Search
`
November 17, 2024

Posted on

FERC Clarifies When Board Appointees Make Companies Affiliates

FERC on Thursday ruled that it will deem companies it regulates as affiliates if one nominates its own members, investors or employees to another’s board of directors.

The commission issued two orders regarding separate transactions that both required it to determine whether the companies involved — TransAlta (NYSE:TAC) and Brookfield Asset Management (BAM) (NYSE:BAM) in one, and Bluescape Energy Partners and Evergy (NYSE:EVRG) in the other — were affiliates of each other. FERC applies stricter oversight of affiliated companies and their transactions to, for example, determine market-based rate authority and screen against market manipulation.

“It’s very important that we have the kind of insight to understand when parties are affiliated so we can do a better job of regulating” them, FERC Chair Richard Glick said during the commission’s monthly open meeting. “If one company … essentially names board members to another company [who are] affiliated with the first company, then we’re going to deem that an affiliate relationship.”

TransAlta and Brookfield

In one of the orders (EC22-45), the commission addressed an application for a change in control affecting Canada-based TransAlta, based on a shift in company holdings controlled by BAM, a global investment firm.

TransAlta has an extensive presence in U.S. electricity markets through its two power marketing divisions and its ownership of several wind assets and the 730-MW coal-fired Centralia Generation Station in Washington. BAM is affiliated with six power marketing companies in the U.S. and with other entities that own or control generation assets across the country.

In 2019, BAM affiliate Brookfield BRP Holdings (Canada) Inc. purchased debt securities in TransAlta with an option for converting to an equity interest in TransAlta’s hydroelectric assets in Alberta, Canada.

In their application to FERC, filed in March 2022, TransAlta and BAM said the debt securities did not confer any equity voting rights in TransAlta and are not convertible into an equity interest in any of TransAlta’s U.S. assets. But the transaction did result in the expansion of TransAlta’s board from 10 members to 12, two of which would be nominated by BRP while it holds the debt securities.

The debt securities agreement also included a “standstill agreement” that established barriers to control during a “standstill period” expected to end around May 1, 2022. That agreement included a number of provisions, including a restriction on BRP or its affiliates (including BAM shareholders) acquiring more than 19.9% of TransAlta’s shares, engaging in any takeover activities, effecting other restructurings and asset sales, and seeking to obtain additional representation on the board, among other activities.

“In addition, applicants state that the standstill agreement provides that any voting rights associated with shares in TransAlta owned by [BRP] or its affiliates must be exercised in favor of the board’s management nominees and voted in accordance with any recommendations by the board on all other proposals and matters, including director appointments and removals, at annual shareholder meetings,” FERC noted in its order. “Applicants argue that as a result, [BRP], shareholders and other BAM affiliates currently have no discretion to vote any common shares, except solely with respect to a board-recommended extraordinary transaction that would result in a person acquiring more than 50% of the outstanding common shares.”

The companies told FERC that BAM shareholders increased their aggregate holdings in TransAlta’s common shares to 10.1% in March 2020 and now own 13% of the shares. Before expiration of the standstill agreement, they sought the commission’s approval for BAM affiliates to own, with power to vote, 10% or more of common shares.

“Applicants state that because termination of the standstill agreement would result in a change in control over the TransAlta companies if shareholders, together with any other BAM affiliates, own 10% or more of the common shares, applicants request commission authorization for the proposed transaction and associated change in control over the TransAlta companies,” FERC wrote.

The companies contended that, despite BAM affiliates already exceeding 10% ownership, the standstill agreement ensured that BAM and its affiliates could not control TransAlta or its subsidiaries.

“Therefore, applicants argue that a change in control requiring prior commission approval will not occur until the expiration of the standstill provisions, anticipated to occur on or about May 1, 2022,” FERC wrote. “We disagree.”

The commission specifically disagreed with TransAlta and BAM citing FERC’s 2009 decision in Cascade Investment, L.L.C. (EC09-78) to support their contention that the initial investment that elevated BAM and affiliate ownership above 10% did not result in a change of control because of the limitations set out in the standstill agreement. It noted that the Cascade proceeding involved a standstill agreement that included provisions intended to restrict Cascade Investment’s ability to control a public utility through ownership in a holding company, Otter Tail Corp. Those provisions included limiting Cascade’s holding to less than 20% of Otter Tail’s voting securities, a commitment not to seek a seat on board of either Otter Tail Corp. or Otter Tail Power, and a commitment not to influence Otter Tail’s operations or the price at which it sold power.

The TransAlta/BAM proceeding differed in key ways, the commission said:

  • The application in Cascade was filed before the acquisition of 10% or more voting securities in Otter Tail, whereas BRP and other BAM affiliates had acquired 10.1% of TransAlta in March 2020, which is above the threshold provided in FERC’s blanket authorization of such transactions.
  • Unlike in Cascade, the BAM affiliates have placed two directors on TransAlta’s board, arguing that holding two seats is insufficient to gain control of the board given its large size and independent composition. But the commission pointed out that it has concerns with structures where the investor itself will be represented on the board, “which confers rights, privileges and access to nonpublic information, including information on commercial strategy and operations,” as noted in FERC’s other decision issued Thursday (see below).
  • Although the TransAlta standstill agreement contains limitations on the ability of the affiliates to vote shares, it does not contain explicit prohibitions regarding the ability to influence the day-to-day operations of TransAlta, unlike in Cascade.

“We find that contrary to the requirements of [Federal Power Act] Section 203, applicants failed to file a timely request for the disposition of a public utility and acquisition of securities,” the commission wrote. “Specifically, applicants were required to receive commission approval prior to the acquisition by shareholders of greater than 10% of the outstanding TransAlta shares. While we take no further action here, applicants are reminded that they must submit required filings on a timely basis or face possible sanctions by the commission.”

Still, the commission did approve the companies’ application, finding the change in control would have no impact on competition, rates and regulation, nor would it result in cross-subsidization.

Bluescape and Evergy

In a similar proceeding, the commission found that Dallas-based Bluescape is “individually an affiliate” of Evergy and directed the Midwest utility’s operating companies to submit additional information within 30 days so that FERC can process a notice of change in status (ER20-67, ER20-113, ER20-116).

FERC said that Evergy’s appointment of C. John Wilder, Bluescape’s executive chairman, to its board of directors presented a “concern” the commission previously expressed in a proceeding involving CenterPoint Energy. The commission said then that it had an issue with “structures where the investor itself would be represented on the board through the appointment of the investor’s own officers or directors, or other appointee accountable to the investor, in order to support a finding of control.”

“Where an investor’s own officer or director … is appointed to the board of a public utility or holding company that owns public utilities, the investor itself will have those rights, privileges and access, and thus the authority to influence significant decisions involving the public utility or public utility holding company,” FERC said. “As a result, we find that the appointment of a non-independent director from Bluescape to the Evergy board rebuts the presumption of lack of control … and that Bluescape is deemed to be an affiliate of Evergy.”

The commission directed Evergy’s subsidiaries to update their asset appendix with all of Bluescape’s energy affiliates and their associated assets, as well as their horizontal and vertical market power analysis with their affiliates’ generation and transmission assets and inputs to electric power production.

Evergy’s subsidiaries in September 2020 filed a notice of change in status regarding changes to their upstream ownership. This came shortly after Evergy said it would remain a standalone company after exploring several purchase offers by other companies. (See Evergy Releases Standalone Plan Details.)

FERC twice filed deficiency letters in 2021 requesting more information on the upstream ownership. Public Citizen and the Communications Workers of America filed a joint protest in November 2021.

In its Thursday order, the commission found another investment management firm, Elliott Management, was not an Evergy affiliate. It said the record indicated Elliott owns less than 10% of Evergy’s outstanding voting securities and said Public Citizen did not present enough evidence to rebut the presumption of lack of control under federal regulations.

FERC ruled that Elliott’s appointment to Evergy’s board, former U.S. Sen. Mary Landrieu (D-La.), is independent and not compensated by Elliott.

Wilder and Landrieu were named to the board in February 2021, with Wilder also chairing the Finance Committee.

Tyson Slocum, director of Public Citizen’s Energy Program, still applauded the ruling as a “a win for consumers, market integrity and protection from corporate raiders.”

“For utilities with captive ratepayers, all affiliates can only engage in financial transactions with the utility at arm’s length,” Slocum said in a statement. “This prevents an investor from selling services at inflated costs, and then having the utility recover those inflated costs from ratepayers. Today’s order ensures that banks, hedge funds and private equity funds that seek to control a utility’s board cannot engage in such abusive practices.”

Speaking to reporters after the commission’s meeting, Glick said, “This is about consumer protection. If you have affiliates engaging in self-dealing, and we have no way of knowing it or seeing it because we don’t consider two entities affiliates, we’re not going to be able to protect consumers adequately enough.” He also said the rulings would provide certainty to companies so that they know when they would be considered affiliates.

Posted on

RFF Summit Seeks Effective, Efficient, Equitable Paths to Net Zero

WASHINGTON, D.C. — Resources for the Future (RFF) CEO Richard Newell opened his organization’s Net Zero Economy Summit on Thursday by zeroing in on why international goals to limit global warming and climate change have been so hard to translate into action.

“No single nation directly controls atmospheric concentrations or, indeed, the Earth’s temperature. These are byproducts of something else — emissions,” Newell told the audience of about 300. “This is why targeting emissions such as carbon dioxide and methane is so important, because emissions are something we can control and drive down.

“Net zero brings the challenge of climate change down to the level of a balance sheet: emissions in, removals out,” he said. “The same economic forces that contributed to a problem could be harnessed to fix it.”

Newell’s comments provided a focus for the daylong summit, which dug into the complex nexus of economics and politics surrounding net-zero initiatives in the U.S. and worldwide, the progress being made and the systemic inertia that continues to slow the transition.

Richard Newell 2022-10-20 (RTO Insider LLC) FI.jpgRichard Newell, RFF | © RTO Insider LLC

On the progress side, Newell said, setting net-zero goals, as 139 countries have done, “focuses everyone’s attention on an outcome that can be directly controlled, something that’s scientifically consistent with stabilizing the environment and something that’s technology-inclusive, open to innovation and ready to harness the power of incentives.”

“Net zero is also scalable at multiple levels for a wide range of decision makers” — from national to state to individual cities and businesses, he said.

But, even with the billions in new funding to advance the U.S. energy transition in the Infrastructure Investment and Jobs Act and the Inflation Reduction Act, the gap between aspiration and action still remains, said Ali Zaidi, White House national climate advisor.

“Code red is no longer a line in an IPCC report,” Zaidi said, referring to the most recent report from the UN International Panel on Climate Change, which predicted potentially catastrophic impacts from climate change without “deep reductions” in greenhouse gas emissions in the coming decades.

“The big, defining question of this moment is not whether we acknowledge that this is the decisive decade; science has acknowledged that for us,” Zaidi said in his summit keynote. “The question is, are we going to put the steel in the ground? Are we going to make the decisions?

“We have gotten very used to analyzing and aspiring and failing to take action,” Zaidi said. “If we fail to do that, no matter how beautiful our model looks in 2040 or in 2050, that’s not going to solve the problem, and we will have failed to meet the moment.”

“We have gotten really, really good at stopping things from happening,” agreed Matt Rogers, former CEO of the Mission Possible Partnership, an alliance of organizations working on decarbonizing heavy industry, such as steel, cement and chemicals. “Now we need a whole new muscle that says, ‘How do we make things happen? How do we build projects … at scale?’ That is an essential element at the federal level, at the state level, at the local level.”

The steel industry, for example, has a major opportunity for decarbonization, Rogers said, during a session on industrial decarbonization. Coal-fired steel blast furnaces need to be refurbished or rebuilt every 15 years “because you’re operating at such a heat level, the bricks get brittle,” he said.

“Between now and 2035, every blast furnace in the world has to go through turnaround,” which could allow all those plants to convert from coal to some form of clean hydrogen, Rogers said.

“That, all of a sudden, is a very different economic model … [but] it doesn’t work if we spend another decade on permitting,” he said. “We need to be able to execute quickly. It’s about speed and scale; those are the key markers.”

‘Block Decarbonization’

A failure to take necessary actions to reduce GHG emissions now could mean a 3-10% drop in U.S. gross domestic product by the end of the century — a potential revenue loss of up to $2 trillion per year — Zaidi said, citing figures from the Office of Management and Budget.

Both he and Newell said hitting net-zero targets — while ensuring an effective, efficient and equitable transition — will require a mix of economic and policy drivers.

For Newell, the three core components are “market incentives, technology innovation and international collaboration, with each of these forces guided by well-designed policy.”

“We need innovation in the market policy and financial structures that must underpin a net-zero economy, and we need these structures to be more equitable in delivering the benefits and distributing the costs of actions taken,” he said. “In short, we need the economy to work for the climate.”

Looking back over RFF’s 70-year history, Newell cited the organization’s early role in the development of the cap-and-trade system, established in 1990, that helped the U.S. reduce the sulfur dioxide emissions that caused acid rain.

Matt Rogers 2022-10-20 (RTO Insider LLC) FI.jpgMatt Rogers | © RTO Insider LLC

Putting a price on that pollution meant “we could improve on traditional approaches to regulation by creating incentives to find the most effective and efficient ways to drive that pollution down,” he said.

While recognizing that any kind of national carbon cap-and-trade market is not, at least at present, politically viable, RFF continues to support the idea “because it has so many benefits,” said Alan Krupnick, the organization’s industry and fuels program director. “It levels the playing [field] by having every emitter in the economy subject to a single price.”

Building on President Biden’s climate agenda, Zaidi’s three drivers for net zero are irresistible economics, irreversible progress and visible impact, backed up with a list of administration actions. Examples include the domestic content provisions of the IRA’s solar investment tax credits, U.S. automakers’ ongoing retooling as they ramp up production of electric vehicles, and the impact on community and child health from the rollout of electric school buses funded by the IIJA.

The challenges ahead are, first, avoiding delay, and “taking federal policy and making sure the system metabolizes it as quickly as possible to figure out how to use it,” he said. “For folks in the private sector, the time to make decisions is now. Boards can’t commission study committees; they’ve got to greenlight capital projects. …

“When we delay, costs go up, the risk on implementation goes up, and the people who hurt the most are the poorest and least able to adapt,” Zaidi said.

Rogers said the IIJA’s funding for hydrogen hubs could serve as a model for the mix of policy, economics and accounting for regional differences, which will be needed to get projects done and emissions reduced.

“The right mix of projects in Los Angeles or San Francisco is different, and the way you go about doing it is different in LA or San Francisco than it is in Houston,” he said. “The incentives the DOE has put out in terms of these hydrogen hubs [have] provided a great focusing mechanism on how we get communities to come together and say, ‘Alright, so how do we do this where we live?’”

The hubs could also open the way for a more holistic approach to permitting, in which a cluster or block of projects could be evaluated together rather than one by one “so local leaders can make decisions about block decarbonization,” Rogers said.

Such an approach could show “how the projects fit together and how the hydrogen project enables an ammonia project, and the ammonia project enables decarbonization of the port with shipping activities or decarbonization of fertilizer,” he said.

Looking toward 2030, Rogers said, the next milestone in U.S. and global climate commitments will be “how many projects that we actually get done. The measure of merit is no longer … about commitment; it’s about real projects, real speed on the ground.”

Posted on

ERCOT Board of Directors Briefs: Oct. 18, 2022

Directors Approve Aggregated DER Pilot Project

AUSTIN, Texas — ERCOT’s Board of Directors last week approved a pilot project in which Texas energy providers can aggregate their customers’ small distributed energy resources and sell their extra energy back to the grid.

The directors voted unanimously Oct. 18 to approve the Aggregated Distributed Energy Resource Pilot Project. The project is intended to evaluate how aggregated DERs can support reliability, participate in the wholesale market and play a role in emergency situations.

“This is a great big historic moment for Texas,” tweeted Arushi Sharma Frank, Tesla’s (NASDAQ:TSLA) lead for U.S. energy markets policy. The pilot “will drive demand for DERs [and] retail competition, and prove out the technology solutions needed for a resilient grid.”

Frank and Tesla have played a key role in the project’s formation. Tesla conducted a virtual power plant demonstration with its Powerwall energy storage product in North Texas earlier this year, while Frank was involved in a Public Utility Commission task force on DERs and testified before the PUC.

Arushi Sharma Frank 2022-04-19 (RTO Insider LLC) FI.jpgArushi Sharma Frank, Tesla | © RTO Insider LLC

The commission in July directed ERCOT to develop the pilot. Focused on aggregations of individual sites that can inject or withdraw power from the grid in response to ERCOT instructions, the project will give the grid operator’s staff time to develop a full framework for aggregated DER participation (51603).

The pilot will be conducted in phases so that it can begin as quickly as possible while minimizing changes to ERCOT and distribution service provider systems. Future phases could introduce additional design elements “to help expand participation opportunities while still maintaining distribution and transmission grid reliability.”

“We wanted to find a way to allow these resources to participate in the markets without a significant expense to our system upfront,” said David Maggio, ERCOT’s director of market design and analytics.

The initial participation will be limited to 80 MW of registered capacity and 40 MW of non-spinning reserve service to establish limits by load zone and by qualified scheduling entities (QSEs), allowing for diverse geographical and technology participation. ERCOT staff can increase those limits.

The DERs will be dispatched in real time by ERCOT’s security-constrained economic dispatch on a zonal basis and settled using a zonal price. They will only be eligible to qualify for the non-spin ancillary service and offered into and awarded in the day-ahead and real-time markets, similar to the grid operator’s current process for aggregated load resources.

“From our point of view, we’ll see a single resource, a single bid into the market and single telemetry,” Maggio said. “It will look like every other resource we might see.”

The pilot will get underway in January when staff begin DER qualification testing. ERCOT expects the pilot to last at least three years.

PUC Chair Peter Lake said a key answer he is looking for is transmission costs.

“That’s a big question we’ll need to be answered before we put it on monthly bills for our ratepayers,” he said.

Vegas Lays out Priorities

Board Chair Paul Foster welcomed new ERCOT CEO Pablo Vegas to his first board meeting, saying that, “in a very short period of time … he is already beginning to put his mark on the organization.”

Vegas, who only stepped into his position on Oct. 1, said he has been working with the executive team on one of the key elements of his first 100 days, developing a “clear remote work policy.”

One of interim CEO Brad Jones’ first actions last year was to allow most non-operations staff to work from anywhere in Texas, in part to address retention issues it faced after the February 2021 winter storm that drew negative attention to the grid operator.

Vegas Board 2022-10-18 (RTO Insider LLC) Content.jpgERCOT CEO Pablo Vegas delivers his first update to his Board of Directors. | © RTO Insider LLC

 

“The next evolution of our remote work policy … will continue to focus on balancing, first and foremost, meeting all operational requirements of ERCOT without exception, preserving flexibility for employees whose job roles enable them to work remotely and focus on the continued strengthening of our corporate culture,” Vegas said.

His other 100-day priorities include meeting with key market, regulatory and legislative stakeholders and ensuring the grid is ready for this winter by deploying and executing on new and existing efforts. ERCOT has scheduled winter weatherization workshops Tuesday for transmission service providers and generation owners to review requirements in place following the 2021 winter storm.

Vegas echoed comments he has made in several settings since becoming CEO, saying the key to rebuilding trust in ERCOT is simply “the core of what our operational strategy is.”

“Only through consistent and successful execution under a variety of conditions and scenarios can we return the trust of all Texans that their grid is sound and reliable,” he said, pointing to the grid’s dozens of energy-usage operations during the summer.

“The grid has withstood those tests and passed, but this doesn’t mean that our work is done. It’s really just beginning,” Vegas added. “We’re going to continue executing our mission with the recent successes we’ve had. And we’ll continue to build on that as we move forward.”

Records Fall in Summer Heat

Staff said this past summer was a record-breaking one for both Texas and its grid operator.

Average temperatures from June through August (84.8 degrees Fahrenheit) were the second highest in the state dating back to 1895, exceeded only by 2011 (86.8 F). The heat, and the state’s continued growth, led to 33 demand records, highlighted by an all-time peak of 80.01 GW in July.

“It seemed like we were setting new peaks every day,” Dan Woodfin, vice president of system operations, told the board.

He noted ERCOT set monthly demand records in April and the next four months, using the fingers on one hand as he listed the months. ERCOT added its sixth monthly demand record of the year on Oct. 12 at 66.1 GW.

Staff had about 8 GW of additional installed wind and solar capacity to work with, resulting in higher hourly renewable generation than the year before. Thermal forced outages were also higher this summer than the previous, but only by an average of an extra generating unit from 2021.

Kenan Ögelman, vice president of commercial operations, told directors that while ERCOT did not have to issue any energy emergency alerts during the extreme heat, it did experience several scarcity intervals that led to operator actions. Ancillary services were almost doubled that of two years ago at some points, and the 2,573 total reliability unit commitment (RUC) hours was 10 times that of 2020’s summer.

“We’re using RUCs more than we do traditionally,” Ögelman said.

Asked whether staff were trying to minimize the use of RUCs, Ögelman said, “We’re trying to minimize, but not at the expense of reliability.”

Natural gas prices that reached $9/MMBtu and increased demand for energy led to increased prices. Load-weighted average prices were up over the previous two summers, exceeding $160/MWh in July.

TAC Shares Changes with R&M

Technical Advisory Committee members and ERCOT staff will continue to tweak its process for handling priority revision requests after meeting with the board’s Reliability and Markets Committee on Oct. 17.

TAC Vice Chair Bob Helton, of ENGIE, shared with the R&M his committee’s proposals to accelerate protocol changes that are stuck in the stakeholder process, qualifications for its members and changes to the credit working groups’ structure. (See ERCOT TAC Considers Membership Requirements, Process Changes.)

Bob Helton 2022-10-17 (RTO Insider LLC) FI.jpgBob Helton, ENGIE | © RTO Insider LLC

The Credit Work Group (CWG) has reported to the board’s Finance and Audit Committee since 2004, but the R&M asked earlier this year that it hear market credit issues from ERCOT staff. The F&A has agreed to give up its market credit oversight responsibilities, with TAC agreeing to take on the role and proposing to consolidate it with its Market Credit Working Group, which reports to the Wholesale Market Subcommittee.

The R&M asked Helton to work with staff in formalizing the Independent Market Monitor’s role in the stakeholder process. The IMM is currently free to comment on revisions requests and participate in the discussions.

The board will vote on the TAC proposals during its December meeting.

Directors Approve Nine Rule Changes

The board passed six nodal protocol revision requests (NPRRs), a modification to the Nodal Operating Guide and two system change requests (SCRs) during the meeting:

  • NPRR1058: requires quicker updates by QSEs to the telemetered resource status, high sustained limit (HSL) and other relevant information, improving the physical responsive capability calculation’s validity and dispatch.
  • NPRR1084: allows ERCOT to publicly provide information about resources’ forced outages, forced derates and start-up loading failures in a more complete and timely manner.
  • NPRR1118: clarifies the outage schedule adjustment (OSA) process to improve the terminology and clarifies the process for issuing advanced action notices and OSAs, as well as offer submission and RUC procedures after an OSA is issued.
  • NPRR1127: clarifies which entities are required to have hotline and 24/7 communications with ERCOT, and requires those entities answer each hotline call to proactively ensure situational awareness during emergency situations.
  • NPRR1139: replaces the usage of the wind-powered generation resource and photovoltaic generation resource productions with the HSL of an intermittent renewable resource as reflected in the current operating plan.
  • NPRR1140: permits generation resources to recover their fuel costs when instructed to start because of an RUC and operate above the resource’s low sustained limit.
  • NOGRR241: clarifies which entities are required to have hotline and 24/7 communications with ERCOT, and requires those entities answer each hotline call to proactively ensure situational awareness during emergency situations.
  • SCR820: builds on the hotline communication process by developing a web-based platform supporting real-time, bidirectional, “send-review” messaging between ERCOT operators and transmission operators during emergency event coordination.
  • SCR823: requests that ERCOT upload a flat file received from each affected transmission/distribution service provider (TDSP) that contains all their electric service identifiers (ESI), besides those that have been retired. This flat file would allow all retail electric providers to have county names associated to all ESIs on the very first day following the go-live of Texas SET V5.0 production.
Posted on

Renewable Devs Criticize PJM Response to FERC on Queue Proposal

INDIANAPOLIS — Several renewable energy developers and investors filed comments with FERC on Thursday arguing that PJM’s response to the commission’s deficiency letter on its interconnection queue restructuring proposal is insufficient (ER22-2110).

Jointly filing as the Affected Interconnection Customers, the companies argued that PJM has not explained whether the threshold of $5 million of network upgrades under which a project would be eligible to be placed into a fast-track interconnection study queue includes the costs of upgrades that have already been in construction or whose construction could have been fully securitized already through a signed interconnection service agreement (ISA).

Such projects should be permitted to be entered into the fast-tracked expedited process, the companies argued, even if the necessary upgrades would exceed $5 million.

“Network upgrades that have already been constructed or fully securitized prior to the transition date cannot adversely affect subsequently queued projects because they have already been fully committed to financially,” they said. “Transition Cycle projects in queue windows AE1 through AG1 with allocations towards network upgrades that have been fully constructed or securitized (‘fully funded [network upgrades]’) prior to the transition date through a signed ISA should be eligible for the Expedited Process category, regardless of whether those network upgrade allocations are greater than $5 million.”

Without that being the case, the ad hoc group argued that there could be impacts for companies both within the transition queues and those in the pre-transition cycles, which could see their network upgrade burden increase.

“In some instances, it could inadvertently cause such pre-Transition Cycle projects from signing an ISA even though they have remained in queue for up to six years, having planned for network upgrade socialization that PJM is now removing. Such an outcome would be illogical and would not be just and reasonable.”

The group also argued that PJM has not satisfied FERC’s request for justification for the proposed removal of two tariff sections related to reporting and penalties for completing a percentage of the transmission service request studies within a certain time frame. Without further information from PJM, it encouraged FERC to require that the language remain in the tariff until another approach can be found.

“PJM claims to be concerned about inconsistent requirements in its tariff, but PJM does not explain why it cannot consolidate the inconsistent provisions in one place or revise them to fit them into the new regime,” the group said. “PJM also does not try to explain why penalties are no longer needed to enable it to process study requests in a timely fashion, which is very important given the huge backlog of its interconnection queue.”

The group of companies includes Acciona Energy USA, ConnectGen, Copenhagen Infrastructure, Hecate Energy, Leeward Renewable Energy Development, Scout Clean Energy and Tri Global Energy.

Queue Backlog Discussed During OPSI Annual Meeting

During a panel during the Organization of PJM States Inc.’s Annual Meeting discussing the interconnection queue backlog on Oct. 18, American Municipal Power General Counsel Lisa McAlister said she believes that imposing penalties for failing to complete a percentage of the studies could be unfair to both transmission owners and RTO stakeholders.

“While that makes sense and it could be a compliment to the stricter requirements of commercial readiness on the generator’s part, the transmission owners do a lot of the interconnection studies from what I’ve seen, and if they have incomplete information or the information … it doesn’t seem really fair to impose penalties on the transmission owners and then … penalties on the RTO itself,” McAlister said. “The RTO is a nonprofit organization that doesn’t really have independent funds, so those are going to get passed through to PJM members who don’t have any skin in the game and certainly aren’t responsible for not having done the studies.”

Fellow panelist Benjamin Greene, RTO policy manager for American Electric Power, said the penalties could erode the relationship between PJM and its TOs, as well as potentially put the transmission providers in an awkward position of trying to determine which of the two is at fault for studies not being complete.

PJM Vice President of Planning Kenneth Seiler told the panel the RTO is hoping that if FERC approves its proposal soon, it could get through the transition queues within two to three years. Smaller projects that have minimal impact on the grid could be done within six months, with much of the work PJM staff have to commit to studies laying in those projects that would require hundreds of million in transmission upgrades.

Seiler also said he’s hopeful that FERC will revise its interconnection queue Notice of Proposed Rulemaking (RM22-14), issued in June, to remove a proposal to allow developers to ask RTOs and transmission providers to determine the costs of different combinations of projects. Such a rule would increase complexity and slow down PJM’s ability to complete studies, he said. (See FERC Proposes Interconnection Process Overhaul.)

“If we’re going to continue to have optional studies, we’re almost going to go back to where we were or where we are now, which is going to be pretty time consuming. We’re going to have to spin off another group to do optional studies, which everyone else is then taking their studies and deciding if they want to move forward, because all these projects intersect with each other. So the more flexibility we introduce for the developers, the more time it’s going to take for us to process the queues,” Seiler said.

Posted on

PJM MRC Preview: Oct 24, 2022

Below is a summary of the agenda items scheduled to be brought to a vote at the PJM Markets and Reliability Committee meeting Monday, part of the RTO’s Annual Meeting of Members. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.

RTO Insider will have a full report for the Nov. 1 newsletter, along with coverage of the subsequent Members Committee being held this Wednesday.

Markets and Reliability Committee

Opening Remarks (1:05-1:40)

PJM CEO Manu Asthana will deliver opening remarks to the MRC, followed by a presentation on diversity, equity and inclusion (DEI) by Michael Coyle, the RTO’s chief DEI officer.

Consent Agenda (1:40-1:45)

B. The MRC will consider endorsement of the 2022 Reserve Requirement Study’s recommended values for the forecast pool requirement (FPR) and installed reserve margin (IRM) for the next capacity year and set projections for the following three. Should the vote pass, the RRS is scheduled to go before the Board of Managers in December. (See “Stakeholders Endorse 2022 Reserve Requirement Study Results,” PJM PC/TEAC Briefs: Oct. 4, 2022.)

C. The committee will consider proposed revisions to Manual 28: Operating Agreement Accounting to eliminate an exception that has allowed combustion turbine units to recover the costs of their full generation even when they’re operating above their load signal. The changes would bring them in line with the practices and penalties other generator types currently follow. (See “Elimination of ‘CT Rule’ Receives Endorsement,” PJM Market Implementation Committee Briefs: Oct. 6.)

Issue Tracking: Operating Reserve Clarification for Resources Operating as Requested by PJM

D. The committee will also consider proposed revisions to Manual 39: Nuclear Plant Interface Coordination as a part of a periodic review. (See “Manual 39: Nuclear Plant Interface Coordination,” PJM Operating Committee Briefs: Aug. 11, 2022.)

E. The MRC will consider revisions to PJM’s tariff addressing the internal network integration transmission service process that aim to reduce administrative burdens for approving new agreements for transmission within PJM’s network. (See “Streamlining Internal NITS Process Under Consideration,” PJM MRC/MC Briefs: Sept. 21, 2022.)

Issue Tracking: Internal Network Integration Transmission Service Process

Endorsements (1:45-2:20)

1. Fuel Requirements for Black Start Resources (1:45-2:10)

PJM staff will review a proposed package of changes meant to ensure that resources providing black start capabilities are available should they be needed. The language would create a new, higher tier of black start service — “fuel assured” — for generators with added fuel availability, such as through on-site storage or connections to multiple gas pipelines. (See PJM, Monitor Debate Black Start Fuel Requirements Proposals.) The committee will be asked to endorse the proposed manual revisions.  

Issue Tracking: Fuel Requirements for Black Start Resources

2. Residential Customer Measurement and Verification for Demand Response (2:10-2:20)

Ken Schisler of CPower will review a proposed problem statement and issue charge to address residential customer measurement and verification for demand response. The work would evaluate the use of statistical sampling for interval-metered residential customers as a solution to data access remaining a barrier to such customers participating in wholesale markets through curtailment service providers. (See “DR Proposal Brought Before MRC After MIC Rejection,” PJM MRC/MC Briefs: Sept. 21, 2022.) The committee will be asked to approve the issue charge.

Posted on

PJM Stakeholders, Bowring Debate Monitor’s Budget, Scope During OPSI Annual Meeting

INDIANAPOLIS — PJM Independent Market Monitor Joe Bowring last week criticized inquiries into the budget of his firm, Monitoring Analytics, and the scope of its contract with the RTO, saying they threaten the IMM’s independence.

Bowring told the Organization of PJM States Inc.’s (OPSI) Market Monitoring Advisory Committee, meeting as part of OPSI’s Annual Meeting event on Oct. 18, that stakeholders have recently questioned the RTO’s Finance and Liaison committees about his firm.

“Some of the sectors have been using the Finance Committee as a point of attack against the Market Monitor, and we think it’s a precursor of what we can expect over the next three years; our contract is up in three years,” Bowring said. “A number of the sectors were not happy when our contract was renewed the last time around, and we are experiencing this as the beginning of the next round of attacks on the Market Monitor and our existence, let alone our independence.”

Alex Stern, director of RTO strategy for Public Service Electric and Gas, responded that stakeholders involved in the budget approval process were seeking answers about the cost of Monitoring Analytics’ services and why its expenditures historically have been millions below its budget.

“There were concerns expressed that members are paying substantially more for the services of Monitoring Analytics than other regions that are similarly situated, and there were concerns that there are escalations in the budget year over year despite actuals consistently coming in much lower,” Stern said.

Bowring said unspent money in the Monitor’s budget is subtracted from its allocation in the subsequent year’s budget, preventing it from profiting from excess funds. He noted that Monitor Analytics is seeking a $500,000 budget increase from approximately $14.6 million this fiscal year to $15.1 million next year, of which they expect to spend $13.5 million.

“If our budget is $13 million and we spend $11 [million], we don’t get to keep the other $2 [million]; it simply falls forward into the next year and reduces the next year’s budget by that amount. So it’s a zero-profit, cost-based operation,” he said.

Jason Barker of Constellation Energy said his company supports a strong and independent Monitor, but it has misgivings regarding its scope and whether Monitoring Analytics may be exceeding it. When asked to elaborate by committee members, he said some of the issues were confidential and questioned whether the body would have the authority to act on complaints brought before it.

“The central question is, who oversees the market monitoring activities? Is it this committee? Is it the board? What powers would this committee have, and how would they exercise them if matters are brought before you?” he said.

Jackie Roberts, federal policy adviser for the West Virginia Public Service Commission, said it frustrates the states’ attempts to act upon concerns regarding the IMM and report them to FERC when they’re made in forums they cannot participate in, such as the PJM Liaison Committee, rather than before the OPSI Advisory Committee.

“We hear a lot about what Joe’s doing at these meetings, but what we don’t hear are criticisms that occur at the Liaison Committee and where Joe [Bowring] can’t hear the criticisms and the states can’t hear the criticisms,” Roberts said. “It’s very hard to report to FERC about the Market Monitor through this committee as we are obligated to do without knowing what those comments are, and the Liaison Committee is not charged with reporting to FERC about the Market Monitor.”

She called for PJM to limit discussion of IMM performance and direct that to the Advisory Committee or open the Liaison Committee to state participation.

Marji Philips of LS Power said there have also been concerns regarding Bowring’s influence on stakeholder discussions, which she said can sometimes tamp down on negotiations.

Maryland Public Service Commissioner Michael Richard said he believes a broad scope for the Monitor is important for states to gain confidence that PJM’s markets are functional by providing more oversight and involvement than their individual offices can.

“We believe that he has a very broad mandate and he is in the position of what he deems important to ensure competitive markets,” he said.

Competition is Key

Bowring praised the performance of the RTO’s competitive markets and outlined several potential improvements and future challenges during the meeting last week.

“We need collectively to make the markets work. Competitive markets have worked; they continue to work; and it just requires everyone to buckle down and think about that being the focus and not accepting some of these counter narratives which suggest that somehow markets are fundamentally broken,” Bowring said.

Many of the areas Bowring expressed concerns about have to do with what he believes are instances where parties try to sway the competitive aspects of the markets.

Bowring said that renewable resources, for examples, should compete in a single capacity market, alongside other generators. That would increase the capacity market price for thermal generators and provide a strong incentive for intermittent resources to hybridize to make themselves more reliable and able to compete.

Markets do, however, need clear rules around their functioning, Bowring said, and it’s important that those rules remain focused on using the principles of competition toward their solution.

“You can’t solve every possible problem we foresee coming for the next 20 years; we have to solve the problems in front of us, thinking about the future. We have to remain technology neutral and not have our thumb on the scale in any particular direction. We also don’t need artificial price increases to solve what we may perceive to be problems. We’ve gone through cycles of PJM and others thinking that we need to raise prices and saying prices are too low. As long as we have the market rules right, prices are not too high or too low, they are what they are and people have to deal with the outcomes of that,” Bowring said.

[CORRECTION: An earlier version of this article mistakenly attributed a quote by Jackie Roberts to Marji Phillips.] 

Posted on

FERC Affirms SPP’s Zonal Planning Criteria

FERC on Thursday sustained a previous order accepting SPP tariff revisions that establish an annual process allowing each transmission pricing zone to develop a uniform planning criteria that the grid operator would use to evaluate the need for zonal reliability upgrades (ER22-1719).

The order addressed requests for rehearing and alternative clarification after the commission’s June approval of SPP’s filing. (See FERC Accepts SPP’s 2nd Try at Zonal Planning Criteria.)

SPP transmission owners ITC Great Plains, Oklahoma Gas & Electric, GridLiance High Plains and Evergy’s subsidiaries all filed rehearing requests that FERC said “primarily revive arguments raised in their initial pleadings” that:

  • the proposed two-step voting process for approving zonal planning criteria allows small transmission customers to block their adoption;
  • using SPP’s regional planning criteria as a backup and allowing TOs to use their own local planning criteria, but directly assigning the costs, both violate the cost-causation principle;
  • exempting one of the 18 pricing zones from the planning criteria development process is unduly discriminatory;
  • SPP abdicated its role in the development process and did not comply with the requirements of Orders 1000 and 2000 regarding its responsibility for transmission planning; and
  • the June 29 effective date for the revisions imposes compliance and implementation burdens.

FERC said SPP continued to meet its burden under Federal Power Act’s Section 205 that its tariff revisions are just and reasonable and not unduly discriminatory or preferential. It noted that SPP’s proposed two-step voting process to approve zonal planning criteria provides a “just and reasonable mechanism for parties to achieve consensus that does not provide an undue advantage to any class or type of transmission owner or customer.”

The commission did clarify that the development process will begin on April 2, 2023.

Posted on

SPP Brings Back Ex-staffer to Develop Western Services

SPP has welcomed back Carrie Simpson, a former six-year staffer with extensive market design expertise, to lead the continued development of its service offerings in the Western Interconnection.

The RTO on Thursday announced Simpson’s appointment as director of Western services development, effective Nov. 1. Working with SPP’s Western stakeholders, she will direct the ongoing development and implementation of wholesale markets and other services.

Simpson left SPP for Xcel Energy-Colorado in 2015 after playing a critical role in helping design and draft the rules for the grid operator’s Integrated Marketplace. The Day 2 market launched in 2014 and serves as the foundation for the RTO’s Western market offerings.

“Developing services that address the needs of the Western Interconnection is a huge opportunity,” Simpson said in a statement. “I look forward to working with stakeholders across the west in my new role to develop solutions that support affordable, reliable electricity for the whole region.”

As Xcel Energy-Colorado’s Western markets director, Simpson and her team were responsible for analyzing and evaluating participation in organized wholesale markets. She already has strong relationships with Western stakeholders and established herself as one of the key subject-matter experts participating in SPP’s Markets+’s development, one of the RTO’s six different Western services. (See SPP Woos Western Utilities with Markets+ Offering.)

“We’re very excited to welcome Carrie back to SPP,” said Bruce Rew, SPP’s senior vice president of operations. “She has extensive knowledge and experience in operations and market design, as well as collaboration in the Western Interconnection.”

In an email to Western stakeholders, Rew said Simpson will work closely with them to ensure SPP’s Western energy services continue to “reflect the collaborative, mutually beneficial partnerships we’ve established since 2018,” when the grid operator announced its intent to act as a reliability coordinator for Western utilities.

That service went live in 2019 and was followed by the Western Energy Imbalance Service Market in 2021. That same year, the Western Power Pool selected SPP to operate its Western Resource Adequacy Program. The grid operator is also assessing whether to expand its RTO in the West.

SPP said Simpson’s role is new and reflects the company’s “commitment to pursuing strategic opportunities to enhance electric reliability and affordability in the Western part of the U.S.”

Simpson, who has 18 years of industry experience, has an undergraduate degree from Harvard University and a law degree from the University of Denver’s Sturm College of Law. She is licensed to practice law in Colorado.

Posted on

FERC Rules Kentucky Muni Can Remain a MISO TO

FERC on Thursday affirmed the Henderson, Ky., municipal utility’s status as a transmission owner in the MISO region, ruling its facilities can be classified as transmission rather than distribution lines (ER19-776-001; ER19-809-001).

Big Rivers Electric Corp. has disputed Henderson Municipal Power and Light’s standing as a MISO transmission owner, arguing that the city’s lines are distributed in nature and that it shouldn’t share in Big Rivers’ transmission pricing zone.

FERC previously found in 2019 that Henderson’s 69-kV and 161-kV lines can be categorized as transmission, making the city a MISO transmission owner in the pricing zone. The utility is interconnected with Big Rivers’ transmission system.

The commission said it’s appropriate that Big Rivers “share its imputed revenues for its bundled load with Henderson for transmission service provided by the Henderson facilities.” FERC added that a joint pricing zone is appropriate in this instance because it provides for Henderson to recover revenue from the facilities’ physical location and is similar to MISO’s other joint pricing zones.

The commission said Big Rivers and Henderson should both have a stake in the pricing zone, despite Big Rivers’ reconfiguration of its system in 2019 by disconnecting a substation tie line between its facilities and Henderson’s.

FERC’s decision confirms an administrative law judge’s opinion last year.

MISO’s Board of Directors approved the transmission-owning membership of Henderson in 2018. The grid operator applied FERC’s seven-pronged transmission test under Order 888 to determine that most of Henderson’s system qualified as transmission. (See “6 Added to MISO Membership,” MISO Board of Directors Briefs: Dec. 6, 2018.)

Big Rivers in 2019 alleged that MISO presented for stakeholder review the results of the transmission test during a Planning Subcommittee meeting after it had already filed Henderson’s application as a transmission owner with FERC.

Posted on

Solar Farm Trend Turns Old Coal Mines Green

Before it closed in 2015, the Hobet coal mine in southern West Virginia was one of the largest surface coal mines in the U.S. Now, Kansas City-based renewable developer Savion is planning to turn 3,000 acres of the site into the state’s largest solar farm with up to 250 MW, enough to power more than 30,000 homes.

The SunPark Solar project is one of many former coal mines being transformed into solar generating sites.

The Environmental Protection Agency recently identified 17,756 mine sites totaling 1.5 million acres, enough space to generate almost 90 GW of power. In June, the Department of Energy announced it would spend $500 million from the Infrastructure Investment and Jobs Act to transform former mine lands into “clean energy” sites. At least two of the projects must be solar; also eligible are geothermal, fossil fuel generation with carbon capture, energy storage and advanced nuclear. (See DOE Launches $500M Project to Put Clean Energy on Mine Lands.)

Founded in 2019, Savion was acquired in December by Shell New Energies (NYSE:SHEL) and has solar and storage projects in various phases across 31 states. The SunPark project is the result of an agreement the company reached earlier this year with SEVA WV, a West Virginia-based company that also hopes to develop an industrial park, lodging and recreation on the remaining 1,500 acres of the former mine.

The electricity Savion generates will be sold into the wholesale electric market. Commercial operations could begin between 2025 and 2028.

Elsewhere in West Virginia, a state formerly famed for its coal mines, FirstEnergy subsidiary Mon Power (NYSE:FE) is planning a solar power facility at a 44-acre reclaimed strip mine in Tucker County. That site is one of five locations where Mon Power plans to build a solar energy facility, for a total of 50 MW of renewable power generation. In May, Mon Power and FirstEnergy’s other West Virginia subsidiary, Potomac Edison, announced they had begun accepting West Virginia customer subscriptions to purchase power from the facilities through solar renewable energy credits (SRECs). More than 87,000 SRECs per year will be available when all five projects are up and running.

“We expect to obtain customer commitments this year for 85% of the solar renewable energy credits to be generated by the projects and will then seek final approval from the [West Virginia Public Service] Commission,” Will Boye, a spokesperson for FirstEnergy, said in an email. The company hopes to start full-scale construction next year at its first site, Fort Martin Power Station, with construction at the other four sites commencing in 2024 and 2025.

Silver Spring, Maryland-based Competitive Power Ventures (CPV) has two such projects in its portfolio: the Backbone Project in the western Panhandle area of Maryland, and Maple Hill Solar Farm in Cambria County, Pennsylvania. The former will generate 175 MW, enough to power roughly 30,000 homes. That project is waiting for an interconnection agreement with PJM, CPV’s Matt Litchfield said in an interview. “We hope to start construction in the next six months.” The Pennsylvania project will generate 100 MW, after an investment of more than $200 million, he said.

Seven Sites on Nature Conservancy-Managed Lands

The Nature Conservancy announced in July 2021 that it had reached agreements with Sun Tribe, based in Charlottesville, Virginia, and Washington, D.C.-based Sol Systems, which will build solar energy facilities on former coal mining lands that the environmental group manages in southwestern Virginia.

In September 2021, Dominion Energy Virginia (NYSE:D) announced its own partnership with the Conservancy for the Highlands Solar project, which will reuse about 1,200 acres of the former Red Onion surface mine and surrounding properties in Wise and Dickenson Counties. The partners said the project will generate approximately 50 MW. Additional benefits for the area could include “an increase in local tax revenues, the ability to provide additional funding through solar siting agreements, and the creation of clean energy jobs,” they added.

Dominion plans to begin construction in 2024 or 2025, subject to approval by the Virginia State Corporation Commission, and will use the project to work toward its mandate under the Virginia Clean Economy Act to produce its electricity from 100% carbon-free sources by 2045.

While most of the Cumberland Forest Project that the Nature Conservancy manages — almost 253,000 acres in southwestern Virginia, eastern Tennessee, and eastern Kentucky — consists of woodlands, it includes seven former coal mining sites as well, including the Highlands Solar site, five other sites in Virginia, and one just over the state line in Tennessee. Sun Tribe is developing the latter six sites, Brad Kreps, Clinch Valley Program Director for the Nature Conservancy, said in an interview.

The Conservancy says the three companies’ solar farms will cover nearly 1,700 acres and generate an estimated 120 MW.

“We are trying to find ways to create benefits for nature and new economic benefits for localities, such as tax revenues and jobs,” Kreps said.

But he conceded that most of the job creation involved will take place during the construction phase of the projects; no one expects the new solar farms to replace the number of jobs lost with the demise of mining. “It doesn’t take very many people to operate the facilities,” he said.

According to job posting site Indeed, solar panel installers in Virginia average about $24.50 per hour. Less than 12% of construction workers in the solar industry are unionized, according to the Solar Energy Industries Association. Although that is less than the national average for construction, it is double the 5.6% union participation rate reported in 2020 for the mining, quarrying, and oil and gas extraction segment, according to the Bureau of Labor Statistics.

But while converting coal mine sites to solar won’t provide all the economic benefits that have been lost in Appalachia, supporters say it is essential to use sites such as these to minimize the need to convert farmland and woodlands. Princeton University energy and climate expert Jesse Jenkins has estimated that the most cost-effective scenario for reaching net-zero emissions will require solar over an area equivalent to the states of Connecticut, Rhode Island and Massachusetts.