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August 18, 2024

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FERC Refuses Rehearing of PG&E-San Francisco Dispute

FERC on Thursday denied Pacific Gas and Electric’s request for rehearing in a case that has pitted the utility against the city and county of San Francisco for more than 18 years over PG&E’s application of its wholesale distribution tariff (WDT) to the municipal customers of San Francisco’s public utility (EL15-3-005, EL5-704-027).

The utility, the San Francisco Public Utilities Commission (SFPUC), operates a hydroelectric power project in the Hetch Hetchy Valley, near Yosemite National Park, and owns transmission lines that bring power from the Sierra Nevada to San Francisco.

It supplies electricity to schools, public housing tenants, libraries and municipal departments using the distribution system PG&E owns and operates in San Francisco — making the publicly owned utility both a customer and competitor of PG&E.

Since 2014, San Francisco has argued to FERC that PG&E has unreasonably denied distribution service to many of its 2,200 metered interconnection points under section 212(h) of the Federal Power Act.

The section prohibits mandatory retail wheeling such as forcing PG&E to deliver another utility’s power through its distribution lines. But it exempts cities and counties where “such entity was providing electric service to such ultimate consumer on the date of enactment of this subsection [Oct. 24, 1992].”

A FERC administrative law judge issued an initial decision in November 2016 that supported San Francisco’s argument. It cited the commission’s orders under Suffolk County Electric Agency (96 FERC ¶ 61,349) from November 2001. In that line of decisions, known as Suffolk I-IV, FERC said section 212(h) grandfathered classes of customers, not individual customers at specific delivery points.

“The Commission’s orders and opinions … support San Francisco’s argument that grandfathering applies to the class of customers that was eligible to receive wholesale distribution service on October 24, 1992, regardless of where in the city those customers may be located now or in the future,” the ALJ wrote. The judge defined the “class” of customers in the case as all “municipal public purpose load” in San Francisco.

PG&E, in contrast, contended that only “points of delivery” that existed prior to Oct. 24, 1992, could be grandfathered under its WDT. Customers that had relocated since that time were ineligible, it said.

FERC Overturned

In a November 2019 order, FERC disagreed with the ALJ’s decision. It found the Suffolk precedent inapplicable and said PG&E had not unreasonably denied service to some of San Francisco’s end users.

“The commission explained that San Francisco’s ‘class of customer’ approach would entitle all municipal public purpose load as designated by San Francisco that was eligible to receive wholesale distribution service on October 24, 1992,” FERC explained in Thursday’s order. “Ultimately, the commission concluded … that PG&E’s point of delivery approach to determining which San Francisco customers qualify for service under the WDT was just.”

The D.C. Circuit Court of Appeals reversed FERC’s decision in January 2022. It found that FERC’s interpretation of section 212(h) and PG&E’s tariff were too narrow, and its “attempts to defend its interpretation [were] unpersuasive.”

“That the tariff references ‘points of delivery’ does not necessarily imply that only specific points of delivery may be grandfathered, and those references to ‘points of delivery’ do not change the fact that the tariff expressly references the criteria of Section 212(h)(2),” it said.

The court criticized FERC’s orders in the case as demonstrating a “troubling pattern of inattentiveness to potential anticompetitive effects of PG&E’s administration of its open-access tariff.” Faced with claims that PG&E was refusing service to San Francisco customers, FERC “fell short of meeting its duty to ensure that rules or practices affecting wholesale rates are just and reasonable,” it said.

The appeals court sent the case back to FERC on remand. (See San Francisco Wins Against PG&E, FERC in DC Circuit.)

FERC issued a new decision in October that followed the court’s direction and agreed with San Francisco that its precedent did not limit grandfathering to a fixed location.

“The commission concluded that San Francisco’s loads within the customer classes served on October 24, 1992, are entitled to grandfathered service under the WDT, granted the complaint filed by San Francisco, and directed PG&E to submit revised WDT provisions,” FERC noted Thursday.

PG&E requested a rehearing.

PG&E Denied

In its request, “PG&E argues that the commission in the order on remand exceeded [its] authority in FPA section 212(h),” FERC noted. “PG&E urges the commission to set aside Suffolk County because, according to PG&E, the Suffolk County customer-class approach to grandfathering is inconsistent with the plain language of the statute, the intent of the statute in its legislative history, and the concept of grandfathering.”

PG&E also contended that “even assuming Suffolk County is valid and applicable precedent, the commission in the order on remand failed to address the potential for harmonizing PG&E’s proposed delivery-point methodology with the Suffolk County customer-class approach.”

FERC rejected PG&E’s arguments.

“PG&E asserts that the ‘customer-class approach’ can be reconciled with grandfathering based on points of delivery to provide service to a specific type of customer within a defined service area, because limiting grandfathering eligibility does not conflict with the text or intent of section 212(h),” FERC said.

But “in the order on remand, and as further discussed here, the commission has defined a coherent class of San Francisco customers eligible for grandfathering,” FERC said. “As the D.C. Circuit explained, the WDT ‘allows grandfathering of a customer San Francisco served under the prior interconnection agreement even though the customer seeks [WDT] service at a new delivery point.’

“Consistent with Suffolk County, eligibility under FPA section 212(h) therefore extends not only to the customers who were actually receiving service on October 24, 1992, but also to all subsequently interconnected customers of the same class.”

Second Case

In its January 2022 decision, cited above, the D.C. Circuit reversed FERC in a second case involving PG&E’s provision of distribution service in San Francisco.

In that case, the city and county contested PG&E’s refusal to provide lower-voltage secondary service to many sites within the city. PG&E instead offered to connect higher-voltage primary service, which requires the installation of transformers and carries higher fixed costs for ratepayers.

The city argued that the practice violated PG&E’s WDT.

The court remanded the matter back to FERC after overturning the commission’s unanimous 2020 decision rejecting San Francisco’s complaint.

In December, FERC ordered settlement judge procedures for the then three-year-old dispute. (See Settlement Hearing Ordered for PG&E, SF Distribution Dispute.)

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New York PSC Approves 20% Installed Reserve Margin

The New York Public Service Commission on Thursday approved a slight increase to the amount of reserve resources that load-serving entities must have available for the upcoming capability year (07-E-0088).

The New York State Reliability Council (NYSRC) had in December proposed raising the installed reserve margin from 19.6% to 20% for the 2023/24 capability year, which begins May 1 (05-E-1180). The figure equates to an installed capacity requirement of 120% of forecasted peak load for the year.

The council told the PSC it based its decision on the addition of 549.3 MW of wind generation and the need to maintain 350 MW of operating reserves during load shedding. It calculated the figure using the GE MARS system to examine factors such as demand uncertainty and scheduled or forced outages to establish a value above forecasted peak such that the loss-of-load expectation from resource deficiencies is fewer than 0.1 event days per year on average.

NYISO supported the proposal, as its own analyses yielded an IRM of 19.9%; 20% was “within a range of reasonable IRM levels that will maintain reliability.”

The PSC also said that the adopted IRM will “not have a significant adverse impact on the environment.”

The NYSRC will re-evaluate the IRM before the end of the year and submit another value should conditions change.

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PJM MRC/MC Preview: March 22, 2023

Below is a summary of the agenda items scheduled to be brought to a vote at the PJM Markets and Reliability Committee and Members Committee meetings Wednesday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.

Markets and Reliability Committee

Consent Agenda (9:05-9:10)

The committee will be asked to endorse as part of its consent agenda:

B. proposed revisions to Manual 12: Balancing Operations resulting from the manual’s periodic review;

C. proposed revisions to Manual 14C: Generation and Transmission Interconnection Facility Construction; and

D. proposed revisions to Manual 37: Reliability Coordination.

Endorsements (9:10-9:50)

1. Periodic Review of Default CONE and ACR Values (9:10-9:30)

PJM’s Skyler Marzewski will review the proposed default cost of new entry (CONE) and avoidable-cost rate (ACR) values resulting from the Quadrennial Review. The values for most resource types would rise under the proposal, largely from changes to investment tax credits under the Inflation Reduction Act and to the reference resources for some classes, based on last month’s first read. (See “Updated Default CONE and ACR Figures,” PJM MRC/MC Briefs: Feb. 23, 2023.) The committee will be asked to give an advisory vote on the values, as well as corresponding tariff revisions.

Issue Tracking: Periodic Review of Default CONE and ACR Values

2. Manual 11 Revisions (9:30-9:50)

PJM’s Joseph Tutino will review proposed revisions to Manual 11: Energy and Ancillary Services Market Operations, and the committee will be asked to endorse them.

Members Committee

Endorsements (11:10-11:30)

1. Periodic Review of Default CONE and ACR Values (11:10-11:30)

Marzewski will again review the proposed default CONE and ACR values, and the committee will be asked to give an advisory vote on the values and tariff revisions.

If approved by both committees, PJM anticipates filing the changes with FERC by the end of the first quarter with an effective date in November.

Issue Tracking: Periodic Review of Default CONE and ACR Values

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FERC Issues Show-cause Order on ComEd Formula Rate Protocols

FERC last week ordered show-cause proceedings for Commonwealth Edison’s (NASDAQ:EXC) formula rate protocols, saying that they may not provide adequate transparency and lack a proper framework for challenging rates (EL23-31).

The commission found ComEd’s protocols deficient in that they do not specify who can request information from transmission owners and what has to be provided in response, holding the utility to standards imposed by a 2012 order on MISO’s protocols. The commission has since opened proceedings on formula rate protocols regularly, seeking to ensure they are compliant with the provisions laid out in the MISO order. (See related story, PSCo, Idaho Power Comply with Show-cause Order.)

FERC said ComEd may not be meeting several of the disclosures the MISO order requires, including accounting practices for items where the commission hasn’t provided specific direction, changes in tax elections and correcting of errors and prior date adjustments. It also said there does not appear to be adequate detail on various types of costs, requirements on documents requests, and the identification of transactions related to mergers and how they may affect formula rates.

The MISO order also requires that the updated filing with FERC must follow an informational exchange period with interested parties, but the commission said ComEd’s protocols may not require an adequate time frame. The utility’s definition of which parties can participate in the review process may also be insufficient by not providing enough clarity.

The provisions for challenging formula rates may also be inadequate, FERC said, by not containing enough information about which parties can informally challenge the proposed inputs and how that challenge can be converted to a formal challenge with the commission if a resolution cannot be found. The order also says that the protocols do not contain enough clarity that such challenges are pursuant to the protocols themselves, rather than rule 206 of its Rules of Practice and Procedure.

ComEd has 60 days to respond to the order to either defend its protocols by showing how they comply with the commission’s requirements or to detail the changes it believes would be necessary to address the issues laid out in the order. Comments will be accepted within 21 days of the utility’s response to address whether the rates are just and reasonable or to suggest possible changes.

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ITC Defends ROFR Use for Major Tx Buildout

ITC Holdings (NYSE:ITC) says that a MISO 2016 market efficiency project is proof that rights-of-first-refusal laws benefit the grid and ratepayers.

Nathan Benedict, ITC’s regulatory strategy manager, said the transmission developer is so confident that the 50-mile, 345-kV line in Minnesota has been so successful that it will use the project as a case study when it files comments on transmission planning and cost containment with FERC later this week.

The $118 million Huntley-Wilmarth line was part of MISO’s 2016 Transmission Expansion Plan and would have been open to competitive bidding were it not for Minnesota’s more than decade-old ROFR law.

A handful of state legislatures in MISO’s footprint have introduced and sometimes tabled ROFR rules this year. The pressure to pass or set aside the laws is sharpened by the nearly $30 billion in new transmission spending the grid operator may recommend for its Midwest region under its long-range transmission plan (LRTP). Mississippi became the latest MISO state to enact a ROFR law when Gov. Tate Reeves signed legislation earlier this month.

Meanwhile, a pending complaint asks FERC to invalidate states’ ability to give incumbent utilities first shots on construction. (See MISO States Ramp Up ROFR Legislation.)

“It takes this discussion of who is going to build the transmission off the table and focuses on the transmission planning,” Benedict told RTO Insider. “We realize the most cost-effective measure to cost containment is coordinated transmission planning.”

“We feel at the end of the day, the Minnesota ROFR allowed us to manage costs effectively and respond to route, environmental and landowner concerns and secure a return on investment,” ITC Midwest Communications Manager Rod Pritchard said.

Pritchard said Huntley-Wilmarth was originally estimated at $108 million in 2016 dollars. He said the original design incorporated a single-circuit, H-frame wooden structure design that ultimately morphed into the costlier double-circuit, steel monopole design after input from the Minnesota Public Utilities Commission.

Possible routing changes meant project co-owners ITC Midwest and Xcel Energy (NASDAQ:XEL) were grappling with nine different route alternatives ranging from 45 to 57 miles that differed from MISO’s preliminary estimates, Pritchard said. At one point, landowner feedback collected by the Minnesota PUC could have pushed the line’s cost as high as $167 million.

Pritchard said that because of “collaboration with incumbent utilities and very aggressive cost-containment measures,” ITC and Xcel were able keep costs at $118.3 million. He called Huntley-Wilmarth an “excellent example of two transmission owners under the ROFR process working together” to provide the best routing and cost-containment decisions.

Huntley-Wilmarth is now alleviating constraints in southern Minnesota and northern Iowa, once one of MISO’s most congested spots, Pritchard said.

“There are segments of our industries where competition doesn’t make sense,” Benedict said, pointing to a 2022 Concentric Energy Advisors’ report that concluded competitive projects average 27% in cost increases and an additional 12 months of schedule delays.

Benedict said there’s no time to waste in energizing the new transmission necessary to bring record amounts of renewable energy online.

ITC estimates it will be responsible for roughly $1.4 billion to $1.8 billion of MISO’s first LRTP portfolio, which is valued at $10 billion. The developer will be involved in six of the 18 projects.

“As an incumbent, we have extensive knowledge of the communities, the geography … the intricacies of what it takes to plan transmission,” Benedict said.

He said states have the “prerogative” to remove the uncertainty from transmission-expansion decisions after FERC issued Order 1000 in 2011.

Benedict acknowledged that ITC differs from other utilities in that it’s an independent and unbundled transmission developer. He said the company’s independence from generation means it’s focused on how to best improve the transmission system.

“We really want an efficient grid that works best for customers,” he said.

Benedict said while transmission investment raises customer bills, it can also offset delivered energy costs and other portions of the bill.

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Texas Court Reverses PUC’s Uri Market Orders

A Texas appeals court on Friday reversed the Public Utility Commission’s orders to keep ERCOT wholesale prices at the $9,000/MWh cap during the deadly February 2021 winter storm, adding even more uncertainty to a market facing a yet-to-be determined redesign.

A three-judge panel for the 3rd Court of Appeals in Austin ruled that the PUC exceeded its authority by setting prices at their limit for four days during the storm. The commission said that the move was necessary to incent generation to stay online as ERCOT worked desperately to bring the grid back to life after it came within minutes of a total collapse. (See Texas PUC Won’t Reprice $16B Error.)

The court said the commission’s actions “entirely” eliminated competition, contrary to state law.

“Setting a single price at the rule-based maximum price violated the Legislature’s requirement in the Utilities Code … that the commission use competitive methods to the greatest extent feasible and impose the least impact on competition,” Justice Edward Smith wrote (03-21-00098-CV).

The court reversed two PUC orders responding to market transactions clearing as low as $1,200/MWh (51617) and remanded the case for “further proceedings consistent” with its ruling. Whether that takes place at the PUC or in another arena remains to be seen.

The PUC said it doesn’t comment on pending litigation. Neither does ERCOT.

The appeal was filed by Luminant (NYSE:VST), Vistra’s generating subsidiary, shortly after the 2021 storm, also known as Winter Storm Uri, knocked about 50 GW of generation offline. More than 200 Texans died during the resulting dayslong outages.

Other energy companies intervened on both sides of the case.

“We agree with the decision today by the Court of Appeals in Austin, but this is an ongoing legal proceeding, and we cannot predict the final outcome,” Luminant spokesperson Meranda Cohn said in an emailed statement.

Luminant argued before the court last year that the PUC’s actions addressing the power shortage were “invalid and ineffective” and “wreaked havoc.” The PUC told the court that the appellants were upset over their financial losses and were asking the judges to “second-guess” decisions made by the PUC and ERCOT under extreme weather conditions.

The actions resulted in $16 billion of market transactions that ERCOT’s Independent Market Monitor said were incorrectly priced during 33 hours after ERCOT stopped shedding firm load. The PUC declined the reprice the transactions. (See “Monitor: $16B ERCOT Overcharge,” ERCOT Board Cuts Ties with Magness.)

Katie Coleman 2017-03-01 (RTO Insider LLC) FI.jpgKatie Coleman, O’Melveny & Myers | © RTO Insider LLC

Attorney Katie Coleman, whose law firm represents several market participants, pointed out that some of the balance during the storm has since been securitized and that some participants are paying off debt that they now might not even owe. Other transactions settled outside ERCOT can’t really be undone, she said.

“Resettling just the real-time and day-ahead markets creates chaos and undermines positions from two years ago,” Coleman said. “It’s a giant mess. I don’t know how they can even try to unscramble that egg.”

Austin-based energy consultant Alison Silverstein, who was part of FERC’s decade-plus work settling the 2001 California market implosion, used a different metaphor in agreeing with Coleman.

“Practically speaking, it will be challenging to unwind the daisy chains of electricity transactions from that week, figure out what the prices should have been and claw the overpayments back,” she said. “This could be harder for Uri transactions because a lot of that money paid for wildly inflated natural gas, rather than increasing many generators’ profits. It’s unlikely that the PUC can claw back Uri profits from businesses it doesn’t regulate.”

The court is aware of those same issues. “Our decision in this appeal may have very real material consequences for all involved,” Smith said in his opinion.

But Silverstein agreed with the court’s decision, finding it ironic that the ruling found that the PUC exceeded its authority by “eliminating competition entirely.” She pointed to Smith’s use of direct quotes from Texas statutes regarding “electric services and their prices should be determined by customer choices and the normal forces of competition” and that regulatory authorities should use “competitive rather than regulatory methods … to the greatest extent feasible” and with “the least impact on competition.”

“For the past year and at present, the Texas commission and legislators are considering a number of electric market options and policies that would advance regulatory methods that stifle customer choices and choke competition,” Silverstein said. “This order should remind us that since 1995, Texas legislators and policymakers have repeatedly supported free-market competition for electricity. We should find ways to fix our current reliability and affordability challenges by leveraging competition, not squashing it.”

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FERC Rejects Last-ditch Effort to Save Tx Project

FERC on Friday approved MISO’s ability to abandon the only competitive transmission project it has ever assigned to its South region.

The commission’s order means the RTO can cancel its selected developer agreement with NextEra Energy Transmission (NEET) Midwest (NYSE: NEE) for the $115-million, 500-kV Hartburg-Sabine Junction project in East Texas. The grid operator recommended the project in 2017 (ER23-865).

MISO said that Texas’ 2019 right-of-first-refusal law prevented NEET Midwest from obtaining regulatory approval from the Texas Public Utility Commission to construct the project and meet a June 2023 in-service date. The grid operator said that after a fresh analysis of the project showed that it provided little value, it would not reassign the project to incumbent Entergy Texas. (See MISO Cancels Hartburg-Sabine Competitive Project.)

The project was intended to alleviate constraints in a load pocket straddling Texas and Louisiana.

NEET and the Southern Renewable Energy Association (SREA) attempted to save the project by lodging protests of the agreement’s cancellation with FERC. SREA has accused Entergy of strategically building generation near existing line routes to thwart projects that would open up Entergy’s service territory to outside generation supply. The nonprofit has said Entergy wants to preserve its load pockets. (See NextEra, SREA Protest Canceled MISO Project at FERC; SREA Criticizes Lack of MISO South Planning in FERC Tx Proceeding.)

SREA argued that MISO performed only a “limited” screening when it reexamined Hartburg-Sabine and did not conduct a more in-depth congestion analysis. The organization said the project could still be necessary to the MISO South system.

But the commission said MISO appropriately followed its tariff when it used schedule delays to trigger a project analysis and ultimately seek a dissolution of the developer agreement. FERC concluded it was “reasonable” for MISO to determine that NextEra was unable to complete the project.

“While NextEra and Southern Renewable disagree with MISO’s choice of outcome, we find that MISO appropriately exercised the discretion provided by its tariff in arriving at that outcome,” FERC said. “The issues NextEra and Southern Renewable raise do not provide a sufficient basis for us to find that MISO acted in a manner that is inconsistent with its tariff under the circumstances presented here.”

NEET maintained it was “optimistic” it could resume the project’s development following the 5th U.S. Circuit Court of Appeals ruling last year that Texas’ ROFR discriminates against nonincumbents in the portions of the state belonging to interstate transmission systems. Texas has since appealed the ruling to the Supreme Court. (See Texas Petitions SCOTUS to Review ROFR Ruling.)

“We disagree with NextEra’s argument that it is premature for MISO to find that NextEra is unable to complete Hartburg-Sabine given the status of Texas ROFR [l]aw litigation,” FERC said. “While it is true that the Fifth Circuit remanded the issue of the constitutionality of the Texas ROFR [l]aw under the Commerce Clause of the U.S. Constitution to the Western District, the Texas ROFR [l]aw is currently in effect.”

Entergy said it was appropriate for MISO to seek to terminate the developer agreement because the project can no longer deliver benefits.

In comments to FERC, Entergy said NextEra and SREA’s allegation that the utility is trying to stall outsider transmission projects or usurp those projects is untrue.

Entergy said its newly proposed, $1-billion Babel-Running Bear 500-kV project in East Texas is “completely different” from the Hartburg-Sabine project, counter to what NextEra alleged. Entergy gave notice to MISO that it intends to construct a substation and build a 150-mile 500-kV line to accommodate regional load growth and relieve the historically constrained Western Region load pocket. Unlike Hartburg-Sabine, a market efficiency project, the Babel-Running Bear project would be classified as a baseline reliability project and not be open to regional cost sharing.

The MISO stakeholder community has criticized Entergy for proposing billions of dollars of baseline reliability projects in the RTO’s South region in this year’s transmission-planning cycle. Stakeholders have pressed the grid operator to determine whether some of the projects could become more comprehensive, regionally allocated projects. (See Initial MTEP 23 Ignites Familiar Arguments over MISO South’s Reliability Spending.)

“Entergy believes that the transmission system should be planned and constructed to provide customers with reliable, reasonable cost electric service, including to accommodate the transition of a changing resource mix,” Entergy told FERC. “Among other things, transmission planning should consider generation solutions and local distribution facilities to ensure that the results of the planning process are efficient and will provide for a reliable grid.”

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Lone RI OSW Proposal to be Evaluated for Affordability

Rhode Island Energy said Friday it had hoped to receive more than one proposal in the state’s second offshore wind solicitation but recognizes the challenges facing the sector.

The company said it will now evaluate the joint Ørsted-Eversource proposal and decide in about three months whether to move forward with contract negotiations.

Future affordability of energy will be the central consideration in the process, it said.

The solicitation called for proposals for 600 to 1,000 MW of generation capacity, as specified in a 2022 Rhode Island law.

In response, Ørsted and Eversource proposed Revolution Wind 2, an 884-MW wind farm with projected economic benefits of $2 billion for the state. The two already are developing Revolution Wind 1, which would send 400 MW to Rhode Island and 304 MW to Connecticut.

Rhode Island Energy, a subsidiary of PPL (NYSE:PPL), is running the solicitation and would buy the power generated by a completed project.

Rhode Island Energy President Dave Bonenberger said in a news release Friday that under state law, any long-term power purchase agreements would need to be for 15 to 20 years.

“We’re committed to helping Rhode Island meet its leading clean energy goals and will carefully review Ørsted and Eversource’s joint proposal,” he said. “Our objective is to advance the clean energy transition while keeping energy affordable and reliable for our customers. This is the lens through which we will evaluate the proposal.”

Bonenberger also alluded to the financial and logistical challenges facing U.S. offshore wind developers.

“Although we had hoped to see more developers put forward additional proposals within this appeal, we also know there are a multitude of factors at play right now. As we move forward, our evaluation will consider future energy affordability and how this proposal meets the requirements of both the RFP and state law,” he said.

Headwinds

The first and so far only offshore wind farm completed in the U.S. generates a peak 30 MW off Block Island delivered to the Rhode Island coast. That is 0.1% of President Biden’s 30-GW goal for 2030.

Offshore wind energy is an important part of Rhode Island’s strategy to reach 100% renewable energy by 2033; multiple lease areas are clustered on the Outer Continental Shelf south and southeast of the state.

But as the Rhode Island RFP opened Oct. 14, offshore wind developers were wrestling with supply chain constraints, soaring interest rates and inflation.

Developers of two other New England OSW projects, Commonwealth Wind and South Coast Wind, have said the challenges that arose in 2022 made those projects untenable with the power purchase agreements that they had previously agreed on.

Commonwealth developer Avangrid wants to scrap its contracts and rebid; South Coast has not made that request, but also has not said its concerns have been satisfied.

Avangrid also said terms of the Park City Wind contract in Connecticut are untenable, and it has pushed back the in-service dates of Commonwealth and Park City in hopes that delaying start of construction would give manufacturers time to bring higher-output wind turbines to market.

Ørsted, meanwhile, is expecting a $365 million cost impairment on the Sunrise Wind 1 project in New York because its contracts were not locked in before economic headwinds arose in the nascent U.S. offshore wind industry.

And Eversource began looking for a buyer for its offshore wind assets in 2022 to free up capital.

Rhode Island’s second OSW solicitation closed March 13 with just the single Ørsted-Eversource proposal.

By contrast, when New York’s third OSW solicitation closed Jan. 26, it had drawn a robust response from six developers.

New York offered bidders the option of an inflation-adjustment mechanism.

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PSCo, Idaho Power Comply with Show-cause Order

FERC last week approved two Western utilities’ revisions to their transmission formula rate protocols in their response to a show-cause proceeding initiated last year.

The commission said Thursday that Public Service Company of Colorado (PSCo) (NASDAQ:XEL) and Idaho Power (NYSE:IDA) proposed revisions that are consistent with the standards established in a 2012 order regarding MISO transmission owners and would remedy the show-cause order’s concerns. It directed both companies to submit a compliance filing within 30 days of the orders (EL22-39 and EL22-37, respectively).

FERC opened the proceedings against the two utilities and three others last April under Section 206 of the Federal Power Act. It said the utilities did not appear to provide customers and regulators the ability to challenge rates resulting from the formulas. (See FERC Opens Probes on Western Tx Rate Protocols.)

The commission found that each of the five utilities’ protocols fell short on one or more of the following: “the scope of participation (i.e., who can participate in the information exchange); the transparency of the information exchange (i.e., what information is exchanged); and the ability of customers to challenge transmission owners’ implementation of the formula rate as a result of the information exchange (i.e., how the parties may resolve their potential disputes).”

Neither PSCo, a subsidiary of Xcel Energy, nor Idaho Power refuted FERC’s findings.

PSCo said it would broaden the definition of interested parties to specifically identify the entities that can participate in its annual update process. It also proposed several other changes and said it would clarify that formal challenges by the parties should be filed pursuant to the annual informational filing docket’s protocols.

Idaho Power also said it would adopt MISO’s definition of interested parties that can participate in its annual update process. It proposed several other transparency-related revisions and said it would incorporate informal and formal challenge procedures that satisfy the MISO order’s requirements and provide a structured timeline that allows the review process to be completed before the next year’s posting.

In the MISO order, the commission ruled that the RTO’s protocols inappropriately limited who could participate in the review processes and directed it and TOs to revise them to include all interested parties, including customers under the MISO tariff, state utility regulatory commissions, consumer advocacy agencies and state attorneys general.

Two of the other three show-cause proceedings are still active. FERC has not yet ruled on the PacifiCorp proceeding (EL22-38), but it granted Puget Sound Energy’s request for an extension (EL22-41).

The commission approved Public Service Company of New Mexico’s compliance filing in November (EL22-40).

Commission Accepts Black Hills Compliance

The commission also found that Black Hills Colorado Electric’s (NYSE:BKH) July 2022 compliance filing meets the requirements of FERC Order 864, which addresses excess and deficient accumulated deferred income taxes (ADIT) resulting from tax rate changes (ER22-2377).

FERC in June accepted tariff revisions for Black Hills’ transition from a stated rate to a transmission formula rate, suspending them until Sept. 1, 2022, subject to refund, and established hearing and settlement judge procedures. It also accepted the suggested ADIT worksheets, subject to refund and the compliance proceeding’s outcome.

Tri-State Generation and Transmission Association protested and moved to consolidate the proceedings, saying the worksheets lacked transparency and the level of detail required by Order 864. The commission rejected the argument, finding that the worksheets’ calculation steps “are shown clearly enough for an interested party to be able to verify that the calculations were done correctly.”

FERC dismissed Tri-State’s motion to consolidate the proceedings, accepting the compliance filing as just and reasonable without need for a trial-type evidentiary hearing.

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FERC Weighs in on Jurisdictional Questions over Puerto Rico Project

FERC last week granted a petition from a company looking to build an undersea transmission line to Puerto Rico, affirming several of the developer’s questions about its status as a utility and weighing in on whether the project would make the island territory’s transmission system subject to FERC’s jurisdiction (EL23-14).

The company, Alternative Transmission Inc. (ATI), filed the petition for declaratory order in December. It asked FERC to confirm that it could qualify as a utility and therefore be able to submit applications asking for orders directing other utilities to interconnect with or provide transmission services for Project Equity, its Puerto Rican project.

It also asked whether, if FERC were to direct interconnection or transmission to Puerto Rico as part of the project, those orders would “provide a basis for the commission to exercise plenary jurisdiction over Puerto Rico’s electric transmission system or utilities, which have not previously been regulated by the commission.”

FERC first said that its answers to most of the questions would depend on the specifics of an actual project application and any proposed interconnections. But it confirmed that ATI could qualify as a utility and could submit applications asking for an order requiring interconnection or transmission services. It could also therefore be a target of those applications by others.

On the jurisdiction question, FERC said that, unless there was an order issued pursuant to Federal Power Act Sections 210 and 211 (requiring interconnection or transmission), the interconnection that ATI is proposing between Puerto Rico and the continental U.S. would in fact result in the territory’s utilities becoming subject to FERC jurisdiction.

Those sections do provide an exemption though, the commission said.

“Upon receipt of valid applications under Sections 210 and/or 211, the commission could issue orders pursuant to those sections of the FPA allowing interconnection and/or transmission of energy between Puerto Rico and the interstate transmission system while retaining the jurisdictional status quo such that Puerto Rico’s electric utilities would not be ‘public utilities’ under Section 201e of the FPA,” it said.

However, FERC would still have jurisdiction of Puerto Rico’s utilities as part of other FPA sections including 210, 211, 212, 215 and “any other FPA provisions that provide for jurisdiction over Puerto Rico’s transmission system and its utilities.”