Regulatory Updates

PJM Considers Enhancements to Capacity Market

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PJM Interconnection LLC (“PJM”) held a series of workshops in February and March 2021 to discuss possible enhancements to the PJM capacity market, including eliminating or reforming the current Minimum Offer Price Rule (“MOPR”).  PJM believes that MOPR reform needs to come first, before it can move onto considering other capacity market issues.  For MOPR reforms, PJM put forth four possible options, while noting that it is open to considering other proposals during the stakeholder process.  The first option is a transitional approach that maintains the current MOPR while attempting to accommodate state policy resources by reducing the clearing price to ensure total cost does not increase.  The second option is intent-based and would only apply MOPR when certain ex-ante screens are triggered.  The third option would create an explicit buyer side market power screen based on the contractual obligation of a supply resource and the impact to clearing price.  The fourth option would revert back to the pre-December 2019 version of the MOPR and potentially include portions of prior iterations.  In the final workshop, PJM also discussed the possibility of conducting an alternative stakeholder process for MOPR reform, in order to implement the reforms in time for the December 2021 Base Residual Auction.  

PJM’s presentation from the first workshop is available here.
Details from the second workshop, including stakeholder presentations, are available here.
Details from the third workshop, including stakeholder presentations, are available here.
PJM’s presentation from the fourth workshop is available here.

For further information, please contact Thomas Rudebusch, Bhaveeta Mody, or Ellen Hill.

President Biden Announces New Infrastructure Plan

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Photo by René DeAnda at

            On March 31, 2021, the President announced a $2.3 trillion dollar infrastructure plan, during a visit to Pittsburgh, Pennsylvania.  The plan includes a major investment in the expansion of the electric transmission grid, including the creation of the “Grid Deployment Authority” at the U.S. Department of Energy.  This $100 billion portion of the plan would include 20 Gigawatts of high-voltage transmission facilities, and would likely include use of the power marketing administration’s authority to construct and expand transmission.  The proposal includes a 10-year extension of tax credits for clean energy generation and storage.  A national broadband investment program would be created and would work to get 100% nationwide high-speed coverage, including rural and tribal areas.  The broadband proposal would specifically reduce barriers so that municipalities and rural electric cooperatives could actively participate in this plan. A $5 billion rural partnership program would be created, including tribes. $174 billion would also be dedicated to expansion of the electric vehicles market, including 500,000 charging stations, incentives for vehicle purchases, state and local funding and funding to convert diesel school bus fleets.  The plan would fund resilience of infrastructure, including the FEMA Building Resilient Infrastructure and Communities (BRIC) program, HUD Community Development Block Grants and new Department of Transportation initiatives.  Resilience programs would also include targeted work in the Great Lakes and for dam safety.  $56 billion would be targeted to states and tribes to support water and wastewater infrastructure.  The proposal also includes $115 billion for roads, bridges and highways, while also investing $85 billion in public transit. $213 billion would be invested to build and retrofit two million homes and businesses, including weatherization, neighborhood investments, tax credits and a new $27 billion Clean Energy and Sustainability Accelerator for private investments.  $100 billion would be provided for new public schools and funds to upgrade VA facilities and federal buildings.  $180 billion would be targeted for R&D investment, including $15 billion for demonstrations of carbon capture utilization and sequestration, energy storage, hydrogen, nuclear, wind, solar and EVs. 

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DOE to Host Webinars on Wildfire Risk to Electric Infrastructure

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From April 8 through 29, the U.S. Department of Energy (“DOE”) and the National Laboratories will hold webinars concerning the risk of the nation’s electrical infrastructure due to wildfires.  As has been seen, climate change and aging infrastructure have been among causes of wildfire ignition throughout the country, seen dramatically in recent years in the West.  States have authorized power shutoffs in anticipation of high risk weather events, such as wind storms, which may contribute to electrical equipment igniting wildfires. 

DWGP has been tracking and advising utilities on wildfire issues, including the wildfire mitigation plan efforts in California and resiliency efforts such as the California Public Utilities Commission’s emergency preparedness initiative. 

The DOE webinars will discuss not only prevention of wildfires due to ignition by utility equipment, but also protection of utility equipment from approaching wildfires.  Webinars will include:

            April 8, 2021:  Sensing and Detection / Fire Testing Capabilities

            April 15, 2021:  Situational Awareness

            April 22, 2021:  Modeling & Analytical Tools

            April 29, 2021:  Modeling & Analytical Tools / Post Fire Analysis

For more information regarding the webinars, please see the following DOE posting here.

Please contact Lisa Gast, Sean Neal, Robert Laurie, Lauren Perkins, Ellen Hill, and Sylwia Dakowicz for further information.

April 1, 2021 Newly Effective Reliability Standards

As of April 1, 2021, the following standards became effective:

FAC-002-3 – Facility Interconnection Studies
INT-006-5 – Evaluation of Interchange Transactions
INT-009-3 – Implementation of Interchange
IRO-002-7 – Reliability Coordination – Monitoring and Analysis
IRO-010-3 – Reliability Coordinator Data Specification and Collection
MOD-031-3 – Demand and Energy Data
MOD-033-2 – Steady-State and Dynamic System Model Validation
NUC-001-4 – Nuclear Plant Interface Coordination
PER-006-1 – Specific Training for Personnel
PRC-004-6 – Protection System Misoperation Identification and Correction
PRC-006-5 – Automatic Underfrequency Load Shedding
PRC-027-1 – Coordination of Protection Systems for Performance During Faults
TOP-001-5 – Transmission Operations
TOP-003-4 — Operational Reliability Data

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DWGP Assists the Navajo Tribal Utility Authority in Securing USDA Loan Award of $235 Million for Rural Utility Infrastructure Development

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Applauded by Arizona Senators Kyrsten Sinema and Mark Kelly and Arizona Congressman Tom O'Halleran (AZ-01), the U.S. Department of Agriculture (USDA) granted the Navajo Tribal Utility Authority (NTUA) a $235 million Rural Development loan for critical improvements in providing reliable electricity, water, and gas to the Navajo Nation.  The newly awarded investment will fund NTUA’s transmission expansions and upgrades, headquarters and warehouse construction, the service to 5,337 consumers, 144 miles of transmission line, 221 miles of distribution line and funding in smart grid technologies.

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California Joint Agencies Issue First SB 100 Report, and the CEC Approves Volumes I and III of the 2020 IEPR Update

220px California Energy Commission LogoOn March 15, 2021, the California Energy Commission (CEC), California Public Utilities Commission (CPUC), and the California Air Resources Board (CARB) issued the first analysis of California’s 100 Percent Clean Energy Act of 2018 (Senate Bill (SB) 100, De León, Chapter 312, Statutes of 2018) (SB 100 Report). SB 100 sets a 2045 goal of powering all retail electricity sold in California and state agency electricity needs with renewable and zero-carbon resources. SB 100 also updates California’s Renewable Portfolio Standard (RPS) to ensure that by 2030 at least 60 percent of the state’s electricity is renewable. 

The SB 100 Report’s initial findings suggest the goals of SB 100 are achievable, but additional analysis is required to evaluate reliability and other factors more comprehensively. The SB 100 Report’s results indicate that, to meet SB 100 goals, California will need to roughly triple its current electric grid capacity relative to today’s installed capacity. This involves a tripling of solar and wind build rates (based on a 10-year average), and an eight-fold increase in battery build rates (based on 2020), translating to building 69.4 GW of new utility scale solar, 28.2 GW of new customer solar, 48.8 GW of battery storage, 4 GW of long-duration storage, 12.6 GW of onshore wind, 10 GW of offshore wind, and about 100 MW of geothermal. Achieving SB 100 goals by 2045 is estimated to increase total resource costs by about 6%, as compared to reaching 60% RPS by 2045. In addition, while gas capacity is maintained for resource adequacy, implementing SB 100 decreases gas capacity by half as compared to a 60 percent RPS future. The SB 100 Report is the first step in evaluating the challenges and opportunities of achieving 100% clean electricity by 2045, the joint agencies will hold annual workshops and will release a report every four years.

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FERC Considering Whether to Require Additional Financial Assurances of Hydro Licensees

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The Federal Energy Regulatory Commission has issued a Notice of Inquiry (NOI) as to whether additional financial assurance mechanisms should be imposed on all licenses and other authorizations for hydro projects, including original licenses, new licenses, and subsequent licenses. In particular, FERC “is considering whether additional measures should be taken to ensure licensees have the financial resources to operate and maintain their projects for the life of the project, including under unforeseen circumstances.”  The NOI presents several issues to be addressed, including whether financial assurances should be required for all licenses, and whether such assurances should be required at regular intervals during a license term. The NOI proposes three potential mechanisms for establishing sufficient financial assurance, including bonds, a trust or remediation fund, and insurance against unforeseen hazards or dam failures.

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FERC Takes Actions Concerning Fed/State Authority over Distributed Energy Resource Aggregations


On March 18, 2021, the Federal Energy Regulatory Commission (“FERC”) took two actions that affect local control over Distributed Energy Resource (“DER”) aggregations.  First, FERC issued an order on rehearing of its final rule regarding the participation DER aggregations in Regional Transmission Organization (“RTO”) and Independent System Operator (“ISO”) markets (“Order 2222-A”).  In Order 2222-A, FERC sets aside its prior finding in Order 2222 that demand response (“DR”) resources’ participation in DER aggregations could be prohibited by   Relevant Electric Retail Regulatory Authorities’ (“RERRAs”) (e.g., state, municipal, public-power, and cooperative entities).  Instead, Order 2222-A provides the Order 719 “opt-out” will not apply to DR resources participating in DER aggregations comprised of different types of resources (i.e., “heterogeneous” DER aggregations), though Order 719’s” opt-out” will continue to apply to aggregations comprised solely of resources that participate as DR resources.  Further, FERC clarifies that the Order 719 “opt-in” will continue to apply to all DER aggregations, regardless of whether or not they include DR.

Second, FERC issued a Notice of Inquiry (“NOI”) seeking comment on whether to revise the Order 719 opt-out applicable to DR, in light of legal, policy and technological developments since FERC issued Order 719, and subsequent rehearing orders, in 2008 and 2009.  The Order 719 opt-out (codified at 18 CFR § 35.28(g)(1)(iii)) prevents ISOs and RTOs from accepting bids from DR aggregators if the utility distributed over 4 million MWh in the prior fiscal year and the RERRA prohibits the DR to be bid into the markets by a DER aggregator.  FERC is not proposing changes to the small utility opt-in, which prevents ISOs and RTOs from accepting bids from DR aggregators if the utility distributed 4 million MWh or less in the prior fiscal year unless the RERRA affirmatively permits the DR to be bid into the markets by a DER aggregator.

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