Page 1126 – RTO Insider

August 28, 2018

PJM MRC/MC Briefs: Aug. 23, 2018

Delay Approved for Cost Containment Comparisons

VALLEY FORGE, Pa. — The Markets and Reliability Committee last week agreed to a one-year delay in adding cost-containment measures to PJM’s transmission planning process as proponents made clear that their support of the initiative hasn’t wavered. (See Cost Containment Clears MC Vote Despite PJM Plea.)

“We’ve listened to PJM, we’ve heard PJM, and we want this policy implemented and designed correctly,” LS Power’s Sharon Segner said. “This motion could also be called a motion for excellence.”

pjm rev cost containment provisions january 2018 cold snap — Stakeholders consider a variety of issues at PJM’s MRC meeting. | © *RTO Insider*

The proposal, which pushes back the deadlines for implementing two comparative frameworks by a year, was endorsed by acclamation with three abstentions and one objection. The first framework, which will focus on construction costs, will be effective for transmission proposal windows commencing after Jan. 1, 2020. The second focused on return on equity and will be effective for windows after May 1, 2020.

Segner said the motion “in no way changes” the policy direction of the proposal that was endorsed by the Members Committee in June but was made in response to concerns from PJM staff that the original schedule would not allow enough time to ensure the initiative could be incorporated into the RTO’s Regional Transmission Expansion Plan. It does add detail to the implementation structure.

“There’s unfinished business from the June MC meeting that needs to be addressed in this motion,” Segner said.

“This is the right decision for excellence,” said Susan Bruce, who represents the PJM Industrial Customers Coalition and seconded the proposal.

She called for a “transparent” process and regular progress reporting from PJM staff “to reflect the fact that this is not delay for the sake of delay, but delay to get the rules appropriately crafted.”

Greg Poulos, executive director of the Consumer Advocates of the PJM States, was also supportive.

“It does add more competition to the market,” he said.

PJM Vice President of Planning Steve Herling agreed that the new timeline addressed staff’s concerns.

BTM Visibility

PJM’s Pete Langbein presented proposed Tariff and manual language to increase visibility of behind-the-meter generation, an effort to reduce load forecast errors and the impact of local load shedding.

The changes would create an annual process to model all BTM resources over 1 MW using Energy Information Administration data and transmission owner input. They would also allow TOs to coordinate with BTM generation owners during emergency load sheds to mitigate a grid emergency.

Several stakeholders objected to the proposal, which came out of PJM’s Distributed Energy Resources Subcommittee, being presented at the MRC as a first read. John Horstmann of Dayton Power & Light noted that while the language itself received 88% support at the subcommittee’s July 30 meeting, 58% favored retaining the status quo rather than make any change. Adrien Ford of Old Dominion Electric Cooperative also protested, saying the subcommittee had not discussed the vote before the proposal was sent to the MRC.

Committee Chair Suzanne Daugherty said she would consult Manual 34 to see if the proposal would require a second read at the next meeting.

Market Efficiency

The MRC approved a package of Tariff and manual changes that would alter how PJM evaluates and selects market efficiency transmission projects.

Under “Package G,” PJM would exclude from its base case generating units with facility study agreements and suspended interconnection study agreements. The RTO says including these units causes unrealistic benefit estimates for proposed transmission projects.

Package G received the most support out of nine proposals at the Market Efficiency Process Enhancement Task Force in July. It passed the Planning Committee with 88% in support at its Aug. 9 meeting.

Segner requested a sector-weighted vote on the proposal, calling excluding FSA units a “significant change” and saying she was concerned that PJM was favoring transmission over market-based solutions. It passed with 3.87 out of 5 in favor.

A second set of changes, which would specify that market efficiency proposals must address an RTO-identified congestion driver, passed by acclamation without discussion. Congestion drivers would include current or future market-to-market flowgates and internally binding flowgates.

VRR Curve Quadrennial Review

PJM’s Gary Helm confirmed that FERC has approved an extension until Oct. 12 of the RTO’s deadline to file the quadrennial review of the variable resource requirement curve in its capacity auctions. The extension allows time to push back approval votes as well.

MRC voters will choose among four proposals. Voters at the Market Implementation Committee heavily favored a proposal from Calpine. (See “Quadrennial Review of VRR Curve,” PJM Market Implementation Committee Briefs: Aug. 8, 2018.)

Calpine’s David “Scarp” Scarpignato questioned inclusion of a proposal from the D.C. Office of the People’s Counsel, but the OPC’s Erik Heinle defended it, saying “it’s not a new proposal by any respect” and it’s “been in the process” since it was unveiled at a July 6 special session of the MIC.

Awareness Issues

An initial review of proposed revisions to PJM’s governing documents proved controversial when American Municipal Power’s Steve Lieberman questioned inclusion of a requirement that stakeholders “properly” serve the RTO with rate and waiver requests filed at FERC. Lieberman noted that the change could put stakeholders at risk of being referred for FERC discipline for administrative errors.

PJM staff said the language is necessary to address clerical oversights that happen often enough to be an issue. PJM’s Jen Tribulski said it creates “a basis” for action if staff miss the deadline to intervene in a case or if an applicant is attempting to avoid allowing the RTO to weigh in on the issue.

Lieberman said the “change is rather substantive” and urged other stakeholders to consider its implications.

Interconnection Clarifications Approved

Stakeholders endorsed by acclamation revisions to Manual 14C that clarify procedures for construction of interconnection facilities for generation and transmission assets.

— Rory D. Sweeney and Michael Brooks

August 27, 2018

Overheard at the NAES NERC Conference

Overheard at the NAES-NERC Conference

SEATTLE — “Buckle your seatbelts; it’s going to be an interesting ride,” NAES CEO Bob Fishman said as he kicked off last week’s third biennial NAES-NERC conference, where nearly 140 power plant operators, engineers and back-office professionals spent three days being schooled in the finer points of complying with NERC standards.

Fishman wasn’t so much referring to the nature of the conference — billed “Sustaining Reliability: Balancing Operations and Compliance” — as the changes forcing the electricity sector to re-examine its approach to reliability.

“To look at the market, we’re entering an era of unprecedented change,” said Fishman, whose company helps generators, transmission owners and others comply with NERC reliability standards. “In my career, I’ve seen the rise of the gas turbine and the combined cycle plant. During my stint at Calpine, we were building 8,000 MW a year for a while, and that was a big shift. But this shift is different and very fundamental.”

Demonstrating his point, Fishman listed several concurrent developments: the decline in electricity demand relative to economic growth; growing reliance on renewables and efficiency; plant retirements; and persistently low power prices driving an increasing number of bankruptcies by generators.

What do those changes mean for compliance, grid operations and the future of the industry? Fishman posed rhetorically.

“The good news is that people can’t live without electricity, so the grid’s not going away soon,” he said. “But we are going to see a very different grid infrastructure and operation than we’ve seen before. The integration of renewables into the grid has and is causing a dramatic shift in where power is generated, how it’s generated and how the grid copes with the intermittency of renewables.”

The three-day conference, which featured NERC CEO Jim Robb and FERC Commissioner Neil Chatterjee, touched on EPA’s replacement for the Clean Power Plan, the politically charged debate over grid resilience, cybersecurity, and the impact of electric vehicles and solar generation. (See related story, NERC Seeks to Balance Oversight, Collaboration.)

Here’s more of what we heard.

FERC Discusses Resilience

Mark Hegerle, director of the Division of Compliance in FERC’s Office of Electric Reliability, pondered the meaning of resilience: “Is it encompassed by reliability? Is it part of reliability? Is it something separate from reliability? Does it mean fuel security? Does it mean hardened transmission? Cybersecurity? Recovery from thunderstorms or distribution outages?”

Hegerle noted that FERC in January rejected the Department of Energy’s Notice of Proposed Rulemaking to provide price supports for coal and nuclear plants. Instead, FERC opened its own resilience proceeding setting out three goals: to develop a common understanding of resilience, understand how each region assesses resilience, and use that information to evaluate potential commission actions (RM18-1). (See DOE NOPR Rejected, ‘Resilience’ Debate Turns to RTOs, States.)

“We wanted to actually think before acting. I know that’s a rarity in Washington,” he said.

“FERC has a lot of responsibilities, but protecting the reliability of the bulk power system is among the most important,” Chatterjee said. “It’s a point that I made during my Senate confirmation hearing, and one year into my time at FERC, I remain committed to this mission.”

Chatterjee said he has “gotten under the hood of the system” as commissioner, helping him understand even more what it takes to maintain the high level of reliability enjoyed by the U.S. He also cautioned that historically low natural gas prices and technological innovation are driving “unprecedented changes” in the country’s resource mix.

“These trends promise tremendous benefits to consumers through lower prices and great choice, but they also highlight a need for vigilance to ensure that reliability is not adversely impacted,” Chatterjee said. “Ten years from now, I do not want to regret not having asked the hard questions about the effects of these changes in resource mix.”

On Cybersecurity

“It’s no secret that America’s critical infrastructure is under threat from foreign actors,” Chatterjee said, referring to the potential for cyberattacks on the grid. “Could the grid hold up against a cyberattack that take out a [gas] pipeline? What about a cyberattack that takes down a substation?”

Joseph Baugh, senior compliance auditor for the Western Electricity Coordinating Council (WECC), addressed the need for “low-impact” facilities — such as smaller power plants — to be hardened against cyberattacks, a new requirement under a NERC’s CIP-003 standard.

“Smaller sites can become a vector for attacks on more critical facilities,” Baugh said.

“If you just own a single generation location, that’s a low-impact [bulk electric system] asset — but you still communicate,” Baugh said. “You probably communicate with either a [generation operator] or a [balancing authority] somewhere. And if you have someone providing transmission services for you, you [are] probably communicating with a [transmission operator]. Know where those communications paths lie, know what they look like, know what they use, and develop the protections necessary and applicable to those communication paths.”

“Cyber is a rapidly evolving threat. It's a threat that morphs day in, day out,” Robb said. “Your ability to protect yourself from a security perspective is much, much more complex than operating a system reliably and securely.”

On the Demise of Peak Reliability

Robb said the single most important reliability issue facing the U.S. over the next two years is Peak Reliability’s announcement that it will end operations as the Western Interconnection’s reliability coordinator as soon as the end of 2019. Peak will be replaced by “at least three, maybe four [RCs], depending on how you do the math,” Robb said. “The Western Interconnection is structured very, very differently than the East. It really operates as one integrated machine and has had the benefit of Peak Reliability being the reliability coordinator for the entire interconnection.”

The CEO noted that CAISO, SPP and Canada’s BC Hydro could all be functioning as Western RCs within the next two years and would require NERC certification.

“Most importantly for the West are [that] seams agreements are going to need to be put in place to make sure those RCs operate seamlessly and effectively as one,” Robb said.

Chatterjee said FERC is “closely monitoring” the transition from Peak.

“While I appreciate the desire for greater participation in markets and reduced costs that prompted this change, moving away from a single reliability coordinator in the West reintroduces many of the difficult seams issues that prompted the formation of Peak in the first place,” he said.

Maury Galbraith, executive director of the Western Interstate Energy Board (WIEB), expanded on the potential seams issues in a post-Peak West, listing concerns over outage coordination, system operating limits, awareness of remedial action schemes, data sharing and overall communication.

Galbraith acknowledged that CAISO was likely to become the RC for most of the interconnection and said WIEB was concerned about governance under the ISO — or any other RC that is stood up in the region.

“We think the decision-making of the RC needs to be transparent. It needs to be independent. There ought to be a role for the states and provinces to provide input into that decision-making process,” Galbraith said.

Solar, Storage and Flexible Generation

Chatterjee said his staff gets annoyed when he refers to energy storage as a “gamechanger.”

“They say it’s too cliche of a comment, but there’s truth in that cliche,” Chatterjee insisted. “Storage will be the transformative technology. But for us to be able to realize storage’s full value, we must ensure communication between the customer, the distribution utility, the transmission utility and the RTO in a way that’s never been done before.”

Galbraith pointed to the “explosion” of distributed solar in the West, which is expected to double in the next 10 years. That development is coupled with the significant retirement of coal resources, with about 15,000 MW being shuttered between 2010 and 2025.

A major implication of those two developments: “We are seeing, with all of the renewable generation, a premium placed on flexible operation of other generators,” Galbraith said.

Galbraith noted that Western Interconnection coal units that in 2001 on average operated at near capacity for 52% of their operating days are now functioning as baseload just 22% of the time. In 2016, coal units were offline for 22% of operating days, compared with 9% 15 years ago.

“So one big question for [WIEB’s Western Interconnection Regional Advisory Board] and its members are, ‘Where are we going to get ancillary services, not next winter or summer, but five, 10, 15 years down the road when those coal units are retired or offline?’” Galbraith said.

— Robert Mullin

August 27, 2018

NERC Seeks to Balance Oversight, Collaboration

By Robert Mullin

SEATTLE — NERC CEO Jim Robb said last week his organization is sidestepping Washington’s fuel war politics and striving to maintain its independence from industry while still collaborating to identify best practices and emerging threats.

Robb has had no shortage of issues to address in the four months since he joined NERC from Western Electricity Coordinating Council (WECC). In his keynote address at last week’s third biennial NAES-NERC conference, Robb said the organization is focused on making sure its reliability standards evolve in response to the changing generation mix and the growth of electric vehicles and distributed generation. (See related story, Overheard at the NAES-NERC Conference.)

“Do [the standards] need to be evolved in particular ways to be compatible with the industry as it’s evolving?” Robb asked. “Are we keeping our eyes far enough down the road on reliability issues to make sure that we have a good sense of how this new restructured industry is going to work — and going to work reliably? If we don’t have a sense of what we need to have in the ground 10, 15 years from now, we may have lost the battle, and that’s becoming particularly clear on issues like gas infrastructure.”

Relationship with Industry

Robb, who replaced longtime CEO Gerry Cauley, said the organization is seeking to balance its role as enforcer of reliability standards with the need to work closely with industry to respond to new threats, such as cyberattacks.

“We are an independent authority; however, we are very tightly linked with industry in terms of being able to leverage technical expertise and capability in order to do our work,” Robb said. “Our work is much better because of the relationship we have with industry, but we can never be viewed as not being independent from industry.”

Robb said NERC and its Regional Entities face the challenge of “how to manage the yin and yang of independence and partnership in a way that gets us to the right answer from an oversight perspective.”

Other speakers at the three-day conference also discussed that balance.

Midwest Reliability Organization CEO Sara Patrick emphasized that “authority should defer to expertise” with respect to reliability issues. NERC and the REs must be sensitive to actual operations, “understanding how things work, not just how they’re supposed to work.”

Patrick said her organization has changed from its early focus on enforcement of standards. “Enforcement is only one of the tools in our toolkit and it may not be the most effective,” she said, encouraging companies to self-report violations and devise strategies for avoiding them in the future.

Jeff Craigo, vice president of reliability assurance and monitoring at ReliabilityFirst, cautioned against companies adopting practices that superficially achieve compliance without actually improving grid security, often the product of organizational silos and inadequate communication among different departments.

“The key is that you’re coordinating your compliance program across your organization,” Craigo said.

“You can be minimally compliant, but that won’t get you security,” said David Godfrey, WECC vice president of entity oversight.

Curtis Crews, director of compliance assessments for Texas Reliability Entity, talked about the “circle of competence” between oversight agencies and plant operators.

“I audit; you do maintenance. We need each other,” Crews said.

James Merlo, NERC vice president of reliability management, warned against the tendency for companies to drift from reliability standards.

“You can’t see drift in your own organization” in the same way that “you can’t smell your own room,” Merlo said, referring to the phenomenon of “sensory adaptation.”

“I believe NERC standards are the floor, not the ceiling, so the work of [NERC] is critical,” FERC Commissioner Neil Chatterjee said.

The Politics of Resilience

Robb also acknowledged the highly charged debate over resilience and the Trump administration’s push to protect coal and nuclear generation.

“There’s a tremendous amount of political influence in place right now, whether it’s ‘Can we survive without coal plants?’ or ‘What are we going to do if we don’t have our nuclear fleet?’ ‘How much renewable can we really put on the system?’

“Many of these issues are important technical issues for the industry and NERC and the REs to deal with, but they’re also highly politicized, and our job is to stay out of the political fray and be ideologically independent,” Robb said.

Mark Lauby, NERC’s chief reliability officer, told the conference that resilience has always been part of his agency’s mission.

“It’s our definition of reliability,” he said. “Resilience is something we have to keep our eye on, particularly as the risks change.”

EVs, Behind-the-Meter Generation

Robb also pointed to uncertainties stemming from the increased adoption of EVs and how they will interplay with solar generation.

“We used to always operate the system on a very simple, straightforward baseload, mid-merit peaking array, with a fairly well-known load curve,” he said. “We have to kind of ’fess up. We don’t even know what the load curve looks like. So much [generation] is masked by behind-the-meter generation.

“We’ve learned a tremendous amount over the course of the last two years around how inverter-based resources respond to disruptions on the system, and it’s been a little bit like following a ball of yarn through a house,” Robb told conference participants. “One issue you think you’ve corrected, and then another one appears, and so forth.”

The NERC chief pointed out that inverters are not just a problem for solar-heavy California. (See Solar Inverter Problem Leads CAISO to Boost Reserves.)

“It’s an industry issue because inverters will be highly central to the deployment of batteries, which we’ll see in multiple jurisdictions,” Robb said, adding that solar will also continue to be “one of the resources of choice” over the next 10 to 15 years. He also noted that inverters have “pretty extraordinary capabilities” to promote reliable operations. “We need to be ahead of that.”

Robb also said the industry needs to shift its operating model to one that is “just more stochastic in nature.”

“Policies in general need to be rethought,” Robb said. “Most of our frameworks and rules of thumb around things like resource adequacy were based on largely coal and liquid fuel resource mix and a metal-bending [heavy manufacturing] economy, and that’s not what we have anymore.”

August 26, 2018

FERC Rejects SoCal Edison Bid to Curtail Storage First

By Hudson Sangree

FERC denied Southern California Edison’s proposal to treat its energy storage customers differently from its retail and wholesale ratepayers, ruling Thursday the move wouldn’t pass muster under the Federal Power Act.

In March, the utility asked FERC to revise its wholesale distribution access tariff to facilitate the interconnection of energy storage devices to its system and to deal with their ability to inject energy back into the grid.

SCE also sought permission to curtail delivery to storage customers before it reduced power to retail and other wholesale users during times of high demand. The company said the change was necessary to ensure grid reliability.

ferc energy storage socal edison — Southern California Edison’s Tehachapi storage facility | *SoCal Edison*

FERC disagreed, saying it would be unfair to treat storage customers differently without further studies and without giving them the chance to pay for system upgrades to ensure access to charging (ER18-1248).

“SoCal Edison’s primary basis for treating the interconnection customers at issue here differently is because it currently has no process for treating them the same, an explanation that does not satisfy the mandate of the FPA that an applicant support its proposed rate change as just and reasonable and not unduly discriminatory or preferential,” the commission wrote.

SCE told FERC that when it receives requests to connect energy storage devices to its distribution systems, it studies the discharge of energy from the storage devices into the system, just as it studies the injection of energy from a generator. A customer seeking to connect a storage device must pay the costs of system upgrades needed for injections, it said.

But the utility said it doesn’t review the effects of charging of storage devices. It explained that many of the circuits in its distribution system have limited capacity and that treating a storage device’s charging demands like wholesale and retail loads would require the company to study and recommend upgrades.

The commissioners said the utility’s assertion wasn’t sufficient.

“If SoCal Edison were to offer an interconnection customer the opportunity to be studied for potential system upgrades and the customer declines to do so, then it could perhaps be just and reasonable for SoCal Edison to curtail that interconnection customer’s load before other wholesale loads, but SoCal Edison does not propose such an approach here,” the commission said.

FERC accepted other components of SCE’s proposed revisions that took effect May 30 and gave the company 30 days from Thursday’s order to remove the rejected language from the tariff.

August 26, 2018

FERC Greenlights MISO South Capacity Plan

By Amanda Durish Cook

FERC last week approved MISO’s plan to improve its procurement of reserves in MISO South effective Aug. 26.

The RTO proposed in late April to apply its existing reserve procurement enhancements — first rolled out in 2011 in MISO Midwest — to the sub-regional constraint between Midwest and South.

FERC’s Aug. 23 order said the process will “help improve the price signal for reserves” in MISO South by “implementing a price signal that reflects the causes of the need for redispatch” from operating reserve constraints (ER18-1464-003).

miso south entergy reserves — | *Entergy*

The RTO will model the effects of transmission constraints on the deliverability of reserves and add the marginal cost of delivering them to the zonal reserve market clearing price. The change would also subject to the Independent Market Monitor’s mitigation authority sub-regional capacity commitments in MISO South and binding flows in the Midwest-to-South direction on the sub-regional limit.

The commission agreed that MISO should have the authority to mitigate market power on its sub-regional limit.

“Currently, when [the contract path] binds, MISO cannot mitigate any market power because these limits are not treated as constraints under the Tariff. By treating north-to-southbound … flows as a constraint, MISO will have the ability to mitigate market power if observed,” FERC said.

The Monitor estimated that $684,362 in revenue sufficiency guarantee payments would have been subject to mitigation in 2016 had MISO applied the reserve procurement rules.

In June, the commission issued a deficiency letter, asking the RTO how it would implement the process and still abide by the contractual transfer limits on flows crossing SPP transmission. (See FERC Seeks Info on MISO South Capacity Plan, SPP Tx Limit.) MISO said it meant the term “appropriate limits” to mean the limits set in the MISO-SPP transmission use contract: 3,000 MW north-to-south and 2,500 MW south-to-north.

In response to an Entergy protest, MISO assured FERC that it was not attempting to create new broad or narrow constrained transmission areas, pointing out that the creation of such areas requires separate commission approval. Constrained transmission areas are those identified by the Monitor where transmission or reserve constraints are expected to bind, with narrow constrained areas having a pivotal supplier and broad constrained areas containing more competition.

In another protest, regulators from MISO South states said the commission should compel the RTO to explicitly state the 2,500-MW and 3,000-MW limits in its written Tariff proposal. But MISO said that the limits represented capability available only on a non-firm, as-available basis under its contract. “Reiterating … the flow limits in the Tariff would not accurately reflect the terms and conditions of service,” MISO said.

August 26, 2018

No Pay Required for Frequency Response, FERC Reiterates

By Rich Heidorn Jr.

FERC clarified Friday that its February order requiring new generators to provide primary frequency response did not imply that existing generators are entitled to compensation for providing the service (RM16-6-001).

Order 842 required transmission providers to amend their pro forma generator interconnection agreements (GIAs) to require generators have governors or other equipment to respond automatically to frequency disturbances. (See FERC Finalizes Frequency Response Requirement.)

FERC Order 842 Primary Frequency Response — | © *RTO Insider*

PJM requested a clarification on the order, saying some stakeholders have questioned the RTO’s authority to require existing facilities to provide primary frequency response without compensation.

In its order Friday, FERC dismissed the notion that Order 842 created a blanket prohibition on frequency response requirements on existing generating facilities, saying such a conclusion would be “inconsistent with the fundamental purpose” of the order in ensuring adequate frequency response capability.

“In setting forth requirements for primary frequency response capability and operations, the commission did not address and therefore did not nullify existing requirements for the provision of primary frequency response for existing generators,” FERC said. “We find that Order No. 842 does not relieve existing generating facilities from existing requirements for primary frequency response, including requirements set forth in transmission provider tariffs or business practice manuals, including operating requirements for governors or equivalent controls and/or sustained response.”

The commission said the order also does not prevent transmission providers from proposing additional frequency response requirements under Section 205 of the Federal Power Act, “including requirements for existing generating facilities.”

FERC also rejected AES’ request to reconsider its decision not to mandate compensation for providing frequency response. AES said the lack of compensation “is directly preventing the wide-scale deployment of the very technology that could arrest the aggregate decline in systemwide primary frequency response most efficiently — lithium batteries.”

The company said Order 842’s reference to an individual company’s right to seek compensation under Section 205 of the FPA “is of little consolation to companies currently trying to plan investments on a nationwide basis.”

FERC said AES’ rehearing request did not provide any new information the commission had not already considered and that the company did not address the commission’s findings that the costs of installing and operating a governor or equivalent controls are minimal.

The commission also rejected a rehearing request from Arizona Public Service, which suggested that subjecting projects in the later stages of the interconnection queue to the order’s requirements could be unduly burdensome. “APS provides no specific information that would persuade us to modify Order No. 842’s applicability criteria,” the commission said.

August 26, 2018

Study: No 2018 MISO South Economic Project

MISO will not move forward with an economic project in MISO South this year, based on results from the RTO’s market congestion planning study.

In June, MISO reported that it was focusing on just one area of concern in MISO South in the annual study: the congested 115-kV Natchez area on the southern Mississippi-Louisiana border. However, the RTO said last week that none of the five economic project candidates meant to alleviate the congestion could yield enough benefits to be viable. (See “5 Focus Areas in Market Congestion Planning Study,” MISO Planning Advisory Committee Briefs: June 13, 2018.)

MISO South Market Congestion Planning Study — | *MISO*

“We are not going to be going to the board for any economic projects in the South region,” MISO’s Jordan Cole said during an Aug. 23 MISO South Subregional Planning Meeting.

According to the RTO, a pending reliability project in the 2018 Transmission Expansion Plan will reduce congestion in the Natchez area. Cole said the $22 million, 115-kV line rebuild from Red Gum, La., to Natchez, Miss., will provide enough relief to defer a major project. The project is expected to be in place by early 2021.

“There’s still some residual congestion, but not enough to lead to an … economic project,” Cole said.

Meanwhile, the RTO’s study for MISO Midwest has identified three projects passing the 1.25:1 benefit-cost threshold so far, although the analysis is not complete. MISO in June said it was focusing on four project candidates in four separate locations in MISO Midwest.

Last year’s MISO’s market congestion planning study, which focused exclusively on MISO South, produced the RTO’s second competitively bid project under Order 1000: the 500-kV Hartburg-Sabine junction project. (See “MISO Reviewing Hartburg-Sabine Proposals,” MISO Informational Forum Briefs: July 24, 2018.)

— Amanda Durish Cook

August 26, 2018

ERCOT Briefs: Week Ending Aug. 28, 2018

Barring an unexpected heatwave or a sudden loss of generation, the remainder of the ERCOT market’s summer “looks to be a disappointment” for those hoping for high power prices, according to investment research firm Morningstar.

“We saw some short-lived excitement in July with new demand records set, but lower temperatures look to be sticking around for the rest of August,” the Chicago-based firm said in its Aug. 15 report, “ERCOT and the End of Summer.”

Lower temperatures have replaced the extreme highs of July, when a dome of high pressure settled over Texas and sent temperatures to nearly 110 degrees Fahrenheit. ERCOT broke its system demand record 14 times during July 18-23, with the new mark of 73.3 GW on July 19 smashing the 71.1 GW set in 2016. (See Plentiful Generation Helps ERCOT Meet Extreme Demand.)

ercot morningstar power prices — July 19, 2018 Wind and Load Profile (Houston, Tx temperatures) | *ERCOT, NOAA, Morningstar*

“The cooler outlook should keep August prices in the same range as June,” Morningstar said, pointing to a North Hub settlement of $36.99/MWh on the Intercontinental Exchange trading platform. July’s peak settlement was $112.15/MWh, but August’s prices fell to below $45/MWh on Aug. 10.

“Unless a major heatwave hits or a drop-off in wind generation occurs during the last week of August, we will probably see prices settle around [the] $40/MWh range,” the report said.

ERCOT load exceeded 70 GW for 11 straight days in July, a string that was broken on July 27. Load hasn’t broken 70 GW since, peaking at 69.8 GW on Aug. 23.

Morningstar said an increase in wind energy since July has helped depress prices. ERCOT said wind generation has accounted for 4-7 GW of energy during the summer, in line with its expectations. Wind averaged an above-average daily output of 6.1 GW in August. Without the low wind during high temperatures, generators’ hopes for high prices failed to materialize.

“If August wind generation continues at this level, it may buck the trend of being the lowest generation month and keep prices somewhat subdued,” the firm said.

“The market performed as it was designed to perform,” said Public Utility Commission Chair DeAnn Walker in a statement to RTO Insider. “Whether or not the parameters of the market design need to be adjusted will be something the commission and the market discuss this fall” as it reviews ERCOT’s summer performance (Project 48551.)

ERCOT’s Independent Market Monitor declined to comment, saying it is in the midst of analyzing summer outcomes.

August TAC Meeting Canceled

The Technical Advisory Committee’s leadership has canceled its Aug. 30 meeting, citing a “limited number of items to be considered” this month. It is the third TAC meeting to be canceled this year, and the second in three months.

The TAC meets again Sept. 27 before the next Board of Directors meeting on Oct. 9.

The annual TAC/TAC Subcommittee structural and procedure review will be held Sept. 13.

— Tom Kleckner

August 26, 2018

MISO Outlines Energy Storage Make-whole, Performance Rules

By Amanda Durish Cook

MISO is planning to provide storage with make-whole payments for price volatility, subject storage resources to dispatch and regulation performance rules, and exempt storage from certain uplift charges, officials said last week at a special conference call on compliance with FERC Order 841.

miso ferc order 841 energy storage — Howard | © *RTO Insider*

The RTO is proposing to use the same uninstructed deviation threshold it uses for other generators, Market Quality Manager Jason Howard said during the call on Aug. 21. MISO is currently refining a proposal to implement a more performance-based uninstructed deviation threshold. (See “Final Uninstructed Deviation Proposal,” MISO Market Subcommittee Briefs: May 10, 2018.)

Electric storage resources will be eligible for day-ahead margin assistance payments when they are dispatched below their day-ahead megawatt commitment and revenue sufficiency guarantee payments when they are dispatched in real time above their day-ahead commitments. They will also receive RSG payments when committed above their real-time economic minimum limit when committed in real time under a must-run commitment.

Storage could also be manually redispatched by MISO operators to contradict their day-ahead schedule or real-time offers, even to zero output, RTO staff said.

The RTO is also planning to exempt storage from its revenue neutrality uplift charge, its demand response resource uplift charge, and load ratio share adjustments and ancillary distributions. However, MISO said there was a potential for storage resources to be assessed real-time RSG distribution charges.

MISO plans to vet its performance rules with its Independent Market Monitor.

“We’ve just begun our collaboration with the Market Monitor … so that they do have an initial glimpse of our thoughts,” Howard said. He added that MISO will return with any rule changes regarding threshold and performance at the Sept. 13 Market Subcommittee meeting.

Some stakeholders asked for more specifics about MISO’s Order 841 compliance filing. The RTO said in June it would respond to Order 841 by dividing storage bid parameters into four operating modes: discharging, charging, continuous operations and offline. Market participants will be left to choose a mode for individual dispatch intervals and will also be responsible for managing the state of charge of their storage units. (See MISO Weighing Feedback to Storage Proposal.)

The Energy Storage Association’s Rao Konidena, formerly a MISO adviser, said storage owners must be able to switch among multiple market services, for example regulation to spinning and energy to regulation.

The ESA wants MISO to revise its proposal so that the RTO receives telemetered data in real time when an offline storage resource “returns to interacting with the grid” and can update the state-of-charge in offer parameters for the next dispatch interval. Konidena said that MISO has agreed that a resource’s state-of-charge when returning from offline mode may deviate from the resource’s last metered setpoint.

“MISO has recognized that a storage asset may go into offline mode and leave the market but still remain active charging and discharging to and from other sources and sinks,” Konidena said.

He also said MISO and its Monitor must address how such state-of-charge deviations when returning from offline would be handled.

“The concern is we would be penalized for that behavior,” Konidena said.

August 26, 2018

Can PG&E Quit CAISO? FERC Wants to Know

By Hudson Sangree

Responding to a ruling from a federal appeals court, FERC last week instructed Pacific Gas and Electric and the California Public Utilities Commission to brief it on whether California law allows PG&E to quit CAISO.

The question may be academic; there’s no indication PG&E wants to leave CAISO. But FERC’s ruling on the matter could be worth $30 million a year to the company.

The reason: If PG&E can leave CAISO when it wants, the utility is entitled to continue collecting a 50-basis-point return on equity to remain part of the state’s organized electric market. If it can’t quit, then it could lose its yearly incentive adder.

Ruling in response to a challenge by the PUC, a three-judge panel of the 9th U.S. Circuit Court of Appeals directed FERC in January “to inquire into PG&E’s specific circumstances, i.e., whether it could unilaterally leave the Cal-ISO and thus whether an incentive adder could induce it to remain in the Cal-ISO.”

If PG&E legally must remain part of CAISO, then the company is being paid for something it is already required to do, the panel wrote.

In its Jan. 8 ruling, the appeals court found that FERC had “arbitrarily and capriciously” awarded PG&E the incentive adder without determining whether the company was being incentivized to stay in CAISO, as required by the commission’s regulations. The court remanded the case to FERC to make that determination.

In response, FERC on Monday asked PG&E and the CPUC to brief four issues, including whether California law requires PG&E to participate in CAISO and whether FERC must defer to the PUC’s interpretation of state law (ER14-2529-005).

The controversy over whether PG&E is entitled to the incentive payments has been going on for years.

In the Energy Policy Act of 2005, Congress amended the Federal Power Act to require FERC to provide financial incentives to induce utilities to join RTOs.

FERC responded in 2006 with Order 679, which provided adders to the rate of ROE for utilities that participate in transmission organizations. The bonuses were meant to give utilities an extra reason to join or remain members of RTOs, which are generally voluntary.

The PUC, however, argues that membership in CAISO is mandatory for the state’s three big investor-owned utilities, including PG&E.

PG&E contends participation is voluntary. For staying in CAISO, PG&E has requested and received adders under Order 679 since 2007.

The PUC protested in years past and again in November 2017, saying the $30 million adder was an “unjustified windfall” at the expense of California ratepayers. The Sacramento Municipal Utility District joined the protest.

FERC dismissed the objections, but on appeal the 9th Circuit judges ruled FERC commissioners had abused their authority.

The FERC commissioners, the court said, did not reasonably interpret Order 679 as justifying adders for remaining in a transmission organization. Instead, the commission created a generic adder in violation of the order, the judges ruled.

Order 679 says FERC “will approve, when justified, requests for ROE-based incentives for public utilities that join and/or continue to be a member of” RTOs.

“If all utilities that continued to be members of transmission organizations automatically qualified for incentive adders, the ‘when justified’ language would be surplusage,” the appellate panel wrote.

Briefs from PG&E and the PUC must be submitted to FERC by Sept. 19.