FERC OKs CAISO RMR Agreement for 27.5-MW Plant

FERC approved a settlement Thursday between CAISO and the operator of an aging 27.5 MW cogeneration facility over a reliability must-run agreement (RMR) — a continuation of the ISO’s efforts to keep small, aging natural gas plants online to help ensure reliability this summer and beyond (ER20-1708).

The Channel Islands Power plant, owned and operated by the California State University-Channel Islands Site Authority, came online 33 years ago and was set to retire last year after its power-purchase agreement with Southern California Edison expired in March 2020.

CAISO, however, contended that the plant is needed to maintain reliability under ISO planning standards in a part of Central California — the Santa Clara subarea of the Big Creek/Ventura local area — where the local capacity requirement is 288 MW but total available resources, including the Channel Islands plant, total 250 MW.

FERC rejected the original agreement between CAISO and the Site Authority in June 2020 following protests from parties, including the California Public Utilities Commission, over the $2.6 million revenue requirement from May to December 2020. FERC ordered an evidentiary hearing while encouraging the parties to settle.

CAISO and the authority came back to FERC in December with a lower cost of just over $2 million for 2020, $3.2 million for 2021 and $3.2 million for 2022, if the plant is still needed for reliability. At the recommendation of trial staff, FERC found the new agreement was reasonable and in the public interest.

The new settlement agreement “substantially reduces the fixed revenue requirement for the initial eight months of the RMR agreement,” trial staff said in comments. “Furthermore, it provides rate certainty because the settlement sets forth the fixed revenue requirement for 2021 and the contingent fixed revenue requirement for 2022, thereby eliminating the need for additional commission proceedings.”

RMR Agreements

FERC’s approval of the Channel Islands settlement is the latest development in a series of RMR agreements between CAISO and generators that started in 2019 after the ISO projected potential summer shortfalls from 2020 through at least 2024. (See CAISO, CPUC Warn of ‘Reliability Emergency’.)

The state is transitioning from fossil-fuel generation to renewables and storage under the mandates of Senate Bill 100, which requires load-serving entities to provide 100% fossil-free electricity by 2045.

CAISO and other state agencies projected the transition could lead to capacity shortfalls during summer peak demand until new solar, wind and storage resources in the ISO’s queue come online. But the energy emergencies of August and September, when demand exceeded or nearly exceeded supply during severe Western heat waves, caught the ISO and CPUC off guard.

CAISO had to order rolling blackouts affecting hundreds of thousands of customers Aug. 14-15 and would have done so again during Labor Day weekend if not for dramatic conservation efforts. (See CAISO Avoids Blackouts amid Brutal Heat, Fires.)

In response, the CAISO Board of Governors approved an RMR designation in December for two units at the Midway Sunset Cogeneration facility, a 250-MW natural gas plant built in the late 1980s in a Kern County oilfield. The units were scheduled to retire at the end of this year. (See CAISO Board Fields RA Measures, Big and Small.)

FERC said on April 2 that it needed more information before it could rule on the CAISO-Midway RMR agreement and sent the matter to settlement proceedings. (See CAISO’s 1st System RMR Agreement Set for Hearing.)

The CAISO governors approved an RMR designation in March for PurEnergy’s 34.5-MW Kingsburg Cogeneration plant after ISO management said the 30-year-old gas plant was required for the reliable operation of the transmission system in 2021.

Four months before last summer’s events, CAISO designated three Central California natural gas plants as RMR resources to meet summer demand — the Channel Islands plant, Starwood Energy Group’s 49.5-MW Greenleaf II Cogen facility and Atlantic Power’s 48.5-MW E.F. Oxnard plant. (See CAISO Board OKs $141.7M Tx Plan, RMR Contracts.)

The Board of Governors’ Severin Borenstein noted at the time that CAISO had sought only one RMR designation the year before. “Are we seeing an increase, or should I not think this is a trend?” Borenstein asked.

ISO management said the RMR designations were not a trend “yet” but could become one. “I think the operative word being used is ‘yet’ … but we’re going to continue to be vigilant about this issue,” then-CEO Steve Berberich said.

April 18, 2021November 10, 2023

NYPSC OKs $800 Million Transmission Cost Recovery for Con Ed

The New York Public Service Commission on Thursday approved $800 million in cost recovery by Consolidated Edison for three transmission projects known collectively as the Transmission Reliability and Clean Energy (TRACE) projects.

The projects are needed for reliability in 2023 and 2025 because of the retirement or unavailability of 399 MW of peaking generation located in four out of five New York City boroughs (19-E-0065). In 2019, the state’s Department of Environmental Conservation (DEC) adopted regulations requiring peakers to limit nitrogen oxide emissions during the ozone season or be retired if they can’t comply.

The new projects include the 138-kV Rainey-to-Corona, Gowanus-to-Greenwood and Goethals-to-Greenwood lines.

“It’s likely we will see many more of these projects as we transform our electric system,” PSC Interim Chair John B. Howard said. “The primary reason for the construction of this project is to maintain reliability, but it also builds in safeguards for if and when certain generation assets are curtailed or shut for environmental reasons.”

Graph shows the high-level topology of the Astoria East / Corona 138-kV, standalone TLA. | Con Edison

For the Astoria East/Corona transmission load area (TLA), Con Edison will develop Rainey-to-Corona, a 6-mile, 345/138-kV PAR controlled underground feeder. In the Greenwood/Fox Hills 138-kV TLA, the utility will install two new feeders, including a 1-mile, 345/138-kV PAR controlled line that will connect the 345-kV Gowanus substation with the Greenwood 138-kV substation, increasing transfer capability by about 300 MW.

Con Edison expects to start work immediately. Rainey should be operational by the start of summer 2023, and the Gowanus and Goethals projects are expected to enter service by summer 2025. Because the projects will have climate benefits statewide, cost allocation will be evaluated and considered in future commission orders.

Commissioner Diane Burman voted in favor of the projects but expressed “serious concerns” as the state moves ahead with big changes to the power grid.

She said her top concern in decarbonizing the grid is the reliability of the power supply, ensuring that firm and reliable resources balance the high penetration expected from intermittent resources like wind and solar.

Second is the need for investment in transmission and distribution infrastructure, and recognizing that “the whole nature of the electric power system, and frankly of electric service itself at the local distribution and bulk transmission levels” is rapidly changing, Burman said.

The commission’s third priority is to understand consumer behavior and work with people to achieve the desired outcome at the lowest cost, she said.

Commissioner James Alesi said he believed the approach would help Con Edison meet the goals of the CLCPA as well as comply with the DEC regulations, and hoped that the measure would reduce “pollutants in environmental justice communities and make it easier to transition to a cleaner, low-carbon grid.”

The retiring peaker plants include Con Edison’s 59th Street GT1 (17.1 MW) and 74th Street GT units 1 and 2 (37 MW) in Manhattan; Con Edison’s Hudson Ave unit 5 (16.3 MW) in Vinegar Hill, Brooklyn; the Helix Ravenswood units 1, 10 and 11 (68.6 MW) in Long Island City, Queens; the NRG Astoria GTs (240 MW) in Astoria, Queens; and the NRG Arthur Kill GT1 unit (20 MW) in Staten Island.

April 18, 2021

PJM MRC/MC Preview: April 21, 2021

Below is a summary of the issues scheduled to be brought to a vote at the PJM Markets and Reliability and Members committees on Wednesday. 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 covering the discussions and votes. See next Tuesday’s newsletter for a full report.

Markets and Reliability Committee

Consent Agenda (9:10-9:15)

B. The MRC will be asked to endorse proposed revisions to Manual 14D: Generator Operational Requirements regarding the Resource Tracker ownership confirmation requirement. At the Operating Committee meeting in March, stakeholders unanimously endorsed a “quick fix” to address information entered into the Resource Tracker application. (See “Resource Tracker Ownership Endorsed,” PJM Operating Committee Briefs: March 11, 2021.)

Endorsements/Approvals (9:15-10:15)

1. Long-term Five-minute Dispatch and Pricing (9:15-9:30)

Members will be asked to endorse the proposed solution and associated tariff and Operating Agreement revisions addressing the long-term five-minute dispatch and pricing changes. MC endorsement will also be sought. Stakeholders at the March Market Implementation Committee meeting unanimously endorsed a proposal by PJM and the Independent Market Monitor on the long-term five-minute dispatch evaluation that was under consideration for several months. (See “5-Minute Dispatch Plan Endorsed,” PJM MIC Briefs: March 10, 2021.)

2. Capital Recovery Factor for Avoidable Project Investment Cost Determinations (9:30-9:45)

Stakeholders will be asked to endorse the proposed solution and associated tariff revisions addressing the capital recovery factor (CRF) for avoidable project investment cost determinations. The MC will also vote on the proposed solution. PJM said the CRF values on a table of section 6.8 of Attachment DD of PJM tariff needs updating to reflect current federal tax laws. (See “Capital Recovery Factor Endorsed,” PJM MIC Briefs: March 10, 2021.)

3. Critical Infrastructure Stakeholder Oversight (CISO) (9:45-10:15)

The MRC will be asked to endorse the proposed solutions and changes to Manual 14B, Manual 14F and the Operating Agreement to address the mitigation and avoidance of future CIP-014 (critical infrastructure protection) facilities. The committee will be asked to separately endorse the proposed mitigation and avoidance solutions. (See “CISO First Read,” PJM MRC/MC Briefs: March 29, 2021.)

Members Committee

Consent Agenda (1:10-1:15)

B. Stakeholders will be asked to endorse proposed revisions to Manual 34: PJM Stakeholder Process addressing motions and amendments. The revisions, which were under review for more than a year at the Stakeholder Process Forum, modify three sections in Manual 34, including a clarification on when members can bring an issue directly to the MC for a vote. (See “Manual 34 Revisions,” PJM MRC/MC Briefs: March 29,2021.)

C. Members will be asked to approve proposed revisions to remove the transmission loading relief (TLR) buy-through congestion process from the Operating Agreement. TLR buy-through is a tool PJM uses to curtail interchange transactions that cause loop flow to the RTO around the time emergency procedures are being conducted to reduce the impact on a flowgate or a transmission facility. The process was created when PJM was fully within the Mid-Atlantic region and was issued more frequently than it is today, according to the RTO. (See “TLR Buy-through Quick Fix,” PJM Operating Committee Briefs: March 11, 2021.)

April 18, 2021

NESCOE Floats ‘Overlay’ Tx Planning Concept for Public Policy

The New England States Committee on Electricity (NESCOE) on Wednesday presented a concept that would integrate the RTO’s only existing routine transmission planning process — system reliability planning — with the consideration of public policy-driven options.

NESCOE General Counsel Jason Marshall told the Planning Advisory Committee that the Overlay Network Expansion (ONE) Transmission is one potential approach to transmission planning, calling it “a concept for feedback, not a NESCOE proposal.”

Under the concept, ISO-NE would extend the 10-year horizon of its reliability model to consider public-policy driven demand, infrastructure and resource mix changes up to 40 years into the future. The study would use resources in the interconnection queue or other assumed resources and identify potential delivery locations. Load growth and retirements also would be considered.

If the RTO identifies a public policy solution to be integrated with the preliminary reliability solution, it would be added to the Regional System Plan (RSP) as a ONE Transmission project. If ISO-NE does not identify a public policy solution to be integrated, it would confirm the preliminary reliability project as the preferred solution and put it in the RSP as a Reliability Transmission Upgrade.

NESCOE transmission — ISO-NE headquarters in Holyoke, Mass. | *ISO-NE*

“The idea here is really to leverage the regular planning that [ISO-NE] does for system reliability to get insight into potential public policy transmission options,” Marshall said.

ONE Transmission does not incorporate all the changes NESCOE has identified as needed in its vision statement, which would require tariff changes and should proceed on its track, Marshall said. But ONE Transmission does align with the Vision’s identification of the need for new planning mechanisms for integrating clean energy resources.

FERC Order 1000 required procedures to consider public policy-driven transmission needs. NESCOE’s 2019 Annual Report listed as one priority an assessment of whether the public policy transmission planning process could benefit from adjustment.

According to Marshall, a transparent planning process provides greater visibility into potential cost-effective investments to integrate clean power in addition to an opportunity to co-optimize infrastructure projects, promoting reliability and other public policy objectives. A multi-use transmission project could avoid separate siting proceedings, potentially only years removed, involving the same right-of-way or substation.

Consistent with the Vision Statement, any changes to cost allocation will be considered separately from planning concepts, Marshall said.

Since ONE Transmission is conceptual, Marshall asked that feedback be sent to ISO-NE for posting on the PAC website rather than to NESCOE.

Final Draft Energy, Seasonal Peaks Before 2021 CELT

ISO-NE’s Jon Black and Victoria Rojo presented the PAC with the final draft energy and seasonal peak forecasts, a last step before releasing the 2021 capacity, energy, loads and transmission (CELT) report on May 1.

Other than implementing the new methodology for passive demand resources (PDRs), which Black and Rojo discussed at the March PAC meeting, the RTO made no changes to the energy and summer and winter demand forecast methodologies since CELT 2020:

The final draft 2021 gross annual energy forecast for the region is lower than the CELT 2020 forecast by 4.5% in 2021 and 3.1% in 2029. The gross annual energy for the region is projected to increase at a compound annual growth rate (CAGR) of 1.6% from 2021 through 2030, up 1.4% from CELT 2020.
The final draft 2021 gross 50/50 summer peak demand forecast for the region is lower than CELT 2020 by 3.9% in 2021 and 5.4% in 2029. Gross summer peak demand is expected to rise at a CAGR of 0.7% from 2021 through 2030, down from the 0.9% in CELT 2020.
The final draft 2021 gross 50/50 winter peak demand forecast for the region is lower than CELT 2020 by 6.0% in 2021 and 4.5% in 2029. Gross winter peak demand for the region will be higher at a CAGR of 1.3% from 2021 through 2030, up 1.1% from CELT 2020.

Additionally, Black and Rojo said there was the consideration of the evolving impacts of the COVID-19 pandemic as reported in Moody’s Analytics Economic Outlook. The RTO used multiple versions of the economic outlook (November 2020 and February 2021). February’s economic forecast was the most optimistic. It stated that new COVID-19 infections peaked in January and herd immunity is expected to be achieved by September 2021, along with a relaxing of state and local government restrictions. It also incorporates the impacts of the recent pandemic relief package and an assumption that President Biden’s “Build Back Better” agenda is enacted in the second half of this year at a total cost of less than $1 trillion.

Environmental Update

Patricio Silva, lead analyst in system planning for ISO-NE, delivered an environmental update and said that in 2020, fossil, nuclear, renewable and other generating resources and transmission assets complied with federal and state environmental requirements. In 2021, however, state requirements are evolving, and there is a state of flux at the national level with the transition from the Trump Administration to the Biden Administration.

Siting energy infrastructure remains challenging across New England, affecting fossil, renewable and other generating resources and new or upgraded transmission resources, all needed to maintain reliability.

Estimated native power system carbon emissions of 21.4 million metric tons in 2020 increased 3% compared to 20.8 million in 2019. Shifts in energy consumption, most likely due to the COVID-19 pandemic, resulted in lower monthly net energy demand in 2020, but net system emissions increased compared to 2019.

The Energy Information Administration and other short-term projections suggest annual emissions will increase through 2022 in the region because of increased natural gas generation despite increased nuclear and renewable energy output. Carbon emissions are expected to range between 25-36 million metric tons through 2027.

April 18, 2021

FERC Dismisses Generators’ Complaint Against Mystic

FERC on Thursday dismissed a complaint by New England generators alleging that Exelon intended to game the ISO-NE market by returning Mystic Generating Station to service after its cost-of-service agreement (COS) expires in 2024 (EL20-67).

Exelon provoked anger among some stakeholders last year when it filed interconnection requests with ISO-NE to keep units 8 and 9 at the 2,001 MW Massachusetts plant running beyond the end of its $400 million COS agreement. (See Exelon Bid to Keep Mystic Units Running Provokes Outrage.)

The commission’s April 15 order dismissed two parts of the complaint as moot, noting that Exelon withdrew its interconnection queue position requests within days of the complaint and that FERC addressed disputed cost-recovery language in rehearing orders in July and December 2020.

The generators had argued that Mystic’s withdrawal from the queue positions reflected “Exelon’s intent to continue to operate Mystic 8 and 9 in some form compensated by market-based rates after the Mystic agreement has ended.”

The commission in December clarified its various orders approving ISO-NE’s cost-of-service contract with Mystic after having ruled on rehearing requests from the RTO, power generators and Connecticut regulators. FERC said that while Exelon must demonstrate that Mystic recovers only costs attributable to serving the agreement, the company will not be required to file the COS charge methodology, although costs may be reviewed in the true-up process. (See FERC Further Alters Mystic Cost-of-service Agreement.)

FERC Mystic Complaint — New England and northeastern Canada LNG facilities. | *EIA*

The commission’s July 2018 (ER18-1639-001) and December 2018 orders (ER18-1639-002) approved the RTO’s agreement for Mystic 8 and 9, including payments to the company’s economically co-dependent Everett LNG facility, the plant’s sole source of natural gas.

After withdrawing its interconnection requests, Exelon said it had no intention of repowering the units but hoped to continue operating its neighboring LNG terminal after the retirement of the power plant.

Complainants included Vistra Energy, Dynegy, NextEra Energy, NRG Power Marketing, LS Power, FirstLight Power and Cogentrix Energy Power Management, and were supported by the New England States Committee on Electricity (NESCOE), Connecticut regulators, and public systems.

They all urged the commission to extend the clawback provisions of the Mystic agreement to any iteration of units 8 and 9 that continue operating after the COS agreement and broaden them to include any amounts spent on the LNG terminal.

FERC declined that request, saying, “We already resolved this question in the July 2020 second rehearing order and complainants have failed to support a departure from our prior orders … [wherein we] determined that the clawback provision should not include Everett-related capital expenses and repair costs.”

The commission also disagreed with the complainants’ assertion that, because FERC previously limited Mystic’s fuel cost recovery of Everett fixed costs to 91% rather than the 100% that Mystic sought, it should apply the same formula to the fuel cost recovery of Everett’s capital expenditures and repair costs.

“The two situations are not analogous,” the commission said.

“But, as the commission made clear, it was reviewing the justness and reasonableness of the payments that Mystic would receive as they relate to the amount of Everett-related costs that Mystic could charge to customers. However, the clawback mechanism for Everett’s capital costs that complainants ask the commission to impose would not apply,” FERC said.

April 18, 2021

FERC Rejects GreenHat Arguments in Shell Case

FERC on Thursday rejected GreenHat Energy’s contention that the commission erred in its November ruling in a dispute between the company and Shell Energy North America following GreenHat’s 2018 default (EL20-49).

The November order partially granted Shell’s petition for declaratory order, finding that, under the PJM tariff, entry of data into the Financial Transmission Rights (FTR) Center for bilateral trades “does not automatically establish standalone bilateral contracts at the stated price, absent a separate agreement by the parties.” The FTR Center is PJM’s tool that market participants use for submitting bids into the auctions prior to it going live.

Shell petitioned FERC in May to intercede in a Texas state court case in which GreenHat filed a breach-of-contract claim against the energy company regarding bilateral contracts to transfer FTRs, saying Shell owed $68 million based on entries in the price field of the FTR Center for trades of around 3,870 FTRs. (See Shell Energy Seeks to Avoid Liability in GreenHat Trades.)

The commission in November declined Shell’s request to assert “primary jurisdiction” to resolve the dispute under Texas law as to whether the two companies entered into contracts that Shell would make payments based on entries in the FTR Center, allowing the case to proceed.

In its rehearing request to the November order, GreenHat asked that the commission “clarify that it is not prejudging the merits of either the Texas state litigation or any subsequent commission enforcement proceeding” in its order, including the question whether “parties can bilaterally contract on FTR Center without any other express contractual agreement beyond what occurred on FTR Center.”

FERC GreenHat Case — Size and tenor of GreenHat’s portfolio (quarterly 2016-2018) | *PJM*

GreenHat stated that the commission’s description of the FTR Center as “merely a reporting mechanism that would require a separate agreement to establish payment obligations” could be interpreted as prohibiting the FTR Center from “serving as anything beyond a reporting mechanism.” The company requested that FERC clarify that it had “neither opined on state contract law nor restricted parties who enter prices into the FTR Center from being bound contractually pursuant to state contract law.”

The rehearing request was automatically denied when FERC did not act on it within 30 days. In Thursday’s ruling, the commission said it disagreed with GreenHat’s arguments that it “prejudged or interfered with the Texas state litigation,” and that it “appropriately interpreted the PJM tariff, a matter squarely within the commission’s jurisdiction.”

“The commission has long recognized that state courts have concurrent jurisdiction to consider contract interpretation issues,” FERC said.

The commission also reiterated its defense of FERC’s Office of Enforcement, which is investigating whether GreenHat violated the commission’s Anti-Manipulation Rule.

GreenHat alleged that one or more members of the office’s investigative team had met with Robert Anderson, an independent third-party expert retained by PJM’s board to prepare the Report of the Independent Consultants on the GreenHat Default. The company said that FERC officials had a draft copy of the report and asked Anderson to “alter or remove language in the draft favorable to GreenHat.” (See GreenHat Maneuvers to Remove FERC from Shell Case.)

In the November order, FERC said the Department of Energy’s Inspector General investigated the allegations and concluded there was “no merit.”

In its rehearing request, GreenHat argued that the commission denied the company due process in rejecting “without explanation,” its June motion to bar FERC enforcement staff from participating in Shell’s request for a declaratory order. GreenHat also petitioned the commission to disclose the findings in the Inspector General’s investigation, saying that the “fairness of this proceeding and the reasonableness of the commission’s denial of GreenHat’s motion to bar are in doubt as long as the commission has failed to disclose the scope of the Inspector General’s investigation.”

FERC said it “has long held that a declaratory order proceeding is not an adjudication subject to separation of functions. … The commission did not need to impose such protocols in this case because the instant proceeding concerns a dispute among the parties to this proceeding rather than between Enforcement Staff and any of the parties to this proceeding.”

The commission said the Inspector General labeled its report “Official Use Only” and did not authorize the commission to disclose its findings other than to say there was no merit to the allegations.

“It is consistent with the Administrative Procedure Act (APA) and the commission’s separation of functions regulations and policy for commission staff across offices to advise the commission,” the order said. “In any event, regardless of GreenHat’s allegations with respect to the Inspector General’s investigation and report, enforcement staff’s participation in this proceeding is proper under the commission’s regulations and the APA.”

April 18, 2021

Small Solar in Maine Struggling, Industry Says

Representatives of Maine’s solar industry say burdensome interconnection practices are threatening small-scale projects in the state.

Problems that large-scale solar developers are experiencing connecting projects to Maine’s grid recently triggered an investigation by regulators into Central Maine Power’s interconnection procedures. The same challenges, according to ReVision Energy co-founder Fortunat Mueller, are starting to affect smaller projects in Maine as well. (See Maine Regulators Probing CMP’s Interconnection Practices.)

A bill before the Joint Committee on Energy, Utilities and Technology (EUT) addresses those challenges directly (LD 1100). It would require the Maine Public Utilities Commission to adopt rules for interconnection of renewables that are based on “nationally recognized best practices” and ensure timely complaint resolution options that are not burdensome to small project owners.

In addition, the commission would have to contract an expert to evaluate near-term reforms for renewable energy interconnection standards, practices and procedures.

“Utility processes and [commission] processes are not set up for laypeople, and customers find it difficult to navigate those processes,” Mueller said at an EUT committee hearing on the bill April 13.

Solar Maine — Small-scale solar projects, like residential roof-top solar systems, are experiencing difficulties with interconnection to Maine’s grid, and industry members say the problems are discouraging development. | *Shutterstock*

Cost allocation is the most significant challenge small project owners are facing, Mueller said.

Under current Maine rules, a project that requests interconnection to a circuit that is at capacity incurs the entire cost to upgrade the capacity. If the project that triggers the upgrade is a residential solar array, the interconnection cost will be disproportionate to the project size.

“We’re increasingly seeing circuits or substations around Maine … where the capacity is fully reserved by projects in the interconnection queue,” Mueller said. “That means for whole towns and whole neighborhoods there is no longer an option for businesses or residential customers to go solar without being the triggering project.”

The bill would push the PUC to establish rules that are consistent with the intent of laws passed in 2019 to foster solar expansion in the state.

“The PUC would have to learn about best interconnection practices, and require faster, smarter interconnection application reviews and decisions by [investor-owned utilities],” Steven Weems, executive director of the Solar Energy Association of Maine, said in his testimony. “The resulting rules would ensure small projects are not ground up unnecessarily in the melee pertaining to grid limitations, the processes for examining larger projects and, especially, the eventual costs of upgrading the system.”

PUC Plans Rulemaking

Garrett Corbin, legislative liaison for the PUC, said the commission is already engaged in work that aligns with the bill’s requirements and “questions the necessity” of the legislation.

“We anticipate opening a rulemaking process regarding small generator interconnection procedures,” Corbin said. “The rulemaking will consider cost-allocation requirements with respect to interconnecting customers.”

In addition, the commission is contracting a consultant to support a review of the requirements for the grid to accommodate the future electric transition, Corbin said. The review will identify procedures that would allow transparency of interconnection screening and upgrades for small-scale generators.

April 16, 2021

Lawmakers Wave Through Texas PUC Appointees

Texas senators are wasting no time filling the Public Utility Commission’s vacancies.

On Tuesday, the lawmakers unanimously confirmed Will McAdams by a 31-0 vote. McAdams, a Senate legislative aide for 10 years, was appointed by Gov. Greg Abbott April 1. (See Abbott Taps ABC Texas President McAdams for PUC Seat.)

Thursday morning, the Senate Committee on Nominations asked few questions of Peter Lake, chair of the Texas Water Development Board, who was appointed PUC chair on Monday. Nominations Chair Dawn Buckingham (R) said the panel plans to vote Lake out of the committee on Monday, setting up a confirmation vote before the full Senate.

That would give the commission two members, with a third and final member yet to be named. All three previous regulators resigned in the aftermath of the February winter storms and ensuing long-term blackouts.

Arthur D’Andrea continues to hold the PUC’s chairmanship, which he assumed after former Chair DeAnn Walker’s resignation. D’Andrea resigned in March, shortly after the leak of a phone call in which he told Wall Street investors he was using “the weight of the commission” to avoid repricing $16 billion in D’Andrea Resigns from Texas Commission.)

Texas PUC Appointees — PUC appointee Peter Lake answers questions before the Senate Nominations Committee. | Texas SenateWill McAdams (Will McAdams via LinkedIn)

Lake told the nominations panel that February’s events were “beyond unacceptable” and that there won’t be “any easy answers or quick fixes.”

“This [position] will require very hard decisions to be made,” he said. “If confirmed, I will find out what went wrong, why it went wrong, and how to fix it. We cannot be hampered by institutional inertia or antiquated mindsets. My focus will be to provide the information you all need to craft policy and will work to implement that policy efficiently and effectively.”

McAdams and Lake must both undergo PUC training before they can begin to serve, the commission said.

A meeting scheduled for April 22 was cancelled to allow new commissioners time to get up to speed. The PUC’s next open meeting is scheduled for May 6.

McAdams’ term expires Sept. 1, 2025 and Lake’s on Sept. 1, 2023.

April 16, 2021

CPUC Applies Stricter Oversight to PG&E

The California Public Utilities Commission used its new enhanced oversight and enforcement powers for the first time Thursday against Pacific Gas and Electric, citing the utility’s failure to adequately weigh wildfire risks in maintaining its power lines.

Commissioners voted to put PG&E into the first step of a six-step enforcement process that could lead to the utility being placed into receivership or, ultimately, to the revocation of its license to operate as the state’s largest monopoly utility.

“We’ve never had a process like this for any other utility, and I don’t know of any other PUC in the country that has a process like this,” Commissioner Clifford Rechtschaffen said. “Now we shouldn’t congratulate ourselves with that. It’s a process that’s warranted given PG&E’s conduct.”

The draft resolution, approved unanimously Thursday, says PG&E “is not sufficiently prioritizing its enhanced vegetation (EVM) management based on risk.”

“PG&E ranks its power line circuits by wildfire risk, but the work performed in 2020 demonstrates that PG&E is not making risk-driven investments. PG&E is not doing the majority of EVM work — or even a significant portion of work — on the highest risk lines,” it said. “PG&E conducted more work in 2020 on lower risk power lines than high risk lines if one examines the 161 power lines on which PG&E performed EVM. Less than 5% of the EVM work PG&E completed was on the 20 highest risk power lines according to PG&E’s own risk rankings.”

PG&E oversight — The CPUC’s five commissioners heard from Executive Director Rachel Peterson (bottom center) on the proposed action against PG&E. | *CPUC*

PG&E agreed to the CPUC’s six-step process as part of its exit from bankruptcy in June 2020. The enhanced oversight and enforcement process was later enacted into law under a bill signed by Gov. Gavin Newsom in July. Senate Bill 350 also authorized the state to seize PG&E through eminent domain, if warranted, and transfer its operations and assets to a nonprofit public benefit corporation. (See Governor Signs PG&E ‘Plan B’ Takeover Bill.)

In November, CPUC President Marybel Batjer wrote to then-acting CEO William Smith saying the commission was considering putting PG&E into the stricter oversight regime because of the utility’s vegetation and line maintenance. (See PG&E Faces ‘Enhanced Oversight’ by CPUC.)

The warning turned to action Thursday.

Step one of the process requires PG&E to submit a corrective plan to CPUC Executive Director Rachel Peterson within 20 days. The plan must describe how the company proposes to mitigate the safety risks that triggered the enhanced oversight process. If PG&E fails to adhere to the plan, the CPUC can move to the second step of its enforcement process, which may include activities such as increased inspections, quarterly reports and spot auditing of the utility’s fire-prevention efforts.

Federal Judge William Alsup, who oversees PG&E’s criminal probation stemming from the 2010 San Bruno gas explosion, has expressed similar concerns about vegetation management and is weighing new probation conditions that could require PG&E to de-energize lines during high-risk fire conditions that have not been cleared of overhanging trees. (See Conflict over Power Shutoffs Grows in California.)

In September, a leaning pine tree struck a PG&E transmission line in rural Shasta County and started the Zogg Fire, which killed four residents and burned 56,000 acres, the California Department of Forestry and Fire Protection determined.

The state’s largest utility was also blamed for catastrophic wildfires from 2017 to 2019, caused by its equipment contacting vegetation. The blazes included the Camp Fire in November 2018, which killed 85 people and destroyed more than 14,000 homes in the town of Paradise. PG&E pleaded guilty to 84 counts of manslaughter and arson in that case.

April 16, 2021

CEC Funds Cutting Edge Load Flexibility Project

The California Energy Commission on Wednesday took a step toward making millions of households part of demand response efforts designed to avoid blackouts and bolster the state’s clean-energy goals.

The CEC approved a $16 million grant to the Lawrence Berkeley National Laboratory to establish the California Flexible Load Research and Deployment Hub, nicknamed CalFlexHub. Its four-year mission is to “develop, demonstrate and deploy multiple demand flexible technologies as electric grid resources,” making the technology more user-friendly and available to average homeowners, the CEC said.

“I’m really pleased to support this,” CEC Chair David Hochschild said. “I think that for a long time, electric load, with the exception of a few industrial demand response programs, was just seen as a fixed, rigid thing that we had to ramp up generation to support. I think a more involved understanding of the realities [shows that] there’s a lot about electric load that can be manipulated in ways that support electric reliability and our climate goals, as well.”

“We’re just getting going on this,” he said. “It’s still really early days.”

California demand response — Lawrence Berkeley National Laboratory will develop the California Flexible Load Research and Deployment Hub. | *Roy Kaltschmidt, Berkeley Lab Public Affairs*

The CEC’s plan involves making it easier for homeowners to connect smart appliances — thermostats, heat pumps and water heaters — to the grid to receive signals to curtail consumption in response to high demand, high prices and elevated greenhouse gas emissions. Electric vehicle charging is another target. (See CEC Explores Building Design Role in Decarbonization.)

Under the terms of Senate Bill 100, signed by Gov. Jerry Brown in 2018, the state must supply all retail customers with clean energy by 2045. The result is expected to be a huge increase in solar and wind generation and a decrease in natural gas-fired capacity. Demand response should also play a significant role, the CEC, CAISO and the California Public Utilities Commission have said.

In last summer’s energy emergencies, CAISO and the office of Gov. Gavin Newsom called on industrial users and the U.S. Navy to limit usage during the evening net-peak hours, when solar ramped down but demand remained high because of severe Western heat waves. The efforts limited the blackouts of Aug. 14-15 and avoided additional outages over Labor Day weekend, CAISO said. (See CAISO Provides More Details on Blackouts.)

In recent years, researchers at Lawrence Berkeley National Laboratory have been studying the role that flexible load and demand response could play in ensuring grid stability as the nation transitions to renewable resources.

Mary Ann Piette, a senior scientist and director of the Building Technology and Urban Systems Division at Lawrence Berkeley, told the CEC commissioners that CalFlexHub “will help accelerate the development and deployment of technology … to allow buildings to be better integrated with the electric system for … demand management, dealing with renewable overgeneration, ramping and peak demand issues.”

CEC Commissioner Andrew McAllister said Wednesday that California’s efforts would help “create a new regime” nationally.

A 2019 study by the Brattle Group concluded that by 2030, the U.S. would have up to 200 GW of “cost-effective load flexibility potential.”

“This load flexibility potential, which equates to 20% of estimated U.S. peak load in 2030, would more than triple the existing demand response capability and would be worth more than $15 billion annually in avoided system costs,” Brattle said.

McAllister agreed. “I think the rest of the country is waking up to this fact that grid-connected buildings” and load flexibility will help reduce costs, decarbonize and enhance reliability, he said. “That triumvirate of goals is something that is absolutely in line with load flexibility. We’re going to create a significant body of work over the coming years on this and make it practically applicable in the real world, for real people, to benefit Californians.”

“This is a part of our future,” McAllister said. The electricity grid is “a network, not a one-direction system anymore. It’s a web.”