President Trump announced Monday he will nominate Virginia State Corporation Commission Chair Mark Christie and clean energy activist Allison Clements to FERC.
Democrats have been pushing Clements’ appointment to a Democratic vacancy on the commission since last year, but Trump had refused to name her. (See Senate Confirms Danly to FERC.) The commission is currently controlled 3-1 by Republicans.
Christie presumably would replace Republican Commissioner Bernard McNamee, whose term expired on June 30. McNamee announced in January he would not seek a second term but agreed to remain on the commission pending a replacement. He is allowed to remain on the commission until the end of the current Congress at the end of the year. (See McNamee Declines to Seek Reappointment.)
Christie was elected to the SCC by the General Assembly in 2004 and re-elected in 2010 and 2016. He was president of the Organization of PJM States Inc. when it pressed FERC to protect the independence of the PJM Independent Market Monitor.
He also is a former president of the Mid-Atlantic Conference of Regulatory Commissioners and served in the Marine Corps. A Phi Beta Kappa graduate of Wake Forest University, he received his law degree from Georgetown University. He has taught regulatory law at the University of Virginia School of Law and constitutional law and public policy in a doctoral program at Virginia Commonwealth University.
Clements is an adviser to the Energy Foundation, which seeks to accelerate “the transition to a clean energy economy by supporting policy solutions that create robust, competitive markets.” Clements was until recently the director of the foundation’s Clean Energy Markets program. She switched to consultant status and returned to D.C after several years in Salt Lake City.
She joined the foundation in 2018, after a year running a clean energy policy and strategy consulting firm, Goodgrid. That followed nine years with the Natural Resources Defense Council, including almost six as senior attorney and director of its Sustainable FERC Project, in which she worked on transmission planning, markets development and small generator interconnections.
Earlier, she was a member of the energy regulatory group at Troutman Sanders (now Troutman Pepper) and the project finance and infrastructure group at Chadbourne & Parke (now Norton Rose Fulbright).
She has a bachelor’s from the University of Michigan and got her law degree from George Washington University.
The announcement was cheered by clean-energy advocates.
“This is a welcome announcement, and we congratulate both Ms. Clements and Mr. Christie on their nominations,” said Gregory Wetstone, CEO of the American Council on Renewable Energy. “ACORE has long called for a full, bipartisan complement of five FERC commissioners. We hope the Senate can swiftly confirm these two strong candidates, so FERC can be best positioned to achieve its mission of ensuring reliable, efficient and sustainable energy.”
“We think they will help the commission a great deal and hope they receive speedy confirmation from the Senate,” said Rob Gramlich, executive director of Americans for a Clean Energy Grid.
“A great FERC pairing with two well-regarded folks,” tweeted Tyson Slocum, director of Public Citizen’s energy program. “Both will do a great job.”
Todd Snitchler,CEO of the Electric Power Supply Association (EPSA) also hailed the news. “A full commission benefits everyone. There are many important questions before FERC surrounding how our nation’s competitive power markets can continue to benefit Americans with cost savings, reliability and innovation.”
NRG Energy said Friday it will acquire competitive retailer Direct Energy from U.K.-based Centrica for $3.63 billion in an all-cash transaction.
Texas-based NRG expects the acquisition will result in $300 million in annual cost savings across the two companies “by leveraging our scalable operating platform,” CEO Mauricio Gutierrez said.
The deal will net NRG an additional 3 million retail customers throughout the U.S. and Canada on top of the 3.7 million the company already serves, concentrated mostly in Texas and the Northeast.
Direct Energy is the third-largest seller of electricity in Texas through its fixed-price electricity and gas plans. Centrica, which also owns British Gas, has been pummeled by the coronavirus pandemic’s oil price collapse and hopes the sale will reduce its mounting debts.
NRG CEO Mauricio Gutierrez | NRG Energy
Speaking during NRG’s second-quarter earnings call Friday, Gutierrez called the Direct Energy acquisition “highly complementary.”
“This is a compelling transaction that will greatly expand our retail footprint across North America and further diversify our product offerings and earnings,” Gutierrez said. “This is the right transaction at the right time.”
He said the acquisition will be funded through a mix of debt, equity-linked securities and cash on hand. The move creates a more balanced NRG generation portfolio “particularly in the Northeast, where we can expand the capital-light renewable [power purchase agreement] strategy that we have deployed in ERCOT.”
The takeover will also help NRG continue to lower its dependence on coal and reach long-term emissions reductions targets, Gutierrez said.
NRG targets the end of 2020 for closing the deal, which requires approvals from the Federal Trade Commission, FERC and the Commissioner of Competition under the Canada Competition Act. Centrica will hold a shareholder vote on the acquisition next month.
Gutierrez said the transaction will provide NRG with “the strongest collection of competitive power brands.”
“Since I became CEO four-and-a-half years ago, we have transformed our business from a highly leveraged [independent power producer] to a more stable and predictable integrated power company,” Gutierrez said. “Today’s announcement is consistent with our plan to rebalance our portfolio, reorganize around the customer and continuously improve our business and cost structure while maintaining financial discipline.”
Since emerging from bankruptcy in 2003, the company has been on a buying spree, picking up 11 energy companies, including Texas Genco, Reliant Energy and Green Mountain Energy. Today, NRG generates about 23 GW of capacity from more than 30 power plants. Natural gas and coal dominate the portfolio at 41% and 34%, respectively. Renewables account for 2%.
Houston-based Direct Energy currently purchases electricity from natural gas, coal and nuclear plants.
Gutierrez said NRG leadership is confident in the acquisition despite the near-term impacts of the COVID-19 pandemic. He said NRG has a “proven model of integration” and predicted it would spend about $220 million to consolidate Direct Energy’s systems, processes and personnel with its own.
NRG stock traded higher at $35.50/share early Monday but ended the session at $33.74, down from the previous close of $34.79.
Richard Kornitsky, ISO-NE assistant engineer for system planning, on Wednesday presented the Planning Advisory Committee with revised study scenarios and threshold prices, as well as other high-level assumptions, for the 2020 Economic Study requested by National Grid.
The utility asked for a study focusing on 2035 to provide stakeholders analyses of the best ways to meet state clean-energy goals cost-effectively, leveraging transmission and storage as needed.
Conceptual LMPs with negative threshold prices | ISO-NE
A set of incremental resource scenarios will model two different amounts of offshore wind interconnections, but the substantial focus is on bidirectional use of existing and proposed external tie lines, as well the use of Hydro-Québec as virtual storage, Kornitsky said. Hydro-Québec could provide virtual storage by curtailing its hydro production when New England renewables are overproducing and making resources available when ISO-NE needs them.
In response to a stakeholder question, Kornitsky said that the RTO implemented bidirectionality by incorporating renewable energy credits, recognizing that RECs can allow resources to be profitable even when LMPs are negative.
The study will use bidirectional threshold prices reflecting REC values to first curtail imports, then trigger exports, with renewables curtailed once export capability is exhausted. The prices range from -$100/MWh for behind-the-meter PV to -$30/MWh for onshore wind. The trigger for exports is assumed at -$25/MWh.
Storage Opportunities
Batteries will be a “central focus” of the 2020 Economic Study, Kornitsky said. They will be modeled with a round-trip efficiency of 86% and presumed to respond to LMPs and provide “system capacity,” regulation and reserves.
While ISO-NE Economic Studies do not consider capital costs and fixed operating and maintenance expenses, one stakeholder said such costs and expenses should be “baked in” to the analysis of utility-scale energy storage facilities.
In the third quarter, the RTO will present draft production simulation results, identify sensitivity scenarios and assumptions, and present assumptions for ancillary services analysis. In the fourth quarter, it will present sensitivity scenarios, simulation results and draft ancillary services results before issuing the draft and final reports in the first quarter of 2021.
Two Eversource Projects in Conn.
Eversource Energy engineer Christopher Soderman presented a $13 million project involving circuit separation, structure replacement and reconductoring with optical ground wire (OPGW) of approximately 1 mile of four 115-kV transmission lines crossing Horton Cove in Montville, Conn.
Structure geometry on towers adjacent to the Thames River in Montville, Conn., creates small phase-ground clearances and an increased probability of faults from lightning strikes, according to Eversource. | Eversource
“Reliability is the main driver here,” Soderman said.
Quad-circuit lattice towers and adjacent structures create the potential for disturbances on multiple circuits, while the structure geometry creates small phase-to-ground clearances and an increased probability of faults because of lightning strikes. Soderman said Eversource had 19 disturbances since 2010 caused by lightning strikes or shield wire failures, including three in the last four years in which a single event caused multiple transmission line outages.
The projected in-service date is in the third quarter of 2021.
Soderman also presented a $23 million project to replace 96-year-old double-circuit steel lattice towers between East Granby, Conn., and Agawam, Mass., and to replace old shield wire with OPGW on 7.5 miles, nearly half of the line’s total length.
The project involves replacing 70 decrepit towers with 63 direct-embed, weathering steel monopoles and seven engineered weathering steel monopoles on concrete foundations. Eversource will also install 62 lightning arrestors. The project is estimated to go in service in the fourth quarter of next year.
PJM stakeholders unanimously elected five new members to serve one-year terms on the Nominating Committee during the Members Committee meeting Thursday.
The Nominating Committee class of 2020-2021 is responsible for identifying candidates to serve on the PJM Board of Managers and reports to the MC. It includes one representative from each of the five PJM sectors.
Elected were Lisa McAlister of American Municipal Power (Electric Distributors); Susan Bruce of the PJM Industrial Customer Coalition (End-Use Customers); Jeff Whitehead of Eastern Generation (Generation Owners); Betty Watson of Affirmed Energy (Other Suppliers); and Alex Stern of PSEG Services (Transmission Owners).
Several first reads of issues were held during the Markets and Reliability Committee meeting.
Ed Kovler, PJM’s senior lead business solutions architect, reviewed proposed Operating Agreement language revisions to support improving situational awareness with the Dispatch Interactive Map Application (DIMA), a geospatial situational awareness program that allows operators to see the location of problems on the grid in real time. The language revisions will give transmission owners access to DIMA, which PJM dispatchers have used since 2014. The Operating Committee unanimously endorsed a “quick fix” solution at its June 4 meeting. (See “Dispatch Interactive Map Application,” PJM Operating Committee Briefs: June 4, 2020.)
Jen Tribulski of PJM provided an update on a proposal to rename the Credit Subcommittee as the Risk Management Committee and expand its role to incorporate risk. The new committee, which was first previewed at the April 30 MRC meeting, was originally contemplated to be a subcommittee of the MRC. But based on stakeholder feedback, Tribulski said, it will be a standing committee reporting to the MRC. If it wins endorsement at the August MRC, the new committee will hold its first meeting in the fall. (See “‘Credit’ Subcommittee Proposed to Change to ‘Risk Management,’” PJM MRC Briefs: April 30, 2020.)
Onyinye Caven of PJM reviewed proposed revisions to Manuals 14A, 14B and 14G, which incorporate Tariff changes from the RTO’s second Order 845 compliance filing. The changes were first presented at the July 7 Planning Committee meeting. (See “Manual 14 Changes,” PJM PC/TEAC Briefs: July 7, 2020.)
After several months of debate, stakeholders gave a final endorsement of PJM’s short-term proposal to resolve five-minute dispatch and pricing issues at Thursday’s Markets and Reliability and Members committee meetings.
The MRC endorsed the proposed solution and corresponding language revisions in a unanimous sector-weighted vote, with 69 members voting in favor — an outcome so unusual that PJM officials paused the meeting to double-check the results. In an acclamation vote held during the MC, three members voted against the PJM solution.
PJM’s proposed short-term fixes align the locational price calculator (LPC) to use the reference real-time security-constrained economic dispatch (RT SCED) case for the same target time. The LPC would calculate prices for the interval from 11:55 a.m. to 12 p.m. using the RT SCED solution for a 12 p.m. target time.
Resource offers, parameters and ancillary service assignments would be inputs to the RT SCED cases. Offers for 11 a.m. to 12 p.m. would be effective through 12, with offers for 12 to 1 p.m. used for the dispatch target 12:05.
The MRC and MC voted to approve PJM’s short-term proposal to resolve five-minute dispatch and pricing issues. | PJM
The Market Implementation Committee endorsed the PJM plan in June, with many encouraging the RTO to continue to pursue both intermediate and long-term changes. (See PJM 5-Minute Dispatch Proposal Endorsed.)
Tim Horger of PJM provided an updated presentation on the package. He also highlighted some of the intermediate changes that have already been implemented by PJM, including moving to the five-minute auto case execution for RT SCED cases, which began June 23. Horger said the tests proved successful, and the RTO plans to keep the procedure in place permanently.
As an example, Horger said dispatchers had a 76% rate of approved RT SCED cases priced from Jan. 1 until June 22. But from June 23, when the five-minute auto case execution was implemented, up until July 13, Horger said the approved RT SCED cases priced went to 90%, calling it an “incredible improvement.”
Adrien Ford of Old Dominion Electric Cooperative had spoken at the MIC in support of a proposal presented by the Independent Market Monitor that included changes to dispatch and SCED calculations in addition to the settlements changes in the PJM package. But Ford said Thursday that ODEC had come to support the PJM package because of the work done by the RTO to improve the proposal.
“We were always supportive of [PJM’s] short-term changes, but we just wanted more,” Ford said. “We think these are very positive steps forward for PJM in aligning dispatch and pricing.”
The RTO has said it expects to continue evaluating long-term solutions into 2021, with a quantitative analysis of the pros and cons of different approaches.
Susan Bruce of the PJM Industrial Customer Coalition said the RTO was responsive to stakeholders’ concerns, with it “moving in the right direction.”
Bruce said one of her concerns was PJM maintaining proper documentation on the intermediate changes if the five-minute auto case execution doesn’t continue to work as planned. She said it would be helpful for market participants to have the RTO describe its documentation process in its filing letter to FERC.
Horger said PJM has committed to continue the auto execution started on June 23. He said if the RTO determines the process to not be effective in the long term, it will engage with stakeholders to see if there is another process or method that could be beneficial.
Voting Concerns
Despite the broad support for PJM’s plan, Thursday’s votes were not without some contention.
Greg Poulos, executive director of the Consumer Advocates of the PJM States, said the advocates opposed having the MC endorsement vote on the same day as the MRC’s.
PJM rules allow any stakeholder to object to a same-day vote to have the vote moved to the next MC meeting. Postponing the MC vote would have delayed a FERC filing because there is no MC meeting in August.
But 70% of MC members supported Exelon’s motion to suspend the rules to allow the vote, above the two-thirds threshold required.
Exelon’s Jason Barker said it was “curious” why the advocates would object to a same-day vote if they didn’t oppose the PJM proposal.
“The only purpose to the objection of the same day vote would be for delay, and to Exelon that seems to squander stakeholder time and lead to unnecessary delay,” Barker said.
Poulos said it was a “tricky situation” because the advocates still want to see a long-term solution implemented along with the short-term solution. Poulos said some of the advocates also objected to the PJM’s FERC filing on fast-start pricing, set for the end of July, and were concerned that the short-term proposal would be included in the filing.
FERC on Friday accepted Tariff revisions filed in May by ISO-NE and the New England Power Pool Participants Committee, effective Monday, to make clean-up changes and enhancements to the RTO’s billing policy (ER20-1862).
The changes to the RTO’s Financial Assurance Policy:
revise the definition of “non-hourly charges” to explicitly include any pass-through charges for which ISO-NE acts as agent;
change the timing of when the monthly non-hourly charges bill is issued from the first Monday after the 10th of each month to the first Monday after the ninth of each month;
replace a number of references from “sending” remittance advice or invoices to “issuing” the same to reflect electronic, rather than physical, transmission; and
moving forward the deadline for instructions for alternate payments.
The commission found the updated definition of “non-hourly charges” improves transparency for all stakeholders.
But it said it was “not persuaded” by the arguments of a Canadian-owned entity, Plant-E Corp., which contested the revision to limit of prepayments to five in any rolling 365-day period.
Plant-E said it was told that Canadian covered entities are not allowed to have shareholder collateral accounts under the FAP because investment management firm BlackRock does not offer such accounts to Canadians.
NEPOOL opposed Plant-E’s comments on process grounds because the corporation proposed revisions to the filing for the first time in the proceeding without the benefit of any prior stakeholder consideration or review.
Hydro-Quebec’s La Grande 1 dam near James Bay
ISO-NE argued that Plant-E’s request for special flexibility to manage its collateral through the prepayment mechanism ignores the reason its proposal limits the number of times that a participant may prepay an invoice, i.e., to maintain adequate financial assurance.
The commission ruled that “although Plant-E, as a Canadian entity, does not have access to the collateral accounts that are available to U.S. entities, it does have access to letters of credit, which are used by other market participants to meet financial assurance obligations.”
In addition, the commission found Plant-E’s concern that ISO-NE does not enable Canadian covered entities to have a shareholder collateral account pursuant to the FAP to be “outside the scope of this proceeding.”
In 2015, the commission accepted Tariff revisions that put this limitation in place, and “Plant-E’s concern is therefore an impermissible collateral attack on that commission order,” it said.
PJM stakeholders continued debating changes to processes used to plan market efficiency transmission projects, including the creation of a new regional targeted market efficiency project (RTMEP) process that transmission owners say targets small projects addressing persistent congestion not identified in the forward-looking planning model and other members categorize as excluding competition.
In addition to the RTMEP proposal discussed at Thursday’s Market and Reliability Committee meeting, two additional changes are proposed to edit the way benefits are calculated for traditional market efficiency projects. The new processes were first endorsed at the May Planning Committee meeting. (See “Market Efficiency Process Packages Move to MRC,” PJM PC/TEAC Briefs: May 12, 2020.)
LS Power’s Sharon Segner said the current uncertainty over capacity market rules makes it difficult to move forward with the proposals, citing her company’s “strong concerns” about the proposal.
“We don’t feel this is the appropriate time to be tinkering with the market efficiency rules given the market upheaval that’s underway right now,” Segner said.
Jack Thomas of PJM provided an update of the phase 3 work completed at the Market Efficiency Process Enhancement Task Force (MEPETF), presenting the proposed solution package during a first read at the MRC.
Thomas said phase 3 work focused on creating the new RTMEP process while also looking at the benefit-to-cost calculations and the separation of energy and capacity benefits in calculations.
Stakeholders at the May 12 PC meeting endorsed a combined proposal by American Electric Power and FirstEnergy on the RTMEP process with 56% support. The package, which would exempt RTMEPs from competition, edged out PJM’s proposal (55% support), which called for 30-day competitive windows to select the developer.
The two packages are otherwise identical. Benefits are calculated based on the average of the past two years of day-ahead and balancing congestion, adjusted for outage impacts. To be approved, a project would have to recover its capital cost within four years.
The AEP-FirstEnergy proposal for the benefit calculation metric also was preferred, winning 54% to PJM’s 52%. AEP and FirstEnergy proposed averaging multiple Monte Carlo results and running them on Regional Transmission Expansion Plan (RTEP), RTEP+3 and RTEP+6 years. PJM’s proposal employed a single-draw Monte Carlo simulation, with simulations for both Reliability Pricing Model and RTEP years. Projects would be required to have a capital cost under $20 million and be in service within three years.
Robert Taylor of Exelon said that as more investigation has been done on the endorsed benefit calculation metric, “significant concerns” have arisen, and he requested that PJM take a deeper look at the issue. Without a cap on the number of Monte Carlo runs, the RTO could face a “never-ending series of analysis,” he said.
“We just don’t think the benefits outweigh what is going to be a massive increase in staff, servers and resources to go into that,” Taylor said.
PJM’s proposed window for capacity drivers won 52% support among stakeholders and 63% support over maintaining the status quo. The RTO proposed a 24-month cycle for energy drivers and a 12-month cycle for capacity following the Base Residual Auction.
The PC’s May 12 endorsement was the culmination of 18 months of work by the MEPETF. PJM is looking for endorsement at the Aug. 20 MRC meeting and a final vote at the Sept. 17 Members Committee meeting.
Segner said the task force has had more than 40 meetings over several years, with many of the proposals up for endorsement previously failing to receive enough votes to clear the PC. Generation and non-transmission alternatives can address congestion, she said, and the proposals shouldn’t discredit “market-driven alternatives.”
She said the proposals introduce a new idea of ordering transmission solely based on historical congestion, which differs from current practices in PJM markets that are designed to be forward-looking in the way generation and merchant transmission is developed.
“The grid is always evolving and changing so much in PJM,” Segner said.
Carl Johnson of the PJM Public Power Coalition said he has not been convinced that transmission is the solution to historical congestion that can’t be replicated in forward-looking models.
Catherine Tyler, a member of the Independent Market Monitor team, said congestion is “not inherently bad” and that the calculations used to evaluate the benefit-to-cost analysis ignore congestion increases, making the calculations flawed and not reflective of the actual benefit-to-cost. Tyler said transmission and generation don’t have the opportunity to compete with each other in the proposals, giving an advantage to transmission.
Tyler said PJM’s goal shouldn’t be to “copper plate” the system through unnecessary building projects when congestion could be resolved through generation or other means.
“Transmission should be built [based] on reliability, not cost and benefits,” Tyler said.
Taylor said he disagreed with the concept of congestion not being “inherently bad” and that the work done by the task force focused on cases where the market hasn’t responded in removing congestion and that would bring benefits to ratepayers. There’s value at looking at historical congestion, he argued.
“These are small, quick-hit projects and investments that have a significant and quick payoff for ratepayers,” Taylor said.
Paul Sotkiewicz of E-Cubed Policy Associates said the proposals are an attempt to guess where congestion will be in the near future without taking into account changes that can occur quickly.
Sotkiewicz also issued “caution” with moving forward with the proposals, pointing to actions in the early 2000s by the Alberta Electric System Operator (AESO), which conducted a transmission buildout in anticipation of load growth, with a goal of eliminating congestion in the system. He said AESO’s transmission costs now average about $30/MWh, driving customers to find ways to get off the system to avoid the charges.
He said that if PJM goes forward with current thinking in the proposals, it could be pushed into the same situation, with large customers looking for ways to shave off peak loads and get away from transmission costs.
“It looks like we’re driving up the cost of transmission with really no additional benefits,” Sotkiewicz said.
A panel of women discussed promoting equitable access to clean energy and a sustainable environment Thursday at the annual summer meeting of New England Women in Energy and the Environment (NEWIEE). More than 200 women gathered in cyberspace for the event.
“Of course, I regret that we can’t meet in person as in prior years, but it’s wonderful to have so many participants at today’s discussion of an important topic,” said NEWIEE President Jacquie Ashmore, director of Boston University’s Institute for Sustainable Energy.
Jacquie Ashmore, Boston University | NEWIEE
“A year ago, the NEWIEE board of directors chose increasing racial diversity in the NEWIEE community, and ultimately in the New England energy and environment industries more broadly, as our top priority,” Ashmore said. “Today, almost two months after the murder of George Floyd, NEWIEE has redoubled its commitment to addressing systemic racism and its impacts in our community.”
Following is some of what we heard at the event.
Turning Point
“I actually think the last several months will prove to be a turning point in our efforts around climate justice and environmental justice, and indeed, in the overall thrust and trajectory of the climate and clean-energy movement,” said FirstLight Power CEO Alicia Barton, who previously served as CEO of the New York State Energy Research and Development Authority and the Massachusetts Clean Energy Center.
The intersection of the COVID-19 pandemic, calls for racial justice and the ongoing climate crisis have laid bare the inequalities that result and continue to result in unfair and unjust outcomes for many people, Barton said.
“Now is the time to say that enough is enough,” she said.
Besides reforming the criminal justice system, Barton recommended that the region reconsider its approach to energy and environmental policy.
“Environmental justice, racial justice and equitable access to clean energy are topics that have been ancillary to the overall conversation rather than a driver of the conversation, but I do think that with recent events and because of conversations like the one we’re having today, that is changing and will change going forward,” Barton said.
What’s at stake in this conversation? she asked.
“First, we have known for a long time that pollution is not equitably distributed in the United States,” Barton said. “African-Americans, although they’re a minority of the U.S. population, are 75% more likely than white Americans to live in a community that’s adjacent to sources of pollution.”
Second, air pollution directly increases a person’s likelihood of getting severely sick or dying from COVID-19, she said.
Alicia Barton, FirstLight Power | NEWIEE
“A recent study out of Harvard found that someone who lived in an area of high particulate matter pollution is 15% more likely to die from COVID-19 than an individual who has not been exposed historically to that pollution,” Barton said. “Our energy choices are creating lethally unfair outcomes for many Americans, and we have to do better moving forward.”
Barton noted that New York’s Climate Leadership and Community Protection Act (CLCPA) passed last July “was the first major climate bill in the country to put climate, justice and environmental justice front and center. It requires under the law that at least 35% of the benefits of state investments in climate solutions go directly to disadvantaged communities.”
She said she was pleased to see her former colleagues at NYSERDA issue the biggest clean energy solicitation in U.S. history on July 21.
“If you didn’t notice, [as] part of that effort, the request for proposals specifically requires bidders to prioritize job-creation opportunities for disadvantaged populations. That’s really transformative and something that should be replicated elsewhere,” Barton said. (See related story, NY Announces 4 GW in Clean Energy RFPs.)
She also said that NYSERDA for several years has been including local content and labor provisions in the state’s renewable energy contracts, such as requiring developers to pay workers the prevailing wage. (See New York Plans for Wind Energy, Related Jobs.)
The CLCPA set a target of 6,000 MW of solar by 2025, “and earlier this year, the Public Service Commission approved NYSERDA’s request to increase funding for low-income access to solar and disadvantaged community access to solar 20-fold from what we had done historically,” Barton said.
The NY-Sun initiative was part of the Clean Energy Fund created by the commission in 2016, which established utility collections from ratepayers to support the overall $960 million funding requirement. (See NYPSC Launches Grid Study, Extends Solar Funding.)
Environmental Warriors
Nancy Seidman, RAP | NEWIEE
Nancy Seidman, senior adviser at the Regulatory Assistance Project, introduced and moderated the panel. Seidman was a co-author of a study released in April, “Energy Infrastructure: Sources of Inequities and Policy Solutions for Improving Community Health and Wellbeing.”
“The report documents current inequities in our energy infrastructure: processes, structures and policies that affect low-income and communities of color, including tribes, with a focus on rural areas,” Seidman said.
For example, the report looks at arrearage-management programs to prevent cutoffs in utility service, which is especially important because of job losses from the coronavirus pandemic, she said.
“The timing for releasing our report was good in some respects,” Seidman said. “With COVID and the social unrest of the past few months, I and likely you have all been confronting how inequitable the U.S. really is.”
Mariella Puerto, Barr Foundation | NEWIEE
Mariella Puerto is co-director for climate at the Barr Foundation in Boston, which grants $95 million per year to programs in the arts, climate and education.
“The choices I’ve made have been grounded in equity and justice from the beginning, which was a combination of my love of nature and the environment while I was growing up in Malaysia,” Puerto said.
Training as a police cadet in the rainforests of Malaysia left her awestruck at the jungle’s intense beauty. And a childhood friend’s death from exposure to pesticides pushed her to protect the environment, she said.
“This really opened my eyes to the dangers of toxic chemicals and environmental injustices,” Puerto said. “I knew early on that I wanted to be an environmental warrior, fighting for people and the planet.”
Shalanda Baker, Northeastern University | NEWIEE
Shalanda Baker, professor of law, public policy and urban affairs at the Northeastern University School of Law and co-director of the Initiative for Energy Justice, is author of “Revolutionary Power: An Activist’s Guide to the Energy Transition,” to be published in January by Island Press.
Baker works with other people of color to make sure that energy policy honors equity and social justice.
“In many ways, we are beginning to repeat the mistakes of the fossil fuel system in transitioning to clean energy,” Baker said.
In Oaxaca, Mexico, for example, Baker met indigenous peoples fighting against large-scale wind energy. The more she learned about those struggles, the more she realized that people were facing displacement, unfair contracts and unemployment from renewable energy development.
Later, while teaching law at the University of Hawai’i at Mānoa, “I had a front-row seat to that state’s energy transition. The state had just adopted a 100% renewable portfolio standard [and] was experimenting with community solar. We had maxed out rooftop solar in the state with the highest penetration rates in the country at 17%, and whenever I raised the question of equity or including voices of folks in the community in the energy policy conversation, I got looked at like I had two heads,” Baker said.
She brought the conversation back home by referring to New England having a number of leaders on the American Council for an Energy Efficient Economy scorecard for states.
“Massachusetts [is] No. 1 on energy efficiency, but I guess the dirty little secret about the Massachusetts efficiency programs is that there’s a lot of room for improvement on serving low- and moderate-income renters, as well as people who are not English speakers,” Baker said. “There’s a whole swath of the population that we are not serving.”
Shubhada Kambli, city of Hartford | NEWIEE
Shubhada Kambli, sustainability coordinator at the city of Hartford’s Office of Sustainability, agreed with Baker, saying, “Our community is majority black and brown, with about 30% of residents in poverty. We have energy burdens in some households of about 33%, which means, basically, that some of our residents are paying up to a third of their household income towards energy bills. … For reference, you may know that above 12% is considered high.”
The Hartford city government looks at climate action in terms of social benefits, Kambli said.
She cited the Connecticut Green Bank as a leader in innovation. She also touted PosiGen Solar, which operates in Connecticut, New Jersey and Louisiana. “They are specifically focused on increasing access to solar in low- and moderate-income communities, and they have eliminated the credit score as a gatekeeping tool to determine what types of participants should be partnered with in solar development,” Kambli said.
MISO staff last week reiterated that they can likely reliably operate the grid with a 50% renewable energy mix but warned that variables like generation retirements, fuel prices and solar siting could send energy prices soaring at certain times.
The findings were the latest in the grid operator’s ongoing, multiphase Renewable Integration Impact Assessment (RIIA). Staff’s findings focused on MISO’s ability to provide energy during all operating hours throughout the year as renewable penetration increases.
During a virtual workshop Friday, MISO Senior Policy Studies Planner Chen-Hao Tsai said that for the most part, the RTO can operate the system reliably with 50% renewable penetration, but only if it has the dramatic transmission expansion it identified earlier in the study. (See MISO Renewable Study Shows More Tx, Tech Needed.)
Chen-Hao Tsai, MISO | University of Texas at Austin
Tsai said escalating fuel prices, increases in solar generation and the pace of generation retirements play pivotal roles and could stand in the way of a 50% systemwide renewable portfolio. Any of those variables alone could set off a rise in LMPs, MISO said.
At a 50% penetration, MISO said prices predictably spike in the evening, when peaking units — mostly combined cycle gas units — step in to fill ramping needs. However, Tsai said that if natural gas prices more than double from about $2.50/MMBtu to about $5.60/MMBtu, more coal units will be used for ramping needs, driving up LMPs.
Multiple stakeholders observed that steady, lumbering coal units aren’t designed to provide quick on-and-off daily ramping. Some said the cycling MISO contemplated in the study would cause wear and tear on coal plants and possibly lead to more forced outages.
Other stakeholders pointed out that MISO is still leaving storage out of the study equation, ignoring the technology’s capability to dull ramping needs. Tsai said the RTO plans to reveal new study results with storage considerations in late August or early September.
A spate of thermal unit retirements might also threaten the reliability of a 50% renewable fleet, Tsai said. High retirements paired with a 50% renewable fleet also produce high prices in the evening, he said, with July evening hours yielding systemwide prices as high as $300/MWh.
“In many cases, many peaker units received over $1,000/MWh,” Tsai said. “We still make the penetration target, but we pay high system prices.”
On the other hand, the study indicates that increased solar capacity expected in MISO South would drop LMPs by midday and make the region an exporter to the rest of the RTO’s footprint during those hours. The trend also leads to significant middle-of-the-day solar curtailment during spring and fall months.
Tsai said the solar buildout “creates a new stressed operating point during the shoulder load periods, which may need further review.”
The RTO is also accounting for hundreds of gigawatts of renewable energy in its 20-year transmission planning. It foresees as much as 137 GW of renewables added and up to 114.5 GW in generation retirements by 2040. (See MISO Foresees Massive Shift to Renewables by 2040.)
Again, stakeholders said MISO should investigate how storage devices could soak up excess solar capacity. Some also asked the RTO to revisit the transmission needs it identified late last year to accommodate a 50% renewable mix. Tsai said the study’s transmission expansion portion is too involved and time-consuming to redo.
MISO plans to wrap up the RIIA study by the end of the year.
SPP said Wednesday that its Western Energy Imbalance Service (WEIS) market is at risk of falling behind schedule because it is still waiting on FERC approval of the market’s standalone Tariff.
The RTO had asked for a July 21 effective date, but that deadline passed the day before the Western Markets Executive Committee met virtually. FERC in April issued a deficiency letter, asking for more information on 14 issues. SPP filed a response in May.
“Without having any sort of regulatory certainty, we have to recognize that that is a risk to the program,” David Kelley, SPP’s director of seams and market design, told the committee. “There are a number of things waiting to move forward, pending receipt of the FERC order. There’s still a lot hinging on us getting that order.”
Kelley said the rest of SPP’s work to stand up its WEIS market by February 2021 is on schedule and “going according to plan.” Market trials are scheduled to start in August.
SPP has proposed a 22-cent/MWh net energy-for-load rate for the first year of market operations, based on annual $5 million operating costs, and said initial implementation costs will total $9.5 million. The commission asked the RTO to describe what costs are included in the implementation costs and to explain the ongoing administrative costs that it intends to recover through the WEIS rate (ER20-1059, ER20-1060).
Colorado utilities Xcel Energy-Colorado, Colorado Springs Utilities, Platte River Power Authority and Black Hills Energy have protested the WEIS filings. They contend an existing and neighboring joint dispatch agreement could be impaired by the WEIS market dispatch and that its market flows may harm the Western Interconnection Unscheduled Flow Mitigation Plan. They also contend SPP’s proposal disregards the Northwest Power Pool’s activities and could island Xcel’s balancing authority area from the NWPP reserve sharing group.
The Colorado utilities have all signed up for CAISO’s Western Energy Imbalance Market.
Advance Power Alliance Now an SPP Member
SPP said last week that the Advanced Power Alliance has become its first alternative power/public interest member, raising its membership count to 102. The group is an industry trade association supporting renewable generation and energy storage in SPP and ERCOT.
APA joined SPP following FERC-directed changes to the RTO’s exit fee after a Federal Power Act Section 206 filing by the group and the American Wind Energy Association in 2018. The commission ordered the RTO to eliminate its exit fee for its non-transmission-owning and non-load-serving members. SPP members pay an annual $6,000 membership fee, but exit fees for non-load-serving entities could cost $600,000 under the old format. (See FERC Tells SPP to End Exit Fee for Non-TOs.)
APA CEO Jeff Clark said the organization is “excited” about the opportunity to have “a more significant impact on the policies discussed and adopted in the RTO.” As a member, APA can now vote and join stakeholder groups.
“The SPP is home to some of the best renewable resources in the world. … The growth of clean, renewable generation in the region has been rapid,” Clark said in a statement.
MMU Releases Spring Quarterly Report
SPP’s average hourly load this spring was down 6% from last year, according to the Market Monitoring Unit’s spring State of the Market report.
The report, which covers March through May, attributed the decrease to a drop in demand because of the COVID-19 pandemic and to fewer heating and cooling days.
The average day-ahead price was $14.03/MWh, and the average real-time price was $12.58/MWh, down 41% and 44%, respectively, from last spring. The April day-ahead price of $14.03/MWh and real-time price of $10.43/MWh were the lowest monthly average prices since the Integrated Marketplace went online in 2014.
Coal-fired generation’s share of the fuel mix again fell, down from 32% last spring to 24% this year. Gas-fired generation and wind energy picked up the slack.
The report’s special issues section discusses the impact of a 2018 FERC order that resulted in a major-maintenance cost component for mitigated offers, addressing market participants’ concerns about recovering costs associated with mitigated resources (ER18-1632). (See FERC Accepts SPP Proposal on Maintenance Costs in Offers.)
Of the 491 thermal units eligible for major-maintenance adders, 113 have been approved, the report says.
The MMU will host a webinar Friday to discuss the report and answer questions.
New Wind Mark of 18,343 MW
SPP said it upped its wind-peak record to 18,343 MW on July 17, breaking the previous mark of 18,259 MW established Jan. 8. The record came at 11:13 p.m.
October Board, MOPC Meetings Now Virtual
SPP’s October quarterly governance meetings will be virtual only. The meetings were originally scheduled to be held at its corporate headquarters in Little Rock, Ark., during the weeks of Oct. 12 and Oct. 26.
The Board of Directors, Members Committee, Markets and Operations Policy Committee, Regional State Committee, Strategic Planning Committee and most other governance groups have not met in person since January.
SPP has discussed a mix of in-person and virtual meetings in 2021. Under that format, the MOPC would meet in person and the board virtually during one quarter, and then switch for the following quarter.
