Enviros, States Question Coal Self-commitments

By Tom Kleckner

SAN ANTONIO — Two environmental groups that say regulated utilities’ practice of self-committing coal plants is costing ratepayers have a point, RTO officials said Monday, even as they challenged the groups’ estimates.

The issue is also attracting scrutiny from state regulators.

The Sierra Club released a s tudy last month that estimates that “captive ratepayers” in MISO, SPP, ERCOT and PJM paid $3.5 billion more for energy from 2015 to 2017 because of the “noneconomic dispatch relative to the potential procurement of energy and capacity on the market.”

Coal Self-commitments — Union of Concerned Scientists’ breakfast panel during NARUC’s annual meeting last month | © *RTO Insider*

Meanwhile, the Union of Concerned Scientists (UCS) will release a study early next year that indicates that if MISO economically dispatched all its generation, average wholesale power prices would rise 3% but production costs would drop 11%. That would lower consumer costs, UCS Senior Energy Analyst Joe Daniel said during a Nov. 19 breakfast panel at the National Association of Regulatory Utility Commissioners’ annual meeting. “The market surplus, the relative profitability of the MISO system, would improve by 64%,” Daniel said.

The group, along with the Sierra Club and consumer advocates, has raised concerns about coal plants owned by vertically integrated utilities that self-commit, or run out of merit at times when their production costs exceed the wholesale market price.

The Sierra Club said out-of-merit operations suppress market prices, estimating that MISO’s median hourly market price would have been about $7.70/MWh (30%) higher if coal units had economically dispatched in 2017. “Improved dispatch practice would reduce customer costs, improve market revenues for efficient generators and renewable energy operators, and substantially reduce emissions,” it said.

Coal production costs are frequently above market prices, according to UCS. | *Union of Concerned Scientists*

‘Markedly Different Behavior’

The organization said the decision to operate consistently out of merit is not based on coal generators’ constraints alone, such as slow ramp rates, large fixed-price fuel contracts and avoiding the thermal stresses of repeated start-ups. “For example, within PJM, where most power units are merchants (i.e. unregulated), coal units generally operate in accordance with market prices. The few regulated coal units, owned by Dominion [Energy] or American Electric Power, demonstrated a markedly different behavior, operating in far more hours than warranted by market prices.”

Dominion did not respond to Sierra Club’s observations in detail Monday, saying in an email only: “Our customers expect clean energy that’s also affordable and reliable. We deliver just that, with enough solar and wind energy in operation or under development in Virginia by 2022 to power 750,000 homes. We’re proud of what we’ve accomplished and plan to do more.”

AEP’s Melissa McHenry said the report “does not provide an accurate portrayal of AEP’s generation unit operations within the RTOs” and said RTOs could improve efficiency through multiday dispatch and by sharing forecasted unit operation data.

AEP bids its generation into the markets to allow it to be economically dispatched, but the coal plants’ long start-up time makes it necessary to commit the units “to ensure they are available to produce benefits for our customers,” she said.

“During periods in which AEP anticipates sustained low prices, AEP does offer coal units for commitment and decommitment,” McHenry said.

RTOs Respond

ERCOT said it doesn’t comment on reports that are not staff’s own. Beth Garza, director of ERCOT’s Independent Market Monitor, said on Monday she had not reviewed the report and cautioned against assessing the results of decisions after the fact. “There are legitimate reasons why commitment decisions may appear uneconomic after the fact,” Garza said. “Specific examples are the load forecast didn’t materialize, or actual wind generation was higher than forecast.”

SPP said self-commitment “is not inherently and totally undesirable,” noting a self-committed unit may displace a more expensive one from running. But SPP spokesman Derek Wingfield acknowledged that self-commitments “may limit a market operator’s ability to dispatch generation as economically as possible” and said that SPP studies have shown there is room for “further optimization” in the markets through “further reduction of self-commitments.”

MISO conducted a study on multi-day commitments in 2017 that showed “significantly lower production cost savings” than Sierra Club’s report, spokesperson Julie Munsell said. “MISO’s generation owners and operators are in the best position to know all of the factors and requirements to optimize the reliable and efficient operation of their assets,” Munsell said.

The Union of Concerned Scientists says that if MISO economically dispatched all its generation, average LMPs would rise 3%. MISO says its own study of self-commitments showed a “significantly lower production cost savings.” | *Union of Concerned Scientists*

PJM spokesman Jeff Shields did not comment on the Sierra Club report but acknowledged that although units that self-commit on their own can’t set LMPs, they do change the offer stack “and can ultimately impact what the marginal unit may be.”

Self-committing units that provide an operating range and offer curve and allow PJM to dispatch them are eligible to set prices. PJM doesn’t assess “outright” penalties, but self-scheduled units are subject to operating reserve deviation charges, Shields said.

PJM Independent Market Monitor Joe Bowring said the Monitor’s analysis of coal plants at risk of retirement — which it defines as units for which the forward-looking net revenue from PJM markets does not cover going-forward costs — “does not support the conclusion that regulated units are uneconomic in PJM.”

“We think the UCS analysis is insightful, and we are continuing to develop more detailed analysis of self-scheduling practices in PJM using unit-specific, confidential data not available to UCS,” Bowring said.

Regulatory Recovery

UCS and Sierra Club say that by running the plants out of merit when their production costs are greater than wholesale market prices, utilities can recover fuel and operations and maintenance costs through regulatory proceedings. Sierra Club said its study estimated coal plants with negative revenue lost more than $3.8 billion in 2015-2017 when accounting for fixed O&M costs and revenues from MISO’s and PJM’s capacity markets. State ratemaking likely makes the utilities whole for their losses, Sierra Club said.

Annie Levenson-Falk, executive director for the Minnesota Citizens Utility Board, noted that the UCS study indicates that the state’s two largest entities — Xcel Energy’s Northern States Power and ALLETE’s Minnesota Power — could have realized $85 million to $90 million in gross savings had their coal units been dispatched economically.

“Those are substantial numbers, and it raises concerns for us,” Levenson-Falk said during the NARUC session. “Clearly, this is a problem in the way the plants are operating. In Minnesota, we’re moving quickly to a much higher level of renewable power. You talk about not just generating to meet load, but scheduling variability.”

FERC Commissioner Richard Glick, seated next to Levenson-Falk, was asked whether it was time for the federal commission to get involved.

“This is primarily, at this point, a matter for the state[s],” he said. “Certainly, we’re looking at it. It potentially could have a significant impact on the transparency in the markets we regulate and the price signals to market entry.”

“We can agree and disagree on whether it’s a state issue. I think it’s a game of hot potato,” said Indiana Utility Regulatory Commissioner Sarah Freeman, drawing a wry smile from Glick.

State Investigations

Minnesota and Missouri regulators have picked up the potato by opening investigations into self-commitment. Minnesota Public Utilities Commissioner Matt Schuerger said his commission opened the proceeding as an information-gathering process.

“I do think there are legitimate reasons for self-committing and scheduling, but things can be done better to save customers money,” he said.

Schuerger said the PUC also has potential questions around the reliability unit commitment (RUC) process. “ISOs like MISO have built their reliability commitment process on a large chunk [of generation] coming in at self-commitment,” he said.

“When I got to FERC, I thought I knew about markets,” Glick said last month. “The general notion is you bid in at marginal costs. The ones that bid in the lowest get what they’re needing. Where people aren’t bidding in at the marginal cost, sometimes they’re being told they’re not bidding high enough.

“A significant part of some of these markets, especially MISO and SPP, are not having a truly functional market. That raises a broader question of whether markets are functioning well and sending the right price signals.”

Ted Thomas, chair of the Arkansas Public Service Commission, suggested market monitors might be the right people to look at self-commitment practices.

“This is like the tip of an iceberg of a very big issue all markets will have to deal with,” he said.

SPP MMU IDs Problem

Indeed, SPP’s Market Monitoring Unit called self-commitment a problem two years ago and has been focused on the issue ever since. Its 2016 State of the Market report jived with a 2017 Sierra Club study that found SPP utilities with coal plants generated $300 million in excess costs in 2015 and 2016, costs that consumers picked up. (See Report: Costly Coal Undermining SPP Market, Bilking Consumers.)

The MMU is planning to release its own report on self-commitment within SPP in the next two weeks. Executive Director Keith Collins on Monday said the study results are “directionally” similar to Sierra Club’s latest report, but at a lesser magnitude. The MMU study found only about a 7% increase in costs when units were economically dispatched, as compared to the Sierra Club’s 30% figure.

Collins said the MMU used a day-ahead model in running its study, using historic bids and offers for additional granularity.

“The Sierra Club talks about more advanced forward markets that send a clear commitment signal. We, in our analysis, found that that is potentially a key factor in the analysis,” he said. “Our study found that if you made no change to the market and you just told resources to participate in the market, not only do you increase prices, you increase production costs. When you add a second day to the optimization, you effectively get the benefits of reduced production costs and you do get the increase in price. With a second day … you can capture most of the benefits of addressing the lead-time resources you see self-committing in the market.”

Recommendations

The Sierra Club report suggests commissioners examine the utilities’ market self-commitment and self-scheduling practices through investigations, expanded fuel or rate-case dockets, or during resource-planning reviews. The group also urges regulators to consider disallowing operational costs in excess of market necessity.

Thomas and Freeman last month responded with their own suggestions.

“Meet analysis with analysis … but determine what is going on operationally,” Thomas said. “There are formal and informal things we can do. There are suggestions, and there are carrots and sticks. My normal approach is to start with informal suggestions, because that’s easy, and proceed until the normal collision.”

Freeman argued against what she called adversarial proceedings. She invoked the name of noted regulatory attorney Scott Hempling, who she said preaches aligning interests, as opposed to balancing them.

“If ever there was an issue ripe for aligning interest, this is one of them,” she said. “Everyone wants to achieve those really favorable economic numbers that Joe has shown.”

December 3, 2019

Senate Confirms Brouillette as Energy Secretary

By Michael Brooks

The U.S. Senate on Monday voted 70-15 to confirm Dan Brouillette as secretary of energy.

Brouillette spent most of the day as acting secretary, after Rick Perry resigned on Sunday. Prior to that he had served as deputy secretary since August 2017, when the Senate confirmed him 79-17.

His confirmation was expected. He enjoyed mostly bipartisan support at his nomination hearing last month before the Senate Energy and Natural Resources Committee, which quickly moved to advance him to the floor by a 16-4 vote. (See Danly, Brouillette Advance to Senate Floor.)

The Senate on Nov. 21 voted 74-18 to invoke cloture on Brouillette’s nomination just before it adjourned for the month, setting up Monday’s vote.

Shortly before the vote, Sen. Ron Wyden (D-Ore.) called for a delay on Brouillette’s confirmation until the Senate received more information about Perry’s role in U.S.-Ukrainian relations, central to the House of Representatives’ inquiry into impeaching President Trump.

Wyden cited the fact that Perry had traveled to Ukraine in May for the inauguration of President Volodymyr Zelenskiy and provided him with a list of suggestions for the supervisory board of Naftogaz, the country’s state-owned energy company. The Associated Press reported that two of Perry’s political supporters secured a potentially lucrative oil and gas exploration deal from the Ukrainian government soon after the inauguration, and that one of them, Michael Bleyzer, was on Perry’s list.

Bill Taylor, the acting U.S. ambassador to Ukraine, testified to the House last month that Perry — along with U.S. Ambassador to the E.U. Gordon Sondland and Kurt Volker, special U.S. envoy to Ukraine — ran a “highly irregular” channel of U.S. policymaking toward Ukraine. Perry has refused to testify before the House. At his ENR Committee hearing, Brouillette said he had no knowledge of any conversations Perry might have had with Ukrainian officials about the matters the House is investigating. (See Brouillette Poised to Become Energy Secretary.)

Wyden noted that Brouillette is already serving as acting secretary. “Western civilization is not going to end if the Senate insists on getting some answers to the questions I’ve presented this afternoon,” he said.

Sen. Joe Manchin (D-W.Va.), ranking member of the ENR Committee, spoke in support of Brouillette. “I know some of my dear colleagues have some concerns about questions they want answered,” he said. “I did get some of those from him. He assured me his answers were accurate and correct.”

December 3, 2019

Monitor: Record Low PJM Prices Persist

By Christen Smith

Record low energy prices persisted for the first nine months of the year in PJM, and so too did rumblings from legacy generators losing money over it.

But the loud grievances of some shouldn’t outweigh the benefits to the many, the Independent Market Monitor said in its quarterly State of the Market report, urging stakeholders to be wary of sweeping changes to the markets.

“There is no reason to overturn the key components of the PJM capacity and energy markets,” the Monitor wrote in its report, published Nov. 14. “There is no reason to create convoluted capacity market rules to exclude any competitive offer from any technology including renewable and nuclear technologies. There is no reason to artificially increase energy prices to benefit nuclear and coal plants.”

The sentiments echo the Monitor’s warning in August that PJM’s markets “remain under attack” from those who think its outcomes shortchange them. (See Monitor: PJM Markets Remain Under Attack.)

PJM Market Monitor — PJM’s footprint and its 21 control zones | *Monitoring Analytics*

Instead, the Monitor said, stakeholders should focus on the “refinement of market rules” to “ensure the continued effectiveness of PJM markets in providing customers wholesale power at the lowest possible price, but no lower.”

The Monitor also said that a market-based carbon price — such as that of the Regional Greenhouse Gas Initiative — would serve PJM better than unit-specific subsidies or “inconsistent” renewable portfolio standard rules.

“Implementation of a carbon price using RGGI or a similar market mechanism by the states would mean that the states control the carbon price and that no FERC approval would be required and no PJM rule changes would be required,” the Monitor said. “The carbon price would become part of the marginal costs of power plants, and the impacts on production and consumption decisions would be market based. States would control the resulting revenues. This is the case regardless of the number of PJM states that join RGGI or a similar market.”

In the interim, natural gas plants will continue displacing coal-fired resources, and some nuclear units will lose money while sellers’ efforts to artificially control those elements will keep PJM’s capacity market uncompetitive, the Monitor said.

“The fact that some plants are uneconomic does not call into question the fundamentals of PJM markets. Many generating plants have retired in PJM since the introduction of markets, and many generating plants have been built since the introduction of markets. The level of potential retirements of coal and nuclear units does not imply a reliability issue in PJM and does not imply a fuel security issue in PJM.”

Energy Prices, Congestion Trending Down

Energy prices dropped 30% compared with the same time frame a year earlier, and congestion decreased by two-thirds, the Monitor said.

LMPs dipped from $39.43/MWh in the first nine months of 2018 to $27.60/MWh through September. Lower fuel costs contributed to nearly half the decline, the Monitor said.

As a result of the record low prices, many generators — including FirstEnergy Solutions’ two Ohio nuclear plants — won’t recover costs. (See related story, Ohio Supreme Court Dismisses FES Nuke Lawsuit.) The Monitor’s analysis concludes that average energy market net revenues decreased by 52% for new combustion turbine units; 32% for combined cycle; 82% for new coal plants; 32% for a new nuclear plant; 74% for a new diesel units; 29% for a new onshore or offshore wind installation; and 19% for a new solar installation.

New Recommendations

The Monitor’s highest priorities center around ensuring effective market power mitigation and updates to PJM’s real-time security-constrained economic dispatch (RT SCED) methodology, which stakeholders are exploring through a special session of the Market Implementation Committee. (See “5-Minute Dispatch and Pricing,” PJM MIC Briefs: July 10, 2019.)

To address market power issues, the Monitor said PJM should commit units based only on their parameter-limited schedules when the three-pivotal-supplier test is failed or during high-load conditions, such as cold- and hot-weather alerts or more severe emergencies.

PJM should also approve one RT SCED case for each five-minute interval to send dispatch signals and calculate prices using the same approved SCED case.

Other new recommendations:

PJM should model generators’ operating transitions and peak operating modes.
PJM should revert to the method for the calculation of implicit balancing congestion charges used prior to April 1, 2018.
Fleetwide cost-of-service rates used to compensate resources for reactive capability should be eliminated and replaced with compensation based on unit-specific costs.
The market efficiency process used to calculate the cost-benefit ratio of reliability-based regional transmission expansion projects should be eliminated because it is not consistent with a competitive market design.

December 3, 2019

Ohio Supreme Court Dismisses FES Nuke Lawsuit

By Christen Smith

The Ohio Supreme Court last week rejected FirstEnergy Solutions’ attempt to block a referendum to repeal $150 million in subsidies for its two nuclear plants.

Four of the court’s seven judges dismissed FES’ lawsuit, citing a “lack of justifiable controversy.” While the court documents offer no further elaboration, the referendum effort against FES’ plant subsidies failed in October, and its future — including whether petitioners will get extra time to gather the necessary signatures for inclusion on the November ballot — pends before the same court.

“The decision by the Ohio Supreme Court is a victory for Ohio’s electric customers and recognizes the attempted referendum on HB 6 is over,” Tom Becker, an FES spokesperson, said in email to RTO Insider on Monday. “Those opposed to the bill were unable to gather the requisite number of signatures to initiate a referendum; therefore there is no longer a need for the court to rule on the case.”

Ohioans Against Corporate Bailouts began a campaign against Ohio’s House Bill 6 the same day Gov. Mike DeWine signed the legislation in July. In October, however, the group said it fell nearly 45,000 signatures short of the count necessary for the referendum’s inclusion on the 2020 ballot.

Perry Nuclear Power Plant, located about 40 miles northwest of Cleveland | *FirstEnergy*

In its lawsuit, FES argued the new ratepayer fees collected for its nuclear plants — ranging from 80 cents to $2,400/month — are equal to a tax, making the underlying legislation ineligible for the petition that the group was circulating for a ballot referendum. The law suit named both the group and Secretary of State Frank LaRose, the state’s chief election official, as defendants. (See FirstEnergy Challenges Nuke Vote in Ohio Supreme Court.)

Gene Pierce, spokesperson for Ohioans Against Corporate Bailouts, had a different interpretation of the last week’s ruling.

“The Ohio Supreme Court decision correctly rejected FirstEnergy Solutions’ argument that HB 6’s billion-dollar bailout is not subject to referendum, one of many desperate and greedy FES maneuvers trying to deny Ohioans’ right to vote on bad legislation,” Pierce told RTO Insider in an email. “The argument was ridiculed from the first time it was aired in public, and this legal proceeding was a waste of the Ohio Supreme Court’s time and taxpayers’ money.”

Pierce’s group had asked a federal court to issue a preliminary injunction against HB 6, claiming 38 days of its 90-day allowance to collect signatures were wasted in a “blackout period” during which it sought the attorney general’s approval of the petition’s language before circulation could begin. The suit, filed in the U.S. District Court for the Southern District of Ohio in October, also alleged a well-funded opposition used illicit tactics to undermine its effort.

But Judge Edmund A. Sargus Jr. denied the group’s request later that same month, saying only the state Supreme Court can determine whether state law thwarted the group’s ballot petition — a review the panel has not yet indicated whether it will undertake. (See Federal Court Denies Nuke Petition Extension.) Attorneys for the group appealed Sargus’ ruling Nov. 22.

December 1, 2019

PJM MRC/MC Preview: Dec. 5, 2019

Below is a summary of the issues scheduled to be brought to a vote at the PJM Markets and Reliability and Members committee meetings Thursday. 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.

Markets & Reliability Committee

Consent Agenda (9:10-9:15)

PJM will ask for endorsement of:

B. PJM Manual 3: Transmission Operations — periodic review to update operating procedures.

C. Operating Agreement and Manual 6: Financial Transmission Rights — The first round of recommended rule changes for the RTO’s financial transmission rights market in the wake of the GreenHat Energy default include updated sections reflect additional rounds of the long-term auction and monthly-only balance of planning period auction. (See “FTR Market Rule Changes,” PJM MRC Briefs: Oct. 31, 2019.)

D. Manual 13: Emergency Operations — r e visions to incorporate 2020 day-ahead scheduling reserve requirement.

E. Manual 15: Cost Development Guidelines — r evisions that clarify that market sellers can only change the format of maintenance adders ($/MMBtu, $/MWh or $/start) during the annual review period for energy offer components. (See “Manual 15 Clarifications on VOM Costs,” PJM MIC Briefs: Nov. 13, 2019.)

F. Manual 18: PJM Capacity Market — r evisions that implement the new must-offer exception process approved by FERC to PJM Gens: Use or Lose Capacity Rights.)

G. PJM Manual 19: Load Forecasting & Analysis — a periodic review and documentation of the long-term load forecast.

H. OA revisions that clarify the requirements for sharing forecasted unit commitment data to transmission owners for reliability studies.

1. Transmission Asset End of Life Problem Statement and Issue Charge (9:15-9:45)

Stakeholders will decide whether to formally discuss how incumbent TOs make asset management decisions and whether those projects should stay outside of the regional planning process.

American Municipal Power and Old Dominion Electric Cooperative proposed a problem statement and issue charge at the October MRC meeting that would create a special session of the MRC to discuss what criteria TOs should observe before determining their infrastructure has reached the end of its life and whether those determinants could be — or should be — standardized across all zones. (See “Stakeholders Mull Tx Asset Management Discussion,” PJM MRC Briefs: Oct. 31, 2019.)

2. Opportunity Cost Calculator (9:45-10:05)

The MRC will decide between two packages to update PJM’s opportunity cost calculator.

The main motion from Dominion Energy and Panda Power Funds would make what the sponsors called “modest improvements” to the calculator and include Manual 15 revisions so that it more closely resembles the Independent Market Monitor’s calculator that most stakeholders prefer using. Just under 84% of stakeholders at the Market Implementation Committee voted in favor of the new package in September. PJM’s package — which maintains the status quo but also makes minor clarifications in Manual 15 — received endorsement from 51% of the MIC and will also receive MRC consideration if the main motion fails to gain a two-thirds, sector-weighted plurality. (See “Opportunity Cost Calculator,” PJM MIC Briefs: Sept. 11, 2019.)

3. Governing Document Enhancement and Clarifications Updates (10:05-10:20)

The MRC will vote on non-substantive changes to the Tariff, OA and Reliability Assurance Agreement that standardize cross references in all three documents.

4. Manual 03A Revisions (10:20-10:30)

The revisions to Manual 03A: Energy Management System Model Updates and Quality Assurance stem from a cover-to-cover periodic review and is phase one of an effort to update, reorganize and streamline the manual’s content.

Section 2 was redesigned to reflect PJM’s overall modeling philosophy. The RTO added sections on the following:

Section 2.2.1: Internal World Modeling Philosophy (BES Facility Modeling, Sub-transmission Modeling);

Section 2.2.2: Sub-transmission Modeling Criterion and Responsibilities;

Section 2.2.3: PJM External World Modeling (External World Modeling, Model Exchange and Extraction, Pseudo Tie Modeling, Pseudo Tie Eligibility, Pseudo Tie EMS Modeling);

Section 2.2.4: Naming and Modeling Standards; and

Section 2.2.5: Unique Device Consideration in the PJM Model.

Members Committee

1. Governing Document Enhancement and Clarifications Updates (1:25-1:40)

The same non-substantive changes to the Tariff, OA and RAA that standardize cross references in all three documents that will be up for a vote at the MRC earlier in the day.

2. Load Management Testing Governing Document Revisions (1:40-1:55)

The MC will vote on new load management and price-responsive demand testing rules for Capacity Performance resources after PJM said old measures failed to mimic real-life emergency procedures. (See PJM Stakeholders Support More Realistic DR Testing and “Stakeholders Urge Consensus on Load Management Testing Requirements,” PJM MRC/MC Briefs: Sept. 30, 2019.)

The MRC endorsed the new rules, effective with the 2023/24 delivery year, at its October meeting. (See “New Load Management Test Rules Endorsed,” PJM MRC Briefs: Oct. 31, 2019.) If approved, PJM would hold authority over scheduling tests — instead of the resource itself — and provide advanced notification so participants can prepare. The changes would implement a three-step system that gives resources first notice of an upcoming test one week prior to the two-week testing window, with additional alerts by 10 a.m. the day before and the day of the scheduled test. There will be one test per year when there is no event, with half of resources tested in winter and the other half in summer.

3. Elections (1:55-2:05)

The MC will elect its vice chair for 2020, members of the 2019-2020 Finance Committee and the 2020 sector whips.

December 1, 2019

MISO Explores Changes to Accommodate DER

By Amanda Durish Cook

MISO may have to devise new lines of communication, rethink its data management and alter dispatch rules to give distributed energy resources access to its markets.

Those opinions were laid out at a special Nov. 26 workshop focusing on DER assets’ communication and visibility to the MISO control room.

DER Program Manager Kristin Swenson said the RTO may have to develop new means of communication to provide visibility into distributed resources in the footprint.

“We’ve been pretty locked into this [Inter-Control Center Communications Protocol] world,” she said, referring to the predominant system of real-time data exchange for RTOs and ISOs. “There are a lot of other communication options.” She added that MISO will have to ensure the cybersecurity of communication with DERs and aggregators.

Wisconsin Public Service Commission policy analyst Ryan Kohler, who also participates in the Organization of MISO States, said collecting DER insights is particularly challenging considering that no standardized DER data policy exists across states or RTO/ISOs.

“There’s a cost to this; there’s a question of how all these [data-gathering methods] are going to work together,” Kohler said. “As penetration levels increase, it’s going to be essential that we know what’s going on.”

Kohler said DER operators are going to have to predict their resources’ behavior, be able to react in real time, and maintain forecasts for and historical data of their resources.

“It does take a specialist to get information like this. … So we’re putting the call out. It’s going to take a lot of folks with the same knowledge,” Swenson said, asking that MISO’s utilities make sure their representatives at DER workshops specialize in DER operations.

MISO distributed energy resources — MISO control room | *MISO*

Kohler also said the question remains about what data DER operators need to share with RTO/ISOs in order for them to be able to respond to dispatch instructions.

Advanced Energy Management Alliance Executive Director Katherine Hamilton said aggregators will help DERs meet ISO/RTO dispatch instructions and facilitate communication.

Swenson said that while MISO currently receives real-time load information, it receives no detailed or real-time information directly from devices or aggregations.

“We’re interested in how that evolution will affect us,” she said, adding that MISO is asking how much data it can realistically handle without being overwhelmed.

Answer in Aggregate?

Aggregator Enel X North America’s Nicholas Papanastassiou said his company already offers virtual power plants with market optimization engines that crunch weather data, site-specific costs and price forecasts to update market offers to RTOs. He said virtual power plants provide services that are “beyond simple telemetry.”

“Many other industry players have similar forms of this,” he told MISO staff and stakeholders.

Papanastassiou said it’s best if DERs are allowed to participate both in the retail and wholesale markets as much as possible, though he allowed that some issues might arise if DERs are held to an RTO’s must-offer requirement when they planned on not being available.

MISO Managing Assistant General Counsel Michael Kessler said the RTO’s must-offer requirement applies to capacity resources. Currently, MISO resources are barred from providing capacity if they also furnish output to areas outside the RTO.

Kessler said MISO hasn’t yet examined how a DER would become a capacity resource.

“We’re going to have to explore how these dual participations will line up with essential reliability services,” Kessler said.

Voltus CEO Gregg Dixon said the issue isn’t technology and metering, but dual rulesets from the states and RTOs.

“This isn’t rocket science,” he said of the technology involved for metering. He added that states should invite aggregated DERs into the wholesale market, where the states can benefit from both wholesale market resource adequacy credit and their DERs handling local needs.

“States sign up for the socialized benefits of a wholesale market. Yet, states don’t take full advantage of the benefits,” Dixon said.

MISO said its “key” future issue is aggregation. The RTO currently doesn’t allow aggregation beyond its pricing nodes or local balancing authorities, depending on how demand response resources have registered. And so far, only MISO’s Type II DR resources are eligible for dispatch, but they must be at least 1 MW in size.

Market design engineer Congcong Wang said a large aggregation across multiple transmission and distribution interfaces would affect transmission flow calculations, the RTO’s congestion management and create locational pricing inaccuracies.

MISO is home to about 31 DER pilot programs. (See OMS: 4.5 GW of Unregistered DERs in MISO.)

Mission:data President Michael Murray predicted that MISO will end up using “hybrids” of metering and data-gathering practices, given its large footprint of different state jurisdictions and utility models. He said it was difficult to imagine the RTO imposing just one metering type. Mission:data is a 35-member nonprofit that encourages customer data access policies across the country.

“A lot of these utilities are becoming IT platforms, and they need to be regulated like IT platforms,” Murray said, adding that states might consider designating centralized repositories for information.

“We’re all kind of dealing with this new frontier of working together,” Minnesota Public Utilities Commission DER specialist Michelle Rosier said.

The DER workshop was one of several MISO has hosted over 2018 and 2019, with plans to host more in 2020.

Swenson said MISO’s next DER workshop on Feb. 25 will focus on how the resources will impact the current transmission planning process.

“Because of the changes we’ve seen to the distribution system … our planning horizons may take too long. They’re very, very long,” Swenson said.

MISO also plans to hold another workshop in March on how DERs might contribute to its markets in the future.

December 1, 2019

Judge Denies PG&E Bid to Avoid Wildfire Liability

By Hudson Sangree

The federal judge in charge of PG&E Corp.’s bankruptcy rejected the utility’s argument that it isn’t subject to California’s legal doctrine of inverse condemnation, which holds investor-owned utilities strictly liable for damage to private property caused by their electrical equipment, regardless of fault.

PG&E and other IOUs have argued for years, in courts and in the State Capitol, that they shouldn’t be held responsible for wildfires sparked by their equipment absent a showing of negligence.

The most recent effort was waged before U.S. Bankruptcy Judge Dennis Montali in San Francisco. (See PG&E Seeks to Escape Inverse Condemnation.)

PG&E and its main utility subsidiary, Pacific Gas and Electric, the debtors in the Chapter 11 bankruptcy case, challenged the application of inverse condemnation to them in connection with wildfires in 2015, 2017 and 2018.

They asked Montali to rule that the state’s strict no-fault liability scheme does not apply to private utilities after a 2017 decision by the California Public Utilities Commission involving San Diego Gas & Electric. PG&E contended the CPUC ruling had undermined the ability of IOUs to pass on the costs of wildfires to ratepayers, which PG&E called a core tenet of inverse condemnation.

“Debtors do not appear to contest seriously the legal landscape of inverse condemnation, which is soundly against them,” Montali wrote in his ruling Wednesday. “Instead, they argue that the SDG&E decision renders prior decisions incorrect and that the policy considerations of inverse condemnation demand a result in their favor.”

utility inverse condemnation applies in the Camp Fire. — More than 14,000 homes in Paradise were gutted by the Camp Fire, the deadliest in California history. | © *RTO Insider*

PG&E told Montali he could limit the application of inverse condemnation to IOUs if he found the state Supreme Court was likely to reach a similar conclusion. The state’s highest court has never ruled on the issue, though lower appellate courts have unanimously held that IOUs are subject to inverse condemnation.

Lawyers representing fire victims and insurance companies said the arguments had no merit and were countered by more than a century of case law.

In his decision, Montali said much of PG&E’s argument boiled down to the idea that a privately owned utility shouldn’t be treated the same as a public utility under the doctrine of inverse condemnation, which has been embedded in California’s constitution since the mid-1800s and consistently applied by the courts to regulated utilities and railroads.

State lawmakers have refused repeated efforts to alter the law, including a push by PG&E in July to amend the doctrine to favor IOUs, the judge said.

“This court is not tasked to determine what the law should be and is merely tasked with interpreting what the law is and has been for 125 years,” Montali wrote. “The California legislature has not taken up [PG&E’s] cause to their satisfaction, and this court will not attempt to take its place.”

‘Prudent Manager’

Montali also said he thought it unlikely the state Supreme Court would find in PG&E’s favor, and he rejected the argument by PG&E that the 2017 CPUC decision had jeopardized its ability to spread wildfire costs to ratepayers.

In that decision, the CPUC rejected an application by SDG&E to recover its costs from paying out damages for two major wildfires in 2007. The commission found SDG&E had failed to “reasonably manage and operate its facilities” prior to the fires, saying only the prudence principle, and not inverse condemnation, was relevant to its ruling. PG&E argued the CPUC’s decision meant wildfire costs from inverse condemnation could no longer be spread to ratepayers.

Montali, however, said the CPUC had simply applied its longstanding reasonableness test to SDG&E. That test allows a utility to recover wildfire costs through higher rates only if it acted as a “prudent manager” in operating its grid.

“Essentially, the CPUC evaluates a private utility’s behavior to ensure that it has comported with best practices before it is able to pass on costs to the ratepayers,” the judge wrote.

Inverse condemnation is based on the concept that an entity, public or private, is responsible for damage it causes to private property because it has the power to seize private property for the public good, Montali said. The socialization of those damages is not a central component of inverse condemnation as described in the state constitution and decisions interpreting it, he said.

Since the 1870s, the state constitution has provided that “private property may be taken or damaged for a public use … only when just compensation” is paid to the owner. The provision was initially intended to stem the power of the Southern Pacific Railroad. For decades, courts have interpreted the provision to mean that regulated, monopolistic utilities must compensate property owners whose houses and businesses are destroyed by wildfires sparked by electrical equipment.

PG&E filed for bankruptcy in January following two years of devastating wildfires. State fire investigators found the utility’s equipment ignited 21 major fires in Northern California’s wine country in October 2017 and started the Camp Fire in November 2018. The Camp Fire killed 86 people and destroyed more than 14,000 homes and hundreds of businesses in the Sierra Nevada foothills town of Paradise.

“Debtors have admitted that their equipment was the cause of all the wildfires except the Tubbs Fire; they have not admitted liability for any of them,” Montali noted.

A trial in state court to determine if PG&E started the Tubbs Fire, which killed 22 people and leveled a neighborhood in the city of Santa Rosa, begins in January. Proceedings to estimate PG&E’s monetary liability in the other fires is occurring before another federal judge in San Francisco, subject to the rules of inverse condemnation.

December 1, 2019

Gen Operators Cool to Winter Preparedness Standard

By Holden Mann

Comments on a proposal to ensure generators are prepared for cold-weather events revealed widespread skepticism over the value of pursuing new standards.

NERC Panel Delays Action on Cold Weather Prep.)

The standard authorization request (SAR) would require generator owners and generator operators to:

develop “winterization plans, procedures, and winter-specific and plant-specific operator awareness training;
communicate “associated parameters for generating unit availability” during extreme cold weather to balancing authorities and reliability coordinators; and
work with BAs and RCs during severe weather events to ensure reliable performance.

While most of the 42 r espondents acknowledged the danger of underpreparedness during the winter months, many said the SAR in its current form is misguided.

A common objection voiced by operators in northern latitudes was that they already prepare for extreme cold as a matter of course, while the 2018 event affected generators in areas where winters are typically mild. For example, Thomas Foltz of American Electric Power observed that “RTOs often provide their own guidance” on cold-weather preparedness that are better tailored to the region in which they operate than any national standard could be. Kevin Conway from Public Utility District No. 1 of Pend Oreille County, Wash., said that “NERC has put out guidance on winter weather preparedness, and this should be sufficient.”

Winter Preparedness — Generation outages and derates by RC footprint beginning Jan. 17, 2018 | *FERC*

Richard Jackson, writing on behalf of the U.S. Bureau of Reclamation, said that while winterization is an essential goal, the SAR is too broad. If NERC mandates a cold-weather standard, he said, it should apply only to “areas that don’t normally see harsh winter conditions.”

“As the SAR is presently written, the future standard will result in an administrative burden that offers no increase in reliability for facilities that normally operate in a cold-winter environment,” Jackson said.

Some commenters in warmer areas also expressed misgivings about the proposal. Tony Skourtas of the Los Angeles Department of Water and Power observed that while extreme cold weather has created problems for his utility in the past, the issue was typically fuel supply. Even at the department’s generating station in Utah, which regularly encounters subzero temperatures in winter, “[the] turbine generator and the transformers historically have not been adversely effected.” As a result, he felt the SAR’s focus on generation resources provided no benefit for utilities like his.

Even among the few respondents who generally favored the SAR, many voices encouraged SPP to re-evaluate its scope. For instance, one commenter — identified only as “FE Voter, Segment(s) 1, 3, 5, 6, 4” — advised that nuclear facilities should be exempted from the final standard because the Nuclear Regulatory Commission already inspects for cold-weather preparedness.

Anthony Jablonski of ReliabilityFirst went further than this, arguing that a new standard provided a “perfect opportunity for other extreme weather conditions to be addressed,” such as heat waves, droughts or hurricanes. He also favored enlarging the standard to apply to transmission owners and operators, and to require winterization of switchyards and substations as well as generators.

Nominations for the standard drafting team closed on Nov. 5. NERC’s Standards Committee expects to make its selection and notify members this month.

November 27, 2019

FERC, RF in Debate over CIP-014 Modeling

By Rich Heidorn Jr.

WASHINGTON — FERC officials are engaged in a debate with ReliabilityFirst over the rigor of the modeling transmission owners should undertake to identify “critical” substations.

Matt Thomas, manager of critical infrastructure protection (CIP) compliance monitoring at ReliabilityFirst, told a Nov. 20 meeting of the RF Compliance Committee that FERC officials contend compliance with standard CIP-014 requires TOs to perform “dynamic” analyses in all cases, while RF believes they should be allowed discretion on when static load flow analyses are sufficient. Dynamic models can evaluate the grid’s performance under a variety of scenarios.

FERC approved the standard in response to the 2013 sniper attack on Pacific Gas and Electric’s Metcalf substation.

Requirement R1 of the standard requires TOs to identify substations “that if rendered inoperable or damaged could result in instability, uncontrolled separation or cascading within an interconnection.”

FERC ReliabilityFirst CIP-014 — Matt Thomas, ReliabilityFirst | © *ERO Insider*

“The standard does not mandate a specific analysis, or specific analytical method for performing the risk assessment,” Thomas said. “[It has] given the transmission owner the discretion to choose the specific method that best suits its needs.”

“Our current approach follows what is also outlined in the standards guideline technical basis, that the transmission owner has the discretion to select the analysis method that best suits and fits the facts and system circumstances.”

“The various inputs for registered entities’ risk assessments will likely vary from entity to entity, from region to region, from ISO to ISO and … they’re all based on the topology, and the system characteristics, and the system configurations.”

“With FERC as the higher power here, does that basically require us to comply with that FERC viewpoint?” asked RF Board member Brenton Green.

“At this point, it is a collaborative conversation,” responded Thomas. “They’re trying to see our viewpoint and why we feel it is not required in all circumstances. And we’re also trying to learn from them why they feel it is required. Right now, it’s just a conversation.”

Thomas said RF is discussing the issue with FERC and NERC in hopes of “being aligned on a common approach across the ERO.”

NERC and officials of other regional entities did not respond to requests for comment Tuesday. FERC declined to comment.

“FERC’s assertion that dynamic studies [are required] is probably not a bad one,” said RF Board member Lou Oberski. “You get a different answer if you do a dynamic study than if you just do a simple power flow, load flow kind of [analysis where] you take a station out and see what happens,” he said.

But he said not all entities have the “horsepower” to perform such analyses. “It would be a big lift for the medium-sized entities.”

RF CEO Tim Gallagher said the RE is “supposed to apply engineering judgment.

“So, in cases where it is a large critical facility and we think based on system knowledge and engineering expertise a dynamic stability study is warranted, we’ll do it,” he said. “But to blindly require it for everyone in cases where we know from engineering experience it’s not a concern, that gets into an unnecessary burden and an extra cost. We understand the distinction. We don’t want people to think we’re not going to do our jobs just because it might inconvenience someone.”

Conflicts of Interest on Third-Party Inspections?

Thomas also told the committee increasing use of third parties to meet some of the standard’s requirements has raised questions of conflicts of interest.

Requirement R2 requires TOs have an “unaffiliated third party” verify their risk assessment was performed as required under R1. R6 requires a third-party signoff on the evaluation of sites’ vulnerability to physical attack under R4 and any security plans developed under R5.

“What we’ve seen a few times now is an entity using the same third party for both the activity and the verification,” Thomas said. “As an example, an entity used a third party for their R1 analysis to help them [because] they didn’t have the resources and would also use that same third party to verify their work.”

“It doesn’t quite make sense to have the same party doing the work, and it is something we are continuing to keep our eye on to ensure the risk is addressed,” he said, adding the standard doesn’t explicitly prohibit third parties from reviewing their own work. “The example is if … you had a general contractor build your house … could that general contractor also do the inspection on their work?”

Oberski said the standards drafting team had added the third-party verification requirement to make sure entities “didn’t leave something out” in their compliance measures.

Other Challenges

Auditing for CIP-014 compliance has been challenging, Thomas said, in part because of the sensitivity of location-specific information.

“We’re still learning what the appropriate level [of documentation] is,” he said. “We have to make sure we tell a story of what we reviewed and what we saw but we also can’t capture sensitive information.”

There also are logistical concerns: CIP-014 audits can require additional site visits to substations in addition to corporate offices where much of the audit takes place. He said a recent audit led by FERC spent a week onsite on CIP-014 only.

Gallagher said CIP-014 audits have had benefits along with the challenges. “It’s good in a way because it’s cross-functional — CIP, O&P [operations & planning] and RAPA [reliability assessment and performance analysis], so it’s good for our internal development … but it makes it really hard to schedule. It doesn’t really fit with a CIP audit itself.”

Gallagher said early CIP-003 spot checks were combined with the O&P and CIP-013 spot checks. “As … more of [the CIP standards] became effective, we decided to split those into two separate engagements, mostly logistically for the entities and for us, for the amount of [subject matter experts] that would be required. But with the idea of smaller focused engagements, we are looking at doing combined audits at the same time. We actually are piloting it in 2020 where it will be a combined CIP and O&P engagement.”

RF officials said the combined CIP/O&P engagements would be piloted only for larger entities when the audit scope is fairly narrow.

November 27, 2019

Supply Chain Team Wary of Changing Access Control Terms

By Holden Mann

ATLANTA — The drafting team considering changes to supply chain standards may leave two key definitions in their current form due to concerns over scope creep and communication issues.

The definitions relate to electronic access control or monitoring systems (EACMS) and physical access control systems (PACS), which affect NERC reliability standards CIP-013-1 (Cyber Security – Supply Chain Risk Management), CIP-005-6 (Cyber Security – Electronic Security Perimeter(s)) and CIP-010-3 (Cyber Security – Configuration Change Management and Vulnerability Assessments).

NERC initiated Project 2019-03 after FERC directed it last year to develop rules expanding the supply chain protections to include EACMS. (See FERC Finalizes Supply Chain Standards.) The standard authorization request (SAR) also cited the changes recommended in NERC staff’s supply chain ri s ks report in May. (See “Supply Chain Report Recommends Expanding Standards” in NERC Standards Ne w s Briefs: May 8-9, 2019.) NERC requested the standards drafting team (SDT) also consider revising the definition of PACS as well.

Both definitions apply only to those systems that provide electronic or physical access control to high and medium impact cyber systems. In addition, the definitions would explicitly cover virtual cyber assets, defined as an operating system, firmware or application hosted on shared cyber infrastructure, which are not addressed in the current standard.

In its meeting last week, the standards drafting team (SDT) discussed a suggestion from FERC earlier this year to split the definition of EACMS. Under the proposed change, the existing term would be replaced by EACS (electronic access control system) and EAMS (electronic access monitoring system). Sharon Koller of American Transmission Co. pointed out that using two terms would allow FERC greater precision when doing further work on the standards and help operators avoid confusion.

“There’s somewhat of a contradiction in the usage of the term, and it causes me to question whether FERC used the term EACMS in the order because it’s the only term that existed, or if in fact FERC intends for this standard to cover all of those things,” Koller said. “I’m a proponent of trying to move forward with the two split terms rather than keeping EACMS on the table, [which] I think … just prolongs the pain for industry.”

However, some SDT members felt accepting the changes now could lead to confusion with other standards teams that rely on the original definitions. Communicating proposals to industry could prove difficult as well, with multiple standards using different terminology that must be explained each time.

Discussion over PACS followed similar lines, with the team debating a suggestion to remove alerting and logging functions from the current definition of PACS. These, along with monitoring functions, would be reclassified as physical access monitoring systems (PAMS).

Here the drafting team was more divided: Some members advocated changing the PACS definition to keep the approach to physical and electronic systems aligned, while others said since compromising physical security would give attackers access to electronic systems as well, it made sense for one SDT to consider both. Balancing this viewpoint were those who criticized the inclusion of PACS as an unnecessary expansion of the team’s remit that would place an additional burden on members.

“We’re trying to meet this rigorous timeline that FERC suggested, and … it’s not a mature standard yet. We’re trying to understand it and digest it,” said Jason Snodgrass of Georgia Transmission. “You’re trying to get a whole new realm of your corporation to understand [these] standards … I would be on the side of the fence to recommend patience and stick to the FERC directive.”

Despite the deadline of 24 months given in FERC’s October 2018 order, the SDT decided these questions were compelling enough to keep the EACMS and PACS definitions as is for the initial ballot and comment. This is expected to run from late January through early March, though depending on the team’s schedule it may be moved forward by a few weeks. Team members will meet again in person following the conclusion of the ballot to review the responses and decide whether to adopt the suggestions.