MISO said last week it quickly regained control during its first maximum generation emergency July 7 during a lasting heatwave.
“Uncertainty in both load and supply, impacted by COVID-19, created some challenges that I think we successfully managed,” MISO Executive Director of Real-Time Operations Rob Benbow said during a July 30 Reliability Subcommittee meeting.
Since 2016, the RTO has not completed a single year without a maximum generation event, amassing 10 emergency events in four years. However, summertime emergencies are relatively rare for the grid operator, representing only two of the 10 events.
Benbow said MISO needed “abnormal and emergency procedures” from July 1 through July 20 to navigate tight conditions.
The RTO and its members operated under a hot weather alert July 1-10 and a capacity advisory and conservative system operations — where maintenance outages are asked to be put on hold — July 6-10.
MISO declared a maximum generation event July 7 as high temperatures collided with an unusually large number of unavailable generators in the RTO’s North and Central regions. The emergency lasted from about 1:00 to 5:30 p.m. Load peaked at 116 GW, below the 120-GW forecast.
MISO control room transmission map | MISO
Benbow said MISO anticipated the hot weather and communicated with its members as early as possible.
After the RTO had committed all available resources, almost all of the 600 MW in emergency resources called upon stepped up, he said. MISO also recalled some scheduled transmission outages during the day.
MISO maintained good communication with neighbors PJM, SPP, Tennessee Valley Authority and Southern Co. during the event, Benbow said. The RTO discussed temporarily raising the 2,500-MW MISO South to Midwest regional transfer limit with its southern neighbors, but it ultimately wasn’t necessary.
Following the July 7 event, the RTO again declared a hot weather alert July 16-20 for its Central region.
“Especially the North and Central regions were in the mid-90s for most of early July,” Benbow said.
He noted that MISO would return to the Reliability Subcommittee in August with more information on generation outages and emergency resource performance.
Multiple stakeholders said while the emergency declaration communications to members were clear, it was less clear when MISO terminated its conservative operations and hot weather alerts during July.
Some stakeholders asked if unavailable nuclear generation played a role in the emergency because nuclear plant operators tend to be older and more susceptible to severe COVID-19 infection. Benbow said while one nuclear plant was out during the emergency, he suspected it was “because of mechanical reasons.”
Mild June in MISO
June operations were a different story for the grid operator, with load peaking at just 107 GW on June 30.
June 2020 in the footprint registered at one degree Fahrenheit above NOAA’s 30-year average, according to MISO.
Low natural gas prices also kept prices low during the month.
“The real-time LMP was $18/MWh for the second straight month, a 25% decrease over 2019,” MISO Executive Director of System Operations Renuka Chatterjee reported during a July 21 MISO Informational Forum.
Chatterjee also said load — subdued by the pandemic since mid-March — has gradually begun to rebound. The RTO load bottomed out to about 10% below normal levels during May; the impact has since decreased to about 5%.
“June and July data suggests [that] COVID-19 impact on load and energy is diminishing due to warmer weather, recovering to more historical levels,” Benbow said.
MISO is still using its back-up control center at its Carmel, Ind., headquarters, he said. To date, no operators have tested positive for the novel coronavirus.
Benbow also said its non-core operations employees can now return to MISO offices on a voluntary basis. The RTO currently has no plans to make in-person work mandatory for non-operations staff, but it will likely reevaluate sometime in the fall if the pandemic crisis abates.
Meanwhile, MISO is still rearranging some generation outages after virus-induced barebones work crews caused some utilities to hold off on scheduled spring maintenance outages.
MISO Outage Coordinator Trevor Hines said the RTO is connecting with market participants to discuss rescheduling outages in the fall.
“If you have flexibility to adjust your outage schedule, please reach out to MISO,” he asked members.
Xcel Energy on Thursday reported improved second quarter earnings despite a drop in sales due to the COVID-19 pandemic.
Executives said the Minneapolis-based company had earnings of $287 million ($0.54/share) during the quarter, reflecting lower operations and maintenance expenses, lower income taxes and favorable weather that offset sales declines. That was an improvement from last year’s second quarter, when Xcel reported earnings of $238 million ($0.46/share).
Xcel said its operating companies’ weather-normalized sales for the quarter were down 7.1% compared to last year. Commercial and industrial sales were down 11.5%, but residential sales were up 5.4%.
While executives acknowledged they are seeing some positive economic signals, the company said in its earnings release that “there continues to be substantial uncertainty related to the impact of the COVID-19 pandemic on the remainder of the year.”
The Xcel Energy Center in Minneapolis is home to the NHL’s Minnesota Wild. | Xcel Energy Center
CEO Ben Fowke said Xcel is still on track with its financial plan and reaffirmed the 2020 earnings guidance of $2.73-2.83/share.
“We’ll continue to monitor and manage through the economic uncertainty of this pandemic,” he said.
Xcel recently proposed a $3 billion investment plan in Minnesota. The plan includes $1.8 billion of incremental capital expenditures for repowering wind turbines, a 460-MW solar facility and $1.2 billion of accelerated transmission, distribution and natural gas investment.
Fowke said the plan would create an estimated 5,000 jobs and add more wind and solar to its Northern States Power-Minnesota system.
Xcel’s stock gained 27 cents on the NASDAQ Thursday, closing at $69/share.
ERCOT’s Technical Advisory Committee continues to refine its virtual voting practices, reverting to a combined ballot to reduce the number of roll-call votes and make the best use of members’ time.
Last week, that resulted in the unanimous approval of a ballot loaded with 23 revision requests, two key topics/concepts from the Battery Energy Storage Task Force (BESTF) and seven other items.
Only two nodal protocol revision requests (NPRRs) were voted on separately during TAC’s July 29 meeting. Both were easily endorsed. NPRR984 adds a fourth standard contract term per year for emergency response service (ERS), and NPRR1020 allows energy storage resources with integrated loads that cannot be metered as designed to use internal sensors in calculating the loads.
ERCOT granted the latter change urgent status because it affects ongoing interconnections. The revision will be sent to the Board of Directors for its Aug. 11 meeting.
Staff added clarifying comments to NPRR1020 for the required annual audit of the congestion revenue rights’ (CRR) allocation methodology by the resource entity calculating its ESR’s auxiliary load value. They said their revisions “simply require the audit to confirm that the resource entity’s calculation of auxiliary load ‘does not understate the load value,’ rather than specifying a band of allowable measurement error.”
Tesla’s utility-scale storage plans in ERCOT are boosted by recent Protocol changes. | Tesla
ERCOT has estimated it will cost between $175,000 and $225,000 to make the change. Staff said resource limitations on software developers will delay work on the change until early next year. System implementation would also require revisions to the settlement metering operating guide.
NPRR1020’s sponsor, Tesla, said the urgent status will help it “achieve regulatory certainty and allow its investments to move forward.”
“I think we’ve got Tesla a level playing field with everyone else,” said Bob Wittmeyer, who represented energy-storage developer Broad Reach Power during the early stages of the revision request’s progress through the stakeholder process.
The measure passed without an opposing vote. EDF Trading North America abstained.
TAC endorsed NPRR984 28-1, with independent power marketer Morgan Stanley voting against the motion. Morgan Stanley representative Clayton Greer also indicated he would vote against tabling the change or moving it to the combination ballot, forcing the roll-call vote.
“I’ll vote no on everything with ERS,” he said.
ERCOT said changing the ERS standard contract terms would allow it to better align with typical seasonal conditions and help improve the service’s procurement.
Members, Staff Debate RR Development Budget
TAC approved two key topics/concepts (KTCs) from the BESTF, an initiative to address how to integrate ESRs into the ERCOT system.
Staff first had to allay stakeholder concerns that ERCOT is running out of time and money to incorporate the task force’s work, along with that of the Real-Time Co-optimization Task Force and other projects.
The Advanced Power Alliance’s Walter Reid called for the BESTF and distributed generation to be placed at the top of the ISO’s priority list of development projects
“The work the BEST Force has been doing to get batteries into the protocols needs to be finished,” he said. “We need to facilitate that [investment] … For DG, getting that done is critical.”
ERCOT currently allocates $4 million from its capital project budget to fund revision requests’ development. It has the flexibility to “exceed the target for priority needs,” spokesperson Leslie Sopko said in an email.
“We really do need to consider if there’s some way to relax that $4 million [limit],” Reid said.
Kenan Ögelman, the grid operator’s vice president of commercial operations, cautioned stakeholders against increasing the $4 million allocation.
“Expanding that doesn’t necessarily get [Reid] the relief he wants. The limits … are also resource limits,” Ögelman said. “You also have to look at expanding a budget in this environment of low interest rates and economic uncertainty. The only two options are to move dollars from elsewhere into the $4 million or expand the budget. I think you are at risk of moving dollars out of things ERCOT is doing behind the scene to deliver DG and BEST.”
Staff promised a prioritized list of projects on Aug. 3, with a follow-up discussion during a Protocol Revision Subcommittee meeting on Aug. 13.
The two endorsed KTCs are:
KTC 15-7: Restricts ESRs from withdrawing energy during a Level 3 energy emergency alert and addresses ancillary service responsibility compliance related to the charging suspensions.
KTC 15-8: Grandfathers NPRR989 ‘s reactive power requirements.
ERCOT Updates Price-correction Issue
Dave Maggio, ERCOT’s director of market design and analytics, told the committee staff expects to complete in two weeks a review of day-ahead and real-time market prices following the discovery of erroneous dynamic ratings for three 345/138-kV transformers.
Ratings from unrelated transformers were applied to the three transformers, possibly causing or missing congestion, on operating days between Feb. 12 and July 7, he said. Staff developed a software fix to resolve the issue on July 14.
ERCOT was able to issue a price correction for affected July 7 day-ahead prices. Should staff discover a need for price corrections during the historical period, which is outside the normal 30-day notification period, they will ask the Board of Directors to approve corrections, Maggio said.
Maggio said staff also discovered in May that a software glitch prevented the operating reserve demand curve (ORDC) from properly calculating certain resources’ capacity. Staff corrected the error with a software patch and conducted a detailed review of the ORDC calculations back to when it went live in 2014. They found no additional errors, Maggio said.
ERCOT staff is proposing a revision request to remove requirements that modify DC-tie load zones requiring board approval and a 48-month waiting period after approval. The issue stems from American Electric Power’s recent retirement of a DC tie near the Mexican border in South Texas.
“I think the majority of sensitivity around changes to typical load zone boundaries is because entities serving load to those areas potentially have long-term contracts,” said Reliant Energy Retail Services’ Bill Barnes. “There’s no load served there. It’s just used for export and import [of energy].”
TAC OKs Consent Agenda’s 23 Changes
TAC added NPRR1030 to the combination ballot after agreeing on a desktop edit provided by Greer. Or, as one member jokingly surmised, language provided by a ghostwriter.
The measure changes the CRR auction revenue distribution allocation methodology from a peak 15-minute settlement interval to load ratio share based on adjusted metered load totals for each month. It also makes parallel changes for the CRR balancing account and certain block load transfers for consistency and ease of implementation.
Greer offered language that provided market participants will not engage in DC tie export transactions “that are reasonably expected to be uneconomic in consideration of all costs and revenues associated with the transaction.” The language excludes CRR auction revenue distribution and CRR balancing account allocations.
By making clear such transactions would violate the Protocols, TAC was able to agree on accepting ERCOT’s comments, whose complexity extended to the measure’s implementation timeline from an estimated three months to 12 months. Staff corrected and clarified settlement formulas and corresponding variable definitions.
The edits will be temporarily “grey boxed” and eliminated with NPRR1030’s implementation.
The combination ballot included seven other NPRRs, a Load Profiling Guide revision (LPGRR), four changes to the Nodal Operating Guide (NOGRRs), four other binding document revisions (OBDRRs), a pair of changes to the Planning Guide (PGRRs), three revisions to the resource registration glossary (RRGRR) and one change to the verifiable cost manual (VCMRR).
It also included committee and subcommittee goals, a list of other binding documents and the 2021 meeting calendar. TAC will continue holding monthly meetings on the fourth Wednesday of the month to avoid conflicts with the Texas Public Utility Commission open meetings.
NPRR996: Aligns the Protocols’ hub bus names with the substation names within the ERCOT model.
NPRR1000: Removes the term “dynamically scheduled resource” from the Protocols.
NPRR1002: Establishes energy storage resource “single model” registration and charging restrictions during emergency conditions.
NPRR1003: Replaces all remaining references to the resource asset registration form (RARF) with more general language in anticipation of the RARF’s elimination.
NPRR1004: Creates a new process for determining the congestion revenue rights (CRR) auctions and day-ahead market clearing load-distribution factors by using load forecasting models and existing validation/error correction.
NPRR1015: Clarifies the market system’s submission and reporting changes necessary to complete NPRR863, implement changes to responsive reserve service (RRS) and add ERCOT contingency reserve service.
NPRR1016: Clarifies important reliability requirements for distribution generation resources (DGRs) seeking qualification to provide ancillary service(s) and/or participation in security-constrained economic dispatch.
LPGRR067: Streamlines the assignment of oil and gas profiles by eliminating current processes that are no longer applicable. The revision validates weather sensitivity only for non-interval data recorder electric service identifiers that request the oil and gas flat profile; removes the “TOU Schedules” and “Non-ERCOT Profile IDs” worksheets; and changes the distributed generation profile segment assignment process.
NOGRR195: Addresses the Texas Reliability Entity’s audit recommendations for ERCOT and modifies generator voltage control tolerance bands.
NOGRR208: Aligns the Nodal Operating Guide with the nodal Protocols as modified by NPRR1002. An alignment NOGRR for energy emergency alert will be filed following NPRR1002’s approval to align with the Protocols.
NOGRR209: Replaces all remaining references to the RARF with more general language to align with NPRR1003.
NOGRR212: Aligns the Guide with NPRR1016’s revisions and clarifies DGRs’ reliability requirements.
OBDRR018: Aligns the procedure for identifying resource nodes with NPRR1003’s changes by replacing all remaining references to the RARF with more general language.
OBDRR019: Aligns the requirements for aggregate load resource participation in the ERCOT markets with NPRR1003’s changes by replacing all remaining references to the RARF and updates the process’ change control process with similar other binding documents.
OBDRR021: Aligns the language in the calculation of RRS limits’ procedures for individual resources with the Protocols following NPRR863’s Phase 1 implementation. Also corrects inadvertent errors in the formulas for calculating droop performance to determine RRS limits.
OBDRR022: Incorporates minor edits to the initial other binding document previously approved in conjunction with NPRR933.
PGRR076: Changes the generation resource interconnection or change request (GINR) process to specify that the proposed commercial operations date in the initial GINR application must be at least 15 months after the date of the application; redefines the security screening study output; creates separate reports for the full interconnection study; coordinates reactive study; and clarifies when the dynamic data model should be submitted to meet the quarterly stability assessment prerequisite deadline.
PGRR079: Aligns the guide with NPRR1003’s changes by replacing all remaining references to the RARF.
RRGRR023: Establishes the guide’s provisions and requirements for ESRs identical to those already in place for generation resources and settlement-only generators.
RRGRR024: Aligns the glossary with NPRR 1003’s changes by replacing all remaining references to the RARF.
RRGRR026: Adds a new data point to support implementation of an interim solution representing DGRs and distribution ESRs in the ERCOT network operations model.
VCMRR029: Aligns the manual with NPRR1003’s changes by replacing all remaining references to the RARF.
NYISO has formed a selection subcommittee to find replacements for board members Tom Ryan and Jim Mahoney, whose terms are expiring, CEO Rich Dewey told the Management Committee on Wednesday.
“The process will be very similar to what we’ve done in the past, with the exception of the complications we have as a result of the pandemic and potential restrictions on when and how we can conduct the various interviews,” Dewey said. “If we need to push things a little bit later to accommodate a more effective in-person interview as opposed to doing it online, we will.”
Even if the process is delayed a couple months, the intent is still to have the new members on the board in April, he said.
Demand Curve Reset
The Analysis Group’s final report on the demand curve reset will be posted next week for review at upcoming meetings, along with the ISO management’s draft report, Dewey said. He encouraged people to read and offer feedback on the reports by the August 24 deadline, ahead of discussion at stakeholder meetings in October and a FERC filing in November.
Dewey also mentioned stakeholder concerns that projects coming through the pipeline were appropriately included in consumer impact analyses.
As part of its Grid in Transition initiative, the ISO in April recommended that it implement market design changes through 2024 regarding carbon pricing; comprehensive mitigation review; participation models for distributed energy and storage resources; enhancement of energy and shortage pricing; energy and ancillary services product design review; enhancement of resource adequacy models; revision of resource capacity ratings to reflect reliability contribution; and adjustment of capacity demand curves. (See “Planning the Future Grid” in NYISO Launches Fuel Security Effort.)
Dewey said the ISO had attempted to speed up project development by working on the items piecemeal, but some market participants requested a package approach instead, which the ISO will do.
He said they are committed to doing the impact analyses for the grid reliability and resilience and ancillary service shortage pricing initiatives and getting them to the market participants in the first part of September.
The last item Dewey brought up was the ISO’s project prioritization process in conjunction with the budget.
Because of a “very challenging” budget this year, Dewey said the ISO will not be able to complete implementation of its distributed energy resources software by the 2021 completion date. “So, we are going to move it to 2022,” he said.
Given the “challenging year,” the Management Committee also voted not to conduct a new cost of service study during late 2020-2021 to help determine whether to modify the 72%/28% cost allocation between withdrawal billing units and injection billing units.
Hot Weather Operations OK
The ISO has been operating satisfactorily through the heat and humidity of recent weeks, its first summer without Indian Point Two, the Somerset coal station in western New York, and the Cayuga generating facility north of Ithaca, said Vice President of Operations Wes Yeomans. “And we’re gaining operating experience with the very brand-new Cricket Valley 1,000 MW combined cycle plant … so we thought this would be an interesting summer,” he said.
A heat wave from July 4 to 11 caused record-tying high temperatures in the Syracuse, Rochester and Buffalo areas and a peak load of 29,902 MW, which was surpassed July 27 with a peak of 30,660 MW when another heat wave hit New York City. | NYISO
The state has had three heat waves in July — defined as three consecutive days of 90 degrees. “It feels like they’re all blending together at this point,” Yeomans said.
The first heat wave, between July 4 and 11, hit upstate in the Syracuse, Rochester and Buffalo areas, with cooler weather downstate. Buffalo hit 97 degrees for only the third time in 100 years. Syracuse had seven consecutive days over 90, only the fourth time that has happened in the last century, Yeomans said. The state saw a peak of 29,902 MW.
That changed later in the month with higher temperatures in southeastern New York, Long Island and New York City, he said.
A short heat wave in mid-July ended with a tropical storm across New York City, Long Island and Connecticut, which passed quickly “and was basically a non-event for the bulk power system,” Yeomans said.
The third wave in late July resulted in a peak of 30,660 MW on July 27. “At this point in time that’s the summer peak for 2020, but there’s still a lot of summer ahead of us, and we may exceed that,” he said.
The performance of the generation and transmission system infrastructure has been “fantastic,” he said, promising a more comprehensive hot weather operations presentation at the September Operating and Management committee meetings.
The electric industry has performed well during the coronavirus pandemic but needs to improve its ties to state officials, maintain vigilance on cybersecurity and develop plans for operating control rooms remotely, NERC CEO Jim Robb said Thursday.
“I know my workforce feels very, very stressed in the environment that they’re in because they don’t have the normal work hours that going to and from the office created and because of people having to communicate more electronically,” Robb told attendees of WIRES’ virtual Summer Meeting, adding that NERC’s email traffic increased by 500% in April over February.
“That creates a lot of opportunity for opportunistic actors to play on anxiety and just the distraction that people have” through phishing emails, such as those spoofing Johns Hopkins’ website “saying, ‘click here for the latest information on COVID in your state,’” Robb said. “You can’t take your eyes off the ball for a second. … Our adversaries were very, very active, and I think all of the work that the sector has done to prepare appropriate cyber defenses and encourage proper cyber hygiene among its staff has also served us very, very well.”
Improved Collaboration
Robb said he was pleased with the improved collaboration and cooperation between FERC, the Department of Energy, the Department of Homeland Security, the FBI and NERC and its Electricity Information Sharing and Analysis Center (E-ISAC).
“Relationships across those entities haven’t always been perfectly smooth by any stretch of the imagination. But I think everybody came together during this period of crisis to really work together for the common good,” he said. “The level of information coming out of the government that we could share with the industry through the ISAC is I think at an all-time high in the last three to four months.”
Joseph McClelland, director of FERC’s Office of Energy Infrastructure Security, told the conference that the “unprecedented mass telework,” combined with the use of new procedures and tools, created “a perfect storm” of cyber risks.
Joseph McClelland, director of FERC’s Office of Energy Infrastructure Security | WIRES
He also praised the collaboration between the federal government and NERC, citing the role of the E-ISAC and DOE’s Office of Cybersecurity, Energy Security and Emergency Response (CESER) in distributing information to industry.
“The intel we received, particularly from the Department of Energy … has been timely and very actionable. We’ve been able to share that intel between agencies as well as with NERC and the ISAC. And in turn, the ISAC would share back with us,” McClelland said. “I think adversaries do well when there’s walls and separation between the entities that are affected. COVID, for one reason or another, has helped really dismantle the walls. I’d really like us to build on the models we’re using now and take that further if we can.”
While the industry’s collaboration with federal agencies has improved, Robb said the pandemic highlighted a need to also strengthen relationships with state officials. “One of the things we learned was many things happen at the state level as opposed to the federal level. I think more attention needs to be paid to building … relationships between the asset owners and operators and emergency response departments and infrastructures in the states,” he said.
New Dimension to Resilience
The pandemic has also added a new dimension to the concept of resilience, Robb said. “Most of the time when we think about resilience, we’ve always thought about the physical characteristics of the grid: Do we have enough redundancy built into it? Are we able to recover quickly? I think what this event has taught us is the importance of the resilience of the workforce — the ability to get people quickly into safe places to continue to perform their critical operations.”
The industry isn’t well equipped to deal with “what would happen if you couldn’t get workers isolated safely in a control room and you actually had to run your system remotely,” Robb said. “We published some guidance through the ISAC on how that could be done securely. But I think that’s one of the lessons learned coming out of this: that we spend much more time on which is the way to actually operate the system from a remote posture.”
Disrupted supply chains also are a concern for NERC — for both personal protective equipment and supplies needed for electrical maintenance and repairs. Although the industry hasn’t faced major problems thus far, Robb said, “people are going to have to think about inventory management differently.”
Continuity plans will need to be revised based on lessons learned, he said. NERC’s 2010 report on high-impact, low-frequency event risks included a chapter on pandemic planning.
“I think it was a great starting point for the industry, but I don’t think any of us, when that was put in place, contemplated something as long-lasting and impactful and devastating as the COVID [pandemic] has been. I think at the end of this — whenever the end is — we will need to take a very thorough look back and log all the things that we wish we had done earlier on,” Robb said.
“Everybody had pandemic plans. They were all exercised on occasion. I think now that we’ve lived through [COVID-19], we might exercise those with more purpose than we might have before.”
In its first post-bankruptcy earnings report, PG&E Corp. said Thursday it expects stronger financial performance going forward, as it improves its wildfire-prevention efforts and employs more limited public safety power shutoffs this fire season.
But PG&E reported GAAP losses of $3.73/share in the second quarter, driven mainly by $2.5 billion in costs to exit bankruptcy and help pay for the 2019 Kincade Fire.
The earnings call was led by PG&E Director and interim CEO Bill Smith, who replaced Bill Johnson after he retired June 30. (See PG&E Names New Board of Directors.)
It was the first live earnings report in many months. PG&E, one of the nation’s largest utilities, filed for bankruptcy in January 2019 following two years of devastating wildfires ignited by its equipment. It emerged from Chapter 11 reorganization July 1.
“Today’s call marks a milestone for us, and we’re excited to share our post-emergence vision for the coming years,” Smith said. “We’ve emerged from bankruptcy as a stronger company. The complex legal matters are now resolved, and major regulatory cases establishing our revenues are either approved or settled.”
Smith said PG&E plans to return to investment-grade status after credit ratings agencies reduced its corporate debt to junk bond status during bankruptcy.
Even in June, as the company prepared to exit bankruptcy, the three major ratings agencies — S&P Global Ratings, Fitch Ratings and Moody’s Investors Service — assigned sub-investment-grade status to billions of dollars in PG&E debt, including $4.75 billion in new debt it issued to help pay for its nearly $60 billion reorganization plan.
Share Price Lags
The company’s stock rose slightly during Thursday’s 11 a.m. ET earnings call from $9.12/share at the start of trading to $9.48 at 11:15 a.m., before falling back to $9.29 by 4 p.m.
PG&E’s share price has lagged since the COVID-19 crisis started in March. It fell further in June as the company prepared to issue more than $5 billion in new equity, diluting its existing stock value.
Interim CEO Bill Smith delivered remarks during PG&E’s first earnings call in months. | PG&E
The company is hoping to recover billions of dollars in lost value.
A month before the Northern California wine country fires of October 2017, PG&E’s stock had hit a high of $70.64/share. It plunged as the utility’s equipment appeared the likely cause of most of the 21 major fires during dry, windy conditions in Napa and Sonoma counties.
The company’s stock fell further after it acknowledged one of its aging transmission lines likely started the Camp Fire in November 2018, killing 85 people and leveling much of the town of Paradise, Calif. The corporation pled guilty to 85 felony counts in December related to the fire. (See PG&E Sentenced; Bankruptcy Plan Approved.)
Shares hit a then-low of $7.23/share after the company announced it would declare bankruptcy and reached a historic low of $3.80 on Oct. 28, 2019, three days after another of its transmission line appeared to have caused the Kincade Fire, which tore through the Sonoma County wine region, burning nearly 78,000 acres and destroying 374 structures.
The California Department of Forestry and Fire Protection on July 16 said that its investigation had determined a PG&E high-voltage line running from a geothermal plant near the town of Geyserville had started the fire.
The company still faces lawsuits and a possible criminal investigation from the blaze. In its quarterly report to the U.S. Securities and Exchange Commission on Thursday, PG&E said its “financial condition, results of operations, liquidity and cash flows could be materially affected as a result of the 2019 Kincade Fire.”
Fire-prevention Efforts
With California’s late summer and fall fire season just around the corner, PG&E’s worst enemy would be a new fire started by its equipment. The ratings agencies said in June that the risk of another catastrophic wildfire was a primary reason for keeping PG&E’s credit rating so low.
In Thursday’s earnings report, Smith and other PG&E executives cited ongoing efforts to reduce the risks of wildfires, including grid hardening and enhanced weather monitoring.
PG&E said it is on track to meet the goals it laid out in its 2020 Wildfire Mitigation Plan, submitted to the California Public Utilities Commission.
The utility said it has completed more than half of the system-hardening work it committed to this year by undergrounding or installing stronger poles and covered conductor along 122 circuit miles, a small portion of its huge system.
PG&E owns 106,681 circuit miles of distribution lines and 18,466 circuit miles of transmission lines. More than 50% of its 70,000-square-mile service territory is in high fire risk areas.
The company also said it has completed 70% of its enhanced vegetation management program this year.
“PG&E has reviewed more than 1,200 miles of distribution and lower-voltage transmission lines and taken necessary action to trim or remove hazards and expand rights-of-way,” it said in a news release.
The utility said it fell behind on its “situational awareness” efforts because of supply-chain disruptions caused by the pandemic but still installed 144 weather stations and 60 high-definition cameras in fire-prone areas.
Advanced analytics and artificial intelligence are being added to its fire-prevention arsenal, PG&E said, along with technology from Australia that can de-energize a falling overhead line before it hits the ground, sparking dry vegetation.
The company has promised it will try to keep its public safety power shutoffs shorter and more limited geographically this fire season. Last year, the company shut off power to hundreds of thousands of customers, for as long as a week in some cases, prompting a public and political backlash. (See California Officials Hammer PG&E over Power Shutoffs.)
PG&E understands that vows to change, apologies and financial settlements with fire victims will no longer be enough, Smith said in a statement Thursday.
“We know that what’s needed now is action,” he said. “We will continue to work tirelessly to combat the growing threat of wildfires and keep our customers and communities safe.”
The impact of the coronavirus pandemic on electric demand could lead some state regulators to reconsider their transmission rate structures, former FERC and North Dakota Public Service Commissioner Tony Clark told WIRES’ virtual Summer Meeting on Thursday.
Clark, a former president of the National Association of Regulatory Utility Commissioners, said state regulators took a “do no harm” approach at the beginning of the pandemic by suspending service cutoffs for nonpayment.
Tony Clark, Wilkinson, Barker & Knauer | WIRES
Now, utilities and regulators are trying to determine how to deal with the bad debts that have mounted as many unemployed become unable to pay their electric bills. Utilities will likely be permitted to create regulatory assets for those debts and then engage with regulators in proceedings about recovering the debts, Clark said.
“Either government steps in and picks up the tab for all this societal debt that the utilities are holding, or … you allow the utilities to recover that through rates over some period of time,” Clark said. “But there really aren’t a lot of other options besides some variation of those two concepts.”
The long-term impact, he suggested, could be a change in the “political tradeoff” that has seen many jurisdictions collect much of their utilities’ fixed costs through volumetric charges.
“When you have something like the pandemic hit and volumetric usage drops off dramatically, at least for some classes of customers, that means you’re going to have a utility cost-recovery system that doesn’t work anymore,” Clark said. “So, this is what regulators will be dealing with: trying to figure out what the new normal is … in terms of volume. I think it leads regulators to a place where they begin to look more seriously at trying to recover fixed costs through fixed charges and variable costs from variable charges, which is probably where we should have been all along.”
Zach Smith, NYISO | WIRES
Clark said commercial and industrial customers’ subsidization of residential ratepayer use also could be reconsidered.
Zach Smith, vice president of system and resource planning for NYISO, said New York power demand is about 7% lower than normal following the “astounding” 33% drop in GDP in the second quarter.
While a typical recession is often followed by two years of recovery, this downturn is the result of the “externality” of COVID-19, Smith said. “So there is a real debate about what that recovery is going to be, [and] it’s really a huge question mark as to how this energy demand is going to recover.”
Chatterjee on Order 1000 Disappointment
FERC Chair Neil Chatterjee, speaking via satellite phone from Montana, briefed the conference on the commission’s May order on return on equity and its Notice of Proposed Rulemaking on transmission incentives.
Chatterjee said he was confident Opinion 569-A on ROE “better reflects investor expectations … and is also legally durable so that it will stand up if challenged in court.” The commission said it would consider three inputs in its ROE calculations: the risk premium model, the discounted cash flow and capital asset pricing model. (See FERC Ups MISO TO ROE, Reverses Stance on Models.)
Chatterjee said “one of his great disappointments and frustrations” has been the inability to address Order 1000’s failure to produce the “innovation and cost discipline” he hoped would result from opening transmission development to competition.
“We’re at a point now where I think Order 1000 clearly isn’t delivering the results that were initially envisioned,” he said. “That, unfortunately, is where the agreement ends. What to do about it is a very challenging thing.
“What I’ve just come to recognize [is that] with all of the other complex challenges that we are facing, to try and reopen Order 1000 right now would be biting off more than we could chew. So, what I’m focused on is interacting with stakeholders to see if there are targeted fixes that the commission can examine.”
Transmission Incentives NOPR
FERC’s controversial NOPR on transmission incentives, which generated much comment and criticism in its docket in July, was the subject of WIRES’ final panel, moderated by Nina Plaushin, vice president of ITC Holdings. (See Tx Incentive NOPR Leaves Many with Sticker Shock.)
NARUC Executive Director Greg White, a former Michigan regulator, said he welcomed a fresh look at the policy. “I’m not convinced that FERC’s past incentives have been very effective,” he said, noting he was speaking for himself and not on behalf of NARUC.
White was particularly critical of the adder for participation in an RTO, which FERC has proposed increasing from 50 to 100 basis points. He agreed with Commissioner Richard Glick’s observation that transmission owners are unlikely to leave RTOs and noted that some states require their utilities to participate.
Speaking on FERC’s transmission incentives were (clockwise from top right) Nina Plaushin, ITC Holdings; Julien Dumoulin-Smith, BofA Securities; Julia Frayer, London Economics International; and NARUC Executive Director Greg White. | WIRES
Julia Frayer, managing director of London Economics International, spoke about her whitepaper, which WIRES submitted with its comments on the NOPR. The paper contends TOs take on risks by joining RTOs because of the grid operators’ “governance and operational nature.” The paper also made the case for a transmission technology incentive.
Julien Dumoulin-Smith, managing director at BofA Securities, gave a passionate, highly caffeinated seven-minute speech, beginning with his argument for why “people’s historical understanding of how to establish ROEs are upside-down.”
He ended by urging transmission planners to begin thinking about the role hydrogen could play under electrification that doubled renewables and the size of the grid.
“How do you see the hydrogen role evolving? Is it a midstream industry? Do you do things [with hydrogen] and then send it on electricity? It’s an open question. We’ve seen these tensions between gas — gas by wire and gas midstream itself,” he said.
Transmission planning should reflect how “you think about a distributed or centralized hydrogen economy 30 to 40 years from now,” he said. “I throw that out as my big-picture thought. Take it or leave it.”
Energy experts and officials from New England and New York on Wednesday debated how the power sector can deliver clean, affordable electricity as society moves to a low-carbon and increasingly electrified economy.
All but one of the four panelists were affiliated with Columbia University’s Center on Global Energy Policy (CGEP), which hosted the webinar.
Melissa Lott, Center on Global Energy Policy | Center on Global Energy Policy
The exception was Peter Fox-Penner, founder and director of Boston University’s Institute of Sustainable Energy, who set up the discussion by summarizing his recent book, “Power after Carbon: Building a Clean, Resilient Grid,” published in May by Harvard University Press.
CGEP senior research scholar Melissa Lott moderated the panel and invited the audience to vote on questions, such as whether the lack of a coherent federal decarbonization policy is the biggest obstacle to progress in transitioning to a clean economy. (42% of respondents said “yes.”)
Following is some of what we heard at the meeting.
A Bigger Boat
“We’re going to need a power industry about half again as large as we have [by 2050], maybe as large as double if you take all of current uses,” Fox-Penner said. “If you account for the greater efficiency that electrification brings, and you apply it to every single BTU of energy use in the United States, you about double electricity use.”
Peter Fox-Penner, Boston University | Center on Global Energy Policy
Variable factors on power sector growth include how much electricity is used to produce hydrogen or for direct carbon extraction from the atmosphere, he said.
“We have a big job ahead of us, but that amount of growth in the size of the power grid in 30 years is very manageable,” Fox-Penner said. “The power industry in fact has grown that fast; during the 1940s and ’50s and ’60s, it grew almost exactly that fast, so we know we can do that. But it’s not easy, and it takes planning.”
Distributed energy resources alone will not be able to supply the power needed in the coming decades, he said.
“There are no surprises here; it’s going to come from resources of wind and solar PV,” Fox-Penner said. “I think advanced nuclear will play a role, and certainly current nuclear is playing a role, accounting for 20% of our supply. Gas with carbon capture and storage is coming along strongly.”
Many other resources will contribute less, he said, and then there are “important balancing resources such as large-scale, storage-flexible load and the grid itself, all of which are really far and away the most important and difficult part of achieving a decarbonized grid.”
Willingness to Sacrifice
Cheryl LaFleur, ISO-NE | Center on Global Energy Policy
“I start from the premise that the U.S. has achieved far less decarbonization than we’re capable of, given our financial, technical and natural resources,” said former FERC Commissioner Cheryl LaFleur, now a CGEP fellow and member of the ISO-NE Board of Directors.
LaFleur cited several big, systemic issues impeding progress.
“The first one … is the lack of a national consensus that climate change is a problem and thus the lack of a strategy or goal,” LaFleur said. “Quite simply, if you’re not trying to do something, it should be no surprise that you’re not getting maximum success.”
The second factor is disaggregated decision-making among the different federal agencies and state and local governments, all pursuing policies that are sometimes working at cross-purposes, she said.
“In particular, a lot of people have the say over what gets built, where it gets built and who pays for it,” LaFleur said. “Finally, I think there’s a mismatch between people’s expressed support for climate action and their willingness to do something about it, and I don’t mean just not using plastic straws, but allowing resources, whether they’re utility-scale renewables or transmission to connect renewables, to be built near them.”
One of the more difficult problems will be developing cost-effective, carbon-free resources to balance renewables, but even the so-called “easy” things like solar and wind are difficult to site and build, she said.
LaFleur quoted Fox-Penner’s book as recommending “improved cost allocation and interregional planning for transmission,” saying “those were the exact words in FERC Order 1000, which is nine years old … but has been very little utilized in practice, particularly in states agreeing on the allocation of costs for public policy resources and also the introduction of competitive transmission processes.”
Regarding planning among states, LaFleur said that if Congress wants to require regional planning, people should make use of regional planning structures that already exist and do some things well.
Clockwise from top left: Peter Fox-Penner, Boston University; Richard Kauffman, NYSERDA; Cheryl LaFleur, ISO-NE; Melissa Lott, Center on Global Energy Policy; and David R. Hill, NYISO. | Center on Global Energy Policy
“I don’t know if it’s a stepping stone or an alternative to an RTO, but I strongly believe that the best thing is to let them decide,” LaFleur said. “I’d love to see it develop from an imbalance market to a day-ahead or something stronger, but even if it stays at one of those stops, it’s still a big improvement on using resources over a broader geography, which is especially needed in the West.”
On a separate question as to whether she was worried about the differences between RTO and non-RTO regions when it comes to regional policy, LaFleur said, “Yes, every time FERC upped the ante and required another thing for the RTOs to change their tariff in a slightly different way, I worried we were creating more and more of a divide between the two different Americas, in the organized markets and in the bilateral markets.”
Don’t Wait; Act Now
CGEP scholar Richard Kauffman, chair of the New York State Energy Research and Development Authority and board chair of San Francisco-based Generate Capital, said he prefers market forces over regulatory fiat.
Richard Kauffman, NYSERDA | Center on Global Energy Policy
“By market forces, I’m not talking about FERC-like wholesale market structures, which are quite anachronistic to the power sector. I’m talking about market forces that exist elsewhere in the economy,” Kauffman said. “Our sector has been in a kind of bubble, away from forces affecting other sectors of the economy.”
Investment banker and project consultant Gary Krellenstein said that Kauffman correctly pointed out that the system capacity factor in New York is only 54%. “But given the physical constraints on usage, such as seasonality and weather, won’t using more renewables further decrease system capacity factor? More reliance on intermittent renewables implies a lower capacity factor and higher capital costs.”
Kauffman agreed that if the regulatory and utility business model doesn’t change, average capacity utilization will indeed go further down.
“We may not like flying, but the industry has moved from 50% to 90% average capacity utilization as a result of technology adoption, business model change and flexible pricing,” Kauffman said. “This has resulted in much lower costs for customers. The same lessons are true for the chemical and other manufacturing industries. We need to adopt these lessons to the regulatory utility sector, which has been protected by the golden cage of regulation.”
On the other hand, energy efficiency and demand response are not businesses, but activities forced on utilities by regulators, he said.
David R. Hill, NYISO | Center on Global Energy Policy
David R. Hill, CGEP fellow and a member of the NYISO Board of Directors, recommended avoiding making the same mistakes that led to stranded asset costs in some cases when regulators opened transmission development to competitive markets.
“I’m a skeptic of grand master plans, and I think it’s a mistake to hold our breath and wait for them, or to use the lack of one as the reason why we’re not doing things,” Hill said. “Instead, there are so many tools we already have and have available, some of which we haven’t tried to use here in terms of coming up with the least-cost, fastest, most effective way of solving some of the problems we’re talking about.”
Hill agreed with Kauffman on looking for market-based solutions.
“In the New York ISO, we’re trying to put forward a carbon-pricing initiative as a part of the ISO’s program, and of course we’re trying to slog through what it takes to get support for that to make it happen,” Hill said. “FERC is having its carbon pricing conference in September, and there’s a lot that could be done with existing authority. Waiting for Congress to pass laws or to do something else — we should not wait on that.”
Fox-Penner said he is “convinced that markets work much better if government does a certain amount of planning and a certain amount of adjudication of the markets.”
Hill said it would pay to go back to the fundamentals of why wholesale power markets were opened in the first place, which was to solve problems. The electricity market effort was not a complete success, but the industry can learn from experience and not make the same mistakes as transportation electrification gets underway, he said.
“The lack of innovation on the consumer side of the electric business is amazing,” Hill said. “We need to think about what are the models that can best bring about the innovation. … So much of what happens on the wholesale side now is walled off from consumers, leaving them unable to see it or participate in it.”
On the same day Larry Householder (R) was voted out as speaker of the Ohio House of Representatives, the longtime legislator was officially indicted by a federal grand jury on a racketeering conspiracy charge related to the alleged $61 million bribery scheme by FirstEnergy to pass and maintain a billion-dollar nuclear plant bailout.
In a unanimous decision, House members voted to remove Householder from the powerful position more than a week after his arrest for his alleged involvement in a three-year scheme resulting in the passage of House Bill 6, which authorized zero-emission credits for FirstEnergy Solutions’ (FES) Perry and Davis-Besse nuclear plants. (See Feds: FE Paid $61M in Bribes to Win Nuke Subsidy.)
The members quickly approved the measure without any debate in the Thursday morning session. Householder, who still retains his seat in the house despite calls for his resignation, was not present for the vote. Rep. Bob Cupp, a former Ohio Supreme Court justice, was elected speaker by a 55-38 vote.
Ohio Speaker Larry Householder declined to comment as he left federal court in Columbus, Ohio, after his arraignment July 21. He was removed as speaker on July 30. | WKYC
Republican House leaders, including Speaker Pro Tempore Jim Butler, who was vying for Householder’s position, issued a statement after the vote.
“Today’s strong bipartisan vote to remove Larry Householder as speaker of the Ohio House of Representatives is not a decision any member of the House took lightly, but it was clear that Mr. Householder is unable to effectively lead the House,” the statement said. “This is an opportunity to move the House forward and continue our work to move Ohio forward.”
Legislators on the other side of the aisle were also quick to tout Thursday’s vote for removal.
“The criminal allegations detailed last week and the indictment handed down today made it clear that Larry Householder could no longer serve as speaker of the People’s House,” said House Minority Leader Emilia Strong Sykes (D). “His removal is the first step toward restoring public trust, which for the second time in three years has been eroded by Republican leadership that sees itself as above the law.”
Coming immediately after the House vote, U.S. Attorney David M. DeVillers, of the Southern District of Ohio, announced the grand jury indictment of Householder and four others, including: Matt Borges, a lobbyist who previously served as chair of the Ohio Republican Party; Jeff Longstreth, Householder’s longtime campaign and political strategist; Neil Clark, a lobbyist who owns and operates Grant Street Consultants and previously served as budget director for the Ohio Republican Caucus; and Juan Cespedes, a multiclient lobbyist.
Jennifer Thornton, a Department of Justice spokeswoman, said the charges in Thursday’s indictment were the same as the ones issued in the July 21 criminal complaint.
According to the indictment, from March 2017 to March 2020, the “enterprise” headed by Householder received millions of dollars in exchange for his help in passing H.B. 6. “Company A,” which references FirstEnergy in the indictment, filtered nearly $61 million to a 501(c)(4) nonprofit organization called Generation Now, created by Longstreth and controlled by Householder, to elect him to the speaker role and to support House candidates loyal to him.
Money from Generation Now was also used to fund television advertisements and mailers supporting H.B. 6, according to the indictment. Finally, money was used to defeat a ballot referendum that sought to overturn the law — including bribes to those working for the referendum.
The affidavit filed in support of the criminal complaint also alleges that money passed from “Company A” through Generation Now was used to pay for Householder’s campaign staff, which would otherwise have been paid by his candidate committee, Friends of Larry Householder. It also alleges Householder received more than $400,000 in personal benefits, including funds to settle a personal lawsuit, payments on a house he owns in Florida and to pay off credit card debt.
The racketeering conspiracy charge is punishable by up to 20 years in prison. Thursday’s indictment also seeks forfeiture of any property derived from the racketeering activity and the proceeds from several different bank accounts of Generation Now.
“Dark money is a breeding ground for corruption,” DeVillers said in a statement. “This investigation continues.”
Second Repeal Effort
Meanwhile, two Democratic House members last week proposed repealing part of the state’s two-year budget bill that allows FirstEnergy’s Ohio utilities — Ohio Edison, Cleveland Electric Illuminating Company and Toledo Edison — to consider the profits made by all three subsidiaries averaged together when determining whether they have earned “significantly excessive” profits.
Cleveland.com reported that the provision was added by an unknown House member to the budget bill signed by DeWine last year.
MISO and SPP regulators are close to asking the RTOs for improvements to transmission operations on their seam as their market monitors wind down a study on the subject.
The short list of recommendations could arrive at an opportune time, with both RTOs signaling a willingness to usher in a new era of cooperation.
The Organization of MISO States (OMS) and SPP’s Regional State Committee (RSC) will discuss which recommendations could be most beneficial when their Seams Liaison Committee (SLC) meets on Aug. 10 and Sept. 14. Texas Public Utility Commission Chair DeAnn Walker, who leads the RSC side of the SLC, said July 27 that the committee is moving from the study phase to recommendation selection.
The MISO Independent Market Monitor and the SPP Market Monitoring Unit have recently summarized what they believe are the more effective actions the RTOs can take based on the study.
The SLC has indicated it will urge the RTOs to work together and quickly apply the easiest fixes that don’t entail major software upgrades. The improvements could include implementing a test based on the available flow relief an RTO can provide the other, an automated means to control power swings on constraints, and better testing and activation of flowgates near the seam.
The monitors said the RTOs cause large power flows on each other’s systems. Better managing them could save more than $30 million of the $150 million in annual congestion costs that the RTOs’ flowgates have accrued.
An Age of Teamwork?
SPP CEO Barbara Sugg has prioritized a better relationship with MISO since assuming her leadership position in January. That could bode well for the RTOs’ willingness to implement seams improvements, should the SLC recommend them.
During SPP’s quarterly stakeholder meeting July 27, Sugg said she’s “decided to take ownership of [seams issues] and work directly with MISO.” Sugg, joined by COO Lanny Nickell, has met several times with MISO CEO John Bear and President Clair Moeller.
“I have high hopes for the two companies working together to resolve issues on the seams and that the discussions will be very beneficial to both sides,” Sugg said.
“I commend her for working with John Bear on that relationship, which quite frankly has been lacking in the past,” Walker told SPP stakeholders. “Part of a goal of mine — and some of that has already been accomplished — has been better interaction between MISO and SPP staff, and now the boards.”
SPP Board Chairman Larry Altenbaumer concurred, saying the SLC “was a bit of a catalyst to try and foster an improved relationship at all levels with SPP and MISO.”
MISO also confirmed it was meeting with SPP senior leadership to “discuss opportunities to work more collaboratively on key seams items,” according to spokesperson Allison Bermudez. She said MISO looks forward to providing feedback on the recommendations and would possibly route some of them to stakeholder groups for solution development.
The monitors’ study also concluded that SPP should improve its modeling of MISO’s market-to-market (M2M) constraints. MISO, on the other hand, should eradicate its generator shift factor for low-voltage constraints and M2M constraints, the study said.
But the monitors didn’t find significant value in a joint dispatch model, saying the RTOs might save about $17 million per year, or 0.1% of the region’s total production costs. MISO Monitor David Patton said he believes that the benefits of joint dispatch aren’t being fully captured because MISO assumes optimized congestion management across the seams.
But Patton has said the RTOs could be close to implementing better interface pricing, if SPP will actively model MISO’s transmission constraints at the seams. Patton said MISO’s interface pricing with SPP could be better than its pricing with PJM because SPP is generally better at modeling the MISO transmission system than PJM.
“SPP has a pretty good depiction of the MISO system,” Patton said during July’s Market Subcommittee meeting.
Both monitors concluded this spring that a coordinated transaction scheduling process, like MISO uses with PJM, doesn’t stand to help much unless the RTOs rethink fees they impose on one another. (See Monitor Casts Doubts on MISO-SPP CTS Benefits.)
On the other hand, SPP’s MMU found that unreserved use charges are rare along the seams and don’t negatively impact the systems’ efficiency.
Charges that occur are usually because of outages or extreme weather events, MMU Executive Director Keith Collins said during a recent study update.
