Page 1113 – RTO Insider

October 11, 2018November 29, 2023

ERCOT Board of Directors Briefs: Oct. 9, 2018

ERCOT’s Board of Directors on Tuesday unanimously approved staff’s determination that no market changes are currently needed to address price formation issues as a result of DC tie flows during emergency events.

The determination was in response to one of the Texas Public Utility Commission’s 14 directives to ERCOT related to the Southern Cross Transmission project. In approving the project, which would create merchant ownership of a DC tie connection to the Southeast, the PUC directed ERCOT to complete a number of tasks before allowing the line to be energized (Project No. 46304).

ERCOT General Counsel Chad Seely assuaged the board’s concerns by noting filing documents and information in the PUC’s compliance docket allows the commissioners to discuss the grid operator’s updates and provide feedback during open meetings. Seely and Compliance Director Matt Mereness both pointed to an existing price mechanism that allows up to 1,250 MW of DC tie imports to contribute to a reliability price adder, as minimizing pricing effects within the Texas grid.

The Technical Advisory Committee endorsed the determination during its September meeting, but not before adding language to make it clear staff recognized “potential price formation issues” and that stakeholder discussions were ongoing. (See “TAC Approves First PUC Directive Related to DC Ties,” ERCOT Technical Advisory Briefs: Sept. 27, 2018.)

“The determination doesn’t presuppose any type of future outcome,” Seely said. “If a market participant wants to move forward with a NPRR [Nodal Protocol revision request], ERCOT will work with the stakeholders to facilitate those discussions. No one has had an appetite to sponsor an NPRR to try move any of those issues forward, and we’re not sure it’s necessary at this time.”

Citigroup Energy’s Eric Goff, chair of the Qualified Scheduling Entity Managers Working Group, said during the TAC meeting that a market participant plans to file an NPRR related to the issue. Goff did not identify the participant.

Board Vice Chair Judy Walsh, who led Tuesday’s meeting in Chairman Craven Crowell’s absence, asked Seely if ERCOT would reach “a point of no return” where the Southern Cross project is energized and “we haven’t addressed these issues, and we’re behind the curve?”

Seely responded that even if the price formation issue isn’t addressed by stakeholders in some form, there would be no problem from Southern Cross energizing the project.

ERCOT Projects Year-end $25.5M Positive Budget Variance

ERCOT CEO Bill Magness continues to see a positive trend in budget differences, telling directors he expects “likely a significant [variance] at the end of the year.”

The grid operator’s net revenues were $23.3 million over budget as of Aug. 31, thanks to higher-than-expected loads ($6.7 million over) and increased income because of higher investment balances and rates ($6.4 million). Staff are projecting a year-end favorable variance of $25.5 million.

“We’re still managing to the budget,” Magness assured the board during his regular CEO’s report.

ERCOT has now scheduled a Nov. 19 go-live date for the delayed $2.9 million upgrade to the congestion revenue rights system, having seen “substantial progress” since the last board meeting and resolving “vendor-quality issues,” Magness said.

A re-plan is expected in October for a $4.3 million credit monitoring and management system project, a complex process that reaches down to staff PCs and ERCOT’s server racks.

Looking ahead, Magness previewed a pair of security-related NPRRs wending their way through the stakeholder process. NPRR899 looks at whether digital certificates are still state-of-the-art and creates an opt-out provision, while NPRR902 will provide a definition for ERCOT critical energy infrastructure information and a clear line between public and confidential information.

Magness also said NERC’s Accelerated Generation Retirements Special Reliability Assessment report will focus on the PJM and ERCOT systems. The assessment is expected to be discussed during the organization’s November Board of Trustees meeting.

West Texas Heat Could Mean More Wind Energy

Senior Meteorologist Chris Coleman shared an initial analysis of the effect of summer heat on wind generation, which seemed to bear out his hypothesis that more heat equals more wind energy.

“My theory is that hotter-than-normal weather equals greater-than-normal wind generation,” he said.

Coleman’s study came at the request of Director Clifton Karnei, who represents the cooperative segment. It compared June’s average high temperatures in Midland, Texas, with the average daily percentage of installed wind capacity at 5 p.m., dating back to 2014.

Over the past five summers, Midland’s average high temperature peaked at 98.3 degrees Fahrenheit in 2018 during the state’s fifth-hottest summer on record. That coincided with a 39.2% installed wind capacity production mark. Only June 2014’s 42.9% figure, when highs in Midland averaged 95.7 F, was higher.

The other three years saw average highs between 91.7 and 96.9 F, with no average daily wind capacity above 28.9%.

Coleman said there were some exceptions to his theory, but he couldn’t explain why. “I will need to chisel down into a day-by-day look,” he said.

His preliminary winter forecast projects near-normal weather. He cautioned the board that winter is a “different animal” in how it correlates to peak loads.

“If I forecast colder-than-normal weather, it may not mean a higher peak,” he said, noting that last winter’s coldest day in ERCOT since 2011 (Jan. 17) came during the state’s 75th coldest winter. “If I had to adjust [the forecast], I’d adjust it warmer.”

Staff Files Governance Changes with PUC

ERCOT has filed amendments to its Articles of Incorporation (which has been renamed the Certificate of Formation) and to its bylaws with the PUC (Docket No. 48677).

The changes were approved by more than the necessary two-thirds of the grid operator’s corporate membership by a Sept. 12 deadline. They had been previously approved by the board in August. (See “Special Membership Meeting to be Set,” ERCOT Board of Directors Briefs: Aug. 7, 2018.)

Assistant General Counsel Vickie Leady said she expects the PUC to confirm the articles and bylaws amendments by its Dec. 20 open meeting.

Board Clears 10 Revision Requests on Consent Agenda

The directors unanimously approved seven NPRRs, a change to the Nodal Operating Guide (NOGRR) and two revisions to the Planning Guide (PGRRs) on their consent agenda:

- - NPRR845: Incorporates numerous revisions to the reliability-must-run process, including standardizing the standby cost in terms of dollars per hour instead of dollars per megawatt; adjusting availability metrics used in settlements to the current operating plan rather than the availability plan; clarifying a resource’s post-RMR status and requiring an entity to submit a resource-notification change no later than 60 days before an agreement’s conclusion; allowing ERCOT to retain a mutually agreeable third party to help evaluate submitted RMR budgets; and modifying the RMR agreement to require detailed budgeted costs with or without capital expenditures.
  - NPRR857: Creates “direct current tie operator (DCTO)” as a market participant role, clarifying the obligations of entities operating DC ties interconnected with the ERCOT system.
  - NPRR869: Requires generators over 1 MW within a private use network (PUN) to provide modeling information to ERCOT if they are not: registered with the PUC as a power generation company; part of a PUN with more than one connection to the ERCOT grid; or registered to provide ancillary services. The change includes a netting exemption for a small qualifying facility that provides energy to a customer behind a single point of interconnection. It also deletes a reference to the now-expired System Benefit Fund.
  - NPRR880: Requires ERCOT to publish shift factors for PUN settlement points for the real-time market, as is currently done in the day-ahead market.
  - NPRR883: Removes the real-time reliability deployment price adder from the real-time settlement point price to avoid double payment when resources have received an ancillary services assignment.
  - NPRR888: Clarifies the four-coincident-peak adjustment methodology implemented in conjunction with NPRR830.
  - NPRR890: Aligns protocol price calculation formulas with ERCOT’s calculation of the real-time LMP at a logical resource node for an online combined cycle generation resource, distinguishing between scenarios in which the unit is online or offline.
  - NOGRR177: Revises the NOG to be consistent with NPRR857’s language on DCTOs.
  - PGRR063: Outlines the process for evaluating the reliability impact of transmission projects 100-kV or above that are expected to be in service before the next Regional Transmission Plan’s completion but that were not included in the current plan, a Regional Planning Group project submission, or a generation interconnection or change-request study.
  - PGRR064: Requires resource entities to verify that dynamic devices used for reliability reflect their operating characteristics.

— Tom Kleckner

October 11, 2018

Tx Path Uncertain for Massive New Mexico Wind Farm

By Hudson Sangree

New Mexico regulators approved construction this month of what could be the Western Hemisphere’s largest wind farm, capable of generating as much power as a mid-sized nuclear power plant. But whether all that energy will have a way to reach the load centers of California and the Southwest remains unclear after the regulators denied approval for new transmission lines meant to link the wind project to urban areas.

On Oct. 3, the New Mexico Public Regulation Commission voted 4-0 to allow Pattern Development’s Corona Wind Projects to move forward. Pattern’s plans call for construction of up to 950 wind turbines with the potential to produce 2,200 MW of electricity. That’s about the same capacity as Pacific Gas and Electric’s Diablo Canyon nuclear power plant, the last in California, which is scheduled to retire by 2025.

SunZia Pattern Energy Wind Farm CAISO — The proposed SunZia Southwest Transmission Project could connect wind farms in eastern New Mexico to end users in California. | *SunZia*

In September, however, the PRC declined to let the SunZia Southwest Transmission Project go ahead, citing unresolved concerns, especially that the developers had “failed to sufficiently define the location of the transmission line route for which it seeks approval.” The commissioners denied the project without prejudice so that SunZia’s developers could firm-up their plan and resubmit it.

“We didn’t have any animus against the project at all,” PRC Vice Chair Cynthia B. Hall said. “They just weren’t ready. Things weren’t coming together in the time frames expected.”

With last-minute changes to SunZia’s submissions, “What was actually being requested became sort of a moving target,” Hall added.

SunZia’s $2 billion transmission project would consist of two bidirectional 500-kV lines with a total rating of 3,000 MW. Its proposed 520-mile path from central New Mexico south across the Rio Grande and the Sonoran Desert in Arizona has met with resistance from federal agencies, the military, environmentalists, community groups and ranchers since it was first proposed in 2008.

Some of those concerns have been resolved, particularly with the U.S. Bureau of Land Management and Defense Department, whose land the lines would cross or abut, but problems with some private landowners persist.

Today SunZia’s fate is linked with the Corona project, which would be the line’s anchor tenant.

On Tuesday, SunZia emailed RTO Insider a statement saying, “The PRC approval of Pattern’s Corona Wind Projects is a very positive development for SunZia and New Mexico.

The huge Corona Wind Projects is proposed for an area of New Mexico with the highest average wind speeds. | *Pattern Energy*

“The Corona Wind Projects are the anchor tenants for SunZia’s first line,” it continued. “This approval paves the way for SunZia to provide the PRC (and the hearing examiner [HE]) with the additional information they need to be able to approve the location of SunZia. We expect to provide this information to the PRC (and HE) in early 2019.”

For its part, Pattern urged the commissioners to weigh each project on its own merits for permitting purposes, despite the close connection between Corona and SunZia.

“They agreed that our permit should stand on its own,” said Crystal Coffman, business development manager for affiliate Pattern Energy Group, based in Houston.

Hall said the commissioners were impressed with Pattern’s compliance and planning efforts. “They had everything nailed down,” she said. And the commissioners also were excited about New Mexico potentially being home to the hemisphere’s largest wind farm. “It sure gives us a sense of pride at the moment,” she said.

Adam Renz, who handles government relations and external affairs for Pattern Energy, said the company was planning to work with SunZia on its next PRC filing to help ensure the transmission line’s approval. A major goal for the West’s biggest wind farm would be to supply energy to California as it seeks to meet its 100% clean-energy target by 2045. (See Can Calif. Go All Green Without a Western RTO?)

The best way of doing that would be through SunZia’s high-voltage lines, sending energy across the Southwest to CAISO’s territory, Renz said.

“SunZia has always been a bit of a dream project that would allow us to deliver electrons into CAISO,” he said. “At the end of the day it’s a direct long-lead line into California.”

October 10, 2018

Coal Group Seeks Reliability Bonus from MISO, SPP

By Tom Kleckner and Amanda Durish Cook

The Lignite Energy Council, a North Dakota coal lobbying group, reportedly plans to approach MISO and SPP in an effort to have them pay more for coal-fired generation.

Lignite Energy Council CEO Jason Bohrer | *Lignite Energy Council*

CEO Jason Bohrer told the group’s Oct. 3 fall meeting he thinks the LEC could show the RTOs that they should pay more for coal-fired power because it provides resilience benefits, The Bismarck Tribune reported.

Bohrer also said the council has applied for membership in MISO, saying its focus on coal energy is “sometimes overlooked in their boardroom and their circles,” according to the report.

The LEC did not respond to a request for comment, and, as of late Tuesday, MISO said it had not heard from the group. If MISO does receive a request, spokesman Mark Brown said it would likely go before the RTO’s stakeholder process for discussion.

“Without having seen a specific request from the council, we can’t speculate on these questions; however, it appears this would be a matter for our stakeholder process,” Brown said.

SPP also hasn’t been contacted. COO Carl Monroe said the RTO is aware “some in the industry” believe “particular resources deserve compensation specifically for their guaranteed availability and role in ensuring reliability.”

“We are currently considering whether and how we might accurately and fairly assess a resource’s ability to meet reliability-related requirements,” Monroe said. “We assume this may lead to modifications to our market rules and capacity requirements and eventually to a market-based solution that values particular resources differently than we do today.”

Bohrer was optimistic when the Department of Energy released its August 2017 study on grid reliability, which recommended supporting out-of-market coal and nuclear plants. (See Perry Grid Study Seeks to Aid Coal, Nuclear Generation.)

The CEO said coal “not only ensures reliability for our nation’s electric grid, it also is far less expensive than heavily subsidized renewable fuels.”

The council was disappointed, however, when FERC in January unanimously rejected DOE’s proposal and opened a docket on grid resilience. (See FERC Rejects DOE Rule, Opens RTO ‘Resilience’ Inquiry.)

“Currently, regional electricity markets do not properly compensate generators who produce ‘always on’ power or whose power is not susceptible to weather disruptions,” Bohrer said in a statement Jan. 9. “It remains our hope that FERC will ultimately level the playing field when it comes to dispatching energy sources with the long-term goal focused on a resilient grid to serve our homes, businesses and the national economy.”

Williston Basin lignite mine | *North Dakota Studies*

The council aims to maintain the viability of lignite, which is mined at five sites in North Dakota and one in eastern Montana, according to the LEC website. The group’s members include mining companies, generators and service businesses.

By participating in RTOs, Bohrer said at the conference, the LEC would make the case that wholesale markets are skewed by subsidies for renewables. “The market is a competitive market, but it is not a free market,” Bohrer said.

October 9, 2018March 8, 2024

Illinois: PJM Market Design Enriching Exelon

By Rory D. Sweeney

Transmission constraints combined with PJM’s market design and Exelon’s control of local generation allow the company to name its price for capacity commitments in the Chicago area, according to an energy economist advising the state of Illinois.

“While PJM’s Base Residual Auction has many safeguards, it does not have an explicit ability to mitigate market power on the scale exerted by Exelon in Northern Illinois,” economist Robert McCullough wrote in an affidavit commissioned by Illinois Attorney General Lisa Madigan. “Overall, it seems very likely that Northern Illinois is not well served by the existing algorithm.”

Madigan included the affidavit last week in Illinois’ brief in the FERC “paper hearing” on potential changes to PJM’s capacity market (EL18-178). Madigan’s brief said the high clearing prices in Exelon’s Commonwealth Edison zone in the Chicago area “are consistent with an economic withholding strategy.” (See related story, Little Common Ground in PJM Capacity Revamp Filings.)

At issue in the docket is whether generators that receive state or federal subsidies should have to remove the cost-lowering benefit of their subsidy from their offers into PJM’s capacity auctions.

McCullough, who has worked on RTO issues for more than three decades, says concerns over the market impacts of subsidized generation may not matter in the ComEd zone because Exelon already looms so large there. The capacity offers of individual Exelon units — such as the Quad Cities nuclear plant that receives $170 million through Illinois’ zero-emissions credit (ZEC) program — “is now irrelevant to the market clearing price in Northern Illinois,” he wrote.

“It is impossible for Northern Illinois to meet its reliability requirements without Exelon’s fleet of nuclear plants. Most importantly, the specific cost of any one of the plants is effectively irrelevant since four to five of those plants are required to meet the zone’s reliability requirements,” McCullough wrote. “Since Exelon’s portfolio determines the market price, the actual bid for Quad Cities has no impact on the outcome. Quad Cities’ capacity revenues will be set by the marginal Exelon resource. Exelon can also determine which plants will clear and which will not.”

It’s not the first time Exelon’s market power in PJM has been questioned. Five of the company’s nuclear units failed to clear in the 2014 capacity auction. But analysts said that actually boosted the company’s capacity revenues by almost $150 million because the additional supply would have dramatically reduced clearing prices. (See How Exelon Won by Losing.)

Exelon responded to the Illinois filing by insisting that its bidding strategy followed all market rules.

“In [the 2018] auction, Exelon offered its carbon-free nuclear generation at a competitive price based on each plant’s costs and risks of operation, and we did so in full compliance with all rules governing PJM capacity auctions,” the company said in an email Monday. “Because current rules treat emitting generation the same as clean generation, half of our fleet was not selected in the auction and did not earn any capacity revenues. As a result, most of the generation that ComEd customers paid for in the last auction was other generators’ fossil fuel-burning generation. That needs to change to protect customers and communities from the harmful effects of carbon and air pollution.”

Exelon threw its support in the docket behind a coalition of environmental groups, consumer advocates for Illinois and D.C., and generation companies with nuclear assets to advocate for allowing states to subsidize “clean” generation. (See Zero-Emissions Backers Propose PJM Capacity Principles.)

Three Requests

McCullough’s affidavit was developed to support the attorney general’s filing in the docket, which set a paper hearing to determine how to insulate PJM’s capacity auctions from price suppression created by subsidized generation. (See FERC Orders PJM Capacity Market Revamp.)

In her filing, Madigan urged FERC to require PJM to release bidding data from each auction as its neighbor in the state MISO does, while keeping bidders’ identities anonymous. She also asked FERC to implement a cap on what revenues subsidized resources can obtain under the fixed resource requirement (FRR) structure and to delay implementation of any changes until states can adjust their own policies to account for them. It also called for developing a minimum offer price rule (MOPR) for any subsidized resources and ensuring that units’ avoidable cost rates (ACRs) include all revenues, including those from subsidies and energy and ancillary services markets.

While other filings in the docket called for eliminating price suppression related to subsidies or ensuring that subsidized resources continue to count as capacity to cover a region’s demands, the attorney general focused on the impact of Exelon’s control of supply in the zone served by ComEd, which Exelon also owns.

“Exelon is a pivotal supplier with substantial market power to set the ComEd zone capacity price. The high clearing prices evident in the ComEd zone are consistent with an economic withholding strategy that aims to maximize revenues for a portfolio through strategic bidding of individual units,” Madigan wrote. “Under current capacity auction rules, in the ComEd zone Exelon has no incentive to adopt a bidding strategy that will result in a clearing price that is lower than a competitive price due to the thousands of megawatts of other Exelon capacity that will benefit from a higher, competitive clearing price. … There are insufficient non-nuclear resources for the ComEd zone to clear without some Exelon nuclear units clearing.”

McCullough noted that ComEd’s clearing prices increased from last year’s 2020/21 BRA that didn’t include ZECs to the most recent 2021/22 BRA that did, even though they should have fallen for at least three reasons: the ZEC law, the new tax law that substantially reduced generators’ federal taxes and the expansion of transmission capacity into ComEd.

“Notwithstanding the presence of a subsidized plant, the relatively high ComEd clearing price is consistent with the fact that the subsidized company (Exelon Generation) owns a total of 10,604 MW out of the 27,930.4 MW [that] were offered in the 2021/2022 auction,” the attorney general wrote. “With 40% of the generation owned by a single entity and a resulting [Hirschfield-Herfindahl Index] of 2,347, the ComEd zone is highly concentrated.” The index is used by federal agencies to measure the concentration of markets and considers anything about 2,500 to be “highly concentrated,” according to the Department of Justice’s Antitrust Division.

Flawed Algorithm

McCullough developed his analysis by plotting what the ComEd clearing prices would have been under several hypothetical scenarios published by PJM and its Monitor. The resulting prices and quantities “resemble a cloud of points rather than the traditional monotonic supply curve we see in actual markets” in which costs rise with output, he said.

In fact, he found that the hypothetical clearing price decreased in some scenarios where supply was added or removed, meaning that the final clearing price could have been lowered in the zone either by adding or subtracting supply and the actual price was higher than it necessarily could have been.

“By all appearances, the PJM algorithm does not work well for constrained markets,” he wrote. “The effect of ZECs or other major out-of-market payments on PJM’s capacity market is far from clear or direct. To avoid further market distortions and assure just and reasonable rates, all aspects of the market, including the market characteristics of constrained zones, market power and the details of the PJM algorithms must be part of any analysis.”

However, neither McCullough nor Madigan blamed Exelon for taking advantage of the situation. Instead, they argued it proves that the ZEC program is not suppressing prices.

McCullough said PJM staff incorrectly assumed prices would fall because Exelon would bid Quad Cities at $0/MW-day, when “Exelon could be expected to have simply adjusted its bids on other plants in its portfolio in the ComEd zone to offset the increase in supply and preserve the capacity price level.” So instead of producing the price suppression PJM predicted, “the outcome was actually the opposite to the forecasts from the PJM experts — in spite of significant cost reductions and the expansion of alternatives, the price in the ComEd zone increased from $188.12/MW-day [in the 2020/21 auction] to $195.55/MW-day [in the 2021/22 auction].”

A Complex Market

Because PJM doesn’t release bidding data, McCullough used his analysis to attempt to deconstruct PJM’s algorithm. He concurred with three issues previously identified by the Monitor that:

- - Requiring the algorithm to solve within a specific amount of time can return different results based on the speed of the computers.
  - The results can be impacted by small criteria changes.
  - The algorithm can return more than one optimal result even with identical inputs and parameters.

“When only inflexible or very high-priced offers remain, none of the auction clearing procedures identified in [Reliability Pricing Model] documents are likely to lead to the competitive optimal price predicted by economic theory,” he wrote. “Given the complexity of the PJM capacity market — far more complex than the neighboring capacity market in MISO — it is critical that FERC apply clear and transparent rules to enable review and analysis of the capacity market data and results. … In Northern Illinois, where the same company dominates both the capacity market and owns the utility serving the major capacity loads, the FRR option opens the possibility of self-dealing. In the worst possible case, the FRR might well result in prices above competitive prices for consumers while depressing prices in the BRA.”

To address the issues, he suggested both a MOPR and an offer cap for FRR units set at the net ACR calculated for each unit individually.

“Absent that cap, the capacity market in Northern Illinois will continue to clear at an uncompetitively high level irrespective of the ZEC subsidies,” McCullough wrote. “This is necessary to return the Northern Illinois market to a state as close as possible to competitive conditions where capacity prices represent the net revenues needed to enable the resource to be a capacity resource, based on costs needed to operate but not covered by other revenues.”

October 9, 2018

MISO: Sept. Emergency Response Improved by Jan. Event

By Amanda Durish Cook

Lessons from the Jan. 17 MISO South emergency resulted in smoother management of the Sept. 15 emergency in the region, RTO officials told stakeholders last week. MISO this week pledged more training and more vendor outreach during another post-mortem of last month’s emergency.

MISO had better awareness of its contract limit on SPP transmission linking its Midwest and South regions during the emergency, Senior Real Time Operations Engineer Steve Swan told the Reliability Subcommittee meeting Oct. 5.

The latest maximum generation event resulted in emergency purchases and public appeals to conserve energy. (See Emergency Ops, Calm Summer Top Talk at MISO Board Week.)

miso south emergency maximum generation event — MISO Sept 15 load and capacity | *MISO*

“Overall, performance that day between MISO and our joint parties was a lot better than the January maximum generation event,” Swan said, adding that the RTO communicated often with SPP about flows to South, which exceeded the 3,000-MW north-to-south sub-regional contract limit on the SPP line for about 15 minutes.

MISO is pledging to do more in time for the next emergency, including conducting drills on emergency purchases with external entities and continuing to work with SPP on managing the North-South contract path.

MISO analyst Dustin Grethen said the Sept. 15 emergency could probably have been helped by a reserve capacity product. The RTO hopes to complete a conceptual design of a short-term capacity reserve project by the end of the year or early 2019. It is developing a capacity product with a 30-minute ramp response time furnished by units that are both online and offline.

In September, MISO Executive Director of Market Development Jeff Bladen said that he expected the product to become “a very valuable part of MISO’s portfolio.” He said the 30-minute time span will be useful for system flexibility because wind forecasts become “very, very accurate” 30 minutes out.

Weather Forecasts

Swan said a missed weather forecast led to a 1.8-GW load forecast error in MISO South on Sept. 15. The RTO ultimately had to commit 1.1 GW above the day-ahead commitment for South after a 1.4-GW generator in the region unexpectedly tripped off late on Sept. 14.

“This is one of the worst days we’ve had for our load forecast error historically. It seemed to be a one-off,” Swan said.

The RTO was in “constant contact” with its two weather forecast vendors throughout the day of the emergency, Swan said. The vendors continued to stand by their afternoon forecasts hours before the emergency. However, hotter-than-expected weather materialized quickly, and an expected cloud cover never appeared.

After stakeholder questioning, Swan said MISO had “no reason to believe” that missed forecasts would become more common.

Some stakeholders argued that local meteorologists saw the extreme heat, asking MISO to include local forecasts in their weather predictions. We Energies’ Tony Jankowski asked the RTO to consider hiring an in-house meteorologist. However, RTO staff maintained that even local weather forecasters underestimated the heat that day. Staff said aggregate load forecasts from local balancing authorities were actually lower than MISO’s load forecast for the day.

Michigan Public Service Commission staffer Bonnie Janssen asked if MISO could work with the forecasting vendors more closely. She said it’s not uncommon for surrounding regions to experience unusual weather patterns as hurricanes make landfall. Hurricane Florence had arrived at North Carolina a day earlier on Sept. 14.

Swan said the RTO is continuing to work with the vendors on communication protocols.

2 LMRs Disqualified

Meanwhile, MISO disclosed that it had disqualified two load-modifying resources (LMRs) from providing capacity for the remainder of the 2017/18 planning year because of nonperformance during the mid-January emergency.

MISO analyst Scott Thompson said the LMRs had not updated their availability through the entire month of January or throughout the 2017 summer. They also did not respond to MISO’s scheduling instructions during the January event, nor did they participate in earlier LMR drills, he said.

“They weren’t making the effort to show up. They thought the capacity payment was good enough, but they didn’t hold up their end of the equation,” Thompson said.

FERC and NERC announced in early September that they would investigate the Jan. 17-18 cold snap and subsequent maximum generation alert for the South. (See FERC, NERC to Probe January Outages in MISO South.)

At an Oct. 4 Reliability Subcommittee meeting, Chris Miller, FERC’s liaison to MISO, reminded stakeholders that the commission’s action is simply an inquiry, not enforcement. Miller said MISO and other RTOs seemed to better handle communication during high temperatures this summer and severe weather from Florence.

October 9, 2018

FERC Denies Rehearing on SPP Tx Cost Shifts

By Tom Kleckner

FERC last week denied a rehearing request by SPP transmission owners of its earlier decision on the allocation of transmission costs, saying the TOs had not shown the RTO’s provisions had become unjust and unreasonable (EL18-20).

The commission’s Oct. 3 order affirmed its March decision, which rejected the TOs’ complaint that SPP unfairly allocates costs to incumbent TOs when a new owner is integrated into an existing transmission pricing zone.

The companies had argued that a “loophole” in SPP’s Tariff forces customers within an existing zone to pay a share of the legacy costs for transmission lines newly integrated into the zone. That practice, the complainants said, runs counter to the “no legacy cost shift” protections SPP has established. (See FERC Rejects TO Complaint on SPP Zonal Placements.)

spp ferc attr transmission costs — SPP transmission zones | *SPP*

In the March ruling, the commission said the TOs failed to carry the burden of proof to support their request for a prohibition on cost shifts. In last week’s order, FERC said the TOs also failed to prove that SPP’s Tariff is unjust and unreasonable because it lacks provisions dictating what information RTO must include in filings to add a new TO to an SPP zone to justify cost shifts.

“As the commission noted in the March 15 order, SPP will need to make an [Federal Power Act] Section 205 filing to add the ATRR [annual transmission revenue requirement] of a new transmission owner to an existing zone’s ATRR,” the commission said. “The fact that SPP’s Tariff does not expressly require this filing to justify any potential cost shifts does not change the commission’s obligation to determine that the revised ATRR is just and reasonable. … SPP, and any other proponents of the revised ATRR, still has the burden of proof to demonstrate that the rate is just and reasonable and must ensure that there is a sufficient evidentiary record for the commission to make a reasoned decision. Likewise, the fact that SPP’s Tariff does not specify that SPP must justify any potential cost shifts in its filing with the commission does not prevent parties from arguing that the allocation of the costs of a new transmission owner’s facilities to existing customers in the zone in which SPP proposes to place those facilities renders the revised ATRR unjust and unreasonable under the circumstances of the case.”

The commission noted that it considered information regarding cost shifts in its May 17 ruling on SPP’s placement of Tri-State Generation and Transmission Association in existing transmission pricing Zone 17 (ER16-204). (See FERC Rejects NPPD Objection to Tri-State Zonal Placement.)

The order “provides further assurance that the case-by-case approach to assessing the implications of cost shifts espoused in the March 15 order will not result, as indicated SPP transmission owners fear, in rate impacts being excluded from the commission’s consideration or in protesters bearing an unreasonable burden of proof,” FERC said.

The commission also reiterated its conclusion that the TOs failed to prove that cost shifts create a disincentive to RTO membership. “Indicated SPP transmission owners caution that transmission owners may be reticent to join SPP due to the potential that their customers’ rates may one day increase if other transmission owners join and are placed in the same zone. However, as the commission noted in the March 15 order, not all cost shifts will benefit the new transmission owner, and some could even benefit the existing transmission owner and its customers.”

The filing TOs were American Electric Power, on behalf of Public Service Company of Oklahoma and Southwestern Electric Power Co.; City Utilities of Springfield (Mo.); Kansas City Power & Light; KCP&L Greater Missouri Operations Co.; Nebraska Public Power District; Oklahoma Gas & Electric; Omaha Public Power District; Southwestern Public Service; Sunflower Electric Power; Mid-Kansas Electric; Westar Energy; and Western Farmers Electric Cooperative.

October 9, 2018

IPCC: Urgent Action Needed to Avoid Climate Trigger

By Michael Brooks

Climate change could have catastrophic effects sooner than previously thought and preventing them will require cooperation on an unprecedented global scale, according to a new report by the U.N.’s Intergovernmental Panel on Climate Change.

The study, released on Sunday from Incheon, South Korea, examined the effects of a 1.5-degree Celsius (2.7-degree Fahrenheit) increase in the global average temperature from 1850-1900 levels. If the current rate of global warming continues, the average temperature would hit 1.5 C by 2040, according to the report.

ipcc climate change global warming — Observed global temperature change and modeled responses to stylized anthropogenic emission and forcing pathways | *IPCC*

“It’s like a deafening, piercing smoke alarm going off in the kitchen. We have to put out the fire,” The Washington Post quoted Erik Solheim, executive director of the U.N. Environment Program. He said the world must either stop carbon emissions entirely by 2050 or find some way to remove them. “Net zero must be the new global mantra.”

The report estimates that temperatures have increased by about 1 C (1.8 F) so far, and that the impacts of that increase are already being felt in increased storm intensity, precipitation, wildfires and heat waves; rising sea levels from melting polar ice; and the nearing extinction of several species, including coral. Such impacts could disrupt the global food supply chain and cause mass migration and increased poverty, the report says.

“Extra warming on top of the ~1 degree C we have seen so far would amplify the risks and associated impacts, with implications for the world and its inhabitants,” the IPCC said in a FAQ. “This would be the case even if the total warming is held at 1.5 degrees C, just half a degree above where we are now, and would be further amplified at 2 degrees C global warming.”

The report is a result of a provision in the 2015 Paris Agreement, which saw 195 countries, including the U.S., agree to reduce their carbon dioxide emissions by 26% from 2005 levels by 2025 to prevent a 2-degree Celsius (3.6-degree Fahrenheit) increase. It was added at the request of small island nations in the tropics, which wanted the effects of a 1.5-degree increase to be studied, as they are more susceptible to rising sea levels.

To prevent a 1.5-degree increase, global CO₂ emissions would need to be reduced by 45% from 2010 levels by 2030 and 100% by 2050, according to the report. This is still possible, the authors say, but it would require a massive undertaking by the entire world.

“The speed and scale of transitions and of technological change required to limit warming to 1.5 degrees C has been observed in the past within specific sectors and technologies,” the report says. “But the geographical and economic scales at which the required rates of change in the energy, land, urban, infrastructure and industrial systems would need to take place are larger and have no documented historic precedent.”

For the electricity industry, this means dramatically reducing the use of coal and increasing the use of renewable resources for generation. This is true under every scenario, or “pathway,” studied by the report’s authors.

Coal’s share of the resource mix would need to drop to 1 to 7% by 2050, compared to 40% now, and only if large-scale carbon capture and sequestration technology is developed by then. Natural gas-fired generation would also have to be reduced by as much as 60% (though it could increase with the use of CCS), and renewables’ share would need to increase to as much as two-thirds.

The report is less sure about nuclear power. Under some scenarios global nuclear capacity increases, while it decreases in others. The report attributes this to the high cost of building nuclear plants and political opposition stemming from perceived safety risks. While some countries may elect to rely on nuclear for emission-free power, it may not be feasible for developing countries, the researchers said.

President Trump in June 2017 announced he intended to withdraw the U.S. from the Paris Agreement. The earliest the country can do so is Nov. 4, 2020. (See Trump Pulling U.S. Out of Paris Climate Accord.)

October 9, 2018

NEPOOL OKs Penalty for Delayed Capacity Resources

By Rich Heidorn Jr.

The New England Power Pool Participants Committee last week approved new penalties for ISO-NE market participants that fail to cover their capacity supply obligations (CSOs) when a new resource is delayed.

For delivery years before June 1, 2022, the monthly $/kW-month charge will be the higher of the capacity clearing price and the clearing price in any Annual Reconfiguration Auction for that year. After June 1, 2022, the charge will be based on the outcome of a second run of the third ARA, using the unproven CSO quantities as a demand bid.

The rule changes are designed to shift the responsibility for covering CSOs to participants, which ISO-NE says have the best information about projects’ development schedule and potential delays.

Market participants will still be compensated for their CSOs and continue to have Pay-for-Performance risk.

The RTO said it was acting because of the time lag between its last critical path schedule (CPS) meetings with participants in early January and the beginning of the capacity commitment period in June.

Current rules require ISO-NE to assess a new resource’s likelihood of meeting its CSO and submitting a demand bid if it is in doubt. The new rules will eliminate mandatory demand bids by the RTO for resources unable to satisfy all CPS milestones by the start of the delivery year.

The monthly charge would apply unless the participant covers the shortfall through a bilateral contract or with a resource that was previously counted as a capacity resource. Previous resources can be used for up to two years.

The changes were approved by voice vote after members rejected a proposal by PSEG Energy Resources & Trade to allow a three-month grace period before applying the charge for each year between June 2019 and May 2022. PSEG’s proposal failed with a 47.77% vote in favor (Generation Sector – 14.68%; Transmission Sector – 6.71%; Supplier Sector – 15.48; AR Sector – 5.23%; Publicly Owned Sector – 0%; End User Sector – 5.59%; and Provisional Group Member – 0.067%).

iso ne nepool capacity supply obligations csos — For delivery years beginning in June 2022, the monthly charge rate for resources unable to meet their capacity supply obligations will be based on clearing prices in the third Annual Reconfiguration Auction (ARA #3). A resource that submits and clears a demand bid in ARA3 will pay P1 (ARA3 clearing price). A resource that maintains their CSO and has unproven CSO quantities will pay the P2 rate, which will always be greater than or equal to P1. | *ISO-NE*

The approval completed Phase I of ISO-NE’s two-phase review of rules governing late projects in the FCM. Phase II will take a broader look at the participation of new resources in the market, the RTO said.

As of June 30, ISO-NE said it had identified 26 resources representing almost 30 MW of “unproven” capacity, including almost 28 MW of demand capacity and 2.1 MW of generating capacity. Last month, ISO-NE asked FERC to terminate the CSO of Invenergy’s 485-MW Clear River Energy Center Unit 1 in Rhode Island because it will not be operating in time for the delivery year beginning June 1, 2019 (ER18-2457). (See ISO-NE Asks FERC to End Clear River CSO.)

ICR Values for FCA 13

In a related matter, the Participants Committee also approved by a show of hands a net installed capacity requirement of 33,770 MW for Forward Capacity Auction 13 next year (delivery years 2022-2023). In a separate vote, the committee also approved a 33,750 MW net ICR that will be used if FERC approves the termination of Clear River Unit 1’s CSO.

Net ICRs exclude the Hydro-Quebec interconnection capability credit (HQICC), which members agreed to set at 969 MW. Including the HQICC, ISO-NE projects a reserve margin of 19.3%.

The committee also approved Tariff changes on assumptions used in the ICR calculation. One revision will reduce from 1.5% to 1.0% the amount of load relief assumed from a 5% voltage reduction. A second revision changes the assumption used for the availability of peaking resources in the transmission security analysis from a deterministic derate factor to an equivalent forced outage rate-demand for individual resources, based on their most recent five-year average.

2019 Budgets

In other action, the committee also endorsed the 2019 ISO-NE operating ($198 million) and capital ($28 million) budgets. The operating budget is up $2.9 million (1.5%) from 2018 but down $1.4 million from the preliminary budget presented in August. Including true-ups, the revenue requirement for the operating budget will drop 3.5% from the amount projected to be collected in 2018.

The capital budget is unchanged from 2018.

The committee also endorsed the New England States Committee on Electricity’s 2019 operating budget of $2.35 million, a $45,000 reduction from the five-year pro forma projections endorsed by the committee in June 2017 and accepted by FERC.

Energy Emergency Forecasting

Members unanimously approved changes to Operating Procedure 21 and its Appendix A to create an energy emergency forecasting and reporting process. It includes forecast alert thresholds, criteria for declaring energy alerts and energy emergencies and related data collection provisions.

ISO-NE said the changes are intended to improve market signals for incentivizing resource preparedness before winter 2018/19.

The energy alert thresholds will be based on an assessment of fuel and emissions availability over the next 21 days of operation.

Consent Agenda

Approved as part of the consent agenda were:

Conforming changes to ISO-NE manuals on price responsive demand, Pay-for-Performance, real-time reserve designation and settlement rules and the Forward Capacity Market; and
Revisions to provisions regarding deposits for participating in cluster transmission studies.

Presentation on Labor Day Event

ISO-NE COO Vamsi Chadalavada gave a ISO-NE Prices Top $2,400/MWh in Labor Day Heat Wave.)

Chadalavada said higher-than-forecasted temperatures and dew points, particularly in the afternoon of Sept. 3, caused the RTO’s load served to peak at 22,956 MW (23,174 MW including active DR), almost 2,400 MW (11.5%) above its load forecast.

During the 4-5 p.m. hour, the RTO fell 718 MW below the 24,775 net capability required, which includes operating reserves of 2,108 MW.

The RTO purchased 150 MW from New Brunswick between 4:20 and 5:14 p.m. and 229 MW between 5:14 and 6. NYISO provided 251 MW from 5 to 5:30 and 150 MW from 5:30 to 6.

Real-time hub five-minute LMPs ranged from $19.79 to $2,677.05/MWh for the day, with an average of $262.61.

The real-time net commitment-period compensation was the fifth highest for the year and the highest of the summer at $1.9 million, including $1.1 million in economic payments, $540,000 in dispatch lost opportunity costs and $210,000 in rapid-response pricing opportunity costs.

The high prices during the event will increase the peak energy rent adjustment by $7 million each month, for a total of $56 million, through May 31, 2019, RTO officials said.

The PER adjustment is intended as a hedge for load and a tool to discourage capacity suppliers from creating price spikes through economic or physical withholding.

The increased adjustment will affect generators, imports and active demand resources. Self-supply and passive demand resources are excluded.

ISO-NE is eliminating the PER adjustment beginning June 1. The RTO says Pay-for-Performance and changes to the day-ahead energy market made the adjustment unnecessary beyond that date. (See FERC Rejects NESCOE Request on Scarcity Rules.)

October 9, 2018

MISO: 20% Renewable Limit for Adequate Frequency Response

By Amanda Durish Cook

MISO last week said its grid can currently sustain 20% renewable penetration without damaging frequency response, the latest findings from its ongoing renewable integration impact study.

The RTO in spring published study results showing that increased renewable integration — especially solar generation — will shift peak load to evening hours, with a spikier but shorter daily loss-of-load risk. (See MISO Renewable Study Predicts Later Peak, Narrower LOLE Risk.)

miso renewable integration frequency response — MISO later daily peak under renewable integration | *MISO*

The same study now concludes that MISO can more than double its current 8% renewable share of the resource mix while still maintaining a satisfactory frequency performance. Frequency response decreases slightly but is steady up to a 20% renewable mix, with the system remaining stable after the simultaneous loss of large generators up to 4,500 MW, Jordan Bakke, MISO policy studies manager, said during an Oct. 5 Reliability Subcommittee meeting.

Some stakeholders said the study doesn’t contemplate that future storage resources could help improve frequency response.

“I think it’s important to point out that this study doesn’t include storage, and I think storage could really help the system,” said Dave Johnston, an Indiana Utility Regulatory Commission staffer.

Bakke said the study was conducted with the assumption that frequency response services will continue to go uncompensated.

“To the point we’ve gotten so far, storage hasn’t been needed to solve an identified [frequency response] issue,” Bakke said.

Early this year, FERC declined to order the RTO to compensate providers of primary frequency response, as Indianapolis Power and Light had requested. (See FERC OKs MISO Plan to Expand Storage.)

Coalition of Midwest Transmission Customers attorney Jim Dauphinais pointed out that FERC’s Order 842 requires new generators to be capable of providing primary frequency response as a condition of interconnection.

Bakke said MISO’s study did assume new generators “could provide it, but they won’t because there’s no incentive to provide.”

MISO will continue to work on its renewable integration study through early next year. Bakke said the RTO will likely convene a stakeholder workshop on study results so far in November.

October 9, 2018

Soapbox: PJM Doubling Down on the Wrong Capacity Solution

By Eric Gimon

pjm rpm capacity pricing reform — Eric Gimon | *Energy Innovation Policy & Technology*

It’s easy to love electricity markets. Mathematical algorithms efficiently, safely and transparently dispatch grid resources to match supply and demand. Market signals drive the most valuable grid additions and retirements over time, providing customer savings and a stable investment environment incorporating technology and input cost changes.

PJM has led power market development, embracing rising trends like demand response and grid-scale battery storage. But lately, PJM has doubled down on a “solution” leading down an ever-more complicated and fractious path: its Reliability Pricing Model capacity market.

Electricity power markets are not perfect; critics often cite the “missing money” problem, which contends — with only marginal justification — that price signals balance markets but do not sustain adequate system resources to guarantee supply matches demand. To address this, PJM created a singular “capacity” commodity traded in the RPM, which loads must purchase.

While the RPM has been a boon for some resources, a singular definition of capacity never fairly captures everything the grid needs, and the RPM is open to three criticisms:

First, it tends to overpay some resources without offering premiums to ones that provide more grid services than just megawatts. Imagine forcing a museum to purchase insurance on its art collection with a flat rate on a Rembrandt or a painting from a local artist.
Second, with the RPM, PJM is eschewing part of its system optimizer role by requiring individual or self-assembled coalitions of resources to provide capacity products instead of assembling a diverse set of resources to meet reliability needs.
Third, a conservative organization like PJM naturally tends to forecast higher demand, just in case, effectively forcing customers to buy too much insurance.

Predictably, the RPM has cannibalized energy market revenues in favor of capacity markets and allowed uneconomic legacy coal and nuclear assets to create a large capacity overhang (>30% reserve margin in summer 2018 against a desired ~16%).

Today’s power markets are also flawed by not pricing externalities. Seeing nuclear generators, which have provided free emissions mitigation, on the verge of going under, states like Illinois decided to provide direct financial support. These “out-of-market subsidies” (terminology that ignores other existing direct and indirect subsidies) became PJM’s new bugbear, which contends state-sponsored resources drive prices “too low.”

Last June, PJM wanted to double down on capacity markets by re-engineering them to force some resources to overbid at minimum offer prices to “mitigate” impacts of state policies, making customers double-pay for capacity instead of allowing markets to re-equilibrate by closing uneconomic resources.

Because of push back from FERC, which wants to allow matched resources and load to opt out of the RPM, PJM is doubling down again, striving to protect existing resources at all costs by proposing a two-stage capacity market called the extended Resource Carve-Out (RCO).

Extended RCO forces certain resources to offer into the capacity market at a higher price than their direct costs if they want to participate, or “allows” those resources to opt out of RPM by offering into the auction at a zero price. After this first stage of the two-stage capacity market, PJM determines which resources clear. In the second stage of the two-stage capacity market, PJM would then carve-out the opt-out resources and rerun the auction with the same demand curve to determine a higher clearing price to be paid to all non-carve-out resources that cleared in the first stage.

This would cause serious — and unnecessary — additional consumer expense.

Furthermore, extended RCO has yet another component: a payment to resources that would have cleared the second auction but not the first (the one that identified the actually needed capacity resources). This proposal extravagantly pays these so-called inframarginal resources even though they neither incur a capacity obligation nor provide capacity to PJM customers.

PJM committed the original sin of getting into capacity markets (Band-Aid solutions FERC historically expected to wither away). Over time, these capacity markets cannibalized energy markets, required constant “fixing,” and became the last refuge of increasingly uneconomic legacy assets.

When low natural gas prices and states interested in shaping their resource mixes started to fray this safety line, PJM took a protectionist line and started treating states like monopsonist market manipulators. Then, when FERC — unfortunately sympathetic to these protectionist views — tried to offer a fig leaf to states with opt-out, PJM doubled down on its twisted economic logic to make even that unworkable and expensive.

What should PJM do instead? At the very least, it should allow loads and grid resources to sort out capacity needs bilaterally and unfettered if the RPM seems unfair.

But when you’re in a hole, stop digging! Instead of doubling down on unworkable capacity constructs, PJM should double down on real markets and seek a new paradigm, working with states, that gets it out of the capacity business altogether.

Eric Gimon is a senior fellow with Energy Innovation Policy & Technology, which “works with national and regional decision makers to develop policies that will manage the grid’s transition to a cleaner, lower-carbon resource mix.” Eric holds a B.S. and M.S. from Stanford University in mathematics and physics, and a Ph.D. in physics from UC Santa Barbara.