Page 1021 – RTO Insider

November 8, 2020

MISO to File Midwest-South Tx Rate Extension

MISO will file at FERC in December to extend a rate schedule that determines the payments market participants shell out for using the RTO’s Midwest-to-South transmission path.

Staff revealed Thursday that they are only asking for a one-year extension through Jan. 31, 2022. MISO had first proposed two years.

The rate schedule, set to expire in February, lays out the cost allocation for market participants that use the subregional transfer limit beyond the 1,000-MW contract path linking MISO’s Midwest and South regions. The rate schedule is separate from the RTO’s 2014 settlement agreement with SPP and other parties that set a 3,000-MW limit on north-to-south flows and a 2,500-MW limit in the other direction.

MISO Director of Seams Coordination Jeremiah Doner said the shorter timeline would allow MISO to begin stakeholder discussions on a possible new cost allocation.

Doner said it makes sense to work on a longer-term rate schedule because MISO will likely continue to use the transmission transfer limit for the foreseeable future. The grid operator does not have any transmission projects lined up that can serve as an alternative. Earlier this year it ruled out using new transmission upgrades to secure more transfer capability between its subregions. (See “No Midwest-South Tx Solution this Year,” Price Tag Rising for MTEP 20.)

“It was pretty much locked down in August. Why the sudden change?” Mississippi Public Service Commission consultant Bill Booth asked of the one-year extension.

Midwest-South Transmission Rate — Parties to the settlement agreement for MISO’s Midwest-South subregional transmission constraint | MISO

Doner said that in August, some stakeholders seemed eager to renegotiate the rate schedule. He also said the shorter extension lines up with a possible new agreement with SPP and the joint parties.

Effective Jan. 31 next year, the agreement may be terminated by any party with a year’s notice. However, the parties signed a memorandum of understanding that they would not propose changes to the settlement until Feb. 1, 2022. (See MISO Seeks Extension on Midwest-South Tx Limit.)

Without a revised settlement, flows would be limited to MISO’s original 1,000-MW contract path in either direction.

Under this approach, Doner said negotiations on the settlement and cost allocation can take place in tandem in 2022. The rate schedule would reflect any new terms from the settlement agreement, he said.

Currently, MISO’s payments to SPP and other parties for flows across the transfer limit are recovered from market participants through a combination of load-ratio calculations and flow-based beneficiary allocations.

The load-based share has declined every year since 2016 as the flow-based portion increased. From Feb. 1, 2016, to Jan. 31, 2017, the allocation was 45% load-based and 55% flow-based. From Feb. 1, 2020, to Jan. 31, 2021, the mix is 10% load-based and 90% flow-based.

November 8, 2020

SPP MMU: Summer Load up 2% in 2020

This summer’s average hourly load in the SPP footprint was 2% higher than the year before, according to the Market Monitoring Unit’s quarterly S tate of the M arket report for June through August.

The MMU credited warmer weather for the increase. Heating and cooling degree days were about 16% above the summer of 2019, with June degree days 36% higher than 2019 and July and August both up about 10%. The average hourly loads in the latter two months were nearly identical to the previous two summers.

Coal-fired generation continued to slide, down a point to 35% of the total generation mix. Wind generation increased to 25% of total generation from 20% last summer.

SPP MMU — SPP’s hourly average summer load for the past three years | *SPP Market Monitoring Unit*

Average day-ahead prices and real-time prices were both down 12% from 2019. Day-ahead prices were $20.32/MWh and real-time prices were $19.69/MWh.

The MMU also reported that:

market commitment status was 75% of all offered capacity, up from 68% the year before. Offered capacity in self-commitment status was down to 23%, a drop of 7 points from the year before.
generation outages, which had increased from summer 2018 to 2019, reversed this year, with outages falling from 26,000 GWh to 22,500 GWh.
day-ahead make whole payments doubled, from just over $7 million to more than $15 million, with coal payments increasing from $3.2 million to almost $8.7 million, and gas, simple-cycle payments jumping from $3.4 million to $5 million. “This increase is likely attributable to more resources in market status as compared to self-scheduled status and lower prices during the period,” the MMU said.

The report’s special issues section describes the MMU’s involvement in SPP’s transmission planning process, which has increased since 2018. The Monitor said it has served in an advisory capacity as the planning outcomes influence the market’s long-term efficiency through congestion patterns, operational effectiveness, costs and reliability.

The MMU will host a webinar to discuss the summer report on Wednesday.

November 8, 2020

MISO Embarks on Order 2222 Work

MISO is gearing up to draft FERC-mandated rules before it welcomes potentially thousands of distributed energy resource aggregations into its markets.

Last week’s preparation and discussion was in response to FERC’s Order 2222, which directs RTOs and ISOs to allow DER aggregators to compete in their markets. (See FERC Opens RTO Markets to DER Aggregation.)

During a teleconference Thursday, MISO’s Market Subcommittee voted to create a stakeholder task force to handle the work. The Steering Committee is expected to approve the task force’s creation Monday.

“It was 2016 when FERC issued its first DER aggregation Notice of Proposed Rulemaking,” MISO DER Program Director Kristin Swenson told stakeholders. “We’ve been waiting for this a long time.”

Swenson said MISO must create a “coordination framework” for compliance purposes that facilitates communication among itself, regulatory authorities, distribution utilities and DER aggregations. She said the RTO’s many state jurisdictions means the grid operator faces a challenge in creating multiple operating procedures.

“MISO has a tall order in front of us. … We need to learn how to work with each other in a new way to facilitate all of these new resources on the distribution system,” she said. The grid operator will create a new market participation model for DER aggregators, she said.

“Some folks said that this is the first time they’ve seen a FERC order leading the technology development,” Swenson said. “It’s a pretty exciting order.”

Swenson said staff will focus on how MISO can avoid double-counting DERs in metering and telemetry. “How do we avoid double-counting a DER in both the retail and wholesale markets? To be determined,” she joked.

Earlier this year, Swenson said MISO views visibility into DERs as its first challenge.

“We need to obviously understand shifts in pattern [and] in load. If a lot of rooftop solar is installed, for instance, that can affect our load patterns,” she said during the Reliability Subcommittee’s meeting in April. “We’re mindful that we need to better match some of our processes to changes in the industry.”

Swenson said staff continue to look for solutions to MISO’s “aggregation balance problem,” when the market system, burdened with several thousand points of generation, cannot solve. The system could have trouble locating aggregated DERs’ precise location to alleviate reliability issues.

MISO has until July 2021 to submit a compliance filing at FERC. Swenson said she hopes it’s “pencils down” in June to give time for legal staff to review the proposed compliance.

Swenson said the RTO is planning to hold multiple workshops on how it designs its Order 2222 compliance. The grid operator is also supportive of stakeholders and its state regulators’ decision to form a task force to guide compliance, she said.

The Organization of MISO States (OMS) pressed for a state regulator-led task force as soon as possible during a conference call of the RTO’s Steering Committee on Nov. 3.

“OMS is interested in digging in as soon as possible,” Executive Director Marcus Hawkins said.

Some Steering Committee members bristled that OMS would propose a MISO task force with handpicked leadership in mind. Hawkins said he was only giving the stakeholder community a heads-up that multiple OMS members are interested in helming a new task force. He said the usual stakeholder vote on task force chairs would naturally take place.

“OMS is just being transparent with the fact that it will put people forward,” Hawkins explained.

Swenson said coordination with OMS will be pivotal to MISO’s compliance filing.

“We know this is a state-jurisdictional system; so, much of how this order plays out will be determined by the [relevant electric retail regulatory authorities],” she said. “Understanding what the plans are of each state is critically important to us.”

Stakeholders asked during the Market Subcommittee meeting Thursday whether FERC’s rules always necessitate an RTO task force.

“It depends on the complexity of the issue. And this order touches on several areas,” subcommittee Chair Megan Wisersky said.

November 8, 2020

MISO Concurs with Most 2020 Monitor Recommendations

MISO agrees with nearly all the new market recommendations its Independent Market Monitor issued this year, though the grid operator said executing the ideas may take some time.

The Monitor issued five new recommendations in June in the annual State of the Market report. The recommendations focus on better management of flows across MISO’s seams, implementing dynamic transmission line ratings and disqualifying all energy efficiency resources from the capacity auction. (See IMM Issues 5 Recs in MISO State of the Market Report.)

Kevin Vannoy, MISO’s director of market design, said staff are persuaded on four out of the five ideas, questioning only whether the RTO can single out energy efficiency resources from participating in its annual capacity auction. Vannoy said FERC itself has included energy efficiency in its definition of distributed energy resources with its recent order on DER participation in wholesale markets.

“We feel that’s a reason that we should evaluate whether these resources can or should sell capacity in Planning Resource Auctions,” he told stakeholders during a Resource Adequacy Subcommittee teleconference Wednesday.

Monitor David Patton has said energy efficiency has no place in the capacity market.

“You can see that the quantities are growing rapidly, and MISO needs to look at this before it becomes 2,000 [or] 3,000 MW,” he said in July. “The only way to quantify energy efficiencies is to use a series of highly speculative assumptions, and I think MISO does a reasonable job. It’s just that they’re in an impossible situation.”

Energy efficiency installers are already paid once through savings on their bills, Patton argued.

“It’s hard to come to any conclusion but that [the additional capacity payment is] inefficient,” he said.

Staff say ambient-adjusted transmission line ratings are doable in the footprint, provided transmission owners are forthcoming with ratings. Vannoy said MISO will look for line constraints that could benefit most from variable ratings.

Patton said a “broad adoption” of ambient-adjusted ratings could have reduced the RTO’s congestion costs by as much as $150 million in 2018 and 2019. Over those two same years, TOs could have saved $114 million in congestion costs had they simply provided short-term emergency ratings.

Patton said MISO routinely exceeds $1 billion in the annual value of its real-time congestion, due in part to “very conservative, static ratings by most transmission operators.”

“I think more are becoming aware of this problem,” Patton said, citing last year’s FERC technical conference and the Organization of MISO States’ interest in the footprint’s TOs implementing dynamic ratings.

Vannoy said there will be more development on dynamic line ratings in 2021. The grid operator’s new modular market platform will make it easier for staff to employ dynamic line ratings, he added.

Past Recommendations Put to Bed

Staff said that since last year’s market report, they have fulfilled a 2014 recommendation to create a short-term energy reserve product and delivered on a 2016 recommendation to limit the duration of capacity resources’ outages. Additionally, in the 2021/22 capacity auction, MISO will require full transmission deliverability of capacity resources and enforce a stricter capacity accreditation for load-modifying resources. That will check off two 2017 recommendations.

The RTO said work remains on another 2014 recommendation to use seasonal capacity market procurements. MISO is now studying which hours throughout the year — not just a summer peak — may contain loss-of-load risk. Staff said they continue to explore a more accurate capacity accreditation by accounting for planning resources’ unreported or unforced outages.

MISO is also considering excluding offline resources from setting LMPs and upping its value of lost load and emergency pricing, which would button up Monitor recommendations made in 2015, 2016 and 2018, respectively.

November 6, 2020

CPUC Stops IOU Energy Efficiency Incentives

The California Public Utilities Commission voted unanimously Thursday to enact a moratorium on a longstanding program that provides $30 million to $75 million annually to shareholders of the state’s three big investor-owned utilities for administering energy efficiency programs.

The commission’s decision represented a rare disagreement with one of its own administrative law judges, Julie Fitch, who wrote in a proposed decision that the Energy Savings and Performance Incentive (ESPI) remained a useful motivator.

“Energy efficiency is still our most important resource in which we are expecting utilities to invest ratepayer funds, and we still need the most effective energy efficiency program possible as the urgency of meeting our environmental goals becomes more critical,” Fitch wrote.

Energy-efficient construction and appliances are primary components of the state’s efforts to reduce electricity consumption as part of its strategy against climate change.

Commissioners said they respected Fitch’s careful reasoning but disagreed.

“We don’t need to incentivize people with bonuses for complying with the law,” Commissioner Martha Guzman Aceves said.

ESPI — Reducing electricity consumption is a key component of California’s climate change strategy. | *California Energy Commission*

Senate Bill 350, passed in 2015, requires the state to double its energy efficiency by 2030, and 2018’s Senate Bill 100 requires utilities to provide retail customers with 100% carbon-free electricity by 2045. The ESPI adder, which the CPUC approved in 2013, may be “antiquated” in today’s changed energy landscape, Guzman Aceves said.

“We have an obligation … regardless of whether shareholders get more money or not,” she said. “I think it’s time we start to reward the customers, who are the actual consumers that are conserving here, and move away from an approach of feeling that we need to give utilities extra money for doing their job.”

Guzman Aceves and her four colleagues agreed with an alterna te decision by Commissioner Liane Randolph that called for an indefinite moratorium of the program starting next year.

“The moratorium shall remain in effect pending subsequent action to assess whether, how or when a new version of ESPI or a new incentive mechanism can be devised and implemented,” Randolph wrote.

Consumer groups, such as The Utility Reform Network (TURN), opposed the continuation of the shareholder incentives. The IOUs had gone from implementers of the energy efficiency programs to administrators working with third-party contractors, a role that doesn’t require additional incentives, TURN contended.

San Diego Gas & Electric acknowledged that the role of IOUs in energy efficiency programs has changed. The utility said a review of the incentive program was warranted but said it should continue.

Pacific Gas and Electric argued “shareholder incentives may not be necessary to ensure the planning and delivery of robust energy efficiency programs, [but] they signal the importance and support of programs not primarily intended as resource programs,” such as workforce training, marketing, and consumer education and outreach, Fitch wrote.

“PG&E believes that an incentive for investing in non-resource activities can motivate IOUs beyond minimum compliance obligations, despite internal pressure to reduce impacts to portfolio cost-effectiveness and customer bills,” she said.

November 6, 2020

CenterPoint, OGE Mum on Enable Midstream

CenterPoint Energy and OGE Energy, general partners in gas-gathering outfit Enable Midstream Partners, declined to answer questions on potential sales of their interest in the company during their respective third-quarter earnings calls Thursday.

Instead, they stuck to the companies’ line that they are “now well aligned in our desire to maximize the value of Enable.” Reports surfaced last month that the companies were pondering a sale in the face of depressed commodity prices and other economic headwinds.

A sunny CenterPoint CEO David Lesar instead gave analysts a sneak peak of the company’s future plans, saving more details for the company’s investor day on Dec. 7.

“I’m even more optimistic about where we can take this great company in the future than I was 90 days ago,” said Lesar, who only joined CenterPoint in June.

CenterPoint reported earnings during the quarter on a guidance basis of $200 million ($0.34/diluted share), compared to $241 million ($0.47/diluted share) a year ago.

Lesar shared high-level recommendations from the recently completed Business Review and Evaluation Committee’s work. They include a $3 billion increase, to $16 billion, in capital investment expected to deliver 10% annual base-rate growth; investing $950 million in wind and solar generation; operations and maintenance “cost discipline”; and improving the company’s balance sheet “optionality.”

“To eliminate any initial anxiety you may have, I want to immediately emphasize that our plan does not require any block issuance of new equity nor require a reduction to our current earnings per share,” Lesar said.

Instead, CenterPoint plans to sell “one or two” of its natural gas local distribution companies (LDCs).

“All of our gas LDCs are good assets in constructive regulatory environments, and we hate to sell any of them, but a hard capital allocation decision needed to be made, and I made it,” Lesar said.

Wall Street applauded CenterPoint’s earnings, driving the share price up to $22.80 in after-hours trading, a gain of $1.24 and 5.8%.

Weather Knocks down OGE Earnings

Like CenterPoint’s executives, OGE management begged off answering Enable-related questions during their analysts’ call, which immediately followed that of its Texas partner.

“Whatever we do [with Enable] would be focused on the OGE shareholder,” CEO Sean Trauschke said.

One analyst twice tried unsuccessfully to pry information from Trauschke, asking detailed, vague questions that left the CEO confused.

“I’m still not getting it,” he said after the second question.

“I’m just trying to get information out of you,” the analyst admitted.

The Oklahoma City-based utility reported third-quarter earnings of $177.4 million ($0.89/diluted share), compared to $250.9 million ($1.25/diluted share) a year ago. OGE blamed the loss on less favorable weather compared to the same quarter in 2019, as cooling degree days were down about 21%.

The weather calamities didn’t stop there. Trauschke said the company is still restoring service from an Oct. 26 ice storm, the worst in the company’s history, that resulted in 470,000 outages at its peak. Three waves of sleet, freezing rain and high winds damaged 178 structures on OGE’s transmission system and damaged or destroyed 1,134 poles, 1,050 crossarms and 194 transformers.

As of Thursday morning, OGE had restored power to 372,000 customers.

“It’s kind of our job to address this,” Trauschke said. “In Oklahoma, October is a summer-rate month. Instead of heat, we got an ice storm. But I believe all things even out.”

OGE’s share price climbed to $32.80 after the earnings release but finished the day down at $31.97, a 27-cent drop from the previous day’s close.

November 6, 2020

ERCOT: Record 5 GW of Installed Wind Capacity

ERCOT Wind Capacity — Wind capacity in ERCOT’s interconnection queue shows no signs of slowing. | *ERCOT*

ERCOT said Thursday it will have enough installed capacity to meet forecasted demand this winter and spring thanks in part to a record of new installed wind capacity.

The grid operator said it is on track to add more than 5 GW of wind capacity this year. It currently has 29.3 GW of installed capacity and expects 38.4 GW installed or under some form of study in its interconnection queue by 2024.

ERCOT also expects utility-scale solar to more than double since the end of 2019. It began this year with almost 2.3 GW of solar capacity but will end it with nearly 5.2 GW, including more than 750 MW with signed interconnection agreements.

All told, the grid operator’s seasonal assessment of resource adequacy (SARA) indicates that it will have nearly 83 GW of capacity available to meet a projected winter peak of 57.7 GW that is based on recent historical winter peaks. The assessment for December-February includes an additional 928 MW and 35 MW of wind and solar winter-rated capacity, respectively.

ERCOT’s all-time winter peak is 65.92 GW, set in January 2018.

“In the winter, we’re dealing with morning and evening peaks and sometimes extreme volatility in the weather,” Pete Warnken, ERCOT’s manager of resource adequacy, said in a statement. “We studied a range of potential risks under both normal and extreme conditions and believe there is sufficient generation to adequately serve our customers.”

ERCOT also released its preliminary SARA for the spring season (March-May 2021). It includes a low-wind output scenario for the first time but still predicts ample generation capacity to meet an anticipated peak demand of 64.5 GW. The grid operator expects to have an additional 4.3 GW of spring-rated resource capacity on hand.

November 6, 2020

Exelon Discusses Potential Generation Spinoff

Exelon officials confirmed during a third-quarter earnings call Wednesday that the company is considering spinning off its generation business into an independent company.

CEO Christopher Crane said the company began a review of its corporate structure earlier this year with the help of outside advisers. The review resulted from the evolving landscape of the generation business and the shrinking of “competitive integrated companies in our sector,” Crane said.

The news comes just a few months after Exelon announced the closing of its Byron and Dresden nuclear plants in Illinois, which face hundreds of millions of dollars in revenue shortfalls because of declining energy prices. (See Exelon to Close Ill. Nukes as Gov. Touts Clean Energy Plan.)

Crane said the goal of the review is to see whether two healthy companies could be created that can stand on their own financially and “provide the support needed for the balance sheets, the customers, the employees [and] the shareholders as we go forward.”

“I want to emphasize that the separation of the companies would involve addressing some complex operational, financial and regulatory issues,” Crane said. “No decision has been made, but we continue to do the work to determine the best outcome for our stakeholders.”

Nuclear Plants

The Byron nuclear plant is slated to close in September 2021; the Dresden plant will shut down in November 2021; and Mystic Units 8 and 9 will retire at the expiration of its cost-of-service commitment in May 2024. (See FERC Rejects Exelon’s Mystic Complaints Against ISO-NE.)

Exelon said it experienced a “$500 million impairment of its New England asset group and non-cash charges for Byron, Dresden and Mystic of $260 million.” It said the charges were related to materials and supplies, employee-related costs, construction and other items.

Crane said Byron and Dresden produce 30% of Illinois’ carbon-free electricity while also employing more than 1,500 full-time employees and paying $63 million in annual taxes. He said that without the plants and others at risk of closing, Exelon customers could pay $483 million in increased annual energy costs under PJM’s capacity market structure with an increase of 70% in greenhouse gas emissions.

(See Clock Ticking on Exelon Illinois Nukes Under MOPR.)

“Despite being among the most efficient, reliable units in the U.S. nuclear fleet, they face revenue shortfalls, declining energy prices, lack of capacity revenue and market rules that allow fossil plants to underbid clean energy resources in the PJM market auction,” Crane said.

Earnings

Exelon said it earned $501 million ($0.51/share) for the quarter, 35% less than the $772 million ($0.79/share) it earned for the same period last year. The company brought in $8.85 billion in total revenue for the quarter, slightly less than the $8.93 billion it posted last year.

CFO Joseph Nigro said the company was raising its year-end earnings guidance to $3 to $3.20/share from $2.80 to $3.10/share. Exelon has invested $4.5 billion so far this year to improve infrastructure and increase grid reliability, he said.

Shares of Exelon were down 25 cents, or 0.59%, to $42.22 as of closing on Wednesday.

November 6, 2020March 9, 2025

NERC Board of Trustees/MRC Briefs: Nov. 5, 2020

NERC’s Board of Trustees and Member Representatives Committee (MRC) will hold their first meetings of 2021 remotely because of the COVID-19 pandemic, board Chair Roy Thilly told the groups at their quarterly conference calls Thursday. The meetings had been planned for Feb. 3-4 in Manhattan Beach, Calif.

“We hope that [the pandemic] will be dying down, but of course we don’t know. And there are so many travel restrictions in place on employees of various stakeholders — [at the] Canadian border and other things — that it is prudent for us to do the meetings virtually,” Thilly said.

The pre-meeting and informational session will be held via conference call Jan. 6 as scheduled. A decision has not yet been made on the next board and MRC meetings, planned for May 12-13 in D.C.

Choudhury Elevated to MRC Chair

Paul Choudhury of BC Hydro, who is currently serving as vice chair of the MRC, was unanimously elected to take over from Exelon’s Jennifer Sterling as chair for 2021. ElectriCities CEO Roy Jones will serve as vice chair.

Elections for sector representatives will be held Dec. 7 to 17 to replace members whose terms expire in February 2021. The MRC is accepting nominations through Friday.

The MRC also approved revisions to its NERC MRC Briefs: Nov. 5, 2019.) This year’s changes are intended to give the committee more flexibility by removing unnecessary requirements from the MRC’s procedures for conducting conference calls.

Standards Actions

Howard Gugel, vice president and director of engineering and standards at NERC, presented three standards for approval by the board: CIP-005-7 (Cybersecurity — Electronic security perimeter(s)), CIP -010-4 (Cybersecurity — Configuration change management and vulnerability assessments) and CIP-013-2 (Cybersecurity — Supply chain risk management).

The standards were developed under Project 2019-03 in response to FERC Order 850, which directed NERC to submit modifications to address electronic access control or monitoring systems (EACMS) for high- and medium-impact bulk electric cyber systems. (See FERC Finalizes Supply Chain Standards.) A final ballot concluded on Sept. 10 with 80.78% of industry stakeholders in approval.

The board voted unanimously to approve the standards along with NERC’s 2021-2023 Reliability Standards Development Plan (RSDP), which provides schedules and anticipated resource needs for each project under development or expected to begin. NERC posted the draft RSDP for an informal comment period in August prior to its approval by the Standards Committee in October. After approval, the document will be filed with FERC and Canadian and Mexican government authorities. (See NERC Opens Comments on Standards Plan.)

“[This] is not a static document; it’s … a snapshot as far as things stand today,” Gugel said. “Certainly as new [standard authorization requests] are accepted by the Standards Committee, or new directives [are] issued by FERC, it would augment this plan going forward.”

Winter, Long-term Assessments Previewed

Board members also received an update on NERC’s 2020-2021 Winter Reliability Assessment, set to be released next week, and the 2020 Long-Term Reliability Assessment, which will be released in December.

NERC engineer Stephen Coterillo told the board that all regions are expected to have sufficient resources “under normal winter weather conditions,” echoing FERC’s 2020/2021 Winter Energy Market and Reliability Assessment released last month. (See COVID-19, Weather Drive FERC Winter Outlook.) Fuel and energy assurance pose significant risks in some areas — notably ISO-NE and NYISO — and extreme weather conditions could “result in the use of operating mitigations or energy emergency alerts to meet extreme peak demands.”

Anticipated reserve margins and reference margin levels for 2022 peak season | NERC

Although no specific threats were noted from the COVID-19 pandemic, Coterillo acknowledged that the coronavirus continues to cause “uncertainty in electrical demand projections and … heightened cybersecurity risk.” Damage to electricity infrastructure in Louisiana from this year’s hurricanes could also impact the local grid’s resilience, though the affected systems are expected to be restored by early winter.

On the longer scale, NERC expects sufficient on-peak capacity in most areas for the next five years, with the exception of Ontario and MISO, where planned reserves have the potential to fall below their reference margin levels. NERC Senior Engineer Mark Olson said the team identified several trends that bear watching over the long term, including the rapid projected growth of wind and solar generation resources — expected to comprise 57% of added on-peak capacity over the next five years — and the addition of distributed energy resources, particularly rooftop solar panels, across the North American grid.

November 6, 2020November 6, 2023

Work Gets Underway for WECC Path Task Force

WECC’s new Path Task Force (PTF) on Wednesday kicked off an effort to examine the role of existing transmission path rating procedures in Western Interconnection planning and operating processes and whether they are still applicable to a changing grid.

The regional entity’s Joint Guidance Committee (JGC) authorized creation of the PTF in September to identify the “relevance and role” of total transfer capability (TTC), path ratings and the “three-phase” ratings process in both the operations and planning horizons for industry participants. (See New WECC Task Force to Examine Path Rating Processes.)

The three-phase process is designed to address planned new transmission facilities and the upgrading or rerating of existing facilities through a review group consisting of project sponsors and representatives of other systems that could be affected by the project, according to WECC.

The path rating process provides transmission project sponsors with the means to obtain an “accepted” rating that meets the RE’s criteria and NERC reliability standards.

During the PTF’s kickoff meeting Wednesday, WECC Director of Reliability Risk Management Vic Howell, the staff liaison to the task force, added some flesh to the mission, explaining the stakeholder group will also “identify and explain the changes in regulatory, markets and business practices, as well as changes in operations in planning that support [the PTF’s] conclusions and recommendations.”

Those findings will be reported to the JGC, although the PTF will also give presentations to WECC’s Operating Committee (OC) and Reliability Assessment Committee, Howell said.

Howell said the idea for the PTF originated in July after the Western Area Power Administration gave a presentation on an internal project to more dynamically calculate near-term and real-time TTCs to be posted on its Open Access Same-Time Information System (OASIS), rather than relying on seasonal TTCs.

“That led to some discussions of the shortcomings of too much reliance on seasonal TTC values,” Howell said. “And as we talked about it at the OC meeting and the joint standing committee meetings, there were a lot of questions and discussions about the use of total transfer capability in the operations and the planning horizon, and the discussion led to asking, ‘How does the path rating fit into this whole equation? And where does the three-phase ratings process come into play?”

Howell lauded the professional diversity of the 12-member task force.

“We wanted to make sure that as we choose members for this task force, we get representation from operations, that we get expertise from planning and … from business practices — scheduling and markets and things of that nature,” he said.

Members Speak

In a get-acquainted exercise, Howell asked PTF members to describe their interest in the path ratings issues.

“The one thing that really stands out is tackling this time frame issue that’s come up,” said PTF Chair Matthew Veghte, an engineering supervisor at WAPA.

“We don’t just look at [the power system] from a seasonal perspective or a next-day perspective; we’re looking at all the way from planning — which can be five years, to a year, to six months to 30 days out — to one day out,” Veghte said. “We have all these different time points that have different things going on, and we’re tasked with, ‘How do we figure out TTC with that?’”

Transmission planning consultant Chifong Thomas said she was interested in exploring how to apply planning restrictions to the operating world in a way that’s not “overly restrictive.”

“Because things change when you go from planning to operations, and so how do we communicate the information that was important to help the operating system,” Thomas said.

Gary Trent, transmission planning manager at Tucson Electric Power, cited the fact that his utility will be joining the Western Energy Imbalance Market in spring 2022 while also transitioning to NERC’s MOD-30-02 flowgate methodology for calculating short-term transfer capability.

“I believe that we’re going to see more and more companies heading that way as time moves on, and being able for us to be on the ground here with that is going to help us all out,” Trent said.

Hari Singh, principal engineer at Xcel Energy, said his interest stems from his view that there is “quite a bit of intersection” between the concepts of transfer capability and system operating limits.

“Now whether we say that system limit is for the operations horizon or the planning horizon, I don’t see why they should be very different if the system we’re looking at five years out in the planning horizon is almost the same as what we’re operating today,” Singh said. “I guess I’m certainly very interested in trying to de-mystify this concept of path ratings we’ve had in WECC and how it relates to total transfer capability and system operating limits.”

Audrey Stevenson, operations planning engineer at Bonneville Power Administration, said, “I think the thing I’m most excited about this task force is identifying and trying to reconcile the differences that are present between the performance requirements and planning horizon, which lead to path ratings and operating horizons, which lead to the short-term TTC and also exceedance identification.”

The task force also includes Dede Subakti and Larry Bellnap of CAISO; Brenda Ambrosi of BC Hydro; Peter Mackin of GridBright; Igor Kormaz of Tri-State Generation and Transmission Association; Clint Savoy of SPP; and Bill Shemley of PacifiCorp.