Exelon (NASDAQ:EXC) reported a positive first quarter to investors and analysts Monday, its first earnings report since it completed the separation of its former power generation and competitive energy business, Constellation Energy, in February.
Net income from continuing operations for the first quarter of 2022 decreased to $481 million ($0.49/share), compared to $525 million ($0.53/share) for the same period in 2021. Adjusted to exclude the costs of the Constellation separation, however, earnings increased to $634 million ($0.64/share) from $542 million ($0.55/share).
Company officials said the results reflected higher earnings from Commonwealth Edison, resulting from an increased rate base, and increased returns on equity for PECO Energy, Baltimore Gas and Electric and Pepco Holdings Inc.
Exelon CFO Joe Nigro said the earnings were “driven in part by the recovery of costs associated with ongoing infrastructure investments to improve reliability and resiliency, enhance service for our customers and prepare the grid for a clean energy future.” Exelon reaffirmed its full-year adjusted operating earnings guidance range of $2.18 to $2.32/share and a long-term operating earnings growth target of 6 to 8% through 2025.
“Our grid modernization investments, enabled by constructive regulatory relationships, continue to drive solid operational results and stable earnings across our utilities,” Nigro said.
CEO Chris Crane said the separation of Constellation “really unlocked significant value” for shareholders, with a total return of 76% through the time of the announced deal more than a year ago through mid-April of this year.
“The first quarter was a milestone for Exelon as we successfully completed our separation of the generation business and embarked on our path as the nation’s premier transmission and distribution utility company,” Crane said.
Electric Vehicle Initiative
Nigro spoke about the adoption of electric vehicles and Exelon’s strategy in helping in the transition to EVs, saying they are “unquestionably a key enabler for reducing emissions.”
Jurisdictions in which Exelon operates are targeting 4.2 million EVs on the road over the next 25 years, a twentyfold increase from the end of 2021, he said.
“As our states make this transition over the coming decades, Exelon is poised to support our customers through investments such as upgraded distribution circuitry, substations and ultimately transmission,” Nigro said. “Transforming the grid over this period to meet the increased standards required by EVs, along with other expanded and innovative uses of the grid, will require significant investment.”
COO Calvin Butler said Maryland wants 300,000 EVs on the road by 2025, while New Jersey wants 330,000 by 2025 and 2 million by 2035. Current Illinois law requires 1 million EVs by 2030, and Delaware is looking for 20% of its registered vehicles to be electric by 2025.
“That just goes to show you the opportunity,” Butler said. “And when you look at the infrastructure that is going to be required to meet that and all of our capital plan, we see the opportunity across the Exelon utilities. It’s all different but significant opportunity for us to be partners in building out that infrastructure and preparing the grid.”
Massachusetts Gov. Charlie Baker on Friday swore in Beth Card as the new Energy and Environmental Affairs secretary.
Card replaces Kathleen Theoharides, who announced her departure from the role at the end of April.
“Beth Card has a deep knowledge of environmental policy and a wealth of experience in leading climate resiliency efforts in state government, and we are glad to appoint her as Secretary,” Baker said in a statement.
Card joined the Baker administration last year as undersecretary of environmental policy and climate resilience. She worked previously as the director of environmental and regulatory affairs for the Massachusetts Water Resources Authority and at the Massachusetts Department of Environmental Protection as deputy commissioner for policy and planning and assistant commissioner, Bureau of Water Resources.
“The tireless efforts of Secretary Theoharides have resulted in the creation of critical climate change programs, investment in the commonwealth’s renewable energy portfolio, and the advancement of the administration’s decarbonization goals,” Card said.
Former Mass. EEA Secretary Kathleen Theoharides will join RWE Renewables in June as head of offshore development-east. | RWE Renewables
Theoharides oversaw initiatives in Massachusetts that led to the development of the first U.S. utility-scale offshore wind farm, new procurements for 3.6 GW of offshore wind energy and a statewide mandate to reach net-zero emissions by 2050.
On Thursday, RWE Renewables announced that Theoharides will join the company’s offshore wind team June 1 as head of offshore development-East.
“Katie has been a visionary for Massachusetts whilst driving the state’s clean energy ambitions and will further RWE’s … strategy to rapidly invest €50 billion in clean energy technologies,” said Sam Eaton, executive vice president of offshore wind development, RWE Renewables Americas.
Theoharides will be responsible for development activities along the East Coast, including RWE’s floating wind research array in the Gulf of Maine and the company’s lease area in the New York Bight with partners Diamond Offshore Wind and National Grid Ventures, respectively.
“I’m thrilled to be joining the RWE team to help accelerate the pace of offshore wind deployment in the U.S., and to create clean, renewable energy that will help us achieve our urgent climate goals,” Theoharides said.
The NY Green Bank is starting a $250 million Community Decarbonization Fund this year and increasing its own capitalization by nearly a third to address stakeholder requests for the state-owned bank to improve how it serves disadvantaged communities (DAC), feedback it detailed in a revised annual plan filed May 2 (13-M-0412).
The NY Green Bank in 2021 raised $300 million in private funds to increase its capitalization by nearly a third. | NYGB
The bank raised $300 million from private sources to leverage the nearly $1 billion in ratepayer funding that supported its existing commitments, namely to invest $150 million in affordable housing projects by 2025 and $100 million in building electrification and energy efficiency in disadvantaged communities by 2025.
New York’s Climate Leadership and Community Protection Act (CLCPA) requires that 35% to 40% of all state spending related to clean energy go to DACs, which the NY Green Bank calculates from its total investments planned through Dec. 31, 2025, the end of the current Clean Energy Fund term.
NY Green Bank requested from the Public Service Commission an extension from the original filing deadline in March to more fully gather stakeholder comment, which it summarized in this month’s amended annual report without identifying any commenters.
Noted Comment
Some stakeholders complained of “cumbersome and lengthy” project financing processes, while others noted the increased capital needed to meet state environmental goals across building typologies, including affordable multifamily housing, or to comply with New York City’s Local Law 97, under which most buildings over 25,000 square feet will be required to meet new energy efficiency and greenhouse gas emissions limits by 2024.
One environmental justice advocate involved in those discussions with the NY Green Bank, Clarke Gocker, director of policy and strategy for PUSH Buffalo, told NetZero Insider he is “guardedly optimistic” about the bank’s move toward greater focus on serving DACs.
“If the state’s going to meet its climate goals, there really has to be a sea-change and a revolution in how existing funds are mobilized, and there needs to be a dramatic scaling up of investment that comes first from the public sector,” Gocker said.
PUSH Buffalo is a member of NY ReNews and is on the steering committee, and it has “been calling in the past 18 months, in particular after the passage of the CLCPA, for massive investments to implement the climate law really in line with even [New York State Energy Research and Development Authority’s] own projections released last fall, which are on the order of $10 billion a year,” Gocker said.
The state’s Climate Action Council has estimated a minimum of $1 billion in annual grants and incentives will be required through 2050 to green the affordable housing market, which would require a quadrupling of current funding. The council’s Climate Justice Working Group is helping define DACs, with draft criteria encompassing 35% of the population and households in the state, and it is holding public hearings on the topic through June 30.
Specific census tracts and low-income individuals are included in the draft definition as DACs that bear negative public health burdens or as individuals earning less than 60% of the state median income or participate in assistance programs, regardless of where they live.
NY Green Bank also is committed through 2025 to provide $100 million in financing to help clean transportation businesses locate or expand in New York and up to $100 million toward port infrastructure projects.
Reasonable Terms
“A theme repeated by developers, lenders and community-based organizations related to a lack of capital available to support building decarbonization or ambitious energy efficiency,” the amended plan said. “Owners and operators of regulated multi-family affordable housing properties commented that their properties had no excess cashflow or balance sheet resources to cover the cost of energy-related building upgrades.”
In 2021, NY Green Bank launched two financing channels, which included a request for proposal (RFP) for financing high-performance affordable housing, and another on “mandatorily redeemable preferred equity for disadvantaged community lenders.”
Stakeholders urged the bank to consider replacing the broad pathway for building decarbonization with focused RFPs addressing predevelopment loans, incentive bridge loans and permanent debt, and to publish indicative terms to align with “off-the-shelf” products offered by other real estate project lenders. Specialty lenders, they said, do not necessarily need preferred equity infusion to facilitate the expansion of their lending activities.
Environmental justice advocates pointed out that community-owned solar projects offer greater energy bill savings than those available to subscribers of privately-owned ones, but that lending institutions lack interest in such small, complex projects, the bank said.
One perspective among environmental justice advocates was that NY Green Bank currently charges higher interest rates than the private sector lenders to low-income New Yorkers, Eddie Bautista, executive director of the New York City Environmental Justice Alliance and a member of the state’s Climate Justice Working Group, told NetZero Insider.
The state in 2013 chartered NY Green Bank, which operates as a division of NYSERDA, to work with the private sector to increase investments in the state’s clean energy markets.
SPP Takes AECI Dispute over Winter Storm Charges to FERC
SPP has filed a request with FERC that the commission take immediate action in a dispute between the grid operator and Associated Electric Cooperative Inc. (AECI).
The RTO filed its Section 207 request on April 20, asking FERC to assert its exclusive or primary jurisdiction and determine that it properly compensated AECI for emergency power provided during the February 2021 winter storm as it scrounged for power from its neighbors to meet demand.
It also asked the commission to find that:
the transactions in question are governed by SPP’s tariff;
AECI is entitled only to the compensation provided for under the tariff under federal law; and
the RTO correctly calculated payments and paid the cooperative all the compensation owed as an SPP market participant.
SPP requested the commission act expeditiously to preserve its exclusive jurisdiction over the issues in dispute. AECI has taken its complaint to the U.S. District Court for Western Missouri, where it filed in February (6:22cv3030).
AECI is seeking to recover $37.64 million from SPP for the emergency power it provided during the storm. That includes $29.4 million for the costs to provide the power and $8.24 million in day-ahead residual unit commitment (DARUC) make whole payments SPP has charged the cooperative.
AECI said it was obligated to reimburse the market for other resources that were committed during the emergency events, but did not itself receive any such payments for its resources. It said SPP has not reimbursed the cooperative for any of the make whole payments.
The organization’s representatives discussed the dispute several times last year and this year, SPP said. It said AECI did not follow all of the JOA’s dispute-resolution’s formal steps and that no mutual resolution was reached through the informal discussions.
SPP has filed a motion to dismiss the lawsuit. An RTO spokesperson said the grid operator is waiting on orders from FERC and the court and is unable to provide further comment.
MMU Releases Winter Market Report
Wind energy grabbed a 42% share of SPP’s generation mix during the winter, a 35.5% increase from the previous winter, according to the Market Monitoring Unit’s (MMU) quarterly State of the Market report.
The MMU said wind generation was the primary fuel type during the most recent winter, an increase from 31% the prior winter. Coal and natural gas thermal generation decreased between the two winters, from 38% to 33% and from 21% to 16%, respectively.
Other highlights from the report, which covered December 2021 to February 2022:
Day-ahead prices increased from an average of $18.18/MWh during the 2020 winter to $27.95/MWh in the most recent winter, a 54% increase. Real-time prices increased from an average of $16.93/MWh two years ago to $24.32/MWh in 2022, a 44% increase.
Average winter monthly outages and derates returned to normal after the 2021 winter storm, totaling 29,100 GWh.
Overall, real-time market congestion for intervals with breached flowgates increased to 82% of all intervals, a substantial increase from 2021 (59%) and 2020 (34%). Analysis indicates that over the last three winters, the percentage of intervals with breached market-to-market (M2M) flowgates has increased from 33% of all intervals to 82%, indicating M2M flowgates are a large factor in increased flowgate breaches.
Transmission congestion rights (TCR) funding during the winter came in at 84%, down from 98% the winter before. The MMU partially attributed the low funding levels to significant outages not found in the TCR model as underfunding worsened to $101 million, up $93 million from the previous year.
The 2021 frequently constrained area (FCA) study had similar congestion patterns as previous years, but with more frequent and higher congestion costs. The study identified the southwest Missouri and southeast Oklahoma areas to be added as FCAs.
The MMU will host a webinar to discuss the report on a to be determined date.
Competitive Tx Process Improvements
The Transmission Owner Selection Process Task Force is soliciting stakeholder feedback as it works to improve the RTO’s competitive transmission project selection process. The feedback is due this Wednesday.
SPP has conducted a similar process after each of the four competitive projects it has awarded. The most recent came last month when the grid operator’s board approved NextEra Energy Transmission Southwest’s selection to build a 48-mile, 345-kV transmission line in Oklahoma. (See SPP Board of Directors/Markets Committee Briefs: April 26, 2022.)
The task force is conducting its work even as FERC has backed off some of its Order 1000 requirements. The commission last month issued a transmission planning rules proposal that would offer incumbent TOs a federal right of first refusal on certain regional projects. (See ANALYSIS: FERC Giving up on Transmission Competition?)
MISO and SPP staff on Friday told stakeholders that this year’s coordinated system plan (CSP) study will focus on “potential solutions to historical, persistent congestion issues” on the RTOs’ seam.
The study, which is not dependent on other regional or interregional planning processes, will analyze historical market-to-market (M2M) congestion problems and look for transmission solutions that benefit both grid operators.
The M2M process has resulted in SPP accruing almost $255 million in settlements from MISO since the RTOs began it in March 2015. Under the process, the grid operators exchange settlements for redispatch based on the non-monitoring RTO’s market flow in relation to firm-flow entitlements.
“We’re looking at sort of near-term planning horizon,” MISO’s Ben Stearney told the Interregional Planning Stakeholder Advisory Committee (IPSAC). “We want to target solutions that can be implemented quickly. So really, we’re not looking for large expensive, greenfield projects. We’re targeting kind of a low-hanging-fruit, quick-hit type of projects.”
In their scope document, staff said they have been jointly exploring ways to address M2M congestion where a long-term planning horizon study “may not effectively capture certain existing day-ahead or real-time market conditions.” They raised the concept of a targeted market efficiency project, similar to that conducted by MISO and PJM, before formally agreeing to use the process in the CSP. (See MISO, SPP Take on 2nd Interregional Planning Effort.)
MISO and SPP seams | MISO and SPP
The RTOs’ staffs hope to develop a repeatable process to effectively study persistent congestion on the seam, including a set of appropriate project criteria for inclusion in their joint operating agreement’s (JOA) language. They also plan to recommend transmission upgrades using a yet-to-be-determined cost allocation methodology.
The grid operators’ JOA requires a CSP be conducted every couple of years to find interregional projects. However, previous, more comprehensive studies have come up empty over cost allocation issues. The MISO-SPP Joint Planning Committee, comprising representatives from each RTO, agreed in March to pursue the new study process.
Asked whether the CSP analysis might find projects that have already been identified by the RTOs’ long-term transmission planning efforts already underway, Stearney said those latter studies have longer lead times.
“I don’t see that as an issue,” he said.
WEC Energy Group’s Chris Plante offered his company’s support for the CSP study.
“I think when we look back at the process that MISO and PJM followed when evaluating targeted market efficiency projects, I think we found that to be a very successful process in terms of identifying extremely near-term, low-dollar cost upgrades that can address some of this congestion,” he said.
The RTOs are working to compile two years of historical M2M data and establish a list of candidate flowgates for consideration. They intend to develop the study process and complete the initial assessment this year. However, they pointed out, because the study will require JOA updates to formally recommend any resulting projects, the final tariff language and FERC filings are not expected to be completed until midway through 2023.
Staff will wait until next year to begin the always sticky development of regional cost allocation.
Future IPSAC meetings are scheduled for July 22 and Sept. 23. Additional meetings will be held as needed while the study progresses.
Establishing accurate facility ratings is a significant challenge both in Texas and across the ERO Enterprise, according to participants in a webinar hosted by the Texas Reliability Entity on Thursday.
The webinar, part of the regional entity’s regular Talk with Texas RE series, was focused on the FAC-008 series of reliability standards, the most recent of which, FAC-008-5 (Facility ratings), took effect last October. Violations of the FAC-008 family are frequent both across the ERO Enterprise and in Texas RE; for example, last year the RE assessed a $192,000 penalty against Oncor for infringing the standard. (See FERC Approves $536K in Penalties from WECC, Texas RE.)
“It’s a pretty significant opportunity, [and] a pretty significant risk in this interconnection, to get the proper ratings out there for ERCOT to make the right decisions [and] for you to make the right decisions, and so we need to have reliable operations,” said Curtis Crews, Texas RE’s director of operations and procedures compliance and risk assessment.
A major focus of the webinar was FAC-008-5’s requirement that registered entities establish a “documented methodology for determining facility ratings” of relevant equipment, or facility ratings methodology (FRM). The lack of an adequate FRM is a common cause of FAC-008 violations; utilities may also face penalties for having a methodology but not following it, as in the case of a settlement between WECC and Arizona’s Salt River Project approved by FERC last month. (See NERC Hits SPP, SRP for $406K in Penalties.)
Crews also emphasized that even with a suitable FRM, it is not enough for utilities to rate their facilities once. He said registered entities should review their equipment regularly because repairs and upgrades can introduce new equipment that changes the overall rating for the facility. He warned that utilities “don’t want to wait for me to do that.”
“Texas RE shouldn’t be the one that provides you that periodic review … because if we find something, we’d have to report it, and there have been quite a few facility ratings non-compliances over the last several years,” Crews said.
To help attendees understand how Texas RE assesses a utility’s approach to ratings, Crews shared a list of evidence that auditors look for during their reviews. In addition to a detailed FRM, the RE aims to verify the results against the utility’s facility ratings database using manufacturer specifications and nameplate photos, one-lines and elevation drawings, and any other information that may help to independently establish the rating.
The presentation also contained a list of issues commonly identified during audits, including change-management process gaps — that is, failure to make sure that changes to field equipment are reflected in the ratings database — or omitting an element from the FRM. Crews acknowledged the latter error “doesn’t happen too often, but it has happened across the ERO Enterprise.”
Other issues include failure to maintain the one-line and elevation drawings, or inconsistencies between different records containing the same drawings; failure to account for jointly owned facilities; insufficient processes for keeping track of series elements; and lack of clarity in documentation.
In addition to technical evidence, auditors may look for indications of lax culture at the entity. These could be lifting language directly from the standard to use in the FRM with no modification for the case at hand, or not being able to demonstrate consistent application of the FRM in practice. Another sign that an entity has not done a thorough job is the use of the same ratings for normal and emergency situations.
Crews emphasized that while REs sometimes must penalize utilities as a result of compliance audits, their goal is to help build a reliable grid, rather than to punish wrongdoers.
“That is part of our role, to help ensure reliable operations through effective compliance monitoring, and I think that’s the heart” of what Texas RE does, Crews said. “I used to be at a registered entity, so I understand the ramifications of an audit, and I understand the implications of trying to operate in a reliable situation, given the complex issues like facility ratings.”
FERC and state regulators embraced cluster studies but gave mixed reviews to “fast track” processing as potential solutions to clogged interconnection queues Friday during the third meeting of the Joint Federal-State Task Force on Electric Transmission.
The task force, which includes FERC members and 10 state regulators, was created by FERC Chairman Richard Glick in June to unleash transmission expansion to improve resilience and connect new renewable generation (AD21-15).
FERC Commissioner Willie Philips laid out the first problem at the beginning of the five-hour meeting, noting that interconnection costs, which used to be less than 10% of generators’ total project costs, can now exceed 50%.
“The serial, first-come-first-serve study process incentivizes developers to enter into the queue before they are ready. They do this so that they can snag a spot in line. Interconnection customers also submit multiple interconnection requests at different locations even though they know that not all of them will reach commercial operation,” he said. “They do this to find where they can get the least amount of network cost upgrades. Then there are often late-stage withdrawals or material modifications to projects, which means that transmission providers must conduct restudies. Ultimately this is harming the ability of transmission providers to timely process the queue.”
Jonathan Raab — president of consultancy Raab Associates and facilitator of the meeting — cited data from Lawrence Berkeley National Laboratory showing that the typical duration from connection request to commercial operation has nearly doubled, from 2.1 years in 2000-2010 to 3.7 years for 2011-2021. Only 23% of projects that requested interconnection in 2000-2016 have reached commercial operations, with only 20% of wind projects and 16% of solar completed.
In contrast with the first two meetings, “we’re not just asking questions this time,” Raab said. Instead the meeting sought feedback on five potential improvements:
tighter applicant requirements to enter or remain in the queue;
clustering of applications and areas for studies;
faster tracks for different generator categories (e.g. state solicitations or smaller resources with limited impacts);
tighter study deadlines for RTOs and other transmission providers; and
minimizing restudies.
FERC Warned Against Undermining State Efforts
Several state regulators urged FERC not to issue a sweeping rule that could undermine progress some jurisdictions have made.
Chair Thad LeVar, Utah Public Service Commission | Utah Public Service Commission
Utah Public Service Commission Chair Thad LeVar said that while the interconnection queue process is “easy … to criticize,” policymakers should recognize “the significant reform efforts that many transmission providers across the country have been engaging in in recent years.”
“The specific issues that we’ll be talking about over the next couple hours aren’t new concepts that nobody’s been trying,” he added.
“I’ve heard from the SEARUC [Southeastern Association of Regulatory Utility Commissioners] states as well as some RTOs like PJM,” North Carolina Utilities Commissioner Kimberly Duffley said. “And they request that FERC allow queue reforms to move forward regionally without the disruption of possibly inconsistent requirements.”
Duffley said North Carolina officials are optimistic about recent changes to the queue procedures of Duke Energy Carolinas and Duke Energy Progress.
Commissioner Kimberly Duffley, North Carolina Utilities Commission | North Carolina Utilities Commission
The state has been a leader in utility-scale solar, Duffley said, but beginning about 2014, the first-come-first-serve interconnection queues began experiencing backlogs and queue-squatting complaints.
The addition of new financial security requirements in 2015 provided some relief, she said, but proved insufficient. Additional changes were approved by FERC last August (ER21-1579), following endorsements by the NCUC and South Carolina Public Service Commission, replacing the serial study process with a first-ready-first-served, cluster-based study process.
Duffley said the impact of the new rules, which were based on those of Public Service Company of Colorado, won’t be known until the first quarter of 2023.
“I believe that the RTO and the system planners are best positioned to structure interconnection rules for their individual regions, and that prescriptive one-size-fits-all interconnection rules are not necessary,” said Gladys Brown Dutrieuille, chair of the Pennsylvania Public Utility Commission. “That being said, I think that FERC is in a position that they can encourage interconnection efficiencies throughout the country by promoting best-in-class processes, such as variations in ways to cluster projects.”
Support for Cluster Studies
There was wide support for cluster studies, which allow transmission providers to consider many projects in one study. Supporters say restudies are less frequent and disruptive because generators in a cluster can share the cost of network upgrades.
Phillips said cluster studies should be considered a best practice.
“Almost all RTOs and ISOs have used a cluster approach for years, and PJM is currently working on a cluster proposal right now,” he said. “Several transmission providers outside of the RTO regions have also started moving to a cluster approach in recent years.”
PJM will file with FERC later this month a proposed interconnection queue process that moves away from the first-come-first-served model to a first-ready-first-served concept. “That will make the process somewhat quicker, maybe as quick as 450 days … and that would cut down from an average of somewhere in about 700 days,” said Jason Stanek, chair of the Maryland Public Service Commission. (See PJM Stakeholders Endorse New Interconnection Process.)
Vermont Public Utility Commissioner Riley Allen said clustering can help identify “backbone or … trunk facilities” that provide efficiencies in the system for ratepayers’ benefit.
LeVar said cluster studies also have been helpful in Western states’ review of utility integrated resource plans that result in solicitations for new resources. “There’s usefulness to best practices. But these best practices are going to operate differently in each RTO and particularly between the RTO and non-RTO areas,” he cautioned.
California Public Utilities Commissioner Clifford Rechtschaffen said CAISO’s use of cluster processes has been “very helpful” but “is not a panacea.”
“Last year in CAISO, in one cluster in two weeks, there was 100 GW of applications filed in a single window, which is 10 times the amount of authorized procurement,” he said. “So clustering absolutely helps … but it has to be accompanied by the other reforms that we’re talking about.”
Fast Track
There was less unanimity over fast-track proposals.
Stanek called clustering and fast-track processes “Siamese twins. They’re very different, but they have some similarities that lead to overall efficiencies.”
He suggested fast tracking generation seeking to locate at the sites of retiring plants such as the Oyster Creek nuclear plant in New Jersey and the Indian River coal facility in Delaware, saying it could reduce the need for expensive reliability-must-run agreements.
“Perhaps the standard interconnection process would not be as arduous if we’re using existing switchgear and existing substations behind the fence,” he said. “Taking advantage of the fact that these points have already been modeled, it shouldn’t take 1,000 days or four years for … some generator to step into the shoes of an existing generator.”
Arkansas Public Service Commission Chair Ted Thomas said he agreed “conceptually” with using milestones such as financing and site control to prioritize the queue. “But while we work on those solutions, I also think that we need to be conscious that we not make this a game that only large players can play.”
Glick said any fast track would have to be crafted carefully to ensure it does not violate the Federal Power Act’s prohibition on “undue discrimination.”
“If you start saying small resources have a separate category and make it some expedited approval, that actually might, I think … come across as discriminatory.”
Tighter Requirements
Task force members also expressed concerns over tightening queue eligibility requirements.
Michigan Public Service Commission Chair Dan Scripps | Michigan Public Service Commission
Dan Scripps, chair of the Michigan Public Service Commission, said increasing applicant requirements “could ultimately delay projects that we’re going to need, even if we don’t know who the specific off-taker is today.”
“If I go back to the old … saying that ‘all regulation is incentive regulation,’ in some ways we’re getting the system that we’re encouraging here,” he said. “When you talk to developers, they say the length of the time to get through the queue processes encourages the speculative or placeholder nature of a lot of the projects.”
Transmission Providers’ Accountability
Commissioner Allison Clements said she had concluded that FERC’s attempt at “incremental reforms” in Order 845 in 2018 “hasn’t worked.” The order sought to increase the transparency and timeliness of the interconnection process. (See FERC Order Seeks to Reduce Time, Uncertainty on Interconnections.)
She solicited feedback on ways FERC can ensure transmission providers are meeting their obligations, noting that PJM reported to the commission that 99% of its facilities studies failed to meet tariff deadlines in 2021. She said it is unfair that queue participants are held to strict deadlines while transmission providers are only required to make “reasonable efforts” to meet deadlines.
“Interconnection customers facing steady delays have little recourse when a transmission provider misses a deadline, because the reasonable-effort standard is not a particularly high bar,” she said. “We need to make some sort of modification to the … reasonable-effort standard.”
Among the options are penalties, for which “we’d have to think about the specifics of force majeure exemptions; waivers; amount of the penalty,” she said. “What would we use the penalty for? When [would] the penalty start?”
She said transmission providers also could be required to devote more staff, software and other resources to interconnection, or subject to additional public reporting requirements — “a scorecard relative to performance.”
LeVar said regulators should consider “what barriers might exist to individual generators [and focus on transmission provider] outliers, the ones that aren’t trying to engage in reform and are making the good-faith efforts that many are.”
Affected-system Studies
Scripps urged FERC to set standards regarding cross-RTO affected-systems studies, which, he said, “have the ability to destroy project economics” and have become “a growing source of delay and cost uncertainty for interconnection customers.”
“We expect the affected-system study process to become increasingly critical as more renewable resources come online in renewable-rich areas and transmission capacity becomes ever more scarce,” he said.
In 2018, a FERC technical conference resulted in a September 2019 order requiring MISO, PJM and SPP to improve the transparency of their affected-system studies. (See Affected-system Rules Unclear, FERC Says.) But Scripps noted the commission declined to open a generic proceeding to address broader affected-system coordination issues.
“We saw in the filings from MISO, SPP and PJM that were done in 2019 and 2020 [that] the delays continue to persist and often due to the underlying issues that were brought to light in that technical conference. Namely each RTO’s process and study times are different and tailored to the region.
“It may be time to revisit the commission’s 2019 decision not to initiate a proceeding to better coordinate affected-system studies. Specifically, there may be an opportunity to create a general framework that would be consistent across RTO seams,” he said. “Fully addressing these cross-RTO issues are inherently beyond any one RTO’s or ISO’s ability to fully control.”
Arkansas’ Thomas said he agreed “word for word” with Scripps. “The most effective place that FERC can operate is in the area where you have two RTOs, and the real issue is getting them on the same page. I think that FERC should start gently and move towards less gentle as needed.”
Transmission Planning
Maryland’s Stanek said reform of the generator interconnection process is interlinked with that of transmission planning. “They’re both interdependent elements of developing needed transmission infrastructure and share many of the very same principles and challenges,” he said. “A very key difference here is that the generator interconnection needs are much more focused and much more immediate. This is an issue that we can tackle now and not have to wait 20 years to see if the fruits of our labor yield success. How well these new processes are implemented will determine that success.”
Andrew French, chair of the Kansas Corporation Commission, said the queue backlog is “a symptom of queue-based planning.”
“While we need to, in the interim, try to address the demand for those resources and addressing what’s in the queues now, we can’t lose sight of the fact that the ultimate long-term solution is better long-range planning,” French said.
Vermont’s Allen said, “There’s a growing body of evidence, especially from PJM and MISO, that we can actually interconnect much more capacity going forward if we do it in a very anticipatory long-term planning framework than on a serial or even a … cluster-by-cluster framework that is the prevailing paradigm.”
On April 21, FERC issued a Notice of Proposed Rulemaking that would require transmission providers to use scenarios and probabilistic techniques to identify potential infrastructure needs 20 years into the future based on decarbonization policies and industry trends. (See FERC Issues 1st Proposal out of Transmission Proceeding.)
Cure for What Ails Us
French said the queue backlogs may not be quite as bad as they seem because so many queue entries are “placeholder projects” used for cost discovery on required transmission upgrades.
“If we were able to create some good large amounts of backbone capacity on the transmission system … and put it in the optimal place, you might actually see quite a bit of generation be able to be interconnected, and the backlogs could clear perhaps more quickly than we would think,” he said.
He added, “I know it’s never easy to just snap your fingers and [create] backbone transmission.”
The second half of Friday’s meeting of the Joint Federal-State Task Force on Electric Transmission started off with a touch of irony.
“Now we’ll move on to the much less controversial issue about funding and cost allocation” of transmission projects, Jonathan Raab — president of consultancy Raab Associates and facilitator of the meeting — said about a topic that has sparked sharp disagreements in organized electricity markets across the country.
The first part of Friday’s conference of federal and state regulators focused on clogged generation interconnection queues in RTOs and ISOs. (See related story, FERC-State Task Force Considers Clustering, ‘Fast Track’ to Clear Queues.) The next half delved into the even thornier issue of who should pay for the needed transmission network upgrades spurred by the interconnecting resources piling up in the queues.
The issue of cost allocation has grown in controversy as the grid integrates increasing volumes of renewable resources. Developers must often site renewables far from load centers, other generating resources and existing high-voltage transmission lines in order to cover enough ground to capture economies of scale and locate in areas that offer higher capacity factors resulting from more consistent winds or sunlight.
“In recent years, I think we’re at a point where the changing resource mix has already triggered a number of challenges, and the solutions required are effectively transmission solutions,” Michigan Public Service Commission Chair Dan Scripps said in opening remarks.
“It’s not that we’re building out backbone transmission projects in order to simply accommodate generators, but really to keep the lights on. And whether we continue to allocate a disproportionate share of the cost to interconnecting generators in order to fulfill this reliability imperative, I’m not convinced that the current model strikes the right balance,” he said.
Not ‘From All to Nothing’
Friday afternoon’s discussion aimed to get closer to that balance. Raab framed the session by outlining four cost allocation approaches for the regulators to consider, including:
participants (i.e., the generators) paying for 100% of the costs for network upgrades in RTOs/ISOs;
participants and load sharing the costs for upgrades;
load picking up 100% of the cost for certain types of upgrades; and
costs for new or upgraded facilities being covered by generator subscriptions.
State regulators have generally supported the first option, with some flexibility — and some notable deviations.
In its comments on FERC’s 2021 Advance Notice of Proposed Rulemaking to improve regional transmission planning, cost allocation and interconnection processes (RM21-17), the National Association of Regulatory Utility Commissioners urged the commission to “retain the core tenet of participant funding, while exploring the as yet untapped potential economies of scale that could result from increased coordination among participants,” such as through clustering of projects. (See FERC Goes Back to the Drawing Board on Tx Planning, Cost Allocation.)
On Friday, FERC Commissioner Allison Clements encouraged industry stakeholders to be flexible in their thinking about cost allocation.
“I don’t think the solution is going from all to nothing. I don’t think that, while interconnection customers currently pay off needed upgrade costs, the solution should be jumping to having them pay nothing. That doesn’t jive with [FERC’s] cost allocation principles,” Clements said.
“I’ve never had a project sponsor suggest to me that they’re unwilling to pay their fair share, and I’ve also never had a transmission provider suggest to me that in all, or even in most cases, the whole of network upgrade benefits accrue only to the interconnection customer customers paying for them,” she added.
“I am a believer that when we make certain high-voltage upgrades as part of the [generator interconnection] process, there are real benefits that flow to load,” Kansas Corporation Commission Chair Andrew French said.
Changes to cost-sharing models should not be a “one-way street” directed only at electricity customers, according to French.
“This is not just about getting load to pay more, or to chip in more of the cost to help interconnect generators. It’s to try to find the most accurate cost allocation over all of our investments,” he said.
French pointed out that SPP’s regional planning process can produce a “big backbone” project on which generation developers can “basically free ride for a few years” without dealing with many upgrades.
“They don’t have to pay anything for them, and that’s the situation we were in for maybe the last 10 years before we ran out of capacity,” French said. “I just want to make the point that, ultimately, we need to get to a more holistic, consolidated planning process.”
The intertwining relationship between transmission planning and cost allocation was a recurring theme during the discussion.
Michigan’s Scripps encouraged fellow regulators to avoid “siloing” the cost allocation issue “because it really does connect with a number of other concerns, and I’d argue that participant funding reform should go hand-in-hand with interconnection key reforms.”
Pennsylvania Public Utility Commission Chair Gladys Brown Dutrieuille noted that there isn’t a consensus of support for a 100% participant funding model within the Mid-Atlantic Conference of Regulatory Utilities Commissioners, which she was representing during the meeting. But she also emphasized the support for that model in her own state, which deregulated its electricity market to offload generation investment risks from ratepayers.
“The participant-funding model is based on the tried-and-true ratemaking principle of cost causation. And I just want to highlight what I believe its benefits include: and that would be promoting efficient siting of generation projects, as well as allowing parties that are best positioned to control the interconnection costs to bear the costs.”
North Carolina Utilities Commissioner Kimberly Duffley said there’s a “strong consensus” within the Southeastern Association of Regulatory Utility Commissioners and the industry at large for maintaining the participant-funding model. Duffley cautioned that straying from that model could saddle ratepayers with costs for transmission projects they neither want nor need.
“Enjoyed listening to Commissioner Dutrieuille. Enjoyed listing to Commissioner Duffley,” FERC Commissioner Mark Christie said. “All I can say is, ‘What she said — twice.’”
FERC Chair Richard Glick and Commissioner Willie Phillips both reminded their fellow regulators that judicial precedent requires the commission to look beyond participant-driven costs to consider wider system benefits.
“There’s a number of cases where the courts have essentially said cost-causation really is benefits, and you have to look at who benefits in terms of who pays,” Glick said.
Sharing the Cost
“I believe that cost sharing might actually be more cost-effective for consumers overall, because it could provide some incentive for [transmission owners] to proactively plan and build the optimal transmission lines in the first place,” Phillips said when the subject turned to an allocation approach that splits costs between generators and load.
Phillips pointed favorably to CAISO’s model in which TOs are required to refund upgrade costs back to generators within five years of a project’s operation date, as well as the MISO model where load pays 10% of transmission upgrade costs for lines rated at 345 kV or above.
California Public Utilities Commissioner Cliff Rechtschaffen said that CAISO’s practice was designed to ensure that generators have financial “skin in the game” before seeking interconnection.
“The generator still covers the cost between the generation facility and the point of interconnection. The costs that are covered by this policy are the reliability, substation and deliverability backbone upgrades,” Rechtschaffen said, adding that CAISO caps the level of reimbursement.
“Only upgrades that are needed to meet resource adequacy requirements are reimbursable. So that ensures that the load that’s charged for the upgrades is benefiting and adhering to the beneficiary-pays principle that is so important,” he said.
“I think to the extent that we’re looking for something with relative simplicity, and something with a framework that FERC is familiar with and has approved in the past, a voltage threshold [as in MISO] would seem to make sense,” Maryland Public Service Commission Chair Jason Stanek said.
Dutrieuille called the MISO cost-sharing mechanism “intriguing” and “easy to understand,” but she was reluctant to endorse it. “I would make sure that we understood what the benefits were … [and that] you can quantify them, and they’re not speculative in nature.”
Arkansas Public Service Commission Chair Ted Thomas said as the electricity grid continues to undergo its transition, the “right transmission plan” should function as the shared cost. “Doing that right, there shouldn’t be that many remaining shared costs. That’s a critical point,” he said.
‘Relatively Agnostic’
An allocation approach in which load bears 100% of the costs for transmission upgrades found no support among the commissioners, but a model in which generator subscriptions supported the development of new or upgraded infrastructure sparked some interest.
Stanek pointed out that FERC has used the subscription model in the past for natural gas pipelines and some merchant transmission projects.
“I think some of the benefits that could flow from this would be a faster interconnection process, efficiency and, probably most important to this afternoon’s conversation, making sure that the costs of this upgrade would be paid for in a fair and equitable manner,” Stanek said.
“It’s a framework that I think addresses some of the big thorny knots that we’re dealing with when we talk about free ridership, lumpy and large payments, cost uncertainties — some of the big things that we can’t seem to kind of get around,” Vermont Public Utility Commissioner Riley Allen said.
Allen likened the subscription model with ISO-NE’s cluster interconnection process, in which the RTO assigns the costs for major transmission upgrades to clusters of interconnecting resources. He envisioned a way of scaling up that process for “superclusters” of resources in allocating costs for upgrading a larger backbone system. Instead of being responsible for incremental upgrades to a network on an individual basis, interconnecting generators could be allocated costs based on a per-megawatt fee.
He also proposed the further step of adopting Vermont’s system of using a cost “adjuster” to steer development to areas of the system that already have existing capacity. “So it kind of checks a number of boxes, at least for me, in terms of getting around the problem, working our way past the kind of participant-pays versus load-pays, because this is relatively agnostic,” he said.
“I think the proposal that Commissioner Allen just outlined would be very helpful when in terms of offshore wind if you build a collector system. That’s probably the fairest way of allocating the cost,” Glick said.
Speaking as the lone representative from the “non-RTO West,” Utah Public Service Commission Chair Thad LeVar noted that issue of participant funding is not something the region currently wrestles with. But LeVar cautioned FERC about developing cost allocation rules that could “chill” the West’s efforts toward increased regionalization and — “hopefully” — an RTO.
“I would hate to see the RTO rules that don’t currently apply to us evolve in a way that would scare off stakeholders from the work that’s happening across the West,” he said.
‘A Little Less Consensus’
In wrapping up the meeting, Glick said it was evident there appeared to be “a lot of consensus” on how to address logjams in RTO interconnection queues, and “a little less consensus” on cost allocation for transmission upgrades.
Glick said the lack of agreement was “not surprising” given NARUC’s comments on FERC’s ANOPR last year and the divergent opinions among states on the need to “reform” cost allocation rules.
“So that’s something we need to consider as well, and we’re certainly cognizant of all the actions that are going on at the state level,” he said. “And whatever actions we take at FERC, I think we certainly will, at least from my perspective, take into account what the states are doing and certainly not try to reverse or impede the progress that the states are making.”
PPL reported a positive first quarter during its earnings call on Thursday after announcing earlier in the week that it will raise its default electricity rates by 38% for residential Pennsylvania customers on June 1.
The company reported first-quarter earnings of $273 million ($0.37/share), compared with a first-quarter 2021 net loss of $1.84 billion (‑$2.39/share). Adjusting for special items, PPL’s earnings were $305 million ($0.41/share), compared with $219 million ($0.28/share) a year ago. Some of those items included integration expenses from the planned acquisition of Narragansett Electric from National Grid and last year’s non-cash net loss from its discontinued operations associated with PPL’s former U.K. utility business, Western Power Distribution.
PPL’s rebound comes after the company cut its dividend in half and missed earnings and revenue targets in the fourth quarter of 2021. (See PPL Announces Losses, Dividend Cut in Q4 Call.)
This year’s rate increase will add about $34/month to the average bill. The residential rate will rise to 12.366 cents/kWh, while small businesses will pay 11.695 cents/kWh.
CEO Vincent Sorgi said PPL is “very focused” on making sure customers are familiar with programs to help lower their rates and to also “provide flexible payment plans” like those instituted at the height of the COVID-19 pandemic.
“Commodity prices are way up this year versus last year,” Sorgi said. “That’s a pass-through cost for us, but it’s upwards this year versus last. It could be as much as 50 to 60%, so it is very significant. We are actively reaching out to our customers to help them.”
Narragansett Deal
PPL continues the acquisition process of Narragansett, Sorgi said, with the company receiving approval in late February from the Rhode Island Division of Public Utilities and Carriers. (See RI Agency Approves PPL Acquisition of Narragansett Electric.)
The Rhode Island attorney general’s office appealed the division’s decision to the state Superior Court, receiving a stay of the approval. PPL and other stakeholders provided oral arguments on April 26, with the AG’s office contending that the division misapplied the statutory standard for approval and failed to adequately consider Rhode Island’s Act on Climate in its analysis.
“We disagree and believe the extensive record and evidence in this case demonstrate that the division properly applied the statutory standard and correctly approved the transaction,” Sorgi said. “We continue to believe Narragansett Electric is an excellent fit for PPL and that PPL is an excellent fit for the state of Rhode Island. We remain confident that we will reach a positive outcome in the proceeding.”
Kentucky Operations
Sorgi also highlighted PPL’s Kentucky segment, which earned 25 cents/share for the first quarter, a 7-cent increase over a year ago and attributable to higher base retail rates that took effect July 21.
Ford Motor Co.’s announcement that it will build a $6 billion battery manufacturing complex within PPL’s service territories in Glendale, Ky., “will help put the state at the forefront of the auto industry’s transformation to electric vehicles,” Sorgi said. To support the project, PPL subsidiary Kentucky Utilities has requested regulatory approval to build two 345-kV and two 138-kV transmission lines and two new substations at an estimated cost of up to $200 million.
Sorgi said Kentucky Utilities is continuing to look for opportunities to advance clean energy technologies, including joining the state’s new hydrogen hub initiative in February. “We’re excited to join this new hydrogen hub initiative, and we will continue to engage with the Kentucky administration and other stakeholders as the state’s clean energy strategy evolves.”
He also said that based on PPL’s current coal plant retirement schedule, the company expects its coal capacity to be reduced from just over 4,700 MW to about 550 MW in 2050. The remaining capacity is the Trimble County 2 plant in Kentucky, which was completed in 2011.
“There are any number of technology developments, regulatory mandates or circumstances that could impact the timing of the end of this plant’s economic life,” Sorgi said. “We believe that research and development is key to our clean energy future and fully expect that innovation, technological advances and the relative economics of other cleaner energy sources will support the company’s commitment to not burn unabated coal at this facility by 2050.”
The U.S. Commerce Department’s probe into tariff evasion by Chinese importers of solar panel components has prolonged the life of one northern Indiana coal plant by two years.
NiSource said during its May 4 first-quarter earnings call that it will postpone retirement of the R.M. Schahfer plant’s remaining two units from 2023 to 2025 because the investigation is stalling its development of solar facilities meant to replace the 877-MW facility.
The retirement raincheck is one of the first ripple effects since the federal government began its investigation in April. (See Solar Sector Braces for Tariff Probe Impact.)
In a press release, NiSource explained that the probe has “brought uncertainty and delays to the solar panel market.” It said it was working with its renewable energy developers to “better understand the potential project impacts.”
Shawn Anderson, NiSource chief strategy and risk officer, said the utility’s 10 solar and energy storage projects slated to come online over this year and next now face delays of six to 18 months.
“Our focus has been to accelerate savings for our customers to benefit from the renewable transition, and delays resulting from this investigation may ultimately delay the timing of when our customers could begin receiving these benefits, especially in the current energy cost inflationary environment,” Anderson said during the call.
The utility plans to idle all its coal plants by 2028 and cut its carbon emissions 90% from 2005 levels by 2030. Despite the deferral, NiSource said its clean-energy goals remain unchanged. The company said it expects to retire its Michigan City Generating Station sometime between 2026 and 2028.
NiSource also said despite solar development delays, it remains on track to spend $10 billion in capital investments, including $2 billion on renewable projects, between 2021 and 2024. The utility said it has planned “flexibility in the timing of other gas and electric infrastructure capital investments that can allow adjustments to compensate for delays in renewable generation projects.”
