FERC last week approved Southwestern Public Service Co.’s request to terminate its obligation to enter into new power purchase contracts with qualifying cogeneration or small power-production facilities (QFs) with a net capacity greater than 20 MW (QM19-4).
The commission found that QFs greater than 20 MW within SPS’ service territory enjoy nondiscriminatory access to sell capacity and energy into wholesale markets, in this case, SPP’s Integrated Marketplace. FERC based its Jan. 31 decision on a 2008 order that determined SPP’s markets satisfy the requirement of the Public Utility Regulatory Polices Act of 1978 (PURPA) to give QFs nondiscriminatory access to a market.
Construction crews work on an SPS substation in New Mexico. | Xcel Energy
FERC’s Order 688 in 2006 found that the nation’s commission-approved wholesale energy markets meet PURPA’s criteria for relief from the purchase obligation. It also established a rebuttable presumption that QFs greater than 20 MW have nondiscriminatory access to those markets.
The commission rejected complaints from renewable developers GlidePath Development and Leeward Renewable Energy that transmission constraints that existed in 2008 still persist today. SPS told FERC that it has invested $2.1 billion in transmission facilities subject to SPP’s Tariff and that the RTO’s transmission-owning members have invested $8.3 billion in facilities subject to the Tariff.
Xcel Energy filed the request with FERC on Sept. 5, 2019, on behalf of SPS, its subsidiary, and fellow SPP TO members Oklahoma Gas & Electric, Public Service Co. of Oklahoma and Southwestern Electric Power Co. The order is effective on that date.
FERC on Monday rejected a solar aggregator’s request for a waiver to offer 14 distributed energy resources into ISO-NE’s 2020 Forward Capacity Auction despite a dispute over the projects’ interconnection status (ER20-366).
Genbright had asked FERC to allow its seven solar PV generating facilities and seven storage facilities to participate in FCA14, which opened Monday.
ISO-NE rejected their participation because the developers had failed to file interconnection requests with the RTO.
Genbright said it believed it had met the interconnection requirement by applying to Eversource Energy under the utility’s Massachusetts-approved tariff.
But ISO-NE said the company should have filed interconnection requests under the RTO’s Tariff because the point of interconnection is under FERC jurisdiction.
Genbright, which was acquired by ENGIE North America last May, said ISO-NE’s FCA 14 training material required a valid interconnection request “regardless of the jurisdictional status of the project’s proposed interconnection.”
ENGIE solar farm | ENGIE North America
Genbright contended that the seven PV generators should not be subject to FERC jurisdiction because it will sell all its output to Eversource as a qualifying facility participating in the Solar Massachusetts Renewable Target.
It said “at least three, and perhaps all seven” of the storage facilities also are not subject to the RTO’s interconnection process.
Genbright said Eversource erroneously stated that the distribution line into which each project is interconnecting is subject to FERC jurisdiction because there is a pre-existing QF on the distribution line registered with ISO-NE as a settlement-only generator.
Genbright said neither Eversource nor ISO-NE informed it that Genbright had filed incorrect interconnection requests even though Eversource knew that the projects intended to participate in the RTO’s market.
Eversource and ISO-NE both opposed the waiver request.
Eversource said Genbright was asking for a substantive legal ruling on what causes a distribution-level interconnection to fall under commission jurisdiction rather than merely the correction of a one-time error. It said the company should have sought a declaratory order or rulemaking.
“If Genbright’s views on jurisdiction were correct, they would have far-reaching impacts on auction eligibility, jurisdiction over existing interconnection agreements and the appropriate queue for yet-to-be interconnected generators,” Eversource said.
ISO-NE said it welcomes DER in its markets. “Genbright’s resources, like any other eligible resources in New England, may fully participate in the ISO’s markets, but they must do so in accordance with the same rules that apply to all resources,” the RTO said. “The petition, however, seeks an arbitrary exemption from the Tariff on behalf of Genbright’s projects, an exemption Genbright simply has not justified.”
In denying the request, FERC said Genbright had failed to show the request was limited in scope. “Genbright’s requested waiver would allow the projects to avoid ISO-NE’s complex interconnection study process, including the system impact study, which is ISO-NE’s comprehensive reliability evaluation.”
Results of FCA 14 are expected as early as Wednesday.
The federal judge in charge of Pacific Gas and Electric’s Chapter 11 reorganization set a timeline for it to exit bankruptcy Tuesday and approved its recent agreement with the bondholders that had been trying to take over the state’s largest utility.
Judge Dennis Montali | Commercial Law League of America
“I’m going to issue the order that … approves the [restructuring agreement with bondholders],” Montali told lawyers in the U.S. Bankruptcy Court in San Francisco. He did so despite a lone objection from wildfire survivor William Abrams, who represented himself in court and insisted that PG&E’s reorganization plan should include safety reforms.
“They are here for their short-term payouts,” Abrams said of the bondholders and other parties that have settled with PG&E. Abrams said he was looking at the long-term consequences of the restructuring agreement.
Thousands of other fire victims, represented by the case’s official Tort Claimants Committee, have agreed to a settlement with PG&E that would fund a $13.5 billion trust to pay them and government agencies that incurred costs from wildfires started by PG&E equipment in 2015, 2017 and 2018.
The catastrophic blazes included the Camp Fire, which killed 86 people and destroyed 18,804 structures in Paradise, Calif., in November 2018. And even though it denies liability, PG&E agreed to settle claims from the Tubbs Fire, which killed 22 residents and burned 5,636 structures in Napa and Sonoma counties in October 2017.
The bondholders, led by several powerful East Coast hedge funds, had offered their own reorganization plan that proposed injecting billions of dollars in cash while wiping out the equity of PG&E’s current shareholders and seizing control of the utility. The group settled with PG&E in January in exchange for the utility agreeing to pay some of its notes and to renegotiate others. (See PG&E Settles with Bondholders; Governor Objects.)
PG&E has also settled with insurance companies and other holders of subrogation claims for $11 billion and with local governments for $1 billion.
With all major stakeholder groups in agreement, Montali set a schedule Tuesday for confirmation proceedings to weigh and rule on PG&E’s plan. The process is set to begin this week with the utility filing disclosure statements that describe its plan in language the public can more easily understand. Those affected by the bankruptcy, including fire victims, will then have an opportunity to comment on and object to the disclosures.
Montali scheduled a hearing on the disclosures for March 10 and set May 27 as the start of PG&E’s confirmation hearing.
The California Public Utilities Commission must also approve PG&E’s bankruptcy plan. It opened a formal proceeding in September and scheduled evidentiary hearings starting Feb. 19 at its headquarters in San Francisco. The commission is charged with determining if the utility’s proposals meet the safety requirements of Assembly Bill 1054, a measure that creates a $21 billion wildfire insurance fund for utilities that qualify.
PG&E must exit bankruptcy by June 30 to participate in the wildfire fund.
Gov. Gavin Newsom has said that PG&E hasn’t met the requirements of AB 1054 and repeatedly threatened a state takeover of the troubled utility. Newsom remains the biggest opponent to PG&E’s reorganization plan.
Though he doesn’t have authority over the bankruptcy court, he may have sway with the CPUC. Newsom appointed the commission’s new chair, Marybel Batjer, in July, naming her at the signing ceremony for AB 1054.
PG&E recently offered a new reorganization plan that it said meets the requirements of AB 1054, but Newsom hasn’t said whether it goes far enough to satisfy his demands. (See PG&E Tries to Appease Governor with New Plan.)
SPP‘s Market Monitoring Unit said it is not looking to end self-commitment but that a reduction in the practice would result in a more efficient market.
“We do note that a high volume of make-whole payments [for self-commitments] is not considered desirable. It creates inefficiencies in the market,” Monitor Executive Director Keith Collins said Monday during a webinar on a report it released in December on self-commitments.
Collins capitalized on the previous day’s Super Bowl to put the issue into terms that might make more sense to his audience. “Imagine your favorite sports team, and imagine it’s the players who decide will play, rather than the coach,” he said. “The outcome you get may not be as efficient as the coach optimizing that for you.”
In the report, “Self-committing in SPP markets: Overview, impacts, and recommendations,” the Monitor recommends SPP and stakeholders work to reduce the number of self-commitments to improve price formation and market efficiency. The Monitor also suggests SPP modify its market design by adding another day to the market optimization period.
MW dispatched by commitments, self-commit MWs by fuel type | SPP MMU
The report says a smaller distortion of prices and investment signals “will likely help market participants make better short-run and long-run decisions, which tends to coincide with improved profit maximization.
“Enhanced profit maximization, combined with effective regulation and monitoring, will likely lead to ratepayer benefits in the form of cost reduction,” the Monitor said.
Monitor staff studied offer behavior from March 2014, when SPP’s day-ahead Integrated Marketplace went live, to August 2019. They re-solved past market cases by running two simulation series of a week per month from September 2018 to August 2019, assuming all generation was offered in market status and that it could be started economically by the day-ahead market.
The analysis found that:
The volume of self-committed MW has declined over time but remains nearly half of the total MW volume generated during the study’s time frame.
Prices and production costs were systematically lower when at least one self-committed unit was on the margin.
In almost all cases, self-committed generators had lower revenues because of negative congestion prices. Market-committed generators typically had a more balanced congestion profile.
Resources with long lead times and/or high start-up costs tended to be self-committed instead of market-committed.
Self-committed units generally had much higher capacity factors than those that are market-committed. The largest portion of self-committed dispatch MW were from coal units, exceeding the second-largest fuel type by a 4-to-1 ratio.
In its simulations, the Monitor found that:
When the market made unit commitment decisions and lead times were unchanged, both market-wide production costs and market-clearing prices for energy increased.
When the market made unit commitment decisions and lead times were modified to allow the day-ahead market to commit the resources with long lead times, market-wide production costs were essentially unchanged and market-clearing prices for energy increased about 7% ($2/MWh) on average. Congestion prices fluctuated from -$1/MWh to $1/MWh on average.
Having the economic commitment process solve over a two-day period rather than one would optimize long-lead time resources’ participation in the market, the report says.
“Simply eliminating self-commitment without any additional changes could result in an increase in total production costs,” the report warns. “However, when lead times were shortened to reflect an additional day in the market optimization and self-commitment was eliminated, producers were paid more and production costs declined.”
The Monitor is taking its presentation on the road. Having already shared its recommendations with the Market Working Group, it also plans to meet with the Cost Allocation Working Group.
“We’ll be speaking in different committees and venues,” Collins said.
Transmission owner GridLiance Heartland has gained access to the MISO system through an acquisition of transmission lines in Illinois and Kentucky after an unsuccessful first attempt to join the RTO.
In a trio of orders Jan. 31, FERC conditionally approved GridLiance Heartland’s acquisition of eight transmission assets from Vistra Energy subsidiary Electric Energy Inc. (EEI) (EC20-13), set an annual transmission revenue requirement at about $7.4 million (ER19-2050-002) and OK’d a separate open access transmission tariff (OATT) for the two lines that won’t be under MISO functional control immediately (ER19-2092, et al.).
The third order also established settlement judge proceedings to examine the reasonableness of GridLiance Heartland proposing the MISO base return on equity in the OATT for non-MISO assets. GridLiance proposed a 10.32% ROE for the OATT, the ROE rate in use in MISO at the time of its filing in December 2018. FERC in late November adopted a new 9.88% return on equity for transmission owners. (See FERC Adopts ROE Methodology in MISO Complaints.)
The deal involves two 161-kV substations and six 161-kV transmission lines 8-10 miles in length that cross the Ohio River and connect to the EEI-owned Joppa Power Plant in southern Illinois. Vistra owns an 80% interest in EEI, with Kentucky Utilities controlling the remaining 20%. The assets are currently outside the MISO footprint. GridLiance said it would transfer all assets to MISO control by 2022: Four of the six lines will be turned over immediately to MISO, while two must wait for existing power supply agreements to run their course.
The six lines were originally constructed to power the U.S. Department of Energy’s now-defunct Paducah Gaseous DiffusionPlant uranium facility. EEI reconfigured its transmission system to disconnect from the Paducah plant in 2017. Four of the lines connect with TVA, while the other two connect with the Louisville Gas & Electric/Kentucky Utilities balancing authority area. The lines currently don’t serve any load.
Paducah Gaseous Diffusion Plant | U.S. Department of Energy
MISO’s Board of Directors approved GridLiance Heartland’s application to join the RTO as a transmission-owning member in September 2018 subject to the outcome of the proposed transaction.
FERC had blocked the transaction in August, deciding GridLiance and EEI failed to prove the acquisition wouldn’t adversely affect MISO rates. (See FERC Blocks GridLiance’s Door intoMISO.) The move will increase revenue requirements in the Ameren Illinois transmission pricing zone by about 2.6%.
GridLiance proposed rate mitigation credits to offset the $3.6-million difference between the projected revenue requirements of EEI and itself. The TO said the credits would appear in accounting as a fixed revenue credit and lower its revenue requirement every year for the five years after MISO takes control of the lines.
GridLiance said the credits “balance the risks and rewards for a start-up transco with a small initial rate base.” It also noted that it plans to participate in “proactive” planning studies on how the lines “may be optimized to solve documented transmission constraints.” The company said the lines may prove useful in lessening the strain on the transfer constraint linking MISO’s Midwest and South subregions.
GridLiance also noted that as a MISO member, it could help address “underinvestment” in transmission by MISO’s municipal and cooperative utilities.
Ameren Objects
The commission approved the deal over multiple objections from Ameren.
Ameren faulted GridLiance for using estimated, “snapshot in time” revenue requirements for its rate credits rather than actual amounts. It also said the commission was failing to consider that GridLiance would seek recovery of its $23.6 million regulatory asset that FERC approved last year. Ameren asked that FERC create further protections from the impact of GridLiance’s regulatory asset costs.
The company also said GridLiance’s claims of future benefits to MISO or the Ameren pricing zone were “tenuous.”
But FERC said GridLiance’s rate mitigation proposal addressed its concerns over the rate increase. The commission also said GridLiance Heartland is not to recover any amounts related to its regulatory asset during the first five-year rate mitigation.
“The regulatory asset is related to past development activities by GridLiance Heartland and not to costs that [EEI] would have incurred if it had retained ownership,” FERC warned.
FERC accepted GridLiance’s unorthodox rate mitigation proposal instead of the more commonplace five-year rate freeze based on the company’s assertation that forces out of its control could have increased even EEI’s revenue requirement, such as storm damage, or a new NERC requirement.
Ameren also protested the use of a stand-alone OATT for the non-MISO lines, saying it represented a “step backward in terms of the efficiencies created by having an RTO footprint.”
“We are not persuaded by Ameren’s argument that this proposal is a step backwards because GridLiance Heartland is eschewing the efficiencies of an RTO footprint. RTO participation is not mandatory and Order No. 888 requires that an OATT be on file in order to provide transmission service,” FERC responded.
GridLiance said it also plans to use the OATT to provide transmission service over “any future facilities it acquires in the MISO region but does not transfer to MISO’s functional control.”
FERC granted a one-time waiver of Order 1000’s competition requirements for the OATT. The commission said since GridLiance is proposing to transfer control of the lines and substations to MISO, it afforded no “practicable opportunity” for the TO to adhere to Order 1000. The commission noted the “unique circumstances” present in the transaction and said the waiver would be reassessed if GridLiance decides to build additional facilities under the same OATT.
FERC approved an agreement that will allow the Transmission Agency of Northern California (TANC) to convert capacity on a key transmission line into “option” congestion revenue rights in the CAISO market (ER20-398).
The agreement covers use of TANC’s California-Oregon Transmission Project (COTP), a 340-mile, 500-kV line capable of delivering up to 1,600 MW of energy from Southern Oregon into Northern California. The line is jointly owned by the Western Area Power Administration and members of the Balancing Authority of Northern California (BANC), the BA for a handful of publicly owned California utilities located outside CAISO’s territory, including Sacramento Municipal Utility District.
Completed in 1993, the COTP was built to parallel the older Pacific AC Intertie (PACI). Together the lines comprise the California-Oregon Intertie (COI), a 4,800-MW transmission corridor linking Northern California with the hydro- and wind-rich Pacific Northwest. In 2013, PacifiCorp executed a similar CRR agreement with CAISO over use of the PACI portion of the COI, which CAISO manages as transmission operator.
The new agreement grants TANC access to “option” CRRs, a financial instrument that enables its holder to collect a positive revenue stream for allowing use of transmission capacity. The more common “obligation” CRRs come with risks, namely that they can provide holders with either a positive or negative revenue stream depending on the congestion pattern on a line.
Dual Circuit 500kV power lines
The agreement stipulates that TANC will notify CAISO 30 days ahead of each calendar month regarding the volume of COTP transmission capacity the agency will release for conversion to the special type of CRRs. Capacity will be released on a directional basis (either north-to-south or south-to-north). CAISO will then issue TANC option CRRs that will source and sink at either Bonneville Power Administration’s Captain Jack substation or the Tracy 500-kV CAISO scheduling point, depending on the direction of the release.
The ISO will settle TANC’s CRRs as option CRR payments for intervals when the day-ahead market shows a congestion price difference between the source and sink, but payments will not be issued for real-time congestion. TANC capacity not converted to CRRs will remain as transactions subject to TANC’s transmission tariff.
CAISO’s Nov. 18 filing touted the broad benefits of the agreement for its market participants.
“To the extent that TANC releases portions of the TANC capacity on the COTP for use by the CAISO, the ability of CAISO market participants to schedule transactions on the COI will increase and the CAISO will be able to address congestion more efficiently and reliably,” CAISO wrote. “The agreement provides CAISO market participants more transfer capability from the Pacific Northwest and an alternate path to the PACI. This is a more efficient outcome that increases flexibility.”
CAISO also said the agreement would not affect the financial position of existing CRR holders.
“The total amount of capacity that potentially could become TANC CRRs is equal to the total amount of capacity reserved for the TANC capacity. The agreement simply makes the available capacity easier to use by the entire CAISO market,” the ISO said.
PG&E Concerns Rebuffed
In approving the agreement on Jan. 31, FERC dismissed the concerns of Pacific Gas and Electric, which acknowledged the benefits for CAISO participants, while also contending that the monthly nature of the agreement differed from that of the deal with PacifiCorp and could incentivize TANC to release capacity in a manner that will maximize its own financial benefit.
The commission found no “meaningful distinction” between the TANC and PacifiCorp agreements despite that difference.
“As CAISO notes, the agreement provides an incentive to TANC to release transmission capacity during months when congestion revenue rights are most valuable, and it is during these months that the transmission capacity has the greatest potential to benefit market participants,” the commission said. “Further, TANC must commit to the capacity being released for the entire period.”
FERC also rebuffed PG&E’s argument that the agreement is predicated on modeling transmission capacity in a way that would effectively give priority to TANC to elect its CRR allocation before other participants in the normal election process. The commission noted that the agreement’s modeling of CRR options is consistent with how CAISO models options in the PacifiCorp agreement.
The commission additionally rejected PG&E’s request that the TANC agreement be limited to a two-year term and declined the utility’s recommendation for annual reporting to FERC.
“In light of the information on released transmission capacity available through CAISO’s OASIS, we find no need for CAISO to file similar information with the commission,” FERC concluded.
House Democrats last week released a draft bill that received attention for its ambition to set a national clean electricity standard, requiring utilities to get 100% of their power from net-zero-emission resources by 2050.
But tucked away in the 622-page draft Climate Leadership and Environmental Action for our Nation’s (CLEAN) Future Act is a provision making it mandatary for utilities to join an ISO or RTO.
Section 217c of the bill (page 91) would amend Section 202a of the Federal Power Act, which gave FERC the power to approve RTOs, by removing the word “voluntary” and adding: “The commission shall require each public utility to place its transmission facilities under the control of an ISO or an RTO not later than two years after the date of enactment of the CLEAN Future Act.”
The provision is part of a larger series of desired changes at FERC, reading as a wish list for Democrats and the agency’s critics.
Rep. Frank Pallone (D-N.J.), chair of the House Energy and Commerce Committee, announced the framework for what would become the CLEAN Future Act on Jan. 17. | Frank Pallone
The bill would create an Office of Public Participation and Consumer Advocacy at FERC; clarify that the commission must consider climate change in its environmental assessments of natural gas pipelines; prevent pipeline companies from using eminent domain until they have obtained all necessary federal and state permits; and allow the commission to approve carbon pricing regimes for wholesale power.
Perhaps as, if not more, significant than the RTO provision is a directive that would require FERC to conduct a rulemaking to increase the effectiveness of interregional transmission planning. Section 212 of the bill spells out what exactly this would entail, directing the commission to emphasize that “interregional benefit analyses made between multiple regions should not be subject to reassessment by a single regional entity” and “the elimination of arbitrary voltage, size or cost requirements for an interregional transmission solution,” among other requirements.
The bill would also require FERC to submit a report on its efforts to encourage deployment of technologies that increase transmission efficiency, such as dynamic line ratings.
Clean Energy Credits
The draft bill is an ambitious, sweeping plan to dramatically reduce the country’s emissions and address global climate change that includes requirements for states, FERC, EPA and the Department of Energy, and targets emission reductions from the grid, vehicles and buildings.
The core provision of the bill would require utilities to begin transitioning to net-zero-emission electricity in 2022, giving them 28 years to reach 100%.
This would be facilitated by a clean energy credit trading program, established by DOE, that would function similar to existing state renewable energy credit programs, but the department would dole out credits to generators based on their carbon intensity, not on their resource type. Non-emitting resources would receive credits equal to the amount of megawatt-hours they sell. Generators that emit less than 0.82 metric tons of CO2/MWh would be eligible for credits based on how far below the threshold they are, incentivizing their owners to clean them up.
Utilities would then be required to purchase credits from generators and submit a certain amount, increasing each year, to the department. Utilities that fail to submit enough credits would be subject to a penalty.
While the overall bill drew praise from environmental groups, their reaction to the credit trading program was mixed.
“This broad legislative package includes some policies that would be clear steps forward to address the climate crisis, but it’s concerning that on what is perhaps the central question of climate policy — what counts as clean energy — this bill includes options that could leave a door open to gas and coal,” the Sierra Club said.
The criticism from environmentalists could mean the bill would face some pushback from the more liberal wing of the party, which has supported more aggressive decarbonization plans such as the Green New Deal.
“The legislation includes a national clean energy standard that could be transformational if designed well,” said Rob Cowin, director of government affairs for the Union of Concerned Scientists’ Climate and Energy program. “A national clean energy standard must not increase our reliance on natural gas generation, as natural gas use economywide now contributes more to U.S. carbon emissions than coal. We will continue to work towards enacting legislation consistent with the science and that will provide a just and equitable transition to a clean energy economy.”
“This credit system would encourage emissions reductions through changes in dispatch or investments at a facility, consequently further reducing emissions and lowering costs by allowing low-carbon technologies to participate,” nonprofit Resources for the Future said in a brief on clean energy standard published a year ago.
“The provision of credits to clean resources will likely create an incentive to expand energy supply and consequently lead to lower wholesale market prices. This effect notably differs from that of a carbon price, which would likely raise wholesale prices,” RFF said. “The extent to which decreased wholesale market prices will lead to lower retail prices could vary with the policy target but would be especially likely when customers are served by a vertically integrated utility that generates more clean energy credits than it needs to comply with the standard.”
It is unclear if Democrats intend to introduce the bill this year given its assured death in the Republican-controlled Senate and the upcoming elections. In its press release announcing the draft, the House Energy and Commerce Committee only said that “as it continues to expand and refine” the draft, “hearings and stakeholder meetings will continue throughout the coming year.”
“The CLEAN Future Act treats this climate crisis like the emergency that it is, while also setting the foundation for strengthening our economy and creating good paying jobs for a clean and climate-resilient future,” committee leaders said. “We look forward to continuing to work with all impacted stakeholders on this proposal in the coming months.”
Republicans are also planning to release their own bills to address climate change, as soon as this week. The package aims to boost research and development funding in nuclear energy and carbon capture, as well as increase tree planting. Legislation being drafted by Rep. Bruce Westerman (R-Ark.) would commit the U.S. to planting some 3.3 billion trees each year over the next 30 years.
The California Public Utilities Commission issued proposed guidelines Thursday for utilities to follow in the 2020 fire season when intentionally blacking out areas to prevent electrical equipment from starting wildfires.
At the same time, CPUC President Marybel Batjer issued a ruling calling Pacific Gas and Electric’s reporting to the commission on its public safety power shutoffs (PSPS) “fundamentally inadequate” in detail and substance and ordering it to immediately fix the situation.
CPUC President Marybel Batjer | California State Assembly
“PG&E’s performance during PSPS events in 2019 was unacceptable and cannot be repeated in 2020,” Batjer said in a statement. “The reports that I ordered PG&E to submit are part of the CPUC’s comprehensive review of the 2019 PSPS events.”
The proposed guidelines, issued for public comment, would require the state’s investor-owned utilities to restore power no more than 24 hours after the end of weather conditions that led to a safety shutoff. The IOUs would also have to convene monthly regional workshops with local governments and others on fire safety practices and to conduct PSPS exercises with public safety agencies in fire-prone areas.
The proposed PSPS guidelines would augment the guidelines established by the CPUC in a June decision (19-05-042).
PG&E was heavily criticized for failures in preparedness and communication when it blacked out 2.4 million residents in October. Officials, including Gov. Gavin Newsom and his appointee Batjer, have insisted the situation can’t reoccur. (See California Officials Hammer PG&E over Power Shutoffs.)
The utility is in bankruptcy following two years of catastrophic wildfires in 2017 and 2018 that killed dozens of people and destroyed thousands of structures. It mostly avoided a repeat of the past two fire seasons in 2019, but its decision to de-energize vast swaths of Northern and Central California for days at a time caused controversy.
Public safety power shutoffs were a major source of controversy for PG&E in 2019. | PG&E
CEO Bill Johnson told state lawmakers in November that the power shutoffs had prevented fires, though improvements were needed.
“Turning off power for safety is an effective tool and really only one of the many tools we are using,” Johnson said. “We will get better at using it.”
In her assigned commissioner’s ruling Thursday, Batjer said PG&E’s reports to the commission on the shutoffs last fall had “serious deficiencies” — and that the utility eventually stopped filing reports altogether in December because it unilaterally decided it had fulfilled its obligations to the CPUC.
The weekly reports were instituted in response to a letter Batjer wrote to Johnson on Oct. 14, citing serious “failures in execution” in the shutoffs and ordering corrective action. (See CPUC Orders Changes to PG&E Shutoff Rules.)
PG&E CEO Bill Johnson | California State Assembly
The reports initially took the form of letters from PG&E to Batjer, but an administrative law judge later formally incorporated the reports into the CPUC’s rulemaking on de-energization. Batjer’s ruling Thursday was part of that proceeding (18-12-005). In it she ordered PG&E to resume regular (biweekly) reports on its PSPS corrective actions and to provide the CPUC with a detailed plan in 15 days describing PG&E’s anticipated improvements and challenges regarding PSPS events in the fire season that starts this summer.
Within 45 days, the utility must update its PSPS protocols and be prepared to exercise the measures, without prior notice, in conjunction with the state Office of Emergency Services and the California Department of Forestry and Fire Prevention, Batjer said. She did not propose any penalties in her ruling.
“Based on the identified deficiencies in PG&E’s reporting on its post-PSPS corrective actions to date, I am directing further action to ensure that PG&E is adequately operationalizing the clear guidance we have provided and implementing corrective actions that will meaningfully mitigate the impact of any future PSPS,” the CPUC chair wrote.
The Texas Public Utility Commission last week declined to issue final orders in a pair of rate cases involving CenterPoint Energy and AEP Texas, but it did approve several other rate recoveries.
During an open meeting Friday that lasted less than half an hour, the PUC signed off on nearly $6.4 million in rate case expenses for Entergy Texas (48439) and Southwestern Electric Power Co.’s request to implement a net interim fuel refund of more than $15 million (49974).
Commissioners Shelly Botkin and Arthur D’Andrea proceed without Chair DeAnn Walker.
The commission also approved a $475,000 administrative penalty against EDF Energy Services for failing to reserve sufficient capacity to meet its responsive reserve service for 113 operating hours between March 27, 2016, and Dec. 28, 2017 (50304).
Finally, the PUC approved a $10,000 fine for Shell Energy North America related to over-procurement of ancillary services (50227).
Commissioner Arthur D’Andrea said the PUC will be intervening in a pair of FERC proceedings involving MISO:
Proposed Tariff revisions to expand, modify and clarify the identification and cost allocation of transmission facilities providing regional and local economic benefits to MISO customers (ER20-857, ER20-858, ER20-862).
A proposal to remove the exemption from physical withholding penalty charges for resources not categorized as planning resources (ER20-665, ER20-668, ER20-669).
Chairman DeAnn Walker missed the meeting with an undisclosed illness. D’Andrea chaired the meeting in her absence.
ISO-NE’s External Market Monitor last week presented the New England Power Pool Markets Committee a conceptual design for mitigating market power in the RTO’s day-ahead ancillary services market.
Monitor David Patton led off with a memo describing the advantages of the conduct-impact approach, a two-step process that uses reference levels to test both a participant’s conduct as it relates to a competitive norm and its impact on the market.
The first part of the test considers whether a unit’s offer exceeds its reference level by some pre-established threshold. If the threshold is exceeded, then a second part of the test determines whether the conduct (i.e., the offer) has caused an impact on the market clearing price for energy or ancillary services or affected an uplift payment.
“Our general recommendation is that the conduct-and-impact framework should be applied to the day-ahead ancillary products and should be effective at addressing the market power concerns,” Patton said.
“The nice thing about the conduct-and-impact mitigation framework is, if the market is very competitive, it will rarely if ever mitigate any offers, but the fact that it exists … actually does discipline the behavior of the suppliers of the products,” he said. “We think that this framework, regardless of the outcomes of the simulation analysis, will be effective to mitigate the potential competitive concerns.”
[Note: Although NEPOOL rules prohibit quoting speakers at meetings, those quoted in this article approved their remarks afterward to amplify their presentations.]
In addition to various components of short-run marginal costs, suppliers’ offer prices can be affected by their varied expectations around LMPs, risk preferences and price volatility, even if they have no market power, Patton said. Those differences can prompt suppliers to submit offers that vary substantially from supplier to supplier.
Under the ISO-NE External Market Monitor’s framework, the RTO would use a pre-established price threshold to check participants’ market power. | Potomac Economics
In his presentation, Patton pointed out that price volatility can cause suppliers to limit their exposure by adding a risk premium, to reduce the likelihood of covering an option at a loss. He said reasonable risk premiums should be allowed.
Such latitude would require a model to estimate the variation in such premiums to ensure that the pre-established thresholds accommodate the variation under a wide range of conditions, he said. Setting the thresholds appropriately can change the incentives of suppliers to offer more competitively, with the analysis showing that a pivotal supplier does not have an incentive to raise prices under conduct thresholds of $50/MWh.
The EMM recommended ex post market power mitigation measures to deter physical withholding and provide an alternative to a must-offer obligation. He said the most common forms of such measures are financial sanctions based on the impact of a market participant’s conduct or subjecting a supplier with market power to a must-offer obligation.
“We are worried about the overstepping of bounds,” Brett Kruse of Calpine said. “Traditionally, as we saw in the California Energy Crisis, FERC’s always had the ability to look at something and say, ‘You didn’t violate any rules; you didn’t violate the tariff; you didn’t violate any NERC criteria; but what you did, at its core, was to defraud. You had the intent to defraud people.’ … And they’ve held people accountable for that.” He pointed out that the ex post mitigation that Patton is proposing would occur many months after decisions on LNG arrangements were made and that the Monitor had effectively proposed a “backdoor” must-offer requirement.
“By definition, most exercises of market power do not violate any rules; it’s not fraudulent,” Patton said. “I’m an economist, and if you have market power, I expect you to attempt to exercise it. If you’re a rational economic actor in a market, and you have market power, you exercise it. In fact, you’re under an obligation to your shareholders to exercise market power, which is why market power mitigation must be effective.”
“FERC set up these markets with the notion that people were going to exercise market power, that we were going to get noncompetitive pricing, so either people have to not have market power, or it has to be effectively mitigated,” Patton said.
Market Power Assessment
ISO-NE is also making progress on the market power assessment (MPA) being conducted concurrently with the mitigation design work, Chief Economist Matt White said. (See “Market Power Analysis and Mitigation,” NEPOOL Markets Committee Briefs: Nov. 12-13, 2019.)
An MPA should determine whether market power is empirically supported, and if so, help to identify the specific conditions, frequency and extent to which individual participants may be able to profitably exercise market power, White said.
RTO staff have largely completed the first of four steps in the MPA, White said, presenting a memo.
The four major steps are: developing co-optimized market clearing software; producing study cases and input data; modeling participants’ option offers; and evaluating and analyzing of the market clearing outcomes.
White said the RTO is developing, coding and validating a day-ahead co-optimized market clearing engine model, or study model, by itself because the vendor would not be able to do so before 2024.
After the RTO assembles the data, White said, it must develop the assumptions and construct the offer behavior, using actual numbers, which has to be done under two scenarios: competitive conditions, and conditions in which a participant is able to exercise market power.
The model incorporates the functions and logic of the existing day-ahead market and includes the proposed new day-ahead ancillary services, pricing and co-optimization clearing logic.
ESI Central Case Update
Results for the critical winter months — or Central case — in the RTO’s latest model of its Energy Security Improvements initiative reflect limited changes in assumptions relative to those presented at the prior January MC meeting, Todd Schatzki of Analysis Group said.
The RTO has until April 15 to file a long-term fuel security mechanism with FERC (EL18-182). The Participants Committee plans to vote on the new market design at its April 2 meeting.
Modifications included minor changes to the hourly strike price inputs used in all cases and extending the date of the last barge refueling from Feb. 1 to 14, expanding the available fuel supply. In the cold snap of 2017/18, sea and river ice affected ship and barge deliveries to fuel oil terminals located in Maine and New Hampshire and on the Hudson River.
ESI increases total customer payments in some cases (Frequent, Infrequent) and decreases it in others (Extended). | Analysis Group
Changes result in minor decreases in total customer payments in the Frequent and Infrequent cases, with other results similar to those reported on Jan. 14. The full set of tables is provided in the presentation appendix, Schatzki said. (See NEPOOL Markets Committee Briefs: Jan. 14-15, 2020.)
Customer payments increase because of forecast energy requirement (FER) payments plus the net cost of new day-ahead energy options, with the higher payments partially or more than fully offset by reduced energy (LMP) costs caused largely by the incremental energy inventory under the market design, he said.
The new analysis showed that in the “frequent” stressed conditions scenario, total payments by load would increase 3.2% to $4.23 billion, with $250 million in FER payments and $66 million in net day-ahead option payments partially offset by a $184 million reduction in payments for energy and real-time operating reserves.
Under the “extended” stressed conditions case — based on 2017/18, with its one long cold snap — load costs would decrease $62 million (-2.3%) to $2.66 billion.
The “infrequent” stressed conditions case, based on 2016/17, showed $1.8 billion in load costs, a $35 million (2%) increase.
