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.
Shell Energy wants a seat at the GreenHat Energy settlement table, saying it is “uniquely situated” in the proceeding and could bear a disproportionate financial burden based on its outcome.
In its request for rehearing filed Friday, Shell argued FERC erred when it dismissed more than a score of late-filed motions from intervenors seeking to participate in the unwinding of GreenHat’s financial transmission rights portfolio. The company was declared in default in June 2018 after it failed to make good on its mounting losses.
“Departing from longstanding FERC policy against settlements that may have an impact on others not present during the negotiations, the commission has initiated a course of action that will allow a handful of parties to decide” the best way to liquidate GreenHat’s portfolio, Shell said (ER18-2068). PJM has said having to liquidate the portfolio under existing rules could cost members $430 million or more.
On June 5, the commission gave RTO members 90 days to settle disputes about how to move forward before kicking off a paper hearing on PJM’s request to clarify FERC’s ruling rejecting the waiver. (See FERC: PJM Settle Disputes Before GreenHat Hearing.)
GreenHat’s significant growth in exposure and MTA loss. | PJM
On Monday, Chief Administrative Law Judge Carmen A. Cintron canceled a settlement conference scheduled for Wednesday “to allow more time to prepare for future conferences.” Cintron said the cancellation would not affect a conference set for July 26.
Shell was among more than 20 petitioners that filed after the comment period for PJM’s waiver passed. FERC rejected the late filings, saying none demonstrated “requisite good cause for late intervention.”
But Shell says a PJM Tariff provision caused its tardiness, a circumstance that it says none of the other petitioners face.
“Shell Energy entered into three bilateral transactions involving transfers of a portion of GreenHat’s now defaulted FTR portfolio to Shell Energy and back to GreenHat,” the company wrote. “As a result, PJM informed Shell Energy that it would seek guarantee and indemnification from Shell Energy for the portion of GreenHat’s FTR portfolio that was so transferred. Liquidation of GreenHat’s FTR portfolio could substantially affect the amount sought by PJM under the guarantee and indemnification claim.” (See Shell Energy Seeks to Avoid Liability in GreenHat Trades.)
Shell says PJM didn’t tell the company it would be subject to this clause until after the comment period passed and that no other party participating in the settlement discussions could “adequately represent its interests.”
“Because any settlement to resolve issues related to the massive GreenHat default will necessarily impact all PJM members subject to default allocation assessment (and, in turn, ratepayers), excluding Shell Energy and others from settlement negotiations among only a few parties is unlikely to result in a settlement that is in the public interest,” the company said.
Shell further argued that its participation would not “unfairly prejudice or burden” the allowed parties, none of whom opposed its intervention.
“As Shell Energy originally explained, it is not presenting new evidence or law, nor altering any previously established procedural schedule,” the company wrote. “Shell Energy accepts the record as it stands.”
SACRAMENTO, Calif. — The wildfire package that Gov. Gavin Newsom asked lawmakers to push through in a week cleared two key committees Monday and sailed through the State Senate, 31-7, in an extraordinarily accelerated process.
Some lawmakers complained they hadn’t had time to read the voluminous bill, which was printed late Friday (AB 1054). Newsom has urged them to pass it by July 12, when the legislature adjourns for its summer recess.
The goal of such haste is to signal to credit rating agencies that the state is prepared to prop up its investor-owned utilities in the face of billions of dollars in wildfire liability. The bill includes a multibillion-dollar wildfire recovery fund that would be financed by the IOUs and a surcharge on customers’ bills. Ratepayers and utilities would each pay $10.5 billion.
Gov. Gavin Newsom wants lawmakers to pass his wildfire package by the end of this week. | Cal OES
Assemblyman Christopher Holden, a co-author of the bill and chairman of the Assembly Utilities and Energy Committee, told his Senate counterparts Monday that the measure would help “keep the lights on in order to protect customers.”
“Stable utilities are the backbone of our economy and the necessary background of our daily lives,” Holden said while presenting the bill to the Senate Energy, Utilities and Communications Committee, which passed the bill 9-2. The Senate Appropriations Committee approved it shortly afterward.
Lawmakers are under pressure to help the utilities while avoiding political blowback from any measure that could be labeled a bailout. Voter anger remains high with Pacific Gas and Electric, which has been blamed for starting massive, deadly fires in 2015, 2017 and 2018, including November’s Camp Fire, the deadliest in state history. The state’s largest utility and its parent company, PG&E Corp., filed for bankruptcy in January.
PG&E’s stock price plummeted along with its credit rating, which S&P Global Ratings now lists as “D,” its lowest mark. The price has recovered from its low point of about $6/share in January, closing at $21.73 on Monday.
Stock prices for PG&E and Southern California Edison have dropped amid uncertainly over fire liability and utilities financial stability. | Google
Southern California Edison also has been blamed for deadly fires, such as the Thomas Fire in December 2017 and the Woolsey Fire in November 2018. The Woolsey Fire and ensuing mudflows killed nearly two dozen people.
S&P rates SCE and Sempra Energy, the parent company of San Diego Gas & Electric, as BBB, an investment grade, despite concerns about the IOUs’ long-term stability. But ratings agencies have said they may downgrade the ratings if the state fails to act. Their stock prices have been less volatile than PG&E’s.
AB 1054 includes provisions intended to increase the accountability of utilities for safety. To draw from the recovery fund, the IOUs would have to link executive compensation to safety performance. The California Public Utilities Commission would have to certify a utility had acted reasonably before it could recover wildfire costs.
Testimony and comments at Monday’s hearing were largely positive, even from staunch critics of the IOUs.
Up from the Ashes, a wildfire victims’ group, said it supported the bill because it could compensate victims more quickly. And The Utility Reform Network (TURN) backed the bill, with reservations, because it requires the utilities to contribute billions of dollars to the recovery fund.
Those who opposed it included some fire victims and Sen. Scott Weiner, a San Francisco Democrat, who took issue with a provision that could make it more difficult for utilities to sell assets. San Francisco is considering a bid to purchase PG&E’s equipment and establish a municipal utility.
The legislation goes next to the State Assembly for a concurrence vote as early as Thursday. Because it is an urgency measure that would take effect immediately upon being enacted, it requires a two-thirds supermajority vote by both houses to get to Newsom’s desk.
FERC has accepted SPP’s proposal to refine its generator interconnection procedures by instituting a three-stage study process (ER19-1579).
The RTO’s Tariff revisions adopt a three-phase process of thermal and voltage analysis, stability analysis, and facilities study. They also change the eligibility for refunds of financial security.
The commission rejected concerns from Enel Green Power and EDF Renewables that SPP did not have the staff and resources to accomplish all the revisions’ components.
“We are not persuaded to substitute our judgment for SPP’s in determining the level of staff and resources that SPP needs to implement its proposal,” the commission wrote in the June 28 order. It pointed out that the reforms might reduce redundancies and result in the “more efficient use of administrative time” that could be devoted to the new study process.
The changes include the elimination of the feasibility and preliminary queues, changes to the amount and timing of security deposits, publishing study models earlier in the process, and allowing penalty-free withdrawals when costs increase above certain thresholds. They became effective July 1.
The Tariff revisions were approved by SPP stakeholders in January following several years of development. The RTO filed its request in April. (See “Stakeholders Approve Streamlined Generator Interconnection Process,” SPP Markets & Operations Policy Committee Briefs: Jan. 15, 2019.)
3-Stage SPP Generator Interconnection Study Process | SPP
In its filing, SPP said it had more than 440 interconnection or modification requests, totaling 81 GW of new generation capacity, in its interconnection study queue.
Enel and EDF argued it was unjust and unreasonable to “subject interconnection customers to higher and potentially nonrefundable financial security and a longer queue process” if SPP was unable to efficiently handle the process studies.
FERC disagreed, saying SPP’s proposal to separate the security deposit into three payments, which are due before each of the three phases and become “further at-risk as the interconnection customer progresses through the queue … should help dissuade more speculative projects from entering later study phases, which should decrease the number of late-stage, disruptive withdrawals.”
The commission also found the security deposit’s financial outlays were not “excessive.”
“Under SPP’s design, the total financial security an interconnection customer will pay is roughly 20% of its estimated network upgrade cost responsibility, which is the total payment required for SPP’s existing initial payment,” FERC said.
