Responsibly sourced natural gas (RSG) is now a “sizeable” and “growing” market, according to Andrew Swinick, commercial director at Kinder Morgan (NYSE:KMI).
The market is “driven by voluntary efforts to do better when it comes to our business practices,” he said Tuesday at the Northeast Gas Association’s Regional Market Trends Forum. “In 2018, we had only five companies that had committed volumes to RSG, and today we’re looking at 28.”
RSG, also called producer-certified gas, is a third-party-certified product based on a supplier’s ability to demonstrate it has reduced environmental impacts from its product and operates under best practices of environmental, social and governance (ESG) criteria.
“Right now, the goal of RSG is to minimize emissions along the natural gas value chain and to continuously look at ways to reduce those emissions levels,” he said. More suppliers are turning to RSG in response to end-user demand that Swinick says “is growing radically and dramatically.”
The three major certifying entities in operation currently are the nonprofits Equitable Origin and MiQ, and TrustWell by data analytics company Project Canary.
Certification is based on an ISO-like framework that “provides verification of responsible practices through rigorous independent audits, like emission reductions, no flaring and methane monitoring,” said Jeff Formica, vice president of environmental, safety, health and quality at Seneca Resources.
Seneca achieved Equitable Origin certification for 100% of its Appalachian assets in December 2021, according to Formica. The facility-level certification, he said, ensures that companies are always working to improve their ESG practices.
MiQ, which is also a facility-level certification, targets methane-intensity reduction by understanding how much methane a producer’s facilities emit versus the amount of natural gas they produce. It also ensures certified entities have comprehensive monitoring technologies in place to detect unintended emissions, Formica said.
The TrustWell certification works at the level of the gas well to reduce greenhouse gas emissions, set responsible water stewardship plans, mitigate operational risks and understand community needs, he said.
Growth Opportunity
Kinder Morgan, the largest U.S. gas pipeline company, could receive approval from FERC in the coming weeks for a new market mechanism that would support expansion of RSG.
The company filed a tariff, via its Tennessee Gas subsidiary, with FERC in December that would allow it to secure contracts specific to transporting RSG on its pipelines (RP22-417-001). Suppliers would need to demonstrate that they meet a predetermined, methane-intensity level certified by TrustWell to qualify for the tariff.
If FERC allows the company to move ahead with the new service, it would “encourage the transportation and trading on the Tennessee system of RSG supply from producers,” Kinder Morgan said in its tariff filing.
The company’s customers have shown broad support for the concept, according to Swinick, who said that Kinder Morgan expects to see an order from FERC in the coming weeks allowing service to begin May 1.
Producers see the offering as an “attractive” option, he said.
The Environmental Defense Fund asked FERC to “carefully consider” the program in a Jan. 24 filing and called for a technical conference.
“As the first request for FERC approval of an RSG-type program, Tennessee’s filing has the potential to create a significant precedent for the pipeline industry more broadly,” EDF said.
Consolidated Edison (NYSE:ED) commended Kinder Morgan in a Feb. 22 filing for taking a step that it said will allow customers to procure RSG, and the utility encouraged other interstate pipelines to provide a similar option.
The service will “aid natural gas distribution companies … in their efforts to reduce upstream greenhouse gas emissions associated with production or gathering of natural gas,” Con Ed said.
PJM detailed changes in a proposal to update the process timing for generation deactivations at last week’s Markets and Reliability Committee meeting after some stakeholders previously requested that the RTO slightly modify the language.
David Egan, manager of PJM’s system planning modeling and support department, reviewed the proposal, presenting the revisions to Manual 14D and the tariffin a first read at the MRC. Stakeholders previously gave near unanimous support of the issue charge at the March 8 Planning Committee meeting. (See “Deactivation Process Timing Update Endorsed,” PJM PC/TEAC Briefs: March 8, 2022.)
Egan said current language in the tariff provides 90 days advance notice and 30 days to complete deactivation studies, which is causing “insufficient and unsustainable” time for PJM staff to determine adverse impacts on reliability if more than one deactivation notice is made in a single study period. Industry trends and state energy policies are increasing the number of deactivation notices, Egan said, putting even more pressure on staff to finish studies in a timely manner.
“Thirty days to perform what is the equivalent in the interconnection process of a system impact study leads to overly conservative assumptions, which generally lead to inaccurate results,” Egan said.
The issue charge calls for changes to the tariff and manual to “provide more time to complete analyses, allow additional and improved studies, and provide the ability for more efficient work control and consistency regarding timing of deactivation studies,” Egan said.
The proposed deactivation process establishes quarterly study times for requests, with periods beginning Jan. 1, April 1, July 1 and Oct. 1. PJM staff would study deactivations “holistically” as a batch, Egan said, providing more accurate study results for impacts on the system.
The quarterly schedule would allow enough time for additional required seasonal, interim year and short-circuit analyses, scheduling upgrades, and cost estimates, Egan said, and for PJM operations to identify additional needed operational measures.
A series of 11 deactivation requests in July of 2021 prompted PJM to seek solutions to the review schedule for the RTO’s staff. | PJM
Egan said PJM is a “significant outlier” compared to other RTOs and ISOs in the deactivation process. MISO requires advance notice of 26 weeks for a deactivation, and the studies include 75 days to identify issues and 26 weeks to complete the deactivation study. NYISO requires advance notice of 365 days for deactivation, and studies are conducted in the subsequent quarter.
PJM granted a stakeholder request to insert tariff language that doesn’t constrain a generator to a specific time frame for deactivation and to create exemptions if a unit is forced to deactivate through state legislation or actions by the federal government.
Jason Barker of Constellation Energy asked how a generator that experiences a catastrophic failure will be studied or considered by PJM. He requested that PJM provide an opportunity for an expedited review so that owners don’t undertake carrying costs for waiting to decommission a unit that is “clearly not going to be operating any longer.”
Egan said the impact from a unit that has a catastrophic failure “doesn’t really change anything” because it will still have market obligations and have to look for alternative sources to fulfill the obligations.
“This whole process requires coordination with both transmission owners and generation owners to make sure we are able to mitigate problems on the system,” Egan said.
PJM will move conforming Manual 14D language through the Operating Committee and the Systems Operation Subcommittee if stakeholders endorse the proposal at the April 27 MRC meeting and the final tariff language endorsement at the May 17 Members Committee meeting.
Dave Anders, director of stakeholder affairs for PJM, reviewed a proposed issue charge from the Resource Adequacy Senior Task Force (RASTF) addressing the procurement of clean resource attributes and the creation of a new senior task force.
Anders said the first key work activity in the RASTF’s own issue charge was to determine whether the “forward procurement of clean resource attributes” should be pursued by stakeholders and to examine the inclusion of the social cost of carbon in PJM markets.
After discussions in the task force over the last few months, Anders said, stakeholders recommended a new issue charge for continued discussions and the development of potential market rules to implement the “preferred” design for clean resource procurement. Anders said 70% of RASTF members endorsed pursuing a new issue charge.
Anders said the new issue charge calls for a “comprehensive discussion of market enhancements” that would enable states and other buyers to procure clean resource attributes “on a voluntary basis, through a regional and centralized procurement or market.”
Walter Graf, PJM | FERC
Walter Graf, PJM’s senior director of economics and market services, provided details about the issue charge. Graf said stakeholders expressed interest in having a forum for a “comprehensive discussion on enhancements to the PJM markets.”
Work would start with education on the procurement of clean resource attributes, including defining clean resource attributes across jurisdictions, markets and procurement mechanisms. The second step calls for discussing the objectives of a market construct to enable voluntary procurement of clean resource attributes.
Graf said PJM and stakeholders will determine an approach to conduct analysis and select one or more market design solutions for further development.
The expected deliverables in the issue charge include the education and analysis identified in the scope of work and any proposed market rules to implement the preferred design if one is found.
Discussions would take place in a new Clean Attribute Procurement Senior Task Force reporting to the MRC, and work would continue through the second quarter of 2023.
Denise Foster Cronin of East Kentucky Power Cooperative asked if PJM anticipates moving forward with some type of market change even if the analysis resulting from the new task force doesn’t fully satisfy stakeholders.
Graf said PJM is initiating the conversation “with the hope that we would get something useful out of it.” He said PJM is looking to come to a consensus or compromise on the issue, but endorsing a solution is not necessary.
The committee will be asked to approve the recommendation at its April meeting.
CCSTF Sunset Endorsed
Members unanimously endorsed the sunset of the Capacity Capability Senior Task Force (CCSTF), bringing the work of the group to a close after nearly two years of discussions.
Melissa Pilong of PJM reviewed the sunset proposal and also presented the final report of the work completed by the task force. The CCSTF was originally created in March 2020 to consider using effective load-carrying capability (ELCC) to set the capacity value of limited-duration resources such as battery storage.
Stakeholders endorsed a joint proposal in September 2020 to use the ELCC method to calculate the capacity value of limited-duration, intermittent and combination (limited-duration plus intermittent) resources. FERC approved PJM’s proposal in August. (See FERC Accepts PJM ELCC Tariff Revisions.)
Pilong said work originally endorsed by stakeholders for a second phase of discussions at the CCSTF was moved to the RASTF. The additional work includes a discussion of other rules or rule changes that may be necessary for limited-duration resources to participate in energy and ancillary service markets.
Calpine’s David “Scarp” Scarpignato asked if work by stakeholders to examine using ELCC for all resources and evaluate its usefulness should be done at the CCSTF in the future rather than the RASTF because of the amount of detail needed to be discussed on the issue.
“It’s a ton of work, and I think it would take awhile to do,” Scarp said.
Anders said two different key work activities in the RASTF issue charge relate to the ELCC issue, including activities dealing with the risks and drivers and their relationship to accreditation of resources.
“There would be no reason to keep this CCSTF open to deal with that issue,” Anders said.
Max Emergency Changes Endorsed
Stakeholders unanimously endorsed PJM’s proposal to extend a temporary change to the maximum emergency status for gas combustion turbines and steam generators and an issue charge to look at a long-term solution.
Chris Pilong, of PJM’s operations planning department, reviewed the revisions to Manual 13: Emergency Operations in a problem statement and issue charge. Pilong said PJM made a temporary change to section 6.4 of Manual 13 in a “note” to modify the remaining hours under which a resource may be offered as maximum emergency generation to address recent concerns with fuel security and new emission standards in states.
The changes, which were endorsed in October, said PJM may request a generation owner to move steam units, which are mostly coal-fired, into the maximum emergency category if their remaining run time falls below 240 hours, or 10 days. The units could be restricted from operating during that time unless required to meet reliability needs for the grid. (See Global Fuel Supply Prompts PJM Manual Changes.)
Pilong said units could remain in maximum emergency status until their fuel inventory rose above 21 days, or 504 hours, and the designation would only be implemented to address concerns with local or regional reliability resulting from fuel supply shortages. The previous run-hour threshold for a maximum emergency was 32 hours.
Pilong said the manual change was set to expire April 1, but it needed to be extended to give PJM and stakeholders more time to work on a permanent solution.
The work on the long-term solution was requested to take place under a new problem statement and issue charge titled “Max Emergency Changes for Resource Limitations,” which stakeholders unanimously endorsed at the MRC.
The issue charge calls for reviewing and modifying existing rules in response to concerns with the fuel and non-fuel supply chain, as well as the increasing environmental restrictions on generators that are creating challenges with managing run hours. Pilong said key work activities include examining the hours remaining at which max emergency can be used on a unit, along with the procedures and communications associated with a max emergency event.
The expected deliverables include education on unit eligibility and the opportunity cost calculator, as well as potential revisions to Manual 13 and “enhancements” to existing processes.
Pilong said PJM wants to spend four months working on the issue in the Operating Committee and have a solution before the summer 2022 peak period.
Combined Cycle Minimum Run Time Guidance Endorsed
Members unanimously endorsed a proposal and manual revisions that have been discussed for several months in committees to address pseudo-modeled combined cycle minimum run time guidance.
Hauske said market sellers can model a combined cycle generation unit as multiple “pseudo units” that are made up of a single combustion turbine and a portion of a steam turbine. But he said the potential exists for one or more of the pseudo-modeled units to operate for a period beyond the minimum run time parameter limit compared to an identical non-pseudo-modeled combined cycle unit if the market units of a pseudo-modeled combined cycle unit are dispatched at different times because the steam turbine takes extra time to reach operative levels.
Hauske said the proposed solution calls for adding language to Manual 11 to require market sellers to update the minimum run time of any subsequent pseudo-modeled unit to remove the associated steam turbine start-up time included in the parameter limit when it’s dispatched.
PJM wanted to have the final endorsement in place at the March MRC meeting because the RTO’s unit-specific parameter adjustment process started earlier this month, and determinations on requests must be made by April 15.
Consent Agenda
Stakeholders unanimously endorsed four manual revisions as part of the MRC consent agenda. They included:
revisions to Manual 12: Balancing Operations resulting from a periodic review. The changes include attachment references and other minor revisions.
revisions to Manual 13: Emergency Operations resulting from a periodic review. The changes include new columns with winter values for estimated peak load and estimated load reduction in the voltage reduction summary table.
revisions to Manual 18: PJM Capacity Market to conform with several recent FERC orders, including those on the minimum offer price rule, the market seller offer cap and the removal of the 10% cost adder for the reference resource used to establish the variable resource requirement curve.
revisions to Manual 37: Reliability Coordination resulting from a periodic review. The language would properly label Silver Run Electric as a transmission owner in Attachment A of the manual.
Members Committee
Remote Voting for Annual Meeting
PJM wants to revise Manual 34 before the Annual Meeting on May 17, which includes the Board of Managers election and General Session, to allow for remote voting.
Michele Greening, manager of PJM’s stakeholder process and engagement department, reviewed proposed revisions to Manual 34: Stakeholder Process to update the ballot process during the Annual Meeting at last week’s Members Committee meeting.
Greening said Manual 34 includes language requiring written paper ballots for the elections of board members and the Members Committee vice chair. She said as the current remote meeting format has gone on for more than two years as a result of COVID-19 protocols, PJM identified the need to “exercise flexibility” to conduct the 2020 and 2021 board elections using an alternative to written paper ballots.
The 2020 board election was done remotely through the PJM Voting Application with special auditing provisions to “ensure ballot confidentiality,” Greening said, and the 2021 board election was conducted through a secure, third-party online election service, Survey & Ballot Systems.
Greening said PJM wants to continue to use a secure third-party voting system for stakeholders not attending the Annual Meeting in person. To make the change permanent, PJM is proposing to modify the current Manual 34 provisions requiring a written paper ballot by striking the language.
The committee will be asked to approve the proposed Manual 34 revisions at the April MC meeting.
President Joe Biden’s $5.8 trillion federal budget request for 2023 contains a raft of line items aimed at cutting greenhouse gas emissions, advancing clean energy research and deployments, and propping up the nation’s energy security.
The budget rollout on Monday included announcements from the Department of Energy, the Environmental Protection Agency and the Bureau of Ocean Energy Management detailing the federal dollars for energy and climate projects that are included in their budget requests.
The tax credits and other incentives for clean energy development contained in the failed Build Back Better Bill are not specifically listed in the budget, but, according to a report from Bloomberg, will be included in a placeholder “deficit-neutral reserve fund.”
DOE
The DOE announced a $48.2 billion budget request for 2023 — a $2 billion increase over the $46.2 billion requested in 2022 — with significant clean energy investments but a strong focus on national security. Specifically, close to half of the 2023 budget, $21.4 billion, is earmarked for the National Nuclear Security Administration “to make necessary investments to maintain a safe, secure and effective nuclear weapons stockpile,” according to the DOE’s announcement.
The department is also asking for $202 million for the Office of Cybersecurity, Energy Security and Emergency Response to address cybersecurity risks.
On the energy side, the request focuses heavily on energy efficiency and clean energy research and development. “The investments reflected in this latest budget will cut costs for Americans and secure our energy independence on our path towards a net-zero future,” Energy Secretary Jennifer Granholm said in the announcement.
The budget request includes the following clean energy spending:
$502 million to weatherize at least 50,000 homes, including $100 million to retrofit and decarbonize low-income households, installing energy-efficient appliances and systems to cut energy bills. Another $105 million in grants will go to states to help them create “more reliable and affordable clean energy systems.”
$200 million “to bolster the U.S. supply chain for solar energy technologies through a new Solar Manufacturing Accelerator.” Another $18 million will go toward building international partnerships to “bolster secure supply chains and expand economic opportunities.”
Other supply chain spending includes $5 billion for the Loan Programs Office for investments that will support domestic supply chains for critical minerals.
$4 billion “to accelerate research, development, demonstration and deployment of technology and solutions to cut energy costs through low-cost clean energy resources.”
Another $7.8 billion is slated to support research at the DOE’s national labs and at universities across the country “to accelerate novel technologies for clean energy solutions to mitigate climate change.”
EPA
EPA Administrator Michael Regan said the budget includes “historic investments” in support of the agency’s FY 2022-2026 Strategic Plan, “including tackling the climate crisis, advancing environmental justice, protecting air quality, upgrading the nation’s aging water infrastructure and rebuilding core functions at the agency.”
“For the first time, EPA’s final [Strategic] Plan includes a strategic goal focused exclusively on addressing climate change, as well as an unprecedented strategic goal to advance environmental justice and civil rights,” EPA said. “At the foundation of the plan is a renewed commitment to the three principles articulated by EPA’s first Administrator, William Ruckelshaus — follow the science, follow the law, and be transparent – while adding an additional fourth principle: advance justice and equity.”
In addition to $4 billion to upgrade drinking water and wastewater infrastructure, the plan includes:
$1.1 billion to improve air quality, reduce localized pollution and exposure to radiation, and improve indoor air quality;
$100 million in grants to tribes and states to support greenhouse gas reductions and increased resilience;
$35 million to implement the American Innovation in Manufacturing Act to phase out hydrofluorocarbons, a greenhouse gas; and
$13 million in wildfire prevention and readiness.
In support of Biden’s Justice40 commitment to ensure at least 40% of federal investments in climate and clean energy benefit historically overburdened and underserved communities, EPA would spend $1.45 billion to “create good-paying jobs, clean up pollution, advance racial equity and secure environmental justice,” Regan said. EPA has proposed creation of an environmental justice program office to oversee the effort.
To “rebuild the agency’s capacity” following cuts under the Trump administration, the spending plan would also fund more than 1,900 new full-time equivalents, boosting EPA’s staffing to more than 16,200 FTEs.
BOEM
The Interior Department’s Bureau of Ocean Energy Management would receive $237.4 million in funding, including $51.7 million for BOEM’s renewable energy program, which is supporting the administration’s goal of deploying 30 GW of offshore wind energy capacity by 2030.
BOEM’s conventional energy program, supporting oil and gas leasing, would receive $63.6 million, while its marine minerals program would get $15.4 million to help procure sand and sediment for coastal restoration.
The budget includes $86.4 million to fund BOEM’s environmental analyses.
BOEM plans to issue nine environmental reviews of offshore wind projects in FY 2023 and to hold up to three lease sales in FY 2022 and up to two lease sales in FY 2023.
FERC on Thursday accepted Kestrel Acquisition’s updated market power analysis as partially compliant with the commission’s standards for market-based rate authority (MBRA), and directed the PJM generation owner to submit a further compliance filing within 30 days (ER18-1106-002).
In doing so, FERC rejected a protest by PJM’s Independent Market Monitor, which said that “current PJM market rules for market power mitigation are insufficient to support [market-based rate] authorizations.”
The commission said the Monitor failed “to submit any specific evidence … demonstrating that Kestrel Acquisition has market power.” Rather, the Monitor’s protest was directed at PJM’s rules and not Kestrel’s analysis itself.
“In granting market-based rate authority, the commission does not certify markets as competitive; it determines whether individual sellers have market power,” FERC said. “Here, IMM makes no attempt to show that PJM’s monitoring and existing market power mitigation provisions would fail to mitigate any market power possessed by Kestrel Acquisition.”
The Monitor argued that Kestrel’s MBRA should be conditioned on offering into the energy and capacity markets at cost-based offers. But FERC said that “many of the allegations in IMM’s protest apply to all sellers in PJM, including those that are not part of the protested proceedings. Such sellers have not been given adequate notice and opportunity to comment on IMM’s proposal.”
FERC noted that the Monitor’s criticism of PJM’s capacity market echo those made in a separate complaint, in which the commission approved its proposal to conduct a unit-specific review of all offers in the capacity market. It is also conducting a review the RTO’s rules on parameter-limited offers. “We believe that proceeding, which will provide all sellers in PJM the opportunity to intervene and participate, is the appropriate forum to consider changes to the relevant PJM mitigation rules,” it said.
Kestrel owns the 810-MW Hunterstown Generating Station combined cycle gas-fired power plant located in Gettysburg, Pa.
Commissioner James Danly concurred in a separate statement to highlight that the Monitor’s “concerns in this case would properly be rejected even if the commission had not recently ordered PJM to adopt” the Monitor’s unit-specific proposal.
“I opposed unit-specific review of all offers because doing so likely will result in over-mitigation,” Danly said. “Unit-specific review is not required to adequately mitigate market power concerns, and today’s order in no way indicates otherwise.”
Leaders of an SPP task force charged with designing and developing a consolidated transmission planning process and associated cost-sharing mechanism said last week they will wait until the generator interconnection queue’s backlog has been cleared before building the models for the process.
Staff told the Seams Advisory Group Wednesday that they expect it will take two years to get consolidated planning processes approved, with the first study being produced in 2026 at the earliest.
“We want to get queue clear before beginning the consolidated process,” SPP’s Kelsey Allen said. “It’s very hard to coordinate across the various study processes.”
The RTO’s queue backlog dates to 2017 and includes nearly 100 GW of IC requests, as of November. Renewables and storage account for all the potential projects, with a bit more than 6 GW of thermal requests. FERC in January approved SPP’s plan to clean up the backlog by 2024. (See “GI Backlog Plan Approved,” FERC Denies Co-ops’ $79M Complaint vs. SPP.)
The Consolidated Planning Process Task Force, created last year by the SPP board, has held a couple of education sessions and laid out a high-level work plan, said SPP’s Sunny Raheem, who is chairing the task force. Over the next few years, he said, the group plans to write as many policies as it can and build out technical requirements.
The task force will coordinate with and gather input from affected stakeholder groups in proposing methodologies, approaches, assumptions, parameters, criteria, data requirements and/or outcomes for successful consolidated planning design, implementation and approval.
“Sounds like job security to me,” joked American Electric Power’s Jim Jacoby, the SAG’s chair.
The meeting was the first in-person stakeholder meeting at SPP’s corporate campus in Little Rock, Ark., since the onset of the pandemic.
SPP, MISO to Set Joint Stakeholder Meetings
SPP and MISO staff are planning a series of stakeholder meetings over the next four to six months as they work on a cost-allocation methodology for their joint targeted interconnection queue (JTIQ) study.
The final study report is comprised of seven projects at a total cost of about $1.65 billion. If approved, the projects are projected to resolve 48 reliability constraints and deliver about $724 million in adjusted production costs savings to MISO and $247 million to SPP. (See MISO, SPP Finalize JTIQ Results with MISO Tx Duplicates.)
However, MISO has included two of those projects in its first tranche of long-range transmission projects, raising questions about how that affects the JTIQ’s portfolio.
“That’s one of the first things we have to work out in the upcoming stakeholder meetings,” SPP’s Neil Robertson said. “It does change the complexion of how cost allocation will be approached. …That was one of the primary objectives of [the JTIQ study].”
The stakeholder meetings are expected to be scheduled later this week.
SPP’s M2M Settlements Exceed $250M
SPP accrued almost $7.9 million in market-to-market (M2M) settlements from MISO during January, staff told the SAG, pushing the amount MISO owes its neighbor for congestion to nearly $255 million.
Permanent and temporary flowgates were binding for 1,812 hours during the month. The two grid operators exchange settlements for redispatch based on the non-monitoring RTO’s market flow in relation to firm-flow entitlements.
It was the 11th straight month M2M settlements have accrued in SPP’s favor, and the 26th time in the last 28 months. The grid operators began the process in March 2015.
The two California state entities that oversee investor-owned utility wildfire prevention programs need to exercise their authority more effectively to limit ignitions and public safety power shutoffs, the State Auditor said in a report published Thursday.
The California Public Utilities Commission and the recently formed Office of Energy Infrastructure Safety have fallen short in both regards, Acting State Auditor Michael Tilden said in his report to the state Legislature and Gov. Gavin Newsom.
The CPUC and Energy Safety Office share oversight of the wildfire prevention activities and performance of the state’s IOUs, including Pacific Gas and Electric, Southern California Edison and San Diego Gas & Electric.
The Energy Safety Office accepted utility wildfire mitigation plans despite serious deficiencies and did not ensure proposed improvements were in high-fire threat areas, Tilden wrote.
“The office approved plans despite some utilities’ failure to demonstrate that they are appropriately prioritizing their mitigation activities, and subsequent reviews have found that some utilities failed to focus their efforts in high fire-threat areas,” he said.
The CPUC, which audits utilities to determine if they comply with safety rules, “did not audit all utility service territories on a consistent basis, did not audit several areas that include high fire-threat areas, and has not used its authority to penalize utilities when its audits uncover violations,” he said.
Six of the state’s 20 most catastrophic fires since 2015 were started by utility equipment, Tilden noted. To prevent ignition, IOUs initiated 67 shutoffs from 2013 to 2021, affecting 3.6 million customers, he said.
Utilities have been making improvements, including undergrounding power lines and replacing bare wires with covered conductor, but they have hardened only about 1,500 miles of the estimated 40,000 miles of bare lines in high-threat fire areas, Tilden noted.
“As a result, the state must prioritize the areas utilities need to address first,” he wrote.
Among his recommendations is bolstering a state law that took effect in January requiring utilities to identify line sections that are regularly de-energized to prevent ignitions during dry windy conditions.
“The state could strengthen this law by requiring utilities to identify what is necessary to prevent future power shutoffs if the conditions leading to those shutoffs were to occur again, and to address a type of power outage caused by altering equipment settings [to trigger fast shutoffs] that led to more than 600 unplanned power outages in 2021,” he said.
The CPUC said in a statement that it is “committed to the continuous improvement of its operations. Accordingly, the CPUC will establish a plan and timelines toward implementing the recommendations identified in the California State Auditor’s report.”
Its detailed responses to the audit, along with the responses of the Energy Safety Office, are included with the report.
The commission agreed, for example, that it needs to take a more risk-based approach to its utility audits but disagreed partly with a recommendation for penalizing underperforming utilities.
The Energy Safety Office defended its record, saying the complex process of promoting a safer grid would take time, but agreed that utilities need to “move faster and be smarter” in their fire prevention efforts.
“Utilities will not get ahead of their wildfire risk until they reimagine how they build, operate, and manage their infrastructure,” Director Caroline Thomas Jacobs wrote.
“Energy Safety is committed to driving timely, meaningful and effective changes to the way California’s electrical corporations build, operate and maintain their infrastructure,” she said. “Energy Safety will continue to challenge them, question them and demand continuous improvements to safety.”
FERC last week partially granted four cooperatives’ challenge of American Electric Power (NASDAQ:AEP) companies’ annual update for transmission formula rate charges under the SPP tariff (ER18-194).
The commission agreed with several of the co-ops’ complaints but also rejected others. It ordered AEP to make a compliance filing within 60 days.
The proceeding stems from a formal challenge by East Texas Electric Cooperative, Northeast Texas Electric Cooperative, Arkansas Electric Cooperative Corp. and Golden Spread Electric Cooperative of AEP’s annual informational filings in 2020 on behalf of its Southwestern Electric Power Co. and Public Service Company of Oklahoma (PSO) affiliates. The filing detailed the true-up calculations of charges for the 2019 rate year under the companies’ respective transmission formula rates.
In a settlement approved by FERC in 2019, the AEP rates transitioned from a historical formula rate to a forward-looking formula rate and removed directly assignable transmission costs related to generation.
The cooperatives claimed that in the new formula rates, AEP improperly:
included regulatory commission fees in one account;
accounted for capital lease interest expense;
included coal-mining assets;
included non-utility railcar facilities;
included prepayments for tax credits that were sold;
failed to include all unfunded reserves;
included accumulated deferred income taxes (ADIT) related to accumulated accruals recovered through rates without including the reserves; and
included ADIT related to rate refunds.
FERC disagreed with AEP’s argument that the co-ops’ challenge sought to undermine the settlement process by raising the same issues addressed through the settlement, saying the pertinent issue was whether AEP properly implemented the 2019 rate year formula. The commission agreed with the co-ops that the settlement did not bar future challenges to unfunded reserves and regulatory fees included in the 2019 rate year, finding that they were eligible for inclusion in the challenge, along with whether certain tax credits qualifying as prepayment.
The commission granted the challenge to the proper accounting of regulatory fees, finding they were not taxes. They directed AEP to include in its compliance filing the calculations reflecting the fees’ inclusion and to refund with interest the amounts improperly collected for the 2019 rate year.
FERC also accepted the challenges to capital lease interest expense, the ADIT related to the accumulated reserve accruals for employee benefit costs and the ADIT related to rate refunds.
The commission ordered AEP to refund with interest on all amounts improperly collected for the 2019 rate year and that the refunds be reflected as adjustments in the next rate year’s annual update. It said AEP had not justified why including the ADIT balance in the 2019 rate year’s rate base is appropriate given the ratemaking treatment of the associated accrued reserves. AEP also failed to address whether the ADIT related to rate refunds should be included in rate base when the underlying refund amounts associated with the ADIT are excluded from rate base, FERC said.
The commission, however, denied the challenge to the proper ratemaking treatment for the coal-mining assets and railcar facilities. It found AEP had properly recorded the tax credits at issue, and it also denied the challenge on unfunded reserves associated with contingent liabilities, saying the related employee benefit accounts, except for workers’ compensation, are not considered contingent because PSO knows that it will incur those expenses even if their timing is uncertain.
Washington Gov. Jay Inslee on Friday vetoed a section of a state energy siting council expansion bill that called for a study of the impacts of solar and wind farms on rural areas.
The veto drew criticism from two Republican representatives from rural Eastern Washington, where most of the state’s solar and wind farms have been located. A common complaint from critics of wind and solar farms is that wide-open rural Eastern Washington hosts most of the projects while the electricity produced there goes to heavily populated and forested Western Washington.
The Democrat-controlled legislature this month passed House Bill 1812, sponsored by Rep Joe Fitzgibbon (D), to take Washington’s Energy Facilities Site Evaluation Council (EFSEC) outside the umbrella of its parent, the Washington Utilities and Transportation Commission, and make it an independent agency. (See Bill to Expand Powers of Wash. Siting Council Passes Senate.)
EFSEC, comprising representatives from several state agencies, makes recommendations to the governor for final decisions on the placement of solar farms, wind turbines and other energy resources.
Under existing regulations, a wind or solar developer opting to seek state approval instead of obtaining county permits can bypass county governments by going through EFSEC. Or a developer can choose to have the appropriate county government handle the permitting, sidestepping EFSEC.
Besides being an option for wind and solar ventures, the expanded EFSEC will also have jurisdiction over clean energy product manufacturing facilities, renewable natural gas facilities and hydrogen production plants.
The vetoed section of the bill would have required the Washington Department of Commerce to meet with rural stakeholders to prepare cost-benefit reports on renewable projects, including recommendations on how to more equitably distribute costs and benefits of energy projects to rural communities.
In his Friday veto, Inslee wrote that meeting with rural stakeholders is important, but he said that existing studies and meetings are already underway on the issue, including a study on the drawing board by Washington State University. Inslee also wrote that the supplemental budget for fiscal 2023, which begins July 1, 2022, does not include money for the study requested by House Bill 1812. He wrote that the legislature should request such money in its 2023 session.
On Friday, Reps. Mary Dye (R) and Mark Klicker (R) issued a joint press release condemning the veto. “To say that we are beyond disappointed with the governor’s vetoes is an understatement,” Dye said.
“It is critical for our rural communities and local landowners, especially those in Eastern Washington, to see the big picture of what 30 years of siting utility-scale wind and solar would do to Washington’s rural landscape,” Dye said. “Now that the governor has vetoed these sections, it opens the flood gates for big out-of-state energy corporations to swoop into these small, rural economically-disadvantaged communities and offer leases at a fraction of the value of the agricultural land to struggling farmers and landowners. It’s absolutely devastating to our Eastern Washington farmlands.”
“Those who are living where the green energy is being sited know that the jobs and tax-base impacts have been more salesmanship than substance,” Klicker said. “We asked for a study to show the true costs and benefits, and the governor’s vetoes show we were right to be skeptical. If there was going to be good news about jobs and taxes from these projects, the governor surely would have wanted that documented.”
Dye added: “The governor’s strategy amounts to a hasty build-out of clean energy to serve the Puget Sound without any burden of siting massive wind farms in the Puget Sound view shed. Instead, these facilities will all be sited in our rural counties that have no need for the energy and are already served by clean, affordable hydroelectricity.”
The New England Electricity Restructuring Roundtable changed gears for its first meeting of the year Friday with a focus on equity.
The roundtable, convened quarterly by Raab Associates, featured discussions on equitably decarbonizing the Northeast, a federal energy update and a case study on a unique partnership north of the border.
How to Decarbonize
A panel of speakers from New England organizations examined greening the region’s energy while ensuring that vulnerable communities are not left behind.
“Whoever has benefited the most in the system as it is should bear the greatest burden as we transition to a new system, and whoever hasn’t received benefits from the system as it is should be at the front of the line,” said Rev. Mariama White-Hammond, chief of environment, energy and open space for the City of Boston.
The panelists tried to define equity, noting that it can have various meanings.
“Equity doesn’t mean equal or the same, and it doesn’t happen by accident,” President of the Northeast Clean Energy Council Joe Curtatone said. “We should all align to a value that leads us with deliberate intention to have impact, especially for those who are impacted the worst.”
Another key to reaching the necessary communities is to ensure funding is available, according to Stephan Roundtree, senior regional director at Vote Solar.
“Part of the challenge I’ve seen in my work is inviting or asking folks with barriers to entry to navigate the really complex world of rebates and program eligibility,” he said, adding that states have an increased responsibility to provide resources and connect people to those resources.
Panelists also addressed the challenge of specific technologies, such as offshore wind, which they said is a valuable decarbonization tool that comes with unique equity challenges.
A panel of speakers at the virtual Restructuring Roundtable on Friday discussing equitable decarbonization | Raab Associates
“It’s such an important and critical strategy to make a difference for the electricity sector,” said Staci Rubin, vice president for environmental justice at the Conservation Law Foundation.
Offshore wind developers and governments, she said, also need to involve people in the development process who are directly affected by the associated infrastructure.
“I’ve had recent conversations with several tribes who have really not been part of these conversations about offshore wind in a meaningful way,” she said. “We need to make sure that potentially impacted tribes and community organizations are able to have a say in terms of where the infrastructure will go.”
At the federal level, FERC is trying to make sure that it uses its regulatory powers in a way that meets equity goals, powered by the new Office of Public Participation, its director Elin Katz said.
“OPP is designed to provide opportunities for members of the public, and we have a particular focus on landowners, environmental justice communities, citizens of native nations, and consumer advocates and other community organizations,” she said, raising concern about how to bring those voices into FERC.
“We can’t continue to look at policy development as a top-down process that can fairly consider all sides and deliver equitable results if we don’t also include a diversity of voices in the process itself,” she said.
Case in Point
A powerful example of the way conversations around equity are changing came in the form of a case study on a unique agreement between Hydro-Quebec and the Mohawk Council of Kahnawà:ke.
The council is going to be a joint owner of a transmission line bringing energy from the company’s hydropower facilities in Quebec to New York City.
“In the past, there had been expropriations or land takings without consultation or compensation,” said Kahsennenhawe Sky-Deer, grand chief of the Kahnawà:ke Mohawk community.
The new joint agreement is different from what the community has seen in terms of land use, according to Sky-Deer.
“It’s groundbreaking and unprecedented, and something we welcome very much,” she said. “This is an untapped market in terms of partnership and recognition of Indigenous people.”
The partnership goes beyond a financial transaction and will involve jobs and training for Kahnawà:ke youth, Hydro-Quebec CEO Sophie Brochu said.
“We can be very viable business partners,” Sky-Deer said. “We do bring a different perspective and different energy to the table.”
Federal View
Patricia Hoffman, principal deputy assistant secretary for electricity at the Department of Energy, gave a rundown of new programs coming from the Infrastructure Investment and Jobs Act and called for coordination to speed decarbonization.
“Your priorities, the state, community and national priorities, are all critical as we work together to build a safe, reliable and resilient electric grid,” Hoffman said, adding that the infrastructure bill and associated investments are “a real opportunity to make a difference.”
Capitalizing on the investment opportunity that’s available will not be easy, she said. “We are all going to have to roll up our sleeves, but it is definitely worth the time and effort.”
FERC on Thursday upheld its denial of New York Transmission Owners’ (NYTOs) complaint that NYISO’s funding mechanism for transmission upgrades is unjust and unreasonable, refusing a rehearing of the order and rejecting a separate proposal to revise the methodology (EL21-66-001 and ER21-1647-002).
The commission reiterated its previous determinations, concluding that “petitioners’ repetition on rehearing of the evidence and arguments presented in their prior pleadings does not change our assessment.”
The NYTOs, which included all the investor-owned utilities in the state except PSEG Long Island, asserted that the existing funding mechanism does not allow them to recover a reasonable rate of return for the risks and costs of upgrades caused by generator interconnections.
They asked the commission to direct the ISO to amend its tariff to allow them to provide initial funding for such upgrades and charge the interconnection customer to recover a return on this cost.
But the commission said it continued to find its interpretation that costs are distinct from rate-structuring risks “to be appropriate, including the commission’s corollary finding that the regulatory, reliability, cybersecurity, environmental and operational risks that the NYTOs state they face in connection with owning, operating and maintaining system upgrades are not costs under this provision.”
FERC explained that the precedents cited by the NYTOs — Bluefield Water Works v. Public Service Commission, FPC v. Hope Natural Gas and Ameren Services v. FERC — do not require a change to NYISO’s existing funding mechanism and that the NYTOs had not presented sufficient evidence to show that the existing funding mechanism results in the them facing uncompensated risks and costs.
Neither do the other sections of the NYISO-TO Agreement cited by the NYTOs support their preferred reading, the commission said.
Moreover, in alleging that the complaint order was internally inconsistent and that the commission “clearly affirm[ed]” that risks are recovered through authorized returns yet denied recovery in costs because the risks were not costs, the NYTOs misunderstood the commission’s reasoning, FERC said.
“The fact that utilities incur costs to mitigate and manage their risk, and risks therefore increase costs for utilities, does not mean that risks are, themselves, costs. The costs utilities incur to manage and mitigate risks are borne as expenses, which are fundamentally different to the risks themselves,” the commission said.
Commissioner James Danly dissented from the order because the “commission exceeded its authority by impermissibly eliminating rights expressly reserved to the NYTOs … and by rejecting proposed changes to the funding mechanism that were consistent with those reserved rights.”
