Page 1118 – RTO Insider

August 9, 2020May 6, 2025

NEPOOL Reconsiders Forward Clean Energy Market

Mid-century economy-wide GHG emission reduction targets in New England | E3/EFI

NEPOOL’s Participants Committee on Thursday began taking a new look at how it can adapt market rules to reach New England states’ decarbonization goals with educational presentations on two potential “pathways”: carbon pricing and a forward clean energy market (FCEM).

The pathways discussion — and planning for a parallel “Future Grid” study — resulted from requests by the New England Power Generators Association (NEPGA), New England States Committee on Electricity (NESCOE) and other stakeholders for the region to plot a path toward reaching states’ 2050 decarbonization goals. (See NEPOOL Reviews ‘Future Grid’ Study Requests.)

At the March PC meeting, NESCOE Executive Director Heather Hunt said the organization’s request was intended “to initiate proactive and actionable discussion on the future grid and potential market changes to achieve states’ goals other than through the reactionary changes that have been directed by the FERC and driven the region’s efforts in past years,” according to NEPOOL meeting minutes.

IMAPP Redux?

Carbon pricing and the FCEM were among four long-term proposals considered in detail by stakeholders in the Integrating Markets and Public Policy (IMAPP) initiative in 2016. Carbon pricing foundered because of differing ambitions among the states, with New Hampshire balking at the more ambitious goals of Massachusetts and Connecticut. (See ISO-NE Two-Tier Auction Proposal Gets FERC Airing.)

ISO-NE ultimately adopted a two-tiered capacity construct, the Competitive Auctions with Sponsored Policy Resources (CASPR) to prevent consumers from paying twice for the same capacity through both the Forward Capacity Market (FCM) and subsidies for new, state-mandated supply resources.

CASPR is intended to allow state-sponsored resources to enter the FCM while maintaining competitive prices in the Forward Capacity Auction (FCA). In a substitution auction after the primary FCA, existing capacity resources may transfer their obligations to new resources that did not clear in that first stage because of the minimum offer price rule.

The CASPR substitution auction cleared 54 MW in 2019 and none in 2020. That led some observers to label CASPR a failure, with others calling for it to be redesigned. (See NEPOOL Markets Committee Briefs: May 12, 2020.)

ISO-NE CEO Gordon van Welie has urged patience, telling the PC in March that CASPR is the “next best solution” if the region can’t adopt effective carbon pricing.

“Resource substitution via CASPR will depend on the build-up of economic pressures over time,” he said. He acknowledged CASPR’s performance thus far “has caused concern among some stakeholders that the transition may not occur swiftly enough, or that the lack of substitution may lead to a costly overbuild, leading to a discussion about alternative market designs or structures.”

Forward Clean Energy Market

At Thursday’s PC meeting, Kathleen Spees of The Brattle Group briefed members on its FCEM proposal, which she said could help states achieve their goals without demanding that those goals be uniform. “We developed the Forward Clean Energy Market as one tool that states could use for mobilizing private investment to meet their goals through a competitive market,” Brattle said.

The Brattle proposal resulted from a study funded by the Conservation Law Foundation, Brookfield Renewable Partners, NextEra Energy Resources and National Grid, and one funded by NRG Energy, Spees said.

The proposal acknowledges states’ desire to move from a wholesale market that delivers “reliable, low-cost electricity” to one in which the power is also carbon-free, Spees said.

[Note: Although NEPOOL rules prohibit quoting speakers at meetings, those quoted in this article approved their remarks afterward to clarify their presentations.]

The FCEM would be a centralized, three-year forward auction in which buyers and sellers could voluntarily exchange clean energy attribute credits (CEACs) — a product Spees likened to a renewable energy credit.

Brattle’s proposed Forward Clean Energy Market would be a centralized auction in which buyers and sellers could voluntarily exchange clean energy attribute credits (CEACs). | The Brattle Group

There are two optional variations: One for a “dynamic” CEAC would award more credits to resources that displace more carbon emissions, which would benefit batteries “and focus incentives toward achieving more carbon abatement faster,” Brattle said.

A second option would allow buyers to register a preference for “targeted” resource types to meet carve-outs for preferred technologies such as storage or offshore wind.

The FCEM would assign most fundamentals-based and asset-specific risks to sellers, with features to mitigate regulatory risks and support financeability:

a multiyear commitment period of about seven to 12 years to lock in prices for new resources;
a multiyear forward period to support development and financing of new resources;
a sloped demand curve to reduce year-to-year price volatility and improve revenue certainty; and
the ability for states to make commitments to rely on the market for a minimum time frame and quantity to ensure confidence in the construct.

Spees indicated a willingness to discuss a forward period shorter than three years, which could benefit some renewable developers. But she noted that some clean resources such as offshore wind may also have longer development time frames. She recommended that the FCM and FCEM both be conducted at the same forward period to minimize clearing risks for new resources that seek financing.

Brattle said its simulations estimated that FCEM could save customers $3.60/MWh — or $4.5 billion over 10 years — compared to states’ current practices for bringing clean resources and storage online, including competitive solicitations.

Spees said the FCEM offers several benefits over carbon pricing and traditional RECs.

Carbon pricing maximizes benefits if implemented regionally and economy-wide, which may not be politically feasible in the near term; carbon prices acceptable to all states would likely be too low to achieve the carbon-reduction goals. The FCEM, by contrast, would not require states, cities or companies to agree on a common price or policy goal: States and customers pay to meet their own goals with no cost-shifting to nonparticipants.

Brattle says traditional RECs offer flat incentives over every hour and incentives to offer at negative energy prices during excess energy hours when displacing other clean supply.

“Dynamic” CEACs would scale payments in proportion to marginal CO2 displacement by time and location, incenting the production of clean energy when and where it is most effective in reducing emissions, Spees said. There would be no incentive to offer at negative prices.

Spees said she was uncertain whether the plan would be subject to FERC jurisdiction or outside it like the REC market and the Regional Greenhouse Gas Initiative. Either way, she said, “it’s critical that states have control over their participation. States were very clear when we went through the IMAPP that they want that flexibility.”

Carbon Pricing

Joe Cavicchi of Analysis Group also gave a presentation on the NEPGA-funded carbon pricing study it released in June.

Joe Cavicchi, Analysis Group | Analysis Group

Cavicchi began his presentation with a look at Western Europe, where carbon spot prices, which he said had been ineffectual at about 5 euros/metric ton in 2017 ($5.89), have generally traded between 20 and 25 euros since 2018 ($23.57 to $29.47).

Analysis Group’s study concluded that New England needs a CO2 price of $25 to $35/short ton by 2025, rising to $55 to $70 by 2030, to meet states’ carbon emissions goals. (See Study: $25 Carbon Price Needed to Meet Goals.)

The Analysis Group’s study concluded that New England needs a carbon price of $25 to $35/short ton by 2025, rising to $55 to $70 by 2030, to meet New England states’ carbon emissions goals. | Analysis Group

Cavicchi said a multisector price on carbon could help the transformation to electrification, allowing “a more accurate assessment of the trade-offs when assessing electricity as a fuel for transportation and heating as opposed to fossil fuels.”

It also would allow technology-neutral competition among existing and new zero-emission resources in the electric sector, incentivizing cost reductions and innovation while reducing the need for future state-directed investments. It would additionally reduce the risk of stranded investments that can result when the costs of power from new technologies drop below long-term contract prices.

The study assumed light-duty electric vehicle penetration of 25% in 2025, 60% in 2030 and 90% in 2035. Similarly, it assumed 25% of homes heating with oil, propane or natural gas would switch to electric by 2025, rising to 50% by 2030 and 75% in 2035.

Although a carbon price would increase wholesale power prices, it would not increase consumer costs materially if states rebate the carbon revenues, the study said.

Next Steps

The PC next month will receive education on energy-only markets, such as ERCOT, and alternative approaches to the region’s existing reliance on the FCM for resource adequacy.

The committee expects to begin discussing the pros and cons of the potential solutions in October.

Consent Agenda

Earlier in the meeting, the PC approved the following on the consent agenda:

The amended and restated Services Agreement between NEPOOL and ISO-NE reflecting the evolution in the roles of ISO-NE, NEPOOL and the NEPOOL Generation Information System Administrator, as recommended by the Markets Committee at its July 14-15 meeting.
Revisions to metering requirements for DC-coupled assets: Manual M-28 (Market Rule 1 Accounting) and Manual M-RPA (Registration and Performance Auditing), as recommended by the MC in July.
Revisions to OP-18 (Metering and Telemetering Criteria), which adds requirements for DC-coupled assets, as recommended by the Reliability Committee at its June 16 meeting.
Revisions to Planning Procedure No. 5-1 (Procedure for Review of Market Participant’s or Transmission Owner’s Proposed Plans) in response to the significant increase of proposed plan applications and generator notification forms being processed monthly. Submittals will be required 10 business days before the monthly RC meeting date. Generator application forms have been updated to enable bulk review and summarization, and information regarding the storage component of co-located facilities will be collected to enable improved summarization. The change was recommended by the RC in June.

August 9, 2020

Experts Say Policy Lags Inhibiting Smart DER Use

Experts last week said it’s mostly policy — not technology — holding back widespread adoption of distributed energy resources supported by smart technology.

Those opinions were on display during Austin, Texas-based electricity data research organization Pecan Street’s “Smart DERs — The Missing Link” webinar Friday.

Eaton Research Lab Engineering Specialist Hossein Ghassempour Aghamolki said there’s still a long way to go in smart DER adoption and that the lack of clear, uniform rules is partly to blame.

“We don’t have a universal strategy. … Every market, region [and] state has its own policy,” he said. Part of the problem is that utilities see DERs as a barrier rather than a tool that can be leveraged through smart meters and load forecasting, he said.

“If the business model is there, the technology can catch up,” Ghassempour Aghamolki said.

Arnela Smajlovic, manager of Siemens’ Microgrid Management System, said microgrids are already able to bid into markets for dispatch instructions on behalf of the DERs they manage. She said that scenario can be realized today, but it lacks a business model for commercial use and monetized incentives.

“This concept is all well ahead of its time technology-wise. … We need to get over this limited use of microgrids,” Smajlovic said. “We’re waiting for the business model to catch up. … It’s the [state] commissions that have to agree on how we use this technology.”

Shashank Pande, a Siemens product manager, said smart DER controllers have improved drastically over the last seven years but are still somewhat limited in their capabilities.

“There’s a lot of room to grow in the future,” he said, noting that while inverters improve continuously, constraints involving data sharing and a lack of real-time control still hinder widespread DER systems.

In the meantime, Pande said utilities could do more to expand demand response and time-of-use programs.

Bandera Electric Cooperative CEO William Hetherington said his co-op near San Antonio is focused on incorporating DERs in a rural setting, a completely different challenge.

Hetherington said the co-op began offering rooftop solar installations and programs after getting tired of third-party solar companies hoodwinking members by overcharging and underperforming on generation programs.

The result is Tesla Powerwall solar batteries “scattered throughout the hills of Texas,” he said. Hetherington said Bandera uses the Apolloware DER management system to analyze energy use and avoid overloading inverters.

The co-op has installed about 200 Apolloware systems and hopes to add another 1,000 by the end of 2021, he said. So far, the co-op simply monitors and provides pricing signals and doesn’t perform load control. Hetherington said the idea is that customers get to choose when to respond to price incentives.

“For some reason, people get really upset when you turn their AC off,” he joked.

August 9, 2020

MISO Revisits Scarcity Pricing Rethink

MISO is once again evaluating the effectiveness of the rules behind its scarcity pricing just three years after shelving a similar effort.

Market Design Adviser Michaela Flagg said the RTO will analyze whether to up its value of lost load (VOLL) and change the shape of the operating reserve demand curve. It would likely file revisions in the second quarter of 2021.

“Shortage conditions are not appropriately priced,” she told stakeholders at during a Market Subcommittee teleconference Thursday.

MISO has said it needs to re-evaluate its scarcity and emergency pricing and is exploring a different cost structure under its yearslong resource availability and need (RAN) project. Shortage and emergency pricing has generally been inefficiently low, the grid operator says. (See MISO Exploring Emergency Pricing, Forward Market.)

The current $3,500/MWh VOLL could be understating the value of involuntary load shedding, and the administratively set price doesn’t account for congestion, generation losses or other reserve shortages, MISO contends.

Principal Adviser of Market Design Michael Robinson said MISO first set the VOLL in 2009 based on the class of customers who value uninterrupted electrical service the least and consider shedding load at that price.

“It’s a little bit dated here,” he said. “We established the price that people weren’t willing to pay, and that’s $3.50/kWh. Now, they’re not going to shed hospitals; they’re not going to shed entities that value uninterrupted electric energy service. They’re going to shed customers that value it less … and prefer interruption to those rates. That was the thinking back then.”

MISO’s Independent Market Monitor recommended it ratchet up the VOLL three years ago when it was implementing MISO, IMM Differ over Scarcity Pricing Changes.) Ultimately, MISO didn’t pursue a higher VOLL.

The RTO must consider the consequences to different market segments when adjusting the VOLL, Robinson said, whether that be inconvenience or ruining leisure, to property damage or spoilage of food and other perishables. He said residential and light industrial customers typically suffer the least from load shedding.

Robinson said MISO has never shed firm load because of a capacity emergency since the rollout of the wholesale markets, although it has experienced local load shedding because of transmission outages.

MISO could use a price index or economic research to update the VOLL, Robinson said. “There are a lot of potential approaches.”

However, while MISO could perform its own analysis of end-use customers to establish a price, it would likely be prohibitively expensive and too labor-intensive, he said.

WPPI Energy economist Valy Goepfrich suggested MISO research the retail rates of customers getting paid to interrupt their load. “It might be interesting what you find,” she said.

Monitor David Patton said the understated VOLL means MISO generation still exports to neighboring PJM during shortage conditions. “It creates a mess when you have two [RTOs] valuing electricity at very different levels. … We view this as the No. 1 item for achieving MISO’s RAN initiative,” he said.

MISO Scarcity Pricing — MISO’s operating reserve demand curve stays at $2,100/MWh for most scarcity conditions. | *MISO*

Additionally, MISO’s operating reserve demand curve (ORDC) isn’t nuanced enough to “differentiate shortage severities, especially above minimum requirements,” Flagg said. “A very large portion of the curve is flat.”

The ORDC curve, based on the VOLL, begins at $3,300/MWh, dropping to $2,100/MWh when the RTO clears 8% of its requirement level. At 89%, the level falls to the original $1,100, remaining there until 96% or more of the requirement is cleared, when the curve flattens at $200.

MISO is also reassessing a five-year-old Monitor recommendation that the RTO stop allowing offline resources to set prices. Currently, offline fast-start resources can set extended LMPs during a shortage. The Monitor contends that allowing offline units to set prices artificially suppresses scarcity prices.

Emergency Pricing Fixes on the Way

MISO Research and Development Adviser Yonghong Chen said the RTO will most likely file with FERC before the end of the year to improve its emergency pricing. Chen said that for now, MISO is pursuing a few “simple” fixes that have high impact:

expanding extended LMP eligibility to allow online units with start-up times of four hours or less to set prices during emergencies and emergency alerts;
taking the Monitor’s advice to set an administrative emergency offer floor for emergency resources that respond without an offer; and
updating the emergency pricing structure to reflect the costs of managing congestion on the regional directional transfer limit linking MISO Midwest and South.

Chen said MISO will work on a conceptual design and a benefits evaluation in the fall.

Restoration Energy Pricing Approved

Meanwhile, FERC last month authorized MISO’s new plan to compensate generators that re-energize the grid following a blackout (ER20-1673).

MISO’s compensation for restoration energy relies on last-submitted offers before a blackout as a starting point for pricing, resulting in unique costs based on resource. The RTO will allow for the recovery of start-up costs, emergency purchases and resource-specific energy costs. It would also include recovery for any unusual costs incurred during operation, provided they can be verified by the Monitor. It would also accept after-the-fact updates of offers. (See “Restoration Energy Design Nears Completion,” MISO Market Subcommittee Briefs: Dec. 3, 2019.)

August 9, 2020

McNamee to Leave FERC in September

FERC Commissioner Bernard McNamee announced Wednesday he will leave the commission on Sept. 4, reducing the current four-member panel to three pending the confirmation of his replacement, Virginia State Corporation Commission Chair Mark Christie.

President Trump last month nominated Christie, a Republican, and clean energy activist Allison Clements, a Democrat, to the commission. Clements would fill the seat left vacant by Cheryl LaFleur, who departed nearly a year ago. (See Trump to Nominate Christie, Clements to FERC.)

McNamee, whose term expired on June 30, announced in January that he would not seek a second term but agreed to remain on the commission pending his replacement. He is allowed to remain until the end of the current Congress at the end of the year. (See McNamee Declines to Seek Reappointment.)

“I intend for Sept. 4, 2020, to be my last day serving on the commission,” he said in a statement Wednesday. “Since I announced at our January meeting that I would not be seeking another term, I have continued to work diligently and tirelessly on the important work of the commission. After I leave, I will take some time off and search for a job. Serving as a commissioner has been an incredible honor and an experience for which I am extremely grateful. I thank President Trump for having nominated me and the Senate for having confirmed me. I will have more to say before I leave, but needless to say, I thank the chairman, my fellow commissioners, my advisers and staff, the staff of the commission and all of the FERC community for their support and friendship.”

McNamee was confirmed by the Senate in December 2018. The commissioner, who has been commuting weekly to D.C. from his home near Richmond, Va., has said he is eager to spend more time with his wife and teenage son.

Sen. Joe Manchin (D-W.Va.), ranking member on the Senate Energy and Natural Resources Committee, said the panel has not received the paperwork to hold confirmation hearings on the FERC nominees.

“Commissioner McNamee’s announcement that he will be stepping down in a month’s time means FERC will be operating with only three commissioners as opposed to five. This was not the intention of Congress when the commission was created,” Manchin said in a statement. “I am hopeful the committee will act quickly to restore a fully seated FERC once we have the necessary paperwork.”

The commission will maintain its quorum after McNamee’s departure with Chair Neil Chatterjee and Commissioner James Danly, both Republicans, and Democrat Richard Glick.

August 9, 2020

MISO Prolongs Terms on Midwest-South Tx Limit

The MISO stakeholder community appears to support the RTO’s plan to extend the current arrangement on transmission flows between its Midwest and South regions.

Jeremiah Doner, MISO’s director of seams coordination, told stakeholders during a Market Subcommittee teleconference Thursday that the grid operator will file by Nov. 1 to add two years to a cost allocation agreement with SPP and six other parties. MISO agreed to a settlement, which manages the regional directional flows over SPP’s system to connect the Midwest and South regions, with the seven parties in 2016.

Midwest to South Transmission Limit — MISO Midwest and South | *MISO*

Doner said the agreement’s extension was generally well received by stakeholders.

But not all were happy.

MidAmerican Energy’s Greg Schaefer said he was disappointed because his company’s location in Iowa means it is shouldering a heavy financial burden for MISO’s use of SPP’s system above its 1,000-MW contract path.

“All the costs are being loaded onto a relatively small number of parties,” Schaefer said. “It’s not surprising that there is a consensus here.”

MISO’s payments to the other parties for regional flows above the contract path are recovered from its market participants using a special rate schedule, which increasingly has put emphasis on a flow-based beneficiary allocation over a load ratio calculation. The current calculation is 90% flow-based and 10% load-based, which will continue into 2023. (See MISO Seeks Extension on Midwest-South Tx Limit.)

The 2016 agreement can be terminated by any party with a year’s notice beginning Jan. 31, 2021. Without an extension or alternative solution, MISO’s flows would be limited to its original 1,000-MW contract path in either direction. The agreement limits MISO to 3,000 MW of flows in the north-to-south direction and 2,500 MW in the other direction.

MISO has said a two-year extension of the original terms will buy time for it, SPP and the other parties to explore eventually reopening the agreement’s terms. MISO has also said it may revisit the idea of constructing new transmission capacity to supplant the agreement. (See “No Midwest-South Tx Solution this Year,” Price Tag Rising for MTEP 20.)

August 9, 2020

MISO Investigating LMR Availability Problem

MISO last week said it will begin hunting for solutions to mitigate “significant gaps” between load-modifying resources (LMRs) that clear capacity auctions and what actually shows up to help mitigate emergencies.

The RTO acknowledged during a Resource Adequacy Subcommittee teleconference Wednesday that it had a problem with the amount of LMR-accredited values and what is listed as available to allay demand during summer peak times.

Market Design Adviser Dustin Grethen said that when MISO hit its summer peak in July 2019, 6 GW of LMRs were listed as available, though 11.5 GW cleared the Planning Resource Auction a few months earlier.

Grethen said some of the availability issues result from LMR outages, fear of penalties by overstating load-reducing capability, overly generous LMRs accreditation, voluntary self-deployment or difficulties using the RTO’s availability reporting tool, the MISO Communication System (MCS). Some LMRs that double as emergency demand response enter availability through a separate RTO tool and not the MCS, he said.

Even those reasons cannot explain all the widespread unavailability, Grethen said. He promised MISO would investigate why some LMRs are no-shows after clearing the capacity auction.

Customized Energy Solutions’ Ted Kuhn suggested the grid operator start by checking the MCS’ availability against the metered data LMRs are required to provide.

The LMR availability gap is part of MISO’s ongoing resource availability and need suite of market improvements. The RTO is still gauging which combination of new resource adequacy and capacity market rules it might adopt to reduce the number of maximum-generation emergency events it declares. (See MISO Closer to Seasonal Capacity, Reliability Reqs.)

As part of that, the grid operator will now scrutinize the actual availability of conventional generators and for what they’re accredited. Planning Adviser Davey Lopez said MISO’s planning reserve margin requirement is likely understated because it doesn’t model real-world generation outage scenarios.

Pandemic Still Muddying Forecasts

MISO is still calculating emergency resources’ response during its most recent emergency event on July 7. (See Max Gen Event Managed Efficiently, MISO Says.)

MISO LMR Availability — MISO’s Little Rock headquarters | *MISO*

Executive Director of Market Operations Shawn McFarlane said MISO didn’t have to resort to LMRs that day. He said the peak would have been higher had not thunderstorms popped up in the northern part of the footprint.

McFarlane also said the pandemic continues to complicate load forecasting, as air conditioning load is likely skewed to more residential use this year than in others because of customers working from home.

“We think there’s some offsetting things that made it very hard to predict summer peak,” he said.

Despite that, McFarlane called the event “one of the most orderly max gens I’ve seen,” as MISO responded quickly and committed more resources appropriately.

MISO President Clair Moeller said not much has changed in the RTO’s modus operandi after the pandemic’s announcement.

“The risk profile doesn’t seem to be changing much,” Moeller said during an Informational Forum on July 21. “The good news is the operational impacts of the pandemic are manageable … and we don’t expect that to change.”

Moeller said load “crept back up” in July and is now about 5% less than its normal load average.

“We’re still learning how to forecast in this new environment,” he said.

August 9, 2020

Con Ed Takes $52 Million Hit from COVID

Consolidated Edison said Thursday that the COVID-19 pandemic had negatively impacted its first-half earnings by $52 million — a report that came as the utility struggled to restore power to its more than 500,000 customers in and around New York City after Tropical Storm Isaias hit two days earlier.

The negative impact primarily reflects foregone revenues from the suspension of customer late payment charges and certain other fees associated with the pandemic, as well as higher depreciation and amortization expense, offset in part by the Employee Retention Tax Credit under the CARES Act, the company said.

Despite the effects of the pandemic, net income for the first six months of 2020 was $565 million ($1.69/share), only a 2% drop from the $576 million ($1.77/share) in the first half of last year. Con Ed also reported second-quarter net income of $190 million ($0.57/share), compared to $152 million ($0.46/share) during the same period in 2019.

“We are facing today’s unprecedented challenges by providing essential and reliable service during the pandemic,” CEO John McAvoy said in a statement. “We understand the hardship that Tropical Storm Isaias has had on our customers, and we are working around the clock to restore service.”

McAvoy said crews were restoring power to approximately 300,000 Consolidated Edison Company of New York (CECONY) and 225,000 Orange & Rockland Utilities (O&R) electric customers affected and called Isaias “the second-worst storm in our company’s history.”

The company highlighted the New York Public Service Commission’s decision in July to establish a light-duty electric vehicle “make-ready” program, which includes budgets of $290 million and $24 million for CECONY and O&R, respectively, through 2025, for fast-charger stations and other services. (See NYPSC Approves $700 Million for EV Chargers.)

August 9, 2020

Reliability Guidelines, Standards Posted for Comment

NERC opened 45-day comment periods last week for proposed reliability guidelines on winter weather readiness and supply chain procurement, as well as on planned changes to its Critical Infrastructure Protection (CIP) standards.

NERC RSTC — RSTC leadership at the committee’s last in-person meeting in March. Left to right: Secretary Stephen Crutchfield; Chair Greg Ford; Vice Chair David Zwergel (behind Ford); NERC Chief Engineer Mark Lauby; and NERC Board Vice Chair Kenneth DeFontes. | © *ERO Insider*

Comments will be accepted on the reliability guidelines through 5 p.m. Sept. 21 and through 8 p.m. Sept. 21 for the CIP standards. In addition, ballots for the standards and implementation plan, along with nonbinding polls for associated violation risk factors and severity levels, will be conducted Sept. 11 to 21.

NERC Adds Detail to Winter Guideline

The proposed changes to the winter weather guideline were developed during the regular three-year review process for NERC reliability guidelines. The guideline is currently in its second version, approved in July 2017.

Updates in the most recent draft guideline include replacing references to the Operating, Planning and Critical Infrastructure Protection committees with the new Reliability and Security Technical Committee (RSTC), along with adding detail to the existing guideline’s recommendations for evaluating the readiness of critical components.

New to the recommendations is a clear deadline for finishing winter-related inspections, repairs and upgrades by the local first frost date as set by the National Oceanic and Atmospheric Administration. The guideline also adds lubricants, batteries, uninterruptible power supply systems, and heat tracing and ventilation systems to the list of components that utilities should check for winter readiness.

Jordan Mallory, NERC, (left) and Matthew Harward, SPP, at the meeting of the SAR drafting team for Project 2015-09 in January | © *ERO Insider*

The winter reliability guideline is separate from the proposed cold weather standard currently under development by NERC (Project 2019-06). Some industry stakeholders have questioned the need for mandatory standards on the grounds that the existing guidelines should be sufficient, but NERC representatives have pointed to ongoing issues with cold weather as a reason for continuing the project. (See Cold Weather SDT Planning February Posting.)

“Out of the past 12 years, there have been six blackouts [from extreme cold] — that is a problem. … Obviously, the NERC guidelines may not be enough,” NERC Senior Standards Developer Jordan Mallory said at a meeting of the SAR drafting team in January.

Draft Supply Chain Guidelines Use Broad Strokes

NERC’s proposed supply chain procurement language guideline was developed under the Critical Infrastructure Protection Committee but moved to the RSTC following the merger of the technical committees. The guideline focuses on helping organizations implement effective controls in procurement agreements to prevent exposing themselves to cyberattacks through equipment purchases.

“Regulators have challenged the levels of rigor regarding risk management practices that organizations claim to have attained,” the guideline says. “Remedies applied through the inclusion of targeted controls in the procurement of cyber systems, components, maintenance and related services can assist in the development of a ‘risk-based’ approach to cybersecurity.”

Currently the guideline is in its first draft, so it lacks specific measures for entities to adopt. Instead, the document focuses on broader principles that utilities can follow in their contracts with suppliers, such as identifying cybersecurity risks that might be in play with a particular vendor and specifying audit mechanisms and metrics to ensure vendors are complying with needed changes.

However, the guideline does incorporate links to documents from organizations, including the Energy Sector Control Systems Working Group and the Utilities Technology Council, with more detailed examples of procurement language.

Project 2019-02 Nears Completion

The comment and balloting period for reliability standards CIP-004-7 and CIP-011-3 are hoped to be the last for Project 2019-02, which is focused on clarifying requirements to access bulk electric system cyber system information (BCSI) and establishing guidelines for encryption or other methods to protect such information.

Both standards saw relatively few changes from the last posting: In the case of CIP-004-7, the only significant change is the addition of a new requirement that responsible entities “implement one or more documented access management program(s) for [BCSI]” along with a table defining what such programs must consist of. Changes to CIP-011-3 include clarifying requirements for the reuse and disposal of BES cyber assets and for the components of entities’ information protection programs.

The latest posting also incorporates language previously agreed between the teams for Project 2019-02 and Project 2019-03 to address concern about potential overlaps between their projects. The conflict centered on risk assessments for cloud storage providers, which both groups saw as their domain; however, earlier this year the team for Project 2019-02 agreed to leave specific risk assessment language to the other team and keep its focus on broader questions of risk management. (See CIP Teams Compromise on Cloud Risk Assessment.)

August 7, 2020

Akins: AEP’s Actions ‘Lawful, Ethical’

American Electric Power CEO Nick Akins said Thursday that federal investigators have not contacted the company about an alleged bribery scheme tied to passage of Ohio Hous e Bill 6, and he defended AEP’s contributions to a “social welfare organization” linked to the scandal.

“We are not aware of any information suggesting that AEP’s participation in the process was anything other than lawful and ethical,” he said in prepared comments during a quarterly earnings call with financial analysts. “Based on the facts that we know, we do not believe that AEP is [among] any of the companies specifically described in the [federal charges]. We have not been contacted by any authorities conducting the investigation. If at any point we are, we will cooperate fully.”

Akins said the company has contributed $8.7 million since 2015 to Empowering Ohio’s Economy, a 501(c)(4) nonprofit organized to promote economic and business development in Ohio. The contributions, he said, were ‘’appropriate and lawful,” and he noted that AEP has contributed to a variety of such organizations.

“We consistently advocate for policy positions that benefit our customers, communities and shareholders, and our advocacy of HB6 was no different,” he said. “We ultimately supported the legislation because we believe it maintained important fuel diversity for Ohio, including support for investments in renewables, nuclear generation and two [Ohio Valley Electric Corporation] coal plants.”

AEP owns 43% of OVEC.

Given “concerns that some have expressed regarding the lack of transparency surrounding 501(c)(4) organizations,” Akins said, AEP will commit to include[ing] additional disclosures about its contributions to the organizations in its 2020 corporate accountability report and going forward. Those nonprofits are not required to disclose their donors and the amount of donations.

“We also are reviewing best practices and working to improve our policies and processes around political contributions and contributions to 501(c)(4) entities,” he said.

The Columbus Dispatch, AEP’s hometown newspaper, repo r ted in July that the company has contributed to Empowering Ohio’s Economy, which is part of a federal case that has led to the indictment of Ohio House Speaker Larry Householder and four associates on criminal charges. The nonprofit gave $150,000 to Generation Now, a dark money group that received $61 million from FirstEnergy interests to ensure HB 6’s passage, the Dispatch said. (See FirstEnergy, AEP C EOs Deny Wrongdoing.)

The legislation provided $1 billion in subsidies to a pair of coal plants in which AEP has a 43% stake and two nuclear plants. Businesses, legislators and ratepayers have all called for HB 6 to be repealed.

AEP’s headquarters building in Columbus, Ohio.

“We were surprised and disappointed to learn of what federal investigators allege was a scheme by the speaker of the Ohio House and others to enrich themselves, and we, along with you, have been trying to educate ourselves about the criminal complaint and the underlying conduct in it,″ Akins said.

The comments came the same day Householder and others were to be arraigned in federal court on racketeering and bribery charges. Householder’s hearing was del a yed after he requested new legal representation.

AEP repor t ed quarterly earnings of $521 million ($1.05/share), an increase from 2019’s second-quarter earnings of $461 million ($0.93/share).

The company’s stock price rose 54 cents during the day, closing at $84.83.

August 7, 2020

Research Firm Says Carbon Cuts, Economic Growth Coexist

World Resources Institute researchers made an economic case this week for climate action, given the COVID-19 pandemic.

Dan Lashof, the global research firm’s U.S. director, said 41 states have managed to reduce their carbon emissions in recent years while simultaneously growing their economies. That discredits the maxim that economic growth must come at the environment’s expense, he said.

Maryland topped the list of states decoupling carbon emissions and economic growth between 2005 and 2017, according to WRI’s new resea r ch. The state cut emissions by 38% while growing its gross domestic product by 18% during the 12 years. New Hampshire, Alaska, Georgia, North Carolina and Indiana also made the top 10 in cutting emissions while growing their GDPs by at least 13%.

“It’s a false choice between shrinking emissions and growing the economy,” Maryland Secretary of the Environment Ben Grumbles said during an Aug. 4 WRI webinar.

WRI Research Associate Joel Jaeger said Northeastern and Midwestern states made the most progress cutting carbon while expanding their economies. On the other hand, he said, Texas, the Dakotas and the Gulf States have not made any progress on emission reductions. Idaho was ranked last, experiencing a 17% rise in emissions as its GDP rose by 22%.

Jaeger said states can use large investments in clean energy to help restore the nation’s pandemic-stricken economy.

Carbon-Cutting Economic Growth — Carbon emissions change 2005-2017 | *WRI*

Lashof said a $1 million investment in clean energy in the U.S. creates twice as many jobs in the medium- to short-term than $1 million spent on fossil fuels.

“This is an ideal moment to scale up manufacturing and export of various low-carbon technologies,” said WRI Senior Associate Devashree Saha. Low interest rates typical in recessions make it a “particularly good moment,” she said.

Saha estimated that states need “substantial, but manageable” investments in low-carbon infrastructure. She said the U.S. would need additional annual investments equivalent to about 2% of GDP.

“Even at 2%, that is well within the historical range,” she said. “Energy spending in the United States is at a low point now at around 6% of GDP but has fluctuated to as high as 13%.”

WRI maintains the investments would be money well spent.

“Ignoring climate change is expensive … Delaying action on climate change will further expose the United States to costly damages from climate impacts, air pollution and other public health crises,” Jaeger said, using the nation’s response to the COVID-19 pandemic as an example. He estimated that without new climate policies, the U.S. could encounter economic damages equivalent to anywhere from 1% to 10% of GDP/year by 2100.

To honor the Paris Agreement’s more ambitious target of limiting global warming to 1.5 degrees Celsius, the U.S. needs to cut net emissions by 40 to 50% from 2005 levels by 2030 and aim for carbon neutrality by 2050. WRI said that means U.S. emissions must drop more than twice as fast from 2018 to 2030 than they did from 2005 to 2018.

WRI staff said that can be done with strong federal climate policies, such as carbon pricing and more investment tax credits.

“I think the federal government can amplify these efforts,” Saha said.