SPP leadership has delayed staff’s return to their offices until at least Jan. 4 — a three-month delay from the previous target of Oct. 5 — because of increasing COVID-19 diagnoses in Arkansas.
COO Lanny Nickell said in a Thursday email that SPP’s officers decided to postpone the return to the RTO’s Little Rock headquarters until 2021. The White House Coronavirus Task Force on Tuesday said Arkansas has the nation’s seventh highest rate of new cases: 194 per 100,000. Arkansas on Wednesday reported 942 new cases and 19 deaths, raising its totals to 80,945 and 1,369, respectively.
SPP has delayed by three months staff’s return to its corporate headquarters. | WER Architects
“It wasn’t an easy choice. Like many of you, we’re eager to get back to normal, but case numbers are still high across our state and in Little Rock,” Nickell said. “Especially given our office’s open floor plan, which could exacerbate the effects of exposure should any of our staff become sick, we’re doing all we can to safeguard the health of our employees and our ability to serve you.”
Nickell also said SPP’s system loads have largely returned to pre-pandemic levels. He said the grid operator has sufficient capacity and reserves to meet demand this fall and that delayed generator maintenance has not resulted in an increase in unplanned outages.
CAISO launched a two-part initiative Wednesday that would alter how Western Energy Imbalance Market (EIM) participants submit their base schedules.
The base schedule is the hourly forward energy plan that CAISO uses as a baseline to measure energy balance deviations for market settlements in the EIM. Rules set out three deadlines by which EIM entities must submit the resource plans behind their hourly base schedules.
By the first deadline, at T-75 (75 minutes before the operating hour), all participating and nonparticipating resources must submit their base schedules, and participating resources must submit their energy bids. CAISO’s market software then evaluates each 15-minute interval within that hour for capacity and flexible ramping capability.
A second deadline follows at T-55 after CAISO validates initial base schedules. At that point, market entities can review and update their schedules, which is followed by another set of validations.
At T-40, entities are required to submit final, financially binding base schedules, used by CAISO to balance against the load forecast and set the baseline for determining imbalance energy for the operating hour.
CAISO’s proposal would push the financially binding base schedule deadline from T-40 to T-30, a move that would require the ISO to update its market software to shift the start of the EIM’s real-time pre-dispatch (RTPD) process from T-37.5 to T-29, while retaining the current RTPD completion time of T-22.5. CAISO’s final base schedule test would also be moved to after the T-30 deadline.
CAISO’s proposal would shift the EIM’s final base schedule deadline from T-40 to T-30, shortening the real-time pre-dispatch interval. | CAISO
The ISO committed to examining the change as part of its EIM implementation agreement with the Bonneville Power Administration. A portion of BPA’s customers operate under “slice of system” contracts that provide them with a percentage of the output from the federal Columbia River Power System rather than a fixed volume of energy. Slice nominations can be updated after T-40, potentially exposing BPA to imbalance charges under the existing rules once it begins transacting in the EIM in 2022.
“It would create the ability for EIM entities to submit more accurate final base schedules as the deadline is simply closer to the operating hour,” Danny Johnson, CAISO lead market design developer, said during a call to discuss the proposal Wednesday. “Ideally this reduces the financial impact of imbalance settlement, and it would provide more accurate base schedules to the RSE [resource sufficiency evaluation].”
Johnson added that while the proposal “was precipitated by the EIM implementation agreement, I do want to clearly point out that this change is available to all EIM participants.”
John Walker, an analyst with Portland General Electric, asked whether CAISO would consider moving any of the other base schedule submission timelines in light of the T-30 change.
“Right now, all we’re proposing is that T-40 to T-30 [shift]. I think maybe at some future date we’d think about moving around the other timelines associated with the base schedule submission process, but not within the scope of this initiative,” Johnson responded.
Accounting for Start-up Energy
The second part of the straw proposal would allow EIM participants to factor start-up energy into their hourly resource plans and base schedules. The ISO’s Tariff currently prohibits those participants from submitting base schedules that show energy above zero but below a resource’s minimum load (Pmin).
The proposal notes that some EIM resources have multi-hour start times and minimum loads in the hundreds of megawatts, but existing rules prevent those resources from accounting for start-up energy in their base schedules for the EIM’s RSE ahead of an operating hour.
“This leaves the EIM entity with two options: either exclude this energy from the base schedule, which results in no inclusion in the RSE, or reallocate this energy to other online resources,” the proposal says. “Neither of these options allows the EIM entity to accurately capture a potentially significant amount of energy produced while a resource is starting.”
The proposed plan would entail CAISO altering the logic of its base schedule aggregation portal and the RSE to allow entities to include start-up energy in their base schedule submissions.
“This will allow EIM entities to capture start-up energy in their schedules. The start-up energy will not be hit with uninstructed imbalance energy” charges, Johnson explained.
While the energy will be counted as part of the EIM entity’s RSE for the balancing test, CAISO clarified it would make no changes to the EIM’s capacity, flexible ramp and transmission feasibility tests. A resource operating below its minimum load will still be prohibited from providing ancillary services.
CAISO acknowledges that the changes would create a discrepancy between how start-up energy is treated for EIM and ISO resources. But the ISO noted that it already creates balanced day-ahead schedules through its Integrated Forward Market (IFM) while EIM entities produce their own balanced schedules, allowing the latter to include start-up information in the submission of their base schedules.
“To achieve similar treatment for the CAISO, the IFM would need to include this start-up energy within its optimization. Any after-the-fact inclusion of this energy to balanced day-ahead schedules would potentially create upward flexibility, at the expense of downward flexibility,” CAISO said. “As the CAISO schedules are already balanced, the CAISO does not believe this additional upward flexibility is worth the potential risk of failing the RSE in the downward direction.”
CAISO said it believes inclusion of start-up energy in the day-ahead market should be addressed “holistically” either through its existing extended day-ahead market initiative or some other future effort. (See CAISO Proposal Sets Course for EIM Day-ahead.)
The ISO additionally proposes to implement “after-the-fact” monitoring criteria to ensure participants don’t abuse the market based on the change, including looking for a non-monotonically increasing pattern of base schedules below Pmin over consecutive hours; the lack of a base schedule in an hour following an interval with a base schedule below Pmin; and base schedules remaining below Pmin for an “unreasonably” long period based on the resource’s technology and start-up profile.
Brian Holmes, a director with Utilicast, asked whether resource owners would be given an after-the-fact opportunity to explain why a resource might have been flagged under the criteria, such as a failure to start up.
“I don’t think we want this to be unnecessarily punitive,” Johnson said.
CAISO Senior Manager Brad Cooper said the ISO hopes to implement the start-up energy portion of the proposal by next spring, with the T-30 slated to follow next fall.
Kristina Osborne, CAISO stakeholder engagement and policy specialist, said the proposal will likely fall under the EIM Governing Body’s primary approval authority. She said stakeholders should provide feedback on the proposal and the RTO’s proposed classification by Oct. 14.
The proposal will go before the Governing Body on Dec. 3 and the ISO’s Board of Governors later that month.
Texas regulators are raising concerns about its contract with Texas Reliability Entity as ERCOT’s reliability monitor, questioning whether they are getting their money’s worth and whether there is enough transparency for ratepayers.
The issue came tumbling into the open during the Public Utility Commission’s Sept. 24 open meeting, when it considered a proposal related to oversight of wholesale market participants. Commissioner Shelly Botkin had filed a memo asking to discuss draft amendments to its rules that would make having a reliability monitor discretionary and allow ERCOT to assume the responsibilities (50602). (See “PUC to Consider Reliability Monitor Rule Change,” Texas Reliability Entity Briefs: Sept. 3, 2020.)
“My main concern I have is making the reliability monitor discretionary,” she said. “It doesn’t seem to be an option to me. … If you want to have flexibility in the rule, I understand that, but it’s something I could not get over.”
Chair DeAnn Walker did not hold back as she shared her thoughts on Texas RE serving another four-year term as reliability monitor. She suggested using their contract’s severance clause to give 30 days’ notice of its termination.
“I don’t think we have the authority … to make Texas RE our reliability monitor,” Walker said.
Citing a section in the state’s Public Utility Regulatory Act (PURA), she read aloud from the statute:
“‘The commission shall adopt and enforce rules relating to the reliability of the regional electrical network … or may delegate to an independent organization responsibilities for establishing or enforcing such rules. …
“‘The commission has complete authority to oversee and investigate the organization’s finances, budget and operations as necessary to ensure the organization’s accountability and to ensure that the organization adequately performs the organization’s functions and duties. …
“‘The organization shall fully cooperate with the commission in the commission’s oversight and investigatory functions.’”
PUC Chair DeAnn Walker discusses the Texas RE reliability monitor contract. | Texas PUC
Walker said the statute “clearly says” the commission “may delegate” the reliability monitor’s function to an “independent organization.” That “independent organization” would be ERCOT, not Texas RE, she said.
The PURA repeatedly refers to ERCOT as “the independent organization,” never “ERCOT,” PUC spokesman Andrew Barlow noted.
“What has become clear to me today is that if we delegate the contract, it has to be to an independent organization, and we only have one of those. And that’s ERCOT,” Walker said. “As to us having ‘complete authority to oversee and investigate’ the [reliability monitor’s] finances … we have absolutely none over Texas RE. … I don’t think that contract is consistent with the statute.”
Texas RE holds a $5.3 million contract for the 2020-2023 term, an increase from the previous $4.3 million contract for 2016-2019. The increase did not sit well with Walker.
“To say it was a difficult process with Texas RE is an understatement,” she said of the PUC sending out bids for the new contract. “We raised concerns with [the increase]. We raised concerns because other entities had concerns with it. We were told that’s the price; that’s the actual costs.”
Walker said that in digging into the contract, the PUC discovered that Texas RE had included overhead costs that will increase by $80,000 over the contract’s term.
“The overhead includes part of the CEO’s salary, the board’s salaries, [and] the board’s and CEO’s travels to NERC meetings. … I don’t believe their travel to NERC meetings benefits the state under the reliability contract one bit,” she said.
Barlow said the commission is calling the contract’s value and efficacy into question because of the “return on investment” — Texas RE’s monitoring led to $1.7 million in penalties during its previous contract and almost $150,000 this year — and “somewhat duplicative” work. The Texas RE uses ERCOT data for analysis rather than generating its own, he said.
“The PUC has lawyers and engineers that are fully capable of doing the analysis [the Texas RE] currently handle[s],” Barlow said. “As the PUC continues its ongoing modernization efforts by assessing our own internal organization and scrutinizing major contracts, we’re working to ensure we’re the best stewards of taxpayer resources and protectors of consumer interests.”
“I could sit there all day long and complain that this money shouldn’t be spent this way. The answer I get is, ‘Thank you very much, you’re ex officio,’” said Walker, who, as the PUC’s chair, sits on Texas RE’s Board of Directors.
Texas RE CEO Lane Lanford, who is retiring at the end of the year, said he supports Walker’s “diligence in tracking Texas RE’s expenses along with those of all publicly funded organizations.”
“Ratepayers have a right to know how their money is being spent,” he said in a statement provided to ERO Insider. “As the PUCT considers a new vision for the Texas reliability monitor, Texas RE will continue to assist if needed to ensure the mutual goal of a highly reliable and secure bulk power system within the Texas Interconnection.”
Texas RE is funded through regional assessments, collected by NERC, on load-serving entities’ pro-rate share of net-energy-for-load usage within its regional footprint. Lanford said its reliability monitor finances are “firmly separated” from its NERC activities as the ERO’s delegated regional entity, which is its primary role. The reliability monitoring function is funded through ERCOT’s system administration fee, as stipulated by the PUC’s rules.
“We have a contract I was not comfortable with, that there is not enough transparency to ratepayers and what they were having to pay, and whether we were getting the benefit and whether we were getting the information we needed to maintain that contract,” Walker said.
She expressed further frustration with a Texas RE cash account that she said holds about $250,000 in unspent funds encumbered by the organization’s nonprofit status. She told Botkin and Commissioner Arthur D’Andrea that she had asked whether Texas RE could use the funds to offset the reliability contract, but no action was taken on it.
The PUC may be limited in its options for finding an alternative to Texas RE as the reliability monitor. Commission staff, ERCOT and Potomac Economics, which serves as the grid operator’s Independent Market Monitor, were all mentioned as possible replacements.
“I think we should, and could, look at ERCOT,” Walker said, noting that the grid operator served as the reliability monitor before Texas RE was created in 2010 and was included in the PURA as being able to monitor reliability until a 2015 revision.
Funding issues make it unlikely the PUC would bring the monitoring contract in-house. Texas RE currently dedicates four employees of its approximately 64 staffers to the reliability monitoring function.
“To hire the four here, we would need the money,” Walker said. “We currently don’t have the funding from the legislature to perform the functions that we have within PURA. We scrape by doing the best that we can. For $5.3 million, we could handle a ton of staff to get this done here.”
As for Potomac, Walker said that “in all honesty, we’ve had our issues with Potomac in the past.”
Long-time IMM Director Beth Garza stepped down from her position in December during ongoing contract negotiations with the PUC, citing the need for the commission to have the director it wants. Garza has been replaced by former ERCOT staff Carrie Bivens. (See Bivens Steps in as New Director of ERCOT Monitor.)
“I have come to the conclusion the [PURA] didn’t require us to have a reliability monitor, but we, through our own rule, created that requirement,” Walker said. “I think the rule does need to change, but it needs to change in a different way than what [has been proposed]. We’ll probably have to take comment to get there.”
In the meantime, the thought process will continue. The PUC next meets in open session Oct. 12.
D’Andrea said he supports giving 30 days’ notice to Texas RE, saying “it’s a really bad idea to have a rule where, when you read it, it pretty much creates a no-bid contract.”
“There’s only one entity out there that can win this [request for proposals], and we all know who it is,” he said. “It’s an entity over which we have no control.”
Botkin asked for more time to consider the issues.
“I’m concerned about canceling with no replacement. I’m fully aware there are not a lot of options out there,” she said.
Walker also asked for more time to study the contract.
“We have to be good stewards of the ratepayers’ money,” she said.
Long-term resource adequacy in the Northeast could benefit from offshore wind projects, carbon pricing, nuclear power preservation, customer participation and a nudge toward investment from regulators.
That’s according to participants of a virtual panel as part of Greentech Media’s annual Power and Renewables Summit on Tuesday.
Jeffrey Stokes, senior director of power generation for Public Service Enterprise Group, said there’s an “interim” period of about 30 years in between now and a future in which there’s a total dependence on reliable renewable generation. He said for the interim period, nuclear generation remains vital.
Stokes said PJM should introduce carbon pricing or another way to value renewable and zero-carbon resources. He said more should be done to slow the rate of shutdown notices from nuclear plants in the Northeast and Midwest.
Unmentioned during the panel were the zero-emission credits that PSEG’s nuclear plants in New Jersey receive.
New Jersey Board of Public Utilities General Counsel Abe Silverman predicted widespread electrification will drive the need for a substantial amount of new renewable generation capacity. “We’re talking about serious load growth for the first time in two decades,” he said.
Silverman said offshore wind generation projects can bring a huge amount of capacity from the East Coast to western destinations. “These are very large projects: 800 [to] 1,000 MW.”
| GreenTech Media
Moderator Matt DaPrato, Wood Mackenzie Power & Renewables’ head of research strategy, asked how much offshore wind in the Northeast would be hampered by grid operators’ lengthy interconnection queues and transmission routes that contain “old grid.”
The panelists said offshore projects will inevitability bear transmission upgrade costs.
“Those are the give-and-takes that you have to do to move such a large amount of power,” Stokes said.
“It’s absolutely something we see as a real barrier … in New Jersey,” Silverman added. He said that at least some offshore wind projects could be situated on old nuclear or coal plant sites readymade with existing infrastructure, such as Exelon’s former Oyster Creek Generating Station in New Jersey.
Nevertheless, Silverman said “a lot of projects will need to cross the beach,” which will make for “a very delicate” permitting process across beachfront properties.
He said he was jealous of New York’s two-in-one grid operator and resource adequacy manager governed by a single set of state regulations. He said resource adequacy coordination, generation planning and incenting carbon-cutting aren’t so simple in states that belong to RTOs, like New Jersey.
EDP Renewables Associate Director of Origination Kelly Snyder said she credits PJM’s commercial and industrial customers for pressing for new renewable generation.
Silverman said RTOs and ISOs generally don’t have the “appropriate market structure” to attract private investors to build new technologies or allow customers flexibility.”
“Demand was supposed to be dynamic. … State and federal markets have done a very poor job of including customers in the markets,” Silverman said.
He also said state regulators should consider introducing small incentives for renewable and battery storage projects.
“Batteries are a wonderful, clean way to backfill some reliability needs in some of these communities,” he said.
NYISO and PJM officials discussed potential directions for their capacity markets and ways renewable energy producers could benefit from new market structures during a quick panel discussion during Greentech Media’s annual Power and Renewables Summit on Tuesday.
The panel featured questions about projected capacity market updates and their impact on prices, technologies and risk.
Logan said there will be “casualties” as a result of the orders, pointing out the burgeoning offshore wind sector in both grid operators’ markets. He also said they have sent state policymakers questioning their roles in creating their own energy mixes through legislation. He asked how NYISO and PJM have been working with states to determine what is appropriate bidding behavior by subsidized generators.
Emilie Nelson, executive vice president of NYISO, said the ISO experiences less complications when looking at policies because it only has to deal with one state government, one governor and one legislature. She said one of the benefits of a single-state grid operator is “clarity” in the environmental goals.
Anthony Logan, senior analyst with Wood Mackenzie (top left), speaks with NYISO’s Emilie Nelson and PJM’s Stu Bresler during GTM’s Power and Renewables Summit on Sept. 29. | GreenTech Media
Nelson pointed to the Climate Leadership and Community Protection Act (CLCPA) signed by New York Gov. Andrew Cuomo in July 2019 that set ambitious clean energy goals: 100% zero-emission electricity by 2040 and an 85% cut in emissions by 2050 from 1990. It also requires 70% of renewable energy production by 2030. (See ‘Astonishing’ Buildout Needed for Clean NY Grid.)
“Having the clarity on the direction that New York is trying to go allows us to contemplate some design approaches and different ideas to move ahead and explore things not quite as mainstream to see if they would work for our state,” Nelson said.
Stu Bresler, senior vice president of market services for PJM, said the RTO differs from NYISO in that it must balance the interests of 14 jurisdictions, including D.C., instead of just one state. He said the diversity of opinions and policy direction among the states in the PJM region is a constant challenge.
But Bresler also said having each jurisdiction’s unique perspective is a valuable tool, giving PJM better insight into potential solutions to problems. The Organization of PJM States Inc. allows for an exchange of ideas as to how the markets should evolve and how operations can be done more effectively.
“That diversity of thought provides for a much richer discussion in our region and has really helped us and assisted us in evolving our operations planning and markets over the years that has been beneficial for ratepayers and consumers,” Bresler said.
Looking for Solutions
Logan said NYISO has taken a “damn the torpedoes” leadership style when it comes to decarbonization. He asked where Nelson sees the ISO’s resource mix heading under the new BSM regulations.
Nelson said NYISO is going see a rapid transformation as more solar, offshore wind and storage come online. The ISO is considering how markets need to change to accommodate the changes. She noted its Grid in Transition initiative, which focuses in part on ensuring that ancillary service products are aligned with reliability needs, particularly around New York City. (See NYISO Moves Forward on EAS Projects.)
“It’s a multifaceted strategy across our market platforms because we are expecting so much change on the system,” Nelson said.
Turning to Bresler, Logan said it appeared that PJM has taken a “wait it out” approach toward the MOPR, as some of its states debate using a fixed resource requirement (FRR). He asked how carbon pricing fits into the RTO’s markets. (See Commenters Weigh in on PJM MOPR Compliance Filing.)
Bresler said it’s PJM’s hope that states would not elect the FRR option and instead see how things “play out” in the upcoming capacity auctions. He said the “prevailing wisdom” is the MOPR won’t have a huge impact on the first few capacity auctions because of exemptions granted by FERC to existing renewable resources.
In the long term, Bresler said, PJM has questions about the sustainability and durability of the “broad MOPR rule” and wants the states to work with the RTO to achieve environmental goals by leveraging the competitive nature of the markets. (See NJ Regulators Weighing Input on Capacity Market Exit.) He said a carbon price is a potential solution to reach reduction goals, among other concepts.
“Perhaps there’s a way to incorporate other goals as well but maintain as much as we can this competitive approach across a large region, which has shown to be tremendously beneficial,” Bresler said.
NextEra Energy Transmission (NEET) announced Tuesday that it will pay $660 million to acquire independent transmission company GridLiance, which owns 700 miles of high-voltage lines in Illinois, Kansas, Kentucky, Missouri, Nevada and Oklahoma.
The deal, which includes the assumption of debt, will be financed in part by parent NextEra Energy’s $2 billion sale of equity to BofA Securities and Barclays, announced last week.
Launched in 2014, GridLiance markets its expertise in planning, engineering, construction and operations to small transmission owners, including electric cooperatives and public power. Backed by Blackstone Energy Partners, an affiliate of The Blackstone Group, it also offers its “partners” a source of capital investment for transmission projects.
In addition to the transmission it owns, Gridliance also has long-term partnership agreements in Missouri, Oklahoma, Nevada, Texas and Kansas.
NextEra said the deal will require approval from FERC and utility commissions in Kansas, Missouri and Oklahoma. It is expected to close in 2021.
“GridLiance partners with electric cooperatives and public power utilities to enhance transmission system reliability and is well positioned to benefit from the substantial expected renewables growth over the coming years,” NextEra CEO Jim Robo said in a statement. “This acquisition furthers our goal of creating America’s leading competitive transmission company and is consistent with our strategy of adding high-quality regulated assets to our portfolio.”
“We are very excited to be joining NextEra Energy Transmission at a pivotal time in the company’s development,” GridLiance CEO Calvin Crowder said. “Our unique capabilities, proven track record and tremendous growth prospects, coupled with NextEra’s experience as a leading transmission owner, make this a great fit for both companies. We are also grateful for the support of Blackstone in founding GridLiance and for working closely with management over several years to build the company.”
Fighting ROFR
NEET currently has operating assets in California, New Hampshire and Texas, including Lone Star Transmission in Central Texas (330 miles of double-circuit 345-kV line and six substations).
One of NEET’s affiliates was awarded the rights to the Empire State Line in Western New York (20 miles of 345-kV line and two substations), which will increase renewable energy flows from the Niagara hydroelectric facility and imports from Ontario by 3,700 MW. Another affiliate is building the East-West Tie in Ontario (280 miles of double-circuit 230-kV line), which it says is the first competitive transmission project awarded to a nonincumbent in the province.
The Wall Street Journalreported on Tuesday that Duke Energy recently rebuffed a takeover attempt by NextEra. NextEra is still interested in Duke, the Journal said, noting that such a deal would be the largest utility acquisition ever. NextEra is the largest public utility in the U.S. with a market capitalization of $139 billion; Duke has a market value of about $61 billion.
NextEra shares closed Tuesday at $283.12/share, down $1.02 (0.36%). Blackstone shares rose by 5 cents to $52.71/share (0.095%).
GridLiance was the second asset sale by Blackstone Energy this month. On Sept. 24, it announced it would sell its 42% stake in Cheniere Energy Partners to Brookfield Infrastructure Partners and funds managed by Blackstone Infrastructure Partners for $7 billion. In 2012, Blackstone Energy and its affiliates invested $1.5 billion in Cheniere to build the first two liquefaction trains at the Sabine Pass LNG facility in Louisiana, the first LNG export facility in the continental U.S.
NERC on Monday completed the second of two compliance filings directed by FERC earlier this year, detailing changes to its Rules of Procedure (ROP) intended to “reflect current business practices and provide further transparency to industry stakeholders” (RR19-7).
FERC ordered the ROP changes in January in response to NERC’s five-year performance assessment, expressing dissatisfaction with the transparency of the Electricity Information Sharing and Analysis Center (E-ISAC) considering it accounts for 28% of the ERO’s total 2020 budget. The commission requested that NERC clarify the E-ISAC’s relationship with the Electricity Subsector Coordinating Council (ESCC), correct inconsistencies in terminology used in the ROP and update other operational practices related to the ERO’s infrastructure security program. (See NERC Wins Another 5 Years as ERO.)
The compliance filing was originally due July 21, but NERC requested an extension in order to allow for the full 45-day stakeholder comment period, which FERC approved in March, followed by another delay because of the COVID-19 pandemic. (See NERC Board of Trustees/MRC Briefs: Aug. 20, 2020.)
The commission had ordered an additional compliance filing, submitted in June, discussing NERC’s oversight of its regional entities and the development process for reliability guidelines, as well as the role of the E-ISAC. (See NERC Clarifies Audits, E-ISAC in Filing.)
Registration and Certification Revisions
NERC’s planned changes include:
revisions to the Registration and Certification Program in Section 500 (Organization registration and certification) and Appendices 2, 5A, 5B and 5C;
updates to the infrastructure security program in Section 1003, including the E-ISAC; and
modifications to the sanction guidelines in Appendix 4B.
The first set of changes, which primarily involve adding “more granularity” to registration-related provisions, is being published for the first time. These include sections involving joint registration organizations (JROs), to provide clarity to the requirements for JRO construction and operation; and coordinated functional registration (CFR) agreements, with greater specificity around the information required to make a CFR acceptable to NERC and the roles and responsibilities of parties to the agreement.
In addition, NERC proposes to “add more specificity to the minimum criteria for certification” by detailing that entities’ “tools, personnel, facilities and [processes] used to perform … tasks required by the applicable reliability standards will be evaluated.”
The organization also plans to remove a requirement in Appendix 5A that the Compliance and Certification Committee approve any revisions to registration and certification procedures before they are submitted to the board, while adding a new section to the same appendix specifying how entities maintain their certifications. Redundant language in Appendix 5B will be removed as well, and Appendix 5C will be changed to create better alignment with updated sections of the ROP.
E-ISAC, Sanctions, APB Clarified
Revisions to Section 1003 include the insertion of a paragraph describing the role of the E-ISAC and its place alongside the Department of Energy and ESCC in the U.S. national security framework and language emphasizing that NERC considers security an equal priority to reliability and resilience. References to the critical spare transformer program, the National Infrastructure Protection Plan and other organizations were deleted, as NERC is not involved in these activities anymore.
Changes to NERC’s sanction guidelines aim to emphasize the importance of fairness when determining penalty amounts, with reference to factors such as risk and severity level, as well as the role that nonmonetary sanctions may play in determining the final penalty amount. Additional language was inserted at FERC’s request requiring NERC and the REs to ensure that the size of the offender and its ability to pay are taken into account when setting penalties to ensure that violators do not see sanctions as “an economic choice or cost of doing business.”
In its January order, FERC also directed NERC to “clarify its processes regarding the development and issuance of All Points Bulletins,” part of the E-ISAC’s Critical Broadcast Program (CBP). NERC addressed this request in the last section of its Monday filing, describing the threshold for activating the CBP, procedures for approving activation, the target audience of the program, and methods and timing of communicating critical security information. In addition, the organization discussed the CBP’s relation with other information-sharing mechanisms, such as the NERC Alert process.
FERC on Monday placed an Iowa wind farm’s method for calculating reactive power rates into question, although it declined to initiate a blanket probe into similar NextEra Energy rate filings.
The commission said NextEra Energy Resources’ Crystal Lake II wind farm in north-central Iowa may be improperly including operations and maintenance costs and transmission-related expenses in its reactive power rate schedule. It set the facility’s rates for hearing and settlement proceedings (ER20-2543).
Crystal Lake II said it now requires slightly more than $1 million per year in reactive power revenue. The facility is designed to provide reactive power, and its turbines have been churning since 2012.
Nearby Interstate Power and Light (IPL), an Alliant subsidiary, raised objections to Crystal Lake II’s rate schedule, arguing that it is unacceptable for asynchronous generators to use the reactive power rate methodology FERC established in 1999 for synchronous generators. IPL said the filing was “one of a series of filings by subsidiaries of NextEra to establish charges for reactive service.” The utility asked the commission to consolidate and investigate all similar filings by NextEra subsidiaries.
FERC said a preliminary analysis of Crystal Lake II’s proposed rates showed they could be unjust and unreasonable. The commission said a consolidation of other NextEra filings was beyond the scope of the proceeding but said that IPL “may raise its concerns regarding how the proposed revenue requirement has been calculated in the hearing and settlement judge procedures.”
Crystal Lake wind farm | NextEra Energy
For its reactive power charges, Crystal Lake II included the costs of low-voltage collection system feeders and low-voltage transformers, which aggregate the output of individual wind turbines. The collection system costs include some substation costs.
IPL argued that collection system costs aren’t necessary for synchronous generators’ production of reactive power and therefore aren’t contemplated by FERC’s 1999 methodology. The utility also said the equipment costs can’t be completely dedicated to reactive power production.
“The allocation of accessory electric equipment costs to the production of reactive power has not been shown to be just and reasonable and appears excessive,” IPL said.
The company also charged that Crystal Lake II was expecting to be compensated for transmission-related system losses, though FERC’s methodology only allows traditional generation’s heating losses to be recovered. “Wind-powered generators do not experience significant heat-related losses in the production of reactive power,” it said.
The utility said FERC should “consider balancing the requirement to provide reactive power with the need for reactive power in a particular locale or region.” It said that FERC “should not simply assume that, because a generator is able and willing to provide reactive power, that this reactive power is needed for reliable and efficient operation of the electric system.”
NERC’s Standards Committee is accepting nominations through Oct. 15 to replace nine members who will depart at the end of the year, as well as to fill three spots that are currently vacant.
The Standards Committee comprises the chair and vice chair, along with two representatives from each of 10 industry segments, with memberships staggered so that half of the representatives are replaced each year. This year’s departing members are:
Segment 1, transmission owners: Sean Bodkin, Dominion Energy;
Segment 2, RTOs and ISOs: Charles Yeung, SPP;
Segment 3, load-serving entities: Linn Oelker, LG&E and KU;
Segment 4, transmission-dependent utilities: Barry Lawson, National Rural Electric Cooperative Association;
Segment 5, electric generators: William Winters, Consolidated Edison;
Segment 7, large electricity end users: Venona Greaff, Occidental Chemical;
Segment 8, small electricity users: David Kiguel, independent; and
Segment 10, regional reliability organizations and regional entities: Steven Rueckert, WECC.
In addition, the committee is looking to fill vacancies for the term that ends December 2021 in segments 4 and 7, so nominations will be accepted for these spots as well. In the election, the candidates in those segments with the most votes will be given their choice of terms, with the other term going to the runners-up.
Nominations are also being accepted for Segment 9 (Federal, state and provincial regulatory or other government entities). Currently the segment is only represented by Ajinkya Rohankar of Public Service Commission of Wisconsin, whose term ends in December 2021.
The committee is required to have at least two members from Canada — currently Kiguel and Robert Blohm of Keen Resources, who will leave at the end of 2021. If the regular election does not result in the seating of another Canadian representative, then the Canadian candidate who receives the most votes in their segment will be named as an additional member.
Nominees may be submitted by anyone, with the election to be conducted “shortly after the nomination period is closed.” Industry segments that intend to use a special procedure to elect their representatives must inform the committee by Oct. 15.
Special Election to Fill RSTC Seat
The Reliability and Security Technical Committee is also holding a special election to fill a vacancy in Sector 8 (Large end-use electricity customers). The nominating period ran from Aug. 28 to Sept. 18, with Travis Fisher, president and CEO of the Electricity Consumers Resource Council (ELCON), and Thomas Siegrist, a consulting engineer with Stone Mattheis Xenopoulos & Brew, making the final ballot. Voting began on Sept. 21 and will end at midnight Oct. 5.
Like the Standards Committee’s, members on the RSTC serve staggered two-year terms. Occidental’s Greaff (2020-2022) and former ELCON CEO John P. Hughes (2020-2023) were elected to represent Sector 8 in January; NERC has not identified which is leaving. (See Nominations Close for At-Large RSTC Members.) The winner of the special election will serve out the departing member’s remaining term.
Stronger federal leadership and changes to wholesale electricity market rules are needed to supplement New England’s decarbonization efforts, Massachusetts Secretary of Energy and Environmental Affairs Kathleen Theoharides and Katie Dykes, commissioner of Connecticut’s Department of Energy and Environmental Protection, told Raab Associates’ New England Electricity Restructuring Roundtable.
Theoharides and Dykes were the keynote speakers at the virtual event Friday, which drew an audience of more than 450 people.
There has been “no hint of politics in the way we approach this work,” Theoharides said about Massachusetts, whose Republican Gov. Charlie Baker committed the state to a target of net-zero emissions by 2050.
Theoharides said one approach to meeting that goal is the Transportation and Climate Initiative (TCI), a collaboration of 12 Northeast and Mid-Atlantic states and D.C.
TCI would set a limit on carbon dioxide emissions from diesel and gasoline vehicles and allow states to invest proceeds from the sale of carbon allowances to support the goals of the program, such as electric vehicle chargers and electric buses.
The initiative estimates a cap that cut emissions 25% from 2022 levels by 2032 would produce $10 billion in public health benefits (2017$) while covering almost three times the Regional Greenhouse Gas Initiative cap, which includes the New England states, New York and more recently New Jersey and Virginia. Transportation represents 43% of emissions in the TCI region, and total transportation-related carbon emissions are nearly twice as large California’s, Theoharides said.
Clockwise from top left: Katie Dykes, Connecticut DEEP; Jonathan Raab, Raab Associates; and Kathleen Theoharides, Massachusetts EEA. | Raab Associates
TCI expects to finalize a memorandum of understanding setting its targets this fall, when each jurisdiction will decide whether to sign the MOU and participate.
“It is a capital investment program,” Theoharides said. “It is a point of regulation far upstream from the consumer at the wholesale or fuel-supplier level. Credits would be auctioned off in each state, and the proceeds would go back into the states, much as they do in RGGI, to invest in clean transportation solutions that give people the option to choose transportation that reduces air pollution and that provides mobility for more residents.”
Amid the COVID-19 pandemic, TCI has the potential to reduce the public health impact of environmental pollution significantly, Theoharides added.
“The pandemic has highlighted the connections between air pollution and respiratory diseases, and TCI is a way to ensure sustained investment in transportation that gives people better, more affordable choices for getting to work, school and health care services while cutting the pollution that makes people sick and makes them more vulnerable to disease,” Theoharides said.
Connecticut has pledged to cut carbon emissions by 80% from 2001 levels by 2050 and 100% in the electricity sector by 2040. Dykes said it is “long past the moment for significant changes in the wholesale electricity markets to ensure that Connecticut can either secure the resources that we need to meet our clean energy goals in-market, or that we can get credit for what we have had to procure outside of the market in order to meet our goals.”
Dykes said a “unified approach” is needed to meet the decarbonization mandates.
“We are not even in an acceptable place in terms of having a proactive transmission planning process that ensures adequate competition in our RTO,” Dykes said about ISO-NE. “For the transmission investments, when you look at the dollars spent per mile deployed, New England is at the bottom of the heap in terms of providing … value for our ratepayers. Transmission service costs are more than twice the average of other RTOs and ISOs.”
Dykes thinks that improving the transparency and accountability of ISO-NE and institutions like the New England Power Pool that are “core to the design and implementation of our wholesale markets” is a “necessary and essential step” to achieve affordable decarbonization that uses competition and minimizes risk to ratepayers. She said the current structure reflects that states do not have adequate input and accountability in the design and structure of the RTO’s governance.
Moderator Jonathan Raab said both Massachusetts and Connecticut have plans and policies in place to meet “really bold decarbonization mandates.” He then asked Theoharides and Dykes if New England states can be “fully decarbonized without strong complementary federal action on numerous fronts” and what the federal government could or should do to facilitate the region’s decarbonization efforts.
Dykes said the impact of climate change on the economy and public health is “accelerating faster than we had anticipated.” She said there is a severe disconnect between states and the federal government, which, Dykes said, is “walking away or even making our climate progress more difficult.”
“We have companies in a private market that can accelerate and deploy climate solutions so quickly and cost-effectively,” Dykes said. “I think the tragedy of all this disconnect at the federal level is that it’s preventing the incredible strengths and advantages of our country from being applied at the scale that we need to solve this climate crisis.”
Theoharides added: “It matters that we have a target as a nation we’re shooting for; it’s not just a handful of states which have mandatory emissions targets; we need a federal target, and we need every state to be pulling its weight to get us there. That leadership needs to come from the top.”
Decarbonization Takes the Whole Village
The conference’s second session featured a four-person panel with representation from local and state governments plus a global nonprofit and think tank. The presentations touched on some of the same topics that Theoharides and Dykes broached earlier and delved into job creation and the social justice aspects of decarbonization.
Hal Harvey, CEO of Energy Innovation, said it is not true “that one has to sacrifice economic vitality in order to have a clean environment.” The financial upside of clean energy is good jobs, lower costs and less local pollution, he said. There were 3.3 million clean energy jobs in the U.S. at the start of 2020, representing more than 40% of the energy workforce, Harvey said.
“The fastest two growing careers in America are solar installer and wind installer,” Harvey said. “The opportunities do not require college degrees. … Roughly half of Americans do not have a college degree; we need an energy strategy that gives them great jobs.”
Hannah Pingree, director of policy innovation and future for Maine Gov. Janet Mills, said the first-term Democrat had made climate progress one of her top agenda items, especially in job creation.
“Maine is embarking right now on an offshore wind project, trying to launch the first floating turbine in the next couple of years, so obviously that’s one of the many exciting things we think could bring jobs and economic prosperity,” Pingree said.
Clockwise from top left: Eugenia Gibbons, Health Care Without Harm; Chris Cook, city of Boston; moderator Jonathan Raab; Hal Harvey, Energy Innovation; and Hannah Pingree, Maine Governor’s Office of Policy Innovation and the Future | Raab Associates
While climate change can drive job creation, Chris Cook, chief of environment, energy and open space for the city of Boston, said it also affects socially vulnerable populations. One of the city’s major initiatives this year is creating Community Choice Electricity, which was recently approved by the Massachusetts Department of Public Utilities. The program will allow the city to buy electricity for residents and businesses through its combined buying power to provide affordable and renewable electricity to those who participate in the program.
“If we provide a clean economy [and] a decarbonization pathway that doesn’t expand equity opportunities for our most socially vulnerable residents, then we will have failed,” Cook said. “It’s not about what we do. It’s about who we do it for. They are our neighbors; they are our friends. They are the people that we are charged with at the city level to take care of, and they need to be actively part of the solution.”
Eugenia Gibbons, Boston director of climate policy for Health Care Without Harm, a global nonprofit that works to reduce the health care sector’s environmental footprint, said climate solutions like decarbonization must benefit historically marginalized communities.
“Essentially we are coming from a place of understanding that climate justice will only be achieved if policies that are enacted bring about concrete improvements in the health and lives of communities that continue to bear the burden of environmental and climate pollution,” Gibbons said. “Equity absolutely has to be a factor in designing, implementing and evaluating policy and program solutions. Otherwise, the disparity will just be perpetuated and exacerbated.”
In the absence of federal leadership, “we absolutely have to demonstrate at the state and local level what is possible and what we are capable of achieving [and] ensure that we are not leaving anybody behind when we move forward with this pathway to decarbonization,” Gibbons added.
When Raab asked the panel for closing thoughts, Harvey said 2020 is an inflection point.
“If we use this decade well, we can land at a reasonable climate future, but this is the decade that matters. This is where we have to stop all new fossil installations, period, and much more rapidly change the direction that we are on,” he said. “I can say now it’s cheaper to save the Earth than to ruin it, because it is. We better get busy, because if we don’t do it this decade, it isn’t going to happen.”
