VALLEY FORGE, Pa. — PJM generators urged fellow stakeholders to support a unified opportunity cost calculator capable of wiping out the compliance risks of the dual systems currently offered through the RTO and its Independent Market Monitor.
“PJM wants the status quo with respect to its calculator and the Monitor wants its calculator, and we are still in this situation where market participants can’t get one calculator to eliminate compliance risk,” said Bob O’Connell, director of regulatory affairs and compliance for Panda Power Funds, during a Market Implementation Committee meeting on Wednesday.
Under current procedure, market participants can either use PJM’s calculator in Markets Gateway or the Monitor’s modeling system to build energy cost offers with appropriate adders that help ensure a generator will recoup losses when its resources are scheduled outside of their most economic operating intervals. Some of these opportunity costs arise when regulatory agencies impose environmental run hour restrictions, physical equipment limitations trigger operational restrictions, and force majeure events constrain access to fuel.
“The objective is to make the generator whole,” said Glen Boyle, manager in PJM’s operations analysis and compliance. “Neither PJM nor the IMM will be presenting packages, because we are OK with the status quo.”
Clearly, stakeholders are not.
A New Path
O’Connell presented the MIC with three proposals — drafted in consultation with Dominion Energy — that streamline the calculators to varying degrees.
The first makes small changes that don’t force PJM to rewrite its calculator, O’Connell said. The second revises PJM’s modeling process to mimic the Monitor’s, which many stakeholders prefer for its reliability. The third consolidates the former package into one single calculator, “eliminating all compliance risk,” O’Connell said.
“When you use the Market Monitor’s calculator, the market participant’s only risk is taking the adder the Monitor provides and incorporating into its offer properly,” O’Connell said. “While there is some compliance risk, it’s very limited. As long as you know how to cut and paste, you’re usually in pretty good shape.”
The PJM calculator, however, gives the market seller more control over the modeling process, allowing more room for error and raising compliance risks — the source of O’Connell’s concern when he proposed a task force to revise the calculators in March 2017, he said.
“I’m concerned we won’t be able to get there [one consolidated calculator],” O’Connell said. “We basically decided to offer three packages so we could at least get to something that improves the situation a little more.”
Panda and Dominion will seek endorsement of one of the proposals at the August MIC meeting, O’Connell said.
The packages come five months after O’Connell made a motion at the February Members Committee meeting to table a vote on Operating Agreement language that would force PJM to accept the IMM’s calculator. (See “Calculator Vote Place in a ‘Parking Lot,’” PJM MRC/MC Briefs: Feb.21, 2019.)
At the time, O’Connell said the unusual motion puts the issue in a “procedural parking lot,” giving members flexibility to bring up the issue on short notice in case PJM suddenly decides the Monitor’s calculator is no longer valid.
O’Connell drafted the language after PJM told members last August it would reject the Monitor’s opportunity cost calculator, the culmination of a yearlong dispute over the “increasingly” divergent results produced by the two organizations. (See Stakeholder Proposal Aimed at Ending PJM-IMM Dispute.) The PJM Board of Managers approved Manual 15 revisions in January that governed the use of the IMM calculator as an alternative, effectively reversing the RTO’s earlier decision.
Boyle said Wednesday that PJM must maintain a calculator as mandated by the Tariff and will make clarifying updates to Manual 15 regarding immature units, dual-fuel units and application functionality.
Marybel Batjer, currently the state’s government operations secretary, will soon replace retiring President Michael Picker, Newsom said. He called Batjer “one of the best in the business.”
“She is about reorganization,” Newsom said. “She is about governance.”
Batjer’s official biography says she was appointed by former Gov. Jerry Brown in 2013 to head the Government Operations Agency, a new entity charged with improving efficiency and accountability in state government as part of Brown’s reorganization efforts.
Newsom kept her on in that role and gave her the job of reforming the Department of Motor Vehicles, one of the state’s most inefficient bureaucracies.
Marybel Batjer will be the new CPUC president. | State of California
“She has led forward-looking efforts to revamp the way the state approaches data and technology, modernized the civil service system, and has led the implementation of key initiatives to green state government and promote renewable energy,” Newsom’s office said in a news release.
“Prior to taking office at CPUC, Batjer will complete her work later this month as head of Gov. Newsom’s DMV Strike Team, which has already begun implementation of key changes to transition the California Department of Motor Vehicles into a more customer-friendly and user-centered culture, to better serve Californians,” it said.
She’s expected to take office at the CPUC at the beginning of August.
Previously, Batjer was vice president of public policy and corporate social responsibility for Caesars Entertainment. Her state and federal government experience includes stints as Gov. Arnold Schwarzenegger’s cabinet secretary, special assistant to the secretary of the Navy in the George H.W. Bush administration and a national security advisor in the Reagan administration.
Newsom made the announcement during a press conference and signing ceremony for Assembly Bill 1054, a major new wildfire law that will be implemented in part by the CPUC. (See Calif. Utility Relief Bill Speeds to Governor.)
The CPUC has come under fire in the last year for moving slowly in response to California’s wildfire crisis. There were rumors months ago that Newsom intended to appoint his own CPUC president to replace Picker, a former aide to Gov. Jerry Brown.
Picker said in a recent interview with RTO Insider that Newsom hadn’t asked him to leave, but that he felt it was time to retire. (See Retiring CPUC President Still Has Lots to Say.)
Newsom thanked Picker for his service Friday.
“Michael has brought deep expertise in energy policy and a commitment to advancing the state’s climate goals,” the governor said in a statement. “His knowledge, vision and commitment has been critical as the state examines the role of utilities following recent catastrophic wildfires, and necessary changes in an era of climate change.”
Picker was unavailable Friday, according to an aide. Batjer could not immediately be reached for comment.
SACRAMENTO, Calif. — Gov. Gavin Newsom signed a bill Friday that’s intended to shore up California’s investor-owned utilities against wildfire liability.
Newsom pushed lawmakers to quickly pass Assembly Bill 1054, which they did in less than a week after it was amended to reflect the governor’s wildfire plan. It takes effect immediately as an urgency measure.
“I want to thank the Legislature for taking thoughtful and decisive action to move our state toward a safer, affordable and reliable energy future,” the governor said in a statement after the Assembly gave the bill its final approval Thursday. “The rise in catastrophic wildfires fueled by climate change is a direct threat to Californians.”
The bill does not give utilities the relief from California’s strict liability standard, known as inverse condemnation, that they wanted. But it creates a $21 billion fund to pay for wildfire damages, to be bankrolled equally by ratepayers and the state’s three large investor-owned utilities.
A DC-10 airtanker battles the Woolsey Fire last November. | U.S. Forest Service
Under the measure, the IOUs could opt in and contribute an initial $7.5 billion in aggregate and pay $3 billion more over the next 10 years. Pacific Gas and Electric, Southern California Edison and San Diego Gas & Electric would cover 64.2%, 31.5% and 4.3%, respectively, based in part on the size of the utilities and the miles of power lines that run through high-fire-risk areas.
Ratepayers would fund their $10.5 billion share through charges on electric bills, averaging a few dollars per month.
Elected officials hope the fund will head off further downgrades by credit rating agencies of SCE and SDG&E and alleviate concerns those utilities, like PG&E, could wind up in bankruptcy.
(The bill allows utilities to opt for a $10.5 billion state-backed line of credit in lieu of the wildfire fund. They must choose within 15 days. The general belief is they will opt for the wildfire fund.)
PG&E filed for bankruptcy in January, citing billions of dollars in wildfire liability from November’s Camp Fire, the deadliest in state history with 85 fatalities, and a series of devastating blazes in 2017.
SCE’s equipment is suspected of starting the Woolsey Fire, also in November 2018, which killed three people and destroyed more than 1,600 structures. The utility also faces massive liability for 2017’s Thomas Fire, which it admitted may have been sparked by its equipment. That fire killed two people, while ensuing mudslides caused by rain drenching charred hillsides caused 21 deaths. (See Edison Takes Partial Blame for Wildfire in Earnings Call.)
SCE and SDG&E each had their credit ratings downgraded, although the latter hasn’t had a significant utility-sparked fire in years, since it began a major grid hardening effort that’s often citied as a model.
Stabilizing California
Those who supported the bill said bolstering the utilities against insolvency would allow fire victims to be compensated more quickly and maintain stable rates for customers.
“We’re talking about victims, ratepayers and the industry that keeps the lights on,” said Assemblyman Chris Holden, one of the bill’s three co-authors and chairman of the Assembly Utilities and Energy Committee.
The measure requires PG&E to exit bankruptcy by June 30, 2020, and pony up its share of the initial $7.5 billion before it can recoup costs from the wildfire fund.
It also requires the IOUs to pay a combined $5 billion for fire-safety upgrades without recouping profits from ratepayers through a return on equity.
The Woolsey Fire killed three people in the Malibu area last year. | Department of Defense
Assemblywoman Eloise Reyes said she struggled with the bill but decided to vote “yes” because she felt it would compel PG&E to leave bankruptcy and prioritize safety, while stabilizing electric service and rates in California.
“In the end our job is to stabilize California,” Reyes said.
While speakers on the Assembly floor Thursday generally praised the bill and urged its passage, others remained troubled.
Assemblyman Al Muratsuchi, a Los Angeles-area Democrat, asked “whether we could have done better if we had more than two weeks” to weigh the measure. The bill, in its current form, was first printed two weeks ago and then heavily amended July 5 over the holiday weekend.
Last year, lawmakers hastily passed Senate Bill 901, another major wildfire bill, under pressure from then-Gov. Jerry Brown and legislative leaders. They were told if they didn’t pass the bill, PG&E would go bankrupt, which it did anyway.
“Now we’re being asked to pass this bill, and if we don’t pass it [by July 12] according to the governor … then Edison is going to be downgraded to junk bond status and may face bankruptcy,” Muratsuchi said. He questioned whether the utility would follow the same course as PG&E.
Assemblyman Marc Levine, a Democrat who represents a district north of San Francisco, voted “no” on the measure and said it was not right to offer PG&E assistance when it had yet to upgrade its power lines to prevent fires.
The Caribou-Palermo transmission line that sparked the Camp Fire was 100 years old, and maintenance had been deferred repeatedly, leading to 85 deaths, he said. Other PG&E lines in high-risk areas may be in similar condition, he said.
“It is hard not to see this bill as a reward for monstrous behavior,” Levine told his colleagues. “They have not done the work. They should not be rewarded.”
An analysis by a half-dozen Eastern RTOs and utilities has found no substantial gains from changing how they measure frequency response, according to the standard drafting team considering modifications to BAL-003-1.1 (Project 2017-01).
BAL-003-1.1 (Frequency Response and Frequency Bias Setting) states that a balancing authority typically calculates its frequency response measure (FRM) based on “the change in its net actual interchange (NAI) on its tie lines with its adjacent balancing authorities divided by the change in interconnection frequency.” Some BAs apply corrections to the NAI to account for nonconforming loads.
PJM, MISO, SPP, Ontario IESO, Southern Co. and Duke Energy compared BAL-003 calculations based on NAI with those using net interchange error (NIE) to account for differences between schedules and actual operations.
“The hope was that we would see more of a true frequency response instead of potentially getting an inaccurate response because of different schedule changes,” PJM’s Danielle Croop explained during a drafting team conference call July 11. “Our findings were underwhelming. We did not necessarily see a big difference or a big improvement using the NIE data vs. the NAI. …The initial thought is you’re just shifting the problem and not necessarily fixing the problem.”
Croop said PJM and SPP also looked at their generation data as well as tie line data.
“Unfortunately, we don’t know if that provided good results either, because it’s hard to just measure frequency response over a period of time when you have units doing other things for other reasons like economic dispatch or … regulation. … We haven’t really found anything that we see [as] very promising or improvements from what we have today.”
Tom Pruitt of Duke Energy Carolinas, who said he also looked at generation data, agreed with Croop’s conclusion.
“For the time frame we were looking at, we’ve got a number of other activities occurring that are clouding [the data]. If you’re looking for a simple primary frequency response, it’s going to be difficult to separate that from market activity and other actions that are occurring.”
Drafting team Chairman David Lemmons, of Ethos Energy Group, asked whether the members agreed that measuring load is also not viable.
“Recognize first that the measurement of load for most BAs is actually a calculation of the generation less the ties — it’s a derived value,” responded Pruitt. “It’s not going to be any better than the measurement of ties or interchange error or net generation. If you were capable of measuring individual loads themselves, and get the time synch correct, yeah [you could do it]. But that’s a heck of a lot of work.”
Lemmons said that although the findings were disappointing, they represented progress, nonetheless. “I’m not going to say it’s great news because we’re not seeing a marvelous advancement,” he said. “But it’s at least moving forward with the investigation to determine if there’s something better we could use.”
The team also discussed potential generator requirements in a revised standard.
“Be thinking about what it is you think a generator requirement actually does,” said Lemmons. “Is it a setting just of the governor or is it performance regardless of any other controls in the system? I need to be sure everyone on the team is on the same plane when we post something if we’re going to post it.”
The team will meet in person on July 22-23 at Western Area Power Administration (WAPA) offices in Lakewood, Colo.
PORTLAND, Ore. — Bonneville Power Administration officials on Monday likely dispelled any lingering doubts about their intent to join the Western Energy Imbalance Market (EIM), but it will take some time to address stakeholders’ questions about how the move will affect them.
A proposal attached to that letter detailed the raft of benefits of joining the EIM, including more efficient generation dispatch, as well as improved transmission usage, congestion management and voltage control. BPA also touted the ability to use the EIM as a “non-wires” solution to address congestion and avoid new transmission builds while also helping to identify areas of needed investment.
Some BPA “preference” customers attending the last in a series of “EIM stakeholder” meetings Monday sought to get into the weeds of what EIM membership would mean for them and their workaday relationships with the federal power agency. Those customers represent the Pacific Northwest’s publicly owned utilities, which get first priority for the energy coming off the Columbia River Power System managed by BPA.
Tom Haymaker, manager of energy planning and operations for Clark Public Utilities in Washington, said he’d been “wrestling” with the issue of the “interplay” between the region’s existing hourly bilateral market and the EIM’s intra-hour market — and how BPA would make decisions about offering energy into each after joining the EIM.
“We’re going to be a player in the real-time hourly market, but we won’t be in the intra-hour market,” Haymaker said. “Are we going to be precluded from getting access to certain kinds of power from Bonneville because you’re wanting to put that into the intra-hour, or is there going to be some sort of process where we would have an opportunity to perhaps buy that power ahead of time that you were planning to offer up in the intra-hour?”
Steve Kerns, BPA’s director of grid modernization, offered a roundabout answer. After explaining that the agency already trades in a “very complex set of markets,” he recounted a previous trip to SPP, whose market participants told him that real-time bilateral markets started to “go away” after roll-out of the RTO’s Integrated Marketplace.
“That’s almost the inevitable outcome here … So that means we have to be smarter about how much we want to take to real-time,” Kerns said. “If we think that the [bilateral] market depth in general is going to be less than what it is pre-EIM, we’re going to have to make different decisions about day-ahead marketing than what we did in the past and also consider what we want to roll into the Energy Imbalance Market.”
Kerns said that, like hydro-heavy EIM member Powerex, BPA is not going to stop trading in the bilateral market. “They participate in the EIM, but they still participate in the real-time market as well.”
Haymaker expressed concern that BPA would at times “park” power, reserving it for sale into the EIM rather than making it available to its preference customers.
“We certainly don’t feel we would need to do that in order for the EIM to pencil out,” said Russ Mantifel of BPA’s transmission marketing and sales division. “Joining the EIM does not make future policy decisions about what we’re going to offer up. In order for us to achieve the benefits, I think we don’t have to make the sort of zero-sum decisions that you’re talking about here.”
Haymaker agreed that “the more markets, the better,” an acknowledgment that BPA preference customers pay lower prices for their contracted power when the agency gets higher prices for its surplus sales — which effectively subsidize preference customers.
“I think you’re going to find better pricing in the real-time market after you do this because you’ve got alternatives, so we understand that. But we want access, or the ability to compete with that intra-hour market,” Haymaker said.
“The heart of a lot of this is how do you meet your statutory obligations for both regional preference and preference for the consumer-owned utilities,” said Betsy Bridge, an attorney representing Northwest Irrigation Utilities. “It’s not a question of whether the preference customers get first dibs to that power — so it’s a balancing act. But to reiterate Tom’s point, we have to find a balance there of making sure that preference customers have the first opportunity.”
“And it’s an assumption that we will meet those obligations,” Mantifel said. “We’re confident that joining the market does not create any issues with our ability to do that and that a lot of market changes are going to make that more complicated moving forward — the proliferation of the EIM being one of them.”
Tx Questions
Anna Berg, senior manager of power supply for Snohomish County (Wash.) Public Utility District, wondered how transmission curtailments would affect resources not participating in the EIM.
“What does that look like for the rest of us who are using BPA’s point-to-point transmission or [network transmission]?” Berg asked. “So, if there’s congestion that is occurring between EIM entities, how is that resolved?”
Saying he would be “riffing a little bit” in his response, BPA’s Todd Kochheiser explained that — “where appropriate” — transmission operators would still likely curtail prior to the hour in the face of commercial congestion. But he noted that the EIM also ensures that participating balancing authorities begin the hour with adequate resources by applying a “resource sufficiency test” that also includes a transmission feasibility assessment.
“I could envision as a result of that assessment, we could potentially identify transactions or tags or base schedules that need to be adjusted, either through curtailments or some other mechanism, in order to go into each hour feasible,” Kochheiser said. “To the extent there ends up being congestion within the hour … the market will use available resources that have been bid into the market to try to resolve that congestion. Failing that, I think we would be left with no alternative other than other operational tools such as curtailments, redispatch, etc.”
Mantifel added that, “Even if you’re not participating in the market, the odds of a curtailment ought to be reduced due to the active redispatch of the market, so the market will proactively try to get the flows below whatever physical limits that we’re managing within the market.”
Lauren Tenney, senior policy analyst with the Public Power Council, asked whether BPA expected to see congestion benefits focused primarily in areas where transmission is “donated” to the EIM to facilitate transfers between BAs — known as energy transfer system resources (ETSRs) — or whether there would be enough donated transmission to spread the benefits.
Mantifel said he didn’t think there was a strong correlation between benefits and the number of ETSRs.
“The market’s always working to manage the transmission system better, even if there’s no ETSRs,” he said, adding that it’s not always clear when the EIM is just providing economic benefits rather than relieving a stressed system.
‘Sound Business Decision’
BPA’s resolve to join the EIM became evident during a hair-splitting discussion in which a few stakeholders pressed agency officials on whether the agency had already determined that it would be a “sound business decision” to join the EIM — or if that determination only extended to the signing of the non-binding implementation agreement.
“I think it is a sound business decision,” Mantifel said of joining the EIM. “I mean, this is what we’re establishing. We’ve gone through a pretty arduous process of establishing what we believe to be facts and assumptions and analysis that justify this as a sound business decision … If you think the facts are wrong, if you think they’re insufficient, if you think the analysis is wrong or insufficient in scope or detail, this is your opportunity to disagree with that.”
Stakeholders have until July 22 to submit comments on the plan.
Tenney sought to clarify whether BPA would still in some way revisit the “sound business” issue before issuing its record of decision in two years.
“If nothing changes between now and the final decision, would this issue be something that’s addressed in a final letter to the region?” she asked.
Kerns confirmed that it would, and then attempted to reframe the subject:
“If we do decide to join the Energy Imbalance Market, what strategic value do we get as being a player and helping form the markets? On the other side of the coin, what is the strategic risk to Bonneville of being potentially one of the only balancing authorities on the West Coast not participating in the market? So, I think there’s two ways to look at that.”
The head of a small Iowa solar developer is prepping for a second state supreme court battle over his ability to supply electricity in a state without retail choice — after winning a similar fight in his home state.
Dubuque-based Eagle Point Solar is suing the Wisconsin Public Service Commission and We Energies to compel the utility to connect its planned, third-party rooftop solar projects for the city of Milwaukee (30701). The lawsuit may also clarify rules on what constitutes a public utility in the state.
Barry Shear, Eagle Point Solar | Eagle Point Solar
Eagle Point CEO Barry Shear wants solar developers to be able to own projects that generate electricity for individual customers in a regulated utility’s footprint. The lawsuit cites We Energies’ refusal to honor Eagle Point’s services agreement with Milwaukee to install 1.1 MW worth of solar generation on seven city-owned buildings: three libraries, two public works buildings, a police station and a garage. We Energies refused to connect the solar projects at the distribution level, claiming sole domain over Milwaukee as an electric customer.
“We Energies is saying that a [power purchase agreement] is nothing but selling energy in their service territories. … Their position is it’s an illegal transaction even though there’s no law against it,” Shear said in an interview with RTO Insider.
Eagle Point filed the suit in Dane County Circuit Court in late May after the Wisconsin PSC voted 2-1 against hearing the matter. The commission said the dispute was better left to the state’s legislature because it triggered questions about what defines a utility. Eagle Point filed an unsuccessful appeal with the PSC in spring.
As of July 9, We Energies had not filed its response to the suit.
The agreement would have divided project ownership 80% to Eagle Point and 20% to the city, with the option for the city to purchase the full project over time. Milwaukee has since pared down the solar project to three buildings that it will self-finance, though Eagle Point could still strike a deal on the remaining buildings.
Renewable energy tax credits, like the 30% investment tax credit, are inaccessible to nonprofits and cities such as Milwaukee, which instead rely on third-party providers to attain passed-through savings.
Eagle Point has completed more than 700 solar installations totaling 17 MW. Fighting for access to a regulated utility’s territory isn’t new turf for Shear, who prevailed at the Iowa Supreme Court in a similar 2014 conflict with Alliant Energy.
Wisconsin is one of 15 states that have not clarified whether they allow third-party solar power purchase agreements. | North Carolina Clean Energy Technology Center’s Database of Incentives for Renewables & Efficiency (DSIRE)
While 26 states explicitly allow third-party solar power purchase agreements, Wisconsin is one of 15 states that have not clarified whether they allow such third-party solar arrangements, according to the North Carolina Clean Energy Technology Center.
Utility, Defined?
The case could force that clarification in Wisconsin — and a more strongly defined concept of a “public utility.”
But We Energies spokesperson Brendan Conway said the law is already clear — entities cannot sell electricity to We Energies customers without first registering as a public utility.
“In Eagle Point’s case, because we already provide retail electric service to the city, Wisconsin law prohibits Eagle Point from doing so. Not only is the agreement illegal, it shifts costs to customers who are paying for the infrastructure that provides service when needed and would allow some customers to benefit from our system without paying for a portion of it,” Conway said in an emailed statement to RTO Insider.
“There is no requirement under Wisconsin law that Wisconsin Electric interconnect the facilities owned by a third party who intends to provide electric service to a retail customer already served by Wisconsin Electric,” We Energies argued in the PSC case in December.
The Sierra Club has long encouraged Wisconsin to clear up energy law so that third-party PPAs are explicitly allowed. The move would help expand clean and renewable energy use, the nonprofit claims.
100-Year-plus Case Law
Eagle Point acknowledges that only “public utilities” can sell power to the general public but claims it’s perfectly legal for it to generate for a “restricted class” of customer.
Eagle Point’s Shear is drawing on Wisconsin law and a 1911 case in which a landlord built an exclusive steam plant for tenants’ and neighbors’ use and was not deemed a public utility.
“Offering service `to or for the public’ means generating power `intended for and open to the use of all the members of the public who may require it,” the company said. “The `public’ means the public at large, not a limited subset of the public that stands in a special contractual relationship with the facility owner. By passing statutes that regulate public utilities, the Wisconsin Legislature never intended to regulate sales of electricity that serve a `limited’ or `restricted’ class of customers.”
Shear also cites a 1924 ruling in which a group of neighbors formed a co-op to construct a power line; a 1932 case over a dam Ford Motor Co. built to power an assembly plant; and another landlord case in 1967 — none of which was deemed a public utility.
Eagle Point also points out that no excess electricity would flow back onto the grid, nor would the solar arrays use We Energies’ distribution lines or other equipment to transport power.
Shear said the 1911 case has been upheld many times. “I think we have some pretty strong case law behind us,” Shear said. “The legal work has already essentially been done: If you have a single customer, you’re not a public utility.”
Shear said he considers his Wisconsin suit stronger than his Iowa case because his home state didn’t have any decided cases on what constitutes a public utility.
| Renew Wisconsin
Eagle Point also says its situation “parallels” that of a medical center that the Wisconsin PSC recently ruled could generate its own power through a subsidiary thermal company.
A representative of the Wisconsin PSC has said the agency cannot comment on pending litigation.
Unlike a regulated utility, one solar agreement with the city of Milwaukee won’t make Eagle Point a “natural monopoly,” the lawsuit argues.
Shear is also confident that Milwaukee will be perceived by the courts as a customer, not the public, despite it being a municipality.
“The city of Milwaukee is a single customer. … I’m not selling to the public. There’s a pretty clear distinction there. I’m just making this technology available to everyone in a commercially reasonable way.”
When the deal was scuttled, Shear said he was six months’ deep into engineering work and meetings with the city and We Energies engineers.
“I purchased well over $1 million [of] equipment,” he said. “I had committed my capacity to this. I wasn’t working on other projects.”
In total, Shear estimates he lost about a half-million dollars on the project. He also said Eagle Point missed out on a 2018 grant that would have been awarded had the project been completed by December as originally scheduled.
Shear said he’s fighting We Energies’ position to help cities access increasingly inexpensive renewable energy and meet carbon reduction goals.
“I want to resolve this because this has chilled dozens of municipal solar deals across Wisconsin,” Shear said.
Changing Energy Landscape
Shear says utilities are going to have to accept those in their service territories gaining the ability to generate their own electricity.
“This is a big deal. We Energies has to adapt and grow their business model to expect that their customers are going to be able to produce their own energy. That’s the way it is from here on out,” Shear said.
“They don’t own the sun,” he added after a beat.
Shear expects the battle will eventually reach the Wisconsin Supreme Court.
“My operating presumption is and always has been that it’s going to end up at the state Supreme Court. … While I don’t speak for We Energies, I can’t see them giving up. I’m not giving up either.”
SPP last week reiterated its plans to recover the costs of a NERC penalty for reliability violations by dipping into its employee compensation pool (ER19-97).
In a heavily redacted filing shared with SPP stakeholders at 4:47 p.m. on July 3 — just before the Independence Day holiday — SPP said its board of directors determined the best way to recover the penalty’s costs was to “offset the cost with funds that were approved and allocated to the SPP employee compensation pool,” rather than charging members and market participants.
SPP paid the fine, which NERC approved in the RTO’s role as a registered entity (RE), last year out of a 2017 surplus “that was sufficient to pay the full amount of the monetary penalty.”
The RTO said recovering the penalty cost from authorized employee compensation funds “essentially holds members, market participants, and customers harmless from the cost of the reliability penalty.”
SPP’s headquarters in Little Rock, Ark. | ACE Glass
The amount of the fine and the reason for the penalty have not been disclosed. SPP requested confidential treatment for the filing as privileged material and/or critical electric/energy infrastructure information “in order to mitigate potential risks to the reliability of the bulk-power system under SPP’s control.” Seven of the 29 pages in SPP’s filing were fully redacted and two pages were partially redacted.
SPP told RTO Insider that company policy keeps it from commenting on “such matters.”
“Anything we could say publicly is already stated in the filing,” spokesman Derek Wingfield said.
In FERCOrder 672, the commission said that NERC violations “generally will be made public after the matter is filed … as a notice of penalty or resolved by an admission that the user, owner, or operator of the bulk-power system violated a reliability standard or a settlement or other negotiated disposition.”
But SPP noted the order also allows a filer, if it believes information on the violation “could jeopardize the security of the bulk-power system if publicly disclosed,” to “fully support” its confidentiality claim in the non-public version of its proposal to recover penalty costs.
SPP added the language in its filing after FERC last year denied its request for waivers from regulations guiding the confidential treatment. The commission said SPP must allow intervenors to sign nondisclosure agreements to access information that the RTO believes should be withheld from the general public. FERC said its CEII regulations “recognize that intervenors in a commission proceeding … may need access to information that the applicant believes should be withheld from disclosure to the general public in order to participate effectively in the proceeding.” (See FERC Rejects SPP Confidentiality over NERC Fine.)
SPP is a NERC RE in the Midwest Reliability Organization and Western Electricity Coordinating Council. It is required to compliance with NERC reliability standards for its roles as a balancing authority, planning authority/planning coordinator, reliability coordinator, reserve sharing group, and transmission service provider.
Under Attachment AP of SPP’s Tariff, the RTO may seek recovery of reliability penalty costs by either directly assigning them to the responsible members or market participants or by allocating the costs to all members or market participants.
As justification for its decision to pay the penalty from its employee compensation fund, SPP cited FERC’s 2008 “Guidance Order,” in which the commission said RTOs could tie employee compensation to compliance with reliability standards as one possible way of “prevent[ing] the incurrence of penalties.”
SPP cited the order’s statement that “Bonuses and other incentives received by senior management could also be made contingent on penalty-free operations” and that in reviewing RTO filings, FERC will consider whether the RTO has implemented “personnel policies that place incentives on employees and management to comply with the rules or risk adverse actions.”
SPP said using the existing surplus to pay the reliability penalty “promptly” was an appropriate and reasonable action. The RTO said, “Doing so enabled SPP to pay the penalty in a timely manner as required without having to expend additional time, effort, and resources to file for commission authorization to allocate the costs … prior to paying the penalty, and then invoicing and collecting the funds from the same entities who contributed to the 2017 surplus” through their payment of SPP’s administrative charges.
PJM staff called June an uneventful month for grid operations, despite 23 emergency procedures — including 21 post-contingency local load relief warnings (PCLLRWs) and three hot weather alerts.
PCLLRWs are utilized in the coordination of post-contingency load shed plans between PJM and transmission owners. June’s events occurred in the RTO’s western transmission zones, including Commonwealth Edison, Eastern Kentucky Power Cooperative, American Electric Power, American Transmission Systems Inc., Pennsylvania Electric, and Duke Energy Ohio and Kentucky. There was one PCLLWR on June 25 in the Atlantic City Electric transmission zone for the Chestnae-Moss Mills line.
The hot weather alerts occurred June 27-29 RTO-wide.
PCLLRW count versus peak load over the last three months | PJM
Black Start Packages Coming Together
PJM’s Janell Fabiano told the Operating Committee on Tuesday that stakeholders will soon present new rules for black start resource fuel requirements.
Stakeholders began meeting in July 2018 to reconsider whether the existing fuel requirement of 16 hours proved sufficient given PJM’s focus on resilience in recent years. The group is also considering ways to mitigate high-impact, low-frequency events across all black start resources and fuel types.
Calpine, PJM and Monitoring Analytics continue to work on three similar plans to define fuel assurance and tweak the hourly reserve requirement. Fabiano said stakeholders will bring the three finalized packages to both the OC and the Market Implementation Committee for votes in the fall. Changes will not move forward without support from both committees, she said.
Non-retail BTM Generation Business Rules
Stakeholders delayed voting on changes to Manuals 13 and 14D that refine responsibilities, processes and procedures related to how PJM manages non-retail behind-the-meter generation (NRBTMG). (See “BTM Generation Rules Preview,” PJM OC Briefs: June 11, 2019.)
The revisions to Manual 13 expand upon what events trigger the use of NRBTMG to include “maximum generation emergency” and “deploy all resources” actions, which address capacity shortages or transmission security emergencies.
In Manual 14D, staff updated Appendix A to clarify generator operational requirements for the reporting, netting and operational requirements of NRBTMG.
The delay allows some stakeholders more time to review the revisions. PJM will seek endorsement at the August OC.
Generation Outages
PJM advanced changes to Manual 10: Prescheduling Operations absent the stability-related modifications called into question at the May 14 OC meeting. (See “Generation Outage Revisions Delayed,” PJM OC Briefs: May 14, 2019.)
Stakeholders instead endorsed the remainder of the changes developed out of the periodic cover-to-cover review of the manual that clarifies outage ticket rules for deactivation and black start resources.
Manual Changes Endorsed
Stakeholders unanimously endorsed changes to the following manuals:
Manual 39: Nuclear Plant Interface Coordination (See “Nuclear Plant Interface Coordination Updates,” PJM OC Briefs: June 11, 2019.)
WASHINGTON — Tom Hassenboehler used to work for Sen. James Inhofe, the Oklahoma Republican who famously brought a snowball to the floor of the Senate in 2015 to make the case that the Earth couldn’t be warming.
Has the level of debate improved since then?
Yes, said Hassenboehler, former chief counsel for energy and environment at the House Energy and Commerce Committee, noting his last bosses in Congress were Reps. Greg Walden (R-Ore.) and Fred Upton (R-Mich.).
“They started off [2019] in hearings with the Democrats … acknowledging climate [change] is real and not wanting to have a science debate anymore and … focusing on what is the solution now,” said Hassenboehler, now with The Coefficient Group. “While it may seem small to some folks, I think it is a big step. … Republicans have to be on the same side — of figuring out what their solution is.”
Republican Colin Hayes, former staff director at the Senate Energy and Natural Resources Committee, also sees a change. “The shift in rhetoric is usually a leading indicator of policy change,” said Hayes, co-founder of lobbying firm Lot Sixteen. “And then it’s a conversation about the policy prescription and what it takes to get the requisite number of ‘yes’ votes to make an actual change. That conversation is underway now in a more energized away than it has been.”
Hassenboehler and Hayes spoke Tuesday on an energy policy panel moderated by former Montana regulator Travis Kavulla, now director of energy policy for the R Street Institute, a “free market” think tank, at the Capitol Visitor Center.
Although the two former GOP congressional aides agreed their party is beginning to shed its climate denial, neither predicted major legislation to address the issue anytime soon.
To pass major legislation, “you need a catalyst that often times comes in the form of a crisis,” said Hayes. “Constituents are just ticked off … and so they pick up their phone and call their congressman. I’ve never seen anything get done on the Hill, at least in the energy space, because it was a means to recognize some aspirational, more wonderful world than the one we have. It is almost always a response to people being ticked off.”
Hassenboehler said Congress is responding not only to their constituents but also to Fortune 500 companies that have begun assessing their climate risks in public disclosures. “And that goes for not just tech companies, but to oil and gas and fossil companies as well.”
Lessons from the Failure of Cap and Trade
What does a solution look like?
The failure of the Waxman-Markey proposal — which cleared the House in 2009 but never received a vote in the Senate — means cap and trade is unlikely to be the centerpiece of any future legislation, Hassenboehler said.
Waxman-Markey may have failed in part because President Barack Obama decided on health care as his top legislative goal, Hassenboehler said. “But … it had more to do with the lack of compromise on the proponents’ side … and their kind of one-size-fits-all solution. They didn’t want to see the Senate … shape that bill in a way that was different from the Waxman-Markey proposal. … If the other side had compromised a little more, they would have gotten it done.
“It did lasting damage, frankly, to the brand of cap and trade, which is an efficient way of managing carbon pollution potentially,” Hassenboehler continued. “You’ve got examples all across the states and in other parts of the world that have cap-and-trade programs. We don’t talk about that barely at all anymore. Could that be a potential piece of the pie in the future? Sure, I still think it could come back, but it’s never going to be the lead in a climate bill again in my view.”
Hayes said a “forgotten” lesson of the episode was “it wasn’t Republicans who killed it.”
“It passed the House; it came over to the Senate, then controlled by [Democrats]. … That gave them the votes they needed on health care. That didn’t give them the votes they needed on cap and trade because of the regional nature of these issues,” with opposition from rural lawmakers concerned about the plan’s cost.
FERC Filling the Gaps
Tuesday’s discussion also touched on FERC’s interpretation of the Federal Power Act’s directive to ensure just and reasonable rates.
“Even though the law talks about rates and charges, FERC has looked at this language over time and said, ‘You know what: If utilities aren’t planning their transmission grid in the right way, if they’re not cooperating regionally to plan the transmission grid, that might lead to rates that are unjust or unreasonable,’” Kavulla said. “‘And therefore, we’re asserting jurisdiction over the way the grid is planned for, paid for and built.’”
Hassenboehler said Congress should be “more assertive” in giving FERC direction, through letters and oversight hearings, such as that held by the Senate Energy and Commerce Committee in June. (See FERC Probed on RTO Governance, Market Issues.)
“The way things are rapidly innovating in the electric space, there’s a lot of tough questions out there that FERC is struggling with … and it really all comes down to the power of states versus the feds. … And there’s been no consensus or leadership on that issue in a while. … I think legislation is building over the next several years for that.”
Hayes said FERC’s interpretation of the FPA is a recognition of the limits of legislation on complex issues. “Congress can oftentimes get itself 80, 90, 95% of the way through to the answer on a policy question or problem and secure the votes that are required to make some associated change. But that last 5% can be the technically challenging, politically challenging [issues]. You may just run out of time to answer the question” in a two-year congressional term.
Hayes said he’d like to see the federal government assert jurisdiction over the environmental performance of electric generation.
“Some folks, states’ rights advocates … don’t want them to have that because they are fine with the [state-by-state] patchwork” of environmental policies.
“But I think that those environmental issues are decidedly global in nature. At a minimum … they are national in nature as policy questions. They’re not confined to a single state. You’ve got to get to all 50 [states], or you haven’t really addressed the issue.”
Hassenboehler agreed there are some issues on which the federal government should assert jurisdiction, noting, “We don’t have 50 different labels for food [ingredients].”
He said Congress should tackle the issue of “how data is utilized in the [energy] system: who gets to collect it; who gets to own it.”
“This is energy data, emissions data, things that are being collected across the energy supply chain,” Hassenboehler said. “There’s a lot of need for some systematic consistency.”
It’s said the Supreme Court won’t grant review to reverse a lower court decision that is “merely wrong.” Don’t waste the court’s resources on error of little consequence.
The opposite of that we might call “scary wrong”: something profoundly wrong and with significant potential consequence.
Such is the case with the Natural Resources Defense Council’s new attack on PJM,1 accusing it of suppressing renewable resources relative to other RTOs, wasting billions of consumer dollars in the process and contending, in effect, that a cheap and reliable zero-carbon future could be ours if entities like PJM would just mend their evil ways.
NRDC is wrong in virtually every claim. And it’s scary because policy based on NRDC’s profound errors would be profoundly misguided. We can’t afford to make a bunch of mistakes in dealing with climate change.
The gravamen of NRDC’s attack on PJM is data it compiled showing that the RTO has added more natural gas (“polluting”) resources than renewable resources since 2012. Per NRDC, other RTOs have done the reverse, adding more renewable resources than natural gas resources. NRDC points to RTOs like SPP and ERCOT as good guys.
The worst error in NRDC’s attack is its complete disregard of the relative renewable resources in PJM versus SPP and ERCOT.3
Does this make a difference? Yes, bigly.
National Renewable Energy Laboratory and Energy Information Administration data confirm what is common knowledge in our industry that RTOs like SPP and ERCOT have vastly greater wind and solar potential resources. Of note, higher percentages of its wind and solar potential resources have been added in PJM than in either SPP or ERCOT. In other words, given the renewable cards it was dealt, PJM (or more accurately the PJM region) is doing a better job.
To show this, we’ll use NREL data by state on the “technical potential” of renewable resources, which reflects among other things environmental and land-use constraints. (This is important because a wind project isn’t going to be built in Philadelphia.) Let’s start with wind (because existing wind gigawatts are several times larger than existing solar gigawatts in the U.S. overall, and many times larger in the states comprising PJM, SPP and ERCOT)
SPP has 26 times as much wind potential as PJM, while ERCOT has nine times as much. | National Renewable Energy Laboratory
NREL data show that PJM has around 165 GW of potential onshore wind capacity, in contrast to SPP’s 4,235 GW and ERCOT’s 1,426 GW.4 This means SPP has 26 times more potential wind than PJM; ERCOT has nine times more potential wind than PJM.
How much wind has been added so far in these RTOs? PJM has 9,428 MW of installed wind capacity,5 SPP has 20,610 MW,6 and ERCOT has 22,051 MW.7
So which RTO has made the most of its potential wind resources? PJM has installed 5.7% of its potential, SPP has installed 0.5% of its potential, and ERCOT has installed 1.5%.8
Thus, given the wind resource cards it was dealt, PJM has done much better than SPP or ERCOT.
How about solar?
The NREL data show that PJM has 7,611 GW of potential utility-scale solar capacity, in contrast to SPP’s 31,543 GW and ERCOT’s 15,308 GW.9 This means SPP has four times more potential solar than PJM; ERCOT has two times more potential solar than PJM.
SPP has four times the potential solar resources of PJM; ERCOT has twice as much. | National Renewable Energy Laboratory
How much solar has been added so far in these RTOs? PJM has 1,800 MW of installed solar capacity, SPP has 180 MW, and ERCOT has 1,858 MW.10
So which RTO has made the most of its potential solar resources? PJM has installed 0.02% of its potential, SPP has installed 0.0006% of its potential, and ERCOT has installed 0.01%.
As with wind resources, given the solar resource cards it was dealt, PJM has done much better than SPP or ERCOT.
Thus the reality: PJM has outperformed its RTO brethren in adding renewable resources given the cards it was dealt.
Stayin’ Alive?
Following on its unsound narrative that PJM has done poorly in adding renewable resources, NRDC looks for a culprit. And it finds one in PJM’s capacity market, which it says is “a tool for uneconomic fossil fuel power plants to get paid enough to stay alive.”
This is absurd. Since the start of PJM’s capacity market, an enormous 25,857 MW of coal generation in PJM has retired, which is more than one-third of all coal generation retirements in the entire U.S. of 70,522 MW over the same period.11
If PJM’s capacity market is a tool to keep uneconomic coal plants alive, then it is failing miserably.
NRDC also fails to explain why (per its data) ISO-NE and NYISO have added more renewable than gas megawatts when both of those RTOs have a capacity market. How can this be, given NRDC’s capacity market thesis?
The reality is that new natural gas and renewables in PJM (and elsewhere) are forcing uneconomic coal plants to retire, causing a significant reduction in carbon emissions per megawatt-hour in the RTO.12
This is what needs to continue.
And Those Extra Billions Paid by Consumers?
NRDC claims that PJM has acquired more resources in its auctions than its “target reserve,” and the “extra totals up to billions of dollars more on customer bills.”
This claim reflects a profound misunderstanding of PJM’s capacity market. When the PJM annual auction “clears” (commits to purchase) resources above its target reserve, the clearing price for all capacity resources goes down. This greatly reduces the total cost of capacity that consumers pay.
In the last auction, for example, if resources had offered prices such that the cleared resources were equal to the target reserve, consumers would have paid $18.7 billion for capacity.13 Instead, because resources offered more attractive prices, more resources cleared but at a much lower price, resulting in consumers paying $8.4 billion for capacity — roughly $10 billion less.14
NRDC has it exactly backward.
Annual Capacity Construct
NRDC says PJM has a year-round capacity requirement that hurts renewable resources for no reason. This is an amalgamation of three errors.
First, PJM in fact permits renewable resources to participate in the capacity market notwithstanding their obvious inability to be dispatchable year-round (or at all).15 NRDC ignores this.
Second, PJM in fact permits seasonal resources to match up to simulate an annual resource.16 NRDC ignores this.
Third, PJM basing the capacity construct on summer peak demand does not mean that PJM overbuys capacity for winter and other periods when peak demand is less. Resources need to be acquired for the overall peak, which happens to occur in the summer. Seasonal capacity variations have been considered and rejected for more than 10 years, with a PJM discussion here.17
If the annual capacity market was reconstructed into seasonal markets, then potentially lower prices in non-summer periods would have to be covered by higher summer prices in order to ensure resource adequacy.
There is no such thing as a free lunch.
Biting the Feeding Hand
It is ironic that NRDC targets PJM’s capacity market. The capacity market has been a bulwark against bailout claims for dirty and uneconomic power plants by enabling a transition to cleaner natural gas and clean renewable generation, while assuring resource adequacy years into the future.
Fantasy and Reality
NRDC is promoting a narrative that a cheap and reliable zero-carbon future is easily ours. This narrative requires bad guys like PJM who must be obstructing an easy path forward.
Reality is different. PJM hasn’t obstructed renewable resources and, in fact, is outperforming its RTO brethren given the renewable cards the region was dealt. PJM’s capacity market (like other RTO capacity markets) doesn’t save uneconomic coal plants, doesn’t impose excessive costs on consumers, doesn’t suppress renewable resources and is a bulwark against bailout claims for uneconomic coal units that should retire.
Dealing with climate change will not be cheap or easy.18 We should get real instead of looking for fall guys.
3- NRDC mentions resource potential as one of many factors in resource development, but then proceeds to ignore it (and all other factors) in blaming PJM’s capacity market, as discussed later.
4- The NREL data are on Table 6 of its report “U.S. Renewable Energy Technical Potentials: A GIS-Based Analysis,” available here, https://www.nrel.gov/docs/fy12osti/51946.pdf. For states partially within an RTO, I pro-rated the potential resource by the land-area portion of the state within the RTO.
8- The math is dividing the installed wind capacity for each RTO by the potential wind capacity for that RTO.
9- Same NREL study, using Table 3 for “Rural Utility-Scale Photovoltaics by State.” As with wind, for states partially within an RTO, I pro-rated the potential resource by the land-area portion of the state within the RTO.
10- Same RTO sources as for installed wind capacity.
15- Per PJM report on the auction: “1,416.7 MW of wind resources cleared the 2021/2022 BRA as compared to 887.7 MW of wind resources that cleared the 2020/2021 BRA. … The nameplate capability of wind resources that cleared in the 2021/2022 BRA as annual CP capacity and/or winter seasonal CP capacity is approximately 8,126 MW, which is 1,407 MW greater than the 6,719 MW of wind energy nameplate capability that cleared in last year’s auction. 569.9 MW of solar resources cleared the 2021/2022 BRA as compared to 125.3 MW of solar resources that cleared the 2020/2021 BRA. … The nameplate capability of solar resources that cleared in the 2021/2022 BRA as annual CP capacity and/or summer seasonal CP capacity is approximately 1,641 MW, which is 964 MW greater than the 677 MW of solar energy nameplate capability that cleared in last year’s auction.” https://pjm.com/-/media/markets-ops/rpm/rpm-auction-info/2021-2022/2021-2022-base-residual-auction-report.ashx?la=en.
16- Per PJM report on the auction: “715.5 MW of seasonal capacity resources cleared in an aggregated manner to form a year-round commitment. This is an increase of 317.5 MW over the 398 MW of seasonal capacity resources that cleared in an aggregated manner in the 2020/2021 BRA.” Same source as preceding footnote.
