Page 1237 – RTO Insider

May 27, 2019January 25, 2024

Overheard at AWEA WINDPOWER 2019

HOUSTON — American Wind Energy Association CEO Tom Kiernan kicked off last week’s WINDPOWER 2019, the group’s annual conference and trade show, by reeling off statistics on what he called the wind industry’s “extraordinary momentum.”

- - More than 39 GW of wind capacity under construction or in advanced development. “That’s like building [the wind capacity of] Texas, Iowa and California all over again,” Kiernan said during his May 21 welcoming address.
  - More than 97 GW of installed wind capacity nationwide through the first quarter of 2019, nearing the 100-GW mark.
  - A record number of industry employees, with 114,000 “in all 50 states.”
  - $1 billion in annual economic support “to the communities we live in and work in,” and another $250 million in annual land-use payments.

The industry still faces challenges, Kiernan acknowledged. The federal tax credits that helped fuel wind energy’s growth begin to phase out in 2021. The industry faces uncertainty with laws that differ state by state and opposition to transmission development.

Kiernan said AWEA’s agenda is focused on three programs: market design and transmission; a carbon price; and “scientific, evidence-based best practices” for siting turbines.

“We’re seeking market rules in each RTO that will enable utility-scale wind and solar to compete fairly for all the services on the grid,” he said. “We’d like to see FERC create a national transmission system to allow congestion and curtailment to decline.”

Kiernan called for “meaningful legislation” that will create a carbon price. “Fortunately, politicians in D.C. and the states and around the world are talking about carbon more than ever before,” he said.

“On the left, you have the Green New Deal. On the right, more productive conversations than we’ve ever had before,” Kiernan said. “The future of our industry, the future of the clean grid, the future of our economy [and] the future of our planet will depend upon our success in working with our partners to implement solutions to these problems.”

“This is an exciting time in the wind industry, with a tremendous development pipeline and 97 GW operating today,” said Duke Energy Renewables President Rob Caldwell, AWEA’s incoming board chair. “I feel really fortunate we will hit 100 GW in my term.”

Cost-effective Solutions

Kiernan moderated a panel of industry leaders that addressed how to ensure the industry continues to provide cost-effective solutions and collaborates to continue its push toward a clean-energy economy.

“It now feels like in the renewable section, it’s not a question of if, but a question of wind and how. When solar? When storage?” said Michael Skelly, late of Clean Line Energy and now a senior adviser with Lazard Asset Management. The wind industry is “right on top of the avoided cost, even without tax credits. With gas at $3/MMBtu or $4/MMBtu and if we can get the infrastructure, create the markets and properly site these projects, there’s a tremendous amount of headroom.”

“We’re not going to have an integrated grid until people focus on connectivity. We need a big system to move electrons a lot easier … so it doesn’t matter where you are when you produce,” Pattern Energy CEO Michael Garland said. “We as an industry have to get behind some of these initiatives in Congress, like the infrastructure bill, to support transmission. Most people don’t want transmission in the backyard, and it only takes a few people to stop it. We’re seeing resistance in solar right now that we didn’t use to … it’ll get more complex.”

Google’s head of energy strategy, Neha Palmer, said her company is seeking “viable mechanisms” to allow it to buy all the renewable power it needs. Google last year said it had reached its 100% renewable energy target, and it has completed more than 6 GW of renewable energy contracts.

“We want products to deliver renewable energy that helps us meet our goal. What we need now is power,” she said. “We would like to see renewable generation tailored to provide that service. We all have this 100% goal. The next stage is matching our consumption with the supply.”

“Power markets pull those things together,” Skelly said. “If you have markets designed properly, and they work well, in theory, you ought to be able to place different resources where they work most efficiently.”

Researchers See Continued Opportunities

Research analysts shared their prognostications for the renewables industry, forecasting flat load growth but increased opportunities for both wind and solar energy.

Dan Shreve, head of global wind research for Wood Mackenzie, said wind energy is “absolutely maturing” and becoming a “bigger and bigger part of the energy puzzle.”

“It’s important to understand how wind fits in when you’re talking about adding new generation into the power mix,” he said, projecting flat load growth until 2040, when he expects 80 million electric vehicles to be on U.S. roadways. “It’ll be quite a while to wait to make that larger impact for new power demands on the grid. We’re looking at a levelized cost of electricity from wind, solar and natural gas. They’re the favored elements. That massive adoption of energy renewables comes at a cost to someone, and here it’s coal and nuclear.”

Shreve foresees continued coal plant retirements, as does David Hostert, head of wind research for Bloomberg New Energy Finance.

“Half of the U.S. coal capacity is waiting for someone else to close so they can make their money,” Hostert said. “There is a significant portion of capacity that is going to retire … and will create an opportunity as it needs to be replaced.”

IHS Associate Director Max Cohen sees wind and solar combining to capture 25% of the Lower 48’s electric production by 2040, with solar accounting for 9% by itself. He projects coal’s contributions to slip to 6%, with nuclear at 14%.

“We’ve been boosting solar more than wind,” Cohen said, noting that the economics for wind energy are still “robust,” even under a 20% production tax credit (PTC). “The economics slowly get better, but we see more solar installed every year than wind, starting in 2021. There’s an upside for wind, but state policies can be heavy-handed in their approach” with their support for existing nuclear energy.

Ryan Wiser, a senior scientist at the Lawrence Berkeley National Lab, said the decreasing cost of wind energy — a 69% reduction over the last 10 years — is enough to withstand the PTC’s phaseout by 2024. Those tax credits generate about $23/MW during a wind project’s first decade of operation.

“There are a variety of mechanisms or tools for the wind industry or broader energy sector to press down the cost of wind … even as penetration increases,” Wiser said. “The gap after the current PTC cycle won’t be long.”

“We’re hearing about single-digit [power purchase agreements] in ERCOT and SPP. Is that sustainable? Certainly not,” Shreve said, noting that maturing technology means subsidies are no longer required to beat new gas generation prices. “The PTCs have absolutely been instrumental in driving demand in the U.S. market for 20-plus years. If you’re talking about PPAs in the single digits, I think the [PTCs’] time has come.”

“I hope it isn’t the valley of death we all feared a few years ago,” Hostert said.

NARUC’s Wagner Cautiously Approaches Change

Iowa Utilities Board Commissioner Nick Wagner, president of the National Association of Regulatory Utility Commissioners, injected a note of caution to the festivities as he detailed the group’s focus on wind energy and the grid of the future.

“Nationally, we need to look at where it makes the most sense to put the resources, so we can reduce costs for everybody in the long run,” Wagner said. “While it seems maybe this industry is in its glory days and things look good, ask coal, gas and nuclear what they have to offer, because they’ve been in this same situation. At one point, the nuclear industry thought it would get to the point where it’s too cheap to measure.

“As we work through what we’re doing, ask what could change. There are things that can change very quickly, and we need to be prepared for those things,” he said.

Wagner proudly noted the leadership role his home state has played in the wind industry’s development. He said U.S. Sen. Chuck Grassley (R-Iowa) considers himself the father of the PTCs and that the state was the first to have a renewable portfolio standard.

“That requirement was 115 MW. It’s sort of a joke to us in Iowa,” Wagner said, pointing to the state’s current 9 GW of capacity.

He said Iowa’s advanced ratemaking allows the state “to build generation with regulatory certainty,” but he warned about major regulatory modifications during times of rapid change.

“I haven’t been in the industry for 30 years, but people tell me this is one of the fastest changes we’ve seen,” Wagner said. “I don’t agree we need a new regulatory model, but we have to balance the interests between the consumers and utilities. We want to be careful that, as things change, we don’t create a group of forgotten people with our decisions.”

Transmission Development a Key

Wagner said his state’s success with renewables was “not anything Iowa did.”

“The key to success is the RTOs,” he said. “Iowa could not be able to generate as much [wind energy] as we do without the benefit of being involved with MISO.”

Other speakers agreed with Wagner about the importance of RTOs and transmission development.

“There’s a lot of interest in moving to 100% renewables,” Shreve said. “It’s going to be increasingly important for long-haul bulk transmission to support those endeavors, if they want to support resiliency.”

“I think permitting is getting harder. We need more transmission to tap into the great resources around the country and move it around,” Garland said.

“We really need to get more transmission to where the demand is,” said Cohen, who expects transmission construction “ticking down.”

“A lot of what’s been done for transmission is hardening for weather or upgrading,” he said. “We don’t see a lot of transmission for wind. There’s kind of a transmission fatigue. They’ve kind of built what they’ve built, and they’re done.”

CLEANPOWER Hub to be Added to 2020 Event

AWEA welcomed nearly 8,000 attendees to its annual exhibition held May 20-23 at the George R. Brown Convention Center, with its largest exhibit hall in five years. Organizers are projecting 10,000 attendees at the 2020 event, which will be held June 1-4 in Denver.

The organization announced next year’s event will include a new exhibition hub, called CLEANPOWER, that will bring together the utility-scale wind power, solar power and energy storage industries. Kiernan said AWEA is “throwing the doors open” in creating more opportunities for industry representatives to learn from each other and do business.

“We’re seeing a lot of wind and solar on the grid just working really well together and helping to smooth out our variable production,” Kiernan said. “We hear from many of you that you do as much solar business at WINDPOWER as you do wind business. We like that. CLEANPOWER will be your hub for clean power moving forward.”

— Tom Kleckner

May 27, 2019

FERC Rejects New England Tx Rate Settlement

By Michael Kuser and Robert Mullin

FERC on Wednesday rejected a contested offer of settlement on network service rates for a group of New England transmission owners (NETOs) (ER18-223 5 , EL16-19).

The settlement proposed new rates and a new rate design for regional network service (RNS), local network integration transmission service (LNS) and point-to-point (PTP) transmission service for all the TOs in the region. It would have replaced the existing RNS and LNS rates with new formula rate templates and associated protocols. The PTP rates fall under the same Tariff schedule as LNS.

FERC instituted the proceeding in December 2015, saying ISO-NE’s Tariff “lacks adequate transparency and challenge procedures” on the NETOs’ formula rates and that the network rates “lack sufficient detail” to determine how costs are derived and recovered.

In responding to requests for rehearing of its December 2015 order that established hearing and settlement judge procedures over the matter, the commission noted that it would not be possible to ensure the justness and reasonableness of the transmission rates in the ISO-NE Transmission, Markets and Services Tariff unless the NETOs “were all considered together in a single proceeding due to the possibility of a mismatch in the synchronization of the rates, timing of true-ups, cost allocation or methodology for calculating the RNS rate and LNS rates.”

Last September, the New England States Committee on Electricity (NESCOE), New England Power Pool Participants Committee and the NETOs separately filed comments in support of the settlement, while municipal utilities individually submitted comments in opposition.

The municipals contended that the settlement disadvantaged them by imposing costs for local — or “non-pool” — transmission facilities that provide them with no material benefit. They also contested the settlement’s inclusion of a five-year moratorium prohibiting Federal Power Act Section 205 or Section 206 filings to change the settlement. They argued that it was “heavily lopsided” because it would have subjected non-settling parties to the “most stringent standard of review under applicable law” in challenges under Section 206 while its exceptions “essentially eliminate most constraints that a moratorium would otherwise impose on the Section 205 filing rights of a transmission-owning utility.”

FERC trial staff argued that the settlement was unfair because it contained unreasonable rates and “contains fundamental defects.” Staff cited the TOs’ ability to: conduct “extra-formulaic, ad hoc” ratemaking for all externally sourced inputs every year; over-recover certain plant costs; and recover a return greater than 50% of funding for construction work in progress.

In its order rejecting the settlement, FERC noted that under the approach outlined in its Trailblazer decision, the commission may approve a contested settlement if it determines that “the contesting party’s interest is sufficiently attenuated that the settlement can be analyzed under the fair and reasonable standard applicable to uncontested settlements” and that it makes an independent finding that the settlement benefits the “directly affected” settling parties.

“Here, there are two obstacles to this approach,” FERC wrote. “First, the record is insufficient to determine whether the settlement’s benefits outweigh the objections to it; in fact, contesting municipals present evidence that there is more harm than benefit. Second, the parties who are directly affected by the settlement’s RNS and LNS rate calculation provisions include both parties who support the settlement (NETOs) and those who oppose the settlement (contesting municipals).”

The commission said that based on “the overall lack of necessary detail and transparency,” it could not accept the settlement, and it remanded the proceeding to the chief judge to resume hearing or settlement procedures.

The next day, the chief judge issued a procedural order assigning a hearing judge, a procedural track for the hearing, and a dispute resolution specialist to serve as a settlement facilitator.

The NETOs are Central Maine Power; Emera Maine; Eversource Energy Service; Fitchburg Gas and Electric Light; Maine Electric Power; National Grid; Unitil Energy Systems; United Illuminating Co.; Vermont Electric Power Co.; and Vermont Transco.

May 27, 2019

ALJ Endorses CPUC ‘Stress Test’ on 2017 Wildfire Costs

By Hudson Sangree

The California Public Utilities Commission late Friday released an administrative law judge’s proposed ruling approving staff’s “stress test” methodology for determining rate recovery for 2017 wildfire costs, part of an effort to maintain the credit ratings of the state’s investor-owned utilities.

The methodology, mandated under last year’s SB 901, seeks to balance the IOUs’ financial health against the impact of rate increases on consumers. (See California Wildfire Bill Goes to Governor.)

The proposed ruling would not apply to Pacific Gas and Electric, however, because it exempts utilities that have filed for Chapter 11 bankruptcy reorganization. PG&E filed for bankruptcy Jan. 29, citing, in part, its liability for a series of 2017 blazes that tore through Northern California wine country and the Sierra Nevada foothills.

CPUC — The California Public Utilities Commission released an administrative law judge’s proposed ruling approving staff’s “stress test” methodology for determining rate recovery for 2017 wildfire costs. | U.S. Forest Service

The 2018 Camp Fire, the deadliest and most destructive fire in state history, is not covered under the bill’s stress-test provision, though lawmakers may yet apply SB 901’s requirements to 2018 fires and future blazes. State investigators recently blamed the Camp Fire on PG&E equipment. (See Cal Fire Pins Deadly Camp Fire on PG&E.)

The most obvious application of the proposed ruling would be to Southern California Edison. State investigators determined SCE’s power lines sparked the Thomas Fire, a 280,000-acre blaze in Santa Barbara and Ventura counties that killed two people and later caused a mudflow that killed 21. (See Edison Takes Par tial Blame for Wildfire in Earnings Call.)

The ALJ’s decision has no legal effect until the CPUC approves it. The commission may consider the ALJ’s proposed order as early as its June 27 meeting.

In the “normal course of regulation of investor-owned utilities, a utility seeks recovery of its anticipated costs of operations and a reasonable return on its investments from ratepayers and seeks equity and debt from public markets to fund those operations in advance of the recovery permitted from ratepayers,” Judge Robert W. Haga wrote.

“In the case of a utility exposed to extraordinary costs as a result of a catastrophic 2017 wildfire, however, Senate Bill 901 … adds an exception to the process of rate regulation of investor-owned utilities. Public Utilities Code Section 451.2(b) enacts a new limitation on recovery of such costs from ratepayers and requires the commission to determine the maximum amount, after assessing the financial status of the electrical corporation … that the corporation can pay without harming ratepayers because of an increased cost for access to capital markets, or materially impacting its ability to provide adequate and safe service from inadequate financial resources.”

The main driver of the stress test “is the implied maximum additional debt that a utility can take on and maintain a minimum investment grade issuer-level credit rating” based on the ratings of Moody’s Corp. and S&P Global, Haga wrote.

Earlier this year, investor services downgraded the credit ratings of PG&E, SCE and Sempra Energy, the parent company of San Diego Gas & Electric, to junk-bond or near-junk status because of wildfire liability worries. California holds utilities strictly liable for fires sparked by their equipment under a state constitutional doctrine known as inverse condemnation. (See Calif. Must Limit Wildfire Liability, Governor Says.)

“The stress test therefore focuses on maintaining an investment grade credit rating because this metric is a predictable indicator of a utility’s ability to access capital markets on reasonable, acceptable terms, which is critical to avoid materially impacting its ability to provide adequate and safe service. … In addition to materially impacting a utility’s ability to provide safe and adequate service, utility ratings below investment grade have negative impacts that harm ratepayers. … The stress-test model therefore looks at the utility’s ability to take on additional debt while maintaining an investment grade credit rating, in order to also minimize financial harm to ratepayers,” Haga wrote.

The proposed decision wouldn’t affect PG&E, he said, because “an electrical corporation that has filed for relief under Chapter 11 of the Bankruptcy Code may not access the stress test to recover costs in an application under Section 451.2(b), because the commission cannot determine the corporation’s ‘financial status,’ which includes, among other considerations, its capital structure, liquidity needs and liabilities, as required by Section 451.2(b), as well as its capacity to take on additional, and all cash or resources that are reasonably available to the utility.”

May 27, 2019

California Utilities Prepare as Fire Season Looms

By Hudson Sangree

SACRAMENTO, Calif. — Utilities are bracing for another fire season as the state heads into summer, but officials say troubling questions remain about how to gauge their level of readiness.

Pacific Gas and Electric said widespread power shutdowns will be a key part of its strategy following two years of catastrophic fires fueled by high winds and dry vegetation. The Camp Fire, sparked by PG&E equipment Nov. 8, was the deadliest and most destructive in state history.

The state’s two other large investor-owned utilities, San Diego Gas & Electric and Southern California Edison, have employed strategic shutdowns for years, but this could be the first season that tactics used in drier Southern California are regularly deployed in relatively rainy Northern California.

PG&E has used intentional blackouts only once before, when it first started the practice last October. (See Fire Season Becomes Blackout Time in California.)

“We will only turn off power for public safety and only as a last resort to keep our customers and communities safe,” PG&E said in a news release, responding to controversy surrounding the program.

The Camp Fire and a rash of deadly fires in 2017 led PG&E to file for bankruptcy in January, shake up its leadership and boost fire-prevention practices. (See PG&E Names New CEO , Board Members.)

The utility’s Public Safety Power Shutoff program now includes roughly 25,000 miles of distribution lines, up from 7,000 last year, and about 5,500 miles of transmission lines, including 500-kV lines, an increase from 373 miles at 70 kV and below in 2018. The p lan affects potentially millions of customers in areas of elevated and extreme fire risk in the state’s coastal regions, mountains and foothills.

‘Uncharted Waters’

At a legislative hearing last week, representatives of the IOUs and an official from the California Public Utilities Commission outlined additional measures and shortcomings in the state’s firefighting arsenal. The hearing of the Assembly Utilities and Energy Committee examined the IOU’s wildfire mitigation plans filed with the CPUC earlier this year. (See PG&E Lays out Billion-dollar Wildfire Plan.)

“We’re in uncharted waters,” committee Chairman Chris Holden said.

Sumeet Singh, in charge of PG&E’s wildfire safety program, said the utility has installed 350 weather monitoring stations and plans to have 1,300 by 2020. It has installed 30 high-definition fire-detection cameras and is aiming for three times as many in 2019. The cameras allow firefighters to more quickly verify the location of a fire and monitor its progress before arriving on the scene.

“We’re looking to get to 100 cameras by the end of this year” and to establish remote visual coverage of 90% of PG&E’s high-risk fire areas in the next two to three years, he said.

PG&E said it is making a major push to inspect and harden its grid, which covers 70,000 square miles of Northern and Central California, or 42% of the state. A federal judge overseeing the utility’s criminal probation in the San Bruno gas pipeline explosion case has put pressure on the company to increase inspections and fix problems. (See Judge Postpones Strict Probation Conditions for PG&E.)

“We launched an aggressive inspection program [in] December of 2018, where we moved forward with inspecting all of our transmission infrastructure in the high-fire-risk areas, and we are near completion of doing the same for our distribution system,” Singh told lawmakers. “This really entails an unprecedented level of effort that we have undertaken within our service territory.”

Singh said PG&E has increased transmission line inspections by 130% this year and ramped up inspections of distribution lines by 400%, using a combination of drones, helicopters and workers. The company has turned to Silicon Valley to adopt machine learning to identify potential problems using powerline imaging, he said. (See Silicon Valley Tackles Wildfire Prevention.)

The company is boosting its vegetation management, including clearing branches that overhang bare wires even when its vegetation clearances meet regulatory standards, he said. Half of all ignitions occur when overhanging vegetation contacts power lines, Singh said.

Replacing wooden poles with composite ones and strategically burying some power lines are among other grid hardening strategies, he said. The utility recently said it would bury new power lines in Paradise, as the town is rebuilt.

Gaps in Expertise, Resources

PG&E’s moves mirror those undertaken by SDG&E in the last decade after a series of devastating wind-driven fires in San Diego County in the early 2000s. The combination of 175 weather stations, more than 100 cameras, de-energization and grid hardening has eliminated major wildfires sparked by power lines in the utility’s service territory, said Brian D’Agostino, director of fire science and climate adaptation at SDG&E.

“Since we’ve implemented this plan over a decade ago, we have not seen a catastrophic wildfire ignited by electrical equipment across our region,” D’Agostino told the committee.

The company has spent $1.4 billion in its effort and is continuing to improve, he said. Expanding the use of easements as firebreaks is a current focus, he said. So is tracking “every spark,” he said.

SCE has adopted similar techniques and is pursuing others along the same lines as SDG&E and PG&E.

“They build upon programs we’ve had for many years — things we’ve done in response to redline warnings,” said Phil Herrington, senior vice president of transmission and distribution for SCE.

About one in 10 wildfires in California are ignited by electrical equipment, but a higher proportion of those fires grow into destructive blazes, state fire officials said.

Elizaveta Malashenko, the CPUC’s deputy executive director of safety and enforcement, said the utilities’ efforts may be laudable, but their timelines for completion remain uncertain, and no industry-wide standards exist for wildfire prevention. Last year’s omnibus wildfire bill, SB 901, required mitigation plans to be filed with the CPUC, yet evaluation has proven difficult without longer-term data, she said.

“The PUC isn’t set up to top the expertise of utilities … so I think that’s a gap,” Malashenko said.

“I think we also lack a vision of where are we going with all of this,” she said. “There’s a lot of activity that’s being proposed as part of wildfire mitigation plans, and it looks like the right type of activity, but we don’t really have an articulated vision of what goals we are trying to hit in the future.

“We hear a lot of statements of, ‘This is going to take a long time. We shouldn’t expect that this first round of wildfire mitigation plans and these efforts that utilities are putting in place right now will address all wildfire problems this year.’ … But I think we need to unpack this a bit more and get more specific,” she told the committee.

“What does this mean? How long of a roadmap are we talking about? Are we talking about being able to see measurable results in five years, in three years, in 10 years, in 50 years? How are we going to track that, and what does the system of the future look like?”

Regarding wildfire compliance, there are no black-and-white rules like a building code, she said. And the CPUC was never designed to inspect power lines. “That capability is nonexistent,” Malashenko said.

Every foot of rail line in the state is regularly inspected by CPUC personnel. Doing the same with power lines would require 1,300 to 1,500 additional workers and an annual budget of $125 million, she told lawmakers.

“To me, the question here isn’t which agency does it, but that this gap exists, and we need to recognize it,” she said.

May 27, 2019

Steering Committee Advances Roadmap Suggestions

By Amanda Durish Cook

MISO’s Steering Committee last week routed eight new market improvement proposals to stakeholders for debate and prioritization by voting.

During a Wednesday conference call, the Steering Committee said eight of the 11 ideas submitted met the criteria to be considered in the Integrat e d Roadmap list of market improvements due later this year. They will be ranked by staff and stakeholders alongside existing Roadmap ideas from previous years.

The Steering Committee does not debate the merits of Roadmap candidates, leaving that instead to the Market Subcommittee and the Resource Adequacy Subcommittee.

Main Line Ideas

The package contains three ideas from Main Line Generation, including a suggestion that MISO include energy efficiency measurements in its load forecasting method.

“At present, there is no clear articulation of the process by which energy efficiency measures are included in the demand side of the MISO Planning Resource Auction,” Main Line said.

Some Steering Committee members argued that the proposal was a waste of time because energy efficiency only accounts for about 312 MW of capacity in the footprint and that stakeholders have already spent enough time on the matter. Nevertheless, the item was moved for Roadmap consideration.

Main Line also recommended that MISO develop a way to verify the accuracy of coincident peak load forecasts provided by load-serving entities. While the RTO conducts a random sampling to check load forecasts, Main Line called the current method an “opaque process where stakeholders and MISO are not provided with a detailed understanding of the key drivers of the large majority of the load forecasts provided.”

Finally, Main Line asked that MISO adopt a sloped demand curve in its capacity auction. This is the first time the oft repeated call for a sloped demand curve has ever made it to the Roadmap process.

Monitor Recommendations

The committee advanced two ideas from Independent Market Monitor David Patton, who recommended the RTO use a lower generator shift factor (GSF) cutoff for transmission constraints with limited relief. MISO currently employs a 1.5% GSF cutoff to identify which generators to optimize in its dispatch when managing the flows on a constraint, but the Monitor said that policy “eliminates most or all of the economic relief available” for some constraints.

Patton also said MISO should reduce the unpredictability of its emergency pricing by implementing fixed default floors. Emergency pricing default floors are currently set by a supplier’s offer, which can result in them being either too high or too low under different circumstances, Patton said. He also said the RTO should better calculate megawatt limits on its North-South contract path during emergency pricing events.

Other Recommendations

Among the remaining ideas was a recommendation by Indianapolis Power & Light that MISO introduce a financial incentive for market participants providing primary frequency response, in line with the company’s unsuccessful 2016 FERC complaint. MISO had placed the item in its Roadmap “parking lot” in 2018, putting discussion on hold.

Clean Grid Alliance asked MISO to begin preparations to move to a “universal participation model” that would “eliminate the need for technology-specific generator models.” The group said the removal of standard generator models would allow any technically capable resource to participate in the RTO’s markets. CGA’s Natalie McIntire clarified that the group is only proposing that MISO scope the system changes required to forgo differing models sometime in the future.

Finally, MISO Market Strategy Adviser Lakisha Johnson said the RTO should focus on improving its scarcity pricing and price formation so it can meet needs across all hours and during scarcity pricing in nonemergency events. “Continuously improving scarcity pricing provides incentives for resources to follow MISO’s dispatch,” Johnson said. Some Steering Committee members criticized the idea as too broad.

Direct Path to Stakeholders

Three ideas from Patton were not included in the Roadmap package, instead going directly before other committees for discussion or because they were already being considered as part of the ongoing Resource Availability and Need (RAN) effort. Those ideas include:

A recommendation that MISO improve capacity accreditation in the long term by establishing accreditation on resource availability “during high-load or tight supply periods.” Steering Committee members said the idea was best included in the RAN project, which already aims to evaluate the overall process of capacity accreditation.
A recommendation that MISO improve outage data for capacity calculations by treating unreported outages and derates as forced outages and accounting for the fact that “forced outages may occur when a resource would not have been dispatched.” The Steering Committee said the issue is already being considered in RAN discussions.
A suggestion that MISO improve the calculation of capacity requirements by factoring in the obligation to serve behind-the meter load and accounting for the lead times of load-modifying resources and other emergency resources in the loss-of-load expectation (LOLE) study. Patton said MISO’s LOLE studies “essentially assume that [LMRs and emergency resources] provide more reliability value to the system than they do in reality.”

Meanwhile, the eight forwarded ideas will go before stakeholders for ranking next month. MISO has planned an Aug. 8 stakeholder workshop to review the prioritization of improvements. A final report on how it will order the improvements in the Roadmap won’t be complete until November.

May 27, 2019

MISO Undecided on Amending Storage Plan

By Amanda Durish Cook

CARMEL, Ind. — MISO is still pondering whether to amend its Order 841 compliance filing, after FERC earlier this month rejected multiple requests to alter the landmark order requiring RTOs to provide storage resources access to their markets.

As part of its May 16 ruling (Order 841-A), the commission rejected MISO’s requests to reconsider compliance deadlines and consider a phase-in for minimum size requirements for storage participation. (See FERC Upholds Electric Storage Order.)

“MISO is still reviewing Order 841-A,” Kevin Vannoy, the RTO’s director of market design, said at an Energy Storage Task Force (ESTF) meeting Thursday. “To the extent in our review of the order that we need to review our compliance filing, or amend it, we may or may not do that. We’re still deciding.”

In the meantime, MISO is waiting on FERC to act on its compliance filing, which includes both a request to delay a storage participation model until 2021 and limit the participation of storage resources 1 MW and smaller to 50 in the first year of compliance and 150 in the second year. (See MISO Requests Storage Compliance Delay into 2021.) MISO has said it will gradually increase the number of small storage devices in its market as it “improves its software’s capability to manage them.”

RTO staff have said they expect a response from the commission in July, and Vannoy reminded stakeholders that MISO’s filing is still open for comments.

“FERC has time to review and folks can comment,” he said.

MISO has said its phased approach is a “reasonable precaution to proactively address the potential for large numbers of small electric storage resources, rather than waiting to react to adverse impacts of future high volumes of small electric storage resources.”

But FERC maintains that benefits of increased competition will outweigh complexity and implementation costs.

In Order 841-A, the commission said the 100-kW minimum size requirement is a “balance between the benefits of increased competition fostered by the opportunity for smaller resources to participate in the RTO/ISO markets … and the potential need to update RTO/ISO market clearing software to effectively model and dispatch these smaller resources.”

“We continue to believe that, given the record showing that all RTOs/ISOs are already accommodating the participation of smaller resources in their markets and the commission’s willingness to consider requests to increase the minimum size requirement in the future, we are providing the RTOs/ISOs with adequate time to develop the requisite tariff language and update their modeling and dispatch software to comply,” FERC said.

The commission repeated its position that any RTO experiencing difficulty calculating the market after an influx of storage participation could file a request to increase the minimum size requirement. It also pointed out that its compliance directives don’t include any of the distributed energy resource aggregation rules that were first considered in its original Notice of Proposed Rulemaking, making compliance less burdensome.

“We continue to find that the timeline for compliance and implementation is reasonable,” FERC said, adding that it will not allow individual RTOs to propose their own compliance timelines.

Vannoy said MISO’s request for delay had lined up with the early delivery of its new market system platform by a third-party vendor in 2021.

Next up: Hybrid Resources

The Thursday meeting was the last in-person meet-up of the ESTF before it sunsets next month after a year and a half of service. The group will provide a final report of potential storage topics to the Steering Committee, which will route the items to the appropriate stakeholder committees for possible policy development.

Entergy’s Yarrow Etheredge asked if MISO should consider extending the life of the ESTF because of the uncertainty surrounding the Order 841 compliance filing and a decision is not expected until July.

Task force Chair John Fernandes said stakeholders might consider ad hoc meetings focusing on energy storage, but monthly meetings of the ESTF were no longer necessary.

“Where there is interest in discussing this further, it would be on an as-needed basis,” Fernandes said.

The ESTF’s topic list focuses heavily on how MISO might facilitate market participation for hybrid resources that include both generation and energy storage devices. The group said the RTO should work out how modeling, forecasting and offer data submittals will work for those resources. MISO must also determine allowable capacity factors for the purposes of its Planning Resource Auction. It currently lacks historical data on the charging patterns and behavior of hybrid resources, making capacity factors difficult to determine.

Some stakeholders agreed that hybrid resources are a more pressing matter than storage-as-transmission assets (SATA) because they believe multiple hybrid resources will be built before a SATA project is realized. Others added that if MISO wants to incorporate hybrid resources soon, it needs to rethink its postponement on combined cycle modeling until mid-2023. (See “At Least 1 Market Project Delay,” New MISO Platform Headed to the Cloud.) Multiple stakeholders said better combined cycle modeling and hybrid resource modeling are inextricably linked.

May 27, 2019

PJM MRC Preview: May 30, 2019

Below is a summary of the issues scheduled to be brought to a vote at the PJM Markets and Reliability Committee on Thursday, along with highlights of first readings and discussion issues. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.

RTO Insider will be in Valley Forge, Pa., covering the discussions and votes. See next Tuesday’s newsletter for a full report.

Consent Agenda (9:15-9:25)

B. Endorse proposed revisions to Manual 01: Control Center and Data Exchange Requirements as a part of the cover-to-cover review.

C. Endorse proposed revisions to Manual 03: Transmission Operations as a part of a cover-to-cover review.

D. Endorse proposed revisions to Manual 07: PJM Protection Standards to update applicability references and an Institute of Electrical and Electronics Engineers standard reference.

E. Endorse proposed revisions to Manual 11: Energy & Ancillary Services Market Operations and Manual 13: Emergency Operations to clarify the impact of operationalizing gas contingencies on reserve requirements and reserve market eligibility.

F. Endorse proposed revisions to Manual 13: Emergency Operations as part of a cover-to-cover review.

G. Endorse proposed revisions to Manual 36: System Restoration as a part of a cover-to-cover review.

1. Fuel Security Senior Task Force Charter

Stakeholders will get a first look at the charter for the newly formed Fuel Security Senior Task Force, two months after a lengthy debate over whether the discussion was even necessary. (See PJM Stakeholders Reluctantly OK ‘Fuel Security’ Initiative.)

The draft charter fleshes out the details of the compromise problem statement and issue charge stakeholders spent more than two hours haggling over at the March MRC meeting, including an open-ended timeline that doesn’t commit stakeholders to action by the end of the year. PJM will seek endorsement at the June MRC meeting.

4. FERC Order Related to Hourly Cost Offers

PJM will present an update on fuel cost policies after FERC accepted the RTO’s March compliance filing that clarifies:

Clearly specifying when a penalty for noncompliance with a fuel-cost policy would be terminated by PJM.
Allowing a new resource a 90-day time period before it submits its fuel-cost policy.
Specifying that a market seller may only update its minimum run time for the uncommitted hours in real time and that a market seller’s make-whole payment be based on the minimum run time specified at the time of commitment.

FERC also reaffirmed the Independent Market Monitor’s right to oppose PJM filings on issues beyond market seller offers in capacity auctions (ER16-372). (See FERC Upholds PJM Monitor’s Right to Protest Fuel-cost Policies.)

– Christen Smith

May 27, 2019

‘Grid Transformation Day’ Highlights ISO-NE Challenges

WESTBOROUGH, Mass. — More than 150 people attended ISO-NE’s first-ever Grid Transformation Day last week to hear about the speed of the change overtaking the power industry — and the breadth of resources needed to accommodate it.

Here’s some of what we heard.

Dealing with Outdated Data

Stephen Rourke, ISO-NE vice president for system planning, said the industry is changing so fast that some of the RTO’s statistics for last month are already significantly misleading.

One example: The figure of 1,381 MW of battery storage in the interconnection queue as of April 1 is already out of date, with the number now topping 2,500 MW.

Information is still key, he said about the RTO’s response to growth of distributed energy resources.

“So every night at around 10 or 10:30, we get five-minute snapshot data from 10,000 different solar sites around the region,” Rourke said. “Thanks to working with the utilities and the states, we have actually mapped every single solar panel in New England to the town or city that it’s in.”

However, getting that data in real time would significantly increase costs, “so we have not gone down that path yet,” he said.

Steve Widergren, principal engineer at Pacific Northwest National Laboratory, said that our modern, data-driven society requires a much more flexible and resilient transmission system, which must transition to meet the challenges of changing demand characteristics, he said.

“We’re asking the grid to do a lot more than it was originally designed to do, which I think has been the mantra for electricity through its entire life,” he said. “We have already seen what extreme weather events are doing and can do, so the mission is how to mitigate the damage and recover quickly. The grid is increasingly a critical national asset.”

The policy environment is changing as “corporates and municipalities are demanding more clean energy, and this clean energy operates in a different way from traditional power plants, so that’s a challenge for the system,” said Janet Gail Besser, managing director of regulatory innovation at the Smart Electric Power Alliance.

She listed various legislative initiatives around the region, including a bill on solar siting in Rhode Island (House Bill 5789).

“As we see more of these resources, we see more of the challenges in siting even distributed energy resources, and that’s not going to go away,” Besser said.

Technical Challenges

Aidan Tuohy, principal project manager at the Electric Power Research Institute (EPRI), spoke of the challenges of integrating DER into grid operations, such as ramping to compensate for both short- and long-term intermittency of wind and solar.

In his native Ireland, for example, the grid operator is “buying 14 different kinds of ancillary services to deal with all this,” Tuohy said.

Hosting capacity — the volume of DERs that the distribution system can handle at a given time and place — is important from a bulk services perspective and comes up when trying to get distributed battery storage to provide some service that can’t actually be accessed because the system is starting to hit some limit, Tuohy said.

“EPRI has been exploring the use of technologies to better understand where and how much DERs you can put on your system so that you can then plan around that … and flag where upgrades are needed,” he said.

Barry Mather, manager for integrated devices and systems at the National Renewable Energy Laboratory, said grid operators have “a lot of tools in the toolbox” and that the large number of options is in itself a challenge.

In sharing NREL research on the Hawaii grid, Mather said it is “a very interesting system with lots of PV; mostly distributed, not transmission-scale,” which results in steady-state over-voltage issues.

What smart inverter function should actually be used?

“Obviously, frequency ride-through is a big deal on an island system such as in Maui, where you have relatively large frequency transience, just because the system is not very large,” Mather said. “But even [with] things like the volt/[volt-ampere reactive] settings [on inverters], how specific do you need to be?”

“Another important step in this planning matrix is to understand where you are going to go, because these DER assets, even though they’re small systems … are designed relative to a utility-scale lifetime, maybe 25 or 30 years,” Mather said.

The smart inverter setting you set today may not be the same setting that will be needed when DERs reach their ultimate penetration level, he said.

“The biggest game-changer is demand response,” said Debra Lew, senior technical director at GE Energy Consulting. “I can’t convey to you the importance of this … think of it as demand response on steroids. This is going to be way bigger than what you think of today because, first of all, we’re electrifying all these new loads,” from transportation to space heating to water heating and cooling.

“These loads are inherently flexible; we can extract a lot of flexibility out of them, so a significant amount of our demand in the future is going to be price-responsive or controllable,” Lew said. “This demand is going to compete directly with storage, and that’s something to think about as you make investments for the future.”

Lew said she participated in a meeting the previous week in which a Californian said their state currently had a half-million electric vehicles and plans for 7 million.

“We did a back-of-the-envelope for 7 million electric vehicles: 420 GWh of storage. That’s huge,” Lew said. “Even if you can access only a tiny bit of that, that’s a huge amount of storage.”

Utility Perspective

“Vermont is the Hawaii of the East, but our mountains don’t blow off their tops,” said Chris Root, COO of Vermont Electric Co.

Vermont is leading the way in New England in terms of overall renewable energy on its system, but because of the intermittent nature of wind and solar, its grid is increasingly weather-dependent as more renewables come on, Root said.

For example, he said the load in the middle of an overcast day is 2.5 times that of a sunny day, and that when snow covers a solar panel, its energy production drops to zero — which drew the comment that Hawaii probably had the edge in weather.

“I do believe storage is going to be critical in the future, because we have loads that change, we have generation that changes, and the only thing that’s going to be able to equate that is going to have to be storage,” Root said.

He said Vermont utility Green Mountain Power has installed 1,900 Tesla Power Walls and “can’t install them fast enough.” He noted the state has two utility-scale energy storage facilities of 4 MW and 1 MW — but he likes to remind people that storage is not an energy source.

“You have to put energy in; then you can take it out.

“Sometimes when policy gets way ahead of engineering, that can be a little scary,” Root said. “We’re still solving the problems that are happening today, so it gets a little scary when you’re trying to play catch-up from an engineering perspective.”

National Grid has seen its average solar interconnection request in Massachusetts triple in size over the last few years and double in Rhode Island, said Brian Gemmell, the company’s vice president for asset management and planning.

“For those that know the transmission system well, there’s a lot of ripple effect with getting all these megawatts. … We don’t have a lot of transmission in central and western Massachusetts and, indeed, some of the areas in Rhode Island,” Gemmell said. “We’re grappling with a dramatic uptick in [distributed generation].”

“It’s a given that we’re going to need innovation … but the biggest thing we’ll need is collaboration,” said Vandan Divatia, Eversource Energy’s director of ISO-NE policy and interconnections. “We have a role in every sector of the grid, from a customer-facing angle to grid-type investments, to supply, and the key thing is going to be collaborating with the right folks.”

Highlighting the ambitious clean energy policies and greenhouse gas reduction targets of various states in the region, Divatia said, “This may mean, based on the numbers you run … one scenario is you need to have every single new vehicle by 2030 to be electric.

“Massachusetts has shown great leadership in this area by enabling a make-ready program to deploy $45 million to get about 18,500 EVs,” and the region needs about 80,000 charging stations to help people overcome their range anxieties regarding EVs, Divatia said.

“Again, if we want to go from here to there, we’re going to need a lot more electric infrastructure,” he said.

— Michael Kuser

May 27, 2019November 29, 2023

ERCOT Technical Advisory Committee Briefs: May 22, 2019

AUSTIN, Texas — Unable to reach a decision on a rare update to a key metric used to determine systemwide offer caps, the ERCOT Technical Advisory Committee last week delegated a staff proposal to the Wholesale Market Subcommittee for further discussion.

ERCOT has proposed lowering the peaker net margin (PNM) threshold from $315,000/MW-year to $273,600/MW-year, based on a revised 2018 report by The Brattle Group that set the cost of new entry (CONE) for generation plants — typically combustion turbines — at $91,200/MW-year. The PNM threshold is set at three times the CONE, which means the $315,000/MW-year threshold used in recent years implies a CONE of $105,000/MW-year.

The PNM threshold is used to determine the point at which the systemwide offer cap is reset from the high offer cap of $9,000/MWh to the low offer cap (the higher number between $2,000/MWh or 50 times the daily effective fuel index price).

During its Wednesday meeting, the committee rejected two separate motions in roll-call votes, both of which would have referred the issue to the WMS for further discussion on the study’s values. One motion would have tabled ERCOT’s proposal; the second would have approved it. The latter motion fell just short, by a 66-34 margin.

When the smoke cleared, TAC Vice Chair Diana Coleman, of the Texas Office of Public Utility Counsel, agreed with ERCOT to send the proposal to the WMS.

Brattle initially set the CONE for CTs at $88,500/MW-year but revised it in the final draft estimate of ERCOT’s market equilibrium and economically optimal reserve margins. The study, which “translated” an earlier version conducted for PJM to account for locational cost differences, adjusted assumed interest rates and corporate tax rates to come up with the new CONE.

The current CONE dates back to a 2012 Brattle study, which the Texas Public Utility Commission used to update its resource adequacy requirements earlier this year (Project 48721). (See “PUC Amends Resource Adequacy Rules,” Texas PUC Briefs: May 9, 2019.)

“We’re in a rising interest rate environment,” Reliant Energy Retail Services’ Bill Barnes said in advocating for the WMS’ further evaluation. “Let’s avoid a 10-year backward-looking number and use values that make sense.”

ERCOT staff said they would take time to bring in a consultant to review the Brattle analysis. They noted its Independent Market Monitor, Potomac Economics, has used a CONE of between $80,000 to 95,000/MW-year in recent reports and that the process used to change the CONE is “consistent with our current methodology.”

Luminant’s Ian Haley countered by bringing up PJM to Consider Revisions to Demand Curve Design.)

“This is so controversial in PJM that this is being litigated at FERC,” Haley said, objecting to making a “major market change” with seven days’ notice. “This is not something PJM instituted and everyone grabbed hands and sang ‘Kumbaya.’ These are some numbers with big issues in other markets. I have a lot of trouble with [ERCOT] describing them and running with them and showing slight differences [justifying] why they work here in six slides.”

Subcommittees to Review Emergency Procedures

The TAC also delegated to the WMS and its Reliability and Operations Subcommittee further discussions on the need to balance emergency procedures and system reliability.

ERCOT has already spent the last month working to resolve issues raised by a late-winter cold-weather event that resulted in generation resources being forced to adjust their outage schedules. (See ERCOT Generators Upset over Early March Weather Event.)

The grid operator has held two workshops on its procedures for issuing operating condition notices (OCNs) and conducted a webinar on a Nodal Protocol revision request (NPRR930) that would require it to use a weekly reliability unit commitment process to commit resources with an approved outage. The NPRR also sets an offer floor for the resource at the systemwide offer cap. (See “Changes Coming to ERCOT’s OCN Process,” ERCOT Briefs: Week of April 22, 2019.)

Two other NPRRs (934 and 935) addressing emergency procedures are going through the stakeholder process.

TAC members pushed to gain a clearer understanding of ERCOT’s OCN procedures and asked for greater accuracy in weather forecasts and planning assumptions.

“The range of possible outcomes of load [and] the range of possible forecasts for wind and icing are all very situationally dependent,” ERCOT COO Cheryl Mele said. “I’m not sure that is something we can hard code. We want to make that as transparent as possible and share that information with folks as soon as we can. I don’t think we can develop specific criteria around that because cold weather, hot weather [and] wet weather combined with cold all present very different types of risks to us.”

“We don’t expect hard coding, but we think we can get close to it,” Calpine’s Brandon Whittle said. “I think there’s a way to narrow that scope a little bit to where we have general consistency.”

“We don’t want an emergency declared days in advance, which is not what ERCOT wants to do,” Citigroup Energy’s Eric Goff said. “There are certainly other instances in the protocols worth finding and revising. At the same time, we can ensure we have communications around emergency conditions that are very clear and procedures that don’t have much guesswork.”

Barnes said his concern is that market participants are using ERCOT’s planning assumptions and the planning process to make operational decisions, “so we’re always going to overshoot.”

“That’s the nature of solving this problem,” he said. “Inherent in our market design is an acknowledgement we’re willing to accept a high level of reliability risk.”

Barnes referred to recent comments filed by Texas Competitive Power Advocates, a trade association representing ERCOT generators, wholesalers and retail providers. TCPA called for a holistic review of ERCOT’s reliability standards by the grid operator itself, along with Texas Reliability Entity and market participants.

“[TCPA] is concerned that this fundamental conflict between the reliability standards and required scarcity means that even lower reserve margins will be required before the economic signals are apparent and trusted to lead to a turnaround in supply,” the association said.

“There’s a lot of subjectivity in interpreting the standards,” Barnes said. “Not just ERCOT, but every power market has this tension between the need to preserve reliability and the need to let markets solve those problems. I know we probably have a reluctant partner in ERCOT to review the standards to see if there’s more room for relaxation of those, but that’s worth continuing to discuss.”

Wind, Solar Energy Set New Marks in April

Mele’s revamped operations report revealed ERCOT in April set new monthly generation records for its wind and solar fleets, producing 7,148 GWh and 408 GWh, respectively. That bettered the previous marks of 7,060 GWh of wind in May 2018 and 368 GWh of solar last June.

Wind energy accounted for 26.7% of ERCOT’s production during April, besting coal (19%) and nuclear (12.3%), while gas accounted for 39.9%.

April’s peak demand of 51.6 GW was a 3.7% increase over April 2018’s peak (47.9 GW) but below the April 2017 record of 53.5 GW.

Mele said she wants to retire the previous operations report’s format but agreed to add real-time revenue neutrality allocation (RENA) metrics to the deck. RENA measures the amount of leftover market revenue paid to qualified scheduling entities on a load-ratio share to keep the grid operator revenue neutral.

TAC Tables One Change, but OKs 17 Others

Committee members tabled an NPPR (917) that would set a 20-year grandfathering period to assist settlement-only distribution and transmission generators (SODGs and SOTGs) in their transition from zonal to nodal energy pricing.

NPRR917 currently allows existing SODGs and SOTGs to apply for continued zonal pricing until they opt in for nodal pricing or Jan. 1, 2030, whichever comes first. The proposed rule would grandfather distributed generation resources that have entered into interconnection agreements or power purchase agreements before Jan. 1, 2019.

In objecting to the request, solar developer Cypress Creek Renewables called for allowing existing SODGs and SOTGs to opt out of nodal pricing and continue to receive zonal prices for five years, with the option of extending the treatment for additional five-year increments for up to 40 years.

Cypress Creek is supported by Lower Colorado River Authority, which prefers a longer grandfathering period rather than a shorter one. The two entities will work together over the next month on joint comments.

Ralph Daigneault, legal counsel for Potomac Economics, said the Monitor is concerned with any grandfathering clause, but even more so when the term extends to 40 years.

“We think it’s bad precedent and bad market design. Any exception to that perpetuates the bad market design,” he said. “I think the comments by Cypress Creek are a step backwards. The smaller we get with that number, the more comfortable the IMM is going to be.”

“The big motivation for doing this zonally is if you have a load entity in that zone, and your generation is in that zone, you get a natural hedge,” said Walter Reid of the Advanced Power Alliance. “That is the business model that was expected, but unfortunately, we’re changing that.”

ERCOT says the change would better align its operations with the overall nodal market design and reliability needs and would increase economic efficiency.

The TAC did approve seven other NPRRs, three revisions to the Nodal Operating Guide (NOGRRs), four other binding document changes (OBDRRs), two modifications to the Planning Guide (PGRRs) and a system change request (SCR):

- - NPRR885: Adds new language to address the solicitation and operation of must-run alternatives, as directed by the Texas PUC (Project 46369). The commission ruled that a resource entity must file a notification of suspension of operations at least 150 days prior to the date on which it intends to cease or suspend operations; within the 150-day notice period, ERCOT must determine whether the resource is needed for reliability.
  - NPRR896: Outlines the process to evaluate the cost-effectiveness of procuring reliability-must-run service or one or more must-run alternatives.
  - NPRR921: Replaces all instances of the “all-inclusive generation resource” and “all-inclusive resource” terms with “generation resource and settlement-only generator (SOG)” and “generation resource, settlement-only generator and load resource,” respectively. Eliminating the all-inclusive generation resource enables ERCOT to more narrowly tailor the requirement’s applicability to a reasonable scope.
  - NPRR923: Updates the weather-sensitivity process by allowing transmission and/or distribution service providers an additional 30 days to complete the investigation and execution of requests to revise electric service identifier (ESI ID) load profiles.
  - NPRR924: Moves the Independent Market Information System Registered Entity Application for Registration form into a section of the Nodal Protocols that houses similar forms.
  - NPRR926: Removes the 90-day period between subsynchronous resonance (SSR) study approval and initial synchronization, clarifies that the SSR mitigation plan is part of the SSR study, and adds an ERCOT review process that gives the grid operator 30 days to review the SSR study. The change also gives ERCOT 45 days to implement any required SSR monitoring after the study’s approval.
  - NPRR929: Adds new criteria for determining whether a point-to-point (PTP) obligation with links to an option bid is eligible to be awarded based on the resource’s current operating plan (COP) status at the node where the bid sources. Bids will not be eligible for awards if they source at a resource with a COP status of “OUT” or “OFF” and the resource is not offered into the day-ahead market.
  - NOGRR185: Uses the terms created in NPRR889 (RTF-1 Replace Non-Modeled Generator with Settlement Only Generator) to replace the terms “all-inclusive generation resource” and “all-inclusive resource” in the Nodal Operating Guide.
  - NOGRR188: Aligns the guide’s language with ERCOT’s wide area network refresh project to allow implementation of Voice over Internet Protocol.
  - NOGRR189: Aligns the NOGs with NERC Reliability Standard PRC-002-2 (Disturbance Monitoring and Reporting Requirements).
  - OBDRR009: Revises the online and offline capacity reserves to prevent price reversal and price distortion during DC tie out-of-market actions.
  - OBDRR013: Changes the current single-value voltage categories of 345, 138 and 69 kV used to define generic transmission shadow price caps for N-1 constraint violations to accommodate Lubbock Power & Light’s transmission equipment, which does not fall into the three existing categories. The ranges are: greater than 200 kV ($4,500/MW), 100 to 200 kV ($3,500/MW) and less than 100 kV ($2,800/MW).
  - OBDRR014: Changes the location where resource nodes with disallowed energy-only offers, energy bids and point-to-point bids will be posted, and clarifies that the congestion revenue rights team will use the most recent list when building the auction model. The OBDRR also modifies its approval process to better account for revisions that may require a project and a separate SCR.
  - OBDRR015: Sets the value of lost load (VOLL) equal to the systemwide offer cap, which changes the high systemwide offer cap to the low systemwide offer cap should the PNM exceed its threshold within an annual resource adequacy cycle.
  - PGRR069: Uses terms created by NPRR889 to replace the terms “all-inclusive generation resource” and “all-inclusive resource” in the Planning Guide. The PGRR also clarifies the applicability of the generation interconnection or change request process to different generators, based on NPRR889.
  - PGRR070: Aligns the Planning Guide with NERC Reliability Standard TPL-007-2 (Transmission System Planned Performance for Geomagnetic Disturbance Events) by identifying responsibilities for performing studies needed to complete benchmark and supplemental geomagnetic disturbance vulnerability assessments.
  - SCR799: Enables ERCOT to provide transmission service providers its current month, 60-day and 90-day outage study cases in the system operations test environment on a monthly basis.

— Tom Kleckner

May 24, 2019January 15, 2025

Outside Parties Slow MISO-PJM Freeze Date Thaw

By Amanda Durish Cook

After five years of discussion, MISO and PJM are still slogging through development of an alternative to their “freeze date” used to grandfather permissible unscheduled transmission flows that predated their seam.

And while the RTOs promise progress on the issue, they acknowledge that outside entities with a stake in any changes are still resistant to a proposed solution, stakeholders learned Tuesday.

The RTOs rely on the April 1, 2004, “freeze date” to determine firm rights on flowgates based on historical firm flows that occurred before creation of the seam between their markets. That date is used to establish acceptable flows in both the market-to-market (M2M) process and transmission loading relief.

Andy Witmeier, of MISO’s seams administration team, said the RTOs still agree that the freeze date needs updating.

“We’re more than 15 years away from it now, and issues with the date have become prominent,” Witmeier told stakeholders during a MISO-PJM Joint and Common Market conference call. Those issues primarily have to do with how designated network resources are dispatched and determining eligibility for transmission service requests.

But five years on, the RTOs are still facing opposition from parties to their congestion management process (CMP), which includes MISO, PJM, SPP, the Tennessee Valley Authority, Manitoba Hydro, the Minnkota Power Cooperative and Associated Electric Cooperative Inc. The CMP was established to minimize unscheduled market — or loop — flows among neighboring balancing areas.

All CMP parties stand to be affected by a change in the freeze date, MISO staff have said.

In November, MISO and PJM announced that their original goal of a full freeze date replacement by June 2019 was too optimistic. Now, the RTOs say they will continue talks on a possible replacement throughout the year and hope to implement a solution in 2020.

FFE vs. FFL

In M2M procedures between RTOs, an RTO’s entitled firm usage is classified as a firm flow entitlement (FFE). In the transmission loading relief process utilized for nonmarket entities in the CMP, an RTO’s entitled firm usage is classified as a firm flow limit (FFL).

Witmeier said MISO and PJM were close to a solution last year, but that nonmarket entities party to the CMP had issues with how the proposal might impact FFLs.

The RTOs’ proposal would divide flowgate allocation — or FFEs — among four separate “buckets” to prioritize access to the flowgates. (See “Freeze Date Update,” MISO-PJM Markets Meeting Addresses Seams Issues.)

The first bucket — which would get primary consideration for flowgate needs — would consist of active designated network resources predating the freeze date and historic transmission service requests.

A second bucket would consist of active designated network resources dating after the freeze date, while a third would be used for transfers from local balancing authorities with excess generation to LBAs short on generation.

The fourth, lowest-priority bucket would be for market-wide transfers based on RTO transmission planning.

MISO and PJM last summer changed their policies to make post-freeze date designated network resources with a defined dispatch order eligible to receive FFE allocations — a small piece of the RTOs’ broader proposed solution.

Witmeier said most CMP entities favor completing an FFE solution by mid-2020 while continuing to work on how FFLs would be handled. However, some want any solution delayed until both FFEs and FFLs can be addressed.

“Obviously, we have to have a unanimous agreement from all parties. … We’re not there yet,” Witmeier said.

‘A Long Time’

MISO, PJM and CMP entities have been working for about five years on a freeze date alternative through their Congestion Management Process Working Group.

Witmeier also said the two RTOs are specifically working on how to account for FFE allocation priorities and in what order they would curtail the overallocation of rights on a particular flowgate.

A joint white paper on the matter that would detail an alternative way to calculate the freeze date is still in the works, Witmeier added.

Customized Energy Solutions’ David Sapper asked if MISO and PJM could move to a FERC filing on a freeze date alternative without all nonmarket entities signing on.

“Five years is a long time,” Sapper observed.

PJM Director of Energy Market Operations Tim Horger said the two RTOs are considering substitutes to unanimous accord and may consider a filing that not all parties have signed on to. He also said parties to the CMP are “frustrated” that talks on a potential solution have taken this long.

“There is going to be a path forward shortly,” Horger promised stakeholders.

MISO and PJM staff promised to return to the Aug. 27 JCM meeting with an update.