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July 7, 2024

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SPP MSC Approves ‘Duty of Candor’ Tariff Language

State regulators in SPP’s Markets+ footprint have approved tariff language designed to address a “gap” in the accuracy of information to be shared with the Market Monitor under FERC’s duty-of-candor requirements.  

Weeks of discussion between regulators, SPP’s Market Monitoring Unit, and SPP and western utility legal staff resulted in the Markets+ State Commission’s endorsement of a paragraph during its regular monthly conference call Feb. 16. 

Nebraska abstained from the vote. 

The proposed tariff language would require market participants to “exercise due diligence and good utility practice” in providing material information when responding to the MMU’s written request for data and information. The MMU would provide a “reasonable amount of time” for utilities to deliver the requested information, depending on the amount of information.  

If the market participant determines there is an error in its response, it would have to “promptly” notify the MMU and work to correct the mistake. 

Questioned as to why the language is necessary, Keith Collins, vice president of market monitoring at SPP, said the MMU has encountered several instances within the RTO’s current footprint of entities either ignoring the monitor’s request or submitting incorrect action.  

“This does happen, unfortunately,” he said, noting the MMU based several hypothetical examples shared during deliberations over the language on those circumstances.  

“We feel that this particular language will solve that gap that we’ve identified with those examples,” Collins added. 

“Given what we’ve seen in the West, I just think there’s some real scar tissue about market manipulation,” said MSC Chair Eric Blank, who also chairs the Colorado Public Utilities Commission. “This is just common-sense protection that it seems the lawyers for SPP and for the market participants have agreed to.” 

Western commissioners brought the issue up during the Markets+ Participant Executive Committee meeting in January, requesting a clear definition of the participant obligation gap. (See “MMU, MSC to Collaborate,” SPP Markets+ Participants Executive Committee Briefs: Jan. 23-24, 2024.) 

A 2022 FERC Notice of Proposed Rulemaking related to “duty of candor” would require all entities communicating with the commission or other organizations — e.g., the MMU — about FERC matters to provide “accurate and factual information” (RM22-20). (See FERC NOPRs Would Require ‘Candor,’ Improved Accounting for Renewables.) 

The language will be brought forward for stakeholder approval during MPEC’s virtual meeting Feb. 20. 

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ConEd to Invest $20B in Tx and Climate Resiliency Through 2028

Consolidated Edison last week reported its plan to invest nearly $20 billion over the next four years in transmission infrastructure as part of its Reliable Clean City initiative and to mitigate climate vulnerabilities. 

The New York-based utility, which serves parts of New Jersey via Orange & Rockland (O&R) Utilities, made significant strides in the past year with the Clean City project, completing several sections and receiving state authorization for further upgrades to the six-mile-long Queens-based underground transmission line. It also was approved to start its $810 million Brooklyn-based interconnection hub for offshore wind power. (See $1.2B Con Edison Clean Energy Upgrade Approved.) 

“Clean energy is the future of our industry, and we are making strategic investments to build a grid capable of carrying that clean energy and protecting our infrastructure from climate change while maintaining our world-class reliability,” said ConEd CEO Tim Cawley in a statement.  

ConEd’s subsidiaries, Consolidated Edison Co. of New York (CECONY) and O&R, submitted plans to the state’s Public Service Commission (PSC) to invest $1.3 billion over five years to prepare for climate change (22-E-0222). They also proposed investments of about $2.82 billion in heat pump programs (18-M-0084) and obtained approval to increase their electric vehicle implementation budgets to nearly $450 million (18-E-0138). 

Con Edison’s corporate structure and ratings | Con Edison

The subsidiaries submitted utility thermal energy network pilot proposals totaling $289 million but await PSC approval (22-M-0429). 

ConEd plans to fund these investments by issuing $3.25 billion of long-term debt in 2024 and an additional $1 billion in 2025, with $6 billion more in long-term debt expected through 2026 and 2028 at CECONY and O&R. 

“Con Edison closed the year with no long-term debt at the parent company, due to the strategic sale of our former subsidiary, the Clean Energy Businesses,” said ConEd CFO Robert Hoglund. 

ConEd sold off CEB, consisting of 3,300 MW of renewable energy projects, to RWE Renewables America in 2022 for $6.8 billion and continues to realize financial benefits. In its 10-K filing, the utility reported a nearly 41% increase in annual net income, which rose to just under $2.52 billion ($7.25/share) in 2023 from $1.66 billion ($4.68) in 2022. (See Con Ed Yearly Earnings Continue to Rise.) 

Adjusting for the CEB sale, and other financial hypotheticals, ConEd’s annual earnings saw a more modest 9.6% increase, rising to $1.76 billion ($5.07/share) in 2023 from $1.62 billion ($4.57/share) in 2022. 

ConEd forecasts its 2024 adjusted earnings per share to be between $5.20 and $5.40 and expects an average annual increase in peak demand for electricity and gas over the next five years to be 2.7% and 1%, respectively. It also anticipates a 6.4% annual rate base growth through 2028. 

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We Energies Secures FERC Permission to Switch Coal Interconnection with Gas Plant

FERC on Feb. 15 allowed We Energies a MISO tariff waiver, making it simpler for the utility to trade gas for coal at its Oak Creek campus in Wisconsin. 

The commission granted We Energies a one-time waiver of MISO’s generator interconnection procedure requirements so it can link up a new gas-fired generator at a different voltage to replace its Oak Creek coal plant under a replacement generating facility request (ER24-646).  

We Energies plans to retire two of its 60-year-old Oak Creek coal units in May and the remaining two units by December 2025. It intends to replace the capacity with a $1.4 billion, 1.1-GW natural gas power plant and LNG storage facility to be completed in 2028.  

Oak Creek is connected to ATC’s 230-kV transmission facilities. ATC plans to transition its system surrounding Oak Creek to 345-kV and 138-kV only and eliminate its 230-kV facilities by 2027, hence the new gas plant requiring an interconnection at a different voltage than the existing coal plant. We Energies said it had to request the waiver due to factors outside of its control. 

ATC supported We Energies’ waiver request and said it would be the most cost-effective and efficient means of dealing with the issue. We Energies said if it wasn’t granted the waiver, it would have been forced to either install facilities to interconnect with ATC’s current 230-kV facilities and then replace them soon after with 138-kV- or 345-kV-compatible facilities, or “submit a new interconnection request for a project that would otherwise qualify for MISO’s generating facility replacement process due to no fault of its own.” 

Oak Creek’s generator interconnection agreement struck in 2000 did not specify a voltage level for the coal plant’s interconnection service. 

FERC said We Energies acted in good faith and that the waiver addresses a concrete problem with no detrimental consequences. 

We Energies executives have said the Oak Creek gas plant would serve as a backup power source when renewable energy output dwindles. Nonprofit Clean Wisconsin has argued any new natural gas additions go against We Energies’ goal of achieving an 80% reduction in carbon emissions from 2005 levels by 2030 and 100% carbon-neutral energy by 2050. 

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PJM MRC Preview: Feb. 22, 2024

Below is a summary of the agenda items scheduled to be brought to a vote at the PJM Markets and Reliability Committee meeting Feb. 22. 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 week’s newsletter for a full report. 

Markets and Reliability Committee

Consent Agenda (9:05-9:10)

B. Endorse proposed revisions to Manual 3A: Energy Management System (EMS) Model Updates and Quality Assurance with the goal of aligning to NERC’s Bulk Electric System (BES) definition. (See “Other Committee Business,” PJM OC Briefs: Feb. 8, 2024.)

C. Endorse conforming revisions to Manual 11: Energy and Ancillary Services Market Operations to implement the real-time temporary exception process FERC approved in EL21-78. (See “Real-time Temporary Exceptions Manual Revisions Proposed,” PJM MIC Briefs: Jan. 10, 2024.)

D. Endorse proposed revisions to Manual 38: Operations Planning resulting from its periodic review. (See “Other Committee Business,” PJM OC Briefs: Feb. 8, 2024.)

E. Endorse proposed revisions to Manual 40: Training and Certification Requirements resulting from its periodic review.

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FERC Rejects Rehearing Request for Mystic Agreement Disclosures

FERC has rejected a rehearing request from a group of New England public power utilities seeking the disclosure of additional information related to the Mystic cost-of-service agreement between Constellation and ISO-NE (ER18-1639-026). 

In October, FERC initially ruled against the public power groups’ request for additional disclosures of information, focused on the agreement’s supply arrangement with the nearby Everett LNG import facility. (See FERC Rules Against Additional Mystic Agreement Disclosures.)  

The public power organizations argued in their November rehearing request that FERC improperly denied outside entities the ability to review and challenge data related to the Mystic Generating Station’s revenues and the management of Everett as a part of the Mystic agreement. Both Everett and Mystic are owned by Constellation. 

The coalition wrote that FERC’s denial of the request for more transparency “pulls an impenetrable veil over information that the ISO-NE customers … require in order to verify the justness and reasonableness of the charges imposed on them and their customers.” 

In its Feb. 15 response to the rehearing request, FERC stood by its decision to deny additional public disclosures.  

“We continue to find the Mystic Agreement’s arrangement is just and reasonable and appropriately provides sufficient assurance that the inputs to the Mystic Agreement filed rate are accurate,” FERC wrote. 

The commission emphasized its prior finding that ISO-NE’s auditing rights in the agreement “are sufficient to ensure accuracy and transparency while preserving the confidentiality of commercially sensitive information and avoiding security risk.” 

ISO-NE and Constellation signed the Mystic agreement in 2018 over concerns that Mystic’s impending retirement would introduce significant resource adequacy risks to the regions. The cost-of-service agreement to retain Mystic began in June 2022 and will expire at the end of May 2024. 

As Mystic is the main customer of LNG from Everett, its looming retirement has triggered an ongoing effort to retain Everett after Mystic’s retirement. The two largest gas utilities in Massachusetts recently announced agreements with Everett to keep the LNG import facility operating for six more years, subject to the approval of the Massachusetts Department of Public Utilities. (See Constellation Reaches Agreements to Keep Everett LNG Terminal Open.) 

ISO-NE has not been involved in the negotiations to keep Everett open beyond the end of the Mystic agreement. The station is on track to retire at the end of the agreement in the spring.  

The costs associated with the cost-of-service agreement have been substantial; ISO-NE estimated that it cost ratepayers more than $600 million in the first 18 months of the agreement. More than $200 million of this cost came solely from January and February of 2023, driven by the spike in global LNG prices.   

Everett’s primary operational conditions for these months were listed as tank management, which includes self-scheduling to run and burning off excess fuel to make room for prescheduled LNG shipments. 

“While we remain sympathetic to customers’ concerns regarding the high costs of the provision of fuel security by the Mystic units, we believe we have struck the right balance,” FERC wrote in its rehearing response. “We are not persuaded that providing the additional information … is necessary to verify Mystic’s costs and ensure that the Mystic agreement’s filed rate is accurately implemented.” 

The public power entities also challenged FERC’s ruling with the D.C. Circuit Court of Appeals in early February, writing that “the commission’s decision to prevent customers from verifying the justness and reasonableness of the charges imposed on them through the cost-of-service agreement is not supported by substantial evidence or reasoned decision making, as required by the Federal Power Act.” 

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GSA, DOD to Power Federal Facilities with 2.7M MWh of Clean Energy

The Biden administration wants to buy more than 2.7 million MWh of carbon-free electricity (CFE) per year to power hundreds of federal and military facilities across the 13 states served by PJM, according to a request for information jointly issued by the General Services Administration and Department of Defense on Feb. 9. 

The RFI also sets out an ambitious timetable for the procurement, which it describes as “one of the federal government’s largest-ever clean electricity purchases.” The official request for proposals could go out in May, with awardees announced in September and the first clean electrons going online by the end of the year.  

In line with President Joe Biden’s 2021 executive order establishing a 100% clean energy goal for federal facilities by 2030, GSA and DOD are looking to make half of the CFE procurement matched hour for hour with demand on a 24/7 basis.  

With over 300,000 buildings, the U.S. government is the nation’s largest energy consumer and “a steady customer prepared to make long-term investments,” GSA Administrator Robin Carnahan said in the RFI press announcement. “We’re using the government’s buying power to spur demand for clean, carbon pollution-free electricity, and we’re partnering with industry to drive toward the triple win of good jobs, lower costs for taxpayers and a healthier planet for future generations.” 

Brendan Owens, assistant secretary of defense for energy, installations and environment, stressed the link between clean energy and national security, and DOD’s leadership in “greening federal government operations.”  

“Today’s announcement will help facilitate grid transformation to address the climate crisis and to provide clean, reliable and affordable electricity that ensures mission resilience for DOD operations,” Owens said. 

The RFI specifies that the government is looking to procure the CFE through retail electricity contracts rather than traditional power purchase agreements. Contracts could be for up to 10 years, with fixed per-kWh prices.  

Critically, the government is only interested in retail contracts for “bundled CFE,” which means “the original associated energy attributes have not been separately sold, transferred or retired,” according to the RFI. Renewable energy certificates (RECs) are the most used measure of clean energy attributes, with each REC certifying that 1 MWh of new wind or solar energy has been put on the grid.  

“Unbundled” RECs or similar energy attribute certificates (EACs) can be sold separately from the power that produced them. Solar installers may sell them to bring down the costs of an installation, and utilities or other companies often buy them to meet state-level clean energy mandates, passing on the cost to customers through increased rates. 

In other words, the Biden administration wants to make sure that the EACs for any clean electricity used to power federal facilities will not be sold for profit or used as a substitute for putting additional, clean energy on the grid.  

The RFI specifically asks that retail electricity suppliers be able to track and document that that any bundled CFE does not include EACs that have previously been counted for a state renewable portfolio standard. Companies are also expected to be able to track and report how much of the CFE provided is matched hour for hour with demand.  

1 Million MWh for BGE

The RFI does not list the federal or military facilities to be powered with CFE or their locations, but it does provide some hints. 

GSA intends to include 650 accounts in the solicitation, with contracts possibly awarded in phases. 

The RFI also provides a list of the megawatt-hours the government will need in the service territories of each of the investor-owned utilities in the PJM states. Baltimore Gas and Electric leads the list with 1,031,740 MWh. The massive military base at Fort Meade is part of the utility’s service territory. 

Commonwealth Edison comes second, with 403,774 MWh, while 201,297 MWh will be needed for Pepco’s service territory, which includes the high concentration of federal buildings in Washington, D.C.  

All three utilities are owned by Exelon Corp., which also owns Delmarva Power (1,381 MWh) and Atlantic City Electric (2,273 MWh). How will Exelon and other utilities handle the additional clean power this procurement could produce? 

In a statement emailed to RTO Insider, Exelon said it has been “modernizing our [transmission and distribution] assets over the last decade, allowing us to continue delivering safe, reliable, affordable energy to our customers even with a growing share of renewable and distributed energy resources.” 

Exelon’s long-range plan calls for $31 billion in investments “to strengthen our infrastructure — both physical and IT — to prepare our assets for an influx of renewable energy sources. … When these sources are built — we will be ready to deliver the energy.” 

GSA does recognize that the size and scope of the procurement may mean it will have to be rolled out in phases, and the agency may not be able to get all the clean energy it wants at the time contracts are awarded. The RFI notes that “GSA is considering including minimum CFE requirements describing how much bundled CFE can be delivered and when.” 

In such cases, “it is anticipated that contractors will be required to provide traditional retail electricity supply to meet [GSA’s] requirements,” the RFI says. 

A key question is how much new clean electric power will be needed to meet the government’s procurement targets. The RFI specifically says any clean power that has come online since Oct. 1, 2021, could be awarded a contract. 

In addition, beginning in July, PJM began its new “first-ready, first-served” interconnection process aimed at clearing a backlog of 260,000 MW from its interconnection queue.  

According to a year-end post on the RTO’s website, it estimates it will be able to clear 300 projects totaling 26,000 MW for interconnection this year. However, the overlap between the PJM queue and the federal procurement could be minimal as the RFI differentiates the bundled CFE it wants to purchase from “grid-supplied” CFE. 

The comment period on the RFI will run through March 18. GSA is holding an “industry day” Feb. 20 to talk about the RFI with retail electricity suppliers and other stakeholders. For more information, email CFESupport@GSA.gov. 

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LADWP Poised to Join CAISO Day-ahead Market After Board OK

CAISO notched another victory in the competition to bring organized markets to the West on Feb. 13 when the Los Angeles Department of Water and Power’s oversight board authorized the utility to prepare to join the ISO’s Extended Day-Ahead Market. 

LADWP has yet to issue a formal announcement on a market decision and did not respond to a request for comment in time for publication of this article. But the resolution advanced by utility officials and approved by the Board of Water and Power Commissioners on Feb. 13 allows LADWP “to proceed with necessary activities, agreement preparations, and other related EDAM work that will be brought back to the board in the future for approval.” 

“We think this is a good move forward,” Fred Pickel, LADWP’s ratepayer advocate, said ahead of the vote. “While the benefits exceed costs, it won’t have as big of an impact as participating in [CAISO’s] EIM, probably, but the information that all parties will get by participating in a formal market of this type will likely enhance everybody’s understanding of both short-run and long-run impacts and needs.” 

LADWP would be the third entity to commit to the EDAM following commitments by six-state utility PacifiCorp and the Balancing Authority of Northern California, a joint powers authority that manages system operations for the Sacramento Municipal Utility District and five other publicly owned utilities. (See BANC Moving to Join CAISO’s EDAM.)   

The largest municipal utility in the U.S., LADWP has been participating in CAISO’s real-time Western Energy Imbalance Market (WEIM) since April 2021. EDAM will expand the capability of the WEIM by including trading of day-ahead energy, which requires increased coordination among participants. As it works to attract members, the ISO faces strong competition from SPP’s Markets+ day-ahead offering, which has generated especially strong interest in the Northwest.  

The commissioners offered no comments before approving the request, which LADWP officials, including General Manager Martin Adams, submitted in a Feb. 5 letter and accompanying resolution. 

“EDAM builds on the success of WEIM, providing additional benefits to its participants while increasing regional coordination, supporting policy goals of the state of California and meeting demand more efficiently,” the letter said. 

LADWP estimates EDAM will increase its net revenues by $20 million to $59 million a year, with most gains “expected to result from savings in adjusted production costs and enhanced EDAM transmission-related congestion transfers,” the officials said in the letter. LADWP realized nearly $149 million gross benefits from its participation in WEIM in 2023, according to CAISO. 

The utility expects to incur about $14.7 million in setup costs to join EDAM, including system upgrades, training and ISO onboarding fees. It also estimates $21.1 million in annual costs for ongoing participation in the market, mostly stemming from administrative fees. 

“Overall, EDAM presents a strong net annual financial opportunity while helping LADWP better integrate additional renewable generation, thereby minimizing curtailments and greenhouse gas emissions in its service territory and the Western region,” the letter said. 

Extensive Reach

While LADWP’s service territory is limited to the city of Los Angeles, its reach extends far into other parts of the West. The utility owns and operates more than 3,600 miles of transmission lines spanning five states, including half the capacity on the 3,100-MW Pacific DC Intertie linking the L.A. metro area with the Bonneville Power Administration’s area in the Pacific Northwest. 

LADWP’s other interstate transmission assets include 60% of the contract capacity rights on the Southern Transmission System line connecting Southern California with the Intermountain Power Project (IPP) in Utah, a 36% ownership stake in the Mead-Adelanto Transmission Project connected to Nevada, and co-ownership of the Navajo-McCullough Transmission Line between the now-retired Navajo Generating Station in Arizona and the McCullough substation in Nevada. 

The utility also controls about 8,000 MW of generating capacity, including the 1,900-MW coal-fired IPP, 15% of the output from the 2,080-MW Hoover Dam in Nevada, and 5.7% of output from the 3,300-MW Palo Verde nuclear generating station in Arizona. 

IPP is slated for conversion to an 840-MW natural gas-fired plant in 2025, including turbines capable of burning a fuel mixture containing 30% hydrogen. Last year, LADWP was authorized to convert its Scattergood Generating Station, the largest gas-fired plant in Los Angeles, to hydrogen. 

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CEC Approves $1.9B for ZEV Infrastructure

The California Energy Commission approved a plan for spending $1.85 billion over the next four years to expand zero-emission vehicle infrastructure across the state. 

The bulk of the money — $1.15 billion — will go toward infrastructure for medium- and heavy-duty ZEVs. That includes $130 million for zero-emission infrastructure at ports. The funding is for battery-electric charging as well as hydrogen fueling. 

For light-duty vehicles, the plan includes $658 million for ZEV infrastructure.  

The commission approved the investment plan for the Clean Transportation Program during its Feb. 14 business meeting. 

At least half of the money in the investment plan will be used to benefit disadvantaged communities. 

“We need to make sure that this is zero-emission refueling infrastructure for everybody,” said Commissioner Patty Monahan, the CEC’s lead commissioner for transportation. 

ZEV infrastructure is needed for residents of multifamily dwellings, rural areas, and dense places “that are suffering disproportionately from air pollution,” Monahan said in a statement after the vote. 

Monahan also noted that funding figures could change based on the state budget. (See Newsom Budget Would Trim Calif. Climate Spending.) 

“As we all know, this is a tough budget year,” she said during the commission’s meeting. 

Funding Sources

Funding in the investment plan comes from three sources: the state general fund; the Greenhouse Gas Reduction Fund (GGRF), which gets money from the cap-and-trade program; and the Clean Transportation Program, which is funded through a surcharge on California vehicle registration. 

For example, the plan allocates $230 million in GGRF money over four years for zero-emission drayage truck infrastructure. Electric school bus infrastructure will receive $125 million in each of the next three years from the general fund. 

The investment plan divides funding into general categories, with details of the programs to be worked out through the CEC’s solicitation process.  

In addition to funding for light-, medium- and heavy-duty ZEV infrastructure, the plan allocates $46 million for “emerging opportunities” in areas such as aviation, marine vessels and rail. And $5 million will go toward workforce training. 

The plan’s emphasis on infrastructure for medium- and heavy-duty ZEVs is due to the outsized impact conventional trucks have on air quality, the CEC said. 

Trucks account for roughly 2% of the 31 million vehicles registered in California. But they’re responsible for about 23% of on-road greenhouse emissions, as well as large shares of nitrogen oxides and particulate matter from the transportation sector. 

“For these reasons, medium- and heavy-duty vehicles represent a significant opportunity to reduce GHG and criteria emissions while focusing on a small number of vehicles,” the investment plan states. 

EV Charging Needs

California will require all new cars sold in the state to be zero emission by 2035. The state’s Advanced Clean Trucks and Advanced Clean Fleets regulations set timelines for transitioning medium- and heavy-duty trucks to zero emission. 

The CEC released a report in August projecting that the state will need about 1 million public or “shared private” chargers in 2030 to support 7.1 million plug-in electric cars. By 2035, the numbers are expected to grow to 2.1 million public or shared chargers needed for 15.2 million light-duty plug-in EVs. 

Currently, California has close to 94,000 public and shared private chargers, in addition to private chargers at homes and other locations. The CEC said in a release that funding in the new investment plan will result in about 40,000 new chargers across the state. 

Funding from other programs also will boost ZEV infrastructure. For example, the state is expecting to receive $384 million in federal funding through the National Electric Vehicle Infrastructure (NEVI) program. 

“Combined with previous investment plans, funding from the federal government, utilities and other programs, the state expects to reach 250,000 chargers in the next few years,” the CEC said. 

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FERC Meets at Howard Law School and Gets Update on OPP Activity

WASHINGTON — FERC got a presentation of its Office of Public Participation’s 2023 Annual Report at its monthly open meeting Feb. 15, which was held at Howard University’s School of Law. 

The law school was founded in 1869, at a time when there was a great need for lawyers who would help Black Americans protect their newly established rights, Chair Willie Phillips said at the start of the meeting, held in a moot courtroom at the school. 

“As the first Black chairman of FERC, as a graduate of this esteemed law school and as a great-grandson of a slave, it is not lost on me the significance of this moment,” he added. “And so, it is indeed a pleasure to be here with you, to be here with my colleagues, and to present this meeting and to conduct the business of the Federal Energy Regulatory Commission in front of the next generation of energy lawyers and practitioners.” 

In addition to Howard Law students and faculty, the audience included former FERC Commissioner Colette Honorable, now executive vice president of public policy at Exelon, and recently retired FERC Secretary Kimberly Bose, who is also an alumna. 

In addition to reaching out to potential future energy lawyers, FERC heard from its Office of Public Participation and how it is reaching out to the public after being founded in 2021. 

“Our Office of Public Participation is key to our continued efforts to involve members of the public in FERC proceedings that are important to them,” Phillips said. “Hearing from the public is essential to ensuring the commission continues to make decisions that are in the public interest.” 

The OPP is meant to empower, promote and support public voices in FERC proceedings, said acting Director Nicole Sitaraman. 

“Public participation is our sole focus, and to remind public attendees here today: OPP is a non-decisional office and has no role in FERC decision-making and contested proceedings,” she added. “This allows us to interact fully with the public, which includes open and contested cases.” 

In 2023, the office participated in more than 160 meetings all around the country with constituents including landowners, tribes, environmental justice leaders, university researchers, environmentalists, consumer advocates and small business owners. It also developed video workshops on the natural gas prefiling process, the fundamentals of intervening in a FERC proceeding and the process for filing comments. 

OPP also developed 15 educational resource documents, which were praised by commissioners for helping to translate the dense technical language it deals with into everyday English. 

“The explainers, in case you haven’t read them, are taking concepts like: How does an energy market work? How does a capacity market work?” said Commissioner Mark Christie, “and trying to put those extremely difficult, complicated concepts into something that someone who’s not in this business for years and years and years can understand.” 

The report also included the most common questions OPP gets when it is dealing with the public, which includes how to participate in FERC processes, how to deal with post-construction impacts of regulated facilities on private property and how to engage with FERC when projects it regulates bring up environmental justice concerns.

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Federal Researchers Flip Switch on OSW Research Array

Researchers have activated a new array of sensors off the New England coast to gather information that could improve the design and operation of wind energy generators. 

The equipment was set up over the past three months and on Feb. 15 began gathering data on wind and weather patterns as well as wildlife activity. 

The zone being monitored — south of Massachusetts and Rhode Island, east of Long Island — is a center of early offshore wind energy development in the United States. A small wind farm has been operating there since 2016, three larger facilities are under construction and plans for six lease areas there are in various stages of development. 

The efficiency of those wind farms will benefit from analysis of the wind and weather, and of the interaction between the ocean and atmosphere, the U.S. Department of Energy and the National Oceanic and Atmospheric Administration said Feb. 15. 

Seven surface buoys, two subsurface buoys and six shoreline field stations have been set up, along with three lidar buoys that can measure wind up to 250 meters above sea level. The Woods Hole Oceanographic Institution’s air-sea interaction tower near Nantucket will be used as well. 

Along with weather, the sensors will monitor the activities of birds, bats and whales over the next 18 months. Researchers hope to gain a better understanding of their patterns of movement in the area, and thereby analyze the effects of offshore wind construction and operation on wildlife. 

The effort is called WFIP3 — it is the third phase of the Wind Forecast Improvement Project funded by DOE and NOAA. The Pacific Northwest National Laboratory and Woods Hole are leading the weather component of WFIP3; Duke University is leading the wildlife component. 

DOE and NOAA said the first and second phases collected data to improve the accuracy of short-term land-based wind forecasting/modeling in the Great Plains and Pacific Northwest regions, respectively. 

The data generated by WFIP3 will be used to inform offshore wind generation siting and grid integration, as well as to advance weather and wind plant modeling.  

Dave Turner, manager of NOAA’s Atmospheric Science for Renewable Energy Program, said in a news release: “We want to use these insights to improve NOAA’s operational weather prediction models, which often serve as the foundational forecasts for the energy community in their daily management of their wind plants.”  

DOE’s Alejandro Moreno said: “Understanding the offshore environment better is a Grand Challenge that DOE and its partners are addressing to ensure that offshore wind can not only operate efficiently and sustainably, but also contribute to grid reliability in the energy system of the future.”