MISO West Planning Belies Upgrade Needs, Critics say

MISO West won’t be the site of pricey buildouts in this year’s transmission planning cycle, despite complaints from critics that renewables in the region’s interconnection queue necessitate billions in grid upgrades.

“We don’t have any super big-ticket projects for the West this year,” MISO Manager of Expansion Planning Zheng Zhou said at a June 2 subregional planning conference call for the region, which includes Minnesota, Iowa, parts of the Dakotas and western Wisconsin.

Transmission owners in MISO West proposed 145 new projects for about $910 million in the 2020 Transmission Expansion Plan (MTEP 20), which so far contains 510 proposed projects at a combined $4.06 billion.

The costliest is American Transmission Co.’s $40 million Arcadian power transformer upgrade project in southeast Wisconsin, proposed because of the age and condition of the existing equipment.

But no projects in the West region were among the top 10 most expensive, currently found in MISO’s Central and South regions. (See Price Tag Rising for MTEP 20.)

At the same time, the West region is showing the need for billions in transmission investment to accommodate new generation projects, based on the makeup of MISO’s interconnection queue.

The April 2018 cycle of 35 projects at 4.7 GW shows the need for a total $1.1 billion in network upgrades, before affected-system network upgrades are factored in. The August 2017 cycle of about 4.1 GW in 27 projects also needs about $1.1 billion in transmission upgrades.

Stakeholders have argued that MISO West is neglected in terms of new transmission capacity, which they say has led to prohibitively expensive network upgrades and stifled proposed renewable generation projects.

MISO is currently processing six cycles of West interconnection requests dating to 2017. The interconnection queue currently contains 434 projects totaling 67.4 GW, enough capacity to cover a little more than half of MISO’s peak load. More than 60 generation projects have dropped out of the queue so far this year, while about 30 have completed generator interconnection agreements.

Revealing Overlap

MISO also announced it has identified 313 reliability issues in need of solutions in the West service areas of Northern States Power, Central Minnesota Municipal Power Agency, Minnesota Municipal Power Agency, Minnesota Power, Otter Tail Power and Minnkota Power Cooperative.

Most of those reliability issues are not covered by proposals submitted for MTEP 20. MISO said it will continue assessing the likelihood for contingencies and announce any additional transmission needs during the next West subregional planning meeting in August.

The RTO has pledged to address the increasing cost of network upgrades in its interconnection queue by linking its annual transmission planning process with network upgrade planning. The synchronization could result in MISO approving more transmission projects; however, those changes will begin with MTEP 21, not MTEP 20. (See MISO Floats Ideas on MTEP, Interconnection Coupling.)

Zhou said MISO cannot yet confidently select a project that handles overlapping economic, reliability and generator interconnection needs because so many proposed generation projects drop out of the queue.

Clean Grid Alliance’s Natalie McIntire said she understands MISO doesn’t have a process in place for combining reliability, economic and network upgrade projects, but she asked the RTO to be more forthcoming about projects that could potentially be merged.

“Maybe we can be a little more transparent and bring this process out into the open,” she said.

MISO says it will begin publishing new regional planning maps that show possible economic, reliability and generator interconnection needs on the same chart.

“We wanted a more holistic map of issues,” expansion planning engineer David Ticknor explained to stakeholders. “This will hopefully allow us to coordinate and collaborate on holistic solutions … in planning cycles going forward.”

Ticknor said the new maps will be updated periodically and contain indicators for generator interconnection thermal constraints, MTEP reliability constraints and congested flowgates that are possibly ripe for an MTEP economic project.

Ticknor said, for now, the maps will be educational and not used to propose transmission solutions.

“How are we going to move past the educational piece to use these maps for consolidated projects?” McIntire asked.

Ticknor said MISO will also begin internal and stakeholder discussions on project overlaps its planners have observed. “We figured starting off with a map was the easiest way to start a conversation about how things can work moving forward,” he said.

Sustainable FERC Project’s Lauren Azar asked if MISO is actively monitoring transmission assets that might be ripe for age and condition-related upgrades so it might find opportunities to consolidate project types even further.

Ticknor said MISO doesn’t currently ask TOs for a list of impending upgrades to aging equipment but that it could look into maintaining such a list.

June 7, 2020January 31, 2024

FERC OKs Basin Electric’s Market-based Rates

FERC last week approved Basin Electric Power Cooperative’s request to make wholesale sales of energy, capacity and ancillary services at market-based rates in its Central and SPP regions, effective June 7, designating the cooperative as a Category 2 seller (ER20-1505).

The commission said Basin met its requirement that the co-op and its affiliates lack or have adequately mitigated horizontal and vertical market power.

Basin said it has turned over functional control of its Eastern Interconnection transmission facilities in the Central and SPP regions to MISO and SPP, respectively.

Before Nov. 1, 2019, Basin was exempt from commission jurisdiction because its member-owners were public power districts, electric cooperatives that have Rural Utilities Service debt, or electric cooperatives that sell less than 4 million MWh of power annually.

Basin said that it lost its exemption because of two of its owner-members themselves lost exempt status. Tri-State Generation and Transmission Association lost its status when it admitted nonexempt Mieco Inc., a subsidiary of subsidiary of Marubeni Corp., as a member. Upper Missouri G&T Electric Cooperative lost its exemption when it was determined that one of its members was selling more than 4 million MWh of electricity annually.

Basin told the commission it is seeking market-based rate authority only in the Central and SPP regions. It plans to file a second application for MBRA in the other markets in which it operates once it has a Tariff on file with FERC for them.

FERC denied Basin’s request for a waiver of the minimum 60-day notice requirement, ruling its MBRA would be effective June 7, 61 days after its filing. The commission noted its policy that, absent extraordinary circumstances, it does not grant waivers of notice requirements when an agreement for new service is filed on or after the day service has commenced. However, the commission said it would not require refunds for sales prior to June 7.

The commission also directed Basin to file electric quarterly reports.

FERC defines Category 2 sellers as those entities that aren’t Category 1 sellers, which are wholesale power marketers or wholesale power producers affiliated with 500 MW or less of generation in a region.

Empire Gets Waiver for Solar, Wind Projects

The commission also conditionally approved Empire District Electric’s request for a waiver to permit designated marketing employees to perform scheduling and related activities for certain Empire affiliates, effective May 1 (ER20-432).

The waiver allows marketing employees to perform services for two small solar power production facilities indirectly owned by affiliate Liberty Utilities and three wind-generating projects that will be indirectly owned by Empire.

FERC said its decision relies on “Empire’s representations that scheduling and related activities to maximize efficiencies, coordinate scheduling, perform forecasting and other sharing of information will be used to the benefit of captive customers.”

Liberty has acquired the 50-MW Luning Solar Energy Center and the 10-MW Turquoise Liberty Project, both in Nevada. Liberty is a direct subsidiary of California utility CalPeco, to which Luning makes power sales.

Empire has signed agreements to acquire indirect and controlling interests in three wind projects with a total capacity of approximately 600 MW: Neosho Ridge Wind, a 301-MW facility planned for Kansas; Kings Point Wind, a 150-MW resource that will be located in Missouri; and the approximately 150-MW North Fork Ridge Wind project, to be built in Missouri.

Empire told the commission that any market information will be shared “with the ultimate goal of maximizing the performance from the wind and solar projects, the benefits of which flow to the captive retail customers of CalPeco and Empire.”

The three wind projects will be included in Empire’s rate base upon state regulatory approval. The solar projects are in CalPeco’s rate base.

June 7, 2020

PJM Operating Committee Briefs: June 4, 2020

PJM presented the Operating Committee with proposed rule changes concerning the testing, compensation, substitution and termination of black start resources Thursday.

Most of the changes involve additions to Schedule 6A of the Tariff and section 4.6 of Manual 12, said PJM’s Becky Davis, who walked stakeholders through a matrix of revisions. She said redline versions of the Tariff and manual language will be available for review by the OC’s July 9 meeting.

The committee approved an issue charge for the initiative at its May meeting. (See “Black Start Issue Charge Endorsed,” PJM Operating Committee Briefs: May 14, 2020.)

The problem statement focuses on four areas:

Making units that entered black start service through a transmission owner integration subject to the same testing requirements as those compensated under Schedule 6A: a successful test every 13 months.
Clarifying rules for substituting one black start unit for another. Current rules allow a black start unit owner to substitute one unit for another if the substitute is on the same voltage level and has a valid annual test. PJM said it is responding to an increase in questions about adding, maintaining and managing black start substitutes. The proposed rules would require 40 days’ notice for substitution requests.
Adding language allowing PJM to replace black start units that fail or do not perform tests without lengthy delays.
Allowing updates to the capital recovery factor table governing compensation for black start capital costs to remain consistent with current tax law and interest rates.

PJM attorney Steve Pincus said the RTO is not concerned over potential conflicts between its rules and black start units covered by “legacy” agreements with TOs.

Pincus said PJM would look at the agreements on a case-by-case basis to resolve any potential conflict, noting there are only a “handful” of agreements that fall into that category. He said the PJM testing rules are likely more stringent than those in the legacy agreements but that if an agreement with TOs was more demanding than PJM’s, “I’m confident we would not have a Tariff [violation] issue.”

If necessary, Pincus said PJM would seek a Tariff waiver from FERC to address any inconsistencies.

In addition to the four topics in the problem statement, the OC also will consider how to compensate black start owners for their fuel costs under the minimum tank suction level (MTSL) rules. The Markets and Reliability Committee approved the expansion of the initiative to cover MTSL on May 28. (See “Fuel Requirement Issue Charge,” PJM MRC Briefs: May 28, 2020.)

Dispatch Interactive Map Application

Ed Kovler of PJM conducted a first read of a proposed problem statement and issue charge to consider giving TOs access to the Dispatch Interactive Map Application (DIMA), a geospatial situational awareness tool that the RTO’s dispatchers have used since 2014.

PJM and several TOs brought forward draft language for the Operating Agreement to be endorsed through the “quick fix” process documented in Manual 34. The OC will vote on the issue charge at its July 9 meeting.

DIMA allows operators to see the location of problems on the grid in real time and respond quickly.

Kovler said DIMA has been a “paradigm shift” for PJM dispatchers, moving away from old tabular displays that most operation centers have to a geospatial display that helps them better understand the relationship of equipment.

TOs have requested read-only access to DIMA to improve their own operators’ situational awareness, Kovler said.

PJM plans to present the DIMA issue charge at the July and August MRC meetings and the September Members Committee meeting. If endorsed, the OA changes will be sent to FERC in September for review.

Kovler said PJM expects FERC to act in about 60 days and that the RTO will begin implementing the increased access “almost immediately” afterward.

“There’s a lot of IT work that needs to be done,” Kovler said, estimating it could take more than five months to complete. A “phased rollout” could take several months more to complete, he said.

June 7, 2020

Analyst: Texas ROFR Bill Likely to Survive

A Texas law giving incumbent transmission companies the right of first refusal to build new power lines in the state will likely survive another round of judicial review, according to one energy analyst.

The 5th U.S. Circuit Court of Appeals last week heard oral arguments in NextEra Energy’s effort to repeal the 2019 law but is not expected to rule on the matter for several months (20-50160).

NextEra Energy Capital Holdings, on behalf of four other NextEra transmission owner/developer entities, appealed a U.S. district court’s February decision to not overturn Texas Senate Bill 1938. (See NextEra Appeals Court Decision on Texas ROFR Law.)

Texas ROFR — The 5th Circuit Court of Appeals in New Orleans is weighing NextEra’s appeal of Texas’ right-of-first-refusal legislation. | *5th U.S. Circuit Court of Appeals*

The law essentially allows only incumbent transmission companies to build new power lines in Texas by granting regulatory certificates of convenience and necessity to the owners of the endpoints of a new transmission line. NextEra has alleged the law imposes burdens on interstate commerce by restricting entry into Texas’ transmission market, “outweighing any local benefits.”

ClearView Energy Partners, a D.C.-based independent energy policy research firm, said in a letter to its clients that it believes oral arguments during the June 1 hearing provide SB 1938’s proponents a reason to be optimistic.

The firm said Judge Jennifer Elrod appeared “skeptical” of NextEra’s standing and the “ripeness of the appeal.” Judge Gregg Costa “appeared at times to share” that view, it said.

“Judge Costa, however, did offer the view that Texas was not just establishing a right of first refusal … akin to a Minnesota law recently upheld by the 8th Circuit, but rather an outright ban,” the firm said.

Costa was referring to a similar case in Minnesota before the 8th U.S. Circuit Court of Appeals. (See Justice Dep t . Joins Challenge to Minn. ROFR Law and Courts Up hol d Minn. ROFR, MISO Cost Allocation.)

ClearView also said it considers the upcoming decision to be a “potential indicator of whether other states may see low judicial risk if they consider similar laws.”

“The 5th Circuit’s ruling could provide additional clarity of how the courts are interpreting the limits the dormant Commerce Clause imposes on states that create in-state preferences or requirements, an issue that has raised judicial risk in the past for state renewable power mandates,” the firm said.

NextEra is appealing the decision because it says NextEra Energy Transmission (NEET) Midwest could lose its “lawfully won right” to build the $115 million Hartburg-Sabine Junction transmission project in MISO’s East Texas footprint. It says SB 1938 “substantially impaired” NextEra’s reasonable contractual expectation to obtain a CCN from the Texas Public Utility Commission, as required by NEET Midwest’s agreement with MISO.

NEET Midwest won the project’s rights in 2018 through a competitive bidding process. (See NextEra Wins Bid to Build MISO’s 2nd Competitive Project.)

The legislation also affects NEET Southwest’s application with the PUC, the appeal’s defendants, to transfer ownership of 30 miles of 138-kV facilities from Rayburn Country Electric Cooperative in SPP’s region of East Texas.

June 7, 2020

PMU Vote Delayed by PJM

PJM’s Planning Committee postponed a vote by one month on “quick-fix” manual revisions to implement the RTO’s plans to expand the use of synchrophasors and make them a requirement for certain projects under the Regional Transmission Expansion Plan (RTEP).

Stakeholders were scheduled to vote on the issue charge and endorse the proposed manual language at the June 2 PC meeting to require synchrophasors — also known as phasor measurement units (PMUs) — in all new substations and major construction projects to monitor bus voltage and line flows.

Some members said they were concerned about using the quick-fix process to endorse the changes and questioned PJM staff about missing Tariff language in the proposal.

Dave Souder, PJM’s senior director of system planning, said the PMU expansion will improve reliability and give operations staff the tools they need for the increasingly dynamic monitoring needs of the grid. Souder said he recognized some stakeholders may have issues with the quick-fix method, so he requested that members express their concerns about the proposed manual language in advance of the July PC meeting.

“I really don’t want to force a quick-fix solution down the stakeholders’ throats,” Souder said.

PJM PMU — Types of projects under the PMU Placement Strategy | *PJM*

Shaun Murphy of PJM reviewed the PMU problem statement, issue charge and proposed solution at the meeting. In his presentation, Murphy said language is being proposed for section 1.4.1.3 of Manual 14B to add a PMU Placement Strategy (PPS) to identify the synchrophasor device coverage needed to support the RTO’s real-time synchrophasor applications. The PPS, which includes placement targets and required operational dates, would make mandatory a program that is currently voluntary.

Murphy said instituting the PPS would close the gap between research and real-time control room use and improve data reliability and oscillation detection. (See Oscillation Event Points to Need for Better Diagnostics.)

Making each substation “PMU ready” costs as much as $120,000, he said, and each substation would have two or three PMUs that cost about $10,000 each. As many as 889 projects could be created over a 12-year span if a voltage threshold of 100 kV for each unit is accepted, according to PJM. The PMU requirement would be effective for projects presented to the Transmission Expansion Advisory Committee after June 1, 2021.

Murphy said about 80 PMUs will be added each year at a cost of about $8 million annually.

Tom Hyzinski of GT Power Group said the yearly price tag seemed reasonable compared to the value of the information that could identify costly problems on the system. Hyzinski asked if there was any discussion by PJM on ways the cost could be allocated across stakeholders so that no one would be greatly impacted by the expense.

Souder said PJM was open to discussing cost allocation among stakeholders, but he said the RTO felt PMUs have to be expanded across the system to be effective. Souder said the technology would be required for both baseline and supplemental projects to spread the technology.

Dave Mabry of the PJM Industrial Customer Coalition (ICC) said he was thankful for the educational session PJM held on May 26 on PMUs and their benefits to the system. He asked if there were any Tariff changes considered in the PJM proposal, noting that the Tariff makes references to PMUs in generation interconnection.

Souder said PJM’s legal review concluded the manual language was sufficient.

Mabry said the ICC opposed using the quick-fix solution and thinks the issue would benefit from further consideration by stakeholders regarding the implementation strategy and cost allocation. He said the education session convinced the ICC to support the problem statement but that the group still has reservations about the PJM proposed solution and is concerned that it will increase the justification of supplemental projects, which are reserved for incumbent transmission owners and not subject to competitive bidding.

“We don’t want to implicitly approve supplemental projects we have questions about,” he said. “Our concern is whether PMUs are going to become a nexus for trying to justify supplemental projects.”

Souder said he understood that stakeholders have concerns about supplemental projects but said if PJM only requires PMUs in baseline projects, it will limit the ability to propagate the technology across the system.

“It truly is a catch-22,” Souder said. “We need the data across the systems so we can fully utilize the tools.”

June 7, 2020

PJM PC/TEAC Briefs: June 2, 2020

Reserve Requirement Study Assumptions

The PJM Planning Committee on June 2 unanimously endorsed the 2020 Reserve Requirement Study assumptions, which reset the installed reserve margin (IRM) and forecast pool requirement (FPR) for 2021/22 through 2023/24 and establish the initial levels for 2024/25.

Jason Quevada of PJM presented the assumptions, which were developed in the Resource Adequacy Analysis Subcommittee (RAAS). The 2020 assumptions are similar to those in 2019 except for the modeling of wind and solar, Quevada said during the PC’s meeting.

Previously, capacity values for wind and solar generators with three or more years of operating data were set based on their actual performance, with values for newer wind units set based on a combination of actual performance and class average capacity factors. The new Capacity Capability Senior Task Force will be meeting this year to develop a method for calculating wind and solar capacity values using effective load-carrying capability (ELCC), a measure of the additional load that a group of generators can supply without a reduction in reliability. (See AWEA Balks at PJM Plan on Wind, Solar Capacity.)

The ELCC approach, which is intended to address the underestimation of wind and solar output variability, is expected to have a minimal impact on the FPR.

The reserve requirement values will be based on a capacity benefit margin — the amount of transmission import capability reserved for emergency import sales — of 3,500 MW, the same as 2019. PJM will also continue using a load forecast error factor of 1%.

Staff will use the PRISM model to develop a cumulative capacity outage probability table for each week of the year except the winter peak. For the winter peak week, staff will create a table based on RTO-aggregate outage data collected between 2007/08 and 2019/20 to account for the risk caused by the large volume of concurrent outages observed during that time frame.

The final report is planned to be presented to the RAAS and the PC in September, with final approval in October.

Load Impact and Forecast Update

Andrew Gledhill of PJM’s resource adequacy planning unit presented the estimated COVID-19 impacts on load. Gledhill said that since March 24, weekday peaks have averaged 10.4% less (9,300 MW) than projected before the coronavirus pandemic. The weekday peak impacts have ranged from 0.6 to 15%, and the biggest impact to load forecasting came in the first week of May.

While impacts in May were generally larger than April, Gledhill said PJM believes some of the impact is because of increased “weather sensitivity” — increased cooling loads with summer’s arrival.

On May 26, for example, when the RTO’s weighted average daily temperature was above 70 degrees Fahrenheit, peak load was only 0.6% below expected.

“Essentially, PJM saw the impact of COVID-19 weaken a bit during the last half of May,” PJM spokeswoman Susan Buehler explained after the meeting. “It is likely some combination of increased economic activity and hotter weather driving up residential air conditioning usage as people continue telecommuting from home. We don’t yet have a full picture of which influence is greater.”

Overall energy consumption has been less affected by the pandemic, Gledhill said, with the average reduction since March 24 being 8%. Recent data suggest the reduced trend could be starting to change, he said, as a result of weather sensitivity and the lifting of stay-at-home orders across the country.

Moody’s Analytics’ forecast of U.S. real GDP | *PJM*

PJM last month asked FERC to approve a waiver allowing the RTO to post a revised peak load forecast for the second Incremental Auction for delivery year 2021/22.

The RTO posted its initial forecast for the auction before Feb. 1. The revised forecast reduces peak loads by 1.7% for 2020 and 1.6% for 2021, based on Moody’s Analytics’ April 2020 Economic Forecast, which predicts that third-quarter 2021 real GDP will be 7.1% lower than assumed in PJM’s posted load forecast.

PJM asked FERC to respond no later than June 15, three weeks before the start of the IA on July 6. PJM is publishing two sets of planning parameters for the auction, Gledhill said, with the first set based off the 2020 forecast and the second set based off the updated April forecast. If FERC approves the waiver, PJM will use the second set.

Competitive Planner Update

Ilyana Dropkin of PJM presented an update on the Competitive Planner, a web-based application for transmission owners and developers to participate in the RTO’s competitive planning process under Order 1000.

The current PJM process for proposal submission relies on an Excel template. Dropkin said that having a web-based application increases the speed and accuracy of the process and provides near-real-time tracking of submissions.

Beta testing was implemented May 6-20, Dropkin said, and volunteers suggested improvements and provided feedback about how the application compares to previous methods for submitting proposals.

Dropkin said registration for the new application is scheduled to begin June 22, and it will be opened for use about July 1.

Those looking to participate in the competitive planning process can get access to Competitive Planner by prequalifying through the critical energy/electric infrastructure information (CEII) process, Dropkin said.

Transmission Expansion Advisory Committee

Generation Deactivation Notification

Phil Yum of PJM provided the Transmission Expansion Advisory Committee an update on recent generation deactivation notifications, including a request received in May for Dickerson Units 1, 2 and 3. The coal-fired plant in Dickerson, Md., totals 545 MW.

According to a press release from plant owner GenOn Holdings, Units 1, 2 and 3 came online in 1959, 1960 and 1962, respectively. GenOn said the decision to deactivate the coal units was “driven by unfavorable economic conditions and increased costs associated with environmental compliance.”

GenOn requested a deactivation date of Aug. 13. The company will continue operating approximately 312 MW of natural gas- and oil-fired generating capacity at the site. Yum said a full result of the reliability analysis of the deactivation will be presented at the July TEAC meeting.

Yum also presented a second read of the deactivation of Chesterfield Units 5 and 6 (1,015 MW) in the Dominion zone, which are scheduled to retire on May 31, 2023. Yum said a generation deliverability problem was discovered at the Chickahominy 500/230-kV transformer, which would be overloaded with the loss of the Chickahominy-Surry 500-kV line.

PJM is recommending installing a second Chickahominy 500/230-kV transformer at an estimated cost of $22 million.

A second read was also presented on several transmission upgrade projects related to the reinstatement of the Shippingport, Pa.-based Beaver Valley nuclear plant in March. (See Beaver Valley Nuclear Plant to Stay Open.)

June 6, 2020

Mass. Senators to ISO-NE: Think Clean on Boston RFP

Massachusetts’ two U.S. senators on Friday urged ISO-NE to prioritize “state climate, energy and health goals” when evaluating responses to a request for proposals seeking transmission projects to address the 2024 retirement of the Mystic Generating Station near Boston.

Sens. Ed Markey and Elizabeth Warren, both Democrats, sent a letter criticizing the RTO’s Boston 2028 RFP planning process for listing “environmental impact” in the lowest priority category for evaluation, noting that “public health impacts are not called out at all.”

ISO New England transmission — New England likely needs 1,500 MW+ of new offshore wind resources every year to achieve 80%-by-2050 decarbonization goals. | *The Brattle Group*

“In particular, the eventual retirement of this power plant, which is the largest fossil fuel plant in New England, presents an opportunity to continue cleaning up the New England power grid and safeguarding public health,” they said. “The six New England states have all committed to achieving at least a 75% reduction in their greenhouse gas emissions by 2050. The Carbon Free Boston initiative aims to reach a target of carbon neutrality for the city by 2050. As part of the Boston 2028 RFP, ISO-NE should consider and prioritize these targets.”

ISO-NE spokesman Matthew Kakley declined to comment Friday, saying the RTO had just received the letter and was still reviewing it.

The RTO received 36 phase one proposals in response to the request, with costs ranging from about $49 million to $745 million, and in-service dates ranging roughly from mid-2023 to 2026.

The RTO’s transmission planners will share their draft list of qualifying proposals at a Planning Advisory Committee meeting June 17.

Both Markey and Warren last November joined five of their fellow New England senators in sending a letter to the RTO accusing it of “preserving the status quo of a fossil fuel-centered resource mix” in its fuel security planning triggered by the Mystic retirement. (See Senators Ask ISO-NE to Heed States on Clean Energy.)

Side Pressure

“As Massachusetts and other New England states work to reach decarbonization targets and respond to the ongoing COVID-19 pandemic, it is more important than ever that regional transmission organizations consider these impacts as part of electric-grid planning,” the senators said.

Eight qualified transmission project sponsors submitted bids for the Boston RFP. Among them was Anbaric Development Partners, which in March announced details of its proposed 900- to 1,200-MW Mystic Reliability Wind Link transmission project, including an option for an additional 1,200 MW of transmission capacity. (See ISO-NE Planning Advisory Committee: March 18, 2020.)

“Additionally, as Massachusetts and other New England states continue efforts to limit and stop the spread of COVID-19, it is important to consider the public health effects of various kinds of electricity generation,” the senators said. “Research continues to show a link between air pollution and higher COVID-19 death rates, placing a premium on regional transmission organizations’ factoring air quality into their grid-planning decisions — particularly for communities that are disproportionately affected by COVID-19 and the historic burden of air pollution.”

Last June, about 300 people turned out in Springfield, Mass., to attend a Department of Energy Resources hearing on a proposal to alter the state’s renewable portfolio standard to include biomass plants. (See Residents Protest Biomass at Mass. DOER Hearing.)

Among the nearly 60 people testifying were a dozen biomass industry proponents and five members of the Springfield City Council opposing plans by Palmer Renewable Energy for a 35-MW wood-burning plant in East Springfield.

“Clean energy and clean air are both important policy objectives for Massachusetts and the broader New England region, and those priorities should be reflected appropriately among the evaluation criteria for the Boston 2028 RFP,” the senators said.

Last August, about 40 environmental activists marched in front of the headquarters of Connecticut’s Department of Energy and Environmental Protection to protest state regulators’ approval of a new gas-fired power plant in the town of Killingly. (See Connecticut Activists Protest Gas-fired Plant.)

The Connecticut Siting Council last June approved construction of the 650-MW Killingly Energy Center by Florida-based developer NTE Energy, permitting the plant to emit up to 2.2 million tons of carbon dioxide each year.

“Fossil fuel plants are increasingly uneconomic, particularly as the cost for new renewable electricity generation declines, and after factoring in the costs to public health from air pollution,” the senators said. “In pursuing transmission solutions to meet electricity demand and address reliability needs, ISO-NE can also strive to better integrate low- or no-carbon generation projects, with the added benefit of saving ratepayers money and avoiding the need to bail out uneconomic plants.”

June 5, 2020

PG&E Fire Victims Urge Judge to Reject Plan

Fire victims unhappy with Pacific Gas and Electric’s reorganization scheme urged U.S. Bankruptcy Judge Dennis Montali to reject it Thursday, while others asked him to appoint an examiner to look into allegations of voting problems.

The victims had most of Thursday to make their cases during the second day of arguments over whether Montali should confirm or deny PG&E’s Chapter 11 plan. (See Lawyers Argue PG&E Bankruptcy Plan.) The arguments are scheduled to continue at least through Friday, after which Montali will have to decide whether to accept PG&E’s proposal to exit bankruptcy.

The case began more than 16 months ago as PG&E faced billions of dollars in liabilities for years of devastating wildfires ignited by its transmission lines and other electrical equipment.

During the morning’s session, two lawyers and an individual fire victim contended that many victims hadn’t received ballots in time to vote on the reorganization plan by the May 15 deadline.

“The request for an appointment of an examiner is based on the very large amount of voting procedure irregularities that we’ve now seen,” attorney Bonnie Kane said. “Primarily it appears from the problem of the fire-victim creditors not receiving ballots or receiving them after the time in which they could vote.”

Montali disputed the idea that there were a large number of irregularities.

PG&E victims reject plan — The Tubbs Fire in October 2017 wiped out part of Santa Rosa, Calif. | *City of Santa Rosa*

Of the approximately 80,000 fire victims sent ballots, about 50,000 responded, voting overwhelmingly for PG&E’s plan, Montali said. (See PG&E Bankruptcy Moves Toward Conclusion.) It isn’t unusual for many people not to vote in bankruptcy cases, as well as in presidential elections, he said.

“There are 50,000 people who voted, and by my count, less than 1,000 who may be, for whatever reason, in that category” of those who experienced voting difficulties, the judge said. “I don’t consider that large in relation to the 50,000 who voted.”

The vote by fire victims to approve the plan by a margin of approximately 85% wasn’t even close, he noted.

“This isn’t a city council election,” where the winner is decided by 15 votes, he said.

Montali gave more credence to fire victim Theresa Ann McDonald, who said she wanted to learn if voting problems occurred and why — just as she had wanted to know if PG&E started the Camp Fire, which burned down her home in Paradise, Calif., in November 2018.

The utility has acknowledged its equipment started the Camp Fire, the deadliest and most destructive in state history.

“Those are all pieces in putting the entire puzzle together,” McDonald said.

She said Montali could appoint an examiner after approving PG&E’s plan, allowing the bankruptcy case to move forward.

PG&E lead attorney Stephen Karotkin contended even that could jeopardize the funding the company needs to emerge from bankruptcy by casting a cloud of uncertainty over its plan.

“The debtors will be going out to the market to raise equity capital of $9 billion in the most efficient manner possible, and to have an overhang of a potential examiner here will impact the ability to effect that marketing effort on the best possible basis,” Karotkin said.

After hearing all the arguments, Montali said he would rule on the matter later.

‘Exposed to Risks of Fire’

Later in the day, fire victim William Abrams, a frequent self-represented litigant in the case, urged Montali to reject PG&E’s reorganization plan because, he said, it fails to ensure that a safe and financially stable utility emerges.

“This plan put together is not in good faith,” Abrams said. “Its primary goal is to ensure that entrenched investors can cash out and exit the stock — to leave victims and the public living among the PG&E lines, exposed to risks of fire and risks associated with the fires that they cause.”

Abrams and his family had to flee their home in Santa Rosa, Calif., in October 2017, as the Tubbs Fire roared through the city. State fire investigators said PG&E equipment didn’t start the fire, but the company agreed to settle with victims as part of its restructuring.

Abrams repeated the argument that fire victims are the only large group of creditors being asked to accept PG&E stock as part of their settlement agreement. (See Skeptics Get Last Chance to Sound off on PG&E Plan.) Half of a $13.5 billion victims’ trust is expected to be funded with the utility’s stock, which could diminish in value or become worthless, he said.

PG&E said it hopes to attract “traditional utility investors” after bankruptcy, but the utility won’t pay dividends for years, he said.

“I don’t see how that is possible,” Abrams said.

The state and the California Public Utilities Commission will have to solve PG&E’s safety and financial problems within months after it leaves bankruptcy, including by raising rates, he argued.

June 4, 2020

NERC Clarifies Audits, E-ISAC in Filing

NERC has submitted the first of two compliance filings directed by FERC earlier this year, providing information about its oversight of regional entities, the development process for reliability guidelines and the role of the Electricity Information Sharing and Analysis Center (E-ISAC) in developing reliability standards (RR19-7).

FERC ordered the filing on Jan. 23 in response to NERC’s five-year performance assessment, with the deadline originally set for April 22. (See FERC Extends NERC Compliance Filing Deadline Again.)

RE Audit Expansion Proposed

NERC’s Rules of Procedures (ROP) and the delegation agreements it signed with REs in 2007 require it to perform “comprehensive” audits of their compliance monitoring and enforcement programs (CMEP) at least once every five years.

However, FERC noted in January that NERC’s performance assessments for both 2014 and 2019 failed to mention whether it had actually performed any such audits in the relevant period. The commission required NERC to produce any RE audits it had performed or provide a plan to perform them within the next 18 months.

In its filing, NERC disclosed that it had “conducted two [CMEP] audits of the regional entities” since 2014 that examined confidential information and conflict-of-interest procedures, as well as internal controls evaluations. NERC also performed two “non-CMEP audits” during the period to examine REs’ implementation of the event analysis process and of Section 215 of the Federal Power Act.

The audit reports were not provided in the public filing; NERC requested that the commission treat the information as privileged material because it “reflects confidential business information as well as NERC’s investigative audit process.”

Along with information on its audit history, NERC outlined a proposal to enhance RE audits by expanding the scope of its internal audit program — which currently focuses on CMEPs, the Organization Registration and Certification Program (ORCP) and its bulk electric system exception activities — to encompass such functions performed by the entire ERO Enterprise. These audits, dubbed “regulatory programs audits” in the proposal, would be carried out at least once every three years, either by NERC or an outside auditor.

Under the proposal, the organization would also conduct a separate “nonregulatory programs” audit every year with participation by observers from FERC. The nonregulatory programs audit would cover other delegated functions performed by the REs outside of the CMEP, ORCP and BES exception activities.

Clarity on Reliability Guideline Development

NERC audit — NERC’s proposed risk monitoring flowchart | *NERC*

FERC also ordered NERC to explain its guidance development process, how it determines if guidance documents are addressing the risk they are designed to, and “how and at what interval NERC will evaluate whether components of the guidance document should be incorporated into the reliability standards.” The mandate was prompted by concern that unlike reliability standards, which have a transparent development process, guidelines may be “based on the input of a limited number of interested participants.”

In response, NERC explained the difference between reliability standards — which set requirements for operation of the bulk power system — and reliability guidelines, which “[outline] approaches for managing potential risks to reliability.” While it emphasized that it “carefully considers” whether a guideline or a standard is best suited for a particular circumstance, the organization also acknowledged that it lacked a formal framework for addressing known and emerging reliability risks.

NERC has already begun the process of formalizing its existing process. At February’s meeting of the Member Representatives Committee, Chief Engineer Mark Lauby outlined a proposed risk management framework. (See NERC Developing Risk Mitigation Framework.) The framework, which NERC included in the compliance filing, comprises six steps:

Identifying risks and creating a risk registry;
Prioritizing risks;
Identifying and evaluating mitigation strategies;
Deploying mitigation strategies;
Measuring the strategies’ success; and
Monitoring the residual risk.

Reliability guidelines may be selected in the third step as the best method for addressing moderate- or low-impact sustained risks, or risks in areas that fall outside NERC’s jurisdiction. Responsibility for guideline development previously fell within the charters of the Operating, Planning and Critical Infrastructure Protection committees; these procedures will be consolidated under the new Reliability and Security Technical Committee (RSTC) after its first meeting next week.

The RSTC will also be responsible for evaluating the effectiveness of guidelines after they are posted. Under the RSTC charter, comments are accepted on an ongoing basis and must be reviewed every quarter. At any time, the committee may update a guideline, and every third year the guideline must be reviewed for continued applicability, usefulness and effectiveness. Metrics for evaluation of guidelines include:

performance of the BPS before and after the guideline’s introduction;
use and effectiveness of the guideline as reported by industry via survey;
industry assessment of the extent to which the guideline addresses risks; and
additional metrics specific to each guideline as determined by the RSTC.

E-ISAC Information Sharing Detailed

The final section of NERC’s filing details how the E-ISAC shares industry information with the ERO and the role that its data play in developing reliability standards. FERC requested the material because of concern that while E-ISAC’s code of conduct prohibits sharing information received from registered entities with enforcement staff, it may be permitted to share such information for the purposes of developing standards.

NERC said in its filing that the E-ISAC operates under “broad information-sharing restrictions” that generally restrict personnel from sharing any voluntarily reported information with non-ISAC staff at NERC. Limited exceptions are allowed. Specifically, such information may be shared only with:

NERC’s president and CEO for providing oversight of the E-ISAC;
NERC’s general counsel for providing legal advice to the ERO;
other persons or entities to whom the submitting entity has provided permission for such sharing; and
persons or entities authorized to review such information by the Electric Subsector Coordinating Council (ESCC).

In spite of these restrictions, NERC acknowledged that some E-ISAC data may be used to inform development of reliability standards. This is generally limited to information provided through the E-ISAC but also publicly available through other avenues. The E-ISAC may also share nonpublic reports that anonymize and aggregate otherwise protected information. Such reports might include trending analysis or analysis of a specific threat, vulnerability or risk, as long as no specific entities are implicated.

NERC plans to enhance the coordination between the E-ISAC and the Standards Department with quarterly meetings between relevant personnel so that relevant information may be exchanged more smoothly and frequently, in hopes of establishing a “regular feedback loop” to help strengthen standards development.

The E-ISAC also features prominently in the second compliance filing ordered by FERC, which is due on Sept. 28 (extended from the original deadline of July 21). NERC last week posted the draft filing for comment. It details proposed revisions to the E-ISAC’s relationship with the ESCC, along with changes to NERC’s sanction guidelines to clarify how the ERO Enterprise applies monetary and nonmonetary penalties to registered entities. The comment period runs through July 10. (See NERC Seeks Comments on Proposed ROP Changes.)

June 4, 2020

Lawyers Argue PG&E Bankruptcy Plan

Attorneys began debating the merits of Pacific Gas and Electric’s reorganization proposal Wednesday during the final days of the utility’s 16-monthlong bankruptcy case before Judge Dennis Montali in San Francisco.

“I’m prepared to shut up and listen for your argument,” Montali told the lawyers participating in the hearing via Zoom video. Dozens of attorneys were scheduled to deliver statements Wednesday through Friday.

PG&E Bankruptcy Plan — Stephen Karotkin | *Weil, Gotshal & Manges*

PG&E’s lead attorney Stephen Karotkin made the first argument. He said PG&E’s plan resulted from months of “hard-fought, good-faith” negotiations that led to agreements with all the major parties in the case, including creditors, insurance companies and the victims of major wildfires sparked by utility equipment in 2015, 2017 and 2018.

An estimated $30 billion in liabilities from those fires — including the November 2018 Camp Fire, the deadliest in state history — caused PG&E to file for bankruptcy in January 2019.

“The plan before you today has the overwhelming support of the fire victims in addition, your honor, to the support of the governor’s office [and the California Public Utilities Commission],” Karotkin told Montali. “All those approvals and support serve to ensure expedited distributions to fire victims, and that, your honor, is the principal goal that these debtors have expressed since these cases were commenced last January.” (See CPUC Approves PG&E Bankruptcy Plan.)

Karotkin warned the judge that if he doesn’t approve the plan, it could delay payments to fire victims for years. It would also prevent PG&E from taking part in a state fund to insure it against future wildfire liabilities. PG&E must exit bankruptcy by June 30 to participate in the wildfire fund established last year by Assembly Bill 1054.

Until Wednesday, a dispute between PG&E and the case’s official Tort Claimants Committee had threatened to derail the case. But the TCC and PG&E filed court papers before the hearing saying they had resolved the committee’s objections to provisions in the Chapter 11 plan, which the committee had argued could have hampered lawsuits against the utility for post-bankruptcy activities. PG&E contended the provisions were commonplace in bankruptcy cases but agreed to remove them.

One creditor group, consisting of state public employee retirement systems that bought PG&E shares, continues to oppose the reorganization proposal. It is pressing a securities fraud action against PG&E, saying it was deceived about potential fire liabilities and the resulting devaluation in PG&E stock.

Karotkin told Montali the opponents are subordinate shareholders whose opposition is outweighed by the support of the majority of PG&E’s creditors.

Some fire victims still oppose the plan. They argue victims could be shortchanged because PG&E plans to fund a $13.5 billion victims’ trust with $6.75 billion in company stock, which could end up being worth less when the utility emerges from bankruptcy. Some of the self-represented fire victims are among those scheduled to argue before Montali. (See Skeptics Get Last Chance to Sound off on PG&E Plan.)