Page 1094 – RTO Insider

May 29, 2020

PJM End-of-life Proposals Fail at MRC

A proposal to open end-of-life (EOL) transmission projects in PJM to regional planning and competitive bidding was narrowly defeated in a vote at the Markets and Reliability Committee meeting Thursday.

The “joint stakeholders” proposal from American Municipal Power (AMP), Old Dominion Electric Cooperative (ODEC) and others failed with a sector-weighted vote of 3.23 (65%). The proposal needed a sector-weighted vote of 3.33 (66.7%) for passage.

The proposal won support from 100% of the End-Use Customers, 97% of the Electric Distributors and 71% of Generation Owners. But it was opposed by 59% of Other Suppliers and all but two of 14 Transmission Owners.

Transmission owners would have been required to notify PJM and stakeholders of any facility nearing the end of its life at least six years before its retirement date so that the project could be included in five-year planning models and potentially opened to competitive bidding. It would also modify the supplemental project definition to exclude EOL projects, which would become a new category of regionally planned projects.

A proposal by PJM also failed with a sector-weighted vote of 1.77 (36%) at the MRC.

Despite failing at the MRC, supporters of the joint stakeholders proposal unsuccessfully attempted to bring it to a vote at the Members Committee meeting in the afternoon after Chair Steve Lieberman, of AMP, recused himself from the meeting.

PJM end-of-life — Number of baseline vs. supplemental projects (2010-2019) | *PJM*

After about 90 minutes of parliamentary jousting, the stakeholders called a vote to suspend the rules to allow consideration of their proposal, but the motion fell short of the two-thirds needed with a vote of 3.08 (62%).

ODEC’s Mark Ringhausen, who presented the joint stakeholder package, said it would allow for Order 1000 competition in EOL projects that would ultimately lead to lower costs for ratepayers.

Ringhausen highlighted the TOs’ May 7 notification that they were considering a Federal Power Act Section 205 filing to amend the Tariff as an alternative to the proposals under consideration. Ringhausen said the TO filing at FERC after June 8 would be similar to the PJM proposal, which had “almost zero transparency,” giving the TOs control over most of the future transmission planning.

Dave Souder, PJM’s senior director of system planning, presented the RTO’s package, which would have required TOs to have a formal program for EOL determinations and to identify potential EOL projects five years in advance. Projects that “overlap” with RTEP violations would be included in a competitive window seeking regional solutions.

PJM cited language in the Consolidated Transmission Owners Agreement (CTOA) that allowed TOs to retain the authority to “build, finance, own, acquire, sell, dispose, retire, merge or otherwise transfer or convey all or any part of its assets, including any transmission facilities.” The RTO also said its role was limited by two FERC rulings involving ‘Asset Management’ not Subject to Order 890, FERC Rules.)

“At the end of the day, we’re going to have to agree to disagree,” Ringhausen said of the stakeholders’ insistence that their proposal complies with the CTOA and the PJM Tariff. “Hopefully, we can get this in front of FERC and make them look at it and say what the right outcome should be here for this process.”

Mike Gahimer of the Indiana Office of Utility Consumer Counselor said PJM “misrepresented” the FERC orders. In the order involving Southern California Edison, Gahimer said, FERC stressed the limited scope of asset management as “looking at components, not entire substations or transmission lines for replacement.”

Gahimer said the joint stakeholder proposal didn’t involve components, but rather lines and substations. “I don’t think anyone, including the most biased among us, would claim that the projects at issue here are day-to-day projects,” he said.

AMP’s Ed Tatum said that with the amount of transmission infrastructure that’s going to have to be replaced in the next decade, careful planning is going to be needed. He said PJM’s expertise is essential to ensure that the planning for the grid of the future is simply not rebuilding the transmission system of the past. He fears the future of transmission planning will be moved out of the jurisdiction of PJM and back to the TOs without coming up with compromises.

“That’s a great concern from the standpoint of those who believe transmission and an independent transmission planner is a cornerstone to competitive markets,” Tatum said. “We think that PJM should be the independent planner. We think they bring value from a more holistic look.”

Thursday’s votes are unlikely to bring an end to the billion-dollar debate over control of EOL projects.

The TOs have scheduled a webinar from 2 to 4 p.m. Monday to discuss their potential Attachment M-3 filing. They could file the attachment after the 30-day comment period expires June 8.

Supporters of the joint stakeholders proposal could file a complaint with FERC contending the current procedures are not just and reasonable.

May 29, 2020

NYISO Management Committee Briefs: May 27, 2020

NYISO has suspended the sequestration of its control room operators but is in no hurry to bring its other staff back to ISO offices as New York begins its recovery from the coronavirus pandemic, CEO Rich Dewey told the Management Committee on Wednesday.

The ISO ended sequestration for its Krey Boulevard control center operators on May 4 and that for Carman Road two weeks later, Dewey said. “We think we’re in a reasonable posture to suspend the sequestration of those staff members,” he said, adding that the ISO is prepared to resume sequestration if there is a resurgence of infections in the region.

For now, Carman Road staff are handling the day shift, with Krey Boulevard working nights.

Other NYISO staff are “almost exclusively” continuing to work from home while the ISO tracks the state’s reopening plans.

Although the ISO does have return-to-office plans, Dewey said it will be “conservative” in implementing them. “There’s no particular schedule for when we will start phasing people back into the office,” he said. With telework “working pretty well … we’re not going to be in a rush to change that posture.”

Dewey said the joint Board of Directors/Management Committee meeting scheduled for June 15-16 at the Sagamore Resort on Lake George has been converted to a virtual session. Like past in-person gatherings, the meetings will include both general sessions involving all attendees, and breakouts with individual board members and about 10 stakeholders.

“It’s very important for our board members to get feedback from market participants,” Dewey said. “I think we’ve demonstrated that the technology is quite capable. … We won’t have the normal social interaction, but we’ll do the best we can under the circumstances.”

The topics will include the “Grid in Transition” and “Navigating Uncharted Territory,” which will explore post-pandemic economic changes that may impact the sector.

Summer Capacity Assessment

NYISO’s baseline analysis shows a 1,721-MW capacity margin surplus for the summer peak in 2020, a drop of 506 MW from 2019, said Wes Yeomans, vice president of operations.

The 90th percentile forecast shows a 193-MW shortfall, a decrease of 616 MW from last year. Such extreme conditions might require the ISO to either tap its 2,620 MW of operating reserves or call on emergency operating procedures, including voltage reductions, emergency purchases and voluntary load reductions, for up to 3,080 MW.

The summer assessment shows 2,273 MW in generation deactivations, including the state’s last two coal-fired plants (the 155-MW Cayuga Unit 1 and the 655-MW Somerset plant) and the retirement of Unit 2 of the Indian Point nuclear plant (1,299 MW), which shut down at the end of April.

The ISO has one new generating asset, the 1,177-MW Cricket Valley combined cycle plant in Dover, N.Y.

60-minute Rule for Energy Storage

The Management Committee approved changes to section 4.4.3.1.1 of the Services Tariff to only award energy storage resources (ESRs) energy schedules that are sustainable for at least 60 minutes during a reserve pick-up (RPU) event.

The change was prompted by concern that during an RPU, real-time dispatch may award a larger energy schedule than an ESR can sustain for 60 minutes, as required by the Northeast Power Coordinating Council.

This can occur because the real-time dispatch/corrective action mode used to perform an RPU must issue updated schedules very quickly and thus only looks out 10 minutes.

May 29, 2020

Five New Recommendations from NYISO Monitor

Potomac Economics’ 2019 State of the Market Report for NYISO adds five new recommendations while concluding the ISO’s markets “performed competitively” in 2019.

Potomac’s Pallas LeeVanSchaick told the NYISO Management Committee on Wednesday that 2019 energy prices were the lowest in the past decade, dropping 22 to 34% from 2018. He cited a 22 to 41% drop in natural gas prices from expanded production, and muted demand from a mild winter and summer.

Mild weather, energy efficiency and behind-the-meter solar generation contributed to the lowest average load in more than a decade, the ISO’s Market Monitoring Unit said.

NYISO monitor — Fuel type of real-time generation and marginal units in New York, 2017-2019 | *NYISO*

Capacity prices also fell to 8 to 26% of the net cost of new entry (CONE) outside of New York City, thanks to reduced local capacity requirements and new capacity additions. Although New York City prices rose, they still represented only 58% of net CONE. “That’s an indication of significant capacity surpluses,” LeeVanSchaick said.

The five new recommendations are in addition to 17 from prior reports.

Only one of the new recommendations — modifying the “Part A” test to allow public policy resources to obtain exemptions when it would not result in price suppression below competitive levels — was identified as a high priority. The MMU said the change is needed to ensure buyer-side mitigation (BSM) rules are balanced between protecting the market from price suppression and facilitating the state’s desire to control its resource mix.

“The BSM measures were originally designed to prevent entities from suppressing capacity prices below competitive levels by subsidizing uneconomic new entry of a conventional generator,” the Monitor said. “The BSM measures are not intended to deter states from promoting clean energy and other legitimate public policy objectives.”

It said it supports a plan NYISO developed with stakeholders that allows public policy resources to avoid mitigation if enough existing capacity exits the market, or if demand increases enough to boost capacity requirements. The proposal was filed with FERC on April 30 (ER20-1718).

The MMU also recommended that:

Day-ahead and real-time reserve clearing prices should incorporate reserve constraints for Long Island. Currently reserve providers on Long Island are paid clearing prices for the larger Southeast New York region. Changing the compensation would improve incentives and “provide better signals to new investors in … the long term,” the Monitor said.
Increase the offer/bid floor from -$1,000/MWh to -$150/MWh. Negative prices are used when ISO operators reduce external interface limits or curtail external transactions to maintain transmission security on an external interface. In this rare situation, external transaction schedulers can buy power at “arbitrarily” low prices, resulting in uplift for NYISO customers. “We recommend raising the bid and offer floor to a level that is closer to the range of potential avoided costs of supply for generation resources,” the Monitor said. “Negative $150/MWh should be more than adequate to provide such flexibility.”
Translate the annual revenue requirement for the demand curve unit into monthly demand curves reflecting their reliability value. NYISO’s capacity market currently is divided into six-month summer and winter capability periods with a single capacity requirement and demand curve for each, although the reliability value of resources is much greater in high-demand July than the shoulder month of October. The bifurcation “may lead to inefficient incentives for resources that are not consistently available during all 12 months,” the Monitor said. It recommended switching to monthly capacity demand curves with a minimum reference point high enough to ensure resources have incentives to coordinate planned outages with the ISO. The remainder of the demand curve unit’s annual revenue requirement would be allocated in proportion to the marginal reliability value of capacity across the 12 months. “These changes would concentrate the incentives for resources to sell capacity into New York during the peak demand months of the summer (i.e., June to August),” it said.
Translate the demand curve reference point from installed capacity (ICAP) to unforced capacity (UCAP) terms based on the demand curve unit technology. The capacity demand curves currently are based on net CONE, estimated in ICAP terms and then converted into UCAP based on the regional average derating factor, which reflects the forced outage rates of the existing fleet and UCAP-ICAP ratios of intermittent resources. This technique results in the monthly capacity demand curves being set higher than if the derating factor of the demand curve technology were used. “This inconsistency will become more pronounced as additional intermittent resources are added to the system,” the Monitor said.

May 28, 2020

NERC Planning Level 2 Supply Chain Alert

NERC is preparing to issue a Level 2 alert in “two to three weeks” in response to President Trump’s recent declaration of a national emergency regarding foreign threats to the bulk power system, CEO Jim Robb said in a presentation Wednesday.

NERC Supply Chain Alert — NERC CEO Jim Robb | © *ERO Insider*

The ERO’s alert follows Trump’s lead in focusing on BPS equipment developed, manufactured or supplied by entities connected to “foreign adversaries,” defined as any foreign government or nongovernment person connected with threats against the U.S. or its allies. (See Trump Declares BPS Supply Chain Emergency.) It will require registered entities to report the extent of such equipment connected to their systems and report back to NERC, which will use the information to determine strategies for mitigating any potential damage from these components.

The Level 2 alert will be NERC’s second this year; the first was issued in March to address the COVID-19 pandemic. (See Coronavirus, Cybersecurity Top WECC Board Discussion.) Currently, NERC is working with FERC and the U.S. Department of Energy to identify the manufacturers subject to its data request. Information gathered in the alert will help DOE determine “whether this is a huge problem or a very surgical problem,” and how strong a response is needed as a result.

“We’re going to take a very prudent, risk-based approach to this,” Robb said. “This isn’t going to be rip and replace — [we want to] assure ourselves that we don’t have untoward activity going on out on the system.”

Hardware Attacks More Likely

Trump’s executive order was welcomed by NERC when it was issued earlier this month, with the organization saying the declaration would “help support activities already underway in NERC’s supply chain standards and other work” to provide security to the BPS. But some in the industry have expressed concerns about the broad wording of the order and warned of a “cloud of uncertainty” that will exist until DOE has clarified its application.

Sukesh Aghara, a professor of chemical and nuclear engineering at the University of Massachusetts Lowell who participated in the briefing with Robb, said the decision to declare a national emergency reflected both concerns about hardware-related cybersecurity threats that have been building for years and alarm from the strain placed on supply chains by COVID-19 that has resulted in shortages of basic supplies across the U.S.

Those long-term fears have a number of causes: Robb pointed out that the supply chain for electrical equipment used in the BPS has almost entirely moved overseas. This trend could give foreign governments a degree of leverage over U.S. critical infrastructure that they never could have hoped for in previous years.

Aghara also pointed to a 2018 report in Bloomberg Businessweek that China’s intelligence services had inserted microchips in circuit boards manufactured in the country that were eventually used in computing equipment used by almost 30 U.S. companies including Amazon and Apple, as well as government agencies. The chips reportedly gave attackers the ability to monitor any network to which the altered equipment was connected.

Questions have been raised about that story — both Amazon and Apple have denied that any hostile hardware was found in their equipment and said the report was riddled with inaccuracies — and Aghara acknowledged that the reported vulnerabilities “may or may not have led to … a malicious outcome.” However, he said that even if this incident was less severe than first believed, the idea of a supply chain-based hardware attack is plausible and troubling enough that leaders would want to get in front of it as much as possible.

“Milton Friedman [commented] that when a crisis occurs, the actions that are taken depend on the ideas that were lying around,” Aghara said. “So I think it is not surprising that this might be the critical moment where something like an executive order … might lead to a significant change in what we do.”

A Good First Step

In light of these long-building issues, Robb said industry reaction to the executive order has been positive overall. Though many continue to call for more clarity, most see it as a first step toward providing utilities with the tools they need to level the playing field with their greatest threats.

“You’re getting attacked by nation-state actors, but as [Southern Co. CEO] Tom Fanning, one of the co-chairs to the [Electric Subsector Coordinating Council], said, ‘I’m a company — I can’t hit back. I don’t have the authority to go and punch North Korea on the nose, and yet they’re coming after me,’” Robb said. “So therefore, government help here is very important and very welcome.”

May 27, 2020

MISO Seeks LBA Input on Load Forecasting

MISO is calling on expertise from its local balancing authorities to help improve load forecasting, RTO engineers said Tuesday.

Operational Forecast Planner Adam Simkowski said during a special workshop that the call for LBA involvement stems from the Jan. 17, 2018, cold spell that caused MISO and SPP to call for voluntary load reductions from customers and nearly forced load shedding in MISO South.

FERC last year issued a report on the event that , among other things, called for improvements to MISO’s three- and five-day-ahead load forecasting. The commission recommended that the RTO work with its LBAs to achieve better results. (See FERC Calls for Cold Weather Reliability Standard.)

MISO is interested in learning more about how LBAs conduct forecasting and is asking them to share their methodologies and accuracy assessments, Simkowski said. He asked LBAs to contact the RTO by June 9.

Simkowski said MISO is so far concentrating on becoming more accurate with events that can be anticipated three and five days out, including snowstorms, tropical depressions, and substantial temperature swings and deviations.

MISO LBA Load Forecasting — Entergy crews in MISO South during extreme cold on Jan. 17, 2018 | *Entergy*

LBAs already submit day-ahead and seven-day forecasts to MISO daily. Simkowski said the RTO’s load forecasts are generally more accurate than those submitted by the LBAs.

To build forecasts, MISO combines data into its software from LBAs, its own seasonal modeling, historic load data and live load and weather data. It shares the forecasts with customers, who can offer adjustments. MISO forecasters can manually adjust the forecast model if they don’t agree with the software results. The RTO also checks forecast accuracy later.

MISO creates an hourly load forecast for control room planners that is updated every 15 minutes and extends seven days out. It also generates a five-minute forecast updated every five minutes that looks six hours ahead.

The RTO also estimates daily peaks over the next 31 days for the purposes of outage coordination.

Senior Operational Forecast Engineer Dorsana Desai said most of MISO’s load forecasting errors can be attributed to weather that doesn’t behave as predicted.

“One degree of temperature forecast error results in up to 2,000 MW of load forecast error,” she said.

MISO missed its load forecasting mark most egregiously on Sept. 15, 2018, Desai said, when MISO planned for about 85-degree Fahrenheit temperatures on average. Actual temperatures clocked in closer to 89 F, resulting in a 7.6-GW under-forecasting error.

Desai also said the 2017 solar eclipse in mid-August eluded MISO forecast engineers. The event — and widespread cloud cover and thunderstorms following soon after — had the RTO overestimating load by about 6 GW. Desai said MISO expected demand to rebound after the eclipse.

May 27, 2020

Trial Begins to End PG&E Bankruptcy

A trial that could conclude the bankruptcy of Pacific Gas and Electric began Wednesday via videoconference, with the judge presiding from his breakfast room.

PG&E’s Chapter 11 case is the sixth-largest bankruptcy in U.S. history and by far the largest of any energy utility. The COVID-19 crisis has forced it to be decided by U.S. Bankruptcy Court Judge Dennis Montali from his home, with lawyers arguing from remote locations.

The “confirmation” proceedings to approve or deny PG&E’s proposed reorganization plan lasted just an hour on the first day, with only one witness called.

PG&E Bankruptcy — Judge Dennis Montali confers with lawyers for PG&E and fire victims by Zoom video on May 27.

Christina Pullo, a vice president with claims administrator Prime Clerk, testified about the results of voting on the plan that concluded May 15. Nearly 87,000 wildfire claimants were eligible to vote along with tens of thousands of other creditors, she said.

Pullo confirmed the results of the vote, previously filed in court papers, that showed at least 85% of fire victims and an overwhelming majority of other creditors approved of PG&E’s reorganization plan. That plan, valued at close to $60 billion, includes $13.5 billion for fire victims, $11 billion for the insurance companies and hedge funds that hold third-party subrogation claims, and $1 billion in compensation to local governments for fire-related expenses. (See PG&E Bankruptcy Moves Toward Conclusion.)

The company plans to issue nearly $26 billion in new stock to help pay for the plan.

Pullo faced cross-examination by William Abrams, a wildfire victim who has represented himself throughout the proceedings. Abrams has repeatedly said he opposes the plan because it doesn’t do enough to ensure victims get paid or to force PG&E to become a safer utility.

On Wednesday, he asked Pullo about alleged voting irregularities and about Prime Clerk’s connection to PG&E via its parent company Duff & Phelps, which Abrams said holds a sizable stake in PG&E. As a non-lawyer, his questioning was frequently interrupted by instructions from the judge and objections from some of the dozen or so attorneys who participated in the hearing.

Should Montali approve PG&E’s plan, it would end a bankruptcy that started 16 months ago, when the company filed for Chapter 11 protection and reorganization in January 2019 as it faced up to $30 billion in wildfire liabilities.

State fire investigators determined the utility’s transmission lines ignited massive fires in 2015, 2017 and 2018 that combined killed more than 100 people and destroyed some 25,000 structures.

The fires included the Camp Fire, the largest in state history, that killed 85 residents and leveled more than 14,000 homes in and around the town of Paradise, Calif., in the Sierra Nevada foothills.

Critics have accused PG&E of funneling profits to shareholders rather than maintaining aged infrastructure, such as the century-old Caribou-Palermo line that sparked the Camp Fire.

The California Public Utilities Commission levied a record $1.9 billion in penalties on PG&E for its maintenance and safety failures. The commission is required to approve the utility’s Chapter 11 plan under state law, with a vote scheduled Thursday.

The bankruptcy proceedings are scheduled to continue through next week.

May 26, 2020

NERC Seeks Comments on Proposed ROP Changes

NERC is seeking comments through July 10 on proposed changes to its Rules of Procedures (ROP) that were ordered by FERC earlier this year in response to the ERO’s five-year performance assessment (RR19-7).

The planned updates apply to Section 1003, covering NERC’s infrastructure security program — particularly the Electricity Information Sharing and Analysis Center (E-ISAC) — and its sanction guidelines in Appe n dix 4B of the ROP.

Clarity Sought on E-ISAC’s Role

In its January order, FERC said that despite its growing share of NERC’s budget — accounting for 28% of NERC’s total 2020 budget and 26% of the projected bu d get for 2021 — the E-ISAC program lacks transparency. The commission requested that NERC clarify the E-ISAC’s relationship with the Electricity Subsector Coordinating Council (ESCC), correct inconsistencies in terminology used in the ROP and update other operational practices related to NERC’s infrastructure security program. (See NERC Wins Another 5 Year s as ERO.)

To address FERC’s order, NERC made a number of additions to Section 1003, along with revisions to existing language. Significant insertions include a paragraph describing the role of the E-ISAC and its place alongside the Department of Energy and ESCC in the U.S. national security framework, expanding on a less detailed description in the current version of the ROP. The organization also added language emphasizing that it considers security an equal priority to reliability and resilience.

NERC ROP Changes — E-ISAC headquarters in Washington, D.C. | © *ERO Insider*

In addition, language stating that NERC “[fills] the role of the [ESCC]” was deleted. The new wording says that the organization “shall coordinate with” the council.

References to the critical spare transformer program, the National Infrastructure Protection Plan, vulnerability assessments of certain systems and working with the National SCADA Test Bed and Process Control Systems Forum were also deleted, as NERC is not involved in these activities anymore.

Sanction Changes Emphasize Fairness

The changes to the sanction guidelines in Appendix 4B clarify NERC’s and regional entities’ application of base penalties, in addition to emphasizing NERC’s focus on violation risk factor and severity level when determining penalty amounts. NERC also expanded on the role non-monetary sanctions may play in determining the final penalty amount.

Additional changes ordered by FERC include language requiring NERC and regional entities to ensure that “violators do not consider the imposition of monetary and/or non-monetary sanctions to be an economic choice or cost of doing business” by considering the size of the offender and its ability to pay when setting a penalty. The new language also stressed that penalties on multiple subsidiaries of a parent corporation that commit the same violation must be proportionate to the seriousness of the violation and the size of the offender.

Presentation Planned for August Board Meeting

FERC’s order in January mandated NERC make a compliance filing with the necessary revisions by July 21, but NERC requested an extension on the deadline in February that it said would allow for the full 45-day stakeholder comment period, as well as providing time for the Board of Trustees to review the changes before its meeting Aug. 20. (See NERC Seeks M o re Time on Rule Changes.)

FERC approved this request March 1, granting NERC until Aug. 28 for the compliance filing. The commission later extended the deadline again to Sept. 28 in light of the COVID-19 pandemic. (See FERC Extends NERC Compliance Filing Deadline Again.)

A separate compliance filing ordered by FERC — which requires NERC to detail audits of regional entities in the past five years or provide a plan for performing them within the next 18 months — was delayed to June 1.

May 26, 2020

New Rules Threaten Mexico’s Foreign Energy Investment

Mexico’s government has been chipping away at the country’s electricity market reforms ever since Andrés Manuel López Obrador assumed the presidency in December 2018.

Mexico Foreign Energy Investment — Mexican President Andrés Manuel López Obrador | *Office of the Presidency*

A planned 2019 auction of renewable energy contracts, dominated by foreign private investment, was cancelled. Natural gas contracts with private developers were renegotiated. Attempts were made to grant clean energy certificates, awarded to clean energy generators that began operations after August 2014, for legacy state-run hydro plants.

Last month, the government suspended synchronization trials for 28 wind and solar projects and placed indefinite limits on the amount of electricity renewable resources can provide to the grid, measures that affected 4.5 GW of capacity.

The final blow may have come on May 15, when the government announced new regulations that give priority to electricity generated by Mexico’s state-run electricity monopoly, Comisión Federal de Electricidad (CFE). Relying on gas and heavy fuel oil, CFE’s energy costs are as high as $141/MWh. In comparison, renewable energy, without marginal costs, goes for about $20/MWh and has generally been dispatched first.

No wonder, then, that as renewable developer Mannti Cummins put it, a WhatsApp war erupted that afternoon and into the evening. (Because Mexican phone companies charge for texts, many phone users resort to the WhatsApp Messenger tool.)

“I read through [the rules], and it hurt. ‘I can’t believe they’re doing this. I can’t believe they’re doing this,’” Energía Veleta’s Cummins told RTO Insider. “It’s just the weirdest thing I’ve ever seen.

“I’ve been in kind of a daze since then,” he said. “This flips the whole market on its head. It kills renewables. They’ve taken some body blows and punches, but it’s a knockout for renewables.”

Mexico’s state-run electricity monopoly, CFE, has been the big winner under the new Mexican administration. | © *RTO Insider*

The new policy also limits new power generation permits and places additional restrictions on new renewable resources. That places at risk 44 renewable projects, worth about $6.4 billion, scheduled to begin commercial operation this year and next.

Mexico’s energy ministry, Secretaría de Energía (SENER), said the rules were necessary because of a drop in demand caused by coronavirus lockdowns and to preserve the grid’s reliability, safety and continuity. Market participants and observers aren’t buying that and note the rules will allow CFE to burn fuel oil the country’s state-run petroleum company, PEMEX, can’t sell in a world awash with oil.

A May 18 report produced by global law firm Norton Rose Fulbright said, “SENER has eliminated any doubt that power sector policy in Mexico is being driven by the state-owned utility and dominant market player [CFE], rather than by sound and competitive policy principles enshrined in Mexican law.”

That would make a seer of José María Lujambio, former legal counsel at Mexico’s regulatory commission (Comisión Reguladora de Energía, or CRE) and the Austin, Texas-based energy practice leader for Mexican law firm Cacheaux Cavazos & Newton. A couple of years ago, he predicted CFE would enjoy a “privileged position” under AMLO, as López Obrador is more commonly known. (See Changes Add Uncertainty to Mexico’s Power Market.)

“It’s another chapter, perhaps the most shocking, among several specific measures that have put obstacles in place for private participation,” Lujambio said last week.

Duncan Wood, director of the Wilson Center’s Mexico Institute and an internationally respected specialist on North American politics, said no one should have been surprised by the recent announcements. AMLO came into power promising greater state control of the country’s natural resources and cracking down on what he said was private corruption.

“Still, it came as a bit of a shock because it’s such an obvious, blatant aggression against the energy reform of 2013,” Wood said in a WhatsApp message. “What we’re seeing here is an attempt to centralize control of the electric system, to promote CFE as the dominant actor within the electric sector.

“Ultimately, this is all about increasing political power and centralizing control over the economy,” he said. “This is one way of attempting to eliminate competition for CFE, not just in terms of competition for generating electrons but about competition for the supply of electricity to the market. If CFE becomes the only actor that can supply electricity, that gives it an enormous amount of political power.”

“[AMLO’s] actions prove he wants to stick it to private companies,” said Cummins.

‘Huge’ Potential

Ambassadors from the European Union and Canada were quick to respond to the latest measures, sending letters to SENER Minister Norma Rocío Nahle on May 15 that were almost immediately leaked to the Mexican media. European companies Engie, Enel, Iberdrola and Vestas and several Canadian firms dominate Mexico’s renewable market.

“This agreement establishes various actions and strategies [for] operational control, which put at risk the operation and continuity of renewable energy projects of Canadian companies in Mexico,” wrote Graeme Clark, Canada’s ambassador to Mexico.

“Potential investors will be completely freaked out by this move,” Wood said.

Modern buildings tower over Mexico City. | © *RTO Insider*

Some market participants expect legal injunctions to stop the rules before they are in place. That’s what happened following April’s suspension of market tests for renewable resources. The country’s grid manager backpedaled and began pre-operational testing again.

Wood pointed out that during AMLO’s May 18 mañanera — as his daily morning two-hour press conferences are called — Mexico’s president said he respects the decision of the courts.

“I don’t think this is the end of the story, however,” Wood said.

SENER’s proposal was published in Mexico’s version of the Federal Register on May 15, but not before pushback from the national commission of regulatory improvement (CONAMER), which determines whether new laws have an economic impact. CONAMER called for regulatory impact studies and a 20-day public comment period, saying the new measures would pose compliance costs on companies.

Those requests were to no avail. The commission’s chief resigned the afternoon of May 15. An hour later, Cummins said, the decree was published.

“It’s clearly illegal,” he said. “Not only did they not follow the procedures in making changes to regulations, they pushed it through on this fast track.”

“The planning and reliability of the National Electric System requires rational economic regulation for the accelerated and progressive incorporation of all energies,” SENER said in a statement May 16. “In the case of intermittent energies, they must be incorporated through the intervention and necessary support of plants that have full availability and provide planning and operational reserves.”

As if to rub salt in the wounds, CFE Director Manuel Bartlett said last week private renewable companies should pay for part of the market’s baseload power. “Do you think it’s fair for the CFE to subsidize these companies that don’t produce power all day?” he asked Reuters.

So where does Mexico’s electricity market go now? Wood said that barring an electoral loss in 2022’s “mid-terms” and an ensuing AMLO resignation, private developers will have to wait until the next administration takes over in 2024 for a change in fortunes.

“Mexico has incredible natural endowments for renewable energy,” he said. “It has shown that if you create the right legal framework and regulatory framework, then companies from around the world are willing to invest in renewable energy and produce electricity at an incredible low cost.

“There are huge opportunities for renewable energy long-term,” Wood said. “But short-term, not a lot.”

May 26, 2020

Stakeholders Urge PJM Action on Carbon Pricing

Stakeholders last week encouraged PJM to take a more active role in facilitating carbon pricing as more states look to join the Regional Greenhouse Gas Initiative (RGGI).

PJM carbon pricing — Marji Philips, LS Power | © *RTO Insider*

Marji Philips, LS Power vice president of wholesale market policy, suggested that PJM should support a IPPs, Renewable Groups Seek FERC Carbon Pricing Conference.)

Philips said PJM can support a technical conference without endorsing carbon pricing and help states achieve their environmental goals without having a uniform carbon price.

“PJM’s always been a leader in advocating that markets drive reliability,” Philips said during the Carbon Pricing Senior Task Force’s May 19 meeting, its seventh meeting since its formation last summer. “Now is not the time to abdicate that leadership by not participating in something like this.”

Market Monitor

John Hyatt of Monitoring Analytics recommended PJM “provide a full analysis” of the impact of carbon pricing on generating units and the revenues that would result to allow “states to consider a potential agreement on the development of a multistate framework for carbon pricing and the distribution of carbon revenues.”

The Market Monitor said a $10/metric ton carbon price would increase short run marginal costs by $3.34/MWh (24%) for a new combined cycle plant and $8.63/MWH (31%) for a new coal plant. For 2019, that would have increased LMPs from $27.32/MWh to $30.71/MWh, a 12% rise, based on the impact on the marginal units’ offer prices (not including a counterfactual redispatch of the system).

A $50/ton price would boost combined cycle plants’ costs by $16.72/MWh (122%) and coal plants by $43.15/MWh (156%).

The Monitor said a $10/ton carbon price would generate $3.6 billion annually in carbon allowance revenues in PJM states.

The current patchwork of state policies has resulted in wildly varying renewable energy credit (REC) prices within PJM, with an implied carbon price ranging from $5.63/ton to $19.21/ton in 2019. Solar REC prices last year ranged from an implied price of $50.23/ton to $806.35/ton, the Monitor said.

The Monitor said the varying REC prices are “inconsistent with an efficient market and inconsistent with the least-cost approach to meeting state environmental goals.”

“Using an RGGI model would leave carbon pricing within the control of the states and not of FERC or PJM,” said Monitoring Analytics President Joe Bowring. “States could define the desired carbon price. The carbon price would simply be part of the short-run marginal cost of operating units in PJM and treated like fuel or other emissions costs.”

Vistra Energy

Becky Robinson of Vistra Energy sai d her company needs a supportive market policy to achieve its emissions goals. Vistra has announced a goal to reduce CO2-equivalent emissions by more than 50% by 2030 and by 80 to 100% by 2050 from 2010 levels.

She said a national, economy-wide price on carbon with dividend payments to help alleviate the rise in energy costs would be the best solution. But she said discussions like the ones happening in the senior task force are a step toward developing a fix.

“We are definitely a believer in the power of economics to change markets and to drive change in the resource mix,” Robinson said.

Disparate state policies regarding clean energy have left states wishing to act on carbon stymied by leakage with the dispatch of cheaper fossil-fuel generated power in non-participating states, she said. FERC rulings that expand the minimum offer price rule (MOPR) to cover state-subsidized generation have also undermined state efforts, causing some states to contemplate exiting PJM’s capacity market. (See NJ Regulators Weighing Input on Ca p acity Market Exit.)

Vistra wants states to have an in-market clean energy policy option that would not be penalized by MOPR, Robinson said, and is open to sub-regional border adjustments or other market changes empowering state policies.

Robinson said the modeling presented by PJM so far has been “inconclusive” on the best border adjustment method, noting that emissions impacts differ depending on the configuration of participating states. RGGI currently includes New York, the six New England states and three PJM states: Delaware, Maryland and New Jersey. Virginia is also poised to join by the beginning of 2021, and Pennsylvania Gov. Tom Wolf issued an executive order in October directing state officials to develop a rulemaking by July 31 for joining the compact. (See Critics: Pa. RGGI Hearing Stacked w i th Detractors.)

During the May 19 task force meeting, PJM presented an updated st u dy on carbon pricing and potential leakage mitigation mechanisms, expanding on another re p ort issued March 27.

Robinson said the studies show that without border adjustments, carbon pricing works better as the pricing footprint gets bigger.

The reports found that with the Maryland, Delaware and New Jersey footprint in RGGI, carbon pricing alone increases net emissions in PJM while border adjustments decrease net RTO emissions. With RGGI expanded to Virginia and Pennsylvania, carbon pricing alone decreases net RTO emissions, while border adjustments increase net RTO emissions. (See PJM P anel Weighs Impact of Pa., Va. Joining RGGI.)

“If what you care about is emissions, it’s not clear that border adjustments are a good thing or a bad thing,” Robinson said. “It’s very case specific.”

Jason Barker of Exelon asked Robinson what solution Vistra recommended the task force consider, noting the group’s prob l em statement and issue cha r ge call for examining border adjustments and leakage mitigation.

Robinson said coming up with a “mutually agreeable solution” for all interested stakeholders should be the goal of the task force. For the states that are not interested in carbon pricing, there should be a mechanism for quantifying the incremental value of carbon pricing. The results should be presented to all the states in PJM to determine if the value outweighs the cost.

LS Power

Philips gave a presen t ation for LS Power, the second largest privately held generation company in the PJM market with more than 11,000 MW of capacity. She said LS Power remains “technology neutral” when it comes to generation — with resources including pumped storage, solar and natural gas combined cycle facilities — and continues to invest where price signals are transparent.

PJM’s competitive market structures have allowed for ongoing investment opportunities that provide consumer benefits, Philips said, and the adoption of transparent carbon pricing within the RTO would continue to provide opportunities for investment and innovation.

“We want the markets to work so we can make investments in a renewable portfolio as well as everything else,” she said.

Barker asked Philips what LS Power would like to see the task force accomplish.

Philips said she supports requests for more data from PJM on the cost and revenue impact to states and would also back Vistra in considerations about how border adjustments could and could not work.

The open-ended nature of the task force charter allows for broad discussions in search of solutions and could bring more changes if stakeholders actively encouraged input from state commissions and legislators, she said. PJM’s markets have already driven change to policy and will continue to bring innovation.

“What PJM has done already in terms of driving down emissions is remarkable. And they’ve maintained regional reliability while doing it,” Philips said. “Obviously, we wish everybody would embrace a carbon price because that would solve a lot of problems. But recognizing that’s not going to happen at this point, we’d at least like to keep the ball moving and get as much of these externalities into the market and priced appropriately.”

Exelon

Kathleen Robertson, director of strategic initiatives and environmental policy for Exelon, s a id PJM should immediately begin to develop border adjustments for RGGI, which is anticipated to cover the majority of PJM load by 2022.

Exelon’s modeling assumed all RGGI generators have carbon costs included in their bids. Offers from non-RGGI generators would not include carbon, costs but power flowing from a non-carbon region to a carbon region would be subject to an additional wheeling cost.

Robertson said Exelon’s analysis concluded that well-designed border adjustments preserve efficiencies of regional energy markets and reduce emissions while preserving state policy choices.

May 25, 2020

UPDATED: PG&E Bankruptcy Moves Toward Conclusion

[Updated to include voting results.]

Proceedings to conclude the sixth-largest bankruptcy in U.S. history will likely happen via video starting Wednesday, the judge overseeing PG&E Corp.’s Chapter 11 reorganization said last week.

Judge Dennis Montali, with the U.S. Bankruptcy Court in San Francisco, conducted a virtual hearing using Zoom on May 19 in which he spoke from his home with a dozen lawyers in New York, California and elsewhere. The remainder of hearings in the PG&E bankruptcy case will probably also be held via video because of the COVID-19 crisis, he said.

The purpose of the May 19 hearing was to establish the schedule for proceedings to approve or reject PG&E’s $60 billion reorganization plan, including the $13.5 billion it has promised to some 80,000 victims of wildfires sparked by its equipment in recent years.

Fire victims and other creditors, about 250,000 in all, had to cast their ballots on the plan by May 15. A two-thirds vote is required for approval.

Late Friday, Prime Clerk and PG&E filed lengthy documents with the court detailing the voting results. Wildfire victims voted by an 85% majority to approve PG&E’s Chapter 11 plan, and the other creditors overwhelmingly supported it, too.

“Fire victims have spoken, and they have spoken loudly and resoundingly in favor of the plan. The time has come to confirm the plan,” PG&E said in its filing.

Trial Starts Wednesday

The “confirmation” trial of PG&E’s plan is scheduled to start Wednesday. After hearing from attorneys for all major parties, Montali will have to decide whether to approve PG&E’s reorganization proposal.

PG&E is trying to exit bankruptcy by June 30 to meet the requirements of Assembly Bill 1054, a measure pushed through the State Legislature by Gov. Gavin Newsom last July that creates a $21 billion fund to insure utilities against future wildfires. California law holds utilities strictly liable for wildfires sparked by their equipment.

May 15 also was the deadline for parties to file objections to the plan. Dozens did so, including the state and federal governments, the U.S. Trustee in the bankruptcy case, and the city and county of San Francisco. They questioned provisions in the plan that they say could exculpate PG&E, its fiduciaries and associates for actions they take after the bankruptcy case has ended.

The Tort Claimants Committee (TCC), which represents fire victims, objected to the plan based on a lack of assurances that the $6.75 billion in PG&E stock, intended to fund half of the victims’ trust as part of a negotiated settlement agreement, will hold its value amid the coronavirus pandemic and potential wildfires this summer and fall.

“The plan … fails to provide fire victims with the treatment and value that was agreed to in the settlement,” the TCC wrote. “Instead, the plan has whittled away various aspects of the settlement and could harm fire victims in amounts that are in the billions of dollars.”

PG&E lawyers told the judge May 19 that negotiations and mediation are underway that could resolve the objections before Wednesday’s confirmation hearing.

CPUC to Vote Thursday

The California Public Utilities Commission is scheduled to vote on PG&E’s reorganization plan Thursday, wrapping up an investigation that began in September. The vote was delayed a week after a party to the proceeding sent an improper ex parte email, the CPUC said. (See related story, Improper Email Delays CPUC Vote on PG&E Plan.) AB 1054 tasked the commission with ensuring PG&E’s plan is in the public interest, including “the electrical corporation’s resulting governance structure … in light of [its] safety history, criminal probation, recent financial condition and other factors deemed relevant.”

A proposed decision by a CPUC administrative law judge recommended approving the plan as long as PG&E agrees to enhanced oversight and enforcement by the commission. The utility has said it will accept the changes, and it agreed earlier this month to pay a record $1.9 billion in penalties levied by the CPUC. (See CPUC, PG&E Agree to Record $1.9B in Penalties.)

Sentencing Ahead

The utility has said it intends to plead guilty to 84 counts of involuntary manslaughter and one count of starting an illegal fire stemming from the Camp Fire in November 2018. State investigators determined a PG&E transmission tower ignited that blaze, the deadliest and most destructive wildfire in state history, which destroyed much of the town of Paradise.

The Butte County District Attorney has said that PG&E’s sentencing hearing will be held on June 16 and streamed live on the Butte County Superior Court’s YouTube channel.

PG&E remains on criminal probation for six felonies related to the San Bruno gas pipeline explosion in September 2010.