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November 6, 2020

Exelon Discusses Potential Generation Spinoff

Exelon officials confirmed during a third-quarter earnings call Wednesday that the company is considering spinning off its generation business into an independent company.

CEO Christopher Crane said the company began a review of its corporate structure earlier this year with the help of outside advisers. The review resulted from the evolving landscape of the generation business and the shrinking of “competitive integrated companies in our sector,” Crane said.

The news comes just a few months after Exelon announced the closing of its Byron and Dresden nuclear plants in Illinois, which face hundreds of millions of dollars in revenue shortfalls because of declining energy prices. (See Exelon to Close Ill. Nukes as Gov. Touts Clean Energy Plan.)

Crane said the goal of the review is to see whether two healthy companies could be created that can stand on their own financially and “provide the support needed for the balance sheets, the customers, the employees [and] the shareholders as we go forward.”

“I want to emphasize that the separation of the companies would involve addressing some complex operational, financial and regulatory issues,” Crane said. “No decision has been made, but we continue to do the work to determine the best outcome for our stakeholders.”

Nuclear Plants

The Byron nuclear plant is slated to close in September 2021; the Dresden plant will shut down in November 2021; and Mystic Units 8 and 9 will retire at the expiration of its cost-of-service commitment in May 2024. (See FERC Rejects Exelon’s Mystic Complaints Against ISO-NE.)

Exelon said it experienced a “$500 million impairment of its New England asset group and non-cash charges for Byron, Dresden and Mystic of $260 million.” It said the charges were related to materials and supplies, employee-related costs, construction and other items.

Crane said Byron and Dresden produce 30% of Illinois’ carbon-free electricity while also employing more than 1,500 full-time employees and paying $63 million in annual taxes. He said that without the plants and others at risk of closing, Exelon customers could pay $483 million in increased annual energy costs under PJM’s capacity market structure with an increase of 70% in greenhouse gas emissions.

(See Clock Ticking on Exelon Illinois Nukes Under MOPR.)

“Despite being among the most efficient, reliable units in the U.S. nuclear fleet, they face revenue shortfalls, declining energy prices, lack of capacity revenue and market rules that allow fossil plants to underbid clean energy resources in the PJM market auction,” Crane said.

Earnings

Exelon said it earned $501 million ($0.51/share) for the quarter, 35% less than the $772 million ($0.79/share) it earned for the same period last year. The company brought in $8.85 billion in total revenue for the quarter, slightly less than the $8.93 billion it posted last year.

CFO Joseph Nigro said the company was raising its year-end earnings guidance to $3 to $3.20/share from $2.80 to $3.10/share. Exelon has invested $4.5 billion so far this year to improve infrastructure and increase grid reliability, he said.

Shares of Exelon were down 25 cents, or 0.59%, to $42.22 as of closing on Wednesday.

November 6, 2020March 9, 2025

NERC Board of Trustees/MRC Briefs: Nov. 5, 2020

NERC Board Chair Roy Thilly | © ERO Insider

NERC’s Board of Trustees and Member Representatives Committee (MRC) will hold their first meetings of 2021 remotely because of the COVID-19 pandemic, board Chair Roy Thilly told the groups at their quarterly conference calls Thursday. The meetings had been planned for Feb. 3-4 in Manhattan Beach, Calif.

“We hope that [the pandemic] will be dying down, but of course we don’t know. And there are so many travel restrictions in place on employees of various stakeholders — [at the] Canadian border and other things — that it is prudent for us to do the meetings virtually,” Thilly said.

The pre-meeting and informational session will be held via conference call Jan. 6 as scheduled. A decision has not yet been made on the next board and MRC meetings, planned for May 12-13 in D.C.

Choudhury Elevated to MRC Chair

Paul Choudhury of BC Hydro, who is currently serving as vice chair of the MRC, was unanimously elected to take over from Exelon’s Jennifer Sterling as chair for 2021. ElectriCities CEO Roy Jones will serve as vice chair.

Elections for sector representatives will be held Dec. 7 to 17 to replace members whose terms expire in February 2021. The MRC is accepting nominations through Friday.

The MRC also approved revisions to its NERC MRC Briefs: Nov. 5, 2019.) This year’s changes are intended to give the committee more flexibility by removing unnecessary requirements from the MRC’s procedures for conducting conference calls.

Standards Actions

Howard Gugel, vice president and director of engineering and standards at NERC, presented three standards for approval by the board: CIP-005-7 (Cybersecurity — Electronic security perimeter(s)), CIP -010-4 (Cybersecurity — Configuration change management and vulnerability assessments) and CIP-013-2 (Cybersecurity — Supply chain risk management).

Howard Gugel, NERC | © ERO Insider

The standards were developed under Project 2019-03 in response to FERC Order 850, which directed NERC to submit modifications to address electronic access control or monitoring systems (EACMS) for high- and medium-impact bulk electric cyber systems. (See FERC Finalizes Supply Chain Standards.) A final ballot concluded on Sept. 10 with 80.78% of industry stakeholders in approval.

The board voted unanimously to approve the standards along with NERC’s 2021-2023 Reliability Standards Development Plan (RSDP), which provides schedules and anticipated resource needs for each project under development or expected to begin. NERC posted the draft RSDP for an informal comment period in August prior to its approval by the Standards Committee in October. After approval, the document will be filed with FERC and Canadian and Mexican government authorities. (See NERC Opens Comments on Standards Plan.)

“[This] is not a static document; it’s … a snapshot as far as things stand today,” Gugel said. “Certainly as new [standard authorization requests] are accepted by the Standards Committee, or new directives [are] issued by FERC, it would augment this plan going forward.”

Winter, Long-term Assessments Previewed

Board members also received an update on NERC’s 2020-2021 Winter Reliability Assessment, set to be released next week, and the 2020 Long-Term Reliability Assessment, which will be released in December.

NERC engineer Stephen Coterillo told the board that all regions are expected to have sufficient resources “under normal winter weather conditions,” echoing FERC’s 2020/2021 Winter Energy Market and Reliability Assessment released last month. (See COVID-19, Weather Drive FERC Winter Outlook.) Fuel and energy assurance pose significant risks in some areas — notably ISO-NE and NYISO — and extreme weather conditions could “result in the use of operating mitigations or energy emergency alerts to meet extreme peak demands.”

Anticipated reserve margins and reference margin levels for 2022 peak season | NERC

Although no specific threats were noted from the COVID-19 pandemic, Coterillo acknowledged that the coronavirus continues to cause “uncertainty in electrical demand projections and … heightened cybersecurity risk.” Damage to electricity infrastructure in Louisiana from this year’s hurricanes could also impact the local grid’s resilience, though the affected systems are expected to be restored by early winter.

On the longer scale, NERC expects sufficient on-peak capacity in most areas for the next five years, with the exception of Ontario and MISO, where planned reserves have the potential to fall below their reference margin levels. NERC Senior Engineer Mark Olson said the team identified several trends that bear watching over the long term, including the rapid projected growth of wind and solar generation resources — expected to comprise 57% of added on-peak capacity over the next five years — and the addition of distributed energy resources, particularly rooftop solar panels, across the North American grid.

November 6, 2020November 6, 2023

Work Gets Underway for WECC Path Task Force

WECC’s new Path Task Force (PTF) on Wednesday kicked off an effort to examine the role of existing transmission path rating procedures in Western Interconnection planning and operating processes and whether they are still applicable to a changing grid.

The regional entity’s Joint Guidance Committee (JGC) authorized creation of the PTF in September to identify the “relevance and role” of total transfer capability (TTC), path ratings and the “three-phase” ratings process in both the operations and planning horizons for industry participants. (See New WECC Task Force to Examine Path Rating Processes.)

The three-phase process is designed to address planned new transmission facilities and the upgrading or rerating of existing facilities through a review group consisting of project sponsors and representatives of other systems that could be affected by the project, according to WECC.

The path rating process provides transmission project sponsors with the means to obtain an “accepted” rating that meets the RE’s criteria and NERC reliability standards.

During the PTF’s kickoff meeting Wednesday, WECC Director of Reliability Risk Management Vic Howell, the staff liaison to the task force, added some flesh to the mission, explaining the stakeholder group will also “identify and explain the changes in regulatory, markets and business practices, as well as changes in operations in planning that support [the PTF’s] conclusions and recommendations.”

Those findings will be reported to the JGC, although the PTF will also give presentations to WECC’s Operating Committee (OC) and Reliability Assessment Committee, Howell said.

Howell said the idea for the PTF originated in July after the Western Area Power Administration gave a presentation on an internal project to more dynamically calculate near-term and real-time TTCs to be posted on its Open Access Same-Time Information System (OASIS), rather than relying on seasonal TTCs.

“That led to some discussions of the shortcomings of too much reliance on seasonal TTC values,” Howell said. “And as we talked about it at the OC meeting and the joint standing committee meetings, there were a lot of questions and discussions about the use of total transfer capability in the operations and the planning horizon, and the discussion led to asking, ‘How does the path rating fit into this whole equation? And where does the three-phase ratings process come into play?”

Howell lauded the professional diversity of the 12-member task force.

“We wanted to make sure that as we choose members for this task force, we get representation from operations, that we get expertise from planning and … from business practices — scheduling and markets and things of that nature,” he said.

Members Speak

In a get-acquainted exercise, Howell asked PTF members to describe their interest in the path ratings issues.

“The one thing that really stands out is tackling this time frame issue that’s come up,” said PTF Chair Matthew Veghte, an engineering supervisor at WAPA.

“We don’t just look at [the power system] from a seasonal perspective or a next-day perspective; we’re looking at all the way from planning — which can be five years, to a year, to six months to 30 days out — to one day out,” Veghte said. “We have all these different time points that have different things going on, and we’re tasked with, ‘How do we figure out TTC with that?’”

Transmission planning consultant Chifong Thomas said she was interested in exploring how to apply planning restrictions to the operating world in a way that’s not “overly restrictive.”

“Because things change when you go from planning to operations, and so how do we communicate the information that was important to help the operating system,” Thomas said.

Gary Trent, transmission planning manager at Tucson Electric Power, cited the fact that his utility will be joining the Western Energy Imbalance Market in spring 2022 while also transitioning to NERC’s MOD-30-02 flowgate methodology for calculating short-term transfer capability.

“I believe that we’re going to see more and more companies heading that way as time moves on, and being able for us to be on the ground here with that is going to help us all out,” Trent said.

Hari Singh, principal engineer at Xcel Energy, said his interest stems from his view that there is “quite a bit of intersection” between the concepts of transfer capability and system operating limits.

“Now whether we say that system limit is for the operations horizon or the planning horizon, I don’t see why they should be very different if the system we’re looking at five years out in the planning horizon is almost the same as what we’re operating today,” Singh said. “I guess I’m certainly very interested in trying to de-mystify this concept of path ratings we’ve had in WECC and how it relates to total transfer capability and system operating limits.”

Audrey Stevenson, operations planning engineer at Bonneville Power Administration, said, “I think the thing I’m most excited about this task force is identifying and trying to reconcile the differences that are present between the performance requirements and planning horizon, which lead to path ratings and operating horizons, which lead to the short-term TTC and also exceedance identification.”

The task force also includes Dede Subakti and Larry Bellnap of CAISO; Brenda Ambrosi of BC Hydro; Peter Mackin of GridBright; Igor Kormaz of Tri-State Generation and Transmission Association; Clint Savoy of SPP; and Bill Shemley of PacifiCorp.

November 6, 2020

GridEx VI Planning Begins

Planning has begun for GridEx VI, which will test response to a coordinated attack from a nation-state adversary, Program Manager Katherine Ledesma told the newly renamed Real Time Operating Subcommittee on Wednesday.

NERC’s design group, which began work on GridEx VI in July, shared its draft scenario narrative during the initial planning meeting last week, Ledesma said. It will be held on Nov. 16-17, 2021.

“The goal for GridEx VI is exercising the response and overall resilience to a coordinated attack from a nation-state adversary,” said Ledesma, who is manager of resilience and policy coordination for NERC’s Electricity Information Sharing and Analysis Center. “We developed this GridEx goal based on past exercises, feedback from those exercises and current events impacting the grid.”

After beginning with a focus on responding to physical or cybersecurity incidents, the biennial exercise has increasingly sought to address grid operational reliability since GridEx IV in 2015, Ledesma said. It has also increasingly involved law enforcement and other government agencies and critical infrastructure sectors such as telecommunications and natural gas.

“While physical and cybersecurity are hugely important, it all comes down to keeping the lights on — coordinating reliable operation involving generation, transmission and distribution,” she said.

GridEx VI will include more comprehensive training opportunities for players and an opportunity to exercise responses involving supply chain or service providers for critical functions, Ledesma said.

“We are planning GridEx VI to be the most comprehensive, realistic and relevant exercise so far, and we are encouraged by the fact that the number of participating organizations has steadily grown through the years.”

The exercise will include activating incident operating and crisis management response plans; coordination with government to facilitate restoration; identifying interdependence concerns; exercising response to a supply-chain-based compromise; and identifying common mode and cyber operational concerns across interconnections.

As in past years, NERC will tap the GridEx working group — industry and government subject matter experts — to help plan the exercise.

“For GridEx VI we decided to break up this group and instead form smaller, targeted groups to focus on specific aspects of this exercise,” Ledesma said.

Having shared the draft scenario narrative during the initial planning meeting last week, NERC will “continue bringing in smaller SME teams as needed that will be scenario-specific,” she said.

One of those teams will involve reliability coordinators, who will be asked to provide input to the planning and design teams, customize scenarios for each RC area and develop control area-specific injects.

Ledesma asked RCs to provide feedback on what scenarios the exercise should include or exclude and whether it should provide an opportunity to explore regulatory issues.

The overall scenario scope is expected by Feb. 1, with a midterm planning meeting Feb. 24 and a final planning meeting May 26.

2021 Work Plan, GMD Role Reviewed

The subcommittee, which changed its name from the Operating Reliability Subcommittee on Sept. 15, also reviewed its 2021 work plan. The plan includes monitoring development of common tools; acting as the point of contact for the Eastern Interconnect Data Sharing Network; frequency monitoring reporting; and development of a cyber intrusion guide for system operators and a reliability guideline or reference document to improve short-term and mid-term load forecasting.

Mark Olson, manager of reliability assessments, briefed the committee on a task it will be assigned with the pending dissolution of the Geomagnetic Disturbance Task Force, as directed by the Reliability and Security Technical Committee.

Olson said the task force will soon complete all work in its current scope but that there will be an ongoing need to investigate and evaluate geomagnetic disturbance (GMD) events. The committee will collect information from transmission owners and generator owners with geomagnetically induced currents (GIC) or magnetometer data on the estimated 200 strong GMD events in an 11-year solar cycle. The collection portal went into operation last month.

The task force’s two-year research effort with the Electric Power Research Institute, which ended in the first quarter of 2020, produced almost 20 publications, he noted.

“Where a severe GMD event occurs … this [subcommittee] is the group that can kind of talk about what the experience was and what kind of impact you faced and maybe how we can tie into these data streams like the GIC data. Maybe the ERO needs to [obtain] some other expertise to help analyze it, but … you kind of have a recipe in what you do in sharing your RC experience with events currently and now applying that to GMD,” Olson said.

“The reality is we’ve had such quiet solar cycles over the last several decades that there’s not a lot of shared experience,” he added. “But the risk is out there.”

The task force is expected to retire after completing its work plan, which is expected late this year or the first quarter of 2021.

November 5, 2020

FERC Sets Tech Conference on RTO Credit Policies

FERC announced Wednesday it will hold a staff-led technical conference Feb. 25-26 on best practices for managing credit risks in organized wholesale electricity markets, an effort to prevent a repeat of PJM’s GreenHat Energy default (AD21-6, AD20-6).

The conference, which was requested by the Energy Trading Institute (ETI) last December, will consider the credit and risk management infrastructure of RTOs and ISOs; best practices and principles for capitalization requirements, financial security requirements and unsecured credit allowances; the applicability of “know your customer” protocols and other counterparty risk management tools; considerations for implementing financial transmission right-specific credit policies, such as a mark-to-auction mechanisms; and the relationship between credit policy and wholesale electric market design.

ETI asked the commission to conduct a rulemaking to update the requirements of Order 741 and section 35.47 of the commission’s regulations on credit and risk management in RTO/ISO markets.

Order 741 resulted in shortened settlement cycles; limits on the use of unsecured credit in some markets; a prohibition on unsecured credit for all FTR-type markets; minimum criteria for market participation; and clarification on when ISOs and RTOs could demand additional collateral from market participants.

“Good credit policy is the cornerstone of any market, and the commission’s guidelines in section 35.47 were appropriate at the time,” ETI said. “However, given the recent GreenHat default and the evolution of these markets over the last decade since the issuance of Order No. 741, ETI strongly believes that the commission and industry should engage in a dialogue to ensure that credit and risk management practices and procedures in the ISOs and RTOs are robust, do not create unnecessary barriers to entry or compliance burdens, and ensure that organized markets are secure in order to meet the commission’s goals of open access, competition and transparency.”

RTO Credit Policies — Size and tenor of GreenHat’s portfolio | *PJM*

ETI asked FERC to hold the conference by March 30 so that it could inform RTO/ISO initiatives to consider revisions to their credit policies. But the ISO/RTO Council (IRC) opposed the request, saying a rulemaking could upset stakeholder proceedings. (See RTO Council Balks at Credit Rulemaking.)

The council, which includes the six FERC-jurisdictional RTOs/ISOs, said FERC should allow the grid operators and their stakeholders to address their credit and risk management issues individually before considering a conference or rulemaking.

“At a minimum, these RTOs and ISOs should have time to gain experience with those rules before the commission facilitates a dialogue of best practices, schedules a technical conference and/or commences any rulemaking proceeding to examine further enhancements to credit policies and practices in organized electricity markets,” IRC said.

The Edison Electric Institute said it did not oppose a technical conference but said a rulemaking would be “premature.”

In June, FERC approved PJM’s proposal to require companies seeking to participate in its markets to provide the RTO with more financial records, corporate information and details of prior defaults. PJM said it will determine whether a company presents an “unreasonable credit risk” based on factors including a history of market manipulation, financial defaults or bankruptcies within the past five years. It also will consider market and financial risk factors such as low capitalization, future material financial liabilities and low credit scores. (See FERC OKs Tougher PJM Credit Rules.)

In September, NYISO Management Committee Briefs: Sept. 23, 2020.)

SPP MOPC Briefs: July 15-16, 2020.)

November 5, 2020

Boosted by Tx, Eversource Posts Strong Q3 Earnings

Eversource Energy reported third-quarter earnings of $346.3 million ($1.01/share) on Wednesday, powered by its electric transmission segment, which fueled a $27.4 million rise from the same period in 2019.

The transmission business earned $125.6 million ($0.36/share) in the quarter, compared with recurring earnings of 33 cents/share last year. The improved results were driven by investment and reliability in transmission facilities, partially offset by share dilution. Eversource earned $933.2 million ($2.76/share) in the first nine months of 2020, compared with $659 million ($2.05/share) in 2019.

The company also reaffirmed both its earnings-per-share projection of $3.60 to $3.70/share, excluding costs related to the now completed $1.1 billion acquisition of Columbia Gas in Massachusetts, and its long-term EPS growth rate of 5 to 7% from its core regulated business through the year 2024.

Eversource and its subsidiaries comprise New England’s largest utility company and supply electricity, natural gas and water service to 4.3 million customers in Connecticut, Massachusetts and New Hampshire.

There was no discernible financial impact — yet — on damage and restoration efforts from Tropical Storm Isaias, which caused “catastrophic” damage to Connecticut, CFO Philip Lembo said on an earnings call with analysts Wednesday. The Connecticut General Assembly passed legislation following the storm requiring customer rebates and payments for spoiled food and medication from utilities during outages of a certain length in the future. Lembo compared Isaias with several major weather events in 2011 and 2012, which also led to legislation.

Isaias caused damage to 21,669 locations, and outages took nine days to restore. The number of damaged areas was more than what Eversource experienced from Superstorm Sandy and Tropical Storm Irene. Those two storms had durations that lasted a day or two longer than Isaias. Of the four storms, the October 2011 nor’easter was by far the worst, with 25,566 locations damaged and outages that lasted up to 13 days.

“We serve 149 cities and towns in Connecticut, and every one of these communities suffered damage from Isaias, much of it catastrophic,” Lembo said.

The CFO added that Eversource “brought in an army of electric restoration and tree crews to restore power, all the while working on the restoration in a pandemic setting.” The restoration process lasted nine days, one to two days less than previous storms that hit Connecticut, even though there were 30 to 35% more damaged locations, according to the company. There also were no workplace safety issues or COVID-19 exposure among the workers brought to Connecticut, Lembo said.

The estimated deferred cost of damage and restoration efforts in Connecticut, Massachusetts and New Hampshire will total more than $275 million, though most of it occurred in Connecticut. It included setting new poles, hanging miles of new wires or replacing hundreds of transformers, and Lembo said the costs would necessitate capitalization. The Connecticut Public Utilities Regulatory Authority will review any cost recovery and Eversource’s performance during the storm by April 2021.

OSW Developments

Lembo provided a “significant development” on Eversource’s offshore wind work with Ørsted as the Bureau of Ocean Energy Management released a review schedule for the 130-MW South Fork project on Long Island. A decision on a construction and operations permit (COP) is due in January 2022, and the project is still expected to be in service by the end of 2023.

Lembo said BOEM’s review schedules for Revolution Wind and Sunrise Wind would be set for each project next year, ultimately helping determine their in-service dates. He noted that Revolution (end of 2023) and Sunrise (end of 2024) are unlikely to meet those targets.

Call transcript courtesy of Seeking Alpha.

November 5, 2020

DR Firm Says 2020 No Benchmark for MISO LMRs

One demand response aggregator has asked MISO market participants not to rely on 2020 data for the 2021/22 enrollment of load-modifying resources.

Voltus said the pandemic-skewed 2020 is not a proper yardstick to measure LMRs against in the 2021/22 planning year. The company said it would not be appropriate for MISO’s load-serving entities and local balancing authorities to make assumptions of LMR performance based on the unusual use patterns and reduced load.

“When registering LMRs for the 2021/22 planning year, it would be unfair to limit LMR megawatt enrollment levels based on summer 2020 load data for loads that were operating at a reduced capacity due to COVID-19,” Voltus said in prepared remarks to MISO’s Steering Committee in a teleconference Tuesday.

MISO’s LSEs and LBAs decide whether to approve LMR enrollments. They typically limit registrations based on capability and load data from the most recent summer.

Voltus Energy Markets Manager Emily Orvis said some public buildings that would have otherwise had air conditioning load were padlocked during the summer.

“Usually, you have schools that hold summer camps, but this year, they didn’t. We don’t want their load-modifying abilities capped on what they could do this year,” she said.

Voltus said MISO should recommend that LSEs and LBAs use 2019 data as an indicator instead of relying on numbers from the past summer.

“They think this can be accomplished outside of the need to redline any Tariff or [Business Practices Manual] language,” MISO stakeholder liaison Jim Kaminski told Steering Committee members.

“While we don’t have a particular position on the issue, we’re certainly willing to look into it,” MISO Manager of Capacity Market Administration Eric Thoms said.

Steering Committee members directed the issue to the Resource Adequacy Subcommittee for further discussion.

If approved, this wouldn’t be MISO’s first adjustment in response the coronavirus pandemic. In July, the RTO allowed market participants to substitute LMRs affected by the pandemic if necessary. (See FERC OKs COVID-19 Waiver for MISO LMRs.) In spring, it also extended by two months a deadline in its interconnection queue for certain generation project hopefuls to demonstrate exclusive land use for projects.

November 5, 2020

Vistra Reports Q3 Earnings Above Expectations

Texas utility Vistra said Wednesday it is taking on the “changing power generation landscape” as it announced earnings that were above management’s expectations.

Vistra reported third-quarter adjusted EBITDA from ongoing operations of $1.19 billion, a 10.3% increase from last year’s third quarter. Year to date, the company’s adjusted EBITDA is at $2.96 billion, up from 2019’s third quarter of $2.62 billion.

Since 2016, “we have meaningfully reduced our cost structure, strengthened the balance sheet to position the business to achieve investment grade credit ratings and enhanced the integrated model,” CEO Curt Morgan said in a statement. “We are now set-up to reinvest in our business as we transform our generation fleet for a sustainable future.”

In September, Vistra told investors it was developing nearly 1,000 MW of renewable generation projects in Texas, including six solar facilities and one battery, and intends to retire an incremental 6.8 GW of coal-fired generation in Illinois and Ohio.

Morgan reminded analysts that “every reputable and objective study” of electric generation sees natural gas playing a “significant role for several years to come, especially as we electrify the economy.”

“We believe we are a natural owner of renewable and energy storage assets given our capabilities and competitive position,” he said. “We have a high degree of competence that we can generate healthy return from these assets through the same skills and methodology by which we extract significant value from our existing fleet.”

The Irving-based company said it expects to allocate about $1.15 billion of capital to transformational growth investments over the next two years, including its Moss Landing and Oakland battery storage projects in California. In May, Vistra entered into a 10-year resource adequacy agreement with Pacific Gas and Electric for a new 100-MW/400-MWh battery to complement the 300-MW/1,200-MWh battery already under construction at Moss Landing.

Vistra also said it had acquired the 60,000 Texas customers of Infinite Energy and Veteran Energy. That expands the footprint of TXU Energy, already the largest competitive retailer in in the Texas market.

The company uses adjusted EBITDA as a measure of performance because it says that analysis of its business is improved by visibility to both that metric and net income prepared in accordance with generally accepted accounting principles.

Vistra share prices peaked at $18.82 shortly after the market’s opening but finished at $18.34, down 5 cents.

November 4, 2020

FERC Approves Standard Revisions, ERO Budgets

FERC has accepted proposed revisions to seven NERC reliability standards submitted earlier this year under Project 2017-07 (Standards alignment with registration) (RD20-4).

The commission on Monday also approved the 2021 business plans and budgets for NERC, the regional entities and the Western Interconnection Regional Advisory Body (WIRAB) (RR20-6).

NERC began Project 2017-07 in order to update reliability standards affected by the risk-based registration (RBR) initiative approved by FERC in 2015 (RR15-4), which removed two functional categories — purchasing-selling entity and interchange authority — from the ERO’s compliance registry because “the commercial nature of these categories [posed] little or no risk to the reliability of the bulk power system.” The initiative also resulted in the creation of a new registration category, underfrequency load shedding (UFLS)-only distribution provider (DP).

Project 2017-07 was originally proposed in order to remove references to the discontinued categories and add UFLS-only DPs where needed to all families of NERC standards. However, during the course of the project, many of the standards were updated by other projects and removed from 2017-07’s scope. The final list of standards to be updated was approved by NERC’s Board of Trustees at its meeting in February. (See “Standards Actions,” NERC Board of Trustees Briefs: Feb. 6, 2020):

FAC-002-2 — Facility interconnection studies, replaced by FAC-002-3
IRO-010-2 — Reliability coordinator data specification and collection, replaced by IRO-010-3
MOD-031-2 — Demand and energy data, replaced by MOD-032-3
MOD-033-1 — Steady-state and dynamic system model validation, replaced by MOD-033-2
NUC-001-3 — Nuclear plant interface coordination, replaced by NUC-001-4
PRC-006-3 — Automatic underfrequency load shedding, replaced by PRC-006-4
TOP-003-3 — Operational reliability data, replaced by TOP-003-4

In its petition to FERC, NERC told the commission that changes were restricted to updating references to the affected organizations and that “no substantive revisions were made to the proposed reliability standards’ underlying requirements.”

Budgets Continue Focus on Cost Control

The ERO Enterprise business plans and budgets approved by FERC reflect NERC’s decision earlier this year to keep spending and assessments flat in light of the economic uncertainty arising from the COVID-19 pandemic. In its final budget released in August, NERC set its proposed 2021 budget at $82.9 million, up $203,000 from 2020. (See NERC Aims for Cost Control in 2021 Budget.) The total ERO Enterprise budget for 2021, including the REs and WIRAB, was projected at $211.2 million.

The final budget keeps to this target by, among other things, holding its 2021 staffing level to 213.38 full-time-equivalent employees, the same level as 2020. Personnel costs are expected to rise overall to $48.2 million, however, because of rising salaries and medical insurance premiums. Operating expenses are also up because of increased software support expenses for products such as the ERO Secure Evidence Locker.

These rises were offset by savings in such areas as meetings and travel, down 33.7% at $2.2 million because of continuing pandemic-related travel restrictions, and fixed assets, down 29.5% to $3.3 million. Spending on the Electricity Information Sharing and Analysis Center (E-ISAC) is expected to drop by 4.8% as well stemming from the “re-evaluation of the E-ISAC strategic plan and optimization of current resources.”

In its budget filing, NERC also disclosed $1 million in penalties that it received between July 1, 2019, and June 30, 2020. The organization requested FERC allow it to deposit the funds in its assessment stabilization reserve, which the commission granted. Following the deposit NERC’s reserve will stand at $2.5 million.

Despite the short-term focus on cost savings, NERC has warned that budget hikes are likely as pandemic restrictions are loosened and the industry resumes normal business. (See NERC: Post-COVID Budget Rises Likely.) Earlier this year, the organization predicted budgets of $87 million and $91.4 million for 2022 and 2023, respectively.

November 4, 2020

Feds Revive, Seek Input on West ‘Energy Corridor’

Federal officials are seeking input on a revised plan to use Western federal lands to create a network of energy infrastructure pathways that would likely provide a big boost to renewable project development.

The West-wide Energy Corridor — really a series of corridors — would wind through seven states, including California, Idaho, Montana, Nevada, Oregon, Washington and Wyoming.

The U.S. Bureau of Land Management, Forest Service and Department of Energy introduced the proposal in September 2005 under the authority of Section 368 of the Energy Policy Act of 2005.

Section 368 directs federal agencies to designate lands in the 11 Western states as right-of-way corridors for electricity transmission and distribution facilities, as well as oil, gas and hydrogen pipelines. It also requires the agencies designating corridors to take into account the “need for upgraded and new electricity transmission and distribution facilities” to “improve reliability,” “relieve congestion” and “enhance the capability of the national grid to deliver electricity.”

In 2009, the agencies prepared a programmatic environmental impact statement (PEIS), and BLM and USFS signed records of decision (RODs) designating about 5,000 miles of Section 368 energy corridors on BLM-administered lands and approximately 1,000 miles on USFS-administered lands.

But the effort to move ahead was stymied in July of that year when several conservation groups — including the Sierra Club and Natural Resources Defense Council — filed suit in federal court alleging that the PEIS and RODs violated the EPAct, National Environmental Policy Act, Endangered Species Act, Federal Land Policy and Management Act and Administrative Procedure Act.

In July 2012, the federal agencies signed a settlement with the plaintiffs that required the agencies to conduct regional reviews of Section 368 corridors and outline a handful of siting principles to guide those reviews.

Those principles require that the corridors must be “thoughtfully sited to provide maximum utility and minimum impact on the environment” and encourage “efficient use of the landscape for necessary development.” The agencies must also define “appropriate and acceptable uses” for specific corridors.

The revised plan contains numerous proposals to shift corridors to alleviate impacts on the environment and Native American reservation lands. It also proposes to eliminate a handful of corridors while adding two new ones in Wyoming and one each in Idaho and Oregon.

New Paths for Renewables

Most significant for renewable developers is a settlement stipulation that requires corridors to “provide connectivity to renewable energy generation to the maximum extent possible while also considering other sources of generation, in order to balance the renewable sources and to ensure the safety and reliability of electricity transmission.”

The revised plan, released Monday, points out that most of the 59 corridors identified in the 2009 West-wide plan already contained existing energy transmission infrastructure that was largely constructed to transmit electricity produced by fossil fuel, nuclear and hydroelectric generating facilities. Since then, the report notes, additional energy infrastructure has been built in those corridors, and many now have pending right-of-way applications for utility-scale renewable resources.

“Renewable energy development in Section 368 energy corridors is critical for connecting renewable energy sources to the grid,” the agencies said.

To bring that point home, the agencies cite the growing need for renewable energy in the West, particularly in California, combined with the remote locations of the regions with some of the greatest potential to generate that energy.

The proposal points to the large number of untapped designated solar energy zones (SEZs) on BLM land near Corridor 18-224 in Nevada.

“There is also a strong interest in solar energy development, combined with substantial existing geothermal energy production in this area. However, a lack of transmission lines to transport solar or geothermal energy to load centers presents a barrier for potential developers,” the plan states.

An isolated area of southeastern Oregon near Wagontire Mountain, positioned close to three Section 368 corridors, contains “significant” wind, geothermal and solar energy potential, according to the report.

“However, renewable energy resources require an additional north-south pathway east of Corridor 7-11 into California. A corridor addition in the area could serve to connect renewable energy to demand,” the plan states.

Wyoming currently has nearly 1,500 MW of installed wind capacity, with another 3,000 MW under construction, the reports notes. While the Gateway West project, slated for completion in 2024, will carry some of that generation to the West Coast, “additional infrastructure may be needed to transmit wind energy from Wyoming to out-of-state load centers, and Section 368 energy corridors could be well placed to accommodate that need,” the agencies contend.

The federal agencies are seeking comments on the revised plan by Jan. 31, 2021.