To ensure that PDRs are not double counted as both a load-reduction and a supply resource in the FCA, the RTO “reconstitutes” PDR demand reductions — most of which is energy efficiency — into historical loads. The goal is to ensure the EE in the gross demand forecast approximates how much EE that will participate in the upcoming FCA.

Since 2010, the RTO has performed reconstitution using total EE measures installed, believing it to be roughly equal with the amount of capacity supply obligations (CSOs) obtained by EE resources cleared in the FCA. But the RTO says it now realizes that EE program administrators install and report EE measure quantities above the CSOs acquired in the FCA. The RTO has no way to differentiate which measures are installed to meet a CSO and which measures are not.

Under the revised methodology, the gross load forecast will be tied to EE’s participation in each FCA rather than all EE that is installed and reported to ISO-NE.

“What we’ve seen is the CSOs for the [Annual] Reconfiguration Auctions are higher than the primary auctions, so we’re trying to correct things for the upcoming primary auction, and now we’re trying to adjust that gross load forecast accordingly to reflect the known differences in the amount of CSOs and PDR that clears in the Reconfiguration Auctions,” Black said.

[Note: Although NEPOOL rules prohibit quoting speakers at meetings, those quoted in this article approved their remarks afterward to clarify their presentations.]

The proposed methodology for adjusting the gross load forecast for the ARAs is based on the average difference between the two most recent reconfiguration auction CSOs and those of the FCAs for the corresponding capacity commitment periods.

The proposed changes would cut forecast 2020 50/50 gross summer peak demand by 652 MW, rising to 1,355 MW for the 2029 forecast. No changes will be made to the existing methodology utilized to reconstitute active demand resources.

The change in load forecasting methodology is the first of three related initiatives the RTO introduced to NEPOOL technical committees so far this year. The second initiative considers the impact of behind-the-meter solar PV on future planning assessments, and the third is intended to improve integration of the FERC Order 1000 solicitation process into the reliability delist bid review, starting with FCA 15.

The RTO will present the load forecasting methodology changes to the RC for an advisory vote in July. If the Participants Committee approves them in August, the RTO will file the Tariff changes with FERC with a requested effective date of Oct. 5.

Operating Changes for Storage

The committee recommended PC support for revisions to Operating Procedure 18 (OP-18) to enable DC-coupled facilities to participate in ISO-NE markets as separate assets.

ISO-NE Manager of Demand Resource Administration Doug Smith presented the proposal, which passed with opposition from two Publicly Owned Entity sector members and an abstention from one Transmission Owner. The proposed effective date is Aug. 6, 2020. (See “Metering for DC-coupled Assets,” NEPOOL Reliability Committee Briefs: May 19, 2020.)

Several market participants are installing electric storage and intermittent generation behind the same point of interconnection. Because some of those co-located facilities are DC-coupled — both the storage and intermittent components share one or more inverters — there is a need to address the metering of such assets.

Load Power Factor Correction

ISO-NE Manager of Real Time Studies Dean LaForest delivered an introductory presentation on improvements proposed for the tracking of the load power factor, the ratio of real power flowing to load versus apparent power in the circuit.

Under Operating Procedure 17 (OP-17), the RTO monitors load power factor by requiring participants to submit survey data for six discrete points in time over the 12-month survey period. But there are “no significant consequence[s]” for failing to meet load power factor standards, LaForest said.

Under the proposed change, the RTO would monitor performance using data from its supervisory control and data acquisition system, allowing it to track every hour of the year.

Poor load factor at high loads — in which reactive power is absorbed from the system — can require unit commitments to support post-contingent low voltage. Poor load power factor at light loads — with reactive power injected into the system — is more common and can require unit commitments to support pre- or post-contingent high voltage, LaForest said.

The RTO would use the more robust data to report on areas where poor performance hurts reliability or increases unit commitment costs.

Compliance with the load power standards for each area would be “consistent” with current operating procedure compliance practices, LaForest said.

Noncompliant entities would be allowed an opportunity to improve their performance; continued failures would result in actions under “existing compliance mechanisms,” he said. The RC will review redline changes to OP-17 in July, with a vote expected in September and PC action in October.

Committee Actions

The RC’s notice of actions included approval of several power purchase agreements.

The committee approved the New England Clean Energy Connect HVDC transmission project from Eversource Energy and Central Maine Power. Based on a voice vote, the motion passed with two Publicly Owned Entity members opposed and eight abstentions.

Also approved were the:

King Street Comprehensive Solar Cluster Project (New England Power);
ASO South Comprehensive Cluster Project (New England Power);
Wareham Cluster Solar and Battery Project (Eversource);
Versant Power Cluster Solar Project (Versant Power/Emera Maine);
Great River Hydro AVR Replacement and Digital Governor Retrofit Project (Great River Hydro);
Highland Avenue Dartmouth Cluster Solar and Battery Project (Eversource);
Bridgeport Fuel Cell Project (Avangrid/United Illuminating);
CMEEC New London Navy Fuel Cell Project (Connecticut Municipal Energy Electric Co.); and
Waterford Solar Project (Eversource).

The committee also recommended PC approval of revisions to Planning Procedure No. 5-1 to update the form for submitting PPAs, with a proposed effective date of Aug. 6. In response to an increase in PPAs and generator notification forms (GNFs) being processed monthly, the revised procedures require submittals 10 business days before the monthly RC meeting date.

June 22, 2020

Pandemic Pause Leaves MISO Under Budget

The great pause brought on by the novel coronavirus pandemic could have one upshot for MISO: It will likely save millions of dollars this year.

The RTO is currently 3% — or $2.6 million — under budget in base operating expenses for 2020, primarily the result of a halt in employee travel and training initiatives and lower staffing levels because of a slowdown in new hires.

“COVID has introduced quite a bit of volatility in our financials,” CFO Melissa Brown told MISO’s Board of Directors during a virtual meeting Thursday.

MISO budget — MISO CFO Melissa Brown in 2018 | © *RTO Insider*

Reductions in utility bills and building maintenance also contributed to the savings, as have delays in work being done by third-party contractors, a product of physical distancing measures, she said.

And while it was “challenging” to conduct remote interviews with prospective MISO employees while lockdowns were at their strictest, Brown said the RTO is now back to interviewing and onboarding.

“I think it’s the shock factor that occurred during the March-April time frame,” she said. “Most of delays, we’re already seeing reversals out, and we expect them to reverse completely by the end of the year.”

Still, MISO predicts to be about $7.3 million — or 2.7% — below its base operating budget by the end of 2020. Brown cautioned the board that MISO’s year-end prediction could change as the pandemic evolves. The RTO had a $264.7 million base operating budget planned for 2020.

“There are still quite a lot of unknowns in the back end of the year,” Brown said. “We expect to continue to have a lot of variability. It could go up or down, and we don’t claim to know the future.”

Other MISO budgets have suffered larger impacts from the pandemic.

Brown said MISO’s other operating expense budget is so far $6.8 million — or 18% — below what was budgeted for 2020, as fewer FERC assessment fees roll in and the third-party studies the RTO depends on for its own engineering studies are held up. By year-end, MISO expects other operating expenses to be down nearly $16 million. And project investments so far this year are down $1.4 million, or a little more than 9% below budget, she said, though MISO expects to be back on track in spending for those investments by the end of the year.

MISO also earned $3.9 million less than it projected to make in interest so far this year.

“What we’re seeing in interest is a marked reduction on interest income,” Brown said, adding that MISO expects to make about $10 million less than it originally anticipated in interest income by the end of 2020.

However, MISO still expects to have a $150.3 million year-end cash balance, slightly higher than the $148.7 million it planned for in its 2020 budget.

June 22, 2020

PJM MRC/MC Briefs: June 18, 2020

Markets and Reliability Committee

Emerging Technologies Forum

Stakeholders unanimously endorsed the charter for the new PJM Emerging Technologies Forum at Thursday’s Markets and Reliability Committee meeting.

Eric Hsia of PJM reviewed the charter, saying significant changes were made after some stakeholders expressed concerns with adding another subcommittee to the schedule. The subcommittee was instead changed to a forum with no formal decision-making role. (See “Emerging Technologies Subcommittee Proposed,” PJM MRC Briefs : April 30, 2020.)

Hsia said the forum is designed to keep stakeholders abreast of technology pilot programs PJM is seeking to implement and to facilitate discussions with technology providers. It will work to ensure transparency through a periodic review of the advanced technology pilot program, Hsia said, and continue fostering collaboration with technology providers and stakeholders.

The forum will not make selections of pilot projects and programs, Hsia said, with PJM maintaining management over the selection. Hsia said no official votes on issues will be made at the forum, but members will be able to conduct nonbinding votes and make recommendations that stop short of creating and voting on solution packages.

The group is currently targeted to meet monthly, with the first forum expected in August.

Greg Poulos, executive director of the Consumer Advocates of the PJM States, expressed support for the forum and urged PJM staff to consider cost-benefit analyses in discussing projects. He said costs are one of the primary concerns of consumer advocates when discussing new initiatives.

Adrien Ford of Old Dominion Electric Cooperative said the changes made to the charter by PJM after stakeholder feedback have made it a stronger and more focused group.

Stakeholder Group Sunsets

Members unanimously endorsed sunsetting seven stakeholder groups that PJM staff said had achieved their original goals.

Dave Anders of PJM said stakeholder feedback resulted in modifications to the original list introduced at the May MRC meeting. (See “Task Force Sunset,” PJM MRC Briefs: May 28, 2020.)

Anders said the Modeling Generation Senior Task Force was struck from the sunset list. The task force met on June 10, Anders said, and members at the meeting expressed support for continuing to meet as needed to provide guidance and feedback.

The other suggested change based on feedback was to keep the Energy Price Formation Senior Task Force, Anders said. Although FERC last month approved PJM’s proposed energy price formation revisions, several members thought additional commission guidance could be received that will require more work related to the task force’s charter, he said.

FERC ordered PJM to submit a compliance filing in 45 days modifying the capacity market’s energy and ancillary services offset to reflect the additional revenues resources will receive under the new rules. (See FERC Approves PJM Reserve Market Overhaul.)

The groups being sunset are the:

Generator Offer Flexibility Senior Task Force, which last met November 2015;
Energy Market Uplift Senior Task Force, which last met March 2017;
Incremental Auction Senior Task Force, which last met January 2018;
Summer Only Demand Response Senior Task Force, which last met September 2018;
Primary Frequency Response Senior Task Force, which last met December 2018 (PJM provided a separate presentation on the work of the task force.);
Distributed Energy Resources Subcommittee (DERS), which last met in May; and
Intermittent Resources Subcommittee (IRS), which last met in March.

Erik Heinle, of the D.C. Office of the People’s Counsel, asked for clarification regarding the two subcommittees on the list, the DERS and IRS.

The MRC approved sunsetting seven stakeholder groups but agreed to retain the Modeling Generation Senior Task Force and Energy Price Formation Senior Task Force. | *PJM*

Anders said the intention is to form a new subcommittee, the Distributed Energy Resource and Inverter-based Resources Subcommittee (DIRS), combining the scope of work of the two groups. Anders said DIRS will report to the Market Implementation Committee, which is set to approve its charter at the July 8 meeting.

5-Minute Dispatch and Pricing

Debate continued on PJM’s proposal to improve coordination of its five-minute dispatch and pricing during a first read of the Operating Agreement and manual language changes.

Adam Keech of PJM presented the highlights of the package, which calls for “work streams”: short-term market changes to address pricing alignment; “enhancements and clarifications” to LMP verification; intermediate operational changes to implement more “regimented” real-time security-constrained economic dispatch (RT SCED) case approvals; and long-term operational changes to investigate changing SCED timing and consider previous dispatch instructions.

The RTO’s proposal will be voted on at the July MRC and Members Committee meetings. Pending FERC approval, implementation is tentatively slated for October.

The measure was endorsed nearly unanimously at the MIC meeting. (See PJM 5-Minute Dispatch Proposal Endorsed.)

Keech said PJM decided to break the process up into short-term, intermediate and long-term efforts based on how quickly they could be implemented.

PJM’s proposed short-term fixes would align the locational price calculator (LPC) to use the reference RT SCED case for the same target time. The LPC would calculate prices for the interval from 11:55 a.m. to 12 p.m. ET using the RT SCED solution for a 12 p.m. target time.

Much of the debate has centered on stakeholders’ desire to implement long-term dispatch changes along with the short-term and intermediate changes.

PJM’s “work streams” for improving coordination of its five-minute dispatch and pricing | *PJM*

Keech said PJM is dedicated to working with stakeholders on the long-term changes and determining if there are formulation changes needed for dispatch by doing side-by-side comparisons with the different dispatch methods used at MISO, SPP, CAISO and ERCOT. PJM is proposing holding the long-term discussion as a working issue at the MIC with reports provided to the Operating Committee, Keech said. Detailed discussions could start at the MIC by September.

Ford said she was glad PJM is committing to look at long-term solutions and suggested making the discussions a special session of the MIC because of the education needed to understand the concepts.

“September sounds as good a time as any to start so that we’re not waiting too long,” Ford said.

Paul Sotkiewicz of E-Cubed Policy Associates said PJM’s short-term proposal and the process moving forward on long-term issues are “eminently reasonable.” He said the point of stakeholder discussions are to get to a place where PJM is using the most up-to-date information possible, making dispatch and pricing more reflective of conditions.

Keech said PJM is looking forward to engaging with stakeholders on the discussions and solutions.

“I can assure you and the entire stakeholder community that we are committed to continuously getting better,” Keech said.

Members Committee

PMA Credit Requirements

Stakeholders unanimously endorsed Tariff revisions related to p eak m arket a ctivity (PMA) credit requirements to address a regulatory change in Ohio concerning the billing of network integration transmission service (NITS). The change was endorsed through acclamation, with one abstention.

Bridgid Cummings of PJM reviewed the revisions.

In 2015, the Public Utilities Commission of Ohio moved NITS and other related charges to a non-bypassable rider that is the responsibility of the electric distribution company. The change means competitive retail electric suppliers serving load in Ohio are no longer allowed to collect NITS or any other transmission-related charges from end-use customers.

PJM requires load-serving entities to sign NITS agreements and post collateral based on their PMA and gives itself the ability to make changes to a participant’s PMA requirement when the RTO determines the PMA is not representative of expected activity. (See “‘Quick Fix’ on PMA Credit Requirements,” PJM MIC Briefs: April 15, 2020.)

Surety Bonds as Collateral

Members endorsed Tariff revisions to approve surety bonds as a form of collateral. The revisions passed with three objections and three abstentions in the consent agenda portion of the meeting.

The proposal allows the use of surety bonds as collateral for all market purposes except financial transmission rights, with a $10 million cap per issuer for each member and a $50 million aggregate cap per issuer.

PJM said it will require the use of bond companies on the U.S. Treasury Department’s certified list and a minimum credit rating of A with S&P Global Ratings, Fitch Ratings and AM Best, or A2 with Moody’s Investors Service. PJM also will require one-day payment demand terms.

June 22, 2020

SPP Briefs: Week Ending June 19, 2020

SPP is facing a two-month delay in gaining FERC approval of the Tariff for its Western Energy Imbalance Service (WEIS) market, staff said last week (ER20-1059, ER20-1060).

Regulatory Policy Manager Nicole Wagner told the Western Market Executive Committee (WMEC) on Friday that SPP, in responding in May to a deficiency letter from the commission, has asked for approval by July 21. The RTO had requested a May 21 approval date when it filed its proposed Tariff in February. (See “WEIS Tariff Approved, on to FERC,” SPP Board of Directors/MC Briefs: Jan. 28, 2020.)

The grid operator plans to launch its Western Interconnection energy imbalance market on Feb. 21, 2021.

FERC in April a ske d SPP for additional information in 14 categories, ranging from implementation and administrative costs to whether marketing employees will sit on the WMEC and how the RTO will ensure committee members do not “run afoul” of separation-of-function rules.

The RTO’s May response drew protests from a number of western utilities, led by Xcel Energy. The company sa id the WEIS Tariff could impair a joint dispatch agreement involving many of the entities. The company also said market flows may harm the Western Interconnection’s unscheduled flow mitigation plan and that SPP disregards the Northwest Power Pool’s activities.

Asked whether SPP would respond to the protests, Wagner said, “We have discussed the possibility of filing additional information with FERC.”

SPP’s WEIS market, with eight participants, is an alternative to CAISO’s Western Energy Imbalance Market. CAISO and PacifiCorp started the EIM in 2014 and have nine participants. They plan to add 10 more by 2022.

Staff said the WEIS implementation program’s various projects are all on schedule, now that it has taken delivery of the market engine that will make everything work. “That was big news for us and why we’re back on schedule,” said David Kelley, SPP’s director of seams and market design.

The program’s costs are trending at or less than 5% above budget. Market trials begin July 1 with connectivity testing. Structured and unstructured testing is scheduled for Aug. 3-Nov. 20.

Staff Close to Seams Agreement with AECI

SPP is working with Associated Electric Cooperative Inc. (AECI) to address remaining reliability concerns over a sidelined competitive interregional upgrade, staff told the Seams Steering Committee on Thursday.

The 105-mile Wolf Creek-Blackberry project in Kansas and Missouri, projected to cost $152 million, was approved by SPP’s Board of Directors last year and included in the 2020 Transmission Expansion Plan. The board suspended the project’s notification to construct (NTC) in April to give both grid operators an opportunity to hash out an agreement over costs and scope. The agreement must be approved by FERC before a request for proposals can be issued. (See “Directors Suspend Competitive Upgrade,” SPP Board/Members Committee Briefs: April 28, 2020.)

Cautioning members that he didn’t want to give a false sense that “we have fully crossed the finish line,” SPP Senior Operations Engineer Neil Robertson said additional analysis has indicated the 345-kV project would increase flows on some lower-voltage systems that would need to be mitigated.

“We’re working with AECI staff on those concerns. We have at least a tentative agreement for a mitigation plan,” Robertson said.

The AECI board of directors plans to take up the proposed agreement this week. SPP staff hope the RTO’s board will reconsider the NTC during its July meeting.

Robertson said staff are also trading possible needs solutions with MISO, SPP Staff Recommend 2020 Joint Study.)

“Hopefully, this will culminate in a set of projects that look like they have the possibility of meeting [criteria] thresholds by both organizations,” Robertson said.

The Seams Steering Committee will likely next meet as the Seams Advisory Committee. Its July meeting has been canceled, but the Markets and Operations Policy Committee plans to recommend a reorganized structure for its stakeholder groups to the board later that month.

The reorganization aligns the MOPC’s stakeholder groups with SPP’s primary functions and oversight responsibilities, allowing the committee to focus on policy-level work.

and renames the Seams Steering Committee as the Seams Advisory Committee. | *SPP*

“It’s just a name change,” System Planning Director Casey Cathey told the SSC, noting that the SAC will continue to participate in the RTO’s interregional planning stakeholder advisory committees with MISO and AECI.

Near Record $5.98M in M2M Settlements for SPP

SPP in April accrued a near record $5.98 million in market-to-market (M2M) settlements from MISO, staff said during the SSC videoconference. SPP has now piled up $82.32 million in M2M settlements since the two neighbors began the process in March 2015.

The process allows the RTOs to dispatch electricity on the most economical routes when congestion leads to constrained flowgates. Settlements have been in SPP’s favor for 46 of the 62 months.

Market-to-market settlements were again in SPP’s favor in April. | *SPP*

Two temporary SPP flowgates along the Kansas-Missouri border accounted for $2.81 million of the settlements. High winds and outages led to the constraints.

Temporary flowgates were binding for 890 hours, resulting in $3.87 million in settlements to SPP. Permanent flowgates were binding for 369 hours during April, resulting in another $2.11 million in settlements, again in SPP’s favor.

June 22, 2020

UPDATED: PG&E Sentenced; Bankruptcy Plan Approved

A federal judge approved Pacific Gas and Electric’s $60 billion Chapter 11 reorganization plan Saturday, two days after a state judge sentenced the company to $4 million in fines and costs, the maximum allowable, for starting the November 2018 Camp Fire that killed 84 people and destroyed the town of Paradise.

It was the state’s deadliest and most destructive wildland blaze and the worst of the catastrophes that led PG&E to seek bankruptcy protection in January 2019.

The approval of PG&E’s reorganization plan by U.S. Bankruptcy Court Judge Dennis Montali in San Francisco came after 17 months of negotiations between the utility, fire victims and other creditors, and Gov. Gavin Newsom. It allows the country’s largest electricity provider to resume its role as monopoly utility for most of Central and Northern California.

The utility will leave bankruptcy burdened with billions of dollars in debt and operating under the scrutiny of judges, elected officials and an angry public.

In Chico, Calif. on Thursday, Butte County Superior Court Judge Michael Deems said he couldn’t imprison a corporation, but he repeated the words of Federal Judge William Alsup, who oversees PG&E’s probation for felony convictions related to the San Bruno gas pipeline explosion that killed eight people in 2010.

“‘If there was ever a corporation that deserved to go to prison, it’s PG&E,'” Deems said, quoting Alsup. “This court is adopting that sentiment. If these crimes were attributed to an actual human person rather than a corporation, the anticipated sentence … would be 90 years to be served in state prison.”

PG&E pleaded guilty Tuesday to 84 counts of involuntary manslaughter and one felony count of unlawfully starting a fire as part of a sentencing agreement with the Butte County District Attorney’s Office.

‘Back to Business’

Fire victims who lost family members in the Camp Fire made statements to the court all day Wednesday and on Thursday morning.

Mike Hanko, a retired truck mechanic, broke down in sobs as he recalled the death of his brother, Dennis Hanko, in the Camp Fire and the devastating effects on their family. The brothers had lived together in Paradise, helping each other through hard times, until a month before the fire, Hanko said.

Hanko, speaking on behalf of himself and his three sisters, said it upset him that PG&E seemed to care more for profits than human lives.

“They just file for bankruptcy, pay fines, money to people they have harmed, and then it’s back to business,” Hanko said. “How can you put a price on a life?”

PG&E sentenced — | *USDA Forest Service/Tanner Hembree*

District Attorney Michael Ramsey read a statement by Tammie Hillis, whose father, T.K. Huff, died in the Camp Fire. Hillis said her father was able to make it to the edge of his property in his wheelchair, where he’d apparently tried to protect himself with a hose and water bucket.

Hillis said her family will never know if her father died quickly or suffered at length as the Camp Fire raced toward his home in the hamlet of Concow, which the fire destroyed shortly before it hit Paradise. His burned remains were identified through a DNA match.

“We are left to picture his last heart-wrenching moments on Earth,” she wrote. “Please explain to me why my father had to die this way … alone, afraid of what was coming down the hill. This was a flaming monster, destroying everything in its path. Our father died from the ultimate monster, PG&E. Their complacency year after year is pure evil. They knew and chose to do nothing, which makes them murderers.”

Ramsey released a report Tuesday, based on grand jury testimony, that detailed PG&E’s failure to maintain its aging transmission lines near Paradise. A C hook that cost 22 cents when it was made in 1919 broke after nearly 100 years of wear. That dropped a 115-kV line that arced on its steel tower, sending molten metal onto dry brush below, Ramsey said Thursday. (See PG&E Pleads Guilty to 84 Homicides and Ar s on.)

He said his office had been unable to show that any PG&E executives approved decisions over the course of decades that led to the fire, but he warned the utility it should know that future disasters could result in individual prosecutions.

“Now, as a result of the investigation and the prosecution and the distribution of the report to the executives of PG&E, those folks are now tasked with the knowledge of their company’s reckless behavior in failing to maintain their equipment,” Ramsey said. “They are on notice.”

He likened it to the procedure in California courts of warning repeat drunk drivers that they will be charged with second-degree murder if they kill someone while driving under the influence of drugs or alcohol.

PG&E Director Bill Smith, who will take over as acting chief executive when current CEO Bill Johnson retires at the end of June, represented PG&E at Thursday’s hearing. (Johnson had pleaded “guilty, Your Honor” 85 times on Tuesday.)

Smith promised, as PG&E executives have vowed numerous times since the utility filed for bankruptcy in January 2019, that it would change and that its equipment would never again cause a tragedy like the Camp Fire.

“Your Honor, we have come before this court [and the] Camp Fire victims … with humility and respect, ready to be held to account for this tragedy and committed to regaining the trust that we have broken,” Smith said.

Bankruptcy Approved

On Saturday, Bankruptcy Judge Montali signed an order approving PG&E’s reorganization plan, as he had said he would in a written order Wednesday and again on Friday, during a hearing to resolve remaining objections.

“These cases are among the most complex in U.S. bankruptcy history,” Montali wrote in his Wednesday order. “They involve difficult legal, financial, practical and personal issues. They were filed because of overwhelming damage claims following the devastating 2015-2018 Northern California wildfires, leaving thousands of victims who suffered from those wildfires owed billions of dollars, plus thousands more of traditional non-fire creditors of various types also owed billions of dollars.”

Like Deems, Montali said he felt he had little choice.

“If the court does not confirm the plan, the only option appears to be leaving the debtors where they have been for the last 17 months,” he wrote. “Leaving tens of thousands of fire survivors, contract parties, lenders, general creditors, allegedly defrauded investors, equity owners and countless others with no other options on the horizon is not an acceptable alternative.”

PG&E had met the requirements of the U.S. Bankruptcy Code by offering a plan that is financially feasible and will not leave the utility facing liquidation after it exits bankruptcy, Montali said. PG&E had also resolved major disputes with objecting parties, and it had won approval for its plan from the California Public Utilities Commission under Assembly Bill 1054, which establishes a wildfire insurance fund for the state’s investor-owned utilities. (See CPUC Approves PG&E Bankru p tcy Plan.)

The company reached negotiated settlements with creditor committees, agreeing to pay $13.5 billion to fire victims, $11 billion to insurance companies and hedge funds that hold third-party subrogation claims and $1 billion to local governments and agencies for wildfire expenses. PG&E plans to finance its bankruptcy with billions of dollars in stock and debt offerings, which it has already begun filing with the U.S. Securities and Exchange Commission.

On Monday, PG&E announced it had raised $8.9 billion in debt, including $3.5 billion for capital investments and $5.4 billion as its contribution to the AB 1054 wildfire fund. (The fund will be financed equally by ratepayers and utilities.) The company said it expects to close Tuesday on an additional $4.75 billion in debt.

Also on Monday, PG&E announced it plans to raise $5.23 billion from new equity offerings, including $4 billion in common stock. The sales are expected to close in mid-July, when the utility hopes to formally exit bankruptcy.

June 21, 2020March 11, 2025

NEPOOL Transmission Committee Briefs: June 18, 2020

New England Power Pool Counsel Eric Runge delivered a memo to the Transmission Committee regarding FERC’s May 26 order approving recovery of costs related to compliance with NERC critical infrastructure protection (CIP) requirements for facilities designated as critical for the determination of interconnection reliability operating limits (IROL) (ER20-739).

The order approved the addition of Schedule 17 to FERC OKs Payment Rules for IROL Facilities.)

The cost recovery provisions apply primarily to generators but also to Cross Sound Cable or similarly situated transmission facilities designated as critical for determining IROL.

The Cross Sound Cable and similarly situated transmission facilities are critical for the determination of interconnection reliability operating limits. | ABB

“More specifically, Schedule 17 provides for ISO-NE to act as a billing and payment agent for recovery of eligible costs of IROL-critical facilities that have filed with FERC and had accepted individual Section 205 cost recovery filings,” the memo said.

The primary issue of controversy in the proceeding was whether past IROL-related costs could be recovered, or whether their recovery would be barred by FERC’s filed-rate doctrine and rule against retroactive ratemaking, the memo said. The same issue had been considered by the TC in its discussions, and the RTO took a neutral position on it in the proceeding.

The commission also noted the preference of some parties for a formula rate treatment of IROL costs and stated that they “may seek formula rate treatment in their proposed [Federal Power Act] Section 205 filings,” according to Runge.

“We expect that some parties will file requests for rehearing on the past cost recovery issue,” the memo said. Any requests for rehearing are due 30 days from the date of the order.

Schedule 9 and Schedule 1 Rates

Mary Bimonte of Eversource Energy, chair of the Participating Transmission Owners Administrative Committee’s (PTO AC) Rates Work Group, presented Schedule 9 and Schedule 1 rates that became effective June 1.

The formula rates for Schedule 9 Regional Network Service (RNS) and Regional Schedule 1 Service have been updated to reflect actual data for 2019, forecasted data for 2020, and the annual true-up and associated interest, Bimonte’s report said. The resulting rates for RNS and Schedule 1 Service were included for stakeholder informational purposes.

The PTO AC approved the filing of the RNS and Schedule 1 rates at its June 11 meeting. An informational presentation will be made to NEPOOL stakeholders at the Reliability and Transmission committees’ joint summer meeting Aug. 18-19. The PTO AC will submit an annual informational filing to FERC on or before July 31.

June 21, 2020

ISO-NE Planning Advisory Committee Briefs: June 17, 2020

About 5,800 MW of offshore wind can be interconnected using AC cable connections to interconnection points along the southern New England coast without significant upgrades to the onshore transmission network, according to ISO-NE’s 2019 Economic Study Offshore Wind Transmission Interconnection Analysis.

ISO-NE Director of Transmission Services and Resource Qualification Al McBride presented the analysis, which noted that some local 345-kV reinforcement and/or expansion is still likely to be needed for this scenario, and that additional interconnections to these points would drive the need for significant network upgrades.

The New England States Committee on Electricity (NESCOE), Anbaric Development Partners and RENEW Northeast last year each requested separate studies from ISO-NE. (See “Modeling More Offshore Wind, Slowly,” ISO-NE Planning Advisory Committee: March 18, 2020.)

Alternatively, additional offshore wind could be connected while avoiding significant onshore transmission upgrades by using HVDC connections from the offshore wind farms to load center substations, McBride said.

Anbaric has proposed the Southern New England Ocean Grid, an open-access, 1,200-MW HVDC network that would interconnect future offshore wind projects in the federal wind lease area off the coasts of Rhode Island and Massachusetts.

Such an undersea network interconnecting an expected surge in offshore wind projects would save New England developers and ratepayers more than $1 billion in onshore grid upgrades, The Brattle Group said in a study commissioned by Anbaric. (See Brattle Study Highlights Benefits of Offshore Grid.)

“There are also potentially hybrids, where you go part of the way with AC, part of the way with DC, or the other way around,” McBride said.

“Just to compare the alternatives, for what we call the AC alternative, you are continuing to add a lot of cable to the water,” he said.

The study also determined that 2,200 MW could be connected using HVDC without major onshore transmission upgrades, which, in addition to the 5,800 MW connected using AC cables, provides a total of 8,000 MW of connected offshore wind off the southern New England coast.

No Public Policy Tx Need

Director of Transmission Planning Brent Oberlin reviewed the steps ISO-NE took in the 2020 Public Policy Transmission Upgrade process that concluded there was no need to proceed with a Public Policy Transmission Study (PPTS) this year.

The RTO agreed with NESCOE’s position that none of the stakeholder submittals regarding public policy requirements identified a federal law that drives a transmission need and said it is not aware of any such requirements that drive the need for transmission.

Similarly, the RTO reviewed NESCOE’s submittal and found that the states have determined that there are currently no state or local requirements that drive transmission that should be studied in a PPTS.

June 21, 2020May 6, 2025

ISO-NE Stopgap Fuel Security Program Gets OK

FERC on Thursday approved ISO-NE’s Inventoried Energy Program (IEP) as a “reasonable” and “technology-neutral” short-term solution to compensating resources that provide fuel security during New England’s winters (ER19-1428).

The commission denied rehearing of its automatic acceptance of the IEP in August 2019. The four-member commission lacked a quorum on the matter at the time. Then-Commissioner Cheryl LaFleur had recused herself from all matters involving ISO-NE, later becoming a member of its Board of Directors after she left the commission. (See Lacking Quorum, FERC OKs ISO-NE Energy Security Plan.)

Thursday’s ruling affirms ISO-NE’s ability to implement the IEP for the capacity commitment periods covered by Forward Capacity Auctions 14 and 15, allowing it to compensate resources for maintaining inventoried energy during the winter months of 2023/24 and 2024/25.

The IEP is a voluntary program that consists of five components, including a two-settlement structure, a forward rate, a spot rate, trigger conditions and a maximum duration. Under the two-settlement structure, participants can choose to participate in either the forward and spot market components of the program or just the spot market.

“Participants that opt to participate in both components take on a financial obligation for inventoried energy during the program delivery period (December through February) at the forward rate in the first settlement period,” FERC explained. “Any deviations from inventoried energy maintained for each event trigger (an inventoried energy day) are settled in the second settlement period at the spot rate.”

ISO-NE proposed a fixed forward rate of $82.49/MWh for inventoried energy sold forward during the delivery period, an estimate of the minimum rate that a gas-only resource would require to sign a winter-peaking supply contract for LNG.

The RTO estimates the program will cost between $102 million and $148 million per year, depending on participation, resource performance and winter severity. It assumed that 1.2 million to 1.8 million MWh of inventoried energy, respectively, would be sold forward and maintained for each inventoried energy day per year.

Natural gas spot prices spiked during New England’s extended cold snap of 2017-2018. | EIA

The commission agreed with ISO-NE that a “misaligned incentives” problem in the current market design may cause fuel-secure resources to be insufficiently incented to invest in energy supply contracts, which may have adverse efficiency and reliability consequences.

Although IEP does not constitute a fully market-based solution, “the proposal is a step in the right direction … while ISO-NE finishes developing a long-term market solution,” the commission said.

Commissioner Richard Glick dissented in a separate statement, calling the IEP “an ill-conceived giveaway that acts as if throwing money at a problem is always just and reasonable.”

ISO-NE kicked off a two-year effort to address regional fuel security after its January 2018 Operational Fuel-Security Analysis (OFSA) showed that the loss of 1,700 MW from Exelon’s Mystic 8 and 9 gas-fired units would deplete 87 hours of 10-minute operating reserves and result in 24 hours of load shedding during the winters of 2022/23 and 2023/24. (See Report: Fuel Security Key Risk for New England Grid.)

The Energy Security Improvements filing by the RTO in April 2020 comprised long-term proposals prompted by FERC’s July 2018 finding that ISO-NE’s Tariff was not just and reasonable because the RTO lacked a way to address fuel security concerns. (See ISO-NE Sending 2 Energy Security Plans to FERC.)

Comments and Protests

Several commenters supported the IEP, with FirstLight Power Resources urging the commission to resist requests to amend the proposal because they would be an unhelpful distraction from the long-term market design efforts.

Calpine and Vistra Energy stated that the IEP’s forward component is the key to winter fuel security because it incentivizes market participants to take the necessary steps to achieve fuel security, including procuring an adequate amount of fuel and fully optimizing their existing fuel infrastructure.

Algonquin Gas Transmission supported the IEP but said that the long-term solution can only address New England’s fuel security challenges if it addresses the lack of firm natural gas transportation and storage in the region.

On the other side, the New England Power Pool stated that neither the IEP nor any other proposal had sufficient stakeholder support to win its endorsement. It said the commission “should not direct specific changes that were not already addressed in the stakeholder process without full stakeholder consideration of such changes through the commission-approved participant processes.” The Environmental Defense Fund meanwhile said the interim nature of the IEP does not permit deviation from the just-and-reasonable standard and that no provision under Federal Power Act Section 205 permits the commission to accept filings on an interim basis.

Several commenters also said ISO-NE had failed to demonstrate that the IEP will benefit customers. NRG Energy urged the commission to reject the program and provide guidance for a substitute interim fuel security proposal. The Massachusetts attorney general stated that the program lacks evidentiary support and will result in arbitrary and discriminatory rates. The Maine Public Utilities Commission argued that, without a determination of need, there is no ability to measure the program’s success.

The commission countered the complaints, saying that the IEP “will likely provide reliability benefits, such as incenting up to 1.8 million MWh of inventoried energy to be available during stressed winter conditions,” while also asserting authority under Section 205 to accept interim solutions proposed by applicants.

Rebutting the demonstrated need argument, the commission found “that a detailed cost-benefit analysis is not required for the commission to find proposed Tariff provisions just and reasonable.”

The commission disagreed with a joint protest by New England Consumer-Owned Systems and Energy New England that the IEP cannot be deemed just and reasonable because it is neither market- nor cost-based.

“By setting a fixed forward rate based on a winter-peaking supply contract for LNG, ISO-NE estimated the minimum value that would incent program participation from a natural gas-only resource, thereby approximating the price that would occur if inventoried energy was competitively procured through a market-based mechanism where a natural gas-only resource was the marginal resource that established the price paid to all resources providing the service,” the commission said.

FirstLight and NRG contended that the program does not correct for the suppression of FCA clearing prices that occurs when resources seeking retirement are held in the market for fuel security reasons and included in the FCA as price-takers, arguments the commission found were “outside the scope of this proceeding.”

The commission also disagreed with arguments that the existing fuel security cost-of-service Tariff provisions or Pay-for-Performance (PfP) negates the need for the IEP, or that its costs are duplicative to those of PfP, again citing the “misaligned incentives issue.”

“It is premature to judge whether the costs of the Inventoried Energy Program are duplicative to those of the long-term market solution because the long-term solution is pending before the commission and is not before us in this proceeding,” the commission said.

FERC said that establishing rates in advance increases the IEP’s effectiveness in deterring retirements by enabling participants to better forecast expected program revenues even if the forward rate is not fully precise. “Accordingly, we disagree with parties suggesting that the forward rate be updated closer to the time of delivery to capture prevailing market conditions,” the commission said. “We also decline to adopt the alternative proposals proposed.”

Rehearing and Program Revenues

On rehearing, several parties reiterated the same arguments made in their underlying protests, the commission said.

The New England States Committee on Electricity argued that the commission erred by failing to articulate a satisfactory explanation and otherwise engage in reasoned decision-making in accepting the IEP because it failed to respond meaningfully to the arguments before it, address substantial evidence in the record, or explain its departure from precedent.

“The commission acted consistent with the directives of FPA Section 205 given the lack of quorum in this proceeding at that time,” FERC said. “Now that the commission has a quorum, we have determined that, based on a review of the evidence in the record, the proposed Tariff revisions are just and reasonable.”

The commission agreed with ISO-NE and its Internal Market Monitor that net revenues from the program should be treated as revenue from an ancillary service in the calculation of an existing resource’s net going-forward costs. The revenues will also be reflected in the Forward Capacity Market’s delist bid mitigation.

“We acknowledge that there are many factors that influence a resource’s retirement decision and that IEP revenues will vary from resource to resource. And, as ISO-NE asserts, the program is not intended to deter the retirement of a specific resource,” the commission said. “However, we find that these revenues appropriately compensate resources that contribute to winter energy security. Moreover, we agree with ISO-NE that it is important that the program be in place in time for participants considering retirement decisions for FCA 14 and FCA 15.”

Dissent on ‘Fatal Flaws’

Commissioner Glick said that the willingness to spend customers’ money without evidence of a commensurate benefit will make stakeholders, including both states and customers, suspicious of actions by the commission and ISO-NE that purport to address fuel security, potentially undermining more serious efforts to actually address the issue.

“I am particularly troubled by the evidence in the record that the program will hand out tens of millions of dollars to nuclear, coal and hydropower generators without any indication that those payments will cause the slightest change in those generators’ behavior,” Glick said. “Handing out money for nothing is a windfall, not a just and reasonable rate. …

“Although the simplicity of ISO-NE’s proposal may, at first, seem appealing, the program contains a number of what should be fatal flaws,” he said.

FERC Commissioner Richard Glick tweeted about his dissent June 18.

Most importantly, Glick said, the RTO does not point to any evidence that there is a near-term operational problem that cannot be adequately addressed by its existing rules, or any evidence that the IEP would address such a problem by making the region more fuel secure.

“Creating a program to funnel money to uneconomic resources in order to prevent their retirement would seem to undermine a key element of the balancing act that the commission relied upon when it found the Capacity Auctions with Sponsored Policy Resources (CASPR) program just and reasonable,” Glick said.

The RTO’s willingness to propose a program that will “work at cross-purposes with the CASPR’s substitution auction raises serious questions about the durability of the CASPR construct,” he said. The proposal “does not possess even the basic principles of an effective market-based solution [and] evaluated against those principles, the [IEP] gets a failing grade.”

June 21, 2020

Boston RFP Review Draws Unexpected Crowd

About 170 stakeholders turned out Thursday for ISO-NE’s teleconference review of the Phase One proposals in its Boston competitive transmission solicitation, overwhelming the Planning Advisory Committee’s phone line and forcing the RTO to open another connection with greater capacity.

The RTO on June 8 surprised many stakeholders — and elicited a swift legal challenge — when it announced that it had narrowed the 36 responses to its first competitive request for proposals under National Grid, Eversource Finalist for Boston Tx Plan.)

ISO-NE Vice President of System Planning Robert Ethier prefaced the review with a defense of the RTO’s evaluation process.

“While the results of this process may be different than some people had hoped or maybe even expected, arriving at the least-cost solution that requires no transmission siting and very little permitting is, to me, a clear success,” he said.

Director of Transmission Planning Brent Oberlin “and his team did not operate in a vacuum,” Ethier said. “ISO management was kept well informed of the progress as we went along, having regular meetings with Brent and his team and certainly vetting each of the significant decisions along the way.”

Questions on Results, Methods

Seeking to extend its Mystic Generating Station cost-of-service contract for an additional year, Exelon on June 10 filed a complaint with FERC accusing the RTO of violating its Tariff by shortcutting its transmission security review and prematurely culling bids received in response to the solicitation. (See Exelon Challenges ISO-NE RFP in Bid to Extend Mystic.)

During the PAC meeting, stakeholders also questioned why certain proposals were rejected.

“I guess I was a little surprised, looking through this presentation, at how many of the proposals were eliminated just because of the right-of-way provision, and not meeting the reactive capability requirement,” said Abigail Krich, president of Boreas Renewables. “Both of those struck me as things that should have been pretty clear in the process, and the project proponents should have known whether their projects met the requirements.

“Given how many were screened out because they didn’t meet those, it raised the question in my mind whether this was confusion on their part; maybe these requirements weren’t made as clear as they could have been,” she continued. “Do you think a number of proposals that were submitted … that even though they didn’t meet the criteria, that they might still be able to move forward?”

“I can’t speak to what others were doing, but while we did have a number of proposals that tripped up on things, there were also some that did not,” Oberlin said. “As far as the instructions, we talked about the need for a dynamic reactive device at the PAC meeting; we provided it in the report; it was pretty clear what needed to be done at the POI [point of interconnection]. I don’t know why people didn’t do that.”

Boston RFP — Mystic Generating Station, on the Mystic River in Everett, Mass.

Among eight qualified transmission project sponsors that submitted bids for the RFP was Anbaric Development Partners, which made two submissions. The first was an AC project that would move 900 MW of electricity on two tri-core cables between the former Pilgrim station area in Plymouth, Mass., to the Mystic substation in Everett. The second was a proposal for a 1,200-MW HVDC cable bundle between the same two points.

The RTO disqualified Anbaric’s AC proposal for missing a required step-up transformer to accompany its static synchronous compensator (STATCOM).

“For the STATCOM, if the transformer is included in the proposal and not the model — and in my experience the majority of STATCOMs in the Eastern Interconnection are modeled without the transformer — it seems to me that this would be an easy question for a deficiency cure,” said Phil Tatro of EN Engineering, which worked with Anbaric on the proposal.

Tatro noted that the STATCOM was included in both the project’s one-line diagram and the switching station layout, both of which were a part of Anbaric’s publicly posted bid.

“This is a feasibility assessment at this stage, and even if you wanted a transformer modeled, it doesn’t seem necessary in a feasibility assessment,” Tatro said.

Oberlin replied that ISO-NE’s goal was to determine whether or not a proposal met the need identified and specified in the RFP’s addendum report.

The RTO found a number of proposals that included the necessary transformer or other equipment but nonetheless weren’t able to meet the requirement, he said.

“Additionally, we did look through the proposals, and there were a number of files that were supposed to be attached that describe all of the electrical equipment … and also we had a section on transformers, and the [transformer] wasn’t described there,” Oberlin said.

Technical and Legal Challenges

The RTO also disqualified proposals, including Anbaric’s, for planning to interconnect using the Mystic 8 terminal, saying that facility is engaged through May 31, 2024.

Regarding the use of the Mystic 8 terminal, Adam Hickman of transmission developer Transource New England suggested that the RTO might consider using a planned outage to accommodate a transmission solution.

“We do encourage the ISO to go back and look at those property and [transmission owner] facility use provisions,” said Theodore Paradise, Anbaric senior vice president for transmission strategy. “We do think that how the ISO came out conflicts with both section 2.05 of the TOA [Transmission Operating Agreement], which requires interconnection of facilities and in fact good-faith negotiations to be engaged in by any signatories to the TOA, but also Section 210 of the Federal Power Act.

“Twenty-two of 35 projects were disqualified on that basis, and it’s just hard to believe that, with all the successful, sophisticated bidders who have won projects across the country, so many got it wrong,” Paradise said. The $49 million proposal from the incumbents is “probably not the least expensive project for consumers when you look at things like avoided transmission upgrades, or impacts on the energy market. One of our projects is less than 30 cents/month on a retail bill for a project that does a lot to bring in zero-priced renewable energy and also to avoid over $600 million in additional system upgrades for state policies.”

Michael Macrae, energy analytics manager at Harvard University, referred to the “the absence of any sort of an environmental impact” being included in the RTO’s evaluation criteria. He quoted from a June 5 letter from Massachusetts’ two U.S. senators “that highlights this concern and raises the question about how the outcome here aligns with New England state goals.”

In their letter, Sens. Ed Markey and Elizabeth Warren, both Democrats, criticized the RTO’s planning process for listing “environmental impact” in the lowest priority category for the evaluation and noted that “public health impacts are not called out at all.” (See Mass. Senators to ISO-NE: Think Clean on Boston RFP.)

“As we laid out in the RFP itself that was issued in December 2019, we proposed a tiered approach to the evaluation of the proposals,” Oberlin said. “The environmental impacts would be considered as we got through evaluating each of the proposals; assuming that they had met the needs and were all cost competitive with each other, we were going to use that to separate the proposals.”

Several stakeholders asked about whether the RTO’s recommended project utilized a usually prohibited remedial action scheme — or special protection system (SPS).

Oberlin explained that the $49 million project did use an SPS as defined by the Northeast Power Coordinating Council, but that he expected that definition to change in the future. Asked whether any of the other reliability projects use such a scheme, he responded that they do not.

Steve Kerr of Exelon asked whether the proposed solution would meet the system needs and allow Exelon to retire Mystic if the New England Clean Energy Connect (NECEC) project designed to carry 1,200 MW of Canadian hydropower to Massachusetts is not built. ISO-NE counsel Kevin Flynn interrupted and directed Oberlin not to answer, saying the RTO “would not speculate.”

Paradise also noted that the ISO-NE final needs assessment from June 2019 shows additional needs without the NECEC line and said it was not speculation that the proposed solution does not meet the needs without that project moving forward. A public referendum on the NECEC project is planned in Maine in November.

ISO-NE requested that PAC members complete their review of the Phase One proposals report and send their comments to pacmatters@iso-ne.com by July 2. The RTO plans to post the final listing of qualifying Phase One proposals on or before July 17, Oberlin said.

June 21, 2020

More Work Needed on MISO Order 845 Compliance

MISO has four months to make two more filings to comply with Order 845, FERC ruled last week.

The commission’s order Thursday marks the second time MISO has been directed to refine its proposed compliance with Order 845, meant to increase the transparency and speed of generator interconnection processes. (See MISO Almost There on Order 845.)

This time, MISO must clear up language relating to surplus interconnection service and studies of projects’ technological advancements (ER19-1823-002, et al.).

FERC said MISO still hasn’t properly explained why it gave itself 60 days to decide whether to conduct additional studies when an interconnection customer seeks to include technological advancements in its project prior to an interconnection facilities study agreement. The commission prescribed 30 days to decide on new studies and told MISO in December to either justify the 60-day timeline or halve it.

In response, the RTO had proposed to “perform the required studies and communicate the results to the customer” within 30 days “after receipt of any additional data that MISO requires the interconnection customer to submit.” FERC’s latest ruling said that language could still allow MISO more than 30 days to decide whether a technological advancement to a project would constitute a material modification and warrant further study.

MISO Order 845 — | *National Renewable Energy Laboratory*

FERC also said MISO interchangeably used the titles “Surplus Interconnection Service Agreement” and “Surplus Interconnection Service Interconnection Agreement” in monitoring and consent agreements, which the RTO drafts to list the roles and responsibilities of a transmission owner and an interconnection customer seeking to interconnect through surplus interconnection service.

“We find that the proposed revisions create a lack of clarity that may cause confusion to interconnection customers,” the commission said, suggesting that MISO might avoid confusion by swapping the two terms with “Surplus Interconnection Facility’s Generator Interconnection Agreement.”

But FERC did accept MISO’s fuller description of how it determines which projects in its annual Transmission Expansion Plan are “contingent facilities.” Order 845 defines those facilities as a generation project’s unbuilt interconnection facilities and network upgrades that, if delayed or canceled, “could cause a need for restudies of the interconnection request or a reassessment of the interconnection facilities and/or network upgrades and/or costs and timing.”

FERC said MISO’s description of the impact criteria it uses in its distribution factor analysis fit the bill.

No Rehearing

The commission also denied the American Wind Energy Association’s rehearing request that it direct MISO to remove “barriers” preventing interconnection customers from exercising the option to build network upgrades.

AWEA contested the compliance filing’s inclusion of Tariff language describing a TO’s right to self-fund network upgrades for interconnection customers. FERC last year ordered MISO to reinstate TOs’ rights to self-fund the network upgrades, and the RTO requested an independent entity variation in its compliance filing to note the change, which the commission accepted. (See MISO Gauging Aftershocks of TO Self-fund Order.)

AWEA argued that “interconnection customers have had very little success exercising the option to build since the commission issued Order No. 2003 and that the commission, in Order No. 845, intended to restore that right.”

But FERC agreed with MISO that “not harmonizing a transmission owner’s right to self-fund with the expanded option to build could impermissibly undermine a transmission owner’s right to self-fund.” It said the RTO had no choice but to reconcile Order 845’s expanded option to build for interconnection customers with the TOs’ right to elect to provide initial funding for standalone network upgrades.