Page 1027 – RTO Insider

November 1, 2020

DTE Energy to Cleave Pipeline Business

DTE Energy backed away from its pipeline business last week, announcing that it will spin off its non-utility natural gas pipeline, gathering and storage business.

The transaction will have the company shedding DTE Midstream and becoming a pure-play electric and natural gas utility. Midstream is set to carve out its own Detroit headquarters and become an independent and publicly traded company by mid-2021. DTE shareholders will retain their shares and receive pro rata shares of the new Midstream company.

DTE said the move will not negatively affect rates, customers or utility operations. CEO Jerry Norcia said the Midstream spinoff announcement “follows a thorough review with our board to identify opportunities to optimize our portfolio and maximize shareholder value.”

“We recognize that this comes not long after our significant acquisition of assets in the Haynesville [Shale] basin,” Norcia said during the company’s third-quarter earnings call Oct. 27. “Through 2019, while business mix discussions were still ongoing, we continued to pursue an aggressive value creation agenda for Midstream, which yielded the Haynesville acquisition. … Because this acquisition and the balance of the Midstream portfolio continues to perform exceedingly well … and thrive on its own, it crystallized our path to pivot to a high growth pure-play utility with the spin of a well run Midstream company. We believe this strategy will unlock significant value for our shareholders.”

Current Midstream President and COO David Slater is set to become CEO of the standalone company.

After the Midstream transaction, DTE will receive about 90% of its operating earnings from its core utility business versus the 70% it receives today.

Midstream owns approximately 2,350 miles of pipeline and operates 91 Bcf of gas storage capacity. DTE acquired most of the network in $1.3 billion and $2.5 billion transactions in 2016 and 2019 respectively. When the deal is complete DTE estimates it will generate 90% of its operating earnings from its utility business versus the current 70% operating earnings from its core utility.

“As most of you know, my background includes a substantial amount of time in the gas industry, including my involvement in development of our Midstream business. The team and I have dedicated a significant amount of time and energy creating a Midstream business at DTE that is recognized as one of the best in the country. So, you can imagine how important this decision is to our team and me. After careful consideration and review with our board, I am confident that the separation is the best way to allow the Midstream business and its team to achieve their full potential and to enhance overall value for our shareholders,” Norcia said.

DTE estimates Midstream will earn $700 million before taxes in 2020.

The company reported third-quarter earnings of $476 million ($2.46/share), compared with $319 million ($1.73/share) in 2019. It said earnings were up because of higher year-over-year residential sales, higher rates and warmer weather. The earnings report represents a turnaround from first-quarter earnings, when DTE contemplated shaving millions from operations and maintenance expenses to offset drooping sales. (See DTE to Cut Spending in Response to Pandemic.)

“I want to thank all the leaders and our 10,000 employees of DTE for creating this tremendous success in a year of great turmoil and uncertainty,” Norcia said. “We are firing on all cylinders, keeping our people safe and delivering for our customers, communities and investors. It is truly remarkable and certainly a reflection of the grit and determination of the great people of DTE.”

Norcia said DTE plans to invest about $14 billion in its electric utility over the next five years, some of that in renewable generation. He noted DTE’s goal of achieving net-zero carbon emissions by 2050. For that to happen, he said DTE needs to double renewable capacity by 2024 and quadruple it by 2040.

November 1, 2020

Transource Tapped for SPP’s 2nd Competitive Tx Project

SPP last week awarded its second competitive transmission project under FERC Order 1000, hopeful that it will succeed where the first one failed.

The Board of Directors on Oct. 27 approved an industry expert panel’s (IEP) recommendation to issue a notification to construct (NTC) to Transource Missouri, the panel’s “designated transmission owner,” for a 75-mile, 345-kV line in Oklahoma. The Sooner-Wekiwa project has a $66 million revenue requirement and an expected completion date of 2026.

The board approved Xcel Energy Southwest Transmission as the alternate builder.

The IEP evaluated 10 project bids under SPP’s competitive transmission owner selection process. Three of those bids came from Transource and occupied the top three spots in the panel’s intricate scoring matrix. The Transource bids were also the three most expensive, coming in between $66 million and $69 million. Projects submitted by other bidders ranged from $52.2 million to $64 million.

SPP awarded its first competitive project in 2016 to Mid-Kansas Electric, but the project was later canceled after load projections dropped. One stakeholder said at the time, “We went hunting for the project, we found it, we caged it — and we shot it.” (See SPP Cancels First Competitive Tx Project, Citing Falling Demand Projections.)

As was the case four years ago, the competitive project’s NTC went to an incumbent transmission provider, despite Order 1000’s requirement removing federal rights of first refusal. Transource Missouri is one of several subsidiaries of Transource Energy, a competitive transmission joint partnership between American Electric Power and Evergy. AEP’s Public Service Company of Oklahoma owns the Wekiwa substation’s end point west of Tulsa.

Oklahoma Gas & Electric owns the Sooner Power Plant at the other end of the project. In years past, the two utilities would likely have negotiated construction responsibilities.

The five-person IEP determined Transource’s winning proposal “best addressed a significant risk” to the project’s success, that being “the timely acquisition of rights of way.”

“This proposal also demonstrated significant capabilities and historical success in construction management and in the ability to operate and maintain a 345-kV transmission line,” the panel said in its final report.

Transource has completed three projects, in Missouri, Nebraska and West Virginia, and has a fourth under development, the Independence Energy Connection in Pennsylvania and Maryland.

SPP’s 2019 Integrated Transmission Planning assessment identified the Sooner-Wekiwa project as a potential competitive upgrade from among more than 1,600 proposed solutions submitted during the ITP process.

It estimated it would produce a 4.29 benefit-cost ratio under the Future 2 “emerging technologies” scenario, which assumed that electric vehicles, distributed generation, demand response and energy efficiency would increase energy growth rates, and that all coal and gas-fired generators over the age of 60 would retire. The assessment said the project will provide an alternate path for bulk power transfers to flow east to major SPP load centers, preventing flows from being diverted to the 138-kV system at Cleveland, Okla.

Requests for proposals were issued in early December 2019, requiring the IEP to be seated. The five-person panel, selected for its expertise in engineering design, project management construction, operations, rate analysis and finance, evaluated the project proposals in those categories. Five of the 10 proposals were submitted as detailed project proposals (DPPs), qualifying them for 100 incentive points each in the scoring. The other five were less detailed and did not qualify for the bonus points.

The winning proposal won a score of 877.9, topping the categories of Project Management and Operations and receiving the third highest point allocation for Engineering Design and fourth highest for Finance. Other projects scored from 517.8 to 871.9.

“I am very favorably impressed with the quality and thoroughness of the analysis of the submitted proposals,” Board Chair Larry Altenbaumer said.

Xcel’s Southwestern Public Service and Oklahoma cooperative Tri-County Electric were the only Members Committee representatives to vote against the recommendation.

“If you climb up to 35,000 feet, the present value revenue requirement for [Transource’s proposal] is 20% higher than the alternative proposal,” SPS President David Hudson said. “This is sort of showing the FERC 1000 process is actually costing SPP ratepayers more money. That isn’t even considering the cost of staff administering the 1,500 DPPs. What is this FERC Order 1000 process costing customers versus what it is saving them?”

The Advanced Power Alliance’s Steve Gaw agreed, saying a FERC 1000 policy discussion is “ripe.”

“It’s clear there are some issues in SPP’s Tariff that need to be thought through,” he said.

Golden Spread Electric Cooperative’s Michael Wise pointed out that the Strategic Planning Committee reviewed SPP’s competitive process following the Walkemeyer project’s selection four years ago. He said several improvements were made to the process.

“It might be necessary for the SPC to once again take up these issues,” he said.

“We would welcome a stakeholder process to look at improvements,” said IEP Chair Steve Strickland, a 35-year veteran of Entergy Arkansas. “This is only the second time we completed the process, and each time, we learned something new.”

October 31, 2020February 12, 2025

FERC Rejects ESI Proposal from ISO-NE

FERC ruled Friday that ISO-NE’s proposed Energy Security Improvements (ESI) market design is “unjust and unreasonable” because it would add substantial costs “without meaningfully improving fuel security” (ER20-1567).

ESI would have allowed the RTO to procure energy call options for three new day-ahead ancillary service products to improve the region’s energy security, particularly in winter when natural gas shortages can leave generators without fuel. Option awards would have been co-optimized with all energy supply offers and demand bids in the day-ahead market.

FERC found that the RTO’s proposed day-ahead ESI products “do not provide enough time for resources to take the steps necessary to perform during stressed conditions if they have not already taken them” as arranged fuel, for example. The proposed market design would have allowed resources that have not made advance arrangements to not participate because of its voluntary nature, undermining its ability to address fuel security. The commission noted that the impact assessment produced for the RTO by Analysis Group said ESI “would not materially reduce reserve shortages or the potential for loss of load, but nevertheless, forecasts increased costs of $20 million to $257 million per year.”

| National Grid

FERC also rejected an alternative proposed by NEPOOL that would have resulted in lower costs to ratepayers than the RTO’s proposal, saying it contains the same deficiencies.

FERC said that although it “does not generally require the mathematical specificity of a cost-benefit analysis to render a proposal just and reasonable … the commission must protect consumers from excessive rates and charges. In light of our finding above that ISO-NE fails to demonstrate that ESI will materially improve fuel security, we find that ESI does not strike an appropriate balance between addressing fuel security in New England while protecting consumers from the significant cost of those fuel security benefits.”

The commission said the RTO’s proposal also does not adequately address the misaligned incentives problem: fuel-secure resources may not be sufficiently motivated to make additional investments in energy supply arrangements. ISO-NE currently relies on resources that might not be available during stressed conditions because it did not procure the necessary fuel or resources with energy storage capabilities and did not take the steps needed to produce energy during stressed conditions.

“We find that, while the procurement of day-ahead reserves or call options allows ISO-NE to procure additional resource capability one day prior to real time, the record in this proceeding demonstrates that one day is not a sufficient time frame for resources to take the steps necessary to perform during stressed conditions,” the commission wrote.

The RTO pointed to the results of the impact assessment to claim that ESI would create strong financial incentives for resources “to maintain more secure energy supplies without an associated forward market.” According to FERC, ISO-NE failed to demonstrate how such incentives would be meaningful to resources that are unable to adjust energy supply arrangements in the day-ahead time frame.

NEPOOL Proposal

The RTO’s proposal had failed to win NEPOOL stakeholders’ endorsement, garnering only 39.6% support at a Participants Committee vote in April. Although Generators, Suppliers and Alternative Resources generally approved the plan, the other sectors were unanimous in opposition.

The committee endorsed a proposal by the New England States Committee on Electricity by a 61.7% sector-weighted vote, with unanimous support from the Transmission, Publicly Owned Entity and End User sectors and unanimous opposition from Generators. (See ISO-NE Sending 2 Energy Security Plans to FERC.)

But FERC said the NEPOOL’s alternative “fails to sufficiently align the timing of reserve procurement with that of fuel procurement and maintains the voluntary nature. … Furthermore, the impact assessment demonstrates that the NEPOOL alternative would not materially reduce reserve shortages or the potential for loss of load.”

The result of more than a year of stakeholder meetings, the ESI proposal was prompted by FERC’s July 2018 finding that ISO-NE’s Tariff is not just and reasonable because the RTO lacks a way to address fuel security concerns that it said could result in reliability violations as soon as 2022. The Tariff currently allows cost-of-service agreements only to respond to local transmission security issues. (See FERC Denies ISO-NE Mystic Waiver, Orders Tariff Changes.)

But FERC said Friday it made no finding on whether the RTO faces fuel security or energy security problem.

“We recognize that ISO-NE has concerns about its current and future ability to reliably serve load given its growing reliance on ‘just-in-time’ resources such as pipeline-fed natural gas and renewable generation, which could have efficiency and reliability consequences,” the commission wrote. “If ISO-NE decides to pursue a solution to address these concerns, we encourage it to explore a market-based reserve product that provides resources sufficient lead time and ability to acquire fuel or take other steps necessary to be able to deliver energy when needed.”

FERC added that it expected a market design would coordinate procurement of forward reserves and incentivize resources to offer into the forward, day-ahead and real-time energy and reserves markets based on their actual costs. It should also prevent the exercise of market power, including through potential mitigation measures and include financial obligations or incentives sufficient to ensure resources can deliver energy or reserves in real time.

“We are not, however, directing ISO-NE to pursue any particular approach,” the commission wrote. “We further note that nothing in this order prohibits ISO-NE from proposing a day-ahead reserves market independent of any proposal to address the concerns at issue here.”

The ruling also rejected ISO-NE’s proposal to sunset the interim fuel security retention mechanism and the inventories energy program one year earlier than currently set in the Tariff.

“We’re reviewing the decision and will discuss next steps with stakeholders,” ISO-NE spokesman Matt Kakley said. “We remain committed to finding market-based solutions to solving the region’s energy security challenges.”

Attorneys for Day Pitney said they “are continuing to digest the implications of the order, including potential next steps for NEPOOL and ISO-NE, and will provide additional information if and as appropriate.”

October 30, 2020

FirstEnergy Fires Jones over Bribe Probe

FirstEnergy announced late Thursday it had fired CEO Charles Jones and two other officials after an internal investigation determined they had violated the company’s code of conduct in the alleged bribery scheme that resulted in the passage of Ohio House Bill 6.

In July, federal prosecutors alleged FirstEnergy spent $61 million in bribes, “dark money” campaign contributions and advertising to elect the speaker of the Ohio House of Representatives and allies in return for their support of HB6, which provided $1.5 billion in subsidies for the utility’s struggling nuclear plants.

In a press release issued Thursday evening, company officials said the Independent Review Committee of the Board of Directors had announced the termination of Jones, along with two other executives: Dennis Chack, senior vice president of product development, marketing and branding; and Michael Dowling, senior vice president of external affairs.

Officials said an internal review related to “government investigations” determined the executives “violated certain FirstEnergy policies and its code of conduct.”

Jones’ firing was announced after the stock market closed and the guilty pleas earlier in the day of former FirstEnergy Solutions (FES) lobbyist Juan Cespedes, 41, and political strategist Jeff Longstreth, 44, who admitted to participating in a racketeering conspiracy.

FirstEnergy is alleged to have supported the election of former Ohio House Speaker Larry Householder (R) and his associates in a three-year scheme that resulted in the approval of zero-emission credits for FES’ money-losing Perry and Davis-Besse nuclear plants.

Denied Wrongdoing

FirstEnergy no longer owns the nuclear plants, after FES emerged from bankruptcy in February as an independent company, Energy Harbor. But the affidavit that accompanied the criminal charges said that the CEO of “Company A” — as FirstEnergy was referred to in the document — was in regular contact with Householder. (See Feds: FE Paid $61 Million in Bribes to Win Nuke Subsidy.)

Jones, who had led FE since 2015, denied wrongdoing in a second-quarter earnings call, saying, “We let the merits of our arguments carry the day when we’re operating in the political environment.” (See FirstEnergy, AEP CEOs Deny Wrongdoing.)

Steven Strah, president of FirstEnergy, was appointed Thursday as FirstEnergy’s acting CEO. Christopher Pappas, a member of the company’s board, was named executive director.

“We as a board have strong confidence that this leadership transition, and Steve’s appointment as acting CEO, will position FirstEnergy to move forward with positive momentum and drive long-term shareholder value creation,” said Donald Misheff, non-executive chairman of FirstEnergy. “I look forward to working with Chris in his role as executive director to oversee the management team’s execution of FirstEnergy’s strategic initiatives, engage with the company’s external stakeholders and support the development of enhanced controls and governance policies and procedures.”

Strah was appointed FirstEnergy’s president in May as part of the company’s succession planning process, taking over the position from Jones. (See Strah Named New President of FirstEnergy.) Strah, who began his career with The Illuminating Company in 1984, previously served as regional president and vice president of distribution support of Ohio Edison and senior vice president at FirstEnergy Utilities.

“I’m excited for the opportunity to lead FirstEnergy, and I am deeply committed to the future of this company,” Strah said. “I have seen firsthand the strong management team and deep bench of highly capable leaders across our organization, and I am confident in our ability to continue delivering value to our stakeholders as we remain intently focused on our business priorities through this transition and beyond.”

According to a company biography, Jones began his career with Ohio Edison as a substation engineer in 1978 before being named president of Ohio Edison’s Penn Power subsidiary in 1995. Jones would later go on to serve as senior vice president and president of FirstEnergy Utilities in 2010, executive vice president and president in 2014 and to president and CEO in 2015.

Plea Deals

The government said the conspiracy began in March 2017 when Householder began receiving quarterly $250,000 payments through Generation Now, a 501(c)(4) nonprofit organization created to mask the payments.

In his plea Thursday, Longstreth admitted to organizing Generation Now with the knowledge that it would be used to receive bribe money to support Householder’s bid for speaker. Longstreth managed the Generation Now bank accounts and made financial transactions to conceal that FES was a source of funding to Generation Now.

Cespedes plea ded guilty to orchestrating payments to Generation Now with the knowledge that the payments were intended to help Householder and his allies political campaigns in return for passing the nuclear bailout legislation.

Both men face up to 20 years in prison but may be looking for lighter sentences by testifying against Householder and the other two defendants, lobbyist Neil Clark and former Ohio GOP Chairman Matt Borges. U.S. District Judge Timothy S. Black, who accepted the pleas, said he would defer sentencing until the cases against the other defendants are resolved.

“There’s a lot more shoes to drop, and there’s a lot of nervous people today. I don’t know who they are, but they do,” Ohio Democratic Chairman David Pepper told The Columbus Dispatch. “It’s no secret we believe the culture of corruption is absolutely overwhelming in Columbus now. Them turning state witness will lead to more information down the road about how far this plot went.”

“Today’s guilty pleas by Longstreth and Cespedes move the HB6 racketeering scandal from allegation to admitted fact,” tweeted state Attorney General Dave Yost, who is pursuing civil litigation over the scandal. “The only remaining question: ‘Who else?’ My team, including a forensic accountant, is going through the first batch of documents in our civil racketeering lawsuit.”

As of 8 p.m., FirstEnergy’s stock price had dropped by 7.3% to $29.30 in after-hours trading.

October 30, 2020

SPP Quarterly Briefing/RSC Briefs: Oct. 26, 2020

The new kid on the block, SPP’s Western Interconnection reliability coordinator, stepped into the fray when CAISO’s RC West experienced shortages this summer.

During the RTO’s joint quarterly stakeholder meeting Monday, Bruce Rew, senior vice president of operations, said the Western RC assisted with load sheds of up to about 1,000 MW Aug. 14-19, when CAISO, faced with energy shortages, first issued energy emergency alerts and then instituted rolling blackouts. (See Theories Abound over California Blackouts Cause.)

“We did help, as best we could,” Rew said. “We worked closely with California and the RC West system as much as possible.”

SPP’s RC ensured all transmission and generation was available to the interconnection during the crisis. The RC did have to declare its own EEAs because of concerns about meeting reserves obligations, Rew said, but it did not shed load in its own nine balancing authorities.

The RTO’s Western RC has only been online since December 2019. It will add 3.45 GW of generating capacity to its footprint next year when Gridforce Energy Management joins. (See SPP Expands its Western RC Footprint.)

SPP’s peak load this summer was down when compared to the previous two. | *SPP*

Closer to home, Rew said SPP’s peak load this summer was down slightly from the previous two years as it recovered from the pandemic’s early effects. The largest spread came in early September when peak load was around 37 GW, compared to more than 45 GW in 2019 and almost 43 GW in 2018. Rew said mild weather and other issues were responsible for much of the drop.

The grid operator remains on track to have wind be its No. 1 fuel source this year. It added 3.6 GW of registered wind resources during the third quarter, bringing the total to 27.4 GW.

“We’re a year ahead of schedule,” CEO Barbara Sugg said.

With an increased reliance on wind energy comes a need for improved forecasting, Sugg said. The RTO’s wind and solar forecasting error averages both improved during the third quarter from a year ago. The wind average was 3.80%, down from 4.54%, and the solar average was 4.70%, down from 5.66%.

Rew said SPP’s Integrated Marketplace now has 264 participants, 177 of which are financial-only and 87 that own assets.

In other quarterly updates, a Strategic Planning Committee group picking up where a working group left off in trying to modify SPP’s congestion-hedging practices by adding counterflow optimization is “trying to determine a path forward on this very complex issue,” Director Graham Edwards said. He said the team will be reaching out to stakeholders before reporting back to the SPC in January. (See SPP SPC Takes on Congestion Hedging Issues.)

Director Mark Crisson, chair of the Strategic and Creative Re-engineering of Integrated Planning Team (SCRIPT) responsible for re-engineering SPP’s transmission-planning processes, said the group has developed a scope and created four sub-teams to handle much of the work. The SCRIPT plans to bring a final report to the Board of Directors for its consideration and approval in October 2021.

SD’s Fiegen to Lead RSC in 2021

The Regional State Committee approved the nomination of South Dakota Public Utilities Commissioner Kristie Fiegen as its next president, effective in January. The committee also voted to have North Dakota Public Service Commissioner Randy Christmann serve as its next vice president and Texas Public Utility Commission Chair DeAnn Walker as secretary and treasurer.

SPP — Kristie Fiegen | *South Dakota PUC*

Outgoing President and Nebraska Power Review Board Member Dennis Grennan offered to virtually hand over the gavel to Fiegen following the meeting, but she had other ideas.

“You can drive on up,” Fiegen said, teasingly offering to take Grennan pheasant hunting if he did.

“I’ll leave after the board meeting,” Grennan responded.

The RSC will also welcome Arkansas Public Service Commission Chair Ted Thomas next year. He will replace his PSC colleague Kimberly O’Guinn, who is taking his seat on the Organization of MISO States.

Dennis Grennan presides over his last RSC meeting as president. | *SPP*

The committee also approved its 2021 budget, despite concerns over a travel and meetings budget that was trimmed by 38.7% from the year before. The budget totals $326,100, but travel and meeting expenses have been cut from $280,497 to $172,000.

SPP has recently looked at alternating the quarterly governance meetings between virtual and in-person to reduce costs. Taking advantage of what it has learned from conducting seven months of meetings over the internet or the phone, the RTO will make that change next year.

“I would like to keep travel as is,” Louisiana Public Service Commissioner Mike Francis said. “It really helps my commission more if we are meeting in person. I really think we’ll figure out how to handle” the COVID-19 pandemic.

“I don’t disagree,” Grennan said. “The sooner we can get back to where at least a portion of our meetings are face to face, the better.”

CAWG to Pause Pricing Zone Work

The RSC directed its Cost Allocation Working Group to remain focused on decoupling SPP’s Schedule 9 and 11 transmission pricing zones while it waits on a white paper from a competing task force.

Oklahoma Corporation Commission staffer Jason Chaplin said the CAWG has been unable to reach consensus on the issue, saying there is a “slight lean” toward keeping the RTO’s existing methodology. The Holistic Integrated Tariff Team (HITT) had tasked the working group with separating the two pricing zones and allowing the creation of larger Schedule 11 pricing zones and/or Schedule 9 sub-zones, taking into consideration new deliverability sub-regions, distribution factor calculations, and market and power flows.

“With this issue, addressed appropriately, we would solve the zonal placement issue,” Nebraska Public Power District’s Tom Kent, who chaired the HITT, told the RSC. “I don’t want us to lose momentum in getting this issue right.”

CAWG Chair John Krajewski, who consults with the Nebraska Power Review Board, suggested the group slow down its work, “so slow, it’s almost a pause.”

The group’s work has been hamstrung while it waits on a deliverability report from the NRIS/ERIS Deliverability Task Force (NEDTF), which the HITT asked to develop policies creating a balance between energy resource interconnection service (ERIS), network resource interconnection service (NRIS), generator-interconnection products and long-term firm transmission service.

The NEDTF’s white paper, which includes a recommendation to replace NRIS with a new capacity resource interconnection service (CRIS), was only approved by the Markets and Operations Policy Committee earlier in October. The task force says CRIS would add deliverability to the existing NRIS product and provide a clearer distinction between the two services. (See “Interconnection Improvements,” SPP MOPC Briefs: Oct. 13-14, 2020.)

The SPP board would also approve the document the day after the RSC meeting.

“If we pause to do more data and do a meaningful analysis, that makes sense,” Kansas Corporation Commissioner Andrew French.

The CAWG agreed to provide a new work plan in November and updates to the RSC in January and April. The work was originally to have been completed in July.

The RSC did endorse the CAWG’s recommendation to implement previously approved language that creates a narrow process to regionally allocate costs for transmission projects between 100 and 300 kV primarily used to move power out of the local transmission pricing zones.

New Mexico Public Regulation Commissioner Jeff Byrd opposed RTWG RR422, while Francis, Walker and OCC Commissioner Dana Murphy abstained.

The MOPC approved the measure during its October meeting. (See “Some Byway Costs to be Allocated Regionally,” SPP MOPC Briefs: Oct. 13-14, 2020.)

October 30, 2020

PG&E Trying to Move Forward from Bankruptcy

In a third-quarter earnings call Thursday, PG&E Corp. executives tried to reassure investors that the company is on track to move forward from its bankruptcy, the catastrophic wildfires of the last three years and the botched power shutoffs that blacked out more than 2 million residents in 2019.

PG&E emerged from bankruptcy in June after a settlement with fire victims that gave them a 22% equity stake in the state’s largest utility.

“With a full quarter behind us after the bankruptcy, we’re now very focused on executing well on the operational and financial plan we set out,” interim CFO Chris Foster said. “We have a strong earnings projection ahead of us supported by regulatory outcomes … and we are excited about the long-term opportunities provided by our state’s focus on clean energy technology.”

PG&E recorded GAAP earnings of 4 cents/share for the third quarter, compared to losses of $3.06/share for the same period in 2019. Non-GAAP core earnings were 22 cents/share compared to $1.11/share.

In the second quarter, PG&E reported GAAP losses of $3.73/share, driven mainly by $2.5 billion in costs to exit bankruptcy and help pay for the 2019 Kincade Fire. (See PG&E Reports Steep Q2 Loss on Bankruptcy, Fire Costs.)

On Thursday, PG&E said it had upped its estimates for the costs of the Kincade Fire, an October 2019 blaze not covered by bankruptcy settlements, to $170 million. The cause remains under investigation by the California Department of Forestry and Fire Protection (Cal Fire), though early indications were that the fire started beneath a PG&E transmission line running from a geothermal plant north of the Napa and Sonoma valleys.

PG&E said it had not de-energized the line because the weather conditions at the time did not meet the criteria in its public safety power shutoff (PSPS) protocols.

Analysts on Thursday’s call also asked about the Zogg Fire, a deadly blaze near Redding that started in late September. Cal Fire seized a portion of a PG&E distribution line in its ongoing investigation of the wildfire. PG&E said Thursday that line had also remained energized because of a relatively low wind speed forecast at the time. (See PG&E Line Was Active when Zogg Fire Started.)

The 2019 and 2020 fires hang over PG&E’s head, along with memories of last year’s PSPS events that drew severe criticism from the public and elected officials.

In fall 2019, PG&E blacked out 2.4 million residents, often without sufficient warning and without providing information about when power might be restored. The company’s websites crashed under a heavy surge, requiring emergency intervention by state agencies. (See California Officials Hammer PG&E over Power Shutoffs.)

This year PG&E promised “smaller, shorter and smarter” shutoffs, with ample public notice and quicker restoration. It gave at least 48 hours’ notice of possible blackouts, and it moved its websites from its data center to the cloud, with testing to make sure the servers could handle heavy traffic, interim CEO Bill Smith said in the call with investors.

The company also set a goal of reducing the number of customers impacted by one-third from last year and met that mark in the five PSPS events it has instituted this year, Smith said. In its latest PSPS event on Sunday and Monday, PG&E blacked out 345,000 customers in portions of 34 counties but restored power to almost all by Wednesday.

Another criticism from last year was that PG&E had not set up a sufficient number of community centers where those who lost power could receive aid. Smith said this year PG&E made 50 centers available to 172,000 residents versus 80 centers for 1 million residents last year.

Despite the utility’s reported efforts, its lagging stock price didn’t move much Thursday. It opened trading at $9.64/share and closed at $9.75/share. PG&E stock was worth more than $70/share before its equipment started the wine country fires of October 2017.

October 30, 2020

PJM Updates Stakeholders on MOPR Filing

Stakeholders got a look Thursday at PJM’s initial response to FERC’s ruling this month on its expanded minimum offer price rule (MOPR).

Chen Lu, PJM senior counsel, presented the Markets and Reliability Committee with highlights of the order, issued Oct. 15, and the additional revisions the RTO must file by Nov. 16 (EL16-49-003, et al.). FERC accepted most of PJM’s compliance filing while reversing its position on state-directed default service auctions. (See FERC Acts on PJM MOPR Filing.)

Lu said FERC largely accepted PJM’s definition of a state subsidy, which included carve-outs for state default procurement auctions and for programs like the Regional Greenhouse Gas Initiative.

“We think this order results in a workably competitive outcome for the markets,” Lu said.

The RTO has little discretion to modify the compliance language directed by FERC, so PJM does not anticipate any additional stakeholder meetings to complete the filing, he said.

MOPR Order Highlights

FERC indicated in the order that the upcoming Base Residual Auction (BRA) date cannot be set until an order on the pending energy and ancillary services compliance filing is resolved, Lu said. That filing was made by PJM in August, he said, with the hope of getting a decision by FERC before the end of the year.

Because pre-auction activities are pegged off the BRA date, Lu said, no deadlines for them may yet be set. PJM is currently evaluating activities that may begin on a voluntary basis for capacity market sellers wishing to start the process early, Lu said. A review of the pre-auction activities will be held with stakeholders at the Market Implementation Committee meeting Nov. 5.

Lu pointed to FERC’s decision on the treatment of state default procurement auctions that have a renewable portfolio standard component. As long as they are competitive and nondiscriminatory and meet criteria outlined in the definition of state subsidy, Lu said, then they will not be deemed state subsidies.

But Lu called to attention a footnote in the order that reads, “While this order accepts the exemption that PJM has proposed, it does not constitute a ruling that any particular state-directed default service auction actually meets these requirements.” FERC used New Jersey’s auction as an example of an auction that would not meet its requirements. Commissioner Richard Glick highlighted this in his dissent, saying that New Jersey’s and other state default procurement auctions that have an RPS component may be deemed by FERC to be a subsidy.

PJM is taking “a little bit of a different view” of the footnote, Lu said. The RTO believes the footnote is “meant as a cautionary tale” to warn New Jersey and other states not to change existing default state procurement auction rules in a way that would allow new renewable resources to escape the MOPR though the limited carve-out, he said.

The RTO is currently working with the Independent Market Monitor and will provide “guidance to all stakeholders” on how the existing state default procurement auctions in the footprint will be treated for the upcoming BRA, Lu said.

He also highlighted the scope of an exemption for incentives designed to promote “general industrial development in an area.” He said the commission rejected a request by a party in the docket to “explicitly include entire electric generation resources” that may have benefited from some sort of industrial development.

FERC ruled that general pollution-control equipment should still be exempt from the definition of a state subsidy, while state programs like tax exemptions for standalone renewable facilities are not exempt and would be deemed a capacity resource with state subsidies.

Lu used as an example a law in Virginia that exempts property taxes for certain pollution control equipment and facilities. He said the definition of pollution-control equipment in Virginia includes entire solar facilities that would also be exempt from property taxes, thereby making it a state subsidy.

Stakeholder Questions

Ken Foladare of Tangibl asked why PJM specifically highlighted renewable facilities in its presentation as generation resources benefiting from state subsidies. He said there are similar laws in other states benefiting natural gas- and coal-fired power plants, along with nuclear plants.

He pointed to a Kentucky law that says a company that owns and operates a coal-fired plant may be entitled to an incentive tax credit. He said almost every generation project he worked on had some sort of state or local tax incentive specifically designed for the generation facility being constructed.

“If you’re going to be singling out solar, you’re going to have to be singling out everybody,” Foladare said. “And pretty much every plant in PJM is going to be subject to MOPR.”

Paul Sotkiewicz of E-Cubed Policy Associates asked what happens to the timing of a BRA if PJM and the Monitor cannot agree on state subsidy cases or if a market participant disagrees with a decision and appeals to FERC instead.

PJM — Paul Sotkiewicz, E-Cubed Policy Associates | © *RTO Insider*

Lu said it is ultimately a capacity market seller’s responsibility to certify if there is a subsidy or not, and FERC has already approved Tariff language describing how market sellers can challenge decisions.

Sotkiewicz said he views the process as being “thrown back on the market participant” to take the litigation and enforcement risk and ultimately dragged through a process that may vindicate their challenge in the end. He said it also “drags the entire market through a mess” where stakeholders are not sure what to believe in the market results.

PJM Monitor Joe Bowring | © *RTO Insider*

“The more definitive we can be on this, the better off we are,” Sotkiewicz said. “And this is not necessarily PJM’s doing. The way FERC came down with this is a major part of the problem.”

Monitor Joe Bowring said he recognizes there is still uncertainty surrounding the MOPR. He said his and PJM’s goal is not to add any additional uncertainty in the process.

“We are making every effort to work closely with PJM to try to ensure we come to an agreement, make rational decisions and do it far enough ahead of time to minimize risk,” Bowring said.

October 30, 2020

MISO: Tx Beats Storage in Integrating Renewables

MISO’s shift to renewable resources can be supported by energy storage devices — but only to a small degree, the RTO said Tuesday.

The final results from MISO’s Renewable Integration Impact Assessment (RIIA) show that transmission is still key to economically using an expanding renewable fleet, though strategically placed energy storage can help.

“Storage, without adequate transmission capacity in the system, may help increase renewable energy delivery but may not sufficiently aid in meeting renewable penetration targets,” MISO Manager of Policy Studies Jordan Bakke told stakeholders during a special teleconference.

After running the RIIA with storage considerations, MISO found that transmission — not energy storage — remains most effective at delivering a hypothetical 40% renewable share of the resource mix under four study scenarios. However, the RTO said transmission buildout with select storage additions seems to be the most effective way to meet renewable energy goals and “may achieve the best overall value.”

Previous results from the RIIA have excluded the role of energy storage expansion, which some stakeholders say is a key consideration in the transition to a primarily renewable generation fleet.

MISO has previously said it can likely operate its system reliably with renewable penetration targets up to 50%, but only if its members engage in dramatic transmission expansion. (See MISO Renewable Study Shows More Tx, Tech Needed.) MISO currently operates with about 8% renewables.

“What we found with wind [and] solar generation, the complexity or challenges that that grid faces increases exponentially beyond 30% [penetration]. … Existing infrastructure becomes inadequate for fully accessing the diverse resources across the MISO footprint. What you need is to change how the grid operates,” Bakke said.

MISO Senior Policy Studies Planner Chen-Hao Tsai said storage alone cannot unlock delivery of a hypothetical 96 GW of renewables every hour of the year.

“Beyond 30%, we still need some substantial transmission solutions,” Tsai said, adding the transmission need remains the strongest to deliver wind generation from the northern portion of the footprint to load centers.

But MISO said an “optimum” amount of storage can help flatten its load curve and spread out an increasingly narrow loss-of-load risk.

The RTO previously found that as renewable generation grows, its daily loss-of-load risk compresses into a steeper and shorter period later in the evening. (See MISO Renewable Study Predicts Later Peak, Narrower LOLE Risk.)

“It will help move that availability around,” Bakke said. Storage resources can concentrate charge and discharge times depending on whether reliability risk is high or low, he said, but they are only available for so long, especially batteries.

When MISO offered both transmission and storage as solution candidates in its study simulation, its algorithm chose to build only a modest 0.5 GW of battery storage. When it ordered its algorithm to only select storage solutions to access the 40% renewable energy mix and not transmission, the simulation added 16 GW of storage footprint-wide at a cost of billions of dollars.

Stakeholders seemed taken aback that MISO’s optimal simulation would recommend such a small amount of storage.

Bakke said the study focused narrowly on how storage can aid renewable energy delivery and adequacy across all operating hours of the year.

“Much of the storage being added now is for planned power plant optimization. It has little to nothing to do with the grid,” Bakke said. “A lot of the planned hybrids today are around plant optimization, not grid optimization.” Storage is also being built to provide ancillary services, something else the renewable integration study did not cover, he said.

Bakke said the storage phase of the RIIA only sought “general truths” about its role in enabling renewable growth and was not designed to favor transmission buildout.

“There is a saturation point after which incremental storage isn’t helpful anymore and the effective load-carrying capability of renewables doesn’t increase,” MISO Policy Studies Senior Engineer Nihal Mohan said. “The results somewhat surprised us. … If we keep on adding more and more storage on the system, we start to see a decline of ELCC on the system.”

Mohan said CAISO has documented a similar trend of diminishing returns of storage after a certain point.

MISO also found that storage devices are more helpful when they are placed next to renewable generation, not load centers.

“When you co-locate storage at generation, it’s kind of like you’re putting a little reservoir near your generation. If you pair storage near the load — if you do not try to solve the transmission issue — there is still renewable curtailment,” Tsai said.

The results are the final leg of the yearslong RIIA. Bakke said MISO’s next order of business on the study is to summarize all study findings into a comprehensive report for stakeholders. He said the report should be completed by the first quarter of 2021.

October 30, 2020

Md., NC, Va. to Team up on Offshore Wind

The governors of Maryland, North Carolina and Virginia said Thursday they will collaborate to promote their states as a hub for the offshore wind industry.

The Southeast and Mid-Atlantic Regional Transformative Partnership for Offshore Wind Energy Resources (SMART-POWER) will seek to increase regulatory certainty, encourage manufacturing of components, reduce project costs through supply chain development and share best practices.

OSW can “drive economic development and job creation as well as reduce the emission of greenhouse gases and other harmful air pollutants,” the group said in a press release, citing Department of Energy estimates that the Atlantic Coast OSW project pipeline could support 86,000 jobs, $57 billion in investments and generate up to $25 billion in economic output by 2030.

Virginia (5.2 GW) and Maryland (1.2 GW) have pledged to build 6.4 of the 29.1 GW in OSW capacity targeted by East Coast states.

Offshore wind — PJM has five coastal states that could develop offshore wind: New Jersey, Delaware, Maryland, Virginia and North Carolina. | *BOEM*

North Carolina has not made any commitments, although it issued a request for proposals this summer for a supply chain and infrastructure assessment that will include identification of necessary port upgrades in Wilmington and Morehead City.

North Carolina’s Clean Energy Plan notes that Avangrid Renewables is developing the Kitty Hawk Wind Energy Area, 24 nautical miles from Corolla, which the company says has capacity for 2.5 GW. The plan, issued in October 2019, followed Gov. Roy Cooper’s (D) 2018 executive order calling for GHG reductions of 40% from 2005 levels by 2025.

Cooper said the three-state agreement “allows us to leverage our combined economic power and ideas to achieve cost-effective success.”

Virginia Gov. Ralph Northam (D) said OSW will be “key to meeting the urgency of the climate crisis and achieving 100% clean energy by 2050.”

The states’ memorandum of understanding says they will coordinate to use their assets “such as deepwater ports and transportation infrastructure, top-tier universities and research institutions, and highly trained workforces to support the offshore wind industry and supply chain to efficiently develop along the Atlantic Coast.”

The states will create a leadership team of representatives from each state that will meet at least quarterly and report to the governors annually on their “activities, progress and future strategies.”

The MOU also says the states will seek to reduce administrative burdens on the industry “by clarifying, streamlining and aligning, where appropriate, state regulatory requirements” for construction of OSW projects.

They also will share best practices about regulatory processes, military compatibility, environmental protection, workforce training, public engagement, competing uses, and community and stakeholder interests, including those of fishermen and boaters.

The states also pledged to coordinate their communications with the U.S. departments of Commerce, Defense, Homeland Security and the Interior.

“An alliance between Maryland, North Carolina and Virginia balances offshore wind economic development more evenly across the East Coast,” said Liz Burdock, CEO of the Business Network for Offshore Wind. “The market is now too dynamic and requires such large-scale collaboration that no one state should go it alone; regional cooperation is a must as the industry begins a multibillion dollar buildout over the next decade.”

Laura Morton, the American Wind Energy Association’s senior director of policy and regulatory affairs for OSW, praised the agreement.

“By adding multistate coordination to their individual efforts, the three states will be able to move forward more efficiently to develop their infrastructure and local supply chains to unleash this brand new American energy industry and the jobs and investments that come with it,” she said.

October 30, 2020

WECC Members Seek More Time, Input on SETF Plan

Stakeholders voiced concern Wednesday that WECC will move too fast and cut too deep with a plan to sweepingly reform its stakeholder committee structure, while company officials attempted to assure them that the proposal is only meant to launch an “iterative” process that will rely heavily on member input.

WECC’s Stakeholder Engagement Task Force (SETF) on Oct. 19 issued a straw proposal that would consolidate or replace most of the regional entity’s standing committees while eliminating subcommittees not actively engaged in vital work projects. (See Plan Would Consolidate, Cull WECC Stakeholder Groups.)

Stakeholder comments on the proposal are due by Nov. 2, with the SETF presenting a progress report to the WECC Board of Directors during its December meeting.

“The process is just basically too short. The details of the proposal you’ve provided don’t really present the members time to be able to come up with some really good suggestions, as you were requesting,” Charles Faust, real-time merchant manager at the Western Area Power Administration and chair of WECC’s Market Interface Committee (MIC), said during a call to discuss the proposal Wednesday.

Faust was speaking on behalf of members of the MIC, which is on the chopping block under the plan, along with WECC’s Operating Committee. The functions of both committees would effectively be combined into a new Operations, Security and Market Interface Committee (OSMIC). Among WECC’s existing standing committees, only the Reliability Assessment Committee (RAC) would remain because its work aligns with the RE’s long-term strategy and reliability risk priorities, the SETF said in its proposal.

Faust said MIC members feel their committee is “still relevant” and are concerned that their voices would be “diluted” under the proposed structure.

MIC members seek an extension of time to comment on the proposal, Faust said, or at least want WECC to solicit a second round of comments that will allow for more considered opinions after the SETF has provided more background on how it arrived at its proposal.

“I’m just wondering if it would be possible to take advantage of the work that was done by the team to provide the ideas and interpretations you had for the proposal to be shared so that the members and stakeholders would be able to glean from that some additional ideas and possibly put forth some recommendations, instead of just putting forth comment,” Faust said.

MIC members also have questions about a provision of the plan that calls for membership in both the OSMIC and the RAC to be limited to a fixed number of stakeholders with members serving staggered terms.

“What does limited membership look like?” Faust said, adding that MIC members want more specifics on that aspect of the plan, including actual numbers.

“By reducing the members, some feel you could be limiting the resources you could draw on,” he said.

The MIC also had doubts about the proposal’s plan to replace the Joint Guidance Committee with a new Performance Review Board responsible for establishing and monitoring performance and stakeholder metrics to gauge the output and effectiveness of standing committee projects.

“With the Performance Review Board reviewing everything, our concern is that could be a very heavy lift for them, and will they have time to fully address all the work from all the committees?” Faust said.

He noted that the new structure “could limit the ability of the exploration of issues” for an industry that is very “dynamic and in flux.”

“Not all issues need to develop work products. Sometimes it’s just a matter of exploring it to see if there is something there or not,” he said.

Faust also posed the question: “What is the structural problem that you’re trying to fix?”

‘A Little Vague’

Jordan White, WECC vice president for strategic engagement, said the SETF proposal attempts to address a problem identified by the working group charged with making periodic reviews of WECC’s governance and structure: “I think just the idea that … there was diminished participation from certain stakeholders.”

WECC SETF — WECC’s Jordan White addressing one of the organization’s last in-person meetings while still a member of the Utah Public Service Commission. | © *ERO Insider*

White said the working group found the standing committees generally suffered from a “lack of direction” despite the “incredible amount of potential” among their members.

“The end-state of where we want to be is this robust, agile, really engaged group where people are really focusing on working on problems,” White said, adding that the straw proposal is really intended to determine what “vehicle” WECC needs to arrive at that goal.

White acknowledged that the SETF is still not clear on what it will present to the board in December; it could include stakeholder comments or an “overarching principle” around how to proceed.

“We don’t have the process all buttoned up now. … It’s going to be iterative,” said Victoria Ravenscroft, WECC’s senior policy and external affairs manager. It would not serve WECC to be “draconian” about the proposal, she said. “We get that the [comments] time is short, but really we see this as the opening of a conversation.”

The only timeline the board provided is that the SETF provide “preliminary findings” around the committee restructuring in December, she said. “It is a little vague,” she added.

“I really appreciate the vagueness of the board directive. … I think WECC should take advantage of that,” said Lorissa Jones-Cardoza, transmission reliability program manager at the Bonneville Power Administration and a member of WECC’s Member Advisory Committee. She pointed out that it took WECC stakeholders more than a year to evaluate the restructuring of the RAC.

“Allowing MIC and the OC two weeks to come up with this proposal is really, I believe, a big disservice to WECC and the stakeholders and the products that are produced,” she said.

“In terms of WECC staff, we take this very seriously and wouldn’t do something to alienate our partners in this,” Ravenscroft replied.

Casey Johnston, director of grid operations for Montana-based Northwestern Energy, said the perspective of the OC has been valuable to his small investor-owned utility that covers a “very large geographic area.”

“The fact is that I have the ability to go to the OC meetings and I can participate, I can comment … and it seems like when [it has] a limited role [within the OSMIC], I would lose that. It would be limited representation,” Johnston said.

He also questioned the lack of representation of “operational folks” on the SETF, which is heavily populated by regulators and industry legal personnel.

“That’s something that I guess struck me when I went through the members,” he said. “They’re all very qualified; they’re all very knowledgeable, but there seems to be some knowledge and experience and perspective missing from some of the other stakeholder groups.

“It’s too late now, but going forward, I really think you need to get some more operational, maybe some merchant folks, involved in the process,” Johnston said.