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August 30, 2024

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FirstEnergy’s Top Executives Face Job Reviews

Top FirstEnergy (NYSE:FE) executives are facing job performance reviews as required by the March settlement of several shareholder lawsuits alleging that the company was damaged by secretly funding a scheme to bribe Ohio politicians for nuclear power plant subsidies.

In a U.S. Securities and Exchange Commission filing June 15, the board announced it had formed a “special review committee” of directors to assess the performance of current top executives and report to the full board by mid-September.

The SEC filing did not identify what it described as “current C-suite executives,” which typically include a company’s CEO, CFO and COO. The company’s website identifies its current leadership team as having nine members, including a member of the board. A company spokeswoman said the committee will determine whose job performance it will evaluate.

The shareholder settlement also required the resignations of six longtime members of the company’s board of directors and a reconstituted board, elected in May, to oversee the company’s future lobbying. (See FirstEnergy Shareholder Settlement: 6 of 16 Board Members Must Leave.)

CEO Steven Strah was appointed in March 2021 after serving about six months as president and acting CEO. Strah began his FirstEnergy career at The Illuminating Co. in 1984.

CFO Jon Taylor was promoted to his position in May 2020 and given expanded responsibilities in August 2021. Taylor joined the company in 2009.

Samuel Belcher, senior vice president of operations, oversees FirstEnergy’s regulated electric utility operating companies in Ohio, Pennsylvania, New Jersey, West Virginia, Maryland and New York, as well as the company’s high-voltage transmission system. He joined the company in 2012.

In July 2021, FirstEnergy agreed to pay a $230 million fine in a deferred prosecution agreement with the U.S. Justice Department. By signing the agreement, the company admitted it conspired with former Ohio House Speaker Larry Householder and his associates by secretly contributing millions of dollars to a 501(c)(4) charity Householder allegedly used to fund efforts to win passage in 2019 of a nuclear bailout bill, H.B. 6, and then defeat a referendum petition drive to allow voters to decide the issue.

Former FirstEnergy CEO Charles Jones publicly admitted the company contributed about $60 million to the charity. Ohio lawmakers later revoked the bailout.

Jones and several other top executives were fired. Householder, expelled from the House, has pleaded innocent and faces a trial in January 2023. Two of his associates pleaded guilty and await sentencing.

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ERCOT Briefs: Week of June 13, 2022

The summer season may have officially begun early Tuesday morning, but ERCOT has already set three new marks for all-time peak demand this year.

The Texas grid operator confirmed demand peaked at a record 75.1 GW Thursday afternoon, breaking the previous record of 74.9 GW set on June 12. Those records were surpassed at 4:30 p.m. Monday, when demand hit 76,743 MW, less than 1,000 MW short of staff’s 77.3 GW peak forecast for the summer. (See ERCOT, PUC Say Texas Ready for Summer.)

Average peaks will remain above 75.7 GW for the rest of the week as the state continues to bake in extreme drought conditions that exacerbate the heat. The Houston area was expected to see temperatures approaching 107 degrees Fahrenheit Monday; widespread temperatures at 108 degrees or above would trigger a heat advisory.

ERCOT’s meteorologist says the footprint’s temperatures will be hotter this week than they were last week, with most of Texas seeing highs of 100 degrees or greater. He said temperatures of 103 to 105 degrees will be common later in the week; the European weather model is forecasting highs of 110 degrees or greater across North Texas this weekend.

Extreme to exceptional drought — defined as widespread crop and pasture losses, exceptional fire risk, and water shortages in reservoirs, streams and wells causing water emergencies — covers 70% of the state’s Southwestern region, which includes Austin, San Antonio and El Paso, according to the National Weather Service.

Sunday’s demand topped out at 73.8 GW Sunday, the 11th straight day it has exceeded 72.4 GW.

The grid continues to rely on wind and solar resources to provide between 25 and 30 GW of energy a day. ERCOT said it has more than 92 GW of expected capacity to meet the demand and has been able to avoid asking Texans to reduce their usage since an informal conservation appeal in May.

Since April, the grid operator has issued three operating condition notices, its lowest-level communication to the market in anticipation of possible emergency conditions. Thermal outages that topped 20 GW near the end of the maintenance season had dropped to 5.3 GW as of Monday.

ERCOT says it has enough capacity to meet demand as it continues to maintain a conservative operations posture by procuring up to 6.5 GW of operating reserves. However, the Independent Market Monitor said in its annual market report that the practice has cost the market up to $845 million year to date.

The Monitor is presenting its report to the grid operator’s Board of Directors Tuesday and a state House committee hearing Wednesday. The ERCOT directors will begin their bi-monthly board meeting Tuesday several hours after the summer solstice officially marks the beginning of summer at 4:14 a.m.

Securitization Bonds are Issued

A special-purpose entity, Texas Electric Market Stabilization Funding, will issue more than $2.1 billion in bonds to cover short pays to the market, a result of legislation last year to compensate market participants for $2.9 billion in debt incurred during the February 2021 winter storm. (See Securitization Offers Texas a Way Forward.)

ERCOT will distribute the bonds’ proceeds to load-serving entities that have demonstrated to regulators that they were exposed to extraordinary costs because of the supply and demand imbalance caused by generation outages during the severe cold.

The bonds will be issued in four tranches, totaling $2.12 billion, with weighted average lives of approximately seven, 16, 22 and 26 years. Their interest rates range between 4.264% and 5.167%.

The four tranches (ERCOT) Content.jpgThe four tranches of ERCOT’s securitization bonds | ERCOT

Moody’s Investors Service assigned a provisional rating of Aaa (sf) for each of the four tranches; a final rating will occur at closing, ERCOT said

The Texas Public Utility Commission authorized ERCOT to assess a monthly “default charge” on qualified scheduling entitles (QSEs) and congestion revenue right account holders to repay the default balance. The grid operator will post miscellaneous invoices to the QSEs Tuesday, and funds will be distributed Wednesday. ERCOT will distribute initial uplift charge invoices beginning in August. Until then, it will use market notices to provide the daily securitization uplift total.

Biannual interest payments to bondholders will begin Feb. 1, 2023, and occur every August 1 and February 1 of the first bank business day thereafter if those dates are not bank business days.

TAC Reviews Structure, Procedures

The Technical Advisory Committee held a workshop last week to review its structure and procedures as it continues to address stakeholder concerns about how it interacts with the new ERCOT board.

“I know there’s been a lot of angst amongst stakeholders as it pertains to what the stakeholder process will be like as we go forward,” TAC Chair Clif Lange said in opening the June 14 discussion. “We want to provide a menu of options, when appropriate.”

Lange said he and vice chair Bob Helton had recently met with director Bob Flexon, who chairs the board’s new Reliability and Markets Committee (R&M) that some stakeholders say is stepping on TAC’s toes. Lange said he and Helton were urged to streamline TAC’s subcommittees and to think of ways to change the structure and reporting relationships of the committee and its participation in the stakeholder process.

“The board is looking for opportunities for the R&M to provide input and recommendations to the board on items bubbling up through TAC,” Lange said. “[The board] sees this as a way to strengthen [the stakeholder] relationship. They see this as an opportunity to improve communications and understanding of the core areas of ERCOT.”

The committee discussed creating a liaison committee that would meet with the R&M as needed to inform the directors on coming ruling changes but failed to reach consensus on how the liaisons would be appointed. Members did agree that a proposal requiring them to be employees of the companies they represent made no sense when some organizations and stakeholder groups rely on outside consultants.

“[The experience proposal] gives the board some degree of certainty that TAC has the expertise membership can draw on,” Lange said.

Lange and Helton will continue the discussion at TAC’s June 27 meeting. They will then meet with the board and get its feedback.

RPG Recommends 345-kV Project

Staff told the Regional Planning Group last week that they will recommend to the board and TAC that a $477 million 345-kV transmission line addition in West Texas go forward as a Tier 1 project.

ERCOT said its independent review of the project indicates the additional pathway will address rapid load growth in the Delaware Basin area. The project includes 71 miles of double-circuit 345-kV lines from the existing Bearkat substation to the existing North McCamey substation and another 94-mile stretch from the North McCamey substation to the existing Sand Lake substation.

A final report for the project is expected to be released next month and will then go to TAC and the board in August for their endorsement.

The Lower Colorado River Authority, Wind Energy Transmission Texas and Oncor jointly submitted the Bearkat-North McCamey–Sand Lake 345-kV addition to the RPG in April, requesting critical designation. It is scheduled to go in service in June 2026.

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Court Strikes a Blow to ISO-NE Winter Plan

The D.C. Circuit Court of Appeals on Friday took a scalpel to ISO-NE’s Inventoried Energy Program, finding that it would unfairly incent resources for storing energy in a way they already do (Belmont Municipal Light Department v. FERC, 19-1224). 

Approved by FERC in 2020 over the objections of then-Commissioner Richard Glick, the IEP is set to be in place for the 2023-2025 winter seasons to compensate resources for the inventoried energy they hold on winter days that hit a certain low-temperature threshold.

But after the court’s ruling, it will be significantly blunted. The three-judge panel found that the program’s inclusion of coal, hydro, biomass and nuclear generators as eligible for compensation is arbitrary and capricious because they already maintain inventoried energy and would not change their behavior in response to the approximately $40 million in new payments that would be sent their way.

“In reviewing FERC’s June 2020 order, we conclude that FERC approved IEP without adequately considering legitimate objections from complainants who pointed out that it would result in windfall payments to nuclear, coal, biomass and hydroelectric resources,” wrote Judge Robert Wilkins in the court’s opinion. 

The court left the rest of the IEP in place, allowing the RTO to compensate oil, natural gas and refuse generators. 

The association representing generators in New England said the ruling is unfair and that the court “cherry-picked its own design, carving the market even further into haves and have nots.”

“At a moment of a national refocus on electric reliability, it flies in the face of logic to deliberately choose to not pay for an identified reliability service for some, but yes to others,” said Dan Dolan, president of the New England Power Generators Association. “With electric reliability in New England’s winters an ongoing focus, I simply hope this is not a harbinger of the future of the electricity market.”

ISO-NE spokesperson Matt Kakley said the grid operator is reviewing the decision.

In addition to throwing doubt on the efficacy of the program starting in 2023/24, the ruling could also affect the grid operators’ plans going forward for this winter. ISO-NE has been considering proposing a new version of the IEP as well as possibly bringing back its Winter Reliability Program. (See ISO-NE Weighs Reviving Reliability Programs for this Winter)

The court’s ruling — and the position of Glick, who in 2020 called the program “an ill-conceived giveaway” — seem to lower the chances that FERC would approve the IEP or a similar program for the winter of 2022/23. 

The petitioners challenging the program included New Hampshire and Massachusetts, municipally-owned electric utilities and environmental groups including the Sierra Club and the Union of Concerned Scientists. Some had asked for the program to be eliminated altogether, but the court rejected that, agreeing with FERC and ISO-NE that the overall program is not unreasonable.

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FERC Partially Accepts NYISO Order 2222 Compliance

FERC on Thursday accepted NYISO’s Order 2222 compliance filing but directed the ISO to file revisions related to small utility opt-in requirements, interconnection rules and other issues (ER21-2460).

The commission also asked NYISO to propose an effective date for its compliance filing in the fourth quarter of 2022 and further propose a reasonable effective date by which it will comply with the requirement to allow DERs to provide all the ancillary services they are technically capable of providing through aggregation while also addressing NYISO’s reliability and visibility concerns.

In its filing submitted last November, NYISO maintained that its existing distributed energy resources (DER) and aggregation participation model satisfactorily complies with the majority of directives in Order 2222. (See NYISO Shares Order 2222 Response with Stakeholders.)

The commission found that NYISO’s existing rules comply with Order 2222 requirements to establish a 100-kW minimum size requirement for DER aggregations (DERA); to propose a maximum capacity requirement for individual DERs participating in its markets through an aggregation; allow a single qualifying DER to avail itself of the proposed DERA rules by serving as its own aggregator; and address distribution factors and bidding parameters for DERAs.

Small Utility Opt-in

The commission found that NYISO complied with the requirement that it accept bids from a DERA if its aggregation includes resources that are customers of utilities that distributed more than 4 million MWh in the previous fiscal year.

However, it found the ISO only partially complied with the “small utility opt-in” provision, a requirement to reject bids from DERA’s that include customers of utilities that distributed less than 4 million MWh in the previous year, unless the relevant electric retail regulatory authority (RERRA) permits those customers to bid into RTO/ISO markets.

Protestors found fault with the ISO’s proposal to apply the opt-in rule to “load serving entities,” which in New York includes small competitive retail suppliers knows as “energy service companies.” The protestors argued that RERRA approvals would be complicated for those suppliers because they have no technical role in distribution system operations. FERC agreed with their argument and ordered NYISO to replace the term LSE with “distribution utility.”

FERC also required NYISO to clarify the aggregator’s responsibilities associated with changes to a RERRA’s opt-in determination and clarify the timing of a resource’s ineligibility when the small utility decides to prohibit its participation.

FERC additionally found that, in complying with Order 2222’s directive for RTOs/ISOs to exempt distribution-connected DERs from their interconnection rules, NYISO inadvertently exempted the interconnections of DERs on both the distribution and transmission system. The commission directed the ISO to fix that error and clarify that interconnection of DERA through the distribution system is exempt from the ISO’s small generator interconnection procedures.

Participation Model

The commission found that NYISO’s proposal complies with the requirement to establish DER aggregators as a type of market participant, but only partially complies with the requirement to allow such aggregators to register an aggregation under one or more participation models in NYISO’s tariff that accommodate its physical and operational characteristics.

FERC acknowledged NYISO’s reliability concerns related to allowing an aggregation to participate through a particular model when some of its resources may not satisfy all the requirements of that model.

“We believe, however, that NYISO could address its reliability concerns by means other than requiring that all individual DERs within the aggregation satisfy the relevant reliability requirements, such as the one-hour sustainability requirement. Therefore, so long as some of the DERs in the aggregation can satisfy the relevant requirements to provide certain ancillary services (e.g., the one-hour sustainability requirement), we find that those DERs should be able to provide those ancillary services through aggregation…” FERC said.

The commission agreed with NYISO that it should not be required to change its capacity market qualification requirements to enable energy efficiency resources or any other resource type that currently does not qualify to participate in its capacity market. Further, because Order 2222 does not require RTOs/ISOs to model energy efficiency in a certain way, FERC rejected as out of scope the arguments raised by various parties on whether energy efficiency should be modeled as supply- or demand-side participation.

Double Counting

NYISO’s existing model affords DERs the opportunity to participate simultaneously in one or more retail programs and the wholesale markets, and its proposal complies with the requirement to allow DERs to provide multiple wholesale services, the commission said.

But the ISO’s proposal only partially complies with the requirement to include appropriate restrictions on the participation of DERs through aggregations, if narrowly designed to avoid counting more than once the services provided by DERs, the commission said, directing a further compliance filing that specifies relevant tariff language.

The commission found that NYISO complied with the requirement to provide a detailed, technical explanation for the geographical scope of its proposed locational requirements.

“However, we find that NYISO does not comply with the requirement to revise its tariff to establish locational requirements for [DERs] to participate in a [DERA] that are as geographically broad as technically feasible,” FERC said regarding the compliance filing to specify the criteria NYISO will use to establish a set of transmission nodes at which individual DERs may aggregate.

The commission also found that NYISO did not comply with the requirement to require the DER aggregator to update its list of individual resources and associated information as it changes; the commission directed the ISO to revise the relevant tariff section, as well as include information and data requirements.

Metering and Telemetry

The commission found that NYISO’s proposal only partially complied with the requirement to establish market rules that address metering and telemetry hardware and software requirements necessary for DERAs to participate in RTO/ISO markets because its tariff lacks the deadline for meter data submission for settlements and does not include references to the specific documents that contain further technical details.

In addition, FERC found the ISO partially complied with the requirement to explain why its proposed metering and telemetry requirements for DERAs are just and reasonable and do not pose an unnecessary and undue barrier to individual DERs joining an aggregation.

“NYISO’s filing lacks clarity regarding its protocols for sharing metering and telemetry data and the meter data submission deadline,” the commission said, requesting the ISO to revise its tariff to include the meter data submission deadline for settlement and specify which entity must submit meter data.

FERC also directed a further compliance filing to include references to specific documents that contain further technical details with respect to telemetry.

The commission found that NYISO sufficiently supported the need for aggregations to provide six-second telemetry, consistent with its requirements for other suppliers, to meet the New York-specific local reliability rule that requires NYISO to respond to thermal overloads in under five minutes.

But the commission also directed a further compliance filing that establishes protocols for sharing metering and telemetry data and ensuring that such protocols minimize costs and other burdens and address privacy and cybersecurity concerns.

Market Rules

Order 2222 requires RTOs and ISOs to revise their tariffs to establish market rules that address coordination between the RTO/ISO, the DER aggregator, the distribution utility and the RERRAs.

NYISO’s proposal only partially complied with those requirements with respect to the role of distribution utilities, the commission found, directing the ISO to continue to coordinate with utilities in developing the further compliance filing.

Furthermore, given that NYISO’s tariff provides utilities with 60 days to review risks to the reliable and safe operation of the distribution system from DERA participation, the commission said it agreed with New York transmission owners that the tariff language lacks clarity regarding the circumstances in which the utility review process applies, directing a further compliance filing with tariff revisions consistent with the suggested alternative language that NYISO proposes in its answer.

The commission found that NYISO must address six of seven coordination requirements to ensure a fully comprehensive, non-discriminatory and transparent distribution utility review process.

First, the results of a distribution utility’s review must be incorporated into the DERA registration process and second, the tariff should include criteria by which the utilities will determine whether each proposed DER is able to participate in a DERA.

Third, the commission directed NYISO to clarify that the scope of distribution utility review of distribution system reliability impacts is limited to incremental impacts from a resource’s participation in an aggregation that were not previously considered by the utility during the interconnection study process for that resource.

Fourth, NYISO must propose in its tariff that a distribution utility provide a showing that explains any reliability findings as required by Order 2222, the commission said.

Fifth, FERC found that NYISO only partially complies with the Order 2222 requirement that a distribution utility have the opportunity to request that the RTO/ISO place operational limitations on an aggregation, or that the removal of a DER from an aggregation be based on specific significant reliability or safety concerns that the distribution utility clearly demonstrates to the RTO/ISO and DERA on a case-by-case basis.

Finally, the commission found that NYISO’s proposed distribution utility review process is only partially compliant with the information sharing requirements of Order 2222.

Coordination Requirements

The commission found that NYISO’s proposal partially complies with the operational coordination requirements of Order 2222 and fully complies with the requirement that the DER aggregator must report to the RTO/ISO any changes to its offered quantity and related distribution factors that result from distribution line faults or outages.

NYISO’s proposal complies with the requirement to revise its tariff to include coordination protocols and processes for the operating day that allow distribution utilities to override RTO/ISO dispatch of a DERA in circumstances where such override is needed to maintain the reliable and safe operation of the distribution system, the commission found.

“We recognize concerns that NYISO’s proposal may subject an aggregator to risk of penalties for situations beyond its control; however, … this requirement will incent [DER] aggregators to register individual [DERs] on less-constrained portions of distribution networks in order to minimize the likelihood of incurring non-performance penalties,” the commission said.

However, NYISO’s proposed tariff revisions lack specificity regarding the existing resource non-performance penalties that would apply to an aggregation when a utility overrides NYISO’s dispatch, prompting request for a further tariff revision to specify the existing non-performance penalties.

In addition, the commission found that NYISO’s tariff does not sufficiently address data flows and communication between NYISO, the aggregator and the distribution utility, and thus directed tariff revisions to describe what data and information will be communicated and to define more clearly the communication that will occur in this coordination process.

The commission also directed a further tariff revision to require that any information provided to NYISO by a RERRA about a specific aggregation must be shared with the aggregator, along with another revision to allow distribution utilities to review the reliability and safety impact of “any change to an aggregation.”

The commission found that NYISO’s proposal does not comply with the requirement that the DER aggregator must attest that its aggregation complies with the tariffs and operating procedures of the distribution utilities and the rules and regulations of any RERRA, and directed a further compliance filing that revises the tariff to specify that the aggregator must attest to its compliance with the tariffs and operating procedures of the distribution utilities and the rules and regulations of any RERRA.

The commission also directed NYISO to file a further compliance filing proposing an effective date by which it will allow DERs in heterogeneous aggregations to provide all of the ancillary services that they are technically capable of providing through aggregation, and to propose an effective date for its compliance filing in the fourth quarter of 2022 at least two weeks prior to the proposed effective date.

Separate Statements

Commissioner James P. Danly concurred with Thursday’s order in a separate statement, saying that NYISO made a good faith effort to comply with Order 2222, which he continues to disagree with, though he agreed that the ISO “failed to fully comply with its scores of dictates.”

“I do not envy NYISO the compliance task we imposed upon it. One hundred percent compliance probably is impossible in a first, or perhaps even second, attempt,” Danly said. “We shall see.”

Danly said NYISO’s failure to fully comply underscores his original concern about the commission’s interference in the administration of RTO markets and distribution-level systems, with Order 2222 not only supplanting many state powers but also permitting RTOs “extremely limited discretion to do anything other than step in line with the commission’s directives for how every little thing should work,” Danly said.

Commissioner Allison Clements issued a partial dissent, expressing concern that the commission allowed NYISO to exclude energy efficiency from DER aggregations because it does not meet the ISO’s general eligibility rules.

Clements argued that the finding “erodes the rule’s plain requirement that an RTO/ISO’s rules may not ‘prohibit any particular type of [DER] technology from participating in [DER] aggregations.’ It sets precedent that may, in the future, allow RTO/ISOs to prevent the participation of other resource types.”

“I remain hopeful that, as the commission evaluates future compliance filings of Order No. 2222, it will strike the right balance between offering flexibility and upholding its requirements as written,” she wrote.

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Counterflow: Stuff That Ain’t So

tesla powerwallSteve Huntoon | Steve Huntoon

Yes, federal policy needs to advance rational transmission grid expansion. We need AC interconnections between ERCOT and the rest of the country.[1] We need more — not less — competition in transmission.[2] And as I wrote in my last column (and before), we should apply unique emergency line ratings for planning/interconnection studies and deploy technologies that increase physical capacity of grid elements.[3] These are no-brainers that FERC continues to eschew.

Which brings me to what FERC is doing in its massive April Notice of Proposed Rulemaking on transmission planning and cost allocation (RM21-17). FERC says it begins with “facts on the ground.” Yes, let’s do!

NOPR Claim #1: Transmission Expansion isn’t Happening on a Regular Basis Through Regional Processes

The NOPR asserts that transmission expansion isn’t happening through regional planning processes on a regular or consistent basis and, “instead,” significant expansion is happening through upgrades constructed as a result of generator interconnection requests.[4]

Wrong, as this PJM chart shows: “Baseline” are planning process upgrades and “Network” are generator interconnection upgrades.[5] The former is $32.4 billion and the latter is $6.6 billion.

Baseline vs network spending (PJM) Content.jpgPJM baseline planning process upgrades totaled $32.4 billion as of December 2021, while network generator interconnection upgrades totaled $6.6 billion. | PJM

Moreover, the $32.4 billion in Baseline upgrades does not include individual transmission owner “supplemental projects,” of which there was $3.3 billion last year alone.[6]

It’s hard to figure out how the NOPR could have this “fact” so wrong, but it may stem from assuming that Baseline upgrades that are not cost allocated across a region somehow only provide “local” benefits. This leads us to:

NOPR Claim #2: Upgrades not Regionally Cost Allocated Don’t Provide System Benefits

The only upgrades in PJM that are always regionally cost allocated are 500-kV and above facilities (and double circuit 345-kV lines). There are many upgrades not regionally cost allocated that provide non-local benefits, including many upgrades that are below 200 kV, cost less than $5 million, are needed in three years or less, and/or relieve contingency violations that would otherwise reduce flow on higher voltage facilities.[7] Nor is the NOPR correct that upgrades not regionally cost allocated are not regionally planned[8] — all $32.4 billion in Baseline upgrades were regionally planned by PJM.

And regarding individual TO “supplemental projects,” these too can provide system benefits as described by PJM to include: “enhancing grid resilience and security, promoting operational flexibility [and] addressing transmission asset health.”[9]

The relatively small number of regionally cost allocated upgrades is a good thing. Why spend billions on a large 500-kV project when an upgrade of an existing transmission facility can relieve the reliability violation?

And non-regionally cost allocated upgrades surely provide no less system benefit than generator interconnection upgrades, which tend to be localized around the point of generator interconnection.

Having created an invalid preference for regionally cost allocated projects over other upgrades, the NOPR follows up by eliminating competition for the former on grounds that eliminating competition will incent transmission owners to pursue more of them.[10] Yikes!

NOPR Claim #3: Generator Interconnection Costs Have Seen a ‘Dramatic Increase’

The NOPR claims that interconnection costs for new generation in $/kw have seen a “dramatic increase.”[11] It arrives at this conclusion based on data from a selected MISO subregion and from PJM that conflate the upgrade cost per kW of actual projects with that cost for proposed projects.[12] Instead, what this data suggest is that participant funding serves to weed out proposed projects with uneconomic interconnection costs. A good thing.

When apples (earlier actual projects) are compared to apples (later actual projects), the source study by Lawrence Berkeley presents this chart, and comes to the opposite conclusion about interconnection costs over time. [13]

In the study’s own words: “These results combine the MISO, PJM, and EIA data to assess how location and queue date correlate with transmission costs. … There is little evidence of significant cost trends over time ….”[14]

In other words, the source study relied on by the NOPR says the opposite of what the NOPR says it says.

As for the NOPR’s poster child for high generator interconnection costs, it cites a 120-MW solar project in PJM and says that the project faced interconnection costs of $1.5 billion, including rebuilding 500-kV lines.[15] Needless to say it is easy to cherry pick one interconnection request out of 8,509 interconnection requests in PJM over the past 25 years.[16]

And lest we forget, those opposed to participant funding would force consumers to pay that $1.5 billion — rather than incent the project developer to find a lower cost interconnection point (or perhaps pursue another project).[17]  Yikes!

NOPR Claim #4: Transmission Customers Unfairly Benefit from Generator Interconnection Upgrades

Here’s another “fact” that drives me up a wall. The NOPR says that generator-paid upgrades can create system benefits for transmission customers who don’t pay for the upgrades.[18] This claimed benefit is more capacity, aka “headroom” on transmission circuits.

This is possible but, as I’ve pointed out before,[19] ignores the fact that a generator benefits for free from all the headroom that already exists on circuits because of past upgrades paid for by transmission customers. There is zero point zero evidence that the headroom created by generator upgrades is more valuable to transmission customers than the headroom created by transmission customers’ upgrades that generators benefit from.[20]

Bottom Line

We need rational transmission policies (like the ones I identified at the outset). Let’s base policies on real facts.

[4] Docket No. RM21-17-000, issued April 21, ¶ 36: “Significant expansion of the transmission system instead appears to occur through interconnection-related network upgrades constructed as a result of generator interconnection requests.” (emphasis added, footnote omitted).

[6] https://pjm.com/-/media/documents/ferc/filings/2022/20220613-pjm-supplemental-comments-on-doe-noi-on-tfp.ashx, page 7, footnote 17. By one tally, supplement project costs since 2005 have exceeded $41 billion.

[7] This last category may be a result of the change in 2013 to a solution-based DFAX methodology that allocates costs based on loadings of the lower voltage solution instead of loadings on the higher voltage facility whose outage causes the violation. https://elibrary.ferc.gov/eLibrary/filedownload?fileid=01A68F74-66E2-5005-8110-C31FAFC91712 The loadings on the lower voltage solution tend to be limited to a single transmission owner zone.

[8] “ … regional transmission planning and cost allocation processes generally have resulted in few regionally planned transmission facilities being selected and ultimately built.” NOPR ¶ 245.

[9] Footnote 6, pages 6-7.

[10] NOPR ¶ 353.

[11] NOPR ¶ 37, 38, 162.

[12] The discussion of MISO and PJM costs in NOPR ¶ 38 relies on Figure 2 of a MISO document here, https://cdn.misoenergy.org/20200520%20AC%20Item%2004%20Current%20Issue%20-%20Generator%20Interconnection%20Queue447230.pdf, and Table 2 of the Lawrence Berkeley National Laboratory study here, https://www.sciencedirect.com/science/article/abs/pii/S0301421519305816?via%3Dihub. (click on “View Open Manuscript”). Regarding the MISO data please note that data for most of the other MISO subregions do not support the NOPR’s claim — even if the data were apples to apples (which they’re not).

[13] Figure 6, page 46, of the above Lawrence Berkeley study.

[14] Page 17 of the above Lawrence Berkeley study (emphasis added).

[15] NOPR ¶ 38 and footnote 58. The subject feasibility study is here, https://pjm.com/pub/planning/project-queues/feas_docs/ae1135_fea.pdf.

[18] NOPR ¶ 165.

[19] Column referenced in footnote 17.

[20] Conversely, if generators can shift interconnection costs to consumers on the assumption of headroom benefit to consumers then generators should pay for the headroom they presently get for free.

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CAISO Order 2222 Filing Needs Some Work, FERC Says

FERC on Thursday accepted CAISO’s Order 2222 compliance filing but told the ISO to submit an update addressing concerns about its model for aggregated distributed energy resources, rules for participation of DERs that are customers of small utilities and other matters.

Order 2222, issued in September 2020, is meant to clear the way for distributed energy resource aggregations (DERAs) to participate in organized wholesale markets. Many DERs, such as rooftop solar arrays, are too small to participate in wholesale markets by themselves and must be grouped together by aggregators.

CAISO’s compliance filing was one of the first two FERC ruled on under Order 2222 (ER21-2455). The commission also conditionally accepted NYISO’s compliance plan Thursday. (See related story, FERC Partially Accepts NYISO Order 2222 Compliance.)

In its filing, originally submitted in July 2021, CAISO said that in 2016 it was the first ISO or RTO to establish a model for DERAs and that it had allowed DERs to participate in its market more than a decade before that.

“Because the CAISO was the first RTO/ISO to establish a DERA model, the CAISO already complies with the vast majority of the mandates in Order No. 2222,” it said. “This filing generally describes the CAISO’s current tariff revisions, and the few incremental changes the CAISO proposes to implement to align its tariff with the final rule.”

FERC was not completely satisfied that CAISO’s existing tariff with small changes met Order 2222’s requirements.

Last October, it asked CAISO for additional details about its compliance plans, including its market participation model for DERAs. (See FERC Asks Details from CAISO, NYISO on Order 2222 Compliance.)

Even after CAISO responded to the request in November 2021, FERC continued to have questions, which it detailed in Thursday’s order while telling CAISO to revise its filing.

DER Participation Model

In Order 2222, FERC required each RTO/ISO to establish DERAs as a type of market participant and to allow them to register under a participation model that accommodated their physical and operational characteristics.

“The commission explained that each RTO/ISO can comply with the requirement … by modifying its existing participation models to facilitate the participation of distributed energy resource aggregations, by establishing one or more new participation models for distributed energy resource aggregations, or by adopting a combination of those two approaches,” FERC wrote.  

The commission said it would evaluate each RTO/ISO proposal to determine if it met Order 2222’s goals of allowing distributed energy resources to “provide all services that they are technically capable of providing through aggregation.”

CAISO said in its compliance filing that it already complies with Order 2222 by allowing DERAs to participate in its market.

In a protest, CPower Energy Management said that “for reasons neither explained nor apparent, CAISO proposes to prohibit aggregations consisting of only demand response resources,” FERC said.

“CPower contends that this decision creates an artificial barrier that is inappropriate and begs the question of why aggregators may only participate in the distributed energy resource aggregation model if the aggregation includes one or more resources with injection capability,” FERC said.

In a separate protest, Advanced Energy Economy and the Sustainable FERC Project raised additional concerns with CAISO’s DERA participation model.

FERC found that CAISO had complied with the requirement to establish DERAs as a type of market participant but found “that CAISO only partially complies with the requirement to allow distributed energy resource aggregators to register distributed energy resource aggregations under one or more participation models in CAISO’s Tariff that accommodate the physical and operational characteristics of the distributed energy resource aggregation.”

FERC also found that CAISO’s proposal to not allow aggregators of “only demand response resources (i.e., homogeneous demand response aggregators) to participate as distributed energy resource aggregators does not comply with Order No. 2222.”

It ordered CAISO to revise its DERA model to allow a homogeneous aggregation of what CAISO called “distributed curtailment resources” to participate or to show that its existing demand response models comply with Order 2222.

Small Utility Opt-in

FERC also had concerns about CAISO’s treatment of Order 2222’s “small utility opt-in” provisions.  

The order requires each RTO/ISO to accept bids from a DERA if it includes resources that are customers of utilities that distributed more than 4 million MWh in the previous fiscal year. But it prohibits RTOs/ISOs from accepting bids from an aggregator if it includes resources that are customers of small utilities that distribute less than 4 million MWh per year — unless the relevant electric retail regulatory authority (RERRA) permits such customers to be bid into RTO/ISO markets by an aggregator.

The commission said CAISO’s proposal essentially complied with the order’s requirement but “lacks necessary precision” because it “deviates without explanation” from the order’s specific wording of the requirement and exception. It told CAISO to revise its proposed tariff language and resubmit it.

“We also find that CAISO’s proposal partially complies with the requirement to explain how it will implement the small utility opt-in … [but] we find that CAISO does not clearly explain the process by which a distributed energy resource provider must notify CAISO of a change in the RERRA’s opt-in determination — specifically, when a RERRA that previously authorized the participation of a resource that is a customer of a small utility decides to bar such participation,” FERC said.

FERC also found that CAISO’s proposal inappropriately allows a local regulatory authority to prevent participation in the CAISO markets by a DER aggregator “that aggregates in utilities that distributed over 4 million MWh in the previous fiscal year.”

“Specifically, CAISO’s proposal requires a distributed energy resource provider that aggregates in utilities that distributed over 4 million MWh in the previous fiscal year to certify to CAISO that its participation is not prohibited by the local regulatory authority,” FERC said. “Order No. 2222 did not provide a mechanism for RERRAs to provide for such a limitation on participation. Rather, the commission specifically declined to provide an opt-out that enables RERRAs to prohibit all distributed energy resources from participating in the RTO/ISO markets through” DER aggregations.

Other Issues

FERC singled out other issues in CAISO’s compliance filing involving double counting of DERAs that participate in one or more retail markets, maximum and minimum sizes for DERAs, and metering and telemetry hardware and software requirements necessary for distributed energy resource aggregations to participate in RTO/ISO markets.

FERC directed CAISO to file an additional compliance filing with 60 days to address the issues it identified.

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MISO Describes Bleak RA Future, Stakeholders Push Back

INDIANAPOLIS, Ind. — MISO executives issued sobering warnings about its future resource adequacy in front of its Board of Directors last week as some state regulators and stakeholders pushed back on the narrative.

“I’m going to make some folks uncomfortable, both stakeholders and MISO staff … but we need to get this on the table,” Wayne Schug, vice president of strategy and business development said Thursday before a board presentation that he said had not yet been vetted with stakeholders.

Schug said MISO has been in contact with state regulators and lawmakers since its April planning resource auction (PRA) resulted in a 1.2-GW capacity shortage across MISO Midwest. The RTO has said the deficit might force it to order temporary, controlled load shedding this summer, and it predicts insufficient firm resources to handle summer peak forecasts under typical demand. (See MISO’s 2022/23 Capacity Auction Lays Bare Shortfalls in Midwest.)

Though MISO has added more resources than it has retired in recent years, Schug said the grid operator has less accredited capacity because most of the additions are largely intermittent.

He said the footprint is in desperate need of controllable resources “to balance weather-dependent resources” based on a future assessment of its supply. The Midwest capacity shortfall means MISO has a one-day-in-5.6-years loss-of-load expectation, short of its target one-day-in-10-years LOLE, Schug said.

“We need to think about the consequences of that and the changes we need to make as a market operator,” he said. “We’re below our target reserve margins. It means MISO will have to declare emergencies more often. … It does not mean that grid reliability of the top tier standard is at risk.”

Schug said while MISO sees load shed as a far-off possibility, it doesn’t mean it may happen.  “It does not move the needle to probably or likely, but it does increase the risk,” he explained

He said while customers have “grace” when a downed power line cuts off power, they view outages caused by insufficient generation as unacceptable. MISO membership needs to ensure that some gas units remain online, Schug said, as the grid operator’s capacity needs are longer than the four hours that most battery storage can supply.

“We need the capacity when the renewables aren’t there. The gas still needs to be there; it will be utilized less often, but it needs to be there,” he said.

MISO said its preliminary 2022 regional resource assessment shows additions of largely renewable resources, coupled with retirement of controllable resources that will further chip away at its stores of accredited capacity. Schug said the planned additions are simply not making up for planned retirements.

“In the next five years, we’re retiring a lot more generation than we’re bringing online,” he said. The risk is mounting, Schug said, and MISO and its members need to discuss whether all scheduled generation retirements should proceed as planned.

“It doesn’t mean there’s not time to address this, but the time is growing shorter and shorter. It takes time to build new capacity,” he said. “Honestly, we’re behind in this discussion. Folks are making long-term decisions now. And we need to give them information to make appropriate decisions to sustain reliability.”

“Time is not on our side,” director Phyllis Currie said by way of agreement.

Director Nancy Lange said MISO doesn’t appear to be in good shape in the near-term or the next 20 years.

“We have an issue we need to deal with,” Schug said. “It’s going to take a village. It’s going to take everything we have.”

Schug said states will need to know their neighbors’ generation plans to ensure that no one is negatively impacting the other and everyone is “bringing appropriate resources to the table.”

Stakeholders Offer MISO Guidance

Indiana Commissioner Sarah Freeman, president of the Organization of MISO States (OMS), said MISO’s summer readiness projection that its firm resources are insufficient to cover peak demand run counter to the Independent Market Monitor’s assessment of expected demand, which relied on the same source material. She said the seasonal assessment process lacks transparency and said MISO’s “messaging and information sharing” on resource adequacy could use some work.

“The early messaging from MISO in this area was problematic and certainly needed more context to be digestible by most consumers of media,” Freeman said. “MISO’s summer assessment is a well-known and well-covered event that generates a lot of headlines, but it’s also a largely undefined process.

“I’m going to be sharing everything I reasonably, ethically and legally can with MISO. Collaboration is the only way to solve this,” Freeman said of the resource adequacy issues.

OMS Executive Director Marcus Hawkins said if the RTO continues to usher the usual 3 GW through the interconnection queue each year, it will avoid the worst — a 10 GW shortfall contemplated in this year’s OMS-MISO survey. (See OMS-MISO RA Survey Says Supply Deficits Could Top 10 GW by 2027.)

“And that’s before the improvements to the queue,” he added, referencing the grid operator’s goal to shorten the queue’s timeline from 505 days to a single year.

Michigan Public Power Agency’s Tom Weeks said MISO’s presentation didn’t devote enough time to how the RTO can get more generation interconnected faster.

“To me, that’s a very direct lever of control there,” Weeks said.

Travis Stewart, representing the Coalition of Midwest Power Producers, said staff are likely undercounting future renewable additions. He also said MISO didn’t seem to be considering that aging generators can catastrophically fail when  kept online beyond retirement dates.

Stewart said MISO must employ a sloped demand curve in next year’s capacity auction.

“We can do it immediately. We can stop resources from exiting the market based on the inefficient signals MISO’s market is sending them,” he said.

Enviros: Transmission Could Have Helped

Clean Grid Alliance Executive Director Beth Soholt also said she was “concerned” about MISO’s messaging in recent weeks.

“The capacity shortage we are facing at this point is not the fault of wind and solar generation. In fact, those resources have been delivering both energy and capacity as expected,” she told the board. “The shortage is a problem of planning. MISO has known about the generation shift and the timing just like the rest of us. There is a reason the environmental sector and Clean Grid Alliance have been saying for years the futures MISO uses to plan its system fall far short of what is needed.”  

Soholt said MISO needs a robust grid to deliver generation to load. She said while MISO is doing meaningfully planning now with its long-range transmission plan, it’s simply being developed too late to “support enough new resource additions to offset the retirements.” (See MISO Makes Business Case on Long-range Tx Plan.)

“MISO needs to own that it is responsible for this situation and that includes not delivering on the transmission grid of the future in time. … MISO needs to ensure that transmission planning and construction are complete in time to serve the needs of new resources,” she said.

Soholt said MISO had the opportunity to begin serious transmission planning five years ago with its regional transmission overlay study, but said it was “cratered by certain stakeholders.”

She blasted MISO’s use of a vertical demand curve in the PRA and said the auction design ensures it doesn’t send an efficient pricing signal “until the last minute.”

She also said MISO could use better market products.

“The developer community is listening to this presentation and wants to bring solutions, but the [MISO] tariff is not keeping up with getting new resources on the system,” Soholt said. “MISO’s markets and market products are not defined in such a way that all resources can provide the full range of products and services they are capable of providing.”

She urged MISO to adopt a more positive narrative, confidence and a “can do” attitude when it comes to the resource transition and to hire outside professionals to assist with its communications.

“Without the central leadership of the [RTO], states will fall back on making inefficient decisions in isolation. It is not an insurmountable challenge to reach much higher levels of clean and affordable resources, but it does require planning and coordination,” Soholt said.

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3 Keys to Fixing the Cash-flow Dilemma in CO2 Capture

There are three things that can fix the cash flow problem in the carbon capture and storage (CCS) industry, says Jeff Brown, managing director of the Energy Futures Financing Forum: Direct pay incentives, project developers with a clear vision and giving developers just one job to do.

Prices and demand are too low to generate the cash flows necessary for long-term financing of capturing CO2, either from the air or at a point source like a cement factory.

Current tax incentives to bridge those gaps are not helping the CCS industry, Brown said Thursday at the Global CCS Institute’s 10th Annual D.C. Forum.

“Tax credits don’t incentivize because basically no corporations pay taxes … and if they do, they have excess tax credits,” he said. “Nobody can use tax credits, except for a very limited volume on Wall Street.”

Furthermore, tax credits are not cash, so they cannot be used to pay off debt. To resolve those issues, Brown said, tax credits need a direct-pay function. Direct pay would allocate tax credits as tax overpayments that can be drawn as cash from the Treasury. The Build Back Better Act included a direct-pay measure, and CCS advocacy organizations are continuing to lobby for its inclusion in smaller legislative packages now under discussion.

In Brown’s view, federal and state governments also have a role to play in simplifying the work that developers must do to make a CCS project successful.

“You need government-owned … or government-supported … pipelines and sequestration, so the developer only has one job — to figure out how to capture the carbon,” Brown said. A government-owned infrastructure approach would minimize timing challenges associated with siting capture facilities, the pipeline for transportation to a sequestration location, and the sequestration location itself.

Developers also need a vision for how to deploy capture infrastructure at scale under current incentive structures, he said.

“People don’t do the first-of-a-kind project unless they can see a trajectory to building enough of them to get their cost-of-capture down,” he said. If there is no “policy-supported trajectory,” the price per ton of CO2 is not going to be high enough to support the project financials.

If the incentives that are in place do not support that level of growth, Brown said “something has to give.”

“Either you have to have policy support for hundreds of projects, or you need to raise the level of the policy incentive so that, within a reasonable number of new units, you can get to the right price,” he said.

Market Vision

Reaching a normal rate of return on a CCS project is the “hardest part” for developers in the nascent CCS market, Michael Brownlie, division director at Macquarie Bank, said during the forum session on finance. The point-source CCS “market” is currently just a set of deals in which a CO2 emitter, a capturer and a sequesterer are integrated through a contract. That could change, he said.

“There is a possibility that we can get a market disaggregation of these things, and you just put CO2 in a pipeline and the lowest bidder for that CO2 [one willing to charge the emitter the least] picks it up and away it goes,” he said. “That’s the dream, but we’re a long way from getting anywhere near that.”

In a perfect market scenario, CCS would have a “durable policy instrument” that creates a revenue source for CO2, said Jay Dessy, director of Breakthrough Energy Catalyst. That instrument could be a carbon tax or tax credits that are enhanced through deadline extensions, direct-pay guidelines or qualifying technologies.

“I think you’ll see CCS applications that get focused on certain sectors, where it makes most cost-effective sense, whether that’s cement or other carbon-intensive businesses,” Dessy said.

Khalid Abedin, managing investment officer at the U.S. Department of Energy’s Loan Programs Office, says he sees the future of CCS as “a commodity similar to natural gas markets.”

In that future, CO2 would be available at different regional hubs, each with their own price point, where buyers and sellers can transact.

“People who are buying the CO2 might be using it for industrial purposes … and the seller, through a pipeline that they’re going to build, is going to take the CO2 to the delivery point,” he said. With a clear trading price, he added, market participants could easily forecast what the cash flow would be for a CCS project.

“That’s what I want the future to look like in maybe five or 10 years,” he said.

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Biden Calls on Major Economies to End Methane Flaring by 2030

With inflation raging and gasoline prices at record highs, President Joe Biden on Friday called for new international initiatives to cut greenhouse gas emissions and dependence on Russian fossil fuels.

Despite mounting threats to energy and food security triggered by Russia’s war on Ukraine, Biden told members of the Major Economies Forum (MEF) on Energy and Climate in a virtual meeting, “We cannot afford to let the critical goal of limiting global warming to 1.5 degrees Celsius slip out of our reach. And the science tells us that the window for action is narrowing rapidly.

“We have to dedicate ourselves as we look forward to delivering on existing goals and undertaking additional efforts to boost our progress,” said Biden, who has sought to assert U.S. leadership on climate policy despite the economic and political challenges he faces with the upcoming midterm elections.

Speaking at the meeting, United Nations Secretary-General António Guterres was even more direct in linking the war in Ukraine to the need for urgent climate action.

“We seem trapped in a world where fossil fuel producers and financiers have humanity by the throat,” Guterres said. “The argument of putting climate action aside to deal with domestic problems also rings hollow. Had we invested earlier and massively in renewable energy, we would not find ourselves once again at the mercy of unstable fossil fuel markets,” he said.

New efforts to reduce emissions from methane flaring and leaks led the list of proposed actions, building on the Global Methane Pledge launched at the UN Climate Change Conference of the Parties (COP 26) in Glasgow in November. (See US, Canada, EU Pledge to Slash Methane Emissions.)

“Each year, our existing energy system leaks enough methane to meet the needs for the entire European power sector,” Biden said, announcing the Global Methane Pledge Energy Pathway. “We flare enough gas to offset nearly all of the [European Union’s] gas imports from Russia. And so, by stopping the leaking and flaring of this super-potent greenhouse gas and capturing this resource for countries that need it, we’re addressing two problems at once.”

Argentina, Canada, Egypt, Germany, Italy, Japan, Mexico, Nigeria and Norway have joined the initiative, committing to eliminate “routine flaring” no later than 2030 and pledging $59 million in “dedicated funding and in-kind assistance,” according to a meeting summary from the White House.

Egypt, which will host COP 27 in Sharm el-Sheikh in November, is also among the 120 countries that have signed the original pledge to cut methane emissions 30% from 2020 levels by 2030.

Biden called on other countries to adopt the U.S. goal for zero-emission vehicles — electric, plug-in hybrid and fuel cell cars — to make up 50% of all light-duty car sales by 2030.

With Canada, Chile, the European Commission, France, Germany, Italy, Mexico, Norway and the United Kingdom signing on, Biden said, “Over the long run, we can remove the pain of volatile gas prices and reduce transportation emissions.”

Nonspecific Pledges and Support

Former President Barack Obama founded the MEF in 2009, with 16 other countries. At Friday’s meeting, 22 countries, the European Commission and the United Nations were represented.

The meeting was also a precursor for the Global Clean Energy Action Forum, a pre-COP 27 event to be held in Pittsburgh in September.

But, as reported in the White House summary, results coming out of the MEF meeting consisted mostly of nonspecific pledges for future action and expressions of support.

Several countries stated their intention to increase their Nationally Determined Contributions (NDCs) to emissions reductions — to keep global warming to 1.5 degrees by 2050 — with announcements to be made at COP 27. But only Australia provided a solid number for its “enhanced NDC,” committing to cut emissions 43% below 2005 levels by 2030.

Similarly, other countries “supported,” but have yet to commit to act on, Biden’s other new initiatives.

Biden called for a $90 billion international commitment for clean energy demonstration projects such as green hydrogen production and carbon capture by the September forum in Pittsburgh. The U.S. and the European Commission are planning a total of $50 billion in funding for such projects, the White House said, including $21.5 billion from the Infrastructure Investment and Jobs Act.

Two additional initiatives target shipping and agricultural emissions. Launched by the U.S. and Norway, the Green Shipping Challenge calls on “governments, ports, maritime carriers, cargo owners, and others to come forward at COP 27 with concrete steps … that will help put the international shipping sector on a credible pathway this decade toward full decarbonization no later than 2050,” the White House said.

Biden’s Global Fertilizer Challenge “aims to raise $100 million by COP 27 to strengthen food security and reduce agricultural emissions by advancing fertilizer efficiency and alternatives,” according to the White House. The goal is to reduce agricultural emissions and food insecurity “by helping countries with high fertilizer usage and loss adopt efficient nutrient management and alternative fertilizers and cropping systems,” the White House said.

Russia leads the world in fertilizer exports.

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MISO, Membership Share Impacts of Great Resignation

INDIANAPOLIS, Ind. — MISO and its membership shared their common experience with the employee churn caused by the COVID-19 pandemic.

The MISO community discussed industry reverberations from The Great Resignation, as the ongoing economic trend is called. It was the subject of the quarterly Hot Topic chat before the Advisory Committee Wednesday during MISO Board Week.  

Todd Hillman 2022-06-16 (RTO Insider LLC) FI.jpgMISO’s Todd Hillman | © RTO Insider LLC

“Many call this a once-in-a-lifetime occurrence,” Todd Hillman, MISO’s senior vice president and chief customer officer, said in opening the discussion. “What we’re seeing is the wave of change is not so much about leaving work but trading up.”

Hillman said the tightening labor market is caused in part by Baby Boomers, especially men, leaving the workforce and fewer young people taking their place. He said that trend is exacerbated in the male-heavy energy industry.

Compensation packages and work flexibility have become increasingly important in holding onto employees, Hillman said.

Clean Grid Alliance’s (CGA) Natalie McIntire said she’s worried about the high number of “important, key” MISO staff members that have recently left.

“We really want to encourage MISO to act assertively to address any internal issues that’s keeping it from retaining employees,” McIntire said. She suggested the grid operator hire outside consultants to review its compensation and company culture.

Hillman said MISO is tapping outside expertise to gauge compensation “given how fast inflation is moving.”

CGA Executive Director Beth Soholt said the RTO’s employees are probably stressed from “stakeholders yelling at them,” daunting study work and pressures to deliver the grid of the future. MISO leadership has repeatedly mentioned the post-pandemic talent shortage as a challenge to completing market initiatives on time.

Cleco Cajun’s Tia Elliott said when jobs were at a premium before the pandemic, employees likely put up with more discontent to hang on to their paychecks.

Staff Turnover’s Budgetary Impacts

The grid operator’s year-to-date budget is becoming a study in how the tight labor market, red-hot inflation and constrained supply chains weigh on bottom lines. MISO’s base expenses are $2.4 million (2.6%) over budget, driven almost exclusively by higher salaries as it tries to retain and attract labor. The RTO’s project investment budget is about $500,000 (4.4%) below budget because of delays, deferrals and cancellations.

The grid operator expects to finish 2022 almost $6 million (2.1%) over its budget. That’s after it reduces some travel and employee training to offset the extra $8 million it must spend on salaries that it didn’t foresee at the beginning of the year.

“This has allowed us to keep our vacancy rate flat,” CEO John Bear said, explaining the extra salary spending before the board’s Audit and Finance Committee June 14. He said MISO began losing employees early during the Great Resignation and noted it’s more expensive to attract a new employee than to keep one.  

CFO Melissa Brown said that because salaries and benefits make up such a large portion of the MISO budget, those overruns are difficult to offset.

Director Barbara Krumsiek said employee attrition is “terribly expensive.” She said with inflation and salaries rising so quickly, you have to react and “have a finer pencil.”

John Orr 2022-06-16 (RTO Insider LLC) FI.jpgConstellation Energy’s John Orr | © RTO Insider LLC

Constellation Energy’s John Orr said he “wholeheartedly disagrees” that employees want good a company culture over strong compensation. He said most importantly, people want to be paid for the value they bring to an organization.

“If you think … pay for performance isn’t the single most motivating factor, you’re seriously misleading yourself,” he said. “People will put up with a lot of BS if they’re being paid well. It happens every day. … Does it sound kind of mean? Yes, but it’s human nature.”

But Krumsiek said she worried that a pay structure that handsomely rewards its most aggressive employees might stifle progress on diversity, equity and inclusion.

“People want to be rewarded for the work they do,” regardless of their backgrounds, Orr said. If managers “have only one type of person working for them, then there’s something wrong.”

McIntire said the environmental sector hasn’t experienced the same degree of turnover that other companies may have. She explained that it’s boom time for renewable energy organizations, and they’re retaining employees and hiring others to keep up with the changing energy landscape.

Soholt also said CGA is “biting the bullet” and hiring more junior staff and taking the time to train them.

“It’s a phenomenon and something we’re going to have to do because there are just not enough people to go around,” she said.

Soholt said her organization is discussing salary adjustments for existing employees. She advised other MISO member companies to publish salary ranges on job postings.

“That saves time for the applicant and the person who is looking to hire,” she said.

ITC Holdings’ Brian Drumm said his company is experiencing higher voluntary departures.

“It’s not really hard to hire a new person, [but] it takes longer, and new people are coming in with more demands,” Drumm said.

Multiple members said job seekers now expect some ability to work from home.

North Dakota Public Service Commissioner Julie Fedorchak said one silver lining is that a dramatic number of exits at the commission have brought in employees with new ideas.

“There’s so much work that needs to be done. It’s very pressing, important work. … People are leaving MISO, and new people are coming in,” director Nancy Lange said.

She said burnout can quickly become an issue with the energy industry’s intense workloads, but MISO is encouraging staff to take vacation time.

Solholt said it’s important for employees to not only take vacation time, but to take uninterrupted time where they aren’t “texting from their children’s events.”

“You really need to have a good time, go to the cabin and disconnect. I want us to go back to that,” she said.