Page 1073 – RTO Insider

July 17, 2020

FERC Orders Uplift Charges on PJM UTCs

FERC ordered PJM to begin billing up-to-congestion (UTC) transactions for uplift, calling the RTO’s current rules unjust and unreasonable.

PJM UTC uplift charges — Example of UTCs causing and profiting from negative balancing congestion | *FERC*

In its ruling Thursday, the commission found that UTC transactions are “similarly situated” to increment offers (INCs) and decrement bids (DECs) that accrue uplift under existing rules (EL14-37).

The commission said that even though it may be just and reasonable to treat UTCs differently than INCs/DECs regarding the bidding locations, as it did in 2018, that is not relevant to whether UTCs should be allocated uplift. (See FERC OKs Slash in Virtual B idding Nodes for PJM.)

“Although the commission has recognized that UTCs have certain characteristics that distinguish them from INCs and DECs, we find that those characteristics do not justify failing to allocate uplift to UTC transactions,” the commission wrote. “Though UTCs and INCs/DECs are different financial products, each are deviations from day-ahead positions that can impact uplift.”

FERC directed PJM to submit a replacement rate within 45 days that treats UTCs as if they were a DEC at their sink points and allocate them both real-time and day-ahead uplift.

Backstory

Thursday’s ruling followed seven years of debate among PJM and its stakeholders over whether uplift can be accurately pinpointed to a specific UTC, given the day-to-day variability of the energy markets. Some members have argued that there’s no proof that UTCs even cause uplift, let alone that they should be charged for it.

FERC instituted an investigation under Federal Power Act Section 206 on PJM’s allocation of uplift to virtual transactions in 2014. In January 2017, the commission extended PJM’s financial transmission rights forfeiture rule to cover UTCs, but it denied the RTO’s proposal to extend uplift charges to the trades as well.

By April 2018, FERC issued Order 844, which incorporated additional uplift transparency rules for all RTOs and ISOs, but it withdrew a requirement that grid operators categorize real-time uplift costs based on their causes and allocate them only to market participants “whose transactions are reasonably expected to have caused” the uplift. (See FERC Orders RTOs to Shine Light on Uplift Data.)

Then, last October, FERC issued an order requiring additional briefing to update whether PJM still wanted to charge uplift on all virtual trades. (See FERC Queries PJM on Virtual Transaction Rules.)

PJM’s brief said it still supports allocating uplift to UTCs. Because UTCs, like all virtual transactions in the day-ahead market, directly affect “the commitment and dispatch of resources, flows on transmission lines, LMP levels and the revenues that resources collect from the market,” UTCs contribute to uplift the same way as INCs and DECs and should be treated similarly, PJM said.

FERC’s ruling cited PJM’s Report on the Impact of Virtual Transactions from 2014 that found UTCs can impact unit commitment by affecting the dispatch of supply resources in the day-ahead market. The report said that when UTCs were removed from the day-ahead market, several generating units were decommitted while other units were committed — an indication that UTCs can impact unit commitment decisions.

While PJM’s report only considered the day-ahead market, “the changes in commitment decisions that were shown by removing UTCs represent the types of commitment and redispatch decisions that could be needed to adjust for the removal of UTC megawatts on certain nodes in the real-time market,” FERC said. “The change in commitment decisions can impact uplift.”

Besides PJM’s filings, the commission also cited analysis provided by the Independent Market Monitor showing that most real-time congestion charges are allocated to UTCs. FERC said the Monitor provided an example of how UTCs can collect “negative balancing congestion on the sink side of the transaction” and that they cause negative balancing congestion charges by contributing to “physically infeasible market flows” in the day-ahead market.

“We find that the Market Monitor’s analysis and supporting examples provide further support for our finding that UTCs can cause uplift in both the day-ahead and real-time markets,” the commission said.

July 17, 2020

FERC Issues Final Rule to ‘Modernize’ PURPA

FERC on Thursday revised how it enforces the Public Utility Regulatory Policies Act, giving state regulatory commissions more flexibility in how they establish avoided-cost rates for qualifying facilities and the ability to require those rates to vary over the span of a QF’s contract.

States may use fixed energy rates for QFs, but they will also be able to base them on projections of what energy prices will be at the time of delivery.

The commission’s final rule adopted most of the proposals in its Notice of Proposed Rulemaking issued in September last year (Order 872 ; RM19-15, AD16-6). (See FERC to Reshape PURPA Rules.)

Perhaps most notably, the commission had proposed reducing the threshold for the presumption that QFs in RTO/ISO territories have nondiscriminatory access to the wholesale markets from 20 MW to 1. But in the final rule, FERC adopted a 5-MW threshold.

FERC also gave state regulators more flexibility in administering its “1-mile rule” — the presumption that affiliated QFs located at least 1 mile apart are separate facilities. Regulators will be able to challenge that presumption if the facilities are located more than 1 mile but less than 10 miles apart. Facilities located 10 or miles apart will still automatically be presumed to be separate.

FERC PURPA — FERC headquarters | © *RTO Insider*

States will also be able to set QF energy rates based on the LMP in wholesale markets. FERC had proposed in the NOPR that the LMP itself represent utilities’ “as-available” avoided costs, but it changed that in the final rule to a rebuttable presumption.

“It’s been my view from the start that FERC should modernize our regulations in ways that not only meet our statutory obligations, but also protect consumers and preserve competition,” FERC Chairman Neil Chatterjee said. “Today’s rule accomplishes those goals. We will continue to encourage QF development while addressing concerns about how PURPA works in today’s electric markets.”

During FERC’s open meeting, held via teleconference Thursday, Chatterjee sought to defend the order against critics who said the commission was trying to effectively repeal PURPA or eliminate its protections for QFs. He asked staff member Joshua Kierstein, of the Office of General Counsel, whether the rule would do that.

“This final rule does not seek to repeal or eliminate any aspect of PURPA, which is a federal law that only Congress can modify,” Kierstein answered in a scripted response. “Congress has required that the commission from time to time revise its regulations implementing PURPA, and that is what this final rule does. … The changes in this final rule will enable the commission to continue satisfying the statutory requirements of PURPA, including that the rules encourage QF development. … The new flexibility the rule gives the states to develop an avoided-cost rate requires that the rate be the avoided-cost rate for the purchasing utility, which is what PURPA requires. …

“We expect that this increased optionality for accurately determining avoided cost will continue to provide encouragement for the development of small power producers and cogeneration, as required by PURPA,” Kierstein said. The rule will also provide more transparency into avoided-cost rate development, “both utilities and their customers, and QFs, are likely to receive more bang for their buck.”

Glick Demurs

As he did with the NOPR, Commissioner Richard Glick issued a partial dissent, saying that the rule would discourage QF development.

Although it included “some modest improvements” over the NOPR, the final rule “still aims to achieve what Congress has failed to do: gut the heart of PURPA, with very little reasoned decision-making,” he said during the meeting.

Glick noted that PURPA requires that utilities can’t treat QFs differently than their own resources, “but today’s final rule ignores this. QFs will no longer be guaranteed an option for a fixed-term contract that makes it easier to finance certain projects. Utilities when they self-sell certainly aren’t subject to such uncertainty.”

Commissioner James Danly responded directly to Glick when his turn came to comment on the rule. “It is inapposite to compare QFs and utilities with regard to guaranteed cost recovery,” he said. “The two types of facilities are in completely different legal and recovery mechanisms.” Congress noted “that QFs are not guaranteed cost recovery and that there’s a certain amount of risk that is assumed.”

Commissioner Bernard McNamee said the rule would continue to encourage QF development while “also ensuring we fulfill our other statutory duty, which is to protect customers from paying excessive rates by ensuring they are not paying more under PURPA contracts than they would if they obtained their power from a utility or the markets.”

In a joint statement, the American Public Power Association, Edison Electric Institute and National Rural Electric Cooperative Association applauded the rule. “FERC’s action will benefit electricity customers while further driving growth in renewable energy,” they said. “PURPA was enacted more than 40 years ago during a national oil crisis to promote increased energy conservation, efficiency and the growth of renewable energy. The energy mix and marketplace have changed significantly since then.”

The Solar Energy Industries Association, however, expressed disappointment. “The overall rule changes approved today will undermine the stated intention of the PURPA statute and stifle competition, allowing utilities to strengthen their monopolies and raise costs for customers,” Katherine Gensler, SEIA vice president of regulatory affairs, said in a statement. “We will continue advocating for reforms that strengthen PURPA and allow solar to compete nationwide.”

The rule takes effect 120 days after its publication in the Federal Register.

July 17, 2020

NYISO BIC Balks on Increased Reserves

NYISO stakeholders on Wednesday delayed a vote on the ISO’s proposal to procure up to 500 MW of additional reserves for Southeast New York (SENY) pending an additional cost analysis.

The Business Issues Committee tabled the proposal with a 68% roll-call vote on which many members abstained.

The ISO wants to procure up to 500 MW of additional 30-minute reserves in the SENY reserve region (zones G-K) as part of its Reserves for Resource Flexibility project. This proposal would increase SENY’s portion of the total statewide reserve requirement from 1,300 MW to 1,550 or 1,800 MW depending on the hour, said NYISO’s Ethan Avallone, who presented the proposal.

The proposal would shift current locational reserve procurements and would not increase the 2,620-MW procurement for the entire state.

The region’s current 30-minute reserves are used to bring transmission assets to emergency transfer criteria — below short-term emergency ratings — after suffering from the first worst contingency in SENY. The additional reserves would provide a market-based mechanism for obtaining resources to bring transmission assets to normal transfer criteria — below long-term emergency ratings — following a contingency, minimizing the need for ISO operators from having to employ out-of-market actions.

NYISO would procure an additional 250 MW for the hours beginning 6 and 22, with an additional 500 MW procured for hours beginning 7 to 21. There would be no increase for hours beginning 23 through 5.

NYISO reserves — Proposed SENY 30-minute reserve demand curve | *NYISO*

Unlike the existing 30-minute reserves, which are priced at $500/MWh, the incremental reserves would have a shortage price of $25/MWh. “This lower shortage price recognizes that reserves procured for emergency transfer criteria are a higher relative priority than reserves procured for normal transfer criteria,” the ISO said.

Avallone noted that NYISO plans to increase the $25/MWh demand curve point to $40/MWh as part of its separate A ncillary S ervice S hortage P ricing proposal.

Amanda De Vito Trinsey, representing New York City, asked for the delay, complaining that while the ISO had estimated the cost of the $25/MWh to be about $300,000 annually, it had not provided an analysis on the impact of the $40/MWh price, which the city had requested at previous stakeholder meetings.

“You’re having us vote before we see the impact analysis [on the $40/MWh price], which defeats the whole point of having an impact analysis,” she said.

“You’re setting a very poor precedent,” agreed Erin Hogan of the New York Department of State’s Utility Intervention Unit.

“I can’t say it any better, but I do agree with Amanda and Erin on that point,” added Chris Hall of the New York State Energy Research and Development Authority.

Howard Fromer, representing Bayonne Energy Center, estimated the $40/MWh price would be no more than 60% higher than the $25/MWh price — a total of about $480,000 a year.

“I don’t quite understand … the call for more delaying,” he said. “We’re talking about noise.”

A NYISO spokesman said after the meeting that the ISO had not endorsed the stakeholders’ cost estimates.

Trinsey countered Fromer, saying that the ISO doesn’t expect to implement the program for two years. “Why are we being rushed to a vote before seeing an appropriate consumer impact analysis?” she asked.

Matt Schwall of the Independent Power Producers of New York, who noted the $40 price will be voted on separately, said delaying the vote on the $25 reserves could impact investment decisions. “We have developers in New York who are looking at making investments in facilities today to respond to changes in the system that are coming in the next couple years. Even a six-month delay … has serious consequences for investors moving forward.”

A stakeholder who asked not to be identified urged members to respect NYISO operators’ concerns, saying the ISO has leaned on “latent reserves” such as Indian Point, which will be completely shut down by April 2021 and peakers that will retire between 2023 and 2025.

“I am pretty appalled … that there appear to be parties that are going to take a stand against reliability because it might have a cost of $480,000” a year, said Mark Younger of Hudson Energy Economics, who represents generation owner Indeck Energy Services and other suppliers Mercuria Energy America and Eastern Generation.

“That’s a gross mischaracterization of what I said,” responded Hogan.

Andy Antinori of the New York Power Authority pressed ISO officials on how long it would take to conduct the analysis of the $40/MWh shortage price.

Avallone initially declined to answer, saying, “We do intend to move forward on the vote today.”

But Tariq Niazi, the ISO’s senior manager for consumer interest liaison, said information on the impact of the $40/MWh shortage price would be included as part of the impact analysis of the Ancillary Services Project, which the ISO hopes to present in August.

With that, Trinsey successfully moved to table the vote to recommend the proposal to the Management Committee.

Fromer said after the vote, however, that there is “precedent” for the MC considering proposals without a BIC recommendation.

July 17, 2020

FERC Rejects Net Metering Challenge

FERC on Thursday rejected a request by a purported ratepayer group that could have ended net metering for rooftop solar generation, prompting relief among state regulators and renewable power advocates (EL20-42).

The commission unanimously rejected the New England Ratepayers Association’s (NERA) petition for declaratory order asking it to essentially outlaw net metering by ruling that FERC has exclusive jurisdiction over sales of rooftop solar power.

NERA asked FERC to assert jurisdiction over energy sales from rooftop solar facilities and other distributed generation located on the customer side of the retail meter whenever their output exceeds the customer’s demand or the energy from such generators is designed to bypass the customer’s load.

The association said such transactions were wholesale sales in interstate commerce, which should be priced at the utility’s avoided cost of energy if the sale is made under the Public Utility Regulatory Policies Act of 1978 or a just and reasonable wholesale rate if the sale is made pursuant to the Federal Power Act. Making such sales subject to the FPA might have required individual homeowner-generators to have a rate on file with FERC, a mandate that critics said would virtually eliminate net metering.

FERC Net Metering — Solar panels line the roof of a turkey barn in Iowa. | *Iowa Farm Bureau*

The commission said it was using its discretion in declining to address the issues raised by the petition. “We find that the issues presented in the petition do not warrant a generic statement from the commission at this time,” it said, adding that the petition “does not identify a specific controversy or harm that the commission should address in a declaratory order to terminate a controversy or to remove uncertainty.”

FERC also said NERA did not meet the requirements for an enforcement action under PURPA because such actions are limited to electric utilities and qualifying small power production and cogeneration facilities.

Widespread Opposition

Thousands of individuals and groups filed comments urging FERC to reject the petition. State officials and others alleged it would upset two decades of legal precedent supporting state and local policies used by 2.3 million net metering participants in 49 states. (See Thousands Oppose Bid to Undo Net Metering.)

Other commenters complained NERA was a front for investor-owned utilities and the fossil fuel industry and said its funding made it akin to a trade group.

Only a handful of groups — Americans for Tax Reform, Californians for Green Nuclear Power, CAlifornians for Renewable Energy, Citizens Against Government Waste, Competitive Enterprise Institute and the Heartland Institute — supported the petition.

Questions over Net Metering Remain

Although the commission was unanimous in rejecting the petition on procedural grounds, Commissioners Bernard McNamee and James Danly issued concurrences expressing concern over the substantive issues raised.

“The commission’s order is not a decision on whether the commission lacks jurisdiction over the energy sales made through net metering; nor is it a decision on the merits of the issues raised by and contained in the petition,” McNamee said. “I also note that, as a general proposition, I think it is best to decide important legal and jurisdictional questions, like the ones raised in in the petition, when applying the law to a specific set of facts, such as in a Section 206 complaint, or through a rulemaking proceeding.”

Danly said the petition raised “difficult legal questions,” including the rate treatment for excess generation and the boundary between federal and state jurisdiction.

“I have yet to reach any conclusion regarding either rate treatment or jurisdictional boundaries, but I am certain that these are questions of profound importance and the commission will eventually have to address them,” Danly said. “I am concerned that dismissing the petition on procedural grounds may well result in a patchwork quilt of conflicting decisions if the questions raised in the petition are instead presented to federal district courts across the country. While the federal courts are more than capable of adjudicating pre-emption claims, they are not steeped in the history of the Federal Power Act nor in matters of national energy policy. Confusion, delay and inconsistent rules — some of which will apply to individual states or parts of states — will be the inevitable result.”

NERA President Marc Brown said while he was disappointed by FERC’s decision, he agreed with McNamee’s and Danly’s comments. “We will review the decision to determine the appropriate course of action we will take in order to ensure that ratepayers are protected from the billions of dollars in cost-shifts unwittingly and unfairly paid by ratepayers to support the rooftop solar industry,” he said in a statement.

States, Renewable Supporters Rejoice

State officials and solar power backers nonetheless rejoiced at the ruling.

“This decision is a victory for state regulators and for anyone with a vested interest in net metering policy,” said Mississippi Public Service Commissioner Brandon Presley, president of the National Association of Regulatory Utility Commissioners. “The timing of this decision is also excellent, as NARUC and our members can prepare for next week’s National Policy Summit knowing that we have been able to uphold a core principle of state utility regulation.”

“FERC made the right call,” said Joseph L. Fiordaliso, president of the New Jersey Board of Public Utilities. “New Jersey has relied on FERC precedent for 20 years as we’ve advanced our net metering programs. As we explained in our pleading, net metering is a retail billing method.”

“As the leader of a coalition of conservative groups, solar advocates, state regulators and elected officials from both sides of the aisle in opposition to this petition, [the Solar Energy Industries Association] applauds FERC’s unanimous decision to dismiss this flawed petition,” said SEIA CEO Abigail Ross Hopper. “We are grateful to the state utility commissions and many other partners who strongly opposed this petition. We will continue working in the states to strengthen net metering policies to generate more jobs and investment, and we will advocate for fair treatment of solar at FERC where it has jurisdiction.”

Gregory Wetstone, CEO of the American Council on Renewable Energy, said moving net metering from state to federal jurisdiction “would have severely limited its appeal by lowering participants’ compensation rate.”

“While we are gratified that today’s decision respects the Federal Power Act, we will continue to stay vigilant about protecting forward-looking state energy policies that deliver the pollution-free renewable power Americans want,” Wetstone said.

“Had FERC taken up NERA’s arguments, it would not only have upended the legal basis for net metering programs but would also have severely hampered ongoing efforts by numerous states to develop programs that value [distributed energy resources] with greater accuracy,” the Institute for Policy Integrity at New York University School of Law said.

July 17, 2020

FERC Proposes Tougher Hydro Safety Rules

Responding to the 2017 Oroville Dam incident, FERC on Thursday proposed tougher safety standards for commission-regulated hydropower projects, including a two-tier safety inspection process (RM20-9).

The Notice of Proposed Rulemaking would change part 12 of FERC’s regulations to codify existing guidance requiring certain licensees to develop dam safety and public safety programs and update regulations regarding incident reporting.

The two-tier inspection structure would include a comprehensive assessment and a periodic inspection.

As under current rules, an inspection by an independent consultant would continue to be required every five years, but the scope would alternate between a “comprehensive” assessment and a “periodic” inspection. These inspections will be in addition to FERC staff’s safety inspections.

The alternating two-tier structure is similar to those used by the Bureau of Reclamation and the U.S. Army Corps of Engineers. “The comprehensive assessment would require a more in-depth review than the current part 12 inspection, would formally incorporate the existing potential failure modes analysis process and would require a semiquantitative risk analysis,” FERC said. “The periodic inspection would have a narrower scope than the current part 12 inspection and focus primarily on the performance of project works between comprehensive assessments.”

FERC Hydro Safety Rules — Oroville Dam on Feb. 17, 2017 | *California Department of Water Resources*

FERC also would change how it evaluates the qualifications of the consultants to ensure those conducting inspections have sufficient expertise for site-specific conditions under what is known as the Part 12D Program.

The change follows a recommendation by the Federal Emergency Management Administration that “the inspection team should be chosen on a site-specific basis considering the nature and type of dam … [and] should comprise individuals having appropriate specialized knowledge in structural, mechanical, electrical, hydraulic and embankment design; geology; concrete materials; and construction procedures.”

FERC said the change “reflects the reality that, for many of the hydropower projects under the commission’s jurisdiction, a single independent consultant will not possess the appropriate degree and diversity of technical proficiency necessary to evaluate all aspects of the project.”

The current requirement that an independent consultant be a licensed professional engineer with a minimum of 10 years’ experience in “dam design and construction and in the investigation of the safety of existing dams” would remain. “However, as proposed, this requirement would apply only to the designated independent consultants and not to other supporting members of the independent consultant team,” FERC said.

Oroville Dam Failure

The commission said the proposed changes are the product of recommendations that resulted from an analysis of the February 2017 incident in which the Oroville Dam in California saw major damage to its primary spillway and the first activation of its auxiliary spillway. About 180,000 people were forced to evacuate the surrounding area.

An independent forensics team concluded there was no single cause of the failure of the dam’s spillway. “The incident was caused by a complex interaction of relatively common physical, human, organizational and industry factors, starting with the design of the project and continuing until the incident,” the report said. (See Report: Regulatory Failure Caused Oroville Incident.)

FERC said the changes were “substantially complete” before the failures of the Edenville and Sanford dams in Michigan in May, which it said remain under investigation. About 10,000 central Michigan residents had to evacuate after the failure of the Edenville Dam after heavy rainfall. FERC revoked the dam owner’s license in 2018 over concerns about the facility not being able to handle floods. (See Michigan Dam with Prolonged Safety Issues Fails.)

Comments on the NOPR are due 60 days after publication in the Federal Register.

The commission also said it plans to update and add new chapters to its engineering guidelines document. Drafts will be issued in four advisory dockets: AD20-20 (Supporting Technical Information Document); AD20-21 (Part 12D Program); AD20-22 (Potential Failure Modes Analysis); and AD20-23 (Level 2 Risk Analysis).

July 17, 2020

FERC Briefs: July 16, 2020

FERC issued a flurry of orders Thursday in its last open meeting before September. (The commission does not meet in August.)

The commission:

CAISO

Ordered additional briefing concerning the calculation of the return on common equity for the DATC Path 15 upgrade to reflect the commission’s revised ROE methodology in Opinions 569 and 569-A. The 84-mile, 500-kV transmission line was built to relieve congestion on the existing Path 15 corridor between northern and southern California (ER17-998-001).
Upheld the result of its January 2020 order that denied Pacific Gas and Electric’s request to recover 100% of the costs from its abandoned Central Valley Power Connect Project (ER19-2582-001).

ISO-NE

Rejected a complaint by Liberty Power Holdings alleging that ISO-NE inappropriately refused to correct a $200,000 billing error resulting from Eversource Energy’s reporting to the RTO load for the Smith & Wesson plant in Western Massachusetts that was mistakenly attributed to Liberty. The commission said Liberty waited too long to seek a correction (EL20-27).
Approved Paper Birch’s request to make wholesale sales of electric energy, capacity and ancillary services at market-based rates in the NYISO and ISO-NE markets. The order said the commission intends to release affiliate information for which Paper Birch requested privileged treatment (ER20-1120).

MISO

Approved an uncontested settlement on Entergy Arkansas’ tariff revisions to ensure the return of excess accumulated deferred income taxes resulting from the Tax Cuts and Jobs Act of 2017 (ER18-1247-001).
Upheld the result of its November 2019 order denying the Louisiana Public Service Commission’s complaint alleging that Entergy Services’ off-system sales of energy to third-party power marketers and others for the benefit of Entergy Arkansas violated its generation and transmission pooling arrangement (EL19-50-001). (See La. PSC Complaints Denied in Entergy System Disputes.)

NYISO

Approved in part and denied in part Alcoa Power Generating’s requests for waivers of the requirements for the company’s Tapoco and Long Sault Divisions to have open-access transmission tariffs, maintain an Open Access Same-Time Information System, and comply with the Standards of Conduct and other regulations (ER20-1580).

PJM

FERC orders — DATC Path 15 tx line | *Duke-American Transmission Co.*

Accepted PJM MRC Briefs: Dec. 19, 2019.)
Upheld its January 2020 ruling allowing Potomac-Appalachian Highline Transmission to recover certain advertising and public advocacy costs incurred during its efforts to win approval for the canceled PATH project (ER09-1256-006). (See FERC Grants Recovery on PATH Project Costs.)
Upheld the result of its October 2019 order finding that Dominion Energy Virginia met its burden under Section 205 of the Federal Power Act to show that changing to the 12-coincident-peak transmission cost allocation method is just and reasonable because it is based on Dominion’s transmission planning (ER19-1661-002). (See FERC OKs New Dominion Tx Rate Structure.) (This order had not been posted to the commission’s website as of press time.)
Ordered hearing and settlement procedures in the North Carolina Eastern Municipal Power Agency’s complaint that Duke Energy Progress’ 11% ROE in the companies’ power supply agreement is excessive. It rejected Duke’s request to dismiss the complaint and set a refund effective date of Oct. 11, 2019 (EL20-4).
Ordered a paper hearing to determine a reasonable proxy for determining the capital structure and cost of capital for a merchant generator in response to a petition for a declaratory order seeking guidance on the commission’s cost-based methodology for compensating reactive power generators. The petition was filed by Ares EIF Management; Competitive Power Ventures; Invenergy Thermal Development; J-Power USA Development; Panda Power Generation Infrastructure Fund; Tenaska; and Vistra Energy (EL19-70).
Accepted PSEG Energy Resources & Trade’s tariff revisions to cancel reactive power service tariff records for the Yards Creek Generating Facility. PSEG has proposed selling its 50% interest in the facility, a 420-MW hydro facility in Warren County, N.J. (ER20-1441).
Ordered hearing and settlement procedures on the continued justness and reasonableness of Constellation Power Source Generation’s reactive supply and voltage control rates (ER17-801-006).

SPP

Reduced ITC Great Plains’ adder for being an independent transmission company from 100 basis points to 25 in response to a complaint by the Kansas Corporation Commission (EL19-80).

July 17, 2020

Xcel to Begin Seasonal Operation at 2 Coal Plants

Minnesota regulators this week approved Xcel Energy’s request to operate two of its four coal units on a part-time basis.

The Minnesota Public Utilities Commission’s order Wednesday allows Xcel to idle its Allen S. King Generating Station and Sherburne County Generating Station Unit 2 during the low-demand spring and fall shoulder seasons (20207-164928-02). Xcel asked in December for permission to implement seasonal operations.

Xcel spokesperson Matt Lindstrom said the utility expects to begin seasonal operations this fall.

The PUC said the move will save customers money and represents “a significant step toward meeting Minnesota’s greenhouse gas emission-reduction goal.” It opened a docket last year to investigate the self-scheduling of coal plants in the state.

“This is an important proposal, and I appreciate Xcel Energy bringing it forward,” Commissioner Matt Schuerger said in a release. “I think this highlights Xcel’s focus on saving their customers money, on meeting Minnesota’s environmental policies and in being responsive to the investigation the commission opened.”

The Union of Concerned Scientists applauded the order. The organization has blasted coal self-commitments as expensive and wasteful. In a recent UCS report, the group named Xcel subsidiary Northern States Power one of the worst offenders for uneconomic operation, saying it ran the two coal plants at a $56.9 million loss in 2018. (See UCS Analysis Knocks Coal Self-commitments.)

Xcel Energy coal plants — Sherco Generating Station | *Xcel Energy*

“Xcel Energy was identified as one of the most egregious actors in our analysis, but this news is a welcome change in behavior,” UCS Senior Energy Analyst Joe Daniel said in an emailed statement. “Xcel, like most utilities, was initially reluctant to recognize the costliness of uneconomic self-commitment. But now, both the utility and the state commission have codified a path forward that will save Xcel’s customers millions of dollars, not to mention the public health benefits of reduced pollution.

“Had all utilities given up their uneconomic coal plant operations in 2018, the average family in Minnesota would have saved $5/month on their electricity bills. Unfortunately, other utilities in Minnesota remain reticent when it comes to changing their operations,” Daniel said.

Xcel said its own analysis found the move could save its customers up to $1.45 million in 2020 and up to nearly $3.5 million by 2023. The commission said customer savings could be reflected in Xcel’s next rate case. The utility also estimated it will save about $13 million in operations and maintenance and another $7 million in capital costs through 2023.

Xcel also said seasonal operations would cut its greenhouse gas emissions by 4 million tons in 2020 and a little more than 7 million tons by 2023. The commission said the decrease could account for a quarter of Minnesota’s goal to reduce emissions 30% below 2005 levels by 2025.

“As we lead the clean energy transition with a plan to reduce carbon emissions 80% by 2030 and pursue our vision of 100% carbon-free electricity by 2050, we’ll pursue innovative ideas like seasonally operating our coal plants,” Xcel said in an emailed statement. “These changes will allow us to add more renewable energy for our customers, reduce carbon emissions and save money on fuel and operations costs, savings we can deliver to our customers.”

But even the seasonal operation will be finite, as both plants are slated for retirement by 2030. Xcel said the King plant will close in 2028 while all three Sherco units will shutter by 2030. The closures will make good on the company’s promise to quit coal by 2030 in its Upper Midwest service territory. (See Xcel Latest MISO Utility to Pledge Zero Coal.)

Lindstrom said that as Xcel idles coal plants, it’s focusing on avoiding workforce layoffs. He said the company will probably let some of the positions at its coal plants disappear as employees retire.

“As we look toward the future of our system and the eventual retirement of our coal plants, we are working with employees, communities and other stakeholders to develop specific plans for each area to determine how we can bring new jobs and capital investment to the region. We’ve transitioned coal plants in the past and believe we can do so without layoffs, by normal attrition and job retraining,” Lindstrom said.

July 17, 2020

MISO Keeps Wait-and-See COVID-19 Approach

MISO is likely still months away from returning its full workforce on-site to its multiple offices in the Midwest and South, based on indications this week from its pandemic incident response team.

The RTO said that while it is creating detailed return-to-work plans, it remains in a holding pattern and is still advising most non-control room employees to continue working from home.

MISO COVID-19 — Angela Weber, MISO | © *RTO Insider*

“The problem for us, and I think everyone right now, is the situation is fluid, and we don’t have a solution yet,” MISO Executive Director of Incident Response Angela Weber told MISO South stakeholders during an Entergy Regional State Committee teleconference Monday. “It’s something we’re still working on and taking our time to do it right.”

MISO meets regularly with an infectious disease doctor and an epidemiologist for updates and advice, Weber said. “We make sure we’re responding in a very measured and informed way.”

The RTO is also monitoring infection rates around the country and pairing the Centers for Disease Control and Prevention’s recommended 14 days of sustained declining infection rates with adequate testing, contact tracing and ample hospital capacity, Weber said. If those criteria are satisfied, MISO would begin moving to normal operations, she said.

Weber’s comments came as the nation’s daily count of new infections nearly hit 66,000, the 37th straight day that the seven-day average of new infections in the U.S. had trended upward. Total COVID-19 deaths, which lag infections, are approaching 140,000.

Most of MISO’s non-control room employees have been working from home since mid-March, and the RTO has isolated its control room staff by forbidding other staff from entering control room buildings. (See Heat Counteracts COVID-19 Impact on MISO Load.) MISO’s meeting spaces are closed to in-person stakeholder meetings through at least the end of the year.

The grid operator has also expanded the financial and mental health counseling it offers its employees, Weber added.

July 16, 2020

Record Number of Entrants Line up for MISO Queue

Facing an unprecedented number of new generator applicants, MISO this week reaffirmed its aim to speed up its interconnection queue.

The grid operator hopes to shrink the time it takes to complete generation interconnection agreement negotiations and clear the queue’s three-part definitive planning phase (DPP), when it performs interconnection studies.

Currently, the queue’s DPP alone takes approximately a year to complete. Combined with interconnection agreement negotiations, the timeline grows to about 505 days. Earlier this year, stakeholders asked through a formal submission to the Steering Committee that MISO address DPP delays.

MISO has said that if the queue’s DPP and GIA negotiations could be shortened to a year total, it would further its goal of aligning the interconnection queue with planning under its annual Transmission Expansion Plan. (See MISO Targets Swifter Queue Processing.)

A speedier process could keep MISO executing interconnection agreements as it prepares to face its largest-ever queue. The June 2020 cycle of prospective projects could bring the interconnection queue to more than 750 projects totaling 112 GW.

Through early June, the RTO was performing interconnection studies on 406 projects totaling 62 GW, more than half of it solar generation. More than 350 additional projects totaling more than 50 GW applied to enter the interconnection queue before the June 25 deadline, interconnection engineer Cody Doll told the Interconnection Process Working Group on Tuesday.

Not all of the 350 projects may survive MISO’s application validation. “We won’t know until we go through and validate the projects which ones will be in the 2020 cycle,” Manager of Resource Utilization Project Management Jesse Phillips said.

This isn’t the first time the queue will exceed 100 GW. It peaked at a proposed 101 GW worth of projects in 2019 before declining as projects withdrew. MISO says about 20% of projects entering the queue complete the interconnection process.

“The cycles are massive, and they’re not slowing down,” Doll said. “It’s going to lead to challenges because there are so many projects.”

The 2020 cycle was the first time MISO used a completely online application process. (See Wary of Contagion, MISO Bars Visitors for 2020.)

Doll said that with increased queue entrants, MISO’s ability to handle the administrative processing of the interconnection requests may be stretched thin. “We may need to throw more people at certain tasks,” he said.

Doll also said affected-system studies, where MISO must wait on other RTOs to study projects near the seams for impacts, remain an obstacle to shortening the timelines.

Several active queue cycles dating from 2017 are currently delayed at least into fall by ongoing affected-system studies. SPP’s studies are affecting projects in the Central and West planning regions, while PJM’s impact the East region’s projects.

Phillips said MISO continues to work with SPP on how the two can cut down on the time needed to conduct affected-system studies.

MISO’s next queue application deadline is March 18, 2021.

July 16, 2020

Panel: Much More Tx Needed for New England OSW

New England needs to build much more onshore transmission to facilitate the incoming surge of offshore wind generation, panelists on a Northeast Energy and Commerce Association webinar said Wednesday.

NECA convened the webinar to discuss how much offshore wind New England can integrate, with representatives from the New England States Committee on Electricity (NESCOE), Anbaric Development Partners and RENEW Northeast summarizing the results of studies their organizations requested from ISO-NE Planning Advisory Committee Briefs: June 17, 2020.)

NESCOE counsel and analyst Ben D’Antonio provided an overview of ISO-NE’s findings under the organization’s requested assumptions. The RTO concluded that about 5.8 GW of offshore wind can be interconnected using AC transmission without significant upgrades to the onshore grid. That’s “if you do it in a strategic way,” at certain points of interconnection, D’Antonio said.

But “above that threshold … major reinforcements to the system were identified as being necessary.” The RTO identified at least four 345-kV onshore lines that would need to be built to facilitate additional offshore resources.

New England Offshore Wind — ISO-NE identified several strategic points of interconnection for offshore wind resources that would negate the need for major onshore transmission upgrades — but only up to 5.8 GW. | *ISO-NE*

It also determined that it’s possible to interconnect up to an additional 2.2 GW — for a total of 8 GW — through long-distance HVDC lines without the need for new onshore transmission. But regardless of the solution, it found the costs to reaching the 8-GW mark were comparable: about $1 billion, D’Antonio said.

Perhaps more stark, however, is the huge amount of renewable energy that would be “spilled,” or curtailed, even with the additional transmission identified: more than 15 TWh/year. Most of that is attributable to oversupply during the fall and spring shoulder months, when load is low, and not to transmission congestion.

“This loss of clean generation can undermine state initiatives to reduce our carbon footprint,” said Katie Bellezza, senior vice president of commercial management and strategy for Novatus Energy, a RENEW member. RENEW’s study focused on Maine’s existing onshore wind, which already experiences significant curtailment.

“Land-based wind and new transmission is currently the least-cost renewable resource available in New England,” she said. “However, due to smaller procurements, it’s difficult to justify those transmission costs. With infrequent onshore renewable procurements of limited scale, we really need to look at other ways besides procurement to fund transmission.”

Anbaric requested that ISO-NE look at higher penetration levels than NESCOE, up to 12 GW. “When we put that request in just last year, it seemed potentially pretty ambitious, but it’s just been remarkable to see the [state OSW] goals increase,” said Peter Shattuck, Anbaric senior vice president for communications.

“When we look big-picture, what we need to avoid is the sort of situation we have now in Maine, where transmission was considered essentially an afterthought, and now there are a lot of bottled-up resources,” he said.

Shattuck also reviewed Anbaric’s proposed undersea transmission network and the Brattle Group’s analysis of it. (See Brattle Study Highlights Benefits of Offshore Grid.)

Moderator Mary Usovicz, principal of consulting firm MUConnections, brought up Eversource Energy and National Grid’s finalist bid in ISO-NE’s first competitive transmission solicitation under National Grid, Eversource Finalist for Boston Tx Plan.)

Usovicz asked the panelists whether they thought there was a better solution.

Shattuck, whose company submitted its own proposal, said, “It just seems like this decision was made on a very narrow, capital-cost basis, and that [basis] risks deferring the upgrades that are going to be needed [for OSW]. … It was essentially a missed opportunity to think bigger picture and really reflect the moment that we’re in right now in New England, where we need a grid that’s centered on renewables.”

“I’ll just kind of state the obvious and say that [decision] was done for reliability, and trying to right-size a solution for reliability is a little bit different than trying to right-size it for maybe a public policy-related issue,” D’Antonio said.