Page 1022 – RTO Insider

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

FirstEnergy Earnings Call Overshadowed by Probes

FirstEnergy’s positive third-quarter financial results were overshadowed Monday by questions over the firing of CEO Charles Jones and the ongoing federal investigation into the company’s involvement in the $61 million bribery scandal over the passage of Ohio House Bill 6.

Christopher Pappas, FirstEnergy board member and new executive director, said the Department of Justice investigation into the bribery scheme has triggered several shareholder and customer lawsuits, and the company is responding to a U.S. Securities and Exchange Commission subpoena received on Sept. 2. Pappas said FirstEnergy is cooperating with both agencies.

In July, federal prosecutors alleged FirstEnergy spent $61 million in bribes, “dark money” campaign contributions and advertising to elect former Ohio House Speaker Larry Householder (R) and his allies in return for their support of HB6, which provided $1.5 billion in subsidies for the utility’s struggling nuclear plants. (See Feds: FE Paid $61 M in Bribes to Win Nuke Subsidy)

On Oct. 29, following an internal investigation related to “government investigations,” the company said it had fired Jones and two other officials, Dennis Chack, senior vice president of product development, marketing and branding, and Michael Dowling, senior vice president of external affairs, for violating its code of conduct. The firings came on the same day as the filing of guilty pleas of former FirstEnergy Solutions (FES) lobbyist Juan Cespedes and political strategist Jeffrey Longstreth, who admitted to participating in a racketeering conspiracy.

Steven Strah, president of FirstEnergy, was later appointed as acting CEO, while Pappas was named executive director. (See FirstEnergy Fires Jones over Bribe Probe.)

Pappas was asked Monday if other FirstEnergy officers or employees were in violation of the company’s policies or code of conduct. Pappas said he couldn’t comment as an investigation is still being conducted. “The investigation is still ongoing, and it would be premature to make any comments on that until we get to a more conclusive state,” Pappas said.

SEC Filing

While FirstEnergy officials were reluctant to answer further questions about the inquiry, an SEC filing by the company on Monday gave hints as to some of the behind-the-scene actions by investigators.

In the filing, FirstEnergy said it has received requests for information related to the government investigations, and those investigations and related litigation “could have a material adverse effect on our reputation, business, financial condition, results of operations, liquidity or cash flows.”

FirstEnergy confirmed that on July 21, it received subpoenas for records from the U.S. Attorney’s Office for the Southern District of Ohio requesting information related to HB6, Householder and other individuals associated with the former speaker. On Aug. 10, the SEC issued an order directing an investigation of possible securities laws violations by FirstEnergy, and on Sept. 1 it issued subpoenas to the company and “certain of its officers.”

The SEC filing said investigations and related litigation could divert the focus of FirstEnergy’s management and result in “substantial investigation expenses” and the commitment of corporate resources.

“We are unable to predict the outcome, duration, scope, result or related costs of the investigations and related litigation, or adverse impacts on federal or state regulatory matters, including with respect to rates, and, therefore, any of these risks could impact us significantly beyond expectations,” the SEC filing said. “Moreover, we are unable to predict the potential for any additional investigations, litigation or regulatory actions, any of which could exacerbate these risks or expose us to potential criminal or civil liabilities, sanctions or other remedial measures, and could have a material adverse effect on our reputation, business, financial condition, results of operations, liquidity or cash flows.”

Earnings and Company Moves

FirstEnergy reported earnings of $454 million ($0.84/share) on revenue of $3 billion, compared to $391 million ($0.73/share) on revenue of $2.9 billion for the same period last year. The results beat FirstEnergy’s internal expectations by a cent, company officials said, and it reaffirmed its outlook for the remainder of its fiscal year as well as long-term growth projections.

Shares of FirstEnergy were up 19 cents, or 0.64%, to $30.12 as of closing on Tuesday.

FirstEnergy also announced it filed an application with FERC last week to move transmission assets in the Allegheny Power System zone to forward-looking formula rates. The move includes transmission assets in West Penn Power’s territory in Pennsylvania, Mon Power in West Virginia and Potomac Edison in West Virginia, Maryland and Virginia. FirstEnergy requested an effective date of Jan. 1.

It also created a new stand-alone transmission company, the Keystone Appalachian Transmission Co., to allow for new construction in the same footprint. FirstEnergy said last week it filed to establish a forward-looking formula transmission rate for the new company, and it plans on transferring certain transmission assets from West Penn Power and Potomac Edison by the start of 2022.

Company officials said they are currently taking steps to improve its liquidity and have been reaching out to its key stakeholders, including ratings agencies, banks, regulators, legislators and union leadership in the aftermath of the investigation.

The board has formed a new subcommittee of its audit committee to assess and implement potential changes to its compliance program. Leslie Turner, a FirstEnergy board member and former senior vice president of The Hershey Co., will lead the effort. Company officials said the new subcommittee will work with management, create an internal audit and engage outside expertise for help and best practices.

“I agree that the actions taken by our board of directors last week were absolutely necessary and are an additional step towards addressing this matter,” Strah said. “The management team is committed to working with the board to assess and implement potential changes as appropriate with the company’s compliance program. We take this as a serious and important matter, and we will begin to address this immediately.”

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.

November 4, 2020

EPA Sued over Coal Plant Wastewater Standards

Nine conservation groups sued EPA on Monday over the agency’s move to weaken standards on water pollution emanating from coal-fired power plants.

The lawsuit, filed in the D.C. Circuit Court of Appeals, challenges EPA’s decision, issued last month, to alter the 2015 Effluent Limitations Guidelines (ELG), which require plants to use modern, affordable wastewater treatment technologies widely used in other industries.

It allows plants more time to reduce their wastewater pollution, extending the deadline for compliance by two years to the end of 2025. Plants can also use cheaper pollution-control technologies to remove toxic chemicals and heavy metals from wastewater if they are scheduled to retire by 2028. The agency’s revisions are expected to save utilities about $140 million each year.

EPA — The coal-fired Pleasants Power Station in West Virginia

“This absurd step backward is little more than a gift to the dirty fossil fuels industry at the expense of people’s health, endangered wildlife and water quality,” Hannah Connor, an attorney with the Center for Biological Diversity, said in a statement. “Many power plants could easily adopt affordable technologies that dramatically reduce toxic discharges, but with this rule, the EPA is telling their polluter friends not to bother with these common-sense measures.”

Joining the Connor’s group in the lawsuit are Chesapeake Climate Action Network, Clean Water Action, Environmental Integrity Project, Natural Resources Defense Council, PennEnvironment, Prairie Rivers Network, Sierra Club and Waterkeeper Alliance.

“This administration’s dangerous decision to give coal power industry lobbyists what they want will not stand without a fight,” said Earthjustice’s Thomas Cmar, one of the attorneys who filed the suit on behalf of the groups. “We’re working with our partners to stop hundreds of thousands of pounds of pollutants from contaminating sources of drinking water, lakes, rivers and streams each year.”

In response to an emailed request for comment, an EPA spokesperson told RTO Insider that the agency does not comment on pending litigation.

November 3, 2020

Entergy, in Eye of the Storms, Beats Expectations

Entergy held its third-quarter earnings call with financial analysts Wednesday as yet another hurricane, the fifth to hit Louisiana this season, bore down on the state.

entergy

“We’ve activated our storm response plan, and we are fully prepared and ready to respond,” Entergy CEO Leo Denault told analysts. “We’ve had a record-breaking storm season with back-to-back hurricanes hitting our service area. Yet no matter what 2020 threw at us, we remain steadfast in delivering on our commitments to our customers, our communities, our employees and our owners.”

Hurricane Zeta made landfall later that evening, ripping through Entergy’s New Orleans hometown with 110 mph winds. The most powerful hurricane to hit the U.S. this late in the year since 1899, Zeta knocked out power to more than 480,000 customers. By Friday morning, 327,000 were still without service, with some facing prospects of a full week without power.

Zeta followed Laura in August and Delta in October, both of which caused significant damage west of New Orleans. Aided by mutual assistance partners, Entergy deployed 12,000 workers after Delta to restore most of the nearly 500,000 outages in five days.

“We showed why we are best-in-class in storm response as we successfully managed to back-to-back major hurricanes all amid a global pandemic. That’s what we prepare for, and that’s what we do,” Denault said. “We can control what we can control. We can’t control the public health crisis, so we’re going to control what we can control.”

Entergy reported third-quarter earnings of $521 million ($2.59/share), as compared to 2019’s third quarter of $365 million ($1.82/share). That exceeded analysts’ expectations of $2.42/share, according to Zacks Information Research.

Denault said the results “amid these extraordinary times” demonstrated Entergy’s progress in building a “simpler, stronger and more resilient company.”

Entergy’s share price lost traction during the week, as did the rest of the broader market. Shares closed Friday at $101.22, down 5.8% following the earnings announcement.