November 15, 2024

ERCOT Technical Advisory Committee Briefs: Nov. 29, 2018

By Tom Kleckner

ERCOT’s Technical Advisory Committee last week endorsed a staff suggestion to increase by 50% the boundary thresholds used to project future loads in Far West Texas.

During the committee’s last meeting of 2018, stakeholders unanimously approved the recommendation, which, assuming Board of Directors approval, raises the Far West weather zone’s boundary threshold from 5% to 7.5%.

The change would allow ERCOT to nearly double the Far West load from its current 3.6 GW to 6.9 GW in 2027, and support 500 MW of growth for 2019-2021 without supporting documentation. The growth has been fueled by the Permian Basin’s rich petroleum reserves, the largest in the U.S. Production has nearly doubled in the last three years, to 3.4 million barrels/day.

Staff said it has been challenged in keeping up with the load growth. The grid operator adjusted its 2019 forecast by 200 MW to keep up with the rapidly increasing demand, and it foresees about a 500-MW increase over the 2018 summer peak (consistent with a similar increase as compared to 2017).

“We’ve understated the Far West load the last two cycles,” said ERCOT’s Calvin Opheim, manager of load forecasting and analysis. He told the TAC the ultimate goal is to produce more realistic projections.

Permian production has been hampered recently by a lack of sufficient pipeline infrastructure. Falling oil prices have also made production less economical, leading some stakeholders to question the need to increase forecasts.

“Our concern is whether [the suggested change to the forecast process] results in building transmission for speculative load,” Golden Spread Electric Cooperative’s Mike Wise said. He referenced a recent ERCOT regional transmission study that forecasted increased load based on rising oil prices.

“We thought all this load was coming on, but approximately 80% was canceled,” Wise said. “You’ve got these loads out there, but we don’t want to build unnecessary transmission. I’m concerned about building transmission ahead of speculative load, then having a V8 moment later on when the load does not materialize.”

“We have a tremendous amount of holes punched in the ground,” Morgan Stanley’s Clayton Greer said of the Permian Basin region. “The capital’s been expended, but there’s no way to get it to market. When production increases, there’ll be a dramatic increase in load. They wouldn’t be punching holes if they were speculative. The holes are in the ground, and extraction is going to happen.”

ERCOT Senior Manager of Transmission Planning Jeff Billo said the grid operator will conclude a major load study next June that could predict “the next piece of infrastructure we need.”

Reliant Energy Retail Services’ Bill Barnes noted that a two-year revision to the planning guide (PGRR042) gives staff flexibility while establishing a methodology for setting their load forecasts.

“Having ERCOT understand load growth is a good thing,” Barnes said.

Stakeholders Tweak Ancillary Service Methodology

Stakeholders endorsed staff’s recommendation to not change how ERCOT computes regulation and responsive reserve service as part of its 2019 ancillary service methodology, after first removing a 1,375-MW floor on non-spin quantities during peak hours.

The Wholesale Market Subcommittee and Reliability and Operations Subcommittee (ROS) have both suggested removing the floor during the hours ending 7 a.m. through 10 a.m. The Lower Colorado River Authority and Luminant were among the TAC members asking that the floor be maintained, saying it would provide more reliability insurance with the growth of volatile wind generation.

However, a motion to remove the floor passed with 71% of a roll call vote. The committee then endorsed staff’s recommendation, with two abstentions.

“I’m a little amazed we’re trying to preserve a floor that’s not necessary and that’s just increasing costs for no good reason,” Greer said. “I thought the goal the last couple of years was to get rid of artificial floors and artificial inefficiencies in our market, and to try and do things in a more analytical way.”

Sandip Sharma, ERCOT’s manager of operations planning, said the 1,375-MW floor has been in place since the nodal market went live in 2010. The grid operator removed a 2,000-MW cap on non-spin reserves in 2016 but left the floor unchanged.

“If you look at the numbers with and without the floor, it’s really not a big difference,” Sharma said, noting the number can be as high as 200 MW across summer peak hours. “Most of the other months, where there’s a higher risk of wind forecast error and net load ramp variability, we’re actually procuring more than what the floor is.”

Citigroup Energy’s Eric Goff said that during the summer months, non-spin deployment “generally” means generating units are turned on and made available for security-constrained economic dispatch (SCED) at a price floor.

“In the summer, when we do have [non-spin deployment] below the floor, we see this generation offered into SCED at a different cost than it normally would,” Goff said. “So it has nothing to do with reliability at all.”

TAC Confirms New ROS Leadership

Stakeholders confirmed new leadership for the ROS, which develops, reviews and maintains operating guides and planning criteria.

Tenaska’s Boone Staples was approved as the ROS chair, and Southern Power’s Tim Hall as vice chair.

Stakeholders Take on 31 Change Requests

Having not met since September and facing a year-end deadline to push through change requests, the committee considered 31 proposed Nodal Protocol revision requests (NPRRs) and other changes.

The TAC approved NPRR889, which adds the newly defined term “settlement-only generator” to replace “non-modeled generator,” after making several desktop changes. Stakeholders modified the definition of “settlement-only transmission generator” to include those units connected to the system with a rating of 10 MW or less and registered with the Texas Public Utility Commission as a “power generation company.”

The NPRR introduces new terms to clarify the distinction between transmission-connected resources and distribution-connected resources, and reorganizes various terms for resources that describe the status, services provided and/or technology used by resources.

Stakeholders agreed to table two other revision requests for a month and allow their further consideration. South Texas Electric Cooperative’s Clif Lange asked for more time to “discuss internally” with staff the co-op’s reliability concerns about NPRR871. The proposed change addresses the review process for transmission projects funded by customers or resource entities, using language pulled from NPRR837’s initial filing to allow for a standalone review. NPRR837 was approved in July.

The committee also tabled NPRR850, referring the proposal to the Credit Work Group and Market Settlements Working Group. The change would lay out principles for staff and market participants to follow during a market suspension and restart, and specifies how settlements will occur during a suspension.

The TAC approved 14 other NPRRs, a Load Profiling Guide revision request (LPGRR), two changes to the Nodal Operating Guide (NOGRRs), three Other Binding Document revisions (OBDRRs), four changes to the Planning Guide (PGRRs), a Retail Market Guide change (RMGRR), two revisions to the Resource Registration Glossary (RRGRR) and a system change request (SCR):

    • NPRR878: Prescribes ERCOT’s posting of an emergency response service obligation report for transmission and/or distribution service providers to the market information system certified area.
    • NPRR879: Proposes that intermittent renewable resources (IRRs) carrying ancillary service (AS) responsibilities receive a SCED base point calculated using the resource’s five-minute intra-hour forecast and adds generation resource energy deployment performance metrics to score performance during those intervals. The change corrects the unit of measure for some billing determinants and also contains administrative edits.
    • NPRR881: Reduces the residential validations requirements from an annual process to a triennial market event.
    • NPRR882: Updates the definition of initial synchronization and interconnecting entity to include certain types of facility equipment changes and clarifies fee language related to generation interconnection or change requests (GINRs).
    • NPRR884: Introduces various systems changes needed to manage cases when ERCOT issues a reliability unit commitment instruction to a combined cycle generation resource that is already qualified scheduling entity-committed for an hour. The resource will operate in a configuration with greater capacity for that same hour.
    • NPRR887: Creates a new market information system certified area posting that provides insight into the potential risk associated with each counterparty’s default uplift charges.
    • NPRR892: Places a $75/MWh floor on energy on units carrying non-spinning and responsive reserves and/or regulation-up service concurrently to ensure the non-spin capacity is priced above the floor.
    • NPRR893: Clarifies the effective fuel index price (FIP) used in market activities executed prior to the operating day’s index publication because the current FIP definition does not address the timing around receiving the data and when it can feasibly be used by market applications. The NPRR also incorporates the OBD “System-Wide Offer Cap and Scarcity Pricing Mechanism Methodology” into the Protocols.
    • NPRR894: Corrects the formula for allocating unaccounted for energy (UFE) to UFE categories by removing its obsolete components referring to distribution voltage level non-opt-in entities.
    • NPRR895: Removes the current exclusion for IRRs that are not wind-powered generation resources in calculating the real-time AS imbalance payment or charge. Photovoltaic generation resources (PVGRs) are currently excluded in both the methodology for implementing the operating reserve demand curve (ORDC) to calculate the real-time reserve price adder and the process for settling the real-time AS imbalance payment or charge.
    • NPRR897: Adjusts the black start service procurement and testing process timeline, adds a weather limitation disclosure form and aligns the load-carrying test procedure with actual practice.
    • NPRR898: Allows the electronic return of ERCOT-polled settlement metering site certification documents to the transmission and/or distribution service provider.
    • NPRR899: Creates a new process by which qualified market participants can request to opt out of receiving digital certificates and having to appoint a user security administrator (USA); clarifies ambiguous requirements certificate holders must meet to receive and continue to hold digital certificates; and clarifies that a USA may be responsible for managing access to certain ERCOT computer systems that do not require digital certificates. The NPRR also revises forms to give new applicants the ability to opt out of receiving digital certificates as long as they meet the necessary qualifications. Allows a qualified market participant that has previously opted out to opt back in.
    • NPRR901: Proposes a new resource status code (“EMRSWGR”) for switchable generation resources operating in a non-ERCOT control area to provide additional transparency for operations and reporting.
    • LPGRR065: Related to NPRR881, this change reduces the residential validations requirements from an annual process to a triennial market event and removes unnecessary load profile model approval process language.
    • NOGRR178: Clarifies language relating to automatic load shedding.
    • NOGRR182: Harmonizes the transmission operator emergency operations plan submittals with NERC Reliability Standard EOP-011-1 by clarifying that TOP plans should be received by Feb. 15 as part of the annual effort to review them within 30 days.
    • OBDRR006: Aligns language with NPRR884’s protocol changes.
    • OBDRR007: Changes the ORDC’s methodology to consider curtailed PVGRs in determining the ORDC price adders.
    • OBDRR009: Revises the online and offline capacity reserves for ERCOT out-of-market actions related to DC ties.
    • PGRR065: Documents and clarifies existing processes by including transmission project information and tracking report and data requirements.
    • PGRR066: Creates an inactive status for GINR projects that won’t be listed in ERCOT’s monthly generation interconnection status report but will retain the interconnection request numbers. The PGRR also defines a process that can be used to cancel interconnection requests that have failed to meet requirements.
    • PGRR067: Describes how wind and solar facility equipment changes are treated throughout the generation interconnection process and clarifies language for GINR-related fees.
    • PGRR068: Lays out the process for adding a DC tie to ERCOT’s planning models and associated requirements, related to the Texas PUC’s directive to determine how best to model the proposed Southern Cross DC tie in its planning cases (Project 46304). (See “Staff’s Determination on DC Tie Flows, Pricing Gets OK,” ERCOT Board of Directors Briefs: Oct. 9, 2018.)
    • RMGRR155: Related to NPRR889, the change uses the new term settlement-only distribution generator (SOG) to replace references to non-modeled generator and registered distributed generation.
    • RRGRR018: Also related to NPRR889, uses the SOG term to replace glossary references to non-modeled generator.
    • RRGRR019: Adds a modeling designation for switchable generation resources (SWGRs) to the resource asset registration form, indicating that SWGRs can potentially operate in another control area.
    • SCR797: Allows ERCOT to automatically share current operating plans with a transmission service provider (TSP) upon request by that TSP.

CPUC Expands Probe into PG&E Practices After Deadly Fire

By Robert Mullin

California regulators will open a new phase of an investigation into Pacific Gas and Electric’s troubled safety practices as the utility faces allegations that its equipment was responsible last month for igniting the Camp Fire, by far the deadliest wildfire in the state’s history.

Aftermath of Camp Fire in Butte County, Calif. | California Governor’s Office of Emergency Services

Public Utilities Commission President Michael Picker announced the development Thursday after a turbulent start to what was meant to be a routine voting meeting. A group of raucous protesters briefly shut down proceedings before being removed from the commission’s San Francisco hearing room.

The first phase of the commission’s examination focused on the breakdown of safety practices leading to the September 2010 PG&E natural gas pipeline explosion that killed eight people and destroyed 38 homes in San Bruno. Picker said the next phase will look into the “corporate governance, [and] the structure and operation of PG&E to determine the best path forward for Northern California to receive safe, affordable, reliable electric and gas service.

Michael Picker | RTO Insider

“As I reviewed the [San Bruno] report, I found myself asking, ‘How can we do that better? What’s the role of the CPUC? How can PG&E actually pursue these duties and do it more safely? Is there a different model to ensure that we have safe and reliable gas and electric service?’” Picker said.

While the cause of the Camp Fire remains under investigation, PG&E filed a report with the CPUC on the day the fire started saying it had experienced an outage on a 115-kV line and observed damage to a transmission tower near the fire’s ignition point. At Thursday’s meeting, Picker said, “The details of the fire are still unfolding.”

Picker had signaled the move to expand the safety probe earlier in the month as the Camp Fire raged through Butte County in the northern part of the state. (See Destructive Fire Drives Down PG&E Stock.) Independent reports on prior deadly incidents criticized PG&E’s safety practices as “dysfunctional” or lacking clarity, he noted.

“This is the kind of thing that keeps me awake at night,” Picker said.

PG&E critics packed Thursday’s meeting, which featured an extended public comment period in which more than 30 residents spoke out against the company, urging the CPUC not to orchestrate a bailout. They pointed to Picker’s recent conference call in which he told Wall Street analysts that it would not be good public policy to allow the utility to go bankrupt. (See Camp Fire Prompts Talk of PG&E Bailout of Breakup.) Picker’s comments helped halt a sharp slide in the company’s share price, which had fallen by more than 62% in the course of a week.

Some speakers at the meeting aimed their anger directly at the CPUC — and Picker in particular.

“The commission’s disregard for the welfare of California has never been more blatant than when President Picker made a statement of the commission’s intent to rescue PG&E … while bodies from the Camp Fire were still being counted — and are still being counted,” said Barbara Stebbins of the California Alliance for Community Energy.

Picker defended his efforts to buttress PG&E, saying, “To operate the grid in a safe manner, PG&E has got to be able to sign contracts, borrow money, raise capital and sign contracts.”

A handful of speakers from Bay Area chapters of the Democratic Socialists of America called for PG&E to be converted into a publicly owned utility, blaming the company’s safety failures on its drive for profits.

Other speakers called for the arrest and prosecution of PG&E executives, who they said were ultimately culpable for the Camp Fire, which leveled the town of Paradise. At least 88 people died and nearly 200 area residents remain missing from the fire that began Nov. 8. Speakers also pointed to the 17 fires last year that investigators have already blamed on PG&E.

Janice Murota, a retired physician, told commissioners, “Not only do we not hold PG&E executives responsible personally for the deaths and the destruction, but we’re expected to bail them out financially. … Please don’t hold us on the hook to cover their liability and their costs. It’s just too much money.”

The public comment period concluded with several protesters unfurling a banner and chanting, “This meeting cannot continue until PG&E admits its crimes.” Picker at that point asked for a five-minute recess to allow protesters to chant before being cleared from the room. One protester could be heard yelling, “We’ll be back!” before exiting.

No ‘Firm Conclusions’

Once the dust settled, the CPUC voted to approve a decision requiring PG&E to adopt 60 safety recommendations laid out in an independent assessment of the utility’s “safety culture.” The CPUC commissioned the assessment by NorthStar Consulting Group in response to the San Bruno disaster.

In 2011, an independent review panel cited a “dysfunctional culture” at PG&E as the main factor contributing to the explosion. NorthStar noted that before the San Bruno incident, “the goals of [PG&E’s] enterprise risk management process were disconnected from the reality, decisions and actions throughout the company.”

While NorthStar credits PG&E for increasing its focus on safety, Picker noted the firm’s report found the company does not have a “clear vision” for its safety program.

Among the report’s “critical” recommendations to PG&E and the CPUC were:

Development of a comprehensive safety strategy, with associated timelines and deliverables, resource requirements and budgets, personnel qualifications, clear delineation of roles and responsibilities, action plans, assignment of responsibility for initiatives, and associated metrics to assess effectiveness.

Greater coordination among PG&E’s lines of business and its corporate safety department to increase consistency, improve efficiencies, minimize operational gaps and facilitate sharing of best practices.

A non-punitive system for reporting actual and potential safety incidents to the CPUC to encourage transparency and sharing of lessons learned among all California utilities.

Adding a performance-based ratemaking mechanism with a safety element to the PG&E general rate ruling approved last year, which runs through 2019.

Development of an implementation plan for NorthStar’s recommendations, to be submitted to the CPUC.

Picker acknowledged that the NorthStar report did not address the 2017/18 fires being attributed to PG&E.

“I don’t have any firm conclusions [about the fires]. That’s why we’re opening the next phase” of the investigation, Picker said.

He likened the CPUC’s response to PG&E’s situation — including efforts to maintain investor support — to remodeling an airplane in mid-flight: “We can’t just crash the plane to make it safer. We have to keep flying at the same time.

“I recognize the public’s growing interest in the future of PG&E, and while everything’s on the table, I want the public to understand that this is going to be a deliberative process and it involves actors other than the CPUC,” Picker said, noting the involvement of the California legislature, capital markets and a federal monitor appointed last year to oversee PG&E’s progress on safety measures.

“The NorthStar report had very specific recommendations but also raised some key fundamental questions,” Commissioner Liane Randolph said. “The fact that they were seeing differences in the effectiveness of the safety based on different parts of the company … just raises some key questions about the management of the company and how the safety culture is handled throughout the enterprise and whether it’s even possible to have all the enterprises have an equal amount of safety.”

Commissioner Clifford Rechtschaffen said it was important to reiterate the ambitions of a safety culture.

“It’s about promoting a mindset, practices and institutionalizing processes that promote and prioritize continuing, ongoing safety improvement. There’s no such thing as being good enough … [but] always looking for how can we do better, how can we make our processes safer — not just [by] meeting compliance but going beyond compliance.”

TO Rate Request Goes to Settlement

In its 2020 transmission owner rate case filed with FERC earlier this year, PG&E cited the financial challenges stemming from the “new normal” of California wildfires when it asked to raise its base return on equity to 12%. The increase would translate into a base transmission revenue requirement of $1.96 billion, compared with $1.79 billion for 2019, pushing up retail transmission rates by an average 9.5%.

In asking for the rate increase, PG&E contended that the wildfires and California’s doctrine of “inverse condemnation” pose financial risks “substantially different” from those faced by utilities in other states. As evidence, pointed to the downgrading of its credit rating as well as the $11.9 billion in losses for the company’s shareholders last year.

Several protesters opposed PG&E’s filing, arguing the utility improperly increased its ROE based on a misrepresentation of the wildfire risks. The protesters also noted that the legislature had introduced legislation (which later passed) to reduce PG&E’s wildfire liability.

FERC on Friday accepted PG&E’s proposed rates but suspended them for five months, ordering the issue to settlement judge procedures after finding the rates “may yield substantially excessive revenues” (ER19-13).

Optimism Rising on EVs as Sales Hit 1 Million Mark

By Rich Heidorn Jr.

WASHINGTON — The Sierra Club, which has spent eight years battling utilities with its Beyond Coal campaign, would seem an unlikely participant in a program by the utilities’ trade group. But Sierra Club attorney Joe Halso was on stage at the Newseum on Friday, taking part in the Edison Electric Institute’s program celebrating the U.S. reaching its 1 millionth electric vehicle.

The Electric Power Research Institute predicted earlier this year that EVs and other electrification efforts could result in load growth of 24 to 52% by 2050. So, on this issue, environmentalists and utilities have common interests.

EVgo has has more than 1,000 fast chargers at 700 charging stations nationwide. It will boost its number of chargers in California, its largest market, by 50% by mid-2019 over mid-2018. | EVgo

Joe Halso, Sierra Club | © RTO Insider

“There’s a role for utilities to play obviously in the electric [vehicle] future,” Halso said. “I think also in a world … with either flat or declining load growth, a strategic opportunity to electrify 250 million vehicles must look pretty good to utilities.”

EEI CEO Tom Kuhn | © RTO Insider

Indeed it does. EEI CEO Tom Kuhn said the alignment of the morning’s speakers — representing consumers, automakers, policymakers, utilities and charging companies — is “incredibly exciting.”

“And so I think we’re here not just to celebrate this milestone of 1 million vehicles, but also to celebrate the collaboration that got us here,” Kuhn said. “I’ve always said the things that change a market … are technologies, public policies and customers. And we’ve got all three of them, finally.”

Amid the celebration — yes, there was a cake — there were also sobering reminders of both the importance of EVs to addressing climate change and the obstacles that could prevent the technology from meeting its potential. Here’s the highlights of what we heard.

Signs of Progress

Participants in Friday’s celebration cited numerous signs of progress in addition to the 1 million milestone:

Dan Turton, General Motors | © RTO Insider
  • General Motors is developing its autonomous vehicles on an “all-EV platform,” said Dan Turton, GM’s vice president for North American policy.
  • ChargePoint, which last week announced a $240 million equity infusion, has pledged to install 2.5 million charging spots by 2025, up from more than 57,000 today. The company has raised a total of more than $500 million from investors including American Electric Power, Chevron, Daimler, BMW and Siemens.
  • Charger network EVgo, which recently completed installing nine fast-charging stations in the I-95 corridor from D.C. to Boston in a partnership with Nissan, also won a contract in August to operate a network of hundreds of stations across Virginia. Julie Blunden, executive vice president of business development, said the company also will increase its charging network in California, its largest market, by 50% by mid-2019 over mid-2018. It currently has more than 1,000 fast chargers at 700 stations. (A DC fast charger can add 60 to 80 miles in 20 minutes.) Virginia will use $14 million from its portion of the Justice Department’s settlement with Volkswagen, which agreed to spend $2 billion on zero-emission vehicle infrastructure in the U.S. after admitting to cheating on diesel emissions tests.
Arshad Mansoor, Electric Power Research Institute | © RTO Insider
  • Arshad Mansoor, EPRI’s senior vice president for research and development, predicted there will be 130 EV models available in five years, up from about two dozen today. BMW will be adding an all-electric Mini and sport utility vehicle, with plans for 25 EV models by 2025, said Bryan Jacobs, vice president of government and external affairs.
  • Regulators have approved $1 billion in utility investments in EV charging infrastructure. Halso said the amount is “a drop in the bucket” compared to what’s needed “but leaps and bounds from where we were five years ago.”
  • More than 130 companies and organizations have signed the transportation electrification accord negotiated by environmentalists and others. The agreement outlines ways transportation electrification can benefit “all utility customers and users of all forms of transportation, while supporting the evolution of a cleaner grid and stimulating innovation and competition for U.S. companies.”
  • Walmart installed chargers at 250 stores in 2018, nearly double the goal it had set, as part of its partnership with Electrify America, the unit VW set up to manage its settlement. It is now possible to drive an EV from Houston to Chicago using chargers at Walmart and Sam’s Club stores, said Sara Decker, the company’s director of federal government affairs.
  • Kathy Kinsey, NESCAUM | © RTO Insider
  • The 1 million milestone would not have been reached without state ZEV programs, said Kathy Kinsey, senior policy adviser for Northeast States for Coordinated Air Use Management (NESCAUM), a group representing the air directors of New Jersey, New York and the six New England states. Until now, she said, states have made “ad hoc” investments in EVs and their infrastructure. But with the money from the VW settlement and utilities proposing infrastructure investments, “our states now have recognized the importance of thinking strategically and regionally,” she said.

The Stakes

Friday’s celebratory mood was tempered by the release a week earlier of the federal government’s Fourth National Climate Assessment, which declared that “the impacts of climate change are already being felt in communities across the country.” (See US Climate Report Spells out Coming Challenges.)

“We cannot continue to pretend that we can solve our climate crisis by only asking the power sector to do more,” said Rep. Paul Tonko (D-N.Y.), who noted that transportation has surpassed electric generation as the largest source of greenhouse gas emissions in the U.S.

Alan Oshima, Hawaiian Electric Co. | © RTO Insider

Alan Oshima, CEO of Hawaiian Electric Co., said EVs are crucial to the state’s goal of 100% clean energy by 2045. He said the state needs to triple its rooftop solar capacity to meet the goal and that daytime EV charging is needed to absorb excess supply. While the state is fifth in per capita EV ownership, he said, it has only 8,000 EVs today.

Tonko acknowledged the limits of EV-boosting legislation possible in the new Congress, where Democrats will hold the majority in the House of Representatives while Republicans will increase their majority in the Senate.

Rep. Paul Tonko (D-N.Y.) | © RTO Insider

“We need to focus on potential policy wins that might be considered singles and doubles,” said Tonko, who pledged to push the deployment of EV charging facilities in any infrastructure bill and to seek an extension of the federal EV tax credit.

President Trump threatened to eliminate tax credits for GM’s EVs after the company announced Nov. 26 it would close assembly plants in Ohio, Michigan, Maryland and Ontario. Although Trump lacks the power to take such action, “we pay a lot of attention to what any president says,” Turton told the EEI gathering. “But this EV movement is going forward regardless.”

Established in 2008, the tax credit provides $2,500 to $7,500 per new EV, depending on the size of the vehicle and its battery capacity. The full credit is available for the first 200,000 EVs per manufacturer, after which it begins to be phased out. Tesla has already hit the threshold, and GM is expected to reach it near the end of this year. In September, a group of Congressional Democrats introduced a proposal to eliminate the per-manufacturer cap and extend the credit for 10 years.

“I think that the evidence has shown that the biggest driver to future EV adoption will be the extension of the federal tax credit,” Tonko said. “We may disagree on what that tax credit may look like or how long we allow it to be in play, but I hope this is an area where the new House Democratic majority can focus next year.”

Fleet Electrification

EV proponents see big opportunities to electrify not only personal transportation but also shipping and buses.

Sara Decker, Walmart | © RTO Insider

Although Walmart’s Project Gigaton aims to reduce GHG emissions throughout the company’s supply chain, Decker acknowledged that electrifying its truck fleet is “probably just a white board exercise at this point.”

Electrification of school and transit bus fleets is on the way, however, said Eric McCarthy, senior vice president of government relations, public policy and legal affairs for electric bus maker Proterra. McCarthy said incentives to make the switch are being provided by the VW settlement, the Federal Transit Administration, and voucher programs in states including Maryland and New York.

McCarthy said his company no longer has to convince transit agencies to “experiment” with EVs, which he said are well suited to fleet use because of buses’ combination of high mileage, low fuel economy and predictable travel routes. Now, he said, the company is focusing on its relations with utilities and educating state regulators.

Eric McCarthy, Proterra | © RTO Insider

Because transit agencies have limited capital budgets, Proterra has begun leasing its batteries, with the original equipment manufacturers taking the operating risk, McCarthy said. “It was authorized by the [2015 Fixing America’s Surface Transportation Act] and many of our customers are taking advantage of that,” he said.

Proterra has buses operating or planned in locations including Georgia, Edmonton, D.C. and Baltimore (in partnership with Exelon unit Baltimore Gas and Electric). On Oct. 30, the company unveiled an electric school bus it is producing with Thomas Built Buses, a subsidiary of Daimler Trucks North America, which has also invested in Proterra.

Julie Blunden, EVgo | © RTO Insider

The California Air Resources Board is expected to rule in January on a proposal requiring all transit agencies in the state to transition to ZEV fleets. “If that happens, and then we see other states adopt that as a model, I think you’re going to see this really take off in five years,” McCarthy said.

EVgo’s Blunden also sees fleets making a swift change.

“If there is one thing that has shocked me this year, it is how fast corporate fleet owners and operators are thinking about moving to electrification. It is going to make your head spin,” she said. “This reminds me very much of 2008 in the solar industry, where we had the very first … utility-scale solar plants. Four years later, utility [solar] was larger than residential.”

R&D

For GM, EVs represented only 1.5% of total sales in 2017, and none of them was a pickup truck or SUV, which have gained market share at the expense of sedans. GM’s Turton said electrifying those heavier vehicles is part of the company’s “all-electric future.”

Alex Fitzsimmons, DOE Office of Energy Efficiency and Renewable Energy | © RTO Insider

“It’s going to take the next generation of batteries, the generation after that, to be able to advance the R&D … to be able to have better, more cost-efficient batteries that can do this with the longer range that’s necessary,” he said.

Alex Fitzsimmons, chief of staff for the Department of Energy’s Office of Energy Efficiency and Renewable Energy, said his agency has three R&D goals for EVs: reducing battery costs (currently more than $200/kWh) to less than $100/kWh; expanding their range to 300 miles (the second generation Nissan Leaf has a range of 151 miles); and completing a full charge within 15 minutes.

Consumer Ignorance

Speakers said the biggest obstacle to wider EV penetration, however, is not technology but consumer ignorance.

“It’s troublesome how little progress we’ve made in the last five years in consumer education,” NESCAUM’s Kinsey said.

Michael Arbuckle, Nissan | © RTO Insider

“A lot of consumers still think that EVs drive like a golf cart,” lamented Michael Arbuckle, senior manager of EV sales and marketing strategy for Nissan, which has sold 365,000 electric Leafs worldwide. “They also think that they’re not affordable — they’re wrong. We know that EVs also have acceleration that’s exciting. They’re fun to drive. They’re great vehicles to drive.”

Southern California Edison’s service territory claims 200,000 EV owners — one-fifth of the U.S. total. Yet less than half of Californians know what an EV is, said Phil Jones, executive director of the Alliance for Transportation Electrification. Jones also noted that the U.S. remains far behind China, which has accounted for about 37% of passenger EV sales since 2011 and about 99% of e-buses. The city of Shenzhen last year converted all of its 16,359 buses to electric.

Joel Levin, Plug In America | © RTO Insider

Joel Levin, executive director of Plug In America, which represents EV drivers, said few auto salespeople are familiar enough with EVs to answer prospective buyers’ questions. “With a gas car, the dealer never has to answer questions like, ‘So, where do I get gasoline?’” he said.

Levin said consumers’ cost comparisons need to switch from sticker prices — at which EVs are a disadvantage — to total cost of ownership, which includes their lower fuel and repair costs.

Auto dealers generally earn more money from repairs than vehicle sales, a potential disincentive to promoting EVs, which have far fewer moving parts than vehicles with internal combustion engines. But Levin insisted that hurdle can be overcome. “There’s other pieces of the value chain that they can capture,” he said, citing rooftop solar sales and installing home chargers.

Multifamily Housing Challenge

Another obstacle to wider penetration is how those lacking individual garages can charge at home.

Jill Anderson, Southern California Edison | © RTO Insider

Multifamily housing remains a hurdle even in SCE’s territory, said Jill Anderson, vice president of customer programs and services.

Anderson said the utility intended to include multifamily housing in its first big launch of light-duty chargers, in part to address concerns that low- and moderate-income residents could be shut out of the transition.

“And that’s the area where we had the most difficulty,” she said. “I think only three or four sites were successful in multifamily charging. So it’s an area we have to think about differently. We might have to think about the utility doing more soup-to-nuts solutions for multifamily. It’s an area that’s going to be important.”

New York state is attempting to increase multifamily penetration by offering rebates on Level 2 chargers (240-V AC units that add up to 20 mph of charging) to apartment buildings in addition to office buildings and public and commercial locations, Rep. Tonko said. The state also is offering grants for DC fast chargers for cities, transportation corridors and hubs such as airports.

Dave Packard, ChargePoint | © RTO Insider

“It is my belief that the federal government can encourage similar investments, and we should ensure that charging is open to public access, interoperable and that the recipients of this funding are required to maintain the equipment,” Tonko said. “Without this type of concerted push, we are going to have many of the same problems and split incentives that we see on consumer-side energy efficiency, where building owners might not see the benefit of making efficiency investments on their tenants’ behalf. We can’t shut these potential consumers out of the EV market.”

Dave Packard, vice president of utility solutions for ChargePoint, said his company is working with competing charging networks to create a “seamless driving experience” that ensures drivers know where to charge and how much it will cost. “I think we have to take a lesson from the cellphone industry,” he said. “Those of you that remember in the early days when you roamed you had to call [through a different provider]. It was just a nightmare.”

Projections

EEI ended the event Friday with the release of a report projecting the U.S. will hit the 2 million EV mark by early 2021 and total 18.7 million by 2030. By then, annual sales would exceed 3.5 million, 20% of total car and light truck sales, EEI said. The report says the U.S. will need an additional 9.6 million charge ports to meet the 2030 projections. There are currently about 45,000 public Level 2 charging ports and 9,000 DC fast-charging ports, the report said.

PJM MRC/MC Preview: Dec. 6, 2018

By Rory D. Sweeney

Below is a summary of the issues scheduled to be brought to a vote at the PJM Markets and Reliability and Members committees on Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.

RTO Insider will be in Wilmington, Del., covering the discussions and votes. See next Tuesday’s newsletter for a full report. NOTE: The meeting will be held at the DoubleTree by Hilton Hotel Downtown Wilmington instead of the Chase Center.

Markets and Reliability Committee

1. PJM Manuals (9:15-9:45)

Members will be asked to endorse the following proposed manual changes:

A. Manual 03: Transmission Operations. Revisions developed to update the generator voltage schedule with new processes that require transmission owners to verify and submit voltage schedules via eDART, generation owners to review the schedules and the eDART contact to acknowledge the schedule. This will all need to be done annually. (See “Generator Voltage Schedule,” PJM Operating Committee Briefs: Nov. 6, 2018.)

B. Manual 10: Pre-Scheduling Operations. Revisions developed as part of a periodic cover-to-cover review.

C. Manual 14D: Generator Operational Requirements. Revisions mirroring those of item 1A above.

D. Manual 27: Open Access Transmission Tariff Accounting. Revisions developed as part of the biennial review.

E. Manual 06: Financial Transmission Rights. Revisions developed as part of the annual review.

F. Manual 11: Energy & Ancillary Services Market Operations. Revisions developed as part of ongoing revisions to the day-ahead timeline. (See “Day-ahead Market Timeline Manual Changes,” PJM Market Implementation Committee Briefs: Nov. 7, 2018.)

2. PRD Review for Capacity Performance Requirements (9:45-10:05)

Members will be asked to endorse at least one of several proposals developed by the Demand Response Subcommittee to address changes to price-responsive demand required for the Capacity Performance construct. The question is whether PRD should be required to reduce load in the winter like other CP resources. (See “Summer-only Demand Response,” PJM MRC/MC Briefs: Oct. 25, 2018.)

3. 2019 DASR Requirement (10:05-10:20)

Members will be asked to endorse proposed revisions to the day-ahead scheduling reserve for 2019. The 2019 calculation of 5.29% is a 0.01-point increase from the 2018 requirement. (See “Day-ahead Scheduling Reserve Recommendation,” PJM Operating Committee Briefs: Nov. 6, 2018.)

4. Surety Bonds (10:20-10:40)

Members will be asked to endorse at least one of two stakeholder proposals developed at the Credit Subcommittee related to allowing use of surety bonds as an acceptable form of collateral. (See “Surety Bond Use,” PJM Market Implementation Committee Briefs: Oct. 10, 2018.)

5. Gas Pipeline Contingencies (10:40-11:05)

Members will be asked to endorse a proposal endorsed by the Market Implementation Committee around gas pipeline contingencies. The proposal, originally developed by Calpine, would provide a broader scope of factors and time for which a unit can recover costs during and after a PJM fuel-switch directive. (See “Gas Pipeline Contingencies,” PJM Market Implementation Committee Briefs: Nov. 7, 2018.)

Members Committee

1. RPM Credit Requirement Reduction Clarifications (1:25-1:45)

Members will be asked to endorse proposed Tariff revisions to remove an apparent overlapping credit reduction provision for qualified transmission upgrades, to clarify milestone documentation requirements for internally financed projects and to clarify that capacity market sellers should submit requests for reductions.

2. PRD Review for Capacity Performance Requirements (1:45-2:05)

Members will be asked to endorse proposed Operating Agreement and Tariff revisions related to CP changes required for PRD. (See MRC item 2 above).

3. Gas Pipeline Contingencies (2:05-2:25)

Members will be asked to endorse proposed OA and Tariff revisions related to gas pipeline contingencies. (See MRC item 5 above).

4. Elections (2:25-2:35)

Members will be asked to elect members of the 2018-2019 Finance Committee, the 2019 sector whips and the 2019 MC vice chair.

FERC Approves Revised TMEP Cost Allocation

By Amanda Durish Cook

FERC last week accepted MISO’s revised cost allocation proposal for the RTO’s relatively new category of smaller interregional transmission projects with PJM.

The new cost allocation affects targeted market efficiency projects (TMEPs) between MISO and PJM and became effective Nov. 28 (ER18-2514). MISO made the allocation revisions as part of a larger update to its cost allocation as the five-year Entergy transition period — which limits cost sharing of transmission projects in MISO South — expires at the end of this month.

MISO
2018 TMEPs | MISO

The RTO’s share of TMEP costs is currently allocated to transmission pricing zones based on each zone’s share of the relative positive congestion contribution, measured by the TMEP candidate study. (See FERC OKs MISO TMEP Cost Recovery Schedule.)

MISO made three complex changes to its cost-sharing formula while still preserving the premise that TMEP costs flow to benefiting transmission pricing zones.

The RTO had been calculating TMEP benefits by using a calculation of the nodal congestion contribution for each load node. Now it will include generator nodes in determining congestion benefits, rather than considering only load nodes. The two nodes will be aggregated to calculate the net benefits of the upgrade to each transmission pricing zone.

MISO will also discontinue its practice of applying the formula to all five-minute dispatches in the real-time market. The formula will now apply only to hours in the day-ahead market in which a reciprocal coordinated flowgate will experience congestion.

FERC said MISO’s proposal will simplify the TMEP cost allocation process.

“We find that the proposed revisions will better define the beneficiaries of avoided congestion as well as allocate the costs of TMEP upgrades more accurately, while removing undue complexities from the calculation of benefits,” FERC said.

The calculation will not account for the contract path on SPP’s transmission that connects MISO Midwest with South. Regulators in South had called for a stakeholder process to determine the impacts of the contract path on cost allocation.

But MISO said an analysis showed accounting for the contract path “indicated minimal change to the cost allocation.”

MISO and PJM have so far recommended seven TMEPs, five that received approval in 2017 and two up for approval this month from the RTOs’ respective boards of directors. The combined projects will cost under $25 million and are expected to reap about $132 million in benefits. (See MISO, PJM Endorsing 2 TMEPs for Year-end Approval.)

PJM, Monitor Remain at Odds over Energy Market Proposals

By Rory D. Sweeney

Roughly a year into the discussion and months past the deadline requested by PJM’s Board of Managers, details of potential changes to the RTO’s energy market remain anyone’s guess.

At Wednesday’s meeting of the Energy Price Formation Senior Task Force (EPFSTF), PJM reintroduced a substantially altered proposal for revising its operating reserve demand curve (ORDC), and both the RTO and its Independent Market Monitor revised their proposals for the allowable synchronized reserve offer margin adder. A new proposal submitted by the D.C. Office of the People’s Counsel would largely maintain the current two-step curve but include some revision details from proposals by both PJM and the Monitor. (See Skepticism Lingers Around PJM Price Formation Goals.)

Attendees at last week’s EPFSTF discuss proposal specifics. | © RTO Insider

PJM revised its ORDC proposal to account for the impact of units’ regulation requirements, shifting its proposed curve to the left and more in line with the current two-step ORDC for synchronized reserves. The current curve escalates from $0/MWh to $300/MWh at 1,590 MW, and the new one escalates gradually from $0/MWh at roughly 2,750 MW to $265/MWh at 1,575 MW. PJM’s original proposed revisions began escalating from $0/MWh at roughly 3,500 MW and reached $265/MWh at 2,100 MW. The revised proposal means that the value of synchronized reserve megawatts will be less until the reserve drops to the minimum reserve requirement (MRR), which remains $850/MWh.

PJM also revised its proposed margin adder down substantially. The current adder is $7.50/MWh, but PJM said the calculation should instead be based on the expected value of the penalty resources pay if they receive a synchronized reserve obligation and fail to perform during an event. For 2017, that value was 1 cent/MWh, and so far in 2018 it’s been 2 cents/MWh. Rather than setting it at $0, PJM argued that it should be allowed to change as clearing prices change.

PJM’s revised ORDC proposal | © PJM

Monitor Revisions

The Monitor’s revised ORDC proposal includes a temporal concept meant to factor in the expected cost of a unit commitment to maintain the reserve requirement in the future. Instead of happening over 30 minutes to provide reserves necessary for 10 minutes in the future, as PJM has proposed, the Monitor’s proposal would look forward until the next expected demand peak based on historical load patterns.

The resulting curves have seasonal variations but rarely extend past $60/MWh before hitting the MRR.

The Monitor revised its adder proposal from a “compromise” of $3.80/MWh — which it now finds “unjustified” — to $0/MWh and recommended that penalties should extend back to the last reserve event when the resource performed to its full obligation but no longer than 12 months.

The Monitor also added a new option to the matrix that would include the changes to the synchronized reserve market but reserve the discussion on the ORDC to the second stage of EPFSTF, including discussion of the relationship between the day-ahead reserve products and real-time reserve products.

Stakeholder Reaction

Stakeholders appeared unconvinced by either proposal. Carl Johnson, representing the PJM Public Power Coalition, said the measuring stick for whether the RTO’s proposal is successful should be its impact on uplift payments.

“If uplift doesn’t go away, we’ve got a problem,” he said.

PJM’s Adam Keech agreed, saying, “I think zero uplift is a good target.”

The Monitor disagreed, however. Monitor Joe Bowring noted several market mechanisms that create uplift that aren’t addressed in the proposal.

“We think some uplift is necessary,” Monitor staffer Catherine Tyler said.

PJM and the Monitor also disagreed with some stakeholders over what the overall goal of the changes should be.

“The goal isn’t to have the lowest prices possible,” Keech said. “The goal is to reflect what the system operators are doing. We’re trying to drive to prices that reflect the system operators’ needs.”

Bowring said the “objective of markets is to have the lowest prices possible for the defined product, but no lower.”

Stakeholders and PJM staff questioned whether the Monitor’s ORDC proposal was more about addressing scheduling issues than generation scarcity.

“This is compensating to some extent for the lack of scheduling tools,” Tyler acknowledged. “However, what we do see in the market now is an operator looking ahead and seeing a need for reserves in the future, and we don’t have a market tool to address that.”

Vote Delayed

PJM’s Dave Anders, who is facilitating the task force, summed up the day by quashing any question about whether stakeholders may be ready to decide.

“It’s been a fluid situation with respect to proposals. I don’t know that we’re ready to vote,” he said, noting that PJM staff will update the board at its meeting this week.

Bowring pointed out that if the initial vote had happened when PJM had initially requested the vote, its proposed demand curve would have been substantially higher than with its revised ORDC presented for the first time at this meeting.

While no one questioned the decision, stakeholders differed on whether a vote should come sooner or later. Some expressed concern that further delay risks the board deciding to approve revisions without waiting for stakeholders’ advice.

Stakeholders have already missed the board’s request to receive stakeholder endorsement for some changes by the third quarter, which could have already allowed for FERC approval and implementation for this winter. (See PJM Board Seeks Reserve Pricing Changes for Winter.)

FERC OKs Key PJM Changes to Address GreenHat Default

By Rory D. Sweeney

FERC on Thursday approved some of the flexibility PJM has sought to address after the historic GreenHat Energy financial transmission rights portfolio default.

The commission accepted Tariff and Operating Agreement revisions that require defaulted FTR portfolios to go to settlement rather than being liquidated through auction (ER19-19). It was one of four requests PJM filed with FERC to attempt to mitigate the financial risk created by the default, which is expected to cost stakeholders more than $100 million to cover the losing bets. Stakeholders have criticized PJM for what they see as bungled handling of the issue. (See Advocacy Group Seeks CFTC Oversight of PJM FTRs.)

PJM analysis shows the continuing downward trajectory of GreenHat’s FTR portfolio. | PJM

FERC’s approval is conditioned on PJM removing Tariff and OA language related to bilateral FTR transactions that is predicated on the commission accepting a related filing that received a deficiency letter requesting more information (ER19-24). FERC made the ruling effective Dec. 1, rendering moot another related filing that sought to ensure an effective date no later than Feb. 28, 2019 (ER19-25).

On Friday, FERC’s Office of Energy Market Regulation accepted by delegated authority the fourth filing, which clarified that a PJM member’s per capita portion of FTR default allocation assessments will not exceed $10,000 per calendar year, cumulative of all defaults, or more than once per each member’s ongoing default if default allocation assessment charges for a member’s ongoing default span multiple calendar years (ER19-23).

Settlement Order

FERC approved sending defaults to settlement rather than liquidation despite several protests, which argued that the requirement prolongs uncertainty, leaves PJM with no alternate ability to mitigate default losses, could increase the size of the default, inhibits liquidity by preventing the sale of valuable hedges and disrupts the orderly unwinding or reorganization of the defaulting entity.

“We acknowledge that inherent in these revisions, PJM stakeholders are exchanging one set of risks for another,” the commission said. “The commission recognizes that PJM, on behalf of the stakeholders who ultimately bear the cost of default, assessed such tradeoffs, including the risk tolerance of its stakeholders, and this proposal is the result of such an assessment. While we acknowledge that there are potential downsides to not liquidating defaulted portfolios through the FTR auctions, we cannot find that PJM’s choice to allow FTR positions to go to settlement is unjust and unreasonable.”

The commission said that while the GreenHat default may be an exceptional event that may never happen again, that doesn’t determine whether the rule changes stemming from it are unjust or unreasonable, nor does how other regions would handle such a situation.

Stakeholders Press MISO on Storage Role

By Amanda Durish Cook

CARMEL, Ind. — Storage is glaringly absent from MISO’s potential plans to manage a possible 40% renewable penetration on the grid, stakeholders told the RTO this week.

During a Nov. 28 workshop to discuss its ongoing findings on the impact of increased renewable integration, MISO suggested using computer-optimized transmission buildout and more pronounced ramping from remaining conventional generation to respond to a 40% renewable resource mix.

MISO last month said it would need to take significant steps to reinforce its grid to handle a 40% penetration comprising 75% wind and 25% solar. The RTO said it found a possible “inflection point” at 40% and that it would be difficult to operate within system limits at that point. (See Study: MISO Grid Needs Work at 40% Renewables.) Its multiyear study seeks to determine what the grid needs to maintain the planning reserve margin, operate within the physical limits of the system and support voltage and frequency.

MISO’s renewable penetration currently stands at about 10%. Findings issued last month indicate the RTO could reliably absorb a 20% renewable penetration without damaging frequency response. (See MISO: 20% Renewable Limit for Adequate Frequency Response.)

But at 40% renewables, MISO has found that renewable curtailment becomes more pronounced during shoulder months, though wind curtailment would occur in every hour during an average day, except in summer. It would also confront significant stability issues.

Possible transmission siting at 40% renewables | MISO

During the Nov. 28 workshop, MISO policy studies engineer Maire Boese said the RTO will likely need to rely on transmission solutions to keep the majority of the renewable energy deliverable to load at the 40% level.

“We want to make sure energy reaches load instead of seeing it be curtailed or not dispatched,” Boese said.

Transmission planning can also become more influenced by computing power and mathematic modeling, MISO concluded.

Yifan Li, of MISO’s policy studies group, said that even with the modeling process, “engineering judgment and human experience” are still the driving factors behind selecting transmission project candidates, although that is changing.

“We’re getting to a point where we can seek some help from computers … to find transmission solutions,” Li said.

Such an automated process led MISO to identify about 80 potential new transmission candidates, down from a pool of about 11,300, he said. The additional transmission would cut down on curtailments and make renewables more deliverable to load, MISO said last month.

The expansion includes 266 miles of circuit at 200 kV or less, 763 miles of 230-kV circuit, 1,373 miles of 345-kV circuit, 316 miles of 500-kV circuit, 267 miles of 765-kV circuit and 408 miles of HVDC line. The transmission solutions do not include a new line linking MISO Midwest with MISO South.

With new transmission, 38.4% of the 40% renewable penetration would be deliverable, as opposed to 34.7% without the solutions, MISO determined. Curtailment of a 40% renewable mix would fall from 18.2% to 9.6% on average.

A 40% renewable mix would also place more ramping responsibility on thermal units, the RTO found.

Wind curtailment at 40% renewables | MISO

Where’s the Storage?

At the workshop, LS Power’s Pat Hayes asked if MISO has studied what levels of storage would be helpful at different points of renewable penetration.

“So far, we haven’t found a strict need for storage,” Policy Studies Manager Jordan Bakke said. “Storage really hasn’t been found to be needed in the areas we’ve studied so far. … When we looked at the issues and we looked at the solutions, the solutions were pretty straightforward.”

Bakke said MISO so far recommends “extracting more flexibility from the current fleet, rather than building something else.”

MISO said as renewable penetration increases, the number of thermal units online increases during off-peak hours despite a decrease in average output. The RTO would especially rely on online coal and combined cycle gas units for ramping in the morning and evening.

Not an Economic Analysis

Veriquest Group’s Dave Harlan said MISO might consider developing incentives to keep remaining thermal units online if they’re needed for ramp capability.

But Bakke said the study is exclusively focusing on the physical needs of the system rather than monetary outcomes. MISO’s study does not contemplate whether conventional generation could economically survive in a landscape with 40% renewable penetration.

“The purpose is not to talk about the money issues,” he said.

Boese said coal asset owners may have to investigate whether their units can handle the more frequent ramping MISO has forecasted. “Less megawatts of coal are available with more ramping,” she said. “That’s something to keep in mind if you’re a generation owner.”

“There’s something like a feedback loop here,” said consultant Roberto Paliza, adding that MISO was failing to answer a key question by not investigating whether conventional generation could economically withstand being needed for more pronounced ramping but less run-time overall. He said the RTO was neglecting to find out if the assistance would be there when needed to facilitate renewable penetration.

But other stakeholders said MISO’s conventional generation solution to combat increasing curtailment conspicuously leaves storage out of the conversation.

Clean Grid Alliance’s Natalie McIntire said it seemed that MISO was looking only to existing conventional generation to manage renewable variability and that storage could also cover ramping flexibility.

Bakke said MISO forecasts very little curtailment from overgeneration, and that curtailment largely correlates to wind delivery issues at night.

Stakeholders responded that storage could hold the wind energy until morning. For that to be useful, Bakke said the storage would have to be locally sited and not general system storage.

Multiple stakeholders asked MISO for another analysis that includes assistance from storage and at what point an influx of storage produces diminishing returns.

Bakke said going forward, MISO would gauge storage solutions in the final phase of the study. He said MISO staff hear “loud and clear” that stakeholders would like to see how both renewables and storage interact on the grid.

Harlan also criticized MISO’s report for only showing averages of system conditions with renewable penetration. He said to properly plan resources, stakeholders need to see the most extreme scenarios that can occur.

MISO staff asked for more written stakeholder feedback on the analysis so far. They said stakeholder suggestions will shape the scope of the study’s third and final phase, which will begin in early 2019.

Bakke said the third phase of the study will either examine renewable penetrations beyond 50% or investigate penetrations up to the 50% benchmark more thoroughly.

FERC OKs PJM Allocations over Dominion, ODEC Objections

By Rory D. Sweeney

FERC on Tuesday approved cost allocations for 60 new transmission projects added to PJM’s Regional Transmission Expansion Plan (RTEP), including three high-voltage projects allocated entirely to Dominion Energy’s zone despite protests that cost sharing of such regionally beneficial projects is under judicial review (ER18-2350).

| © RTO Insider

The projects were filed on Aug. 30 and approved by PJM’s Board of Managers in July. The RTEP amendments include cost responsibility assignments for:

  • 27 transmission enhancements and expansions that operate as lower-voltage facilities whose costs were allocated pursuant to the solution-based distribution factor method;
  • 15 transmission enhancements costing less than $5 million whose costs were allocated to the zones where the enhancements are located;
  • Four transmission enhancements that were included in the RTEP solely to address individual transmission owner Form 715 local planning criteria, and whose costs were allocated to the zones of the individual TOs whose Form 715 local planning criteria underlie each enhancement;
  • Nine transmission enhancements that operate at or below 200 kV whose costs were allocated to the zones in which the enhancements are located; and
  • Five transmission enhancements needed to address spare parts, replacement equipment and circuit breakers whose costs were allocated to the zones in which the enhancement are located.

Dominion and Old Dominion Electric Cooperative argued that three of Dominion’s Form 715 projects address end-of-life planning criteria for high-voltage facilities, and that the D.C. Circuit Court of Appeals in August rejected FERC’s approval of a PJM Tariff revision that resulted in the RTO assigning all the costs to Dominion’s zone for two high-voltage projects the company initiated through its Form 715 criteria.

The court agreed with Commissioner Cheryl LaFleur, who dissented on the revision approval on the grounds that the commission should preserve regional cost allocation “for certain high-voltage projects, even if those projects are selected solely to address local planning criteria.” (See DC Circuit Court Rejects PJM Tx Cost Allocation Rule.)

However, in the current RTEP allocations, LaFleur, Commissioner Richard Glick and Chairman Neil Chatterjee determined that ODEC and Dominion were not alleging that PJM incorrectly applied its Tariff but were instead challenging the cost-assignment provisions of the Tariff itself, and therefore approved the allocations. The order also set Nov. 28 as the refund date for any Tariff revisions that occur when the court’s remand of FERC’s approval is addressed.

Commissioner Kevin McIntyre did not participate in the decision.

FirstEnergy Secures Recovery for Transource Project

By Rory D. Sweeney

FERC on Tuesday granted FirstEnergy Services’ request to recover “prudently incurred abandonment costs” if Transource Energy’s embattled Independence Energy Connection is canceled (ER18-2510).

The request was made on behalf of FirstEnergy affiliates Potomac Edison and Mid-Atlantic Interstate Transmission (MAIT). The authorization allows the companies to recover 100% of any costs incurred for the project after Nov. 27 and 50% of any costs incurred prior to that date, which is the same structure that the project’s other developers — Transource, Baltimore Gas and Electric and PECO Energy — have already received.

The companies told FERC the project must be permitted by both Maryland and Pennsylvania — where it needs easements across roughly 300 private properties — and that, as a market-efficiency project, it faces heightened risk of cancellation because it is subject to annual PJM re-evaluation until it is permitted. The request also noted “local opposition” to sections of the project.

“This local opposition, coupled with the need for … the companies responsible for the other elements to obtain permits from multiple municipal and state authorities, heightens the permitting risk,” the companies argued.

Once referred to as the AP South Congestion Improvement Project, Transource’s Independence Energy Connection project would consist of two lines. The western portion would run from the Ringgold substation in Maryland to the Rice substation in Pennsylvania. The eastern line would run from the Conastone station in Maryland to the Furnace Run station in Pennsylvania. | Transource

Residents in the area of the project have been fighting against the project for years. Half a dozen opponents took the rare step of attending the September meeting of PJM’s Transmission Expansion Advisory Committee to voice their displeasure with the project and request that the RTO withdraw its approval. PJM explained its role is simply to evaluate the benefit of the project, and that the residents need to lodge their complaints with the state regulatory commissions that oversee permitting. (See PJM Redirects Residents’ Protests of Tx Project to States.)

The $366.17 million proposal is the largest congestion-reducing project PJM has ever approved. It would consist of two separate 230-kV double-circuit lines, totaling about 42 miles, across the Maryland-Pennsylvania border. One line would run between the Ringgold substation in Washington County, Md., and a new Rice substation in Franklin County, Pa.; the other would run between the Conastone substation in Harford County, Md., and a new Furnace Run substation in York County, Pa.

PJM estimated that Potomac Edison will be assigned $62.06 million in costs for its part of the project’s construction, while MAIT will pick up $6.42 million. Despite criticism, the RTO has maintained that the project stands to provide more benefits than it will cost. (See PJM Reiterates Support for Embattled Transource Project.)