Page 1040 – RTO Insider

September 25, 2020

NEPOOL Reliability Committee Briefs: Sept. 23, 2020

The cost of the Greater Boston Project is expected to increase by $191 million (33%) primarily because of the underground Wakefield-Woburn, Mystic-Woburn and Sudbury-Hudson lines, Eversource Energy told the New England Power Pool Reliability Committee on Wednesday.

The cost of the three components is increasing by $147 million, to $352 million (72%).

The remaining 30 components’ cost is rising from $367 million to $411 million, a 12% increase over the transmission cost allocations supported previously by the RC and approved by ISO-NE.

Eversource said 25% of the increase is resulting from the need to underground the 115-kV Sudbury-Hudson line. It was initially proposed as an overhead line, but Eversource was unable to secure property leasing rights from the Massachusetts Bay Transportation Authority (MBTA). The proposed underground line is estimated at $91 million, more than double the original cost of $45.3 million, and has an in-service date of December 2023.

Eversource performed an updated alternative analysis and found that a new 9-mile, 115-kV underground transmission line within an MBTA right of way was the “most cost-effective and constructible alternative.” The two alternatives analyzed — a new 10.3-mile, 115-kV underground transmission line entirely in roadways ($110.4 million), or multiple upgrades to convert a 14.5-mile, 69-kV line to 115 kV, reconductor 11.6 miles of other 115-kV lines and upgrade seven substations ($116.1 million) — had higher costs.

The Wakefield-Woburn and Mystic-Woburn lines are increasing to a combined $260.6 million from $160.2 million, representing 50% of the total cost increase. Eversource said additional restrictions on the design and construction required a realignment of underground construction within roadways to avoid interference with existing utilities. Restrictions on work hours and the number of crews also increased the construction bids, the company said.

The matter is slated for a future committee vote.

ISO-NE, NYISO Propose Revision to Coordination Agreement

ISO-NE proposed revisions to its Coordination Agreement (CA) with NYISO to eliminate the need to make a FERC filing when the grid operators update their description of shared interconnection facilities.

The grid operators share three interconnections: the NY/NE Northern AC Interconnection (comprising the PV-20, K7, K6, E205W, 393, 690/FV and 398 interties); the Norwalk Harbor-Northport, NY, Cable (NNC Intertie) and the Cross-Sound Cable Interconnection (CSC Intertie).

Rather than maintaining the detailed list of interconnection facilities in Schedule A of the CA — which requires a FERC filing for any changes — the grid operators are proposing to update the list on their external websites. The addition or removal of an interconnection would still go through the grid operators’ stakeholder processes and filed with FERC.

ISO-NE said it and NYISO sought the change after the addition of a new transmission substation and common metering point modified one of the interties in the NY/NE Northern AC Interconnection. The change replaced the Pleasant Valley substation and common metering point in New York with the Cricket Valley substation and common metering point on the 398 Intertie.

Although the change did not alter the makeup of the NY/NE Northern AC Interconnection, current rules required that it be filed with FERC. “ISO-NE and the NYISO recognized that such ministerial revisions to the ISO-NE/NYISO CA place an unneeded burden on the respective ISOs, their stakeholders and the FERC,” ISO-NE told the committee.

The grid operators plan to file the revised CA with FERC at the end of 2020 and expect an effective date of early 2021. NYISO will go through a similar stakeholder process, which it expects to complete in November or December, according to ISO-NE.

The RTO requested that the RC vote in support of the proposed modifications at its Oct. 20 meeting.

Tie Benefits and ICR Recommended by Vote

The RC voted to recommend that the Participants Committee support ISO-NE’s tie benefits and installed capacity requirements (ICR) and related values for Forward Capacity Auction 15. (See ISO-NE Sees 722-MW ICR Jump for FCA 15.)

The Hydro-Québec Interconnection Capability Credit (HQICC) values for FCA 15, which is associated with the 2024/25 capacity commitment period, is 883 MW, and the ICR is 34,153 MW with a net ICR of 33,270 MW.

The following megawatt values were also recommended for support: Southeast New England Local Sourcing Requirement (10,305), Maine maximum capacity limit (4,145) and Northern New England maximum capacity limit (8,680).

The PC will vote on the ICR and related values on Oct. 1, with a FERC filing expected by Nov. 10.

Winter Readiness, Gas Infrastructure Surveys Added to OP-21

The RC voted to recommend that the PC approve changes to Operating Procedure 21 to add the generator winter readiness survey and natural gas critical infrastructure survey.

OP-21 is being renamed “Operational Surveys, Energy Forecasting & Reporting and Actions During an Energy Emergency” to reflect the additions.

The annual generator survey process enhances situational awareness of pre-winter generator preparations, while the natural gas survey ensures critical infrastructure of the interstate natural gas system is not on electrical circuits subject to automatic or manual load-shedding schemes.

ISO-NE distributes the generator survey before Nov. 1 each year, and it is due back no later than Dec. 1 unless specified otherwise.

The RTO distributes the natural gas survey to representatives of each interstate natural gas pipeline company operating in New England, as well as the Canaport and Everett LNG facilities. It is typically completed in June.

September 25, 2020

NERC Standards Committee Briefs: Sept. 24, 2020

NERC’s Standards Committee voted Thursday to accept the standard authorization request (SAR) presented by the drafting team for Project 2019-06 (Cold weather). It also appointed the team as the standards drafting team (SDT) for the project.

Much of the discussion of the measure at the meeting reflected the responses that it received from industry stakeholders in previous comment periods. (See Cold Weather Team Seeks More Time to Process Response.) Some committee members questioned the wisdom of moving forward with a project that has proven so controversial.

“The industry has rejected this SAR numerous times, and now it’s come to the Standards Committee, and industry has not approved it yet,” said Marty Hostler, reliability compliance manager for the Northern California Power Agency. He added that “numerous issues” remain with the SAR, including unaddressed compliance burdens and the potential impact of adding more detail to existing NERC standards that were intentionally written vaguely to give more flexibility to registered entities.

Sean Bodkin, NERC compliance policy manager for Dominion Energy, agreed that while “almost all of industry supports” some kind of cold weather preparedness requirement, several rounds of stakeholder feedback made clear that the committee shouldn’t support moving forward with the SAR in its current form.

SPP’s Matthew Harward, the chair of the drafting team, pushed back on this interpretation of the stakeholder comments. While he acknowledged that “multiple comments did not agree that a new standard was needed,” he said the team had taken this into consideration and planned to work within existing standards as much as possible. The only new standard that is likely to be needed is “a requirement for [generator owners and operators] to prepare [for] cold weather.”

The measure passed with no negative votes, though Bodkin abstained, along with Venona Greaff of Occidental Chemical, Linn Oelker of LG&E and KU, and John Babik of JEA.

IRPTF SARs Accepted

The committee voted to accept two SARs requested by the Inverter-based Resource Performance Task Force (IRPTF) and approved by the Reliability and Security Technical Committee in June. They will be posted for a 30-day informal comment period as members are solicited for a SAR drafting team. (See “IRPTF SARs Pass After Debate,” NERC RSTC Briefs: June 10, 2020.)

IRPTF’s SARs would apply to the following standards:

FAC-001-3 (Facility interconnection requirements) and FAC-002-2 (Facility interconnection studies) — Clarify which entity is responsible for determining which facility changes count as material modifications; clarify that generator owners should notify affected entities before making a material modification; revise the term “materially modifying” to avoid confusion between Facilities Design, Connections and Maintenance (FAC) standards and FERC’s interconnection process.
MOD-026-1 (Verification of models and data for generator excitation control system or plant volt/VAR control functions) and MOD-027-1 (Verification of models and data for turbine/governor and load control or active power/frequency control functions) — Revise or replace with a new model verification standard that accounts for inverter-based resources.

Two other SARs suggested by the IRPTF — to modify PRC-002-2 (Disturbance monitoring and reporting requirements) and VAR-002-4.1 (Generator operation for maintaining network voltage schedules) — were also approved by the RSTC but were not submitted to the Standards Committee. NERC’s Manager of Standards Development Soo Jin Kim said that the two that the committee approved were considered “higher priorities based on some issues that are occurring today with regard to compliance.”

Questions About Consistency in Nominations

The committee also approved the appointment of the chair and vice chair, along with nine members, to the SAR drafting team for Project 2020-04 (Modifications to CIP-012) and endorsed NERC’s 2021 Reliability Standards Development Plan. (See NERC Opens Comments on Standards Plan.)

None of the prospective team members for Project 2020-04 — who were not identified by name during the meeting — met with serious opposition, but some committee members did raise questions about the nominating process.

Bodkin said one candidate did not seem to have relevant expertise and lacked an endorsement from a generator or transmission owner/operator. However, he dropped the question after Kim and Howard Gugel, NERC’s vice president of engineering and standards, reminded him that ERO staff have the authority to certify a candidate as a subject matter expert — and had done so in this case.

Robert Blohm, managing director of Keen Resources, noted that none of the candidates nominated by stakeholders but not recommended for inclusion by NERC had references on file. He asked whether they had been rejected for failing to submit references — a policy that the committee has objected to before. (See “SDT Candidate Restored After Application Oversight,” NERC Standards Committee Briefs: July 22, 2020.)

In response, Kim explained that the candidates did submit references, but the template used by her team in preparing the report did not have a space for the information. Blohm suggested that the form be updated to ensure those candidates not recommended by NERC were represented with the same level of detail as those who were endorsed.

September 25, 2020

NERC Team Shows off ‘Nifty Tools’

NERC’s Bulk Power System Awareness Team on Thursday gave stakeholders a presentation on their role as the ERO’s “eyes and ears.”

“We collect data, analyze the data and report on the data,” Bill Graham, principal bulk system awareness coordinator, said during NERC’s eighth annual Monitoring and Situational Awareness Technical Conference, held via WebEx. “We’re continuously observing system conditions and using various tools that we have, as well as expertise, [to] try to identify any kind of threats.”

Graham gave his presentation after an update by Wei Qiu, senior engineer of event analysis, on trends in NERC’s energy management system outage data.

The seven-member Bulk Power System Awareness Team, part of NERC’s Reliability Risk Management department, has an average of 22 years of experience. It is headed by Director Darrell Moore, a former transmission operator for Georgia Power.

In addition to Graham, who received nuclear training in the U.S. Navy, it includes senior engineer Mani Mardhekar, a former power trader and analyst of bulk power system operations; senior analysts Ara Johns, a former generation dispatcher for Southern Co., and Brent Kane, a former reliability coordinator for PJM; Tony Burt, former supervisor of reliability coordination operations at Peak RC; and administrative assistant Stephanie Lawrence, who holds a degree in information technology.

In addition to issuing about a dozen special reports annually, the team provides a report each morning that is circulated to NERC CEO Jim Robb, FERC, the regional entities and some reliability coordinators. “It’s a description of what we’ve seen … threats that are potentially in place against the bulk power system, as well as any kind of weather events or anything of the like that needs to be at the forefront of everyone’s mind,” Graham said.

It also collects the EOP-004 disturbance reports filed daily by regulated entities.

“What my team does is the initial triage of these events to understand if there’s an immediate concern,” Graham said. It also files the information into databases used for event analysis and Lessons Learned reports.

But it is not involved with any compliance monitoring, Graham emphasized. “We do file the mandatory EOP-004 reports into the NERC database … but we don’t provide any kind of comment or input with regard to any compliance monitoring issues,” he said. “We steer clear of that 100%. If compliance ever does become an issue, we stop the conversation and get the correct parties involved. We just simply are not part of the compliance regulatory arm of NERC.”

The team has a variety of what Graham called “nifty tools,” including OSIsoft’s PI Vision, which tracks system frequency, and SAFNR v.3 (Situational Awareness for Situational Awareness Tool Nears Rollout.)

It also uses Genscape, which collects power prices and uses sensors to monitor transmission line loads.

Although it is largely used by power traders, “we use it to understand the health and wellbeing of the bulk power system,” said Graham, showing a screen shot from a day when he said there were “buying opportunities” in MISO.

“What my team does is we see this and try to understand why. Why is there a buying opportunity up in the Michigan area? Is there a plant that’s in a forced outage? Is there transmission congestion?”

The group also monitors “all the social media and news websites that you can imagine. So, for example we keep an eye on all the utility websites, all the reliability coordinator websites [and] all the balancing authority information that’s publicly available,” Graham said. “Likewise, we keep a close eye on social media. We do not participate, but we do watch what’s being talked about.”

And because NERC is a nonprofit organization, Graham said, “we make the best use of any single free Internet tool that’s available.”

“So, we’ve become experts at all the different weather websites,” he said. “Hurricanes are a huge deal for us.”

September 25, 2020

FERC, NERC to End CIP Violation Disclosures

FERC and NERC will no longer publicly post information about violations of the ERO’s Critical Infrastructure Protection (CIP) standards, according to a joint white paper published by the organizations on Wednesday (AD19-18).

Under the new rule, NERC will request that CIP noncompliance information filed to the commission be treated as critical energy/electric infrastructure information (CEII) in its entirety, and it will end its current practice of publicly posting redacted versions of the filings. It is unclear whether NERC will continue to provide public information about violations of CIP standards in any form.

NERC and FERC’s new direction is a sharp contrast to a proposal floated last year that would have seen the ERO file public cover letters with its CIP-related Notices of Penalty (NOP), including the name of the violator, the standards violated (but not the requirements) and the penalty amount. (See FERC, NERC Propose New CIP Disclosure Rules.) The remainder of the NOP, containing details on the violation, mitigation activity and potential vulnerabilities to cyber systems, would be submitted as a nonpublic attachment with CEII designation.

NERC has been redacting information claimed as CEII from public filings on a line-by-line basis since 2019; previously, the public version of NOPs involving CIP violations contained similar information as the confidential submissions to FERC, with CEII excluded entirely. The proposal for public cover sheets came about in response to “an unprecedented number of requests” under the Freedom of Information Act (FOIA), with the organizations saying the new approach would achieve “an appropriate balance of security and transparency.”

Dueling Concerns over Security, Transparency

Stakeholder responses to the last white paper, submitted in November 2019, revealed widespread opposition to the proposal, though the reasons for disapproval varied widely. (See FERC, NERC Reviewing Comments on CIP Disclosures.)

CIP violations — FERC headquarters in D.C. | © *ERO Insider*

Several consumer advocacy groups, such as the Foundation for Resilient Societies (FRS) and Public Citizen, criticized the plan for not providing enough transparency. FRS objected to the requirement that any CIP violations be fully mitigated before an NOP is submitted, and to allowing utilities to request indefinite delays in public disclosure. Public Citizen called for further reforms, including formal protection for whistleblowers.

At the other end of the spectrum was a number of industry representatives, such as the MISO Transmission Owner stakeholder sector, and a group of trade organizations, including the Edison Electric Institute, National Rural Electric Cooperative Association and WIRES. They argued that even the limited information that NERC and FERC proposed to release “could provide roadmaps to bad actors” targeting critical infrastructure assets by exposing vulnerabilities in the bulk power system.

Report Sides with Industry Objections

In their final decision, FERC and NERC leaned decisively toward the second line of reasoning, agreeing that the previous proposal “is insufficient to protect the security of the bulk power system” and that disclosing the identity of CIP violators creates “substantial risks” from hackers and other malicious cyber actors.

“Since the public does not have a statutory role in the enforcement of reliability standards, public disclosure of CIP noncompliance information does not serve any statutory purpose,” the white paper said. “Although commission and NERC staffs recognize the potential deterrent effect of publicizing the identity of violators in general, the security concerns discussed here outweigh the potential benefit.”

In addition, the report cited a filing by the Department of Energy that argued the commission “did not fully avail itself” of the authority to protect CEII provided to it by the Fixing America’s Surface Transportation Act and the Federal Power Act. The department also noted that the FOIA contains exemptions for both CEII and confidential business information, and suggested that CIP violation information could fall under either category.

September 24, 2020

NJ BPU Outlines ‘Shared Responsibility’ EV Plan

New Jersey regulators on Wednesday approved a “shared responsibility” model for building a public electric vehicle charging network that will have utilities provide the wiring infrastructure and private investors owning the charging equipment in most instances (QO20050357).

The New Jersey Board of Public Utilities’ order will have ratepayers fund the utility investments in “make ready” infrastructure for light-duty EVs. Non-utility entities — site owners, property management companies, and EV service equipment companies — will install and operate charging stations using private capital.

Electric distribution companies (EDCs) would only be allowed to own the charging equipment in areas of “last resort” — locations that fail to generate private sector requests for make-ready infrastructure after at least 12 months.

The BPU’s action implements the Electric Vehicle Act of 2020, which set a goal of registering at least 330,000 light-duty, plug-in EVs by the end of 2025, at least 2 million by 2035, and 85% of all new light-duty vehicles sold or leased by 2040.

According to the state’s Energy Master Plan, transportation generates 42% of the state’s net greenhouse gas emissions, making EV adoption essential to meeting the state’s goal of 100% clean energy and an 80% cut in emissions from 2006 levels by 2050.

NJ Lags

“To date, the private sector has not made a business case to install EV chargers without a critical mass of EVs on the road, and consumers hesitate to purchase EVs without the ability to charge away from home,” the order said. “As a result, the adoption of EVs has lagged. The circular problem continues as the EVSE [electric vehicle service equipment] infrastructure companies are disinclined to develop publicly available charging sites where there is an uncertain amount of demand for their services. …

“While New Jersey ranks near the bottom of EV adoption, stakeholders generally agree that an investment in charging infrastructure to address range anxiety coupled with the BPU’s new EV incentives will serve to spark EV adoption and confidence in the emerging technologies.”

New Jersey is also encouraging the transition by offering residents purchasing or leasing a new EV a subsidy of $25/mile of EPA-rated all-electric range. The maximum payment is $5,000 for vehicles with a range of more than 200 miles.

‘Make Ready’

NJ BPU EV charging — New Jersey residents purchasing or leasing a new electric vehicle are eligible for subsidies of $25/mile of EPA-rated all-electric range. The maximum payment is $5,000 for vehicles with a range of more than 200 miles. | *Center for Sustainable Energy*

EVSE infrastructure companies or site hosts would notify their EDC of their intent to install EVSE at a location. The EDCs would develop and own the transformers, meters and other make-ready infrastructure.

The order says such sites will be deemed “used and useful” — allowing EDCs to recover their investments — even if the make-ready site is not immediately used. “While this does not exempt the utility from showing that it was prudent in the manner in which it made the site charger-ready, the utility should not be at financial risk for putting in an installation that was duly authorized pursuant to this order,” the board said.

EDCs will be permitted to begin work without board review for any make-ready installation expected to cost less than $100,000. Projects estimated between $100,000 and $250,000 will be subject to a “soft cap” requiring the EDC to notify board staff and the New Jersey Division of Rate Counsel; it will be allowed to begin work unless staff or another party objects to the project within 60 days. Projects expected to exceed $250,000 will be subject to a “hard cap” requiring board approval.

The order sets the minimum filing requirements for light-duty EV infrastructure proposals from EDCs and requires them to file their plans by Feb. 28, 2021. EDCs must propose ways to minimize the barriers to EV adoption created by demand charges. Filings from two utilities, Public Service Gas and Electric and Exelon’s Atlantic City Electric, are already under review by the BPU.

The Electric Vehicle Act of 2020 set the following goals for plug-in vehicle (PIV) adoption:

At least 25% of state-owned non-emergency light-duty vehicles will be PIVs by Dec. 31, 2025.
At least 400 DC fast chargers (at least 50 kW) available for public use at no fewer than 200 charging locations by Dec. 31, 2035.
At least 1,000 Level 2 chargers shall be available for public use across the state by Dec. 31, 2025. The state currently has more than 400.
At least 15% of all multifamily residential properties shall be equipped with EV chargers by Dec. 31, 2025.

The Department of Environmental Protection, consulting with the BPU, will establish goals for electrification and infrastructure development for medium- and heavy-duty vehicles such as transit and school buses by Dec. 31, 2020.

The board acknowledged concerns that EVs will not contribute to the Transportation Trust Fund, which generates revenues for maintenance and road repairs through a tax on gasoline and diesel sales. Staff said stakeholders’ consensus was to develop a user fee for EV drivers; it pledged to work with the state Department of Transportation to address the issue.

The board adopted staff’s recommendation that it allow charging infrastructure owners flexibility to adopt payment methods that meet their needs, noting that the 2020 law established sale of electricity at an EV charger as a service, not a regulated sale of energy.

September 24, 2020

Calif. to Halt Gas-powered Auto Sales by 2035

California Gov. Gavin Newsom issued an executive order Wednesday that will prohibit the sale of all gasoline-powered automobiles in the state by the middle of the next decade.

The governor’s order will require that all new passenger cars and trucks sold in California be emissions-free by 2035, accelerating the state’s already ambitious goals of electrifying its transportation sector. The state currently has more than 725,000 EVs on the road and accounts for about 50% of the nation’s EV sales.

The move is expected to reduce statewide automobile emissions of greenhouse gases by 35% and NOx by 80%.

The order also directs the state’s Air Resources Board to develop regulations mandating that 100% of all operations of medium- and heavy-duty trucks be emissions-free by 2045, “where feasible,” with the mandate becoming effective in 2035 for all drayage trucks.

“This is the most impactful step our state can take to fight climate change,” Newsom said in a statement.

The transportation sector accounts for more than half of California’s carbon emissions, 80% of smog-forming pollution and 95% of diesel emissions, leaving the Los Angeles Basin and Central Valley with some of the dirtiest air in the country, the statement noted.

“For too many decades, we have allowed cars to pollute the air that our children and families breathe. Californians shouldn’t have to worry if our cars are giving our kids asthma,” Newsom said. “Our cars shouldn’t make wildfires worse — and create more days filled with smoky air. Cars shouldn’t melt glaciers or raise sea levels threatening our cherished beaches and coastlines.”

California gas powered sales — | *California Energy Commission*

Newsom’s order requires state agencies to partner with the private sector to speed up deployment of “affordable fueling and charging options” and to ensure that all Californians have “broad accessibility” to EV markets. The order does not prevent residents from owning gasoline-powered cars or selling them on the used car market.

The governor’s office is assuming that zero-emission vehicles “will almost certainly be cheaper and better” than traditional vehicles by the time the rule goes into effect, according to the statement.

“The upfront cost of electric vehicles are projected to reach parity with conventional vehicles in just a matter of years, and the cost of owning the car — both in maintenance and how much it costs to power the car mile for mile — is far less than a fossil fuel-burning vehicle,” the statement said, citing a BloombergNEF study.

Newsom also positioned the move as an economic opportunity for the state and U.S. automakers. EVs are California’s second-biggest export, Newsom said during a press conference.

“If American manufacturers do not commit to zero emissions, they’re not going to be able to sell their cars globally. They’re not going to be able to sell their cars in China, in India, in Israel, in Ireland, [which] are also committed to similar goals that California is advancing,” Newsom said in a video posted on Twitter.

“This is about strengthening our competitiveness [and] encouraging more manufacturing jobs,” he said.

‘Strong Action’

Newsom’s order met with predictable praise from environmental groups.

“In the midst of a historic wildfire crisis, Gov. Newsom is taking strong action to protect California’s economy and the health of its people,” Environmental Defense Fund President Fred Krupp said in a statement. “His announcement today will not only address the single largest source of climate and air pollution in California, but is a major step toward boosting his state’s economic competitiveness and helping Californians who are suffering extraordinary harms from air pollution.”

Krupp added that the new rules will position California “to win a new generation of jobs building affordable zero-emission vehicles — jobs that Europe and China are also hoping to capture.”

“With this announcement, California has the opportunity to be the center of the global clean transportation industry and once again to lead the nation in addressing climate change,” Annie Notthoff, California director of the Natural Resources Defense Council, said in a statement. “The past years of apocalyptic wildfires, record temperatures and droughts have made climate change and pollution all too real for everyone in the Western U.S. — most of all low-income households and communities of color.”

The move also sparked criticism.

Thomas Pyle, president of the American Energy Alliance, an advocacy group backed by fossil fuel producers, castigated the measure for allowing “bureaucrats in Sacramento” to make buying decisions that families should make for themselves.

“Right now, 97% of Americans decide to buy a car with an engine powered by gasoline. They make that decision for all kinds of reasons, including safety, size, range, comfort and, in many instances, because an electric vehicle is too expensive,” Pyle said in a statement. “The governor knows that today’s engines are cleaner, more efficient and more powerful. He also knows that there is no such thing as an environmentally perfect vehicle. This is not only a bad idea, and a bad deal for the state of California, it’s insulting to consumers and families.”

September 24, 2020

Utilities Pledge to Build Largest EV Charging Network

Six Midwestern energy companies have banded together in the hopes of developing America’s largest interstate electric vehicle charging network by the end of 2022.

Consumers Energy, DTE Energy, Evergy, Oklahoma Gas & Electric, Ameren Illinois and Ameren Missouri announced on Tuesday that they had signed a memorandum of cooperation, pledging to construct charging stations across five states. The companies said the network will facilitate clean transportation and bolster range confidence for long-haul EV trips.

The agreement doesn’t say how many charging stations will be built. Ameren spokesperson Jenny Barth said each energy company will “build a program that works best for their area.”

The utilities said more companies could join the effort. They added that network construction is dependent on regulatory approval from each utility’s state.

Largest EV Charging Network — | *Evergy*

“By partnering in the creation of a multistate electric charging network with energy companies outside of our own footprint, we are able to help our customers safely and economically travel to far-ranging destinations,” Ameren Missouri President Marty Lyons said in a release. “Detroit to Oklahoma City or St. Louis to Denver, we are supporting our customers, our communities and our country with cleaner driving.”

Ameren said transitioning to electric transportation can help “dramatically” lower carbon emissions, allowing the utility to meet carbon-reduction goals.

“Our focus in joining this multistate coalition is to develop a charging infrastructure that will help reduce ‘range anxiety’ and lead to broader adoption of electric vehicles,” Ameren Illinois President Richard Mark said.

The Edison Electric Institute estimates that there are more than 1.5 million EVs currently on the nation’s roadways, with just 100,000 public charging stations to support them. The trade association forecasts nearly 19 million electric cars on the road by 2030. To achieve that growth, EEI estimates that 9.6 million public charging stations will be needed.

“Expanding the use of electricity in transportation saves customers money, improves the environment by reducing emissions and enhances quality of life for everyone,” EEI President Tom Kuhn said. “By deploying charging infrastructure and accelerating electric transportation, EEI’s member companies, including Ameren and the other companies collaborating on this initiative, are working together to build a cleaner and stronger economy for the future.”

While there are about 40 EV models today, the Electric Power Research Institute expects automakers to have more than 130 models to choose from in just two years.

“Consumers Energy is committed to building the backbone of the charging network for electric vehicles across Michigan,” Senior Vice President Brian Rich said. “We know we can play an important role in charging the growth of EVs in our state and region, and know that will be good for Michigan’s economy, our communities and the environment.”

DTE Electric CEO Jerry Norcia also said his utility “has a significant role to play in helping make EVs a viable option for many.”

Evergy, which serves portions of Missouri and Kansas and was formed by the merger of Westar Energy and Kansas City Power and Light, tweeted that it was “excited” to partner with the other utilities. Evergy Chief Customer Officer Chuck Caisley said the network will make it “convenient and easy for EV drivers to charge their vehicles no matter where they are throughout the Midwest.”

September 24, 2020

New Study Offers Alternative to Carbon Pricing

Environmental policymakers should abandon the social cost of carbon (SCC) and adopt a more practical metric tied to net-zero-emissions goals, according to a new study.

The study, led by Noah Kaufman at Columbia University’s Center on Global Energy Policy and published in Nature Climate Change, notes that SCC estimates — intended to represent the “optimal” CO₂ price that maximizes net benefits to society — range from “under $0” per ton of CO₂ to more than $2,000/ton.

“The wide range of SCC estimates provides limited practical assistance to policymakers setting specific CO₂ prices,” Kaufman says. Instead, Kaufman and his coauthors recommend what they call the “near term to net zero” (NT2NZ) approach, which they say can eliminate much of the uncertainty, although they acknowledge it “balances benefits and costs only imperfectly.”

carbon pricing alternative — prices in proposals to Congress in 2019. | *Noah Kaufman, et al.*

The authors say the SCC is undermined by the large uncertainties over risk aversion levels, attempts to assign monetary values to noneconomic climate damages and the appropriate discount rates — the value placed on future generations.

The NT2NZ approach proposes a four-step methodology:

Select a net-zero CO₂ emissions date.
Select an emissions pathway to the net-zero target that balances the risks of even higher temperature changes with the additional costs of decarbonizing faster.
Estimate CO₂ prices consistent with the emissions pathway in the near term (e.g., next decade).
Periodically update steps 1-3 using an “an adaptive management strategy.”

“Focusing on the near term means that CO₂ price estimates should not be unduly influenced by assumptions about the highly uncertain long-term evolution of technologies and behavior,” Kaufman said. “Adaptive management can enable jurisdictions to stay close to the desired emissions pathway without making policy details contingent on assumptions about highly uncertain long-term variables.”

To illustrate the approach, the study looked at three straight-line emissions pathways from 2020 levels to net-zero CO₂ emissions targets in 2060, 2050 and 2040. It resulted in benchmark prices in 2025 of $32, $52 and $93 per metric ton (in 2018 dollars), respectively. The price roughly doubles by 2030, “reflecting a much higher annual growth rate than typical CO₂ price estimates based on the SCC or rising at the rate of interest,” the authors write.

Complementary policies such as more aggressive energy efficiency measures and regulations that lead to higher coal retirements could lower the 2050 CO₂ price by $10 to $20/ton, with the price rising by the same amount with less aggressive policies.

The authors acknowledge that uncertainties present in the SCC approach — such as near-term clean energy innovation and fossil fuel prices — also impact the NT2NZ method. “But the NT2NZ approach avoids much larger uncertainties, including assigning monetary values to climate change damages,” they say.

The Climate Leadership and Community Protection Act (CLCPA) signed by Gov. Andrew Cuomo last year requires the Department of Environmental Conservation (DEC) to establish a carbon price — based on either abatement or damage cost estimates — that state agencies can use to consider the societal value of actions to reduce GHG emissions in their decision-making.

The DEC this summer provided draft regulations on the value of carbon to fulfill the CLCPA requirements. The comments that the department receives will be part of the public record.

“It’d be great if the state took a look at our method when developing its [emissions] plan,” Kaufman told RTO Insider.

Pricing emissions, however, should not be conflated with spending on climate change, he said.

Speaking at a Sept. 9 webinar about the possibility of a green stimulus package from Congress after the presidential election, he said, “There’s a pretty big caveat: Spending on clean energy is a really ineffective way to reduce emissions, at least by itself.”

Kaufman recommended keeping expectations low for progress toward deep decarbonization.

“When you look at the data on the impacts of the nearly $100 billion in spending on clean energy from the 2009 stimulus, or the quarter-trillion dollars worldwide, you can find some really good outcomes for clean technology projects. But on emissions? No real evidence that it moved the needle,” Kaufman said.

Throwing money at clean technologies is not a climate strategy, he said. The core of climate policy strategies are policies that directly address emissions, such as regulatory standards and prices.

“The surest way to drive a climate policy analyst crazy is to describe a climate plan based on how much it’s spending,” Kaufman said. “Spending can be a great complement to climate plans, making them cheaper, more effective, more equitable. That’s what Europe is doing right now. But if you want to reduce emissions, regulate emissions.”

September 24, 2020

MISO Sets Candidate Slate for Board Elections

MISO’s Board of Directors has three seats up for grabs in December, though the new board is only guaranteed one new face.

The RTO’s Nominating Committee advanced current Directors Theresa Wise and Robert Lurie for member consideration, along with newcomer Jody Davids. Formerly chief information officer for PepsiCo, Davids has also served as CIO for Agrium, Best Buy and Cardinal Health. She currently sits on the board for Premier, a Charlotte, N.C.-based health care improvement company.

MISO board elections — Jody Davids | *Premier*

Wise and Lurie are both rounding out their first terms and applied for reappointment. Lurie served the one-year remainder of former Director Thomas Rainwater’s term, which expires at the end of December.

Longtime Director Baljit Dail will not make a reappearance at MISO’s U-shaped board table next year. Dail spent 12 years on the board — three more than technically allowed — through a special waiver that allowed him an extra term so the board could retain a person with technology expertise.

MISO’s 139 voting-eligible members can begin casting ballots for candidates beginning 8 a.m. Thursday. The electronic polls will close at 5 p.m. Oct. 30. Board elections require a minimum 25% participation rate to achieve quorum.

Members can vote for or against any of the candidates, or abstain. Candidates must earn a majority of votes cast to be installed. MISO will announce election results in mid-November.

The board voted unanimously during its Sept. 17 meeting to retain Phyllis Currie as its chairman in 2021.

September 24, 2020February 25, 2024

Indiana City Wins Ruling on Station Power

FERC ruled last week that generating facilities that are not online and producing energy must pay for their station power at retail rates subject to state jurisdiction and directed PJM to consider changing its Tariff accordingly (EL20-30).

The commission said an offline generator that requires power to operate its lighting, air conditioning and other facilities “is consuming electricity as an end user and thus, consistent with the boundaries of the commission’s jurisdiction under the [Federal Power Act], the provision of station power is a retail sale subject to state jurisdiction.”

The commission’s ruling came in response to a complaint filed by Lawrenceburg, Ind., and the Indiana Municipal Power Agency against the RTO, American Electric Power Service and Lawrenceburg Power seeking to void the power self-supply monthly netting provisions of the RTO’s Tariff.

The city’s Lawrenceburg Municipal Utilities has an exclusive franchise for supplying electricity within city limits and says Lawrenceburg Power’s 1,160-MW combined cycle plant in the city must take station power service from the city because Indiana law does not allow it a choice of retail supplier. The plant is interconnected with AEP transmission facilities under PJM’s operational control.

FERC approved the netting rules in 2001, saying station power can be supplied to a generating plant in three ways: on-site self-supply (from behind-the-meter generation); remote self-supply (from another generator owned by the same company); or third-party supply.

| Lawrenceburg Municipal Utilities

While the commission disclaimed jurisdiction over the supply of station power, it rejected the petitioners’ request for a declaratory order finding the station power monthly netting provision in section 1.7.10(d)(i ) of the PJM Tariff null and void.

Instead, FERC instituted a new proceeding, requiring PJM to propose changes to its Tariff consistent with the order or show cause why changes are not necessary (EL20-56). The RTO has 60 days to respond.

FERC said PJM’s proposed revisions should clarify that the monthly netting provision in section 1.7.10(d)(i) “does not determine whether a retail sale of station power has occurred in that month.” It also said Tariff provisions should clarify that PJM has no responsibility for the determination of any state-jurisdictional retail rates.

“Because the PJM Tariff’s self-supply monthly netting provision can be read to — and indeed has been relied on by certain PJM generators to assert the right to — determine whether a retail sale of station power has occurred and avoid the retail purchase of station power, which is inconsistent with the commission’s jurisdiction, we find that PJM’s Tariff may be unjust, unreasonable, unduly discriminatory or preferential,” FERC said.

Lawrenceburg Power told FERC that Lawrenceburg Municipal Utilities has attempted to charge the generator a minimum of $845,000 annually “even if Lawrenceburg Power does not consume any station power in the entire year” and that it prefers self-supplying its station power under the PJM Tariff.

“Arguments about the justness and reasonableness of the retail rates, and about what entity within the state of Indiana has authority to provide retail service, are more appropriately raised before the relevant state regulatory body,” FERC said. “The commission does not have the authority to determine when, and on what terms, a retail sale of station power is made.”

The ruling is likely to have impacts on other merchant generators.

Among the intervenors in the case were Buckeye Power, which said it and one of its member cooperatives, Washington Electric Cooperative (WEC), are involved in a dispute with Waterford Power, a merchant generator located within WEC’s service territory, regarding WEC’s right to supply Waterford’s station power.