate “significant gaps” between load-modifying resources (LMRs) that clear capacity auctions and what actually shows up to help mitigate emergencies.
The RTO acknowledged during a Resource Adequacy Subcommittee teleconference Wednesday that it had a problem with the amount of LMR-accredited values and what is listed as available to allay demand during summer peak times.
Market Design Adviser Dustin Grethen said that when MISO hit its summer peak in July 2019, 6 GW of LMRs were listed as available, though 11.5 GW cleared the Planning Resource Auction a few months earlier.
Grethen said some of the availability issues result from LMR outages, fear of penalties by overstating load-reducing capability, overly generous LMRs accreditation, voluntary self-deployment or difficulties using the RTO’s availability reporting tool, the MISO Communication System (MCS). Some LMRs that double as emergency demand response enter availability through a separate RTO tool and not the MCS, he said.
Even those reasons cannot explain all the widespread unavailability, Grethen said. He promised MISO would investigate why some LMRs are no-shows after clearing the capacity auction.
Customized Energy Solutions’ Ted Kuhn suggested the grid operator start by checking the MCS’ availability against the metered data LMRs are required to provide.
The LMR availability gap is part of MISO’s ongoing resource availability and need suite of market improvements. The RTO is still gauging which combination of new resource adequacy and capacity market rules it might adopt to reduce the number of maximum-generation emergency events it declares. (See MISO Closer to Seasonal Capacity, Reliability Reqs.)
As part of that, the grid operator will now scrutinize the actual availability of conventional generators and for what they’re accredited. Planning Adviser Davey Lopez said MISO’s planning reserve margin requirement is likely understated because it doesn’t model real-world generation outage scenarios.
Executive Director of Market Operations Shawn McFarlane said MISO didn’t have to resort to LMRs that day. He said the peak would have been higher had not thunderstorms popped up in the northern part of the footprint.
McFarlane also said the pandemic continues to complicate load forecasting, as air conditioning load is likely skewed to more residential use this year than in others because of customers working from home.
“We think there’s some offsetting things that made it very hard to predict summer peak,” he said.
Despite that, McFarlane called the event “one of the most orderly max gens I’ve seen,” as MISO responded quickly and committed more resources appropriately.
MISO President Clair Moeller said not much has changed in the RTO’s modus operandi after the pandemic’s announcement.
“The risk profile doesn’t seem to be changing much,” Moeller said during an Informational Forum on July 21. “The good news is the operational impacts of the pandemic are manageable … and we don’t expect that to change.”
Moeller said load “crept back up” in July and is now about 5% less than its normal load average.
“We’re still learning how to forecast in this new environment,” he said.
