Page 1052 – RTO Insider

April 15, 2019

ERCOT Board of Directors Briefs: April 9, 2019

ERCOT staff last week warned that forward energy markets indicate high prices this summer, which could lead to unexpected increases in credit obligations.

Given current forward prices, Mark Ruane, ERCOT director of settlements, retail and credit, told the Board of Directors during its April 9 bimonthly meeting that forward adjustment factors may increase materially as summer draws closer, leading to “substantial increases in collateral requirements for ERCOT counterparties.”

ERCOT’s April Board of Directors meeting

Ruane said the market “seems to be expecting high prices,” pointing to August forwards that approached $185/MWh for ERCOT’s North hub but settled back to $160/MWh in mid-March. July forwards were about $100/MWh, and June forwards $85/MWh.

Forward prices are used to adjust the day-ahead and real-time exposure components of ERCOT’s credit calculation. Counterparty letters-of-credit are capped at $750 million, which has been reached only three times — all during last summer.

Ruane said he wants to ensure counterparties are aware of the risks of increased credit requirements and constraints on letter-of-credit issuers, and that they maintain “appropriate collateral” and sufficient letter-of-credit capacity.

“We’re highlighting this risk because we hit the limit three times” last summer, Ruane said.

The Texas grid operator has a historically low planning reserve margin of 7.4% as it heads into summer. It is projecting a record peak of 74.9 GW this summer, with 78.2 GW of capacity on hand. (See ERCOT Summer Forecast: Record Demand, Alerts.)

Ruane also said ERCOT will be holding a mass transition drill with market participants and Texas regulatory staff during the second quarter. The drill is intended to identify potential issues in transitioning a defaulting competitive retailer’s electric service identifier IDs.

Staff, TAC Promise Updates on Cold Weather Event

ERCOT CEO Bill Magness and ENGIE’s Bob Helton, chair of the Technical Advisory Committee, both promised directors and stakeholders a future update on the grid operator’s actions to address events during an early March cold spell that led to much market consternation. (See ERCOT Generators Upset over Early March Weather Event.)

Magness said ERCOT actions “focused on delaying scheduled outages that had not begun prior to forecast peak day morning loads.” Stakeholders complained about a lack of transparency into market information and confusion over communications.

“Sometimes, it’s very important what words you use. ‘Request’ and ‘instruction’ are different things in our world,” Magness said during his CEO update. “The market has to know exactly what to expect from us when we get into these situations.”

The TAC has created a task force to determine improvements that can be made in future situations. Magness said changes could involve:

Communications and procedures during anticipated emergency conditions;
Market visibility of ERCOT forecasts as conditions change;
A process governing delay or withdrawal of planned outages; and
Consideration of cost recovery related to postponing or canceling outages for reliability reasons.

Helton said the TAC plans to hold one or two workshops on the recommendations that might come out of the work.

“We were using new tools, based on where we are today in unchartered territory,” he said. “Sometimes, when you use those tools, you find concerns. There was a little rust on those tools.”

ERCOT Board Chairman Craven Crowell (left) and CEO Bill Magness (right)

ERCOT Projecting $34M Favorable Budget Variance

Magness told the board that ERCOT is already projecting a favorable budget variance of $34 million this year, after having ended last year with a roughly $29 million favorable variance.

The CEO said the variance is driven by interest income from congestion revenue rights and continued load growth. Interest income is expected to be almost $19 million over budget this year as a result of higher balances and rates, and administrative fees are projected to be $6.1 million over budget, based on current system load actuals and forecasts.

A reduction in ERCOT project costs could add another $7 million to the variance. The grid operator moved several projects up from 2019 into 2018, accounting for much of the variance, Magness said.

Magness also unveiled ERCOT’s annual State of the Grid report in a redesigned format that features major accomplishments from 2018’s record-breaking year and highlights the grid operator’s effort to facilitate a competitive retail market, incorporate new technologies and improve cybersecurity awareness.

Directors Approve Changes to NPRR916

The board unanimously approved a pair of Nodal Protocol revision requests (NPRRs) previously endorsed by the TAC during its March meeting.

NPRR916, which changes the mitigated floor for natural gas units from a fuel-indexed price to -$20/MWh, was approved as amended by ERCOT comments. Staff recommended the mitigated floor price be reduced from its original level of $0 and also requested the NPRR’s implementation be accelerated from May 1 to April 10 to “correct inconsistencies in pricing outcomes.” (See “ERCOT to Ask Board for NPRR916 Changes,” ERCOT Briefs: Week of April 1, 2019.)

Mark Ruane, ERCOT director of settlements

The amendments were driven by recent negative gas prices at the Waha Hub and to match the mitigated floor for coal and lignite units.

NPRR909 resolves a gap in the protocols by addressing the unplanned unavailability of emergency response service (ERS) loads and generators. Morgan Stanley, in the Independent Power Marketer segment, cast the lone opposing vote at the TAC “as a matter of principle,” Helton said.

Directors also approved the Human Resources and Governance Committee’s recommendation to allow business-continuity emergency purchases by ERCOT of up to $5 million and unanimously approved nine other NPRRs, a change to the Retail Market Guide (RMGRR) and a system change request (SCR) on its consent agenda:

NPRR891: Removes the 50-kW threshold for non-opt-in entities to report unregistered distributed generation to ERCOT for its unregistered DG report.
NPRR900: Addresses inconsistencies in the current Nodal Protocol language that don’t align with current processes, Texas Public Utility Commission rules and system design.
NPRR906: Streamlines the protocol language and removes ambiguity over how ERCOT systems handle the decision-making entity during the security-constrained economic dispatch (SCED) mitigation processes.
NPRR908: Aligns RMG references and updates mass transition notification requirements for emergency qualified scheduling entities (QSEs) to match with RMGRR159’s revisions.
NPRR912: Addresses the settlement of switchable generation resources (SWGRs) that receive a reliability unit commitment instruction to switch from a non-ERCOT control area to the ERCOT control area. The change provides a make-whole payment for an SWGR when its real-time ERCOT revenues are not sufficient to cover certain specified costs the resource may have incurred in complying with the RUC instruction.
NPRR914: Adds data points unique to a controllable load resource available for dispatch service or dispatch with a real-time market bid to the existing 60-day SCED disclosure report.
NPRR8920: Modifies the resource ramp rate logic in the protocols (Section 6.5.7.2, Resource Limit Calculator) to dynamically adjust the amount of ramp rate reserved for regulation service in real time based on the percentage of regulation service being deployed in the opposite direction.
NPRR922: Aligns the DC tie import forecast with forecasts of other resources in ERCOT’s Capacity, Demand and Reserves (CDR) report that are deployed during ERS and other energy emergency alert events. The revision also addresses a reporting gap in the CDR by specifying an approach for forecasting expected capacity imports for planned DC tie projects.
NPRR925: Increases the minimum quantity that can be submitted for point-to-point (PTP) obligation bids from 0.1 MW to 1 MW, matching the minimum quantity for energy-only offers and energy bids.
RMGRR159: Clarifies the mass transition processes and communications by shortening required minimum timelines for initial notification to affected parties from two hours to one hour, and allowing preliminary notification of mass transition to affected transmission and distribution service providers, providers of last resort and PUC staff, as long as protected information is not disclosed. Also clarifies that ERCOT may coordinate periodic testing of mass transition systems and processes with market participants.
SCR798: Introduces a limit on the total number of PTP obligation bids that can be submitted into the day-ahead market per QSE and per counterparty. The limit will apply to the number of bid IDs per operating day.

— Tom Kleckner

April 15, 2019

Supreme Court Won’t Hear ZEC Challenges

By Rich Heidorn Jr.

The U.S. Supreme Court on Monday declined to hear challenges to Illinois’ and New York’s zero-emission credit payments to nuclear plants.

The court denied the Electric Power Supply Association’s petitions for certiorari without comment. The decision left standing last September’s rulings by the 2nd and 7th U.S. Circuit Courts of Appeals that rejected claims that New York’s and Illinois’ ZECs intrude on FERC jurisdiction (18-868 Electric Power Supply Assn. v. Star, Anthony M., et al.; 18-879 Electric Power Supply Assn. v. Rhodes, John B., et al.).

EPSA had been joined by NRG Energy and Calpine in its challenges. The challengers also won support from Courts Misread Hughes on Nuke Subsidies, Supreme Court Told.)

The court’s unsurprising decision — it hears only a small percentage of the cases on which it is petitioned — was a victory for Exelon, the nation’s largest nuclear operator. The company is currently lobbying for nuclear subsidies in Pennsylvania. (See related story, Nuke Talks Continue in Pa. Assembly.)

FirstEnergy also is supporting the legislative effort in Pennsylvania and a similar bill introduced Friday in Ohio to support its Davis-Besse and Perry plants.

New Jersey and Connecticut have also approved nuclear subsidies.

Hughes Ruling

EPSA’s supporters had contended the appellate courts misinterpreted the Supreme Court’s 2016 ruling in Hughes v. Talen, in which the court unanimously rejected Maryland’s contract-for-differences with a natural gas plant.

The court provided state regulators guidance for crafting subsidy programs in the future, saying it rejected Maryland’s initiative only because it was tied to PJM capacity prices. Monitoring Analytics, PJM’s Monitor, contended that legislators could easily avoid the “explicit tether” the court rejected in Hughes.

ClearView Energy Partners said the court’s refusal to hear the New York and Illinois challenges “may cement the ‘fatal defect’” in Hughes.

“In other words, the Supreme Court has not changed its stance that [states] have legal authority to favor certain resources so long as their programs do not require those resources to participate in wholesale electricity markets (even if, as a practical matter, those resources do participate in the markets),” ClearView said.

“Today’s decision likely leaves ZEC opponents looking to the market operators to propose tariff reforms that FERC can approve as the source for relief,” ClearView continued, referring to efforts to ISO-NE’s implementation of a minimum offer price rule (MOPR) for subsidized resources and FERC’s June 2018 order requiring PJM to strengthen its MOPR to address nuclear and renewable subsidies. (See FERC Orders PJM Capacity Market Revamp.)

EPSA Seeks FERC Action

EPSA CEO John Shelk said FERC — which had argued against EPSA’s claim for federal pre-emption of the Illinois law — should now act to protect wholesale market prices from being distorted by nuclear subsidies.

“Even though … FERC determined state nuclear subsides and others impair the integrity of PJM’s wholesale market, FERC has yet to fashion a solution. That is hardly what FERC told the court it would do to protect markets,” Shelk said in a statement.

“The problem has only gotten worse since the June 29, 2018, order, with emboldened nuclear subsidy seekers now pounding on the doors of state legislatures in Ohio, Pennsylvania and again in Illinois for a second helping. FERC told the appeals court the solution lies with FERC; the time for FERC to live up to that promise is now.”

The Electricity Consumers Resource Council (ELCON), which represents industrial customers, said it was disappointed in the ruling. “Subsidizing uneconomic power sources undercuts the competitiveness of U.S. manufacturing, which must maintain a global fuel cost advantage,” CEO Devin Hartman said in a statement.

Environmental Defense Fund Senior Attorney Michael Panfil praised the ruling as “great news for all states that are working to create their best possible climate and clean energy policies.”

“In case after case, our courts have confirmed that states have the fundamental legal authority to craft clean energy policies, address climate change, and work to reduce unhealthy air pollution in order to safeguard the welfare and well-being of their people,” he said. “The Supreme Court’s order today puts any lingering questions to rest.”

April 14, 2019

UPDATED: Nuke Talks Continue in Pa. Assembly

(Updated to include House hearing April 15.)

By Christen Smith

Pennsylvania senators waded into the debate over subsidizing the state’s nuclear fleet on Wednesday, questioning the owners’ need for a legislative solution at a time they are reporting substantial profits.

“You guys are not winning the war in my district,” State Sen. Mario Scavello (R) told a panel of nuclear executives during a public hearing on Senate Bill 510 on Wednesday. “When they are told their electricity bill is going to go up, that just gets to them.”

Exelon and FirstEnergy Solutions told the Senate Consumer Protection and Professional Licensure Committee that SB 510 levels the playing field for carbon-free energy sources unable to profit at low wholesale prices set by polluting fossil fuels. Both companies announced early retirements for nuclear facilities in Pennsylvania, including Three Mile Island in September and Beaver Valley in 2021.

“When the rules allow you to pollute for free, not show up when customers need the power, and get paid the same as power plants that don’t pollute and run 24/7, of course you like the rules,” said Kathleen Barron, senior vice president of government and regulatory affairs for Exelon. “Fossil generators have the luxury of having the costs of their pollution borne by society so they do not have to factor those costs into their market offers.”

Sen. Ryan Aument (R) introduced SB 510 on April 3, more than three weeks after a similar House of Representatives plan drew criticism for its perceived favoring of expensive, aging nuclear facilities instead of cheaper renewable resources or fossil fuels. (See Pa. Lawmakers Introduce 2nd Nuke Subsidy Bill.) Both proposals create a third tier within the state’s Alternative Energy Portfolio Standard (AEPS) program, from which suppliers must buy 50% of their power by 2021. Unlike the House version, however, the Senate bill directs the Public Utility Commission to set credit prices and guarantee between 17 and 23% of Tier III sources purchased include non-nuclear suppliers, like wind and solar. The first two tiers of the AEPS include 16 renewable resource types with targets of 8% and 10%, respectively.

“It’s not a zero-sum game where only one resource, nuclear or renewables, can grow,” Aument said on Wednesday. “My bill makes sure there’s space in Tier III to build up a competitive renewable portfolio. I am not, nor have I ever been, interested in a direct government subsidy for the nuclear industry.”

Pennsylvania State Sen. Ryan Aument (R), S.B. 510’s prime sponsor

In February, Exelon reported record-breaking production levels for its nuclear fleet in 2018. It anticipates operating earnings of $3 to $3.30/share in 2019 based on growth in utility revenue, the impact of zero-emission credits on its New Jersey nuclear plants and previously announced cost reductions.

Sen. Kim Ward (R) pressed Exelon about the billions in profits the nuclear industry collected last year and questioned whether the company supported the bill for financial or philosophical reasons.

Barron said the wholesale market values the cheapest price over the cleanest form of energy, saying it is an unfair comparison that leaves nuclear plants with their hands tied.

“We feel like it’s a financial question of what we are earning as a result of market rules,” she said.

Dave Griffing, senior vice president of government affairs for FirstEnergy Solutions, told Ward to look no further than his company’s latest bankruptcy filings.

“FirstEnergy Solutions wouldn’t have entered into Chapter 11 restructuring if this wasn’t a financial concern,” he said. “We have two sources of revenue — generation and capacity — and those are deflated, so yes it’s a financial concern for us.” (See Judge Rejects Liability Release in FirstEnergy Reorg.)

Critics of the bill insist the subsidies disrupt the competitive wholesale market. (See Critics Warn Pa. Lawmakers Against Nuke Subsidy Bill.)

“With respect to nuclear power plants, [financial problems have] largely been limited to single-reactor units that do not possess the efficiencies of scale to be economically competitive,” said David Spigelmyer, president of the Marcellus Shale Coalition. “Currently across the United States, six nuclear power facilities have announced retirement plans. Four of the facilities are single-reactor facilities, while the other two have announced retirements due to a variety of locally significant factors, including opposition from environmental organizations.”

PJM’s Independent Market Monitor said last month that three of the RTO’s 18 nuclear facilities face revenue shortfalls through 2021. The three plants — Davis-Besse, Perry and TMI — each operate just one reactor. The remaining multiunit facilities, including the subsidized Quad Cities in Illinois, will remain profitable. Even without ZECs, Quad Cities would cover its costs for the next three years, according to the Monitor. (See Monitor Says PJM’s Capacity Market n ot Competitive.)

An analysis from the National Conference of State Legislatures determined SB 510 would cost $550 million in tax credits at a rate of $6.68/MWh — far lower than the prices of subsidies in Illinois, New York and New Jersey. Pennsylvania’s sheer amount of eligible megawatt-hours — $83 million spread across nine nuclear reactors — would make it the largest subsidy program nationwide.

House Resumes Hearings

The House Consumer Affairs Committee drilled deeper into questions surrounding Exelon’s profits during a second hearing on the similarly structured HB 11 on Monday. Citing the Market Monitor’s estimates, Rep. Ryan Mackenzie (R) asked Barron whether Exelon’s other Pennsylvania plants — Limerick and Peach Bottom — earned nearly $350 million combined in 2018, compared to TMI’s $37 million loss.

Barron refused to detail individual unit costs and revenue forecasts and said the Monitor’s estimates are inaccurate.

“It is inaccurate to the extent that the data is based on industry averages in terms of costs,” she said. “The Market Monitor does not have unit-specific costs, as that is competitively sensitive information. The estimates assumed there will be no change in costs and costs will stay exactly the same. It also assumes there will be no risks.”

An analysis from the National Conference of State Legislatures determined SB 510 would cost $550 million in tax credits at a rate of $6.68/MWh — far lower than the prices of subsidies in Illinois, New York and New Jersey. Pennsylvania’s sheer number of eligible megawatt-hours — $83 million spread across nine nuclear reactors — would make it the largest subsidy program nationwide.

Discussion on HB 11 will continue April 29. Barron said if no policy solution passes the legislature before June 1, TMI will shut down.

April 14, 2019

Former FERC Commissioner Brownell Named PGE Chair

By Hudson Sangree

As part of its continued leadership shakeup, PG&E Corp. said Thursday that former FERC Commissioner Nora Mead Brownell would be its new board chair and that Jeffrey Bleich, a veteran lawyer and former U.S. ambassador, would chair its utility subsidiary Pacific Gas and Electric.

“We are focused on taking additional actions to bring about real and dynamic change that reinforces our commitment to safety and continuous improvement,” PG&E said in a news release. “The appointments of Nora Mead Brownell and Jeffrey Bleich, two respected leaders with a deep understanding of the California and federal regulatory environments, underscore our commitment to engage with our stakeholders to address the state’s evolving energy challenges.”

Former FERC Commissioner Nora Mead Brownell | © *RTO Insider*

The news came a week after PG&E announced that a “refreshed” board of 13 directors, to be approved at the next board meeting, would include Brownell, Bleich and eight other new members, along with three holdovers from the current roster. The company also said Bill Johnson, the outgoing head of the Tennessee Valley Authority, would be its new CEO starting May 1. (See PG&E Names New CEO, Board Members.)

The selections were a response to calls from California’s political leaders and utility regulators for greater change at PG&E, which has been blamed for more than 90 deaths from a series of disasters in the past decade, including catastrophic wildfires and a gas pipeline explosion. Critics have said the company’s leadership was skewed toward Wall Street and lacked safety and operations expertise.

PG&E Corp. and Pacific Gas and Electric filed for Chapter 11 bankruptcy reorganization in January, citing the potential for billions of dollars in fire liability.

Some officials, including California Gov. Gavin Newsom, said the newly announced board represents only minor improvement. BlueMountain Capital, a New York-based investment firm, has put together its own slate of candidates that includes former California state treasurer and gubernatorial candidate Phil Angelides.

Brownell helped oversee the transition of NERC to FERC oversight during her term (2001-2006). She later co-founded energy consulting firm ESPY Energy Solutions and has served on the boards of directors of National Grid and Spectra Energy Partners and the advisory board of Morgan Stanley Infrastructure Partners. She was president of the National Association of Regulatory Utility Commissioners during her time as a member of the Pennsylvania Public Utility Commission.

Bleich is a former partner at the global law firm Dentons and a leader of its diplomatic consulting group, PG&E said. He previously served as special counsel to President Barack Obama and president of the California State Bar.

Kristine Schmidt, a member of the Energy Imbalance Market Governing Body who was an aide to Brownell at FERC, was also named as a new PG&E board member. Schmidt is president of Swan Consulting Services.

Brownell did not respond to requests for comment. PG&E has said it may make its new leaders available for interviews after they are “onboarded.”

April 14, 2019

MISO Gives Tentative Nod to Seasonal Capacity Design

By Amanda Durish Cook

CARMEL, Ind. — MISO now cautiously estimates that the benefits of a seasonal capacity auction would outweigh potential drawbacks.

“Right now, our working hypothesis is that it makes sense … but at the end of the day, that’s something we’re really going to have to verify,” Laura Rauch, MISO director of resource adequacy coordination, said during an Resource Adequacy Subcommittee meeting Wednesday.

The RTO last month rekindled the idea of a seasonal capacity auction as part of its multiyear resource availability and need (RAN) initiative. (See MISO, Stakeholders Debate Merits of Seasonal Auction.)

MISO planning adviser Davey Lopez said a seasonal auction would likely create price signals that better match the fluctuating value of capacity across seasons and a “better accounting of resource availability outside of summer.” If MISO adopts a seasonal construct, it would probably establish seasonal reserve requirements.

A seasonal auction would provide “additional visibility into risks not currently captured due to variations in capacity, load, outages, transmission limitations and weather,” Lopez said.

“There may be resources that are not participating in the annual construct when it would make sense for them to participate in one season,” Lopez said, adding that retiring generation and new market entrants alike could participate as partial-year capacity resources.

Customized Energy Solutions’ David Sapper said a seasonal auction could provide a solid foundation as MISO prepares for more renewable resources in its fleet. He said seasonal distinctions make sense when considering the varying output characteristics of the “wind and solar we’re worried about.”

“Setting a framework for this in the future is pretty critical,” Rauch agreed.

But Lopez said MISO is thinking about potential tradeoffs in a seasonal capacity future. He said seasonal auctions could produce complex changes to the loss-of-load expectation (LOLE) study and resulting reserve margin requirement.

Consumers Energy engineer Jeff Beattie said that while his utility for years advocated for a seasonal auction, it has now backed off the idea.

“We’re not necessarily seeing the benefit because our fuel mix is changing. We’re going zero-carbon,” Beattie said. He noted that much of the economic benefit of a seasonal auction derived from converting annual fuel contracts into shorter duration contracts.

“Whereas now, as we’re retiring all of our fossil units, we’re not seeing that cost savings anymore. … I hope we see a study with customer benefit and savings,” Beattie told MISO staff.

But some stakeholders said zero-carbon resources reinforce a need for an auction with seasonal granularity.

Xcel Energy’s Tom McDonough said utilities’ solar additions require a more specific seasonal accreditation. He argued that it’s not appropriate for MISO to accredit solar generation according to its summer output.

“As we know in Minnesota, it’s not going to be there in the winter. It’s not diluted so we’re going to get an exaggerated credit. …We have a thing called snow that covers a solar panel,” he joked.

McDonough said he would support even more auction specificity or even a return to MISO’s earlier monthly capacity auction design.

Madison Gas and Electric’s Megan Wisersky said MISO might consider that capacity today isn’t as fungible as it used to be because of characteristics of new types of generation.

Lopez said MISO will return to the RASC in May with a skeleton design of a seasonal auction.

More LMR Details in LOLE Study

MISO will this year also model load-modifying resource availability information into its annual LOLE study, which does not currently include availability and resource lead times.

Rauch said the improved specificity in LOLE data shouldn’t be considered a process change to the study. She said MISO will only be working with more specific availability data.

But Beattie said the small study alteration should still be documented for stakeholders.

MISO also said it will postpone a plan to model sub-optimized scheduled outages in the LOLE study. The RTO took stakeholders’ advice that it should first gauge the impact of its new planned outage scheduling rules before modeling poorly scheduled outages in the LOLE study. (See “History on Repeat?” MISO, Stakeholders Debate Merits of Seasonal Auction.) In the meantime, MISO will continue to gather information on how outages affect supply.

Lopez said aside from an unusual hypothetical testing scenario with high outages and zero LMR response, material loss-of-load risk within MISO still does not occur outside of summer.

April 14, 2019

New MISO Report Starting Point for Major Grid Change

By Amanda Durish Cook

CARMEL, Ind. — MISO’s new annual report on future trends offers few specifics on the future resource mix and how the RTO will manage renewables growth and continued turnover in the resource stack.

But it does include a plethora of suggestions for market changes that could ease the transition to a still hard-to-pin-down future fleet.

Speaking during an April 9 workshop focusing on the report, MISO Consulting Adviser of Market Design Kim Sperry likened the RTO’s future uncertainty to the small row of electric vehicle charging stations in the parking lot of its Carmel headquarters. She said it remains to be seen whether every parking spot will one day host a charging station.

Sperry asked stakeholders in the room if they thought MISO’s previously identified industry trends of demarginalization, digitalization and decentralization will continue. (See Overheard at MISO Market Symposium.) Most of the about 20 attendees raised their hands, with an enthusiastic Jeff Beattie of Consumers Energy raising both.

“What’s the fleet of 2030? It can be a huge range of possibilities,” MISO Senior Manager of Market Strategy Mia Adams said.

MISO previewed its Forward Report last month by identifying three areas of focus: increasing the deliverability and availability of resources, bettering system flexibility and improving its visibility of distributed energy resources. (See MISO: Winter Emergency Another Signal for Grid Ops Change.)

The RTO said it may suggest scarcity pricing, a 15-minute day-ahead market, more storage integration efforts, modeling smart inverters in planning and collaboration with distribution operators so it can anticipate DER contributions. In the report, MISO CEO John Bear said the RTO recognized “seismic changes” affecting the energy industry at the end of 2017.

The report is part of MISO’s new Integrated Roadmap process, which combines the old Market Roadmap list of prioritized market improvements with more research and reporting on industry trends and the annual publication of an insights and strategy report to explain how major trends might affect RTO operations. (See “MISO Rebrands Market Roadmap,” Committee Considers Ways to Streamline MISO Meetings.) MISO is currently asking for new idea submissions for the Integrated Roadmap through May 1. The RTO will send out a stakeholder prioritization survey in June, and the Integrated Roadmap will be finalized in early November.

Ramping Needs

Sperry said that as multiple smaller generating plants replace large baseload plants and more customers install their own generation, MISO will need stronger resource ramping capability. She said solar and wind generation add more variability to an operating day with more peaks and troughs and steeper ramps as the wind picks up or clouds gather. A resource mix containing 20% each of wind and solar generation could require more than 10 GW of ramping ability in either direction within a few hours. MISO currently requires about a maximum 5-GW ramping capability in either direction.

“There’s much more movement occurring throughout the operating day,” Sperry said of a future with more renewable generation.

Indiana Utility Regulatory Commission staffer Dave Johnston asked if MISO has a method of measuring and predicting its zero-cost bid offers, which would drive the need for ramping. Sperry said MISO does collect data on zero-cost energy but must be mindful of confidential and proprietary information.

Adams said zero-cost energy does raise the question of whether a market based on locational marginal prices will continue to be appropriate. She said MISO may devise “more discreet revenue streams for market participants.”

“With old generation, we didn’t think about essential reliability services. Now we have to think about essential reliability service, so we might need a new market product,” Minnesota Public Utilities Commission staff member Hwikwon Ham said.

Sperry agreed and said future solutions should reconsider “planning all the way through markets and settlements.”

MISO ramp needs with a renewable mix | *MISO*

Forecasting and DER Visibility

Sperry said MISO also realizes it may soon have to stop forecasting load using historical averages as a basis.

“As the portfolio changes, that historical information is going to be a little less accurate,” she said.

“If we just had the same mix of coal and gas thermal units, but they were decentralized, would MISO still see a risk?” Johnston asked.

Adams said MISO’s lack of visibility into distributed resources, not necessarily the decentralization itself, carries the most significant planning and operations risk.

But Ham said MISO doesn’t need total visibility into distributed resources, just more open lines of communication. “MISO doesn’t need to see everything. It just needs to be communicating with the distribution companies,” Ham said.

But Adams countered that more volatility in load will require a response from the bulk electric system, most likely in the form of more flexibility to simultaneously accommodate distributed and more traditional resources.

Johnston asked exactly where MISO draws the line between utility-scale and distributed generation. “We all use this term utility-scale. Can anyone tell me what utility-scale means?” Johnston asked.

Sperry said she didn’t have a “firm” megawatt number and pointed out that even FERC rules vary in terms of what it means for generation to reach utility-scale output.

“It can be 100 kW in terms of storage resources, and I think we’re seeing things in our interconnection queue as low as 1 or 5 MW,” Sperry said.

Johnston said he found the report frustrating for its lack of detailed resource estimates. “I want to know what the problem is. I want to know how many resources are self-scheduling and bidding in at zero. … I don’t know what MISO sees. … What’s the situation now in MISO?” Johnston said.

Adams said the report is based in part on utilities’ future resource plans and that while MISO does foresee significant fleet change, the report is not an attempt to quantify the change. The report, she said, is a starting point in the stakeholder process to begin discussion on needed changes.

“We also know it’s going to take a long time to start to change our markets,” Adams said.

She also said MISO currently lacks the specifics to measure DER participation in its footprint.

“We have no DER visibility, and that’s been fine so far because there’s been very little volatility,” she said.

But Adams pointed out that MISO still needs more data and must figure out how detailed new data on intermittent and emerging technologies should be.

“Do we have to detail down to every asset and every smart thermostat? Well that seems a little out of control,” Adams said.

April 14, 2019December 13, 2023

Oncor-Sharyland-Sempra Deals Inch Toward Approval

By Tom Kleckner

A combined $1.37 billion worth of transactions involving Oncor, Sharyland Utilities and Sempra Energy all but gained regulatory approval last week following a brief hearing on the merits before the Texas Public Utility Commission.

The commission reviewed a stipulated settlement among the three companies and seven other parties, complimenting them on the agreement. The proceeding has been placed on the agenda for the PUC’s open meeting Thursday (Docket 48929).

“It took a lot of work to get here and compromise on everybody’s part,” PUC Chair DeAnn Walker said. “Thanks for bringing us something that is a very good solution to this situation.”

“I’m largely content with [the settlement],” Commissioner Arthur D’Andrea said.

The settlement agreement resolves all issues in a complex series of deals announced by the parties in October, with Sempra buying a 50% stake in Sharyland Distribution & Transmission Services and Oncor acquiring transmission owner InfraREIT. An exchange of transmission assets would increase Oncor’s footprint in West Texas and “de-REIT” the Sharyland utility in South Texas. (See Sempra, Oncor Deals Target Texas Transmission.)

Oncor, Sharyland and Sempra filed for approval with the PUC in November.

Approximately 260 miles of InfraREIT’s transmission system were previously owned by Oncor. They were exchanged for Sharyland’s distribution system as part of a 2017 rate case settlement. (See Texas PUC OKs Settlement in Oncor-Sharyland Asset Swap.)

“This is a rare opportunity for us to acquire assets in ERCOT. Assets don’t come up for sale very often,” Oncor General Counsel Matt Henry said. The assets “happen to be not only on our border but overlapping our existing transmission footprint. As everyone knows, West Texas is absolutely going nuts. We’re excited about the deal from a commercial standpoint.”

The PUC’s approval would mean Oncor will become responsible for building the infrastructure needed to accommodate Lubbock Power & Light’s move from SPP to ERCOT.

“Based on the stipulated language, Oncor would be stepping into the shoes of Sharyland and nothing would slow it down,” said Cody Faulk, an attorney representing LP&L.

PUC staff, the Office the Public Utility Counsel, Alliance for Retail Markets, Steering Committee of Cities Served by Oncor, Texas Energy Association for Marketers, Texas Industrial Energy Consumers and Hunt Consolidated were parties to the agreement. ERCOT, the city of Lubbock, Golden Spread Electric Cooperative and the Texas Cotton Ginners Association do not oppose the revised stipulation.

California-based Sempra acquired an 80% interest in Oncor early last year in a $9.45 billion all-cash buyout. (See Texas PUC OKs Sempra-Oncor Deal, LP&L Transfer.)

Sempra’s legal counsel, Ron Moss, said the company wants to be part of Texas’ “vibrant utility industry.”

“The proposed transaction represents the next step,” he said.

April 14, 2019

NYISO Draft Gold Book Shows EVs Driving Load Growth

By Michael Kuser

A draft version of NYISO’s annual load and capacity forecast shows electric vehicle usage driving a 66% increase in New York’s projected baseline peak demand growth rate over the next 20 years.

Much of that growth would occur in the second half of the study period, according to the preliminary 2019 Gold Book forecast released Thursday, which projects a cumulative electric load growth of 0.05% from 2019 to 2039, compared with the 0.03% growth from last year’s forecast. The baseline summer peak demand forecast growth rate was relatively unchanged between forecasts.

The new report presents load and capacity data for 2019-2029 and energy and peak forecasts through 2039 on a zonal basis and through 2049 on a system basis.

The baseline forecasts show the expected New York Control Area (NYCA) load, including the impacts of energy efficiency programs, building codes and standards, distributed energy resources, and behind-the-meter energy storage and solar PV.

The topline forecast, formerly referred to as econometric, shows what the expected NYCA load would be if not for these impacts, with the listed impacts added back into the baseline forecast. Both the baseline and the topline forecasts include the expected impacts of EV usage.

NYCA energy production by zone | *NYISO*

Load Reduction

Significant load-reducing impacts occur because of energy efficiency initiatives and the growth of distributed BTM resources. Much of the impact is attributed to the state’s energy policies and programs, including the Clean Energy Standard (CES), the Clean Energy Fund (CEF), the NY-SUN program, the energy storage initiative and other programs developed as part of the Reforming the Energy Vision (REV) proceedings.

NYISO staff employ a multistage process to develop load forecasts for each of the 11 zones within the NYCA. In the first stage, baseline energy and peak models are based on projections of end-use intensities and economic variables. End-use intensities specific to New York are estimated from appliance saturation and efficiency levels in both the residential and commercial sectors.

Since last April, net summer capability has increased 228 MW to 39,294 MW, reflecting 744 MW of new additions, against 373 MW of deactivations and 143 MW in decreased ratings.

Total summer 2019 resource capability in the NYCA is 42,056 MW, a decrease of 201 MW compared to the same assessment last year. The ISO credits the decrease to changes in existing NYCA generating capability, special case resources (SCRs) for demand response and net purchases of capacity from other control areas.

Total resource capability for the year includes generating capability of 39,295 MW; SCRs at 1,309 MW, up from 1,219 MW last year; and net long-term purchases and sales with neighboring control areas at 1,452 MW, down from 1,625 MW last year.

The existing NYCA generating capability includes renewable resources totaling 6,351 MW, down from 6,373 MW last year; wind generation unchanged at 1,739 MW; hydropower virtually unchanged at 4,253 MW; large-scale PV unchanged at 32 MW; and other renewable resources down to 327 MW from 350 MW in 2018.

Beyond 2019, NYCA resource capability will be affected by additions of new generation, re-rates of currently operating units and the deactivation of existing generators, the ISO says.

NYISO got more than half of its electricity production from nuclear and hydropower in 2018. | *NYISO*

Transmission Updates

The new report lists existing NYCA transmission facilities 115 kV and larger, including several new ones that came into service since the publication of the 2018 Gold Book. It also shows proposed transmission facilities, including merchant projects as well as firm and non-firm projects submitted by each transmission owner.

In 2017, NYISO’s Board of Directors selected the NextEra Energy Transmission New York’s Empire State Line proposal to satisfy the Western New York public policy transmission need, with an expected in-service date of June 2022.

The board last week selected two 345-kV transmission projects intended to address persistent transmission congestion in New York and foster delivery of renewable energy to the state’s population centers. (See NYISO Board Selects 2 AC Public Policy Tx Projects.)

The projects — part of the broader AC Public Policy Transmission Project — address transmission capacity at the Central East (Segment A) electrical interface and Upstate New York/Southeast New York (UPNY/SENY or Segment B) interface.

While both projects are expected to be in service in December 2023, neither are included in the draft Gold Book, which lists only projects confirmed by March 15. Future Gold Books will include the newly selected public policy transmission projects, the ISO says.

The ISO is taking stakeholder comments on the Gold Book at stakeholder_services@nyiso.com through April 17.

April 13, 2019

Calif. Must Limit Wildfire Liability, Governor Says

By Hudson Sangree

SACRAMENTO, Calif. — California Gov. Gavin Newsom’s “strike force” on utilities and wildfires Friday called for the state to limit the liability that utilities face when their equipment sparks destructive blazes, while reforming the Public Utilities Commission and holding Pacific Gas and Electric accountable for its repeated safety failures.

The task force’s 59-page report details a strategy to ensure that the state’s utilities “are securing our grid, hardening their resources, participating in a procurement strategy that can meet our long-term climate goals and … deliver affordable, reliable service to millions and millions of Californians,” the governor said at a press conference at the state Office of Emergency Services’ operations center.

It recommends ways to prevent the type of catastrophic fires that have killed 139 residents, destroyed tens of thousands of structures, and burned 2.8 million acres since 2017. The report says equipment owned by the state’s three large investor-owned utilities, including PG&E, has sparked 2,000 fires in the past four years.

Sections of the report deal with climate change, changing how the PUC oversees safety and holding PG&E accountable. But shielding the state’s IOUs from wildfire liability is the top priority, Newsom said.

“The most vexing public policy challenge addressed in this report is the equitable distribution of wildfire liability,” the report says. To address the issue, it proposes three potential fixes.

One is changing the state’s strict liability standard, which holds utilities liable for wildfires started by their equipment regardless of negligence. The legal doctrine, called “inverse condemnation” and enshrined in the state constitution, is based on the premise that utilities have the power of eminent domain to take private property for rights of way and are therefore strictly liable for damage to that property.

Other states have inverse condemnation on the books, but none uses it as extensively as California. Critics have said the doctrine inordinately punishes utilities and puts them in financial peril. The report recommends moving to a more common fault-based standard, under which plaintiffs would be required to show wrongdoing to recover damages.

California Governor Gavin Newsom presenting wildfire report — Gov. Gavin Newsom released his “strike force” report on utilities and wildfires at the former Mather Air Force Base on Friday. | *Calif. Governor’s Office*

The “fair allocation of wildfire damages [is] the core of this report,” Newsom said. He pointed to a chart showing a massive increase in wildfire damages in the past two years — with nearly $20 billion in 2017 and almost $25 billion in 2018.

“Who the heck’s going to pay for that? Everybody wants someone else to pay. … The person behind the curtain is going to pay for that,” the governor said. “I’m of the opinion … [that] we all have a burden and responsibility to assume the costs.”

Newsom said it would be difficult to meet the state’s ambitious green energy goals and have a reliable and affordable electric system if changes aren’t made. He said last year’s SB 901, which gave utilities some relief but left inverse condemnation unchanged, is “not enough.”

The strike force report suggests establishing a catastrophic wildfire fund or a “utility liquidity fund” financed by investors, utilities and ratepayers to pay for damages caused by wildfires. (See Does California Need a Catastrophic Wildfire Fund?)

PG&E said in a statement Friday it welcomed the strike force’s recommendations. The company’s beleaguered stock price jumped from below $19 to almost $23/share Friday after Newsom’s presentation.

Southern California Edison parent Edison International also got a boost, rising from below $62 to more than $67. Sempra Energy, parent of San Diego Gas & Electric, rose from less than $128 to almost $130.

Ratepayer advocacy groups, including The Utility Reform Network, were more circumspect in their assessment of the proposals.

“The goal of protecting consumers by making it clear that investors, taxpayers and other stakeholders must share in the costs of wildfire prevention and damage is one we are in total agreement with,” TURN Executive Director Mark Toney said in a statement. But customers “obviously can’t afford to bail PG&E out of billions in liabilities when it is negligent.”

Reform the PUC

Reforming the PUC was another of the strike force’s major recommendations.

The report recommends expanding the PUC’s safety expertise and improving its ability to review wildfire mitigation plans, conduct inspections and audits, and enforce safety standards.

It urges delegating more authority to the commission’s staff “so that judges and commissioners [can] focus on core questions of ratesetting.” The PUC has been criticized for moving slowly and lacking a sense of urgency in addressing utility safety. PUC President Michael Picker recently told lawmakers the commission is set up to slowly process rate cases, not react quickly to emergencies. (See Lawmakers Grill PUC on PG&E, Fires.)

The effort is “long overdue,” Newsom said.

Picker stood near the governor at Friday’s press conference, in an apparent show of unity, and Newsom lauded his reform efforts.

Newsom said the report’s other recommendations are contingent on changes at the PUC.

“Know that each and every one of these attaches to consideration of reforms at the Public Utilities Commission,” the governor said.

Hold PG&E Accountable

Even as it urged overhauling liability standards, the report says PG&E must account for its poor safety record and past disasters.

PG&E filed for Chapter 11 bankruptcy in January, a few months after its equipment was suspected of starting the Camp Fire, which killed 86 people and leveled the town of Paradise. The company said it was forced to seek bankruptcy protection because of the liability it faced for the Camp Fire and a devastating series of blazes in 2017. (See Bankruptcy Only ‘Viable’ Option for PG&E, Lawyer says.)

“PG&E is a textbook example of what happens when a utility does not invest in safety after numerous deadly reminders to do so over many years,” the report says. “Even today, PG&E is taking advantage of the bankruptcy process to promote the interests of investors over fire victims and other stakeholders.”

State fire investigators have determined that PG&E equipment started at least 17 of the 21 major wildfires in Northern California in October 2017. The utility remains on criminal probation for illegal conduct related to the deadly San Bruno gas pipeline explosion in 2010.

The state’s massive wildfires have strained firefighting resources. | *Calif. Governor’s Office*

The report says the state should monitor and intervene in the utility’s bankruptcy proceedings where necessary to protect California residents and “demand that a reorganized PG&E serve the public interest.” Breaking up the company ought to remain an option, it says.

“After years of mismanagement and safety failures, no options can be taken off the table to reform PG&E, including municipalization of all or a portion of PG&E’s operations; division of PG&E’s service territories into smaller, regional markets; refocusing PG&E’s operations on transmission and distribution; or reorganization of PG&E as a new company structured to meet its obligations to California,” it says.

At the press conference, Newsom said, “I just want folks to know we’re watching. … I expect the investors that are involved at PG&E to participate in the solutions, and I expect that PG&E’s going to get serious [and] no longer misdirect, manipulate [and] mislead the people of this state.

“They haven’t been good actors,” the governor added. “I know this personally. I was mayor of San Francisco, where [PG&E is] headquartered. I’m not here to beat them up, but you know the state has suffered because of their neglect and their misdirection.

“Lives have been lost,” he said.

Calls for Legislative Action

Newsom called on lawmakers to implement the report’s recommendations.

“Let’s get something big done before [the legislative] recess,” which begins July 12, he said. “I’m hopeful [the legislature] can meet this moment and meet the demand to be bold and resolved.”

Investor services have downgraded the credit ratings of PG&E, SCE and Sempra to junk-bond or near-junk-bond status because of wildfire liability worries, Newsom said. The legislature can help alleviate those concerns, he said.

“Let the folks on Wall Street know we’re not screwing around,” he said.

Newsom formed his strike force in February and asked for its members to submit recommendations in 60 days.

It was led by his chief of staff, Ann O’Leary, and included members of O’Melveny, one of the nation’s largest law firms (formerly O’Melveny and Myers), and Guggenheim Partners, a global investment and advisory firm, Newsom said. State fire officials and utility regulators were part of the team, news reports said. A complete list of members was not immediately available.

April 12, 2019

UPDATED: Most MISO Zones Clear at $3/MW-day in 2019/20 PRA

By Amanda Durish Cook

MISO’s seventh annual capacity auction cleared at $2.99/MW-day in all but one zone, a significant decline compared with last year’s nearly uniform $10 clearing price.

Zone 7 — representing the Lower Peninsula of Michigan — was the only area to deviate significantly, clearing instead at $24.30/MW-day.

MISO on Friday reported that it committed 134.7 GW worth of capacity for the 2019/20 planning year beginning June 1. The Planning Resource Auction was characterized by “lower offer prices from market participants in most of MISO,” the RTO said, but the volume of generation supply was “consistent” with the predictions from last year’s resource adequacy survey issued in partnership with the Organization of MISO States.

MISO received more than 142 GW worth of offers in this year’s auction, about 7 GW above the nearly 135-GW reserve margin requirement for June 2019 to May 2020.

“There is a surplus above our resource adequacy requirements to meet peak load,” Eric Thoms, MISO manager of capacity market administration, said during a media call Monday to discuss the results.

Market participants this year “simply offered in at a lower price” when compared to last year, Thoms said.

2019/20 auction clearing price overview | *MISO*

Having all but one local resource zone clearing at the same price is a familiar story for MISO auctions. Last year’s auction cleared at $10/MW-day, with the exception of Zone 1 — covering parts of Wisconsin, Minnesota and the Dakotas — which cleared at $1/MW-day. (See MISO Clears at $10/MW-day in 2018/19 Capacity Auction.)

Although higher than 2017/18’s single clearing price of $1.50/MW-day, last year’s $10 price tag elicited criticism from some market stakeholders as being too low. In his 2017 State of the Market report issued last June, MISO’s Independent Market Monitor David Patton said the “fundamental problem” with diminishing capacity can be traced to “the relatively low net revenues generated in MISO’s markets.” (See “Low Capacity Prices,” MISO to Address Growing Supply Shortage in New Year.)

Price Separation, Mitigation for Lower Michigan

The Monitor has reviewed and certified this year’s results but did have to enforce market mitigation for economic withholding in Zone 7. MISO said the IMM mitigated “several” offers representing about 1.5 MW, resulting in a 1 cent/MW-day impact in lower Michigan. It was the second time in the auction’s seven-year history that the Monitor had to enforce mitigation, with the first instance of enforcement occurring in 2013/14 planning year. “While IMM mitigation is rare, we’d like to note the process is working as designed,” MISO said in a statement.

Thoms said the mitigation was “interesting development.”

Speaking during a separate stakeholder call on the results Monday, Thoms said non-zero price offers, tight supply and a lower capacity import limit than last year contributed to price separation in lower Michigan. At nearly 22 GW, Zone 7 had the highest planning reserve margin requirement of MISO’s 10 local resource zones.

Michigan Public Service Commission staffer Bonnie Janssen asked if the price separation was at least in part the result of MISO no longer counting external resources towards satisfying the local clearing requirements for local zones. Thoms said the RTO would examine that as part of future presentations on the auction.

Cleared fuel type in MISO 2019/20 PRA | *MISO*

MISO also reported that more solar and wind generation cleared this year’s auction when compared to the 2018/19 planning year. The auction cleared 680 MW worth of solar, up 47% from last year, while wind capacity increased 21% to nearly 2.7 GW. The share of natural gas-fired capacity (38%) beat out coal (35%), which MISO said illustrates “the industry’s ongoing shift away from coal-fired generation and increasing reliance on gas-fired resources and renewables.”

Thoms said this auction was the first in which natural gas supplanted coal as the leading source of MISO capacity. He also called the increase in renewables capacity “significant.”

The PRA also cleared 15 GW of non-traditional resources, including demand response, energy efficiency, behind-the-meter generation and generation from external resources, compared with slightly more than 14 GW for those resource types last year. This was the first year that MISO included its newly created external resource zones in the auction. (See FERC OKs MISO External Capacity Zones, Dispute Deadlines.) Prior to its external zone creation, MISO treated external resources as if they were physically located within the nearest local resource zone. Even though external resources can clear at different prices than local resource zones, all external resource prices this year followed the $2.99/MW-day clearing price set by the planning reserve requirement.

MISO will go over more detailed PRA results with stakeholders at the May 8 Resource Adequacy Subcommittee meeting.