NERC opened a final ballot Wednesday on a proposal requiring entities that fail to meet performance requirements for “supplemental” geomagnetic disturbances (GMD) to develop corrective action plans (CAP) to minimize their vulnerability.
Voting will be open until 8 p.m. E.T. Nov. 22 on reliability standard TPL-007-4 (Transmission System Planned Performance for Geomagnetic Disturbance Events), which was prompted by FERC Order 851. In addition to requiring CAPs, FERC ordered NERC to authorize extensions of CAP deadlines on a case-by-case basis. (See Revised NERC GMD Standard Approved.)
GMDs, which occur when charged particles ejected from the sun cause changes in Earth’s magnetic fields, can cause voltage instability or collapse, damaging electrical equipment.
NERC’s original GMD standard required applicable entities to assess the vulnerability of their transmission systems to a “benchmark” GMD event, defined as a one-in-100-year event that would cause an 8-V/km “reference peak geoelectric field amplitude” at 60 degrees north geomagnetic latitude using Quebec’s ground conductivity. The standard applies to planning coordinators, transmission planners, transmission owners and generation owners connected at 200 kV or higher.
“Supplemental” GMD events refer to localized “spikes” of intense and damaging magnetic fields that can be created during an event that appears less severe based on spatially averaged measurements over a large area.
The standard opened for comment is virtually identical to the draft that received a 71% affirmative vote, clearing the 67% threshold, in a 45-day ballot period that closed Sept. 9. Organizations that voted in that round will see their votes carried over to the final ballot unless they choose otherwise.
The only change since the initial ballot is language specifying the “Compliance Enforcement Authority” (CEA) — NERC or the regional entity in the U.S. and any entity designated by Canadian officials — will handle requests for extensions. The original version said extensions would be subject to the “ERO.”
TPL-007-4 was created by an 11-member standard drafting team with input from industry and compliance leadership from each regional entity.
Deadlines
The standard requires completion of a CAP within a year after completion of a supplemental GMD vulnerability assessment that concludes the entity does not meet performance requirements. It lists as potential corrective measures the installation, modification or removal of transmission or generation facilities; operating procedures, protection systems or remedial action schemes and demand-side management. Hardware mitigation must be completed within four years after completion of the CAP, with non-hardware measures due within two years.
Under NERC’s CAP Extension Request Review Process, extension requests must be submitted no later than 60 days before the completion date specified in the CAP. The CEA is to convey its decision within 45 days after that.
Extensions will be granted only when implementation has been prevented for reasons outside the control of the responsible entity, such as delays resulting from permitting, equipment lead times or stakeholder processes required by tariff.
“If it was due to a lapse of planning properly or missing a date inadvertently, that’s not beyond the control of the responsible entity,” Steven Noess, NERC director of regulatory programs, said during a webinar Tuesday. “But there might be delays that are [due to] permitting, regulatory processes … [changes in] tariffs or lead times … specific equipment, right of way questions, things of that nature, [and we] certainly want to make it easy for folks to identify them.”
Flexibility Assured
In addition to clarifying the extension process, the standard drafting team also attempted to address industry questions about the level of rigidity in the Implementation Guidance for TPL-007-4 regarding specific mitigation measures. Several of the commenters on the first ballot asked for reassurance the revisions would permit utilities the flexibility to devise their own strategies.
PJM’s Emanuel Bernabeu, who chaired the standard drafting team, emphasized the recommendations in the implementation guidelines are for guidance only. While the team wanted to provide an example of a workable solution, any measure that achieves the goal and is in line with the current scientific understanding may be approved.
“Substantively [it] is the same information we had before, [but] we’ve tried to clarify the language so it’s absolutely clear that this is only [one] acceptable approach, and there are actually other approaches [to] the supplemental events that would be valued,” said Bernabeu.
The NERC Board of Trustees is expected to approve the standard in February 2020.
WASHINGTON — The limits of grid exercises and simulation tools and the need to prepare for a successful cyberattack were recurrent themes at the National Academies’ Committee on the Future of Electric Power in the U.S. daylong conference on computing, communications and cyber resilience.
Observations from the Nov. 1 conference — which featured officials from FERC, NERC, the Department of Homeland Security and Department of Energy — will be in a report by the committee to Congress and DOE, scheduled for release in Fall 2020.
The project was ordered by Congress as part of the 2018 DOE appropriations bill. It directed the National Academies of Science, Engineering, and Medicine to appoint an ad hoc committee of experts to “conduct an evaluation of the expected medium- and long-term evolution of the grid [with a] focus on developments that include the emergence of new technologies, planning and operating techniques, grid architecture, and business models.”
Committee Chair Granger Morgan, professor of engineering at Carnegie Mellon University, asked panelists what recommendations they would like to see in the upcoming report.
“If no one else is jumping on the grenade, I will,” said Scott Aaronson, executive director of security and business continuity for the Edison Electric Institute. “I will continue to beat the drum of resilience.”
Aaronson, part of a panel on moving from a culture of compliance to one of security, decried what he called the “Whack-a-Mole” approach to grid threats, saying the industry should set a goal of “consequence management” that takes advantage of the grid’s inherent redundancy and resilience. Whether it’s “EMP or GMD or cyber or physical or storms or zombies, there’s always going to be a new threat,” he said.
He cited the 2013 sniper attack on Pacific Gas & Electric’s Metcalf substation, in which 17 transformers were damaged at a cost of $15 million. “You know what was cool about that? The lights didn’t blink in San Francisco or Silicon Valley. Why? Because of redundancy.”
“NAS could provide some leadership about how we engineer — on top of this extraordinary machine — more resilient capabilities,” Aaronson said.
Morgan noted the Academies did a report on the resilience of the transmission and distribution system in 2017. What’s new to say? he asked.
Joe McClelland, director of FERC’s Office of Energy Infrastructure Security, suggested the academies could “narrow the focus” to identify what capabilities are required to ensure the continuity of mission critical functions.
“Is it skeletal service, to say, large urban areas? Is it off-site power to a nuclear power plant? There are not very many facilities, but what is the model for a sustainable power source for these facilities — self-sufficient and sustainable — that could dissuade a potential attack by a sophisticated adversary?”
Sobering Reading
McClelland gave his panelists a homework assignment: the February 2017 report of the Defense Science Board Task Force on Cyber Deterrence.
The report concluded Russia and China “have a significant and growing ability to hold U.S. critical infrastructure at risk via cyber attack, and an increasing potential to also use cyber to thwart U.S. military responses to any such attacks.
“This emerging situation threatens to place the United States in an untenable strategic position,” the report continued. “Although progress is being made to reduce the pervasive cyber vulnerabilities of U.S. critical infrastructure, the unfortunate reality is that for at least the next decade, the offensive cyber capabilities of our most capable adversaries are likely to far exceed the United States’ ability to defend key critical infrastructures. The U.S. military itself has a deep and extensive dependence on information technology as well, creating a massive attack surface.”
“That’s sobering,” said McClelland.
The report also called for “additional cost recovery mechanisms” so critical infrastructure owners can invest in resilience that supports U.S. military capabilities.
Vendors’ Roles, Responsibilities
Brian Harrell, assistant director of DHS’s Cybersecurity and Infrastructure Security Agency (CISA), said technology vendors are “part of the solution” and should not be shunned from industry cyber discussions for fear “they just want to sell us a bunch of stuff.”
“I think this industry … is a little apprehensive to bring vendors into the conversation,” he said. “I will say in your time of need, when things go bump in the night, you will be reaching out to your vendor. And so, let’s ensure the vendors are part of the conversation. … We need to build security in from the beginning and not bolt it onto the rear because that is expanding the threat exposure for us.”
Electric Power Research Institute (EPRI) CEO Michael Howard questioned whether software vendors should be held liable for security vulnerabilities in their products.
“In the rush to market with many products, designers will use software languages like C++ with many known vulnerabilities. They will copy sub-routines that also have many known vulnerabilities,” he said. “Should there be regulation so that if these vulnerabilities are then sold and [this] results in a breach — because all the bad actors know what these vulnerabilities are, and they can be prevented with some of the latest software languages — should there be regulation that says if you do this and you rush to market that you will be liable for that?”
In 2016, Taiwan-based Asus agreed to independent audits for 20 years to settle a Federal Trade Commission complaint over a security flaw that allowed hackers to take control of almost 13,000 home routers. Although Asus claimed the routers would “protect computers from any unauthorized access, hacking and virus attacks,” the FTC said it found a “pervasive security bug” in the router would allow an attacker to disable security settings remotely.
Johns Hopkins University computer science professor Yair Amir responded with a cautionary note. “In the cloud domain, there’s a lot of very good use of open source [software] … It’s very effective. If you regulate against it, maybe we lose something.”
Morgan said although Howard was referring to software sold to utilities, “I think the problem exists in spades in the IoT [Internet of Things] space.”
“I don’t even know who would play the role [of regulator],” he said, dismissing the Consumer Product Safety Commission. “They’re totally ineffectual in a lot of other places. They’re not going to be out front, cutting edge, on this,” he said.
“There are several layers of equipment we’re talking about and not all of them are covered by the same regulations,” noted Washington State University Professor in Power Anjan Bose. While relays on the bulk power system are covered by critical infrastructure protection (CIP) standards, “once you start going down the chain into the distribution system … I’m not sure the CIP compliance covers anything, especially if it’s on the other side of the meter.”
“It’s the grid edge things that are now having to send a lot of data into the control center,” he added. “So … the threat surface is increasing.”
The National Institute of Standards and Technology’s (NIST) Information Technology Laboratory recently took comments on a draft discussion paper seeking feedback to identify core cybersecurity capabilities important for IoT devices.
Kevin Stine, chief of the lab’s Applied Cybersecurity division, said feedback was “overall very positive. We hope to move forward with baseline recommendations in the next quarter or so.”
Eliminate Financial Penalties?
Marc Child, chair of the NERC Critical Infrastructure Protection Committee, said he’d like to see an end to the constant churn of standards development.
“I want my [computer science] engineers back,” said Child, information security program manager for Great River Energy. “They have been distracted by spreadsheet land for a decade. I need them working on cutting-edge technology. I want them to go out and buy effective technology, not compliant technology — there is a big difference.
I want them looking at software-defined networks. I want them looking at decoy networks.”
Child said the CIP standards are “a good baseline that covers 75% of the problem. It will raise all of our boats. But I’d like to challenge them to cap the efforts. Any new threats are going to be incremental and could be addressed outside of mandatory standards. I’m going to say something controversial here … I would like to propose we reduce or remove the financial penalties associated with noncompliance. We need a culture of cooperation, and in so doing, we can change the auditor and utility dynamic to one of a shared mission. I want the auditor … on my side of the table.”
Pondering Manual Operations
EEI’s Aaronson said the industry must be prepared for “the inevitability of impact” because “standards simply can’t keep up” with new threats.
He noted grid operators in Ukraine resorted to manual operations to restore power after suspected Russian hackers took remote control of utilities’ SCADA system and cut off service to about 220,000 customers for a few hours in 2016. (See How a ‘Phantom Mouse’ and Weaponized Excel Files Brought Down Ukraine’s Grid.)
“Do we have that capability here in North America? Sort of,” he said. “And that’s not a good answer for chief executives. So, we are beginning to develop the capacity for supplemental operating strategies. I like to call it the MacGyver project. How do we hold the grid together with bubble gum and duct tape?”
“I think the audit regime, and I think [FERC] and state commissions … are starting to realize [the limitations of] check-the-box exercise[s]. ‘Alright, I’ll do x, y and z — I’m secure.’ No, you telegraphed your defenses and you’re complacent,” he said. “… We’re not going to get there overnight, but I think the tide has shifted just a bit to acknowledge the limitations of explicit … binary standards we see today.”
He called for efforts like the Spare Transformer Equipment Program (STEP) and the nuclear industry’s Pooled Inventory Management system (PIM). “What can the electric industry do to mimic that [database] of assets we might need when a bad day comes?” he asked.
David Batz, EEI’s senior director of cyber and infrastructure security, also cited STEP as an example of the efforts industry should pursue. “Let’s broaden the aperture and think about where else within our critical infrastructure we can invest toward resilience and not in all cases drive toward the lowest cost,” he said.
Morgan said guaranteed cost recovery may be needed to fund utilities’ defenses. “Some of the other things that are going to be required if we’re going to address this nation state threat are going to be harder to do and not that cheap,” Morgan said. “The flip side is if I start, as the federal government, providing various cash incentives or other ways to finance stuff, there’s going to be a temptation to gold plate.”
Government Duplicating Private Sector Efforts?
Robert M. Lee, founder of Dragos, said the partnership between government and the private sector is not as effective as it could be.
“I think that we often times publicly spend a lot of time on complimenting each other versus saying, ‘Well, actually this doesn’t work and here are the things that are a waste of time.’ When I look at DHS and DOE, as an example, I see a lot of opportunity. I see a lot of really wonderful people and I see the ability for them to have a significant role in things like amplification, prioritization, helping with … government resources during a time of crisis,” he said.
“But then I see other efforts like, ‘Oh, yeah, let’s go build an incident response team.’ Why? We actually have all of that in the private sector. Why are we spending time and taxpayer money on that? My recommendation is cut out the stuff that we have helped the private sector get really good at and let’s be proud of that momentum and let’s focus on the things like supply chain that actually the private sector shouldn’t take on and that there’s a very significant government role in.”
When corporate boards ask him how to know if they are underspending or overspending on security, Lee said he tells them to meet their regulatory requirements and prepare for known scenarios, such as Ukraine 2015, Ukraine 2016 and ransomware.
“If you prepare for those and then Russia gets crafty and [does] something extra, it happens,” he said. “Your response strategy — that’s your design basis. And everything else above that: invest if you’d like. It’s risk reduction, but there’s no right answer. … If you didn’t prepare for those and you get attacked with the 2015 Ukraine [strategy], you should be in jail. Because it’s an absolute travesty that your community didn’t prepare.”
Unintended Consequences?
Jeff Dagle, chief electrical engineer for electricity infrastructure resilience at the Pacific Northwest National Laboratory (PNNL), said CIP standards have dissuaded some utilities from deploying synchrophasors that can provide situational awareness.
“If an operator can use that data and make a decision within 15 minutes, it is required to be compliant to the NERC cybersecurity requirements,” he said. “There are utilities that are choosing not to deploy technology that’s readily available … because of the … regulatory risk. … If your auditor doesn’t like the way you’ve set it up – bam!”
“And reliability coordinators are having trouble getting this data from the transmission operators because this handoff” is subject to CIP rules, he added. “These … aren’t critical things that somebody could hack in and shut down the grid. This is supplemental information to the operators for better situational awareness to make better decisions. We don’t [require] CIP compliance on some of the other things in the control room. There’s a weather map they can look at and see the thunderstorms coming across their service territory. We don’t require the Weather Channel to be CIP compliant. I suspect this same comment applies to other nascent technologies [and is] slowing innovation,” he added.
FERC’s McClelland noted standards are open to comment at any time. “So, if a standard [or] a requirement is in the way, of security or … reliability, then my expectation is that industry will petition [to change] that requirement.”
McClelland also suggested synchrophasors could be of interest to hackers.
“If you’re saying that … the synchrophasor technology makes [it possible to] react in 15 minutes and that that would be a needed function on the grid, as an adversary, I’m now targeting synchrophasors. … Adversaries are intelligent.”
“If we know adversaries are mapping the power system, you can doggone well bet they’re using electrical engineers to identify critical locations and they’re looking at specific equipment that’s become … absolutely necessary to operate these networks and systems.”
Boundaries Blurring
“The boundaries between utilities and national security are blurring,” said Caitlin Durkovich, director at Toffler Associates, the strategic advisory firm founded by “Future Shock” author Alvin Toffler. “I believe the security and resilience of our country is becoming more intertwined with critical infrastructure than ever before.”
Durkovich, former DHS assistant secretary for infrastructure protection, called for a strategy for an “integrated and resilient modern infrastructure.”
“I think you need a central coordinating body that is different than the post-WWII structure we have today, that is responsible for advancing a modern infrastructure.”
“We have to increasingly focus on this concept of foreign interference and the ability of our adversaries to meddle just enough and not get a kinetic response. We have to rethink what that means given how far they’ll go and what their capabilities are.”
Paul Stockton, managing director of Sonecon, said he expects any attack by the likes of China to be more than just an annoyance. He cited the Worldwide Threat Assessment finding that China could disrupt gas pipelines for days or weeks.
“China is not going to attack a single pipeline. If they’re going to roll the dice and do something that exposes them to such extraordinary risks of U.S. response, they’re going to go whole hog. They’re going to take down as much gas flow as they can to totally disrupt the generation of power to achieve their national security and political goals,” he said. “So, we need to think about this … indirect way of jeopardizing grid reliability in the context of a modernizing grid. Because gas is going to be with us for at least the near- to mid-term and maybe longer.”
“Let’s get going on that because right now owners and operators are left to figure it out for themselves, as are RTOs and ISOs. So, let’s agree on what the threat [is] … . It exists in the classified level. Let’s get something unclassified.”
Stockton said generators in the cranking path for black start plans are also likely to be targeted. “We never really think to test black start in a realistic way because you’d have to have a blackout,” he noted.
In the past, the assumption has been grid operators can import power from outside the blackout footprint to start the cranking path. “Not anymore,” Stockton said. “It is likely — in fact we should expect — Russia and China would like to achieve interconnection-wide blackout or maybe even nationwide. And black start is going to be absolutely vital under those circumstances in a way that just wasn’t true when you think of a New Madrid scenario, as horrible as it would be,” a reference to a worst-case earthquake originating in southeast Missouri.
“The bad guys know that. … They will intentionally target black start assets, cranking paths, generation units, communications — everything they possibly can.”
Limits to Exercises
“I think exercises are getting better,” said Stockton, who is a GridEx facilitator. “But I think they need to focus on this holistic challenge of interdependent infrastructure. That brings the different tribes together. … the tribe of the transmission operators, substation operators, together with cybersecurity personnel. Because they don’t usually kiss on the lips, do they?”
“We don’t have the tools to adequately understand the interactions of these multi systems like gas with electric,” said EPRI’s Howard. “We talk about it. At a high level, we understand it. But it’s the interactions — we don’t have the simulation tools to be able to do a good job with that.”
In addition to participating in national exercises such as GridEx, Harrell said utilities should conduct their own exercises with regularity “to ingrain it into the culture” and ensure familiarity with their response plans.
“I don’t know we do that enough outside of, ‘We have to do this once a year because CIP compliance says we must,’” he said.
Need for Simulation Tools
NERC’s chief engineer Mark Lauby said he would like simulation tools “that allow us — just like we do for an N-1 [scenario] — [to] build to a certain level of risk, understand what the mitigations are that we’re building into the system, and then after that [consider] recovery strategies.”
Lauby said grid operators need to “get in front of” the technology changes, such as the increase in inverters and asynchronous generation on the system, to “be sure we’re not building in more [attack] surface but rather de-risking and taking advantage of the technologies.”
William H. Sanders, interim director of the University of Illinois’ Discovery Partners Institute, said “The trick is to find the models with the right level of detail and abstraction that you can discover things … surprising things emerge, not just you fill everything in, and the model tells you what you knew it would tell you. I think we are making great progress. We have test beds. We have examples of models that can help us understand … I think we need to scale those up in a big way.”
Communication Breakdown?
“There’s no simulation that can fully appreciate the consequences of how things are going to cascade,” Durkovich said. “It all depends on the circumstances and the factors of the day.”
“I know GridEx is continuing to try and [address] this but we do all these exercises and I think live in a fantasy world where somehow communication is not degraded and is fully there.”
In large crowds, cellular service can be difficult because the local network is congested. “What makes us think that’s not going to happen on a really bad day? I was here on 9/11. You couldn’t get anything out.”
She said there aren’t enough exercises at the state and local level. “That’s really where we need to build capacity. Yes, you have DHS. But really, at the end of the day, … they’re not going to be there to respond to critically important state-level assets. … I don’t think states and localities have a full appreciation of how much of the burden they’re going to share on a bad day.”
Morgan said the previous National Academies study “talked precisely to that point and argued there was an urgent need to do something. As best as I can tell, [the report is] sitting on a bunch of shelves around town. We did brief quite a large number of people. But as several of you have said, there needs to be a wider recognition of the urgent [need for] moving towards greater resiliency.”
A fight over potential payments to insurers and wildfire victims has heated up in the Pacific Gas and Electric bankruptcy case and is scheduled to be a major topic of a hearing Nov. 19 before U.S. Bankruptcy Judge Dennis Montali in San Francisco.
Wildfire victims and California Gov. Gavin Newsom have challenged PG&E’s proposed $11 billion settlement with insurance companies and hedge funds — known in the Chapter 11 case as the subrogation claimants — that are seeking reimbursement for insurance payments.
PG&E has hailed the settlement as a milestone in its bankruptcy, which was brought about by billions of dollars in wildfire liability. The utility has asked Montali to approve the agreement at the Nov. 19 hearing.
Newsom’s lawyers, however, said in a court filing Friday that the settlement “is yet another example of legal maneuvering by parties apparently more focused on securing procedural advantages for their own pecuniary interests than on reaching a fair and expeditious resolution of this bankruptcy.”
“Many of the holders of subrogation claims are sophisticated financial institutions that bought the claims at a discount after the insurers paid out claims,” it said. “Certain of those institutions [including Boston-based Baupost Group] also hold equity in PG&E and may be seeking to leverage the settlement of subrogation claims to better position those holdings.”
Newsom asked the judge to delay deciding the matter to allow a competitive process to play out between PG&E and a group of the utility’s bondholders, whose alternative Chapter 11 reorganization plan Montali admitted Oct. 9. (See Judge Admits Takeover Plan as PG&E Starts Blackouts.)
The governor said he wants to continue the closed-door mediation sessions he began with PG&E and its creditors, including wildfire victims, last week. The sessions include a retired bankruptcy judge whom Montali appointed as a mediator at PG&E’s request. (See Pressure Grows for Public Takeover of PG&E.)
The official Tort Claimants Committee (TCC), which represents fire victims, also objected to the $11 billion all-cash agreement. The settlement would lock up those funds, potentially to the detriment of fire victims, the TCC lawyers said. Insurance companies and financial speculators would be given priority, with no guarantee PG&E would have enough liquidity to pay victims’ claims, they said.
“It is time to call this settlement what it is: a mistake,” the TCC lawyers wrote. “The debtors have given away all their cash and placed the wildfire victims in a position of full risk in this case.”
In its current reorganization plan, PG&E has offered fire victims $8.4 billion in cash, but to increase its offer — as many expect will happen — the utility might have to offer a cash-stock combination, the TCC told the judge.
PG&E’s stock fell to a record low of $3.80/share Oct. 28 after it blacked out more than 2 million residents to prevent its from equipment sparking wildfires — yet it also fell under suspicion for sparking the 78,000-acre Kincade Fire in Sonoma County.
Its stock rebounded to $7.06/share at the close of trading Tuesday after several reports in the financial press that PG&E would increase its offer to fire victims to $13.5 billion, the same as bondholders proposed in their alternative reorganization term sheet.
Wildfire Liability Still to be Determined
The amount that fire victims may ultimately be owed is still in question.
PG&E and the TCC agreed Monday to extend the date for wildfire victims to file claims from Oct. 21 to Dec. 31, so that more claims may be submitted. There has yet to be an accounting of the number or amount of individual victims’ damage claims.
Proceedings to estimate the amount of PG&E’s wildfire damages are taking place before a different federal judge in San Francisco. The estimation process is a typical part of bankruptcies involving large numbers of victims.
And blame for one of the biggest fires of the past two years remains in doubt.
Investigators with the California Department of Forestry and Fire Protection (Cal Fire) determined PG&E equipment sparked the Camp Fire in November 2018. That blaze killed 86 people and destroyed more than 14,000 homes in the town of Paradise.
Cal Fire investigators also found PG&E equipment ignited 21 of the 22 wine country (also called North Bay) fires in October 2017.
They found a private landowner’s faulty wiring started the Tubbs Fire, which leveled an entire neighborhood in the city of Santa Rosa, killing 22 residents.
Victims, however, believe jurors should determine who’s to blame. A trial to decide if PG&E caused that blaze is slated to start Jan. 7. The result could add billions of dollars to PG&E’s wildfire liabilities.
Not content with pillorying SPP officials on their home turf, Louisiana Public Service Commissioner Foster Campbell has broadened his complaint over RTO expenses with a letter challenging SPP’s and MISO’s spending on offices and executive salaries.
Campbell last week filed a letter with SPP’s and MISO’s state commissions and the National Association of Regulatory Utility Commissioners’ senior leadership, calling for a “thorough examination of [grid operators’] spending.”
“Turning the American power grid into the electricity equivalent of an interstate highway system is probably a worthwhile goal, but I question how those RTOs freely spend our dollars,” Campbell wrote, adding a new acronym to the industry’s lexicon: Overspending Other Peoples’ Money (OOPM).
The Louisiana commissioner described SPP’s Corporate Center as a “150,000-square-foot Taj Mahal of an office building in a leafy 20-acre suburban setting fit for a Fortune 100 corporation.” He said he hasn’t been to MISO’s corporate offices in Carmel, Ind., and was thus unable to compare them to SPP’s “ornate offices.”
“If MISO’s offices are anything like SPP, then these two [RTOs] have a bad case of OOPM,” he said.
Campbell also lambasted the salaries paid to the grid operators’ top executives. He noted SPP’s Nick Brown and MISO’s John Bear are paid eight and 16 times, respectively, as much as FERC Chairman Neil Chatterjee ($155,500). Campbell cited 2017 data for Brown ($1.5 million in total compensation) and said Bear receives $2.8 million in compensation.
Bear’s salary matches up with the 2017 IRS Form 990 available through nonprofit tracker GuideStar. Brown’s 2016 Form 990 shows his total compensation was $1.2 million.
Campbell contrasted the CEOs’ salaries with Louisiana’s “1.6 million electric customers, many of whom live at or below poverty level.” He said SPP and MISO charge the state’s investor-owned utilities nearly $31 million a year to dispatch energy.
The letter would sound familiar to those who were present last month in Little Rock, Ark., when Campbell livened up the SPP Regional State Committee’s October meeting at the RTO’s corporate headquarters by criticizing the facility’s $62 million price tag and senior executives’ salaries. Several observers found his comments to be political, as Campbell is up for election next year. (See “Louisiana’s Campbell: SPP Spending ‘Extravagant,’” SPP Regional State Committee Briefs: Oct. 28, 2019.)
SPP said it “respectfully but wholeheartedly disagrees” with Campbell’s allegations.
Spokesman Dustin Smith said the grid operator provides “significant” savings to ratepayers in its footprint and listed several examples to back up his point:
“Conservative” cost-benefit studies that indicate the RTO’s services produce $2.2 billion in annual savings across its 14-state region.
FERC’s 2018 State of the Markets report indicating the SPP region enjoys the nation’s lowest wholesale electric costs.
“To anyone who questions SPP’s affordability, stewardship or ethics, we welcome the opportunity to provide answers,” Smith said.
MISO spokesperson Allison Bermudez would only say that the RTO, “as we have for the past 20 years, continue to be good stewards of our members and those customers we work together to serve.”
Louisiana utilities Entergy Louisiana and Southwestern Electric Power Co. both said RTO membership is worth the costs.
Entergy spokesman Mike Burns said the company’s MISO membership has been a “highly effective tool in helping control costs and keeping our rates among the lowest in the nation.” After netting out the RTO’s administrative costs, Louisiana customers realized an estimated $560 million in savings between 2014 and 2018, “largely because of MISO’s organized power markets, which allow power plants to be dispatched more efficiently, resulting in a lower delivered cost of energy,” he said.
“Customers also see significant cost savings from MISO members sharing generation reserves across the organization’s footprint, producing long-term benefits,” Burns said.
SPP’s corporate campus | Nabholz Construction
SWEPCO’s Peter Main said the utility’s customers benefit from SPP’s regional markets through reduced fuel costs and more efficient transmission planning. However, he also said SWEPCO is concerned about the RTO’s rising costs. SPP’s Board of Directors last month approved a record increase in the administrative fee, from 39.4 cents/MWh to 43 cents. (See “Directors Approve 9.1% Administrative Fee Increase for 2020,” SPP Board of Directors/MC Briefs: Oct. 29, 2019.)
“SWEPCO and other SPP members remain concerned about the growing costs of RTO operations,” Main said. “We are actively involved in efforts to ensure that the RTO is cost-effective, efficient and providing good value for our customers.”
SPP is equally concerned about costs. First-year board Chair Larry Altenbaumer created and led a task force focused on finding opportunities to increase value and improve affordability for SPP’s members and stakeholders. The group determined there is work to be done around the edges. (See SPP Value Group Finds No ‘Silver Bullets.)
RTO Insider asked regulatory commissioners in both regions for comment on Campbell’s letter. Arkansas’ Kimberly O’Guinn and Missouri’s Scott Rupp responded.
O’Guinn, who is the RSC’s president this year, said she didn’t agree with Campbell’s assessment, but she “appreciated” his concerns about the costs of participating in SPP.
“The RSC is conscious of SPP’s costs as well as other issues that impact utilities and ultimately the customers,” she said. “Therefore, the majority of the RSC regularly participates in monthly calls and quarterly business meetings to educate ourselves on these matters and engage in dialogue with the SPP Board of Directors and staff, members and stakeholders.”
O’Guinn said the Arkansas Public Service Commission finds that SPP’s services and the Integrated Marketplace have “resulted in net benefits to ratepayers” and justified the commission’s decision to allow certain utilities to transfer functional control of their transmission assets.
“Along with financial benefits,” she said, “participation in SPP has provided increased reliability and a decrease in required reserve margins.”
Rupp said the Missouri Public Service Commission believes “there is a large amount of benefit from RTO membership.” He cited back-of-the-envelope figures from SPP’s last regional cost allocation report that indicated Evergy’s Missouri subsidiaries Kansas City Power & Light and KCP&L Greater Missouri Operations enjoyed 3.97 and 2.15 benefit-to-cost ratios, respectively.
He also said the PSC requires the state’s utilities to file studies every three years that justify their RTO membership.
“In the past few years we have waived the study, believing firmly that benefits are realized and the cost of the study would not be a good expenditure of resources,” Rupp said.
He also noted that that there have been few instances of load shed despite recent severe storms and floods in Missouri. “Before RTO membership, there would have been a shedding of load in Missouri.”
WESTBOROUGH, Mass. — The Northeast Energy and Commerce Association (NECA) last week drew more than 100 participants to its 18th Power Markets Conference to explore grid reliability and resilience, carbon pricing, and the federal and state policies impacting the electricity sector.
Conference co-chairs Mary Usovicz, principal of MUConnections, and David Fixler, an attorney with Greenberg Traurig, mixed up the format by doing away with slide presentations — mostly — and just having panelists say a few words before taking audience questions and polls via Slido, a web-based platform.
FERC Commissioner Richard Glick shared his perspective on the power markets after two years in office.
“Chairman [Neil] Chatterjee gave a speech a couple months ago in which he said he wanted to make FERC boring again,” Glick said. “Well, I don’t think he’s succeeded yet on that. It’s been pretty crazy lately.”
He said the “sometimes too emotional” commission meetings were “emblematic, unfortunately, of the governmental environment, at least related to the federal government these days.”
The heated battles partly stem from how the transition to a new energy world inevitably creates winners and losers, Glick said. There’s “a lot of money” involved, he added.
“When you have a dissent or disagreement and this kind of doctrinaire policy — that’s my view — a lot of these issues end up getting litigated in a court, and all that does is create more uncertainty for you all in the industry,” Glick said. “It doesn’t mean you’re guaranteed to survive a court challenge if there’s a unanimous commission, but certainly it’s much more likely.
“I never realized until I got to FERC how complicated some of these markets have grown … and we see a lot of proposals to tinker with the markets, particularly the capacity markets,” Glick said. “There’s a very broad difference across the country in how the RTOs and ISOs address resource adequacy,” from highly structured markets in the East, to utility-centered planning elsewhere, to total market reliance in ERCOT.
In the debate over federal and state energy policies competing in some way, Glick said the Federal Power Act “is very clear.”
“Resource decision-making is supposed to be left to the states, not to the federal government. The Supreme Court has spoken, and there are limits on what states can do — they can’t set wholesale prices and so on … but for the most part the court was also relatively clear that … it’s up to the states, not FERC, to make resource decisions.”
Glick pointed to frustration with the lack of a federal carbon policy, leading states to decide to go their own way on carbon pricing or emissions standards, a process that produces its own complications — and risks — for organized electricity markets.
“What we’re seeing is the real danger that we’re going to unravel completely these markets,” he said. “Some people might think that’s a good idea, some not, but if you do support markets, it’s a very dangerous road to go down to continue to stifle the states’ efforts.”
During one panel, Rebecca Tepper, chief of the Massachusetts attorney general’s energy and telecommunications division, asked how the wholesale markets would have to change in order for Massachusetts to bring on more renewables without state-sponsored procurements.
“We are looking at transitioning the current fleet [of generators], and the Department of Environmental Protection is looking at every cap on natural gas emissions on a declining basis, but we recognize that fossil [fuel] is going down and we have to replace that,” Massachusetts Department of Public Utilities Chair Matthew Nelson said.
“At the same time, the state is also trying to move transportation and buildings over to the electric grid, so electric’s probably going to be growing,” Nelson said. But he acknowledged he didn’t know what prices the ISO-NE market would have to produce to discontinue procurements.
Asked if there is a breaking point price for electricity consumers, Nelson quipped that his staff would advise him not to answer that question.
“Who wouldn’t want electricity? It’s the closest thing we have to magic,” Nelson said.
On the subject of carbon pricing, Nelson said, “When people see something as complex as a clean peak standard in a single state, you start thinking, ‘Is a regional carbon adder the right way to go?’ If we’re going to design a carbon adder … we don’t want to set a price that fails to impact the market the way we want it to.
“I think RGGI is great, and I like carbon pricing, but is that the thing that is bringing offshore wind on? Is that price or policy sufficient to bring energy storage; to support a Millstone? Those are the questions we have to answer when we are thinking about what a carbon price is in the market.”
Cynthia Arcate, CEO of PowerOptions, asked, “What is the path forward for renewables if there is insufficient demand for” Competitive Auctions with Sponsored Policy Resources (CASPR)?
Mark Karl, vice president of market development for ISO-NE, who earlier referred to CASPR as “the friendly ghost,” said the question goes to the heart of what the New England States Committee on Electricity “is asking all of us to work on, collectively, which is, ‘How do we manage these resources?’”
“I think of CASPR not as a friendly ghost, but as the ghost of a promise that we in the states were going to be able to incentivize renewable resources,” said Marissa Gillett, chair of the Connecticut Public Utilities Regulatory Authority. “We need more work by the states.
“You’re never going to get [carbon pricing] from the states, because we are not eager to make anything else FERC-jurisdictional at this moment.”
Defining the Future
Seth Kaplan, director of permitting and development for Mayflower Wind, which just won Massachusetts’ second 800-MW offshore wind solicitation, brought up the potential for the region to export energy to the Midwest, where older fossil resources are retiring. “There were [U.S. Department of Energy] transmission studies 12 years ago that modeled that with a full build of offshore wind generation and onshore transmission,” he said.
After another speaker referred to wind turbines as “intermittent,” he also gave the audience a vocabulary lesson, saying, “Words matter.”
“All energy sources are to some degree intermittent,” Kaplan said. “Nuclear power plants sometimes go offline. … That’s intermittent. Variable is predictable. We can give you a 90% case that tells you how much energy a wind farm will produce over the course of a year, and that’s what you can plan around.”
Deborah Donovan, Massachusetts director for the Acadia Center, was asked how to tell the difference between the goal of zero carbon, carbon-free electricity, reduction of carbon emissions by 100% and net carbon neutral.”
“There are some subtle differences,” Donovan said. “First of all, it does matter whether we’re talking about an economy-wide target versus a sector-specific target, because not all these terms apply to all situations.”
Following what the U.N. Intergovernmental Panel on Climate Change says about net zero carbon, “that definition is that manmade carbon additions are being balanced by manmade carbon removals, so those could be other actions like reforestation,” Donovan said.
Dan Dolan, president of the New England Power Generators Association, called for an “analysis and articulation” of future market needs at the same depth with which the RTO has been studying fuel security.
“The second component is trying to identify what is the most common element driving these [state] procurements and other entry into the market,” Dolan said. “And pretty clearly it’s carbon; it’s meeting the economy-wide mandates that the states have. A dual and second track to all this is a meaningful look at what it requires on an economy-wide basis … to try and obviate the need for a second wave of contracted resources.”
The morning keynote speaker said that on carbon he was only repeating what ISO-NE CEO Gordon van Welie, FERC commissioners and many others have said in the past.
“The cure for what ails the markets, or at least its biggest problem if you think we should be trying to integrate renewables and keep nuclear plants running without depressing prices, is a carbon fee,” said Rich Heidorn Jr., editor-in-chief of RTO Insider. “Incorporate the externalities, and you could reduce [ISO-NE’s] meeting schedule, and FERC’s workload, quite a bit.”
PJM announced Duane’s resignation, effective immediately, via email Monday. In the release, the RTO said Duane will seek other opportunities after more than 16 years with the organization.
“We are grateful to Vince for his many contributions to PJM and its stakeholders over the past 16 years,” interim CEO Susan Riley said in a statement. “As a member of the PJM Board of Managers, I worked with Vince from the time I joined the board and have enormous respect for his legal perspective. The entire PJM community thanks Vince for his many contributions to PJM.”
Deputy General Counsel Chris O’Hara will assume the role of vice president, general counsel and corporate secretary with responsibility for law and compliance, effective immediately, PJM said.
“It has been my honor and privilege to serve PJM’s employees and members for more than 16 years,” Duane said. “I am proud to have been part of such an outstanding team doing extremely important work, and I know PJM will continue to forge ahead with innovation, integrity and outstanding service to its members.”
Chris O’Hara, PJM | PJM
Susan Buehler, PJM spokesperson, didn’t elaborate much further on Duane’s departure, except to say that it “was purely his decision” and that he was ready to move on and “do something else.”
Duane is the fourth top executive to leave PJM this year, following the resignations of CEO Andy Ott, CFO Suzanne Daugherty and Vice President Denise Foster. In September, Riley announced the restructuring of the State and Member Services Division, previously led by Foster and now headed by Jen Tribulski, senior director of member services, and Asim Haque, executive director of strategic policy and external affairs.
Several key leaders within PJM also received promotions over the summer, announced at the time of Ott’s resignation. (See CEO Andy Ott to Retire.) The organization also hired Nigeria Poole Bloczynski as its first chief risk officer in July and hopes to choose a new CEO before the end of the year. (See PJM Names Chief Risk Officer and “CEO Search Continues,” PJM MRC Briefs: Sept. 26, 2019.)
FERC encouraged PJM’s transmission owners to settle disputes over the sector’s proposed Tariff attachment that revises outdated border and non-zone service rates using a methodology that several members find flawed and unreasonable.
The filing, sent to FERC in June, updates the yearly border charge to prevent network integrated transmission service (NITS) customers — network load located outside PJM’s boundaries but served from within the RTO — from subsidizing border and non-zone service rate customers who use transmission service through and out of PJM (ER19-2105). In the filing, TOs said under existing rates, last updated in 2004, it’s unclear if border rate customers “have been consistently charged transmission enhancement charges (TECs)” because of the ambiguity around which specific TECs apply to border service.
“The PJM TOs argue that the proposed revisions will end the cross subsidy that zonal NITS customers in PJM have been providing to border rate and non-zone service rate customers because revenue from customers taking service under each of these rates is either directly or eventually credited back to zonal NITS customers,” the commission noted in its order.
The proposal would not increase the total cost of providing transmission service in PJM because the increases to border and non-zone service rates will be offset by a decrease for zonal NITS customers, the TOs said in their filing.
FERC accepted the TOs’ filing Nov. 5, subject to refund, with an implementation date of Jan. 1, 2020, but also set a paper hearing and settlement procedures for involved parties to work out their differences over the proposed methodology behind the rates.
Contentions Raised
In proposing the rate revision, TOs wanted to clarify that PJM’s border service includes service to a point of delivery at a merchant transmission facility (MTF) that provides service to a neighboring transmission system — an unnecessary explanation, according to some of the protesters in the proceeding.
The New York Power Authority suggested the clarifying language “is an attempt to create a separate and unjustified classification of customers for purposes of extracting a higher point-to-point transmission service rate from such customers.”
Linden VFT, a New Jersey-based MTF, said the new methodology would increase its border rate charges from $6 million annually to roughly $16 million, potentially forcing the company into insolvency because of “fundamental changes” to its business model. It also objected to a formula that it insists charges the company for lower-voltage transmission facilities “it does not use.”
The TOs offered a solution for double charging of MTFs with firm transmission withdrawal rights (FTWRs): create a credit that would remove the cost of those TECs paid in connection to a facility’s FTWRs from the cost of border rate service.
The Long Island Power Authority argued the crediting mechanism will not work, and the Neptune Regional Transmission Authority supported the claim, noting that the TOs “crediting mechanism is structurally flawed and would result in MTFs with FTWRs and their customers being charged twice for the same allocation of [Regional Transmission Expansion Plan] charges.”
FERC Weighs in
FERC dismissed Linden’s argument that the proposed border rate would charge the company for lower-voltage transmission facilities it does not use, saying “the border rate reflects the fact that a transmission customer may take border rate service from any point within PJM, and that the entire PJM transmission system, including lower-voltage transmission facilities, supports the export transactions.”
“The border rate service, therefore, permits the exporter to access generation anywhere in PJM and such transmission may utilize any of the PJM facilities, including lower-voltage lines,” the commission concluded.
FERC also allayed concerns over the TOs clarifying language on the definition of border service, saying that it is just and reasonable and aligns with commission precedent on the definition of “through and out service.”
Other concerns over whether the proposal meets the standards for formula rate protocols were also dismissed. FERC said because the stakeholders can contest PJM TOs formula rates, there is no need for additional protocols regarding the proposed composite rate. The commission did agree, however, that the TOs’ filing “lacks clarity regarding the process by which parties can challenge or confirm PJM’s calculation of the border rate from the PJM TO’s formulas.”
FERC said a settlement judge will be assigned within 15 days of the filing. The appointed judge will report to the commission within 30 days concerning the status of settlement discussions. At that time, the judge can recommend additional time for settlement negotiations or commence a paper hearing.
The commission granted late-filed motions to intervene from Exelon, PPL and Helix Ravenswood.
NYISO’s Business Issues Committee on Wednesday voted unanimously to recommend that the Management Committee approve Tariff changes intended to help speed up the interconnection process.
Thinh Nguyen, senior manager for interconnection projects, presented the proposed changes, which seek to expedite the class year portion of the interconnection study and limit the potential for one or two projects to cause delay for other projects.
NYISO is proposing to:
require deliverability evaluation in system reliability impact studies;
remove additional system deliverability upgrade studies from the class year study;
conduct expedited deliverability studies for capacity resource interconnection service (CRIS)-only projects; and
tighten CRIS expiration rules to prevent the retention of CRIS by facilities not participating in the capacity market.
Nguyen noted that stakeholders were keen to ensure the proposal would not change the qualities of the current process most important to them, including:
the identification of system upgrade facilities for projects to reliably interconnect, including detailed design, engineering and construction estimates;
provision of binding, good-faith cost estimates that provide reasonable closure on upgrade costs; and
equitable allocation of upgrade costs.
NYISO intends to make many of the proposals effective for Class Year 2019.
A sample timeline of expedited deliverability of the class year study | NYISO
Competitive Entry Exemptions
The committee also voted unanimously to recommend that the MC approve Tariff changes to make competitive entry exemption (CEE) available to requests for additional CRIS megawatts in a manner consistent with the underlying rationale for the exemption.
Senior ICAP Mitigation Analyst Jonathan Newton presented the proposal, which includes a change in the consequences of withdrawing a CEE request or providing false and misleading information.
The changes also modify the CEE rules in a way that could facilitate the repowering and replacement of existing generators by allowing existing portfolio owners that have entered into competitive short-term hedging contracts to qualify for the CEE.
“The changes are a reasonable way to let people move forward without penalizing normal commodity hedging,” one stakeholder said.
NYISO intends to make the proposed rules effective for Class Year 2019 projects, Newton said.
If the MC approves the queue changes this month, and the Board of Directors approves them in December, the ISO anticipates making the filings with FERC by Dec. 20 and seeking orders from the commission during the third week of February 2020.
More Granular Operating Reserves
The BIC discussed a proposal to implement local reserve requirements in certain New York City (Zone J) load pockets.
Market Design Specialist Ashley Ferrer presented the proposal, as recommended by the Market Monitoring Unit, including the modeling of the requirements based on N-1-1 reliability criteria.
Load pockets in Zone J are areas constrained by load levels and generation capability, as well as by transmission-supported import levels into the pocket. The structure and boundaries of each load pocket varies based on load, generation and transmission imports, Ferrer said.
New York Control Area operating reserves | NYISO
The ISO last June established a reserve region in Zone J based on a market design approved by stakeholders in March.
NYISO is proposing to establish operating reserve demand curves for each load pocket that assign a $25/MWh value to the proposed reserve requirements. The ISO proposes 30-minute reserve requirements of 325 MW in Astoria East/Corona/Jamaica; 225 MW in Astoria West/Queensbridge/Vernon; and 250 MW in Greenwood/Staten Island.
“This issue is not prioritized in 2020, but we still consider it important, and it could go forward conceivably in 2021,” said Rana Mukerji, senior vice president for market structures. “We will actually bring forth the methodology [for an impact analysis] before conducting any consumer impact analysis [with respect to the proposal].”
Broader Regional Markets Report
In presenting the month’s Broader Regional Markets Report, Mukerji highlighted updates to two ongoing proceedings.
The first item concerned five-minute real-time dispatch transaction scheduling with Hydro-Québec (HQ) across controllable interties at the Chateauguay proxy.
The proposed plan includes a project to consider scheduling transactions on a five-minute basis with HQ, instead of either the 15-minute or hourly basis currently in effect using NYISO’s real-time commitment software. The ISO is targeting to complete a study of the potential enhancement in 2020.
The second item concerned an effort to clarify the minimum deliverability requirements for external capacity.
At the MC’s May 20 meeting, stakeholders approved enhancements to the performance requirements for external capacity suppliers in response to a supplemental resource evaluation, a proposal that became effective in August after FERC approval.
IPPNY’s Matt Schwall Elected as Vice Chair
The BIC elected Matthew Schwall as its incoming vice chair for 2019/20. Schwall is director of market policy and regulatory affairs for the Independent Power Producers of New York, where he has worked since 2014, and previously worked in various capacities at the New York State Assembly. He is earning a master of science in global energy management at the University of Colorado Denver.
SPP staff last week told the Seams Steering Committee that they have begun “very preliminary” interregional planning discussions with Canadian electric utility SaskPower.
Clint Savoy, the committee’s staff secretary, said a provision in the RTO’s joint operating agreement with SaskPower allows joint planning analysis and coordinated system planning. The discussions center on reliability needs, he said.
SPP and SaskPower share a direct tie through Basin Electric Power Cooperative’s existing transmission facilities in North Dakota. The grid operator completed its first international transaction in December 2015 when it imported power from SaskPower during an emergency situation. (See SPP, SaskPower Make First International Trade.)
In February 2017, the Department of Energy granted SPP’s request to make electricity exports to Canada. The RTO told the department that it wanted to “address emergency assistance transactions” but that it doesn’t normally purchase from or sell to “such external entities.”
The authorization expires on Feb. 7, 2022.
FERC in 2016 approved SPP’s request to recognize the U.S.-Canadian border as a point of sale for transactions with Canadian transmission providers. The ruling allows Canadian companies to register their resources with and make them available to the RTO under its market rules. (See “FERC OKs Canadian Border Point-of-Sale Filing,” SPP Briefs.)
Pseudo-tie Revisions to SPP-MISO JOA
The SSC reviewed and made changes to a new pseudo-tie section of SPP’s joint operating agreement with MISO, addressing its neighbors’ continued deferral of dispatch decisions to its balancing authorities.
MISO has historically deferred to local BAs in making pseudo-tie decisions in the real-time transfer of a resource or load from its “native” BA to an “attaining” BA in a different location.
“There are some local balancing authorities taking the position that we’re not a BA, so we’re not going to execute it anymore,” Savoy said. “We thought it would be helpful to address this in the JOA and avoid those situations in the future.”
Savoy said staff have taken FERC-approved language from the MISO-PJM JOA as a starting point. SPP hopes to file the changes with FERC early next year.
M2M Settlements Swing in MISO’s Favor
Staff’s regular market-to-market (M2M) report indicated another slow month, with 41 permanent and temporary flowgates binding for a total of 664 hours and resulting in a $197,320 settlement in MISO’s favor.
| SPP
August’s numbers dropped to $64.1 million in SPP’s favor. The two seams neighbors began the process in March 2015. SPP has seen positive settlements in 40 of 54 months through August.
FERC accepted an agreement last week between CAISO and a Calpine plant to provide black start service, but it also agreed with the California Public Utilities Commission that more cost information was needed to determine if the deal was just and reasonable (ER19-2800).
The federal commission accepted the agreement effective Nov. 6 but required additional information to be presented at settlement hearings.
CAISO in 2016 determined it needed additional black start capability in the San Francisco Bay Area. It issued a request for proposals in June 2017 and ultimately selected a plan by Calpine to provide battery storage at the company’s gas-fired Russell City Energy Center in the city of Hayward.
The agreement between Russell City and the ISO — in which Pacific Gas and Electric, the transmission provider in Hayward, is also a participant — stipulates that the plant will collect about $7.4 million annually for five years to cover a $21.8 million capital investment and earn a reasonable rate of return. The plant owner will recover both the variable cost of providing black start service and the fixed cost of constructing the battery system.
Calpine’s Russell City Energy Center in Hayward, Calif. | Calpine
The variable cost represents the sum of a start-up charge, a fired-hours charge, greenhouse gas reimbursement, CAISO charge reimbursement, a performance test field support charge and a power plant outage cost reimbursement — all outlined within a schedule of the agreement. The contract also provides for Russell City to recover a “market revenue shortfall” if the revenues received during energy delivery are less than provided for by the schedule.
Russell City contends that CAISO’s competitive solicitation process guarantees that its rates, terms and conditions for black start service are just and reasonable. The ISO would have the option to renew the agreement for an additional five years after the contract expires.
In its comments to FERC, the CPUC said it supported the development of black start capability in the Bay Area but argued Russell City had not provided underlying cost information to support its filing. The state commission requested that FERC require Russell City to refile the agreement with underlying cost information, or alternatively accept the agreement but also determine that it does not set any precedent. FERC agreed with the CPUC’s concerns.
“Although Russell City, CAISO and PG&E represent that they exchanged information with CPUC about cost allocations during their negotiations of the agreement, that information has not been submitted into the record of this proceeding and therefore is not available for this commission to evaluate in determining whether the proposed rates are just and reasonable under Section 205 of the Federal Power Act,” the commission found.
