FERC on Thursday denied rehearing requests on two orders rejecting PJM’s efforts to prevent capacity market participants from attempting to arbitrage between the Base Residual Auction and Incremental Auctions.
PJM and several of its member utilities requested rehearing and clarification of the commission’s May 2018 and May 2014 orders that rejected the RTO’s proposed rule changes to prevent participants from obtaining capacity supply obligations in the BRA and buying out of them with lower-priced replacement capacity in subsequent IAs (ER18-988-001, EL14-48-001, ER14-1461-002).
The 2018 order rejected PJM’s proposal to create a sell-back offer floor at the relevant BRA clearing price and eliminate two IAs while increasing charges and penalties. (See FERC Closes Book on PJM’s ‘Paper Capacity’ Concerns.)
Net replacements to cleared capacity by resource | PJM
“As explained in the May 2018 order, and as reaffirmed here, PJM failed to justify the Incremental Auction modifications that have been proposed,” FERC said.
The commission said PJM’s evidence that resources, particularly demand resources, seek to buy out of their BRA commitments “may not necessarily demonstrate that resources are engaging in speculative behavior.” It noted that the commission approved changes in 2014 requiring DR providers to designate that their resources will be available in the delivery year.
It also noted that PJM’s Capacity Performance rules impose large penalties on resources that fail to perform during a performance assessment interval. “This creates a substantial downside risk for would-be speculators or any market participant … that fails to buy out its capacity obligation in the Incremental Auction.”
And it said PJM was attempting to address the cause of the price differentials between the BRA and IAs by revising its load forecasting methodology in 2015 to reduce over-procurements.
“We do not find it advisable to design a market on the assumption that over-procurement in capacity auctions will result in lower energy market prices,” the commission said. “Each market ought to be designed properly.”
The commission added that it encouraged PJM and its stakeholders “to continue to monitor the issues raised in this proceeding and to develop, if appropriate, solutions to address them.”
FERC accepted settlements Friday with Public Service Company of New Mexico (PNM) and two utilities owned by Berkshire Hathaway Energy — Nevada Power (NEVP) and Sierra Pacific Power Co. (SPPC) — for violations of NERC reliability standards. The settlements with NEVP and SPPC carried penalties of $231,000 and $153,000, respectively; a penalty of $70,000 was assessed for the PNM settlements.
NERC submitted the settlements to the commission on Feb. 27, filing a spreadsheet Notice of Penalty for PNM’s violations (NP20-8) and separate NOPs for NEVP (NP20-9) and SPPC (NP20-10). In a notice Friday, FERC said it would not review the settlements, leaving NERC’s penalties intact.
Rating Revisions
Although SPPC and NEVP both operate under the NV Energy brand, the utilities were cited separately by the Western Electricity Coordinating Council for violations of reliability standard FAC-009, covering the establishment of facility ratings, and VAR-002, relating to the maintenance of generator voltage or reactive power schedules.
NV Energy headquarters in Las Vegas, Nev.
The FAC-009 violations were assessed following self-reports submitted by both entities on Dec. 14, 2016, after a joint internal technical assessment revealed that several of their facility ratings did not include all applicable facilities. In addition, the ratings did not include all required elements. Further investigation found that the violation began on June 18, 2007, when the standard went into effect. In particular:
Eleven transmission lead lines — including one owned by SPPC, one owned by NEVP. and nine owned jointly — did not have established facility ratings.
Wave traps and relay settings were not taken into consideration by SPPC when rating transmission lines of 200 kV and above, or by NEVP for any applicable facilities.
Current transformers were not included in facility ratings by either utility, and relays were also not included by NEVP.
Lead lines to certain substations did not have established facility ratings.
Facility ratings were not established for series and shunt compensation devices.
SPPC did not update facility ratings following changes to its system.
NEVP had no facility ratings, or incorrect ratings, for 24 transmission lines when the facility ratings methodology changed from FAC-009 to FAC-008.
Overall, SPPC had 92 of its 210 facilities with incorrect or no established ratings, while NEVP had no or incorrect ratings for 76 of its 223 facilities.
WECC assessed the violations as posing a serious and substantial risk to reliability of the bulk power system because of the possibility of overloading a BPS element and causing neighboring facilities and protection systems not to operate as intended. Neither NEVP nor SPPC had effective preventive or detective controls that could have prevented this outcome.
In response, both entities implemented mitigation plans — identical except for minor differences in phrasing — that WECC verified as completed by June 20 in the case of SPPC and June 30 for NEVP. Elements of the plans include establishing peer-checked facility ratings for solely and jointly owned facilities consistent with facility ratings methodology; creating a facility rating change control process; and creating an internal task force to ensure that facility ratings follow reliability standards in the future.
Repeated Voltage Deviations
NEVP and SPPC’s VAR-002 violations stemmed from a joint quarterly compliance review conducted on Oct. 26, 2017, with each entity submitting a self-report on July 22, 2018.
During the review, SPPC found that between April 10 and Sept. 13, 2017, one of its generation facilities deviated from the transmission owner’s generator voltage schedule eight times, with a maximum deviation of 1.15% for six hours. In addition, between June 25, 2017, and Aug. 17, 2018, another facility deviated from the voltage schedule 22 times; the maximum deviation was 0.96% for more than 22 days.
WECC identified the root cause of SPPC’s violation as “a lack of clear instructions, training or guidelines” for meeting the established voltage schedule. SPPC also lacked preventive controls, which WECC considered a systemic issue because it revealed a “lack of consistency in SPPC’s approach to meeting the voltage schedule.”
In response, the utility implemented mitigation measures that included revisions to its internal generation procedure; in-house training focused on taking and tracking voltage measurements; and creating additional warning systems for deviations in voltage. WECC verified the measures were completed on March 28, 2019.
NEVP discovered 659 deviations from the voltage schedule at one of its facilities between Dec. 7, 2016, and Nov. 29, 2017, with a maximum deviation of 2.27% for 10 minutes. Further investigation revealed two additional facilities that deviated from the schedule: One deviated eight times between Dec. 7, 2016, and March 14, 2017, and the other five times between March 15 and Sept. 1, 2017.
The utility attributed the deviations to “incorrect methods employed by plant personnel to take voltage readings.” Mitigating steps, completed on Jan. 16, 2019, included revising internal generation procedure for maintaining network voltage schedules; rescinding internal policies that conflicted with the voltage schedules; and expanding reporting requirements at the affected facilities.
In assessing the utilities’ penalties, WECC credited both NEVP and SPPC for self-reporting the violations, cooperating throughout the process and accepting responsibility. However, the regional entity also noted that both companies’ internal compliance programs failed to detect or address the issues. In addition, the FAC-009 violation was particularly lengthy, lasting nearly 10 years. NERC’s Board of Trustees Compliance Committee agreed that the monetary penalties in both cases were “appropriate for the violations and circumstances at issue.”
PNM Files SOL, Maintenance Issues
PNM’s penalties concerned violations of reliability standards TOP-002 and TOP-004 — concerning operations planning and transmission operations — as well as PRC-005, relating to transmission and generation protection system maintenance and testing.
The violations of TOP-002 and TOP-004 concern the same event on Sept. 12, 2016, when a circuit breaker in one of the utility’s 345-kV switching stations faulted internally. Although the breaker was in two separate zones of protection, one did not operate because of a previously undetected malfunction; as a result, the fault was not fully addressed, and several transmission lines and generation units tripped offline.
The TOP-002 violation began when PNM’s system operators failed to update the system operating limit (SOL) after the fault was cleared, having assumed that this would be done automatically by the energy management system; instead, the limit was not changed until the following day. The TOP-004 violation arose from the failure to restore system operations within 30 minutes. Both violations were self-reported to WECC on Feb. 6, 2017.
WECC determined that PNM had “failed to maintain accurate computer models utilized for analyzing and planning system operations,” but that the utility had quickly invoked contingency reserves, started all available load-side generation and requested emergency assistance. PNM did not operate above SOLs at any time during the event. The RE also credited PNM for not only mitigating the specific issues that arose during the incident, but for taking “above and beyond” actions and investments in the years since to proactively reduce risk in its system.
PNM’s violations of PRC-005 stem from two incidents of failure to document maintenance on its facilities. In the first case, the utility reported on Oct. 26, 2016, that it lacked full maintenance records on four batteries, two transmission relays, eight battery chargers and 155 instrument transformers. The second instance was reported on May 25, 2018, and involved maintenance and testing records for two microprocessor relays and one electromechanical relay at a substation.
The root cause of the violations was determined to be ambiguous instructions for documenting and retaining evidence in the first incident, and “a lack of internal controls to ensure accuracy” in the second. WECC noted that the utility was following a stricter timeline for its protection system devices than is required by the standard. In addition, the relays involved in the second violation were considered secondary protection and their failure would likely not result in a significant loss of load in the BPS.
To mitigate the violations, PNM has ensured maintenance on the relevant hardware is completed and has corrected any inaccurate records. It has also established regular meetings to discuss maintenance issues on relays and monthly compliance reviews on all protection system devices subject to PRC-005.
The team working on NERC’s proposed standard for cold weather preparedness plans to meet again in the next two weeks to finish working through the latest round of comments on its draft standard authorization request (SAR).
Team members had planned to address the comments this week but were unable to finish partly because of scheduling difficulties related to the COVID-19 coronavirus outbreak.
The second round of comments on Project 2019-06 opened in February and closed last week, focusing on changes made to the SAR in response to the first round that closed in November. (See Cold Weather SDT Planning February Posting.)
Some of the changes drew widespread appreciation from commenters, but others provoked a more negative reaction. A lengthy comment from Mark Gray of the Edison Electric Institute, which was supported by several other participants, raised a number of potential issues that accounted for most of the drafting team’s time.
Emphasis Shifts to Communication
Gray applauded the SAR for putting greater emphasis than previous drafts on “the need for good communication between balancing authorities, reliability coordinators and generator owners and generator operators” both before and during extreme cold weather events. However, he questioned why the revised SAR included language requiring “communications … of all ambient weather impacts” rather than cold weather impacts only.
In response, NERC Senior Standards Developer Jordan Mallory observed that the expanded language was based on the belief that impacts outside of cold weather events could affect a generating unit’s performance in ways a BA or RC might need to know about. But based on the widespread objection, the team was prepared to drop the language, she said.
“We had a lot of conversations internally about this, and I can say [that] while we still feel all weather needs to be in there, we have heard people speak and we’re at a place where we’re comfortable with communication focusing on cold weather,” Mallory said.
Also at issue was a requirement that utilities report “historical demonstrated performance and limitations during ambient cold weather,” which many respondents complained might provide a misleading impression of a unit’s capabilities. Members explained that this requirement was intended as a supplement to other information, not a replacement.
“We basically landed on demonstrated historical performance as kind of a proxy for the unit’s performance,” said Matt Averett of Southern Co. “[It’s] not [that] the unit will be available above this temperature, [but] below this temperature, its performance is uncertain. … It was kind of a common ground, so to speak, between not having anything at all and falling back on the unit’s design [temperature].”
Regional Split Continues
Establishing an appropriate definition for “cold weather” remained a major point of contention among respondents, with several operators in northern areas continuing to insist that they were capable of handling cold weather preparations on their own. Despite the revisions, these respondents still said the proposed standard could impose a considerable compliance burden on them for no benefit.
As in the previous round of comments, this argument made little headway with the team. But members did promise that future revisions would continue to balance the need for an overarching standard with the requirements of operators in different regions.
“I want to be sure we’re not expecting 10,000 entities to come up with their own definition of cold weather,” said Don Urban of ReliabilityFirst. “I agree it should be the RC and BA. That is done now in our footprint; they define what cold weather is.”
Chair Matthew Harward of SPP said the team would make sure to take the industry’s misgivings into account in the next round of revisions. He also encouraged participants to continue providing feedback, reminding them that FERC was prepared to move forward on the new standard with or without their input.
“FERC has given industry a great opportunity to respond to the FERC cold weather report and propose a solution developed by industry,” Harward said. “I think we can all agree the industry development of a response to the FERC recommendations is more optimal than other options FERC may impose.”
The standard drafting team updating NERC’s standards to address cybersecurity supply chain risks is seeking a way forward in the face of widespread opposition to its proposed changes.
Project 2019-03 was initiated in response to FERC Order 850, which directed NERC to modify standards to address electronic access control or monitoring systems (EACMS) for high- and medium-impact bulk electric cyber systems. (See FERC Finalizes Supply Chain Standards.)
Meeting via conference call this week, the SDT focused on the results of the initial ballot that concluded March 11. The weighted results indicated just over 50% acceptance of the proposal, short of the two-thirds majority required for approval. (See Commenters See Overreach in Supply Chain Standards.)
Push for PACS Removal
Many of the negative comments accompanying the ballot focused on the inclusion of physical access control systems (PACS) in the proposed modifications to CIP-005, CIP-010 and CIP-013. This was not part of the original FERC mandate but was added after NERC staff’s supply chain risks report last May recommended that standards include requirements for PACS on high- and medium-impact systems.
| Pixabay
The addition of PACS had been a subject of disagreement during the drafting process, and some team members pointed to the opposition as justification for removing the term from the proposal altogether. (See Supply Chain Team Wary of Changing Access Control Terms.) Tony Hall of Louisville Gas & Electric and Kentucky Utilities cited a comment from Meaghan Connell of Chelan County Public Utility District that noted that protected cyber assets (PCAs) are excluded from the CIP-013 reliability standards because their risk is difficult to quantify, and recommended PACS be excluded on the same basis.
However, others pushed back against the idea that PACS had no place in the standards, arguing that they could still represent a security vulnerability and that overlooking such systems in earlier standards is no excuse for not recognizing their potential threat.
“The fact that NERC and FERC left PCAs out of the CIP-013 standards is not lost on me. … It seems that they should have both been included, but they were not,” said Jeffrey Sweet, manager of cybersecurity testing and assessments for American Electric Power, adding that he would have preferred to include PCAs in the supply chain standards if the order allowed it. “[We] only addressed the PACS because that was all we were told to address: PACS and EACMS.”
More Warnings of Scope Creep
Team members also responded to concerns about a perceived expansion in the definition of EACMS. Several commenters argued that FERC had only asked for modifications to address EACMS that pose a known risk to the bulk electric system, but the proposed standard would affect all EACMS. This wider scope could cause unintended confusion for utilities and disrupt their workflows, they said.
Hall urged the drafting team to take these warnings seriously and try to clarify its language in order to avoid “messing something up through a process, because there’s always a different way to follow the process.” He observed that an overly vague standard with difficult-to-parse language could quickly bog down both utilities and auditors in trying to verify whether compliance has been achieved.
“I personally don’t want to get into the situation of maintaining lists for the sake of maintaining lists,” Hall added. “Early on in these CIP standards, we had so many violations in CIP-004 because the list didn’t match who actually had access. … We ended up with violation after violation because the list was wrong.”
The SDT’s next meeting has not yet been scheduled. Currently all drafting teams are meeting via conference call in accordance with NERC’s business continuity plan, invoked in response to the COVID-19 coronavirus pandemic.
“I applaud the investment by stakeholders and members in their actions to protect our energy markets,” PJM Chief Risk Officer Nigeria Poole Bloczynski told the Members Committee after the final vote.
The new rules were developed by the Financial Risk Mitigation Senior Task Force (FRMSTF) in response to the GreenHat Energy default in the financial transmission rights market.
The Markets and Reliability Committee approved the Operating Agreement and Tariff revisions in a 4.5 to 0.5 (90%) sector-weighted vote after PJM officials agreed to accept three friendly amendments and members rejected a motion to delay the vote. The MC later endorsed the rules by acclamation with one vote in opposition and three abstentions.
Exelon’s Sharon Midgley called the changes a “significant leap forward in PJM’s credit and risk management program.”
What Changes
After the default of Tower Research Capital’s Power Edge hedge fund in 2007, FERC ordered an end to collateral-free trading with the issuance of Order 741. PJM and other RTOs tightened their credit rules as a result.
But the changes weren’t enough to protect PJM against GreenHat, which purchased a staggering 890 million MWh of FTRs — the largest FTR portfolio in PJM — before defaulting in June 2018. (See Doubling Down – with Other People’s Money.)
PJM formed the FRMSTF to implement recommendations made by an independent investigation of the debacle, which led to the departure of the RTO’s CEO, CFO and general counsel and the hiring of Bloczynski. (See Report: ‘Naive’ PJM Underestimated GreenHat Risks.)
The new rules require companies wanting to become a market participant to provide PJM with financial records, corporate information and details of any prior defaults in energy markets or involvement in market manipulation.
To allow PJM to conduct ongoing risk evaluation, companies also must make annual officer certifications and notify the RTO of any “material adverse change in the financial condition of the participant or its guarantor.”
PJM will determine whether a company presents an “unreasonable credit risk” based on factors including “a history of market manipulation based upon a final adjudication of regulatory and/or legal proceedings, a history of financial defaults, a history of bankruptcy or insolvency within the past five years, or a combination of current market and financial risk factors such as low capitalization, a reasonably likely future material financial liability, a low internal credit score … and/or a low externally derived credit score.”
Unbeknown to PJM, GreenHat’s principals, Andrew Kittell and John Bartholomew, had come to FERC’s attention for their roles in J.P. Morgan Ventures Energy Corp.’s scheme to manipulate the CAISO and MISO markets between 2010 and 2012.
The new rules also seek to prevent applicants who have defaulted from participating in PJM markets under a different name. Factors for determining whether an organization should be treated as the same market participant that experienced a default include “the interconnectedness of the business relationships, overlap in relevant personnel, similarity of business activities, overlap of customer base and the business engaged in prior to the attempted re-entry.”
After GreenHat’s default, Kittell continued trading in PJM for a time under a new corporate name, Orange Avenue.
Amendments
PJM officials made several changes to the language Thursday in response to stakeholder comments at a second “page turn” on the proposals March 13. In addition, PJM accepted three “friendly” amendments to the proposal it had negotiated with stakeholders in the days before the MRC vote.
Bloczynski acknowledged before the votes that some members were concerned the new rules would result in “unintended consequences.”
“We do not believe this is the case,” she said. “However … I commit to you that we’ll continue to review and reform the language to ensure that what the Tariff contains is what we all intended.”
Steve Huntoon | Steve Huntoon
One amendment, sponsored by attorney Steve Huntoon, representing H-P Energy Resources, modified the definition of the term “market participant.”
Huntoon’s amendment eliminated the phrase “or any other PJM member whose application to participate in the PJM markets has been approved by PJM.”
As amended, the definition is “a market buyer, a market seller, an economic load response participant, an FTR participant, a capacity market buyer or a capacity market seller.”
“The problem is the definition of ‘PJM markets’ is very, very broad,” Huntoon said.
As originally written, Huntoon said, it could have inadvertently included generators that provide ancillary services directly, rather than through a wholesale affiliate, as well as transmission owners and customers, including hundreds of municipals and cooperatives that participate in PJM markets through wholesale entities like American Municipal Power and Old Dominion Electric Cooperative. It was an issue Huntoon had raised at the first “page turn” session in February. (See PJM Stakeholders Debate Credit Rule Changes.)
Gary Greiner, director of market policy for Public Service Enterprise Group, won two amendments, including one that makes the judgments of rating agencies such as Standard & Poor’s, Moody’s Investors Service and Fitch Ratings, if available, “the source” for calculating the unsecured credit allowance of market participants. If no external ratings are available, PJM’s internal credit score will apply. If there is difference of opinion among rating agencies, the lowest rating will apply.
“It’s a metric that’s monitored by members, consistently applied and transparent,” Greiner said. “It’s what investors use to buy our stock and bonds.”
Bloczynski supported the change, saying, “We do not believe that this takes anything away from us.”
The rules include a scale ranging from “very low risk” (S&P/Fitch: AAA to AA-; Moody’s: Aaa to Aa3) to “high risk” (S&P/Fitch: BB- and below; Moody’s: Ba3 and below).
PSEG also won a change that PJM only “consider” rather than “apply” any changes to best practices or principles by third-party industry associations relating to risk management in the North American electricity, natural gas or electricity-related commodity markets.
PJM will “bring [the new policies] into the equation, but it won’t be applied it in a hard way that … members would be forced to put into their policies,” Greiner said.
Paul Sotkiewicz of E-Cubed Policy Associates, representing Elwood Energy, moved to delay the MRC vote to give other members time to submit friendly amendments.
But Bloczynski said the “amendments do not change the substance of anything that’s been put in front of you since December” and cautioned that a delay would prevent PJM from winning FERC approval of the changes in time to apply them for FTR auctions in June.
“We do not believe that more time to review the package is necessary or advisable,” she said.
Members voted almost 4 to 1 (80%) against a delay.
The California Public Utilities Commission approved historic increases in the state’s clean energy targets Thursday, calling for almost 25 GW of renewable energy and storage by 2030 at an estimated cost of $45 billion (16-02-007).
The CPUC’s new reference system portfolio (RSP) targets adding 11 GW of utility-scale solar; 3.4 GW of wind; 1 GW of pumped storage; and 8.9 GW of battery storage — eight times the total installed battery capacity nationwide as of 2018, the commission said.
Load-serving entities — including the state’s three big investor-owned utilities and a growing number of community choice aggregators — must use the reference portfolio figures, which the CPUC describes as “optimal” outcomes, in their individual integrated resource plans in 2020. The RSP also is used by CAISO in its annual transmission planning process.
The new RSP could dramatically increase solar and battery storage through 2030. | CPUC
The goal of the effort is to help the state reach its goal of providing 100% “renewable and zero-carbon” energy to retail customers by 2045, as mandated by Senate Bill 100, passed in 2018.
CPUC President Marybel Batjer thanked fellow commissioners, staff and stakeholders before the unanimous vote.
“I think [this] is a very, very good decision, one that will double the clean energy capacity of the state over the next 10 years and one I do believe will keep us on track for the 2045 goals that we must meet … not only for the good of California, but really for the good of the world.”
GHG Reduction not Enough?
Not everyone was as thrilled as Batjer with the result.
The Natural Resources Defense Council issued a statement Thursday saying the CPUC’s order didn’t do enough to address climate change because it maintained a target of reaching a greenhouse gas emissions level of 46 million metric tons by 2030 — the same figure the CPUC adopted in its last two-year IRP cycle.
“Despite recommendations to the contrary from the entire environmental community, multiple electricity providers and even the CPUC’s own Public Advocates Office, the commission adopted a proposal with a relatively high emissions scenario as the state’s reference system plan to guide California’s electricity providers for the next two years,” the NRDC said.
California PUC commissioners met virtually March 26 because of a coronavirus lockdown. | CPUC
However, the plan also requires retail electric providers to outline how they would reach a more ambitious target of 38 million metric tons, a concession to the chorus of those calling for greater GHG reductions.
Commissioner Clifford Rechtschaffen voted for the plan but expressed support for the stricter target in his comments.
Commissioner Liane Randolph, who headed the effort to draft the new reference portfolio, acknowledged not everyone was completely satisfied with the result but said there would be opportunities to revisit the GHG reduction target in the next two years.
“Having LSEs submit their plans toward the additional target of 38 MMT [million metric tons] will allow us to conduct a more practical and less theoretical analysis of what resources are needed to achieve that … target from the perspective of the individual LSEs doing the planning and procurement,” Randolph said.
The 46 MMT figure is 56% below 1990 levels and would exceed the state’s legislative mandate to reduce GHG by 40% below 1990 levels over the next decade, the CPUC said.
Renewables, Storage to Double
Randolph said the dramatic increase in renewable energy and storage statewide deserves praise.
“The decision adopted today provides guidance to load-serving entities to go out and procure approximately double the amount of renewable and storage capacity that is currently online in the electric system in California,” she said in a statement.
From 2020 to 2030, the reference portfolio projects a total increase in utility-scale solar from 16,310 MW to 25,905 MW and wind power from 7,367 MW to 10,293 MW, including 606 MW of wind power from new out-of-state transmission.
Natural gas generation would decrease by about 2.5 GW over the same period but remain as one of the state’s two main power sources, along with large-scale solar.
Commissioner Martha Guzman Aceves called for more effort to eliminate natural gas from the state’s resource mix. Methane, which accounts for about 12% of GHG emissions, has a more potent effect than carbon on global warming, she noted.
Wednesday’s vote was the culmination of a process that began with an administrative law judge seeking input in November 2018 and dozens of utilities, environmental groups, consumer advocates and others commenting on the plan’s iterations during the past 16 months.
The commissioners made their decision in a web conference because of the COVID-19 coronavirus pandemic. Technical problems with the phone company’s virtual setup plagued the commissioners, who also regulate the state’s telecommunications industry.
While obviously irritated, they didn’t threaten repercussions.
FERC last week approved SPP’s revisions to its joint operating agreement with MISO that improve pseudo-tie coordination requirements between the RTOs, effective Monday (ER20-904).
The March 19 letter order accepted revisions addressing definitions, requirements, modeling, interchange schedules and general pseudo-tie coordination. SPP said the changes would improve transmission system efficiency along its seam with MISO by including obligations already in pseudo-tie agreements where MISO is the external balancing authority.
The changes include:
adding certain definitions set forth in the NERC glossary of terms used in reliability standards;
incorporating language requiring the native BA and the attaining BA to coordinate the pseudo-tie’s modeling in accordance with the rules of the native BA and attaining BA, respectively;
adding new subsections to the JOA that outline authorities for pseudo-ties from one RTO into the other; and
revising the requirements with language that includes the impacts of pseudo-ties in the attaining BA’s market flow impacts for the purposes of congestion management procedures. “Neither MISO, nor SPP, nor the entity seeking to pseudo-tie shall tag or request to tag the energy flows from a pseudo-tie into the attaining BA,” the language says.
SPP borrowed from the MISO-PJM JOA to define pseudo-ties as involving the real-time transfer of a generating resource’s or load’s control from the native BA where resource or load is physically located to an attaining BA that is responsible for operating the grid in a different geographic location.
MISO’s control room in Carmel, Ind., where the RTO manages pseudo-tie connections. | MISO
Its pseudo-tie agreement permits load and generating resources external to the SPP BA to be served by SPP. It also allows load and generating resources internal to SPP to function as part of an external BA.
ESR Data Added to Interconnection Procedures
FERC on Tuesday accepted SPP’s Tariff revisions to include specific information related to energy storage resources (ESRs) in the grid operator’s generator interconnection procedures (ER20-918).
With the commission’s approval, the generator interconnection forms will now ask whether or not ESRs will take energy from the system when operating in charging mode and the maximum rate of charge capability.
SPP filed the request on Jan. 31, shortly after stakeholders agreed to form a steering committee charged with determining how best to integrate energy storage. (See SPP Planning Approach to Battery Storage.)
CAISO’s Board of Governors on Wednesday approved $141.7 million in transmission spending and reliability-must-run contracts covering three power plants in Central California.
The 2019/20 transmission plan covers nine projects CAISO says are needed to maintain reliability according to NERC and ISO planning standards. Seven of the projects (totaling $120.7 million) will be located in Pacific Gas and Electric’s service territory, one ($16 million) in Southern California Edison and another ($5 million) in the Valley Electric Association/GridLiance West area straddling the California-Nevada border.
In his presentation to the board, CAISO Vice President of Infrastructure Development Neil Millar characterized the plan as a “modest” capital program and pointed out that all the projects are reliability-driven.
“We did not identify the need for any policy-driven projects or economic-driven projects in this cycle. The one qualifier was that the economic-driven analysis did identify the benefit of advancing a reliability project, but the driver remains the reliability requirement for that project,” Millar said, referring to the $16 million, 230-kV Pardee-Sylmar line-rating-increase project in SCE’s territory.
Millar said CAISO’s analysis of potential policy-driven projects relied on assumptions gleaned from the California Public Utilities Commission’s 2017/18 integrated resource planning cycle. The CPUC’s IRP reference system plan assumes that California’s electricity sector will cap its annual greenhouse gas emissions at 42 million metric tons by 2030 through a generation portfolio consisting of at least 60% renewables. It includes a “generic” base portfolio concentrated in various parts of the state needed to meet that target (see graphic).
“I’m not an engineer, but as a matter of common sense, can you explain how we can go from a 33% to 60% renewable system” without spending on new policy projects? Governor Ashutosh Bhagwat asked.
Millar responded that, in past years, utilities developed renewable portfolios under the expectation that the resources must be deliverable as resource adequacy under CPUC rules. But those portfolios have “started to shift” where some of the output can be energy-only, he said.
This shows the CPUC’s determination of a “generic” base portfolio of renewables needed for California’s electric sector to meet a target of 42 million metric tons of GHG emissions by 2030. | CAISO
“So with the upgrades that were already put in place, we saw that we had considerable capability to take advantage of filling out those areas where developments had already taken place, as well as capacity to meet energy-only requirements where resources would be providing energy and not necessarily resource adequacy capacity,” Millar said.
The scope of the past transmission buildout accounts for the lack of policy-driven needs today, he said.
But Millar pointed to one “qualifier.”
“When you move to these higher [renewable] goals, we’re also seeing a steady escalation in the amount of transmission-related curtailments that’s showing up in the model, and unless there’s a policy requirement to address that curtailment, that would transition over to being an economic requirement,” he said. “Those could drive considerable transmission to address economic-driven transmission needs.”
The board additionally approved CAISO management’s recommendation to put three previously approved projects on hold for further review. The projects are all located in PG&E’s territory and include the North of Mesa upgrades, the 115-kV Morage-Sobrante line reconductoring and the Wheeler Ridge Junction substation project.
Not a Trend — Yet
The board also approved the designation of three Central California power plants as RMR resources for the summer peak season. The approvals are conditional because they will be revoked for any resource that obtains a resource adequacy contract by that time. The facilities include:
Starwood Energy Group’s Greenleaf II Cogen, which is required to help meet the 734-MW local capacity requirement (LCR) for the Drum-Rio Oso subarea within the Sierra local area. The 49.5-MW unit is not currently active in the CAISO market following termination of its Public Utility Regulatory Policies Act contract and is going through a qualifying facilities conversion process to become an ISO participating generator. The 230/115-kV Rio Oso transformer replacement project, which will mitigate the subarea’s reliability need, is not scheduled to be in service until June 2022.
California State University Channel Islands’ Channel Islands Power, which is required to help meet the 288-MW LCR requirement in the Santa Clara subarea of the Big Creek/Ventura local area. The 27.5-MW unit is currently under a resource adequacy contract set to expire on March 30. While 195 MW of new energy storage resources have been procured to meet the expected LCR shortfall in the subarea, they won’t become available until June 2021.
Atlantic Power’s E.F. Oxnard, which is also needed for the Santa Clara subarea. The 48.5-MW plant is currently under a resource adequacy contract that expires May 24. The unit will need to convert from a QF participant arrangement to a conventional market participant arrangement.
Governor Severin Borenstein noted that last year saw just one CAISO unit secure an RMR designation for the summer.
“Are we seeing an increase, or should I not think this is a trend?” Borenstein asked.
“From a local capacity perspective, we wouldn’t expect to see this being indicative of a trend,” Millar said. “Two of these units are qualifying facilities as opposed to being conventional market participants, and there’s a relatively small number of those. The other issue we’re dealing with is that we do have reinforcement projects under way generally to backfill for a number of these items, so there are individual cases that we’re going to have to deal with from a local perspective. So we don’t see this as a trend — at least yet.”
CAISO CEO Steve Berberich interjected: “I think the operative word being used is ‘yet.’ With the fragmentation of the load-serving entities in California, we expect that this could very well be the case. I agree with Neil that this doesn’t necessarily indicate a trend, but we’re going to continue to be vigilant about this issue.”
NYISO has sequestered approximately two-thirds of its operations staff on site at its two control centers to prevent possible infection by the COVID-19 coronavirus from interfering with reliable grid operations, CEO Rich Dewey told the Management Committee on Wednesday.
“First and foremost, from a reliability standpoint, we do not feel at this juncture that we have any reliability concerns specific to the pandemic or the readiness of any market participants, whether generators or utilities, to comply with what we need to do,” Dewey said.
The regular staff are working almost 100% from home, and there have been no reports of infection, he said.
“We have moved two full operational crews on site, provided trailers for sleeping [and] separate food facilities, and have walled off access to any of the individuals participating in that program,” Dewey said. “We’ve got a rotation that will help us maintain grid operations for the foreseeable future.”
The ISO also has been in regular contact with generators and transmission owners, and some of them are also beginning to implement on-site sequestration for staff, he said.
“Similarly, we’ve also been in touch with all the other RTOs and ISOs around the country … and everyone is thinking along the same lines,” Dewey said.
“We’ve also initiated, at the request of the [New York] Public Service Commission, some outreach to the generation community to try to get an understanding — for each of the generation plants — what level of readiness or preparedness exists, and to get a sense if we’re going to have any concerns with respect to their ability to perform.”
2019/20 Winter 5th Mildest in 200 Years
Vice President of Operations Wes Yeomans delivered the Winter 2019/20 Cold Weather Operations report, which showed a seasonal peak load of 23,253 MW on Dec. 19, compared with a seasonal 50/50 forecast of 24,123 MW. NYISO’s all-time winter peak load was 25,738 MW on Jan. 7, 2014.
NYISO 2019/20 winter daily peak loads in perspective | NYISO
Yeomans said there were no “critical issues” to report to stakeholders after a season without “critical operating conditions.”
“It feels strange to give a winter report when the winter was so mild,” he said. “Just how mild was this? Relative to the top 10 mildest winters … dating all the way back to 1820, this one tied with 1906 as the fifth-warmest January in the last 200 years.”
Transmission performance was also excellent, he said.
Yeomans also delivered the monthly operations report, highlighting the mild weather in February that saw natural gas and distillate prices lower compared to the previous month, and natural gas prices down 32.2% year-over-year.
ESR Tariff Revisions Approved
The MC also approved Tariff modifications related to energy storage resource (ESR) participation, as recommended by the Business Issues Committee earlier this month. (See NYISO BIC Briefs: March 19, 2020.)
Energy Market Design Manager Zachary Stines presented the background material for the discussion and vote on proposed Tariff language, which spells out details regarding day-ahead margin assurance payments; the method for setting feasible day-ahead and real-time schedules; generator offer caps, mitigation and reference levels; and installed capacity supplier bidding requirements.
If approved by the Board of Directors in April, the ISO will file the changes with FERC and anticipates making them effective simultaneously with the rest of its ESR participation model.
CIO Doug Chapman said the ISO wants to activate the new software in June and would delay the rollout until September if unable to do so to avoid implementing new software in summer conditions, because it represents a significant change to the system.
“If the summer was mild enough, our operations teams might elect to go ahead, but our default decision would be to avoid the summer and its tight operating conditions,” Chapman said.
Committee Chair Jane Quin, vice president of energy policy and regulatory affairs for Consolidated Edison, announced that the MC will hold a special meeting April 15 to act on buyer-side mitigation rules.
MISO’s weekday loads are looking more like weekends as social distancing measures to lessen COVID-19 cases take hold in more states in the footprint.
“We are starting to notice a few impacts,” Vice President of System Planning Jennifer Curran reported during the Markets Committee of the Board of Directors’ Tuesday meeting, conducted via WebEx and teleconference. (See Virus Fear Sends MISO Board Week to the Web.)
Director Tripp Doggett asked if MISO is experiencing more load shapes on par with weekend usage as more people stay home across the footprint.
“In general, it’s going in that direction; the peaks aren’t as prominent,” Executive Director of Market Operations Shawn McFarlane said.
For instance, McFarlane said, morning peaks are flattened absent the usual flurry of activity to get schoolchildren and workers out the door. In its place is a more dispersed demand over the morning hours, he said.
McFarlane said MISO hasn’t yet quantified how much load has declined across the footprint.
“Things have been evolving. Last week, it was only schools closed. Now we have shutdowns in the industrial sector. It’s very fluid at this time. It’s certainly greater than 5% — now it could be even 10%” year-over-year, he said.
Complicating matters, MISO’s load forecasting relies on historical information. “During this unprecedented time, we don’t have historical data,” Curran explained.
MISO Director Theresa Wise called the forecast challenges “completely understandable.”
Independent Market Monitor David Patton said MISO load in the first three weeks of March was about 8% lower than it was a year ago, reflecting the closure of schools and business. “We’ve noticed a significant impact,” he said.
“We expect that load effect to increase, and we’re talking to MISO about the impact. … We do think the learning of their models will improve the forecast,” Patton said, adding that in the meantime, RTO staff have manually adjusted short-term load forecasts.
MISO Director Baljit Dail asked if generators were scheduling maintenance outages to take advantage of the dip in demand as the economy slows.
“Actually, we’re seeing the opposite. We’re starting to see deferrals of planned outages,” Curran said. She said the root cause is likely that utilities are making do with fewer personnel.
Directors asked if MISO anticipates other impacts related to the pandemic.
A gentler MISO load curve at 5 p.m. ET March 25 | MISO
“It’s early days yet, so we’ll be in constant communication with our members,” Curran said.
The RTO has convened incident response teams focusing on COVID-19 that meet daily and have escalation plans at the ready to protect grid operations, if necessary, Curran said.
“MISO’s top priority is to ensure the safety of its staff and stakeholders and reliability of the bulk electric system,” she said.
Although most MISO employees are working from home, Curran noted that the RTO has operations in four sites in three states: the headquarters and Central Region Operations Center in Carmel, Ind.; the North Region Operations Center in Eagan, Minn.; and the South Region Operations Center in Little Rock, Ark. “So, we have a built-in social distancing,” she said.
Curran said MISO is also working with law enforcement to make sure the RTO’s control room operators can get to and from work as more states order their residents to shelter in place. She also said control rooms are being disinfected more frequently, and MISO has limited access to control rooms to essential personnel only. MISO facilities continue to be closed to visitors through May 1.
“This situation seems to change daily so keep in mind these actions can change or be extended,” Curran said.
Patton also reported Potomac Economics staff are all working remotely.
“We’ve seen no real problems in the functioning of the IMM or the software. Our software is run from a third-party data center, so we didn’t anticipate any impacts there,” Patton said.
