Page 1038 – RTO Insider

October 4, 2020March 11, 2025

RI Updates 2030 Load and Renewables Forecast

Brattle’s analysis also shows Rhode Island demand outlook similar to New England, with moderate load growth through 2030 and significant growth after because of heating and transportation electrification. | The Brattle Group

Rhode Island will need to add about 440 GWh of renewable energy annually to meet the state’s goal of 100% renewable energy by 2030, The Brattle Group said at the second in a series of three public workshops hosted by the state’s Office of Energy Resources (OER) on Sept. 29.

Equally daunting, the state will need to continue adding an average of 400 GWh a year to maintain the 100% target through 2050 as its load potentially doubles from the electrification of heating and transportation, Brattle said.

The consultants are helping state officials develop a plan by year-end for the clean energy target mandated in a January executive order by Gov. Gina Raimondo. (See RI Seeks to Lead with 100% Renewable Goal.)

Electrification Impact

At the first public meeting in July, the analysts said the state would need to add 360 GWh annually through 2030 to meet the target. The current estimate’s base case projects net load of 7,700 GWh in 2030, including electrification of 5% of light-duty vehicles (LDVs) and 5% of heating, based on an ISO-NE forecast, said Michael Hagerty, Brattle senior associate. The baseline also incorporates National Grid’s forecast for energy efficiency.

Michael Hagerty, Brattle | The Brattle Group

The baseline is bracketed by a low-demand scenario of 7,000 GWh and a high-demand scenario of 8,300 MWh, which assumes 15% LDV electrification and 10% heating electrification.

“In our low-demand scenario, we’re assuming that level of electrification does not occur,” Hagerty said.

The study says the state needs to add 4,400 GWh of renewable energy by 2030 to meet 100%. Last year, Rhode Island’s renewable electricity production of 930 GWh represented 13% of the state’s load. The state has 410 MW of renewables, including 230 MW of solar, including net metered resources, and 180 MW of contracted resources.

Current transmission queues list more than 12 GW of offshore wind, and 2.2 GW of onshore wind from Maine and 4 GW from New York. But the ISO-NE queue currently has no Rhode Island-based onshore wind because of wind quality and land availability, Brattle reported.

The costs of transmission and distribution system upgrades needed to accommodate the new renewables is “a source of significant uncertainty,” Hagerty said. “We’ve been reviewing these projections with renewable developers to make sure that they find them to be reasonable, and we’ve generally heard that they are.”

The limited availability of low-cost interconnection points for 1- to 10-MW scale distributed solar has resulted in increased interconnection costs, which might offset some of the cost declines seen in the industry, Hagerty said. An increase of $200 to $300/kW in system upgrades could increase distributed solar costs by $10 to $24/MWh, he added.

Wholesale Modeling

Brattle principal Dean Murphy outlined how the consultants are modeling the New England wholesale electricity market.

Dean Murphy, Brattle | The Brattle Group

“It’s important to recognize that the fundamental nature of this market is going to change substantially, even by 2030, and perhaps especially thereafter due to the significant addition of renewable energy generators across the system,” Murphy said. At 6% of regional load, “Rhode Island … is a very small component of New England overall, so it will be driven more by changes in other states that are also decarbonizing their electricity resources, albeit less quickly than Rhode Island.”

Because the output of renewables is highly correlated and difficult to store, once a lot of solar has been added to the system, incremental additions will have diminishing value. To capture how that dynamic will work out over time, Brattle uses an in-house model called GridSim.

Jurgen Weiss, Brattle | The Brattle Group

The study projects that gas-fired capacity will be kept around until 2040 but will be used much less than now as other renewable resources come online. In response to a question by an attendee, Brattle principal Jürgen Weiss acknowledged that gas generators will become increasingly dependent on capacity revenues to survive as their energy market revenue drops with lower utilization. He said the model accounts for the shift, ensuring all resources cover their fixed and variable costs.

“[It is] important to note that something similar is already the case since there are resources that don’t generate much electricity but stay in the market to provide reliability,” such as older dual-fuel units, he said. “If they have been built, you don’t necessarily need higher capacity prices since the capital cost is sunk and you just need to cover their going-forward costs,” Weiss said.

“Solar may be an excellent complement to wind, in part because it does generate more in the summer, when there is a summer peak for load in the daytime,” Murphy said. “A blend of these two kinds of resources is likely to be better than either one in isolation.”

Natural gas-fired capacity will be maintained into 2040 but will be used a lot less as other renewable resources come online. | The Brattle Group

Environmental Justice

OER Commissioner Nicholas Ucci told the workshop that his office is including social and environmental justice considerations in its work on clean energy.

“Folks should be comforted by the fact that we are accounting for many if not most of those categories in the 4600 framework, either analytically, qualitatively or by other means,” Ucci said, referring to the Public Utilities Commission’s Docket No. 4600, an investigation into the changing electric distribution system.

“One piece of good news is that, unlike in the past when dirty stuff was located in places that hurt particularly vulnerable populations, here we’re talking about locating renewable energy resources — and their negative impact on surrounding communities is considerably less than coal-fired power plants,” Weiss said.

How those vulnerable populations are protected from potential rate increases is a separate and important topic, Weiss said. “But we’re cleaning up Rhode Island’s electricity system, so the trajectory is to remove harm that might have been inflicted in the past. One can also ask whether the policies that are implemented to achieve the 100% renewable electricity target could be used to help those communities that are disadvantaged.”

For environmental justice, “the first step is to look inward,” Ucci said. “A lot of our state agencies are starting to connect with local grassroots organizations to better understand their perspectives [and] working to educate and train ourselves.”

October 4, 2020

FERC Accepts WECC Violation Settlement

FERC on Wednesday approved a settlement between WECC and an unnamed entity in the Western Interconnection for violations of NERC’s Critical Infrastructure Protection (CIP) reliability standards (NP20-21). The settlement does not involve a monetary penalty. NERC notified the commission of the agreement Aug. 30 in a Notice of Penalty (NOP), which FERC indicated in a notice that it would not review.

The NOP was submitted prior to NERC and FERC’s decision last month to end public disclosures of CIP violations and therefore follows the previous practice of redacting from public filings data considered to be critical energy/electric infrastructure information (CEII). (See FERC, NERC to End CIP Violation Disclosures.) Going forward, the organizations will treat CIP noncompliance information filed to the commission as CEII in its entirety (AD19-18); it is unclear whether NERC will continue to provide public information about CIP violations in any form.

Security Gaps in Remote Access Measures

WECC’s settlement with the unnamed utility involves two infringements of CIP-005-5 (Cybersecurity — Electronic security perimeter(s)) and one infringement of CIP-007-6 (Cybersecurity — Systems security management).

Both of the CIP-005-5 violations relate to requirement R2, mandating that entities “allowing interactive remote access to [high- and medium-impact bulk electric system] cyber systems” must implement two-factor authentication (2FA) and that intermediaries that ensure remote access programs do not come in direct contact with the BES cyber systems themselves. The entity made WECC aware of the violations via self-report in February and March 2017.

In the February incident, after multiple users reported lost or damaged security devices, the utility allowed those users to bypass its 2FA system before a planned replacement system had been activated. As a result, cyber assets covered by CIP-005-5 were accessible by passwords alone for some employees. In a few cases, even some users who had not reported issues were still not asked to verify their identities via 2FA. WECC determined the root case of the violation to be failure to assess the risks or consequences of bypassing 2FA and described the risk level as “serious and substantial.”

WECC Violation Settlement — The entrance to WECC headquarters in downtown Salt Lake City | © *ERO Insider*

Details on the March case are less clear because of redactions, but WECC indicated that the entity was not using an intermediate system to block access to applicable cyber assets, although in this case, 2FA was not breached. Staff were also aware of the potential vulnerability and implemented several alleviation measures, including active monitoring of failed login attempts and regular patching of computers used to access the affected systems. As a result, WECC assessed the risk level as moderate, identifying the root cause as failure to clearly understand the compliance requirements or validate them for completeness.

Mitigation measures in the first case include developing a new process for creating, issuing, tracking and revoking hardware tokens, and training staff in their use; the entity also removed any previously granted password-only access. For the second instance, the entity changed its electronic access policies to ensure all interactive remote access goes through the same intermediary and revised its system architecture to ensure consistent policies are followed in future hardware deployment. WECC certified completion of the plans in September and October 2019, respectively.

Patch System Review Finds Holes

The entity’s violation of CIP-007-6 arose from requirement R2 of the standard; specifically, the utility reported in October 2017 that it had discovered “significant gaps in evidence to confirm compliance” with provisions related to high- and medium-impact cyber assets. The identified gaps include:

an inaccurate and incomplete control center patch source list;
patch evaluations not completed every 35 days;
patch installation or mitigation plans not completed within 35 days of patch evaluations; and
procedures ensuring that mitigation plans were completed on schedule not established and administered.

According to the entity’s records, the issues dated back at least to July 1, 2016, when the standard became enforceable. WECC attributed the violation to the entity “underestimating the resources and effort required to establish and operate a compliant security patch program” under the new standard, and determined that the issues posed a serious and substantial risk to BES reliability.

To address the violation, the entity consolidated patch source lists and updated them to include all software and firmware that might be covered by the relevant standard, and implemented standardized manual patch processes for all applicable cyber assets, among other measures. WECC verified completion of the mitigation plan in January 2020.

To justify its argument that no monetary penalty was needed, WECC cited the fact that the entity was cooperative through the process, reported all violations in a timely manner and made no effort to conceal the violations. The regional entity also observed that there was no indication the infringements were intentional.

While WECC acknowledged previous compliance issues with both CIP-005-5 and CIP-007-6, it argued that they did not serve as a basis for aggravating the penalty. The earlier CIP-005-5 violation was of minimal risk and occurred in 2011, and therefore was “not indicative of broader compliance issues,” while the current CIP-007-6 infringement was related to a lack of resources rather than flawed implementation of the patch management program, as in the earlier violation.

October 1, 2020

Experts: Foresight Key to Insider Threat Defense

Experts at ReliabilityFirst’s Insider Threats Webinar on Wednesday warned that many common insider threat mitigation strategies can actually increase the risk of attacks and urged utilities to take a different approach to internal security.

“When we typically think about security controls, we’re talking about disabling somebody’s access or … doing something else punitive to them,” said Dan Costa, technical manager of enterprise threat and vulnerability at Carnegie Mellon Software Engineering Institute. “[But] the likelihood of that insider [causing] some harm against the organization might be best mitigated by … retraining, rebalancing somebody’s workload, [or] having coworker conflict training and mediation sessions available. … Organizations where employees are happy about working there … tend to experience less insider events than those that do.”

Insider threats — defined by Costa as the “potential misuse of authorized access to an organization’s critical assets … in a way that has the likelihood to have some negative outcome” for the organization — are a unique hazard for any company, in that by definition, they originate from those in whom the entity has already placed a great deal of trust. As a result, these incidents are potentially more damaging than external attacks and more likely to be overlooked by management.

They are also frequently overlooked by outsiders: As Costa noted, many organizations prefer to handle insider threat events internally, which means that without legally mandated reporting, the number of attacks reported in publicly available statistics may be deceptively low. Carnegie Mellon’s own statistics, which are based on court records, show a far higher incidence of insider threat events since 1996 in the finance and insurance industry, which has relatively strong fraud prevention laws, than in the utility sector.

Insider Threat Defense — Insider threat incidents by industry or sector since 1996 | *Carnegie Mellon University*

Even if Carnegie Mellon’s record of 29 insider incidents in the utility sector over 24 years is taken at face value, they must still be viewed seriously, given the fact that more than a third of these attacks led to financial impacts in the six figures.

“Insiders … know what is valuable to your organization; they know what is mission-essential to your organization,” Costa said. “They know how it’s protected; they know how to bypass or circumvent those protections; and insiders that are sufficiently motivated to intentionally cause harm to the organization are uniquely positioned to do so.”

Looking for Warning Signs

The vulnerability doesn’t end with current employees, as illustrated in the attack suffered by instrumentation developer Omega Engineering at the hands of former network administrator Timothy Lloyd. Steven McElwee, chief information security officer at PJM, described how Lloyd struck back at his former employer in 1996 when he was demoted, then fired.

“Because of his privileged access as a network engineer, and because of some temper issues, he didn’t handle it very well,” McElwee said. “So he wrote six lines of code … very simple, very elegant, and it was a time bomb. When he was fired, and he left the organization, it successfully deleted all of the source code for Omega engineering. It was a devastating blow to the company, and I don’t think they ever really recovered from it.”

Financial impact of insider threat incidents in the utility sector since 1996 | *Carnegie Mellon University*

Omega later reported spending nearly $2 million repairing the damage from Lloyd’s attack and losing almost $10 million in revenue, resulting in 80 layoffs. Quoting a line from the film “Batman Begins,” (“It’s not who I am underneath, but what I do that defines me.”) McElwee listed several behaviors that should have tipped managers off that Lloyd was likely to cause issues and led them to take additional precautions.

“First of all, he was demoted. That was a sign. … He was on someone’s radar as a problem employee,” McElwee said. “Second, he was considered to be a hothead. So, they might have expected a strong reaction when they were firing him and been able to take some additional precautions. Third, someone knew he was going to be fired. All of these factors should have raised lots of red flags.”

Support, not Punishment

Given cautionary tales like Omega’s, organizations might feel the best defense is to cut off insider attacks before they begin by locking down potentially difficult employees’ access to critical assets as soon as problems emerge, or by transferring, demoting or even terminating these workers. But participants in the webinar warned that these tactics are likely to backfire, creating the very situation they are intended to prevent.

Presenting Carnegie Mellon’s models for the incitement of insider fraud and sabotage events — the two most prominent types of incidents in its research — Costa observed that the vast majority of insider attacks have multiple contributing factors.

In the case of fraud, an individual may begin with no malicious intent toward their employer but move over time toward a decision to steal from the workplace because of family issues, financial pressures, resentment toward the company and other issues. Sabotage may stem from feeling underappreciated and mistreated by coworkers and management.

Both situations can be aggravated by punitive measures such as reassignment, demotion or firing. An employee considering theft of company property may feel that such steps leave them with no legitimate option for solving their issues, while one thinking of sabotaging the workplace may feel insulted by attempts to remove their access and move forward with their plans.

“It’s this combination of concerning behavior and then maladaptive organizational responses, [and] these cycles that start to happen between more concerning behaviors exhibited and more maladaptive organizational responses,” Costa said. “There’s a tipping point where eventually the insider becomes motivated to cause harm to the organization.”

This does not mean that organizations should overlook warning signs for fear of pushing employees into a downward spiral, or that there are no situations where removing an insider’s access is appropriate. However, speakers emphasized that the most effective way to reduce the amount and impact of insider attacks is to understand the pressures that lead employees to cross the line and address them where possible.

“Everyone has vulnerabilities … and not all kinds of vulnerabilities are going to cause issues in their organization,” said Benjamin Gibson, a senior physical security analyst at the Electricity Information Sharing and Analysis Center. “It’s some of these confluences of factors … where you start raising the red flag. … Part of the program is to identify where the vulnerabilities are, know where the people might have vulnerabilities, and knowing can help mitigate [them].”

October 1, 2020

SPP Delays Staff’s Return to Offices by 3 Months

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.

October 1, 2020September 26, 2025

CAISO Floats EIM Base Schedule Rule Changes

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.

October 1, 2020

PUC Reconsidering Texas RE as Reliability Monitor

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.’”

Texas Reliability Entity — 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.

September 30, 2020

GTM Panelists Mull Northeast’s Resource Adequacy

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.”

Northeast Resource Adequacy — | *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.

September 30, 2020

NYISO, PJM Discuss Renewables in Capacity Markets

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.

Moderator Anthony Logan, senior analyst with Wood Mackenzie, said recent NYISO BSM Mitigation Ruling Sparks Glick Rebuke.)

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.

NYISO PJM renewables — 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.

September 29, 2020December 13, 2023

NextEra Buying GridLiance for $660M

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 B lackstone 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.

For Florida-based NextEra, the acquisition will give it a bigger foothold in the Midwest after failing in its 2016 bid for Texas’ Oncor. (See NextEra Said to be Eyeing Evergy as Acquisition Target.)

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.

Appeals Court Sets Dates in Texas ROFR Challenge.)

The Wall Street Journal reported 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.

September 29, 2020

NERC Files ROP Changes with FERC

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 information security program and sanction guidelines updates were submitted for industry comment in May. (See NERC Seeks Comments on Proposed ROP Changes.)

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.

NERC Rules of Procedure — E-ISAC headquarters in D.C. | © *ERO Insider*

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.