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October 31, 2024

MISO Queue Changes on Hold Pending Technical Conference

By Amanda Durish Cook

MISO is postponing a second attempt at changing its generator interconnection queue rules while it assesses FERC feedback and awaits input from a commission technical conference next month.

The RTO will participate in the conference, set for May 13 (RM16-12, RM15-21).

“MISO still believes that reforms to the interconnection queue process are necessary to adapt to a rapidly evolving generation fleet, and we look forward to further discussions with FERC and stakeholders to move this process forward,” the RTO said in an update to the Planning Advisory Committee. (See MISO Unveils Queue Rule Transition as Wind Advocates Seek Delay.)

ferc, miso interconnection queue

FERC last month rejected MISO’s proposed queue changes, saying they assumed the current backlog could be blamed on “speculative” projects and “fail[ed] to consider other potential factors” (ER16-675). Those factors included the timeliness of MISO’s queue processing and its coordination with neighboring RTOs. The commission also said a proposed milestone payment could create barriers to entry for smaller developers.

“We’re free to file again, anytime we want, but we have to address the concerns FERC has,” said Tim Aliff, MISO director of interconnection and planning.

Aliff said MISO’s Interconnection Process Task Force will survey stakeholders to determine which parts of the queue plan are salvageable. He also said some new processes — such as providing interconnection customers with models ahead of the queue entrance — might be included.

MISO also is planning a filing to comply with a FERC order requiring the RTO to charge uniform milestone payments to all external, internal and existing customers. (See FERC Orders MISO to Charge Uniform Interconnection Fees.) Aliff said that filing will be made separately from the revised queue filing.

FERC Stands by Denial of Polar Vortex Make-Whole Payments

FERC last week reiterated its 2015 order rejecting New Jersey Energy Associates’ request for recovery of costs incurred during the polar vortex of January 2014. Natural Gas Price Volatility (Monitoring Analytics) FERC polar vortex

NJEA, which owns the 290-MW South River combined cycle plant, said it was forced to sell natural gas at a loss of $1.3 million after PJM repeatedly canceled the plant’s scheduled start time.

FERC denied the company’s request for a waiver that would have allowed PJM to reimburse it, citing rules against retroactive ratemaking (ER15-952). (See FERC Again Denies Polar Vortex Make-Whole Payments.)

In its ruling Thursday, FERC said that NJEA’s request for clarification and rehearing was asking the commission for the first time to interpret the phrase “actual costs incurred.”

“NJEA’s request is beyond the scope of its original waiver request and [is] inappropriately raised for the first time in a request for clarification and rehearing of the Sept. 4 order,” it said.

– Suzanne Herel

MISO Planning Subcommittee Briefs

Advancements in energy storage are prompting MISO to expand its definition of non-transmission alternatives to include a new category: non-traditional transmission alternatives.

Storage behaves like transmission in several ways, Matt Tackett, MISO principal, told the Planning Subcommittee during an April 19 meeting.

“We started to realize that we’re struggling because we’re trying to make this thing too broad,” Tackett said. “We need to compartmentalize. Trying to force everything into one bucket is counterproductive.”

Non-transmission planning work is still in a “conceptual stage,” and a storage battery could be categorized as either a non-transmission alternative or a non-traditional alternative depending on how it solves a transmission issue.

MISO will seek stakeholder feedback on the issue until May 20. (See “MISO: More Time Needed to Refine Non-Transmission Alternatives Process,” MISO Planning Subcommittee Briefs.)

MISO to Revise Transmission Service Requests for Pseudo-Ties

MISO plans to revise the requirements for pseudo-tied resources to prevent them from generating without transmission rights, said Ankit Pahwa, MISO senior transmission planning engineer.

Pahwa said MISO is concerned that pseudo-tied resources might let their transmission rights expire continuing to import or export power. The RTO is proposing to add language to transmission service requests specifying that transmission rights be firm, point-to-point and maintained for the life of a pseudo-tie.

“What we’re saying is you have to maintain that transmission right to continue pseudo-tying out of MISO,” Pahwa said.

Additionally, MISO is considering performing system impact studies for all such transmission service requests. The RTO currently performs such studies only for pseudo-ties lasting longer than 18 months.

The proposed changes are part of a recent Planning Advisory Committee directive to “appropriately capture pseudo-tie impacts to MISO’s transmission system.”

MISO Questions Need for Transient Stability Analyses in MTEP

A new MISO white paper questions the need for completing a yearly long-term transient stability analysis as part of MISO’s Transmission Expansion Planning (MTEP) process.

Long Term MTEP Study Scope (MISO) - planning subcommittee briefsThe analysis models the dynamics and power flow of the entire system to provide insight into how the grid can return to stability after a significant disturbance, such as the loss of a generator.

A 10-year study during each planning cycle would satisfy NERC and MISO’s long-term planning horizon requirements, but MISO is wondering if it is necessary.

“The question is: Do you or do you not have to run the 10-year-out summer peak transient stability study?” Pat Jehring, of MISO’s planning expansion department, asked stakeholders.

According to Jehring, the RTO could conduct a long-term study using a broad approach — where the scope is widened to include all modeling changes and how they could affect the system — or a narrower interpretation of such changes. Jehring said MISO took the narrower approach with MTEP15 to save time. The RTO might now follow the broader option for MTEP16, with the analysis accounting for the impact of transmission, load changes and dispatch changes on the system.

Jehring said transmission owners have varying opinions about whether a long-term transient stability analysis would be needed for every MTEP.

Will Kenney, also with the planning expansion department, provided insight into the preliminary MTEP16 voltage stability scope, which identifies future reliability risks to MISO’s system.

Kenney said the MTEP16 scope will model a 2021 summer power flow and a shoulder power flow that assumes a 40% wind power contribution. The RTO will evaluate eight transfer paths during the 2021 summer peak, adding new analysis on the impact of eastbound transfers from Ameren Missouri and Ameren Illinois that sink in American Electric Power’s territory. Analysis of the U.S.-Canada interface will model a winter peak to examine transfers from Manitoba to the U.S. portion of MISO North.

The full scope of the voltage study will be presented at June’s Planning Subcommittee meeting, according to Kenney. The project should be completed in time for the board’s approval of the MTEP in December, he said.

— Amanda Durish Cook

FERC Consolidates Duke ROE Complaints, Sets Hearings

FERC consolidated and set for hearing two return-on-equity complaints filed against Duke Energy Carolinas and Duke Energy Progress by overlapping complainants.

The complaint against Duke Carolinas argue that the current 10.2% ROE exceeds the company’s current cost of equity and should be set no higher than 8.49% (EL16-29). Similarly, the complaint against Duke Progress said its 10.8% base ROE should be set no higher than 8.49% (EL16-30).

FERC also established a refund effective date of Jan. 7, 2016.

– Suzanne Herel

MISO, SPP Disagree on 2016 Joint Study

By Amanda Durish Cook

MISO staff are recommending that two joint MISO-SPP committees not develop a coordinated system plan study this year, advising the groups to instead focus on improving their processes.

SPP's Seams with MISO (ACES) Joint Study“MISO is hoping to focus on improving the process for coordinated studies prior to embarking on our next study,” MISO spokesperson Andy Schonert said following last week’s Planning Advisory Committee meeting. He said MISO wants to “take a step back” before proceeding.

MISO said it would review stakeholder input on the recommendation before putting the issue to a final vote.

SPP’s Seams Steering Committee voted earlier this month in favor of producing a coordinated study after discussion with representatives from the RTOs’ Interregional Planning Stakeholder Advisory Committee.

“The overwhelming consensus was that there is sufficient justification to undertake another joint study between the RTOs while concurrently working to implement process improvements,” said David Kelley, SPP’s director of interregional relations.

Schonert said MISO and its stakeholders want another year to align the effort with MISO’s modeling and transmission planning timeline. The RTO also wants any joint study to encompass broader metrics, such as adjusted production costs. He said MISO is committed to learning why proposed projects are not passing interregional reviews and is seeking possible development of a “standalone” interregional process, which would bypass the “triple hurdle” of individual and joint RTO approval procedures.

If just one RTO votes to perform the joint study, the subject is put off until the annual issues review the following year, according to Eric Thoms, MISO manager of planning coordination and strategy.

However, the study will be approved if one RTO votes in favor for three consecutive years — regardless of the position of the second RTO. A first joint study in 2015 failed to recommend any interregional projects, and MISO and SPP met in March for an annual issues review to discuss improving the process. (See MISO, SPP Considering Second Joint Tx Study.)

Thoms said MISO’s current issues with SPP do not warrant a joint study. He pointed out that the new seam along the Integrated System in North Dakota and South Dakota is being monitored, transfer limits between MISO North and MISO South are in place, and congestion has not changed substantially from the 2015 joint study. More historical data is needed before MISO and SPP can identify the persistent levels of market-to-market flowgate congestion, he said.

“This does not mean that we stop monitoring issues or are not open to future studies as we learn more,” said Jesse Moser, MISO manager of infrastructure studies. “Just because we don’t do a study doesn’t mean we stop working with stakeholders on these issues.”

If MISO staff’s recommendation against a study is upheld through a PAC motion, the next opportunity to reconsider would follow the annual issues review in early 2017, Thoms said. If a pressing issue does arise, the two RTOs could scope out a study before the first quarter of 2017, he said.

FERC Denies Occidental’s PURPA Complaints

By Michael Brooks

FERC last week denied Occidental Chemical on three fronts in the company’s battle against MISO and Entergy’s treatment of qualifying facilities.

ferc occidental purpa - occidental logoThe commission dismissed a 2013 complaint by the Dallas-based chemical manufacturer that claimed MISO’s treatment of QFs violated the Public Utility Regulatory Policies Act (EL13-41). Occidental argued that MISO’s plan to integrate QFs in Entergy’s territory would strip them of their rights under PURPA, as the law assumes that they do not have access to wholesale markets.

This plan was detailed in a document titled “Qualifying Facilities Generator Readiness for MISO Reliability Coordination and Market Integration,” which was circulated at informational meetings with QFs. It included two options for QF participation, one of which was labeled the “hybrid option.” Under this option, a QF is allowed to submit offers or self-schedule in both the day-ahead and real-time markets up to its maximum capacity. MISO said that by using financial schedules, which Entergy would be required to agree to, QFs would be able to maintain their right to sell at the avoided cost rate, pursuant to PURPA.

Occidental argued that the hybrid option would prevent QFs from exercising their right to sell as-available energy under PURPA. The company also argued that MISO should have been required to seek FERC approval for its integration plan.

The commission was unpersuaded by Occidental’s arguments.

“In this instance, registration under the hybrid option allows QFs to participate in the MISO market, while continuing to exercise their rights pursuant to PURPA,” FERC said. “We find that the use of financial schedules in conjunction with the hybrid option preserves a QF’s right to provide as-available energy.”

Complaint Against LSPC

While its complaint against MISO was pending before the commission, Occidental filed a complaint against the Louisiana Public Service Commission in February 2014. Occidental protested that the PSC had essentially adopted MISO’s QF integration plan.

FERC declined to take action on the PSC complaint while Occidental’s MISO complaint was still pending. In response, the company sued Entergy and the PSC in federal district court, which stayed the proceeding until FERC reached a decision in the MISO complaint. Occidental appealed, and in January the 5th U.S. Circuit Court of Appeals overturned that decision, noting that it could take years before FERC reached a decision. It ordered the lower court to give FERC 180 days to resolve the MISO complaint; if FERC had not reached a decision, the court could proceed with the suit (15-301).

With the MISO complaint settled, FERC subsequently issued a notice of intent not to act on the PSC complaint (EL14-28).

Rehearing Denied

Finally, FERC denied a rehearing request from Occidental regarding its order waiving the requirement for Entergy to sign power purchase agreements with QFs that have capacities over 20 MW (QM14-3). (See FERC: Entergy not Required to Buy from Large QFs.)

Occidental argued that the commission ignored evidence showing that MISO’s integration plan would deny its Taft QF, located at its Hahnville, La., chemical plant, nondiscriminatory access to the RTO’s markets.

But FERC noted its decision upholding MISO’s plan. “Given this finding, Occidental’s argument in the instant case that it lacks nondiscriminatory access to the MISO markets based on the MISO QF integration plan is moot,” it said.

FERC Affirms Entergy Refund Order on Off-System Sales

By Tom Kleckner

FERC last week affirmed its 2012 ruling requiring Entergy to make refunds to ratepayers because of an improper allocation of the sources of off-system energy sales between 2000 and 2009.

Entergy Service Area - FERC Refund Order on Off-System SalesThe commission denied in part and granted in part requests for rehearing by Entergy Services and the Louisiana Public Service Commission (EL09-61-003).

The PSC set the proceedings in motion with a 2009 complaint alleging Entergy and its affiliates violated their system agreement and engaged in “imprudent utility conduct” when Entergy Arkansas sold excess electric energy to third-party power marketers and other non-agreement members. Entergy’s system agreement is a 1982 contract between the companies and Entergy Services that governs the planning and operation of the companies’ generation and bulk transmission facilities on a single-system basis.

An administrative law judge’s initial decision found Entergy Arkansas had violated the system, ordering refunds. FERC affirmed part of the decision, finding that although the agreement’s relevant provisions are “ambiguous,” it does provide authority for the individual companies to make opportunity sales for their own accounts.

The PSC and Entergy requested a rehearing of the decision based on four issues:

  1. Was the commission correct in finding the system agreement permitted the opportunity sales?
  2. Did Entergy violate the agreement in accounting for the sales?
  3. Was FERC correct in ordering refunds?
  4. Did the commission err in reducing the refund amount as a result of the PSC’s delay in approving a power purchase agreement between Entergy Louisiana and Entergy Arkansas?

FERC rejected Entergy and the PSC’s arguments on each of the first three matters, affirming its previous decision.

“Although the Louisiana commission argues that the system agreement prohibits opportunity sales through its provisions concerning the powers of the operating committee … it is notable that the Louisiana commission can point to no specific provisions that make such a prohibition,” FERC said.

Over-Recovery

However, the commission also rejected Entergy’s contention that no refunds were due to ratepayers because the matter involved a misallocation of costs among different companies rather than an over-recovery. “Entergy Arkansas’ off-system sales of low-cost energy from system resources had the effect of forcing up the rates of captive customers of other operating companies by precluding their purchase of the low-cost energy,” the commission said. “Those captive customers were essentially over-charged as a result of Entergy’s improper accounting under the system agreement and thus are due refunds.”

The commission also clarified that interest on refunds should be included in the payments, consistent with the commission’s general policy.

And it agreed with the PSC’s argument that the refunds should not be reduced by a 12-month period in which the Louisiana regulators delayed approval of a PPA between Entergy Louisiana and Entergy Arkansas. FERC said a more equitable approach would be to reinstate refunds for the 12-month period at issue, saying it could not “necessarily conclude” the PSC’s delay in processing the PPAs was so excessive the refund amounts should be reduced.

In a separate order, FERC set further hearing procedures to determine the final allocation of refunds, which the Louisiana commission has estimated at $77.5 million (EL09-61-002). Entergy contends the amount should be less than $25 million.

The commission agreed with the ALJ that a full re-run of Entergy’s intra-system bill was necessary to provide a fair accounting of damages. FERC found the damages should be altered to reflect adjustments to service schedules and other provisions in the system agreement, including for bandwidth payments.

Entergy’s companies essentially operate as one system, although each has different operating costs. Low-cost companies make annual payments to the highest-cost company, using a “bandwidth” remedy that ensures no operating company has production costs more than 11% above or below the system average. Regulators in Entergy’s states have regularly challenged the annual bandwidth filings, which began in 2007.

New York Environmental Department Rejects Constitution Pipeline

By William Opalka

New York environmental officials on Friday denied a water quality permit for a 124-mile pipeline that would have delivered shale gas from Pennsylvania to markets in eastern New York and New England.

The New York Department of Environmental Conservation said developers of the Constitution Pipeline failed to address regulators’ concerns during a yearlong review.

The water quality permit, which is required under Section 401 of the federal Clean Water Act, was the last regulatory approval needed by Williams Partners and its co-developers, Cabot Oil & Gas, Piedmont Natural Gas, and WGL Holdings, for the pipeline through northeastern Pennsylvania and New York.

FERC approved the pipeline in December 2014, but developers lost the 2016 construction season when FERC would not allow limited tree cutting along the project route after New York officials protested because of the lack of the Section 401 permit. (See Constitution Pipeline Delayed Nearly a Year.)

Failed to Address Environmental Concerns

constitution pipeline, new yorkThe DEC said Constitution’s “application fails in a meaningful way to address the significant water resource impacts that could occur from this project and has failed to provide sufficient information to demonstrate compliance with New York state water quality standards.”

Constitution said it “will pursue all available options to challenge the legality” of the decision. The project was intended to deliver 650,000 dekatherms of natural gas per day to the Wright, N.Y., compressor station for transport farther east.

“In spite of NYSDEC’s unprecedented decision, we remain absolutely committed to building this important energy infrastructure project, which will create an important connection between consumers and reliable supplies of clean, affordable natural gas. We believe NYSDEC’s stated rationale for the denial includes flagrant misstatements and inaccurate allegations, and appears to be driven more by New York state politics than by environmental science,” the company said in a statement released Monday.

The department blamed the company for failing to adequately address its concerns about the project’s impact on 251 streams and 500 acres of forest. The denial also cited the short- and long-term effects of trenching during construction, the loss of shade critical to stream health and the impact the loss of vegetation would have on potential flooding.

“Although the department repeatedly asked Constitution to analyze alternative routes that could have avoided or minimized impacts to an extensive group of water resources, as well as to address other potential impacts to these resources, Constitution failed to substantively address these concerns,” the DEC wrote.

Constitution said it “voluntarily agreed” to incorporate re-routes, adopt trenchless construction methods, commit to trout stream restoration and spend $18 million for wetland mitigation and $8.6 million for migratory bird habitat restoration and preservation.

Tree Cutting

The department was also annoyed that it received reports that landowners, “possibly with Constitution’s knowledge, clear cut old-growth trees along the right of way for the pipeline, including trees near streams and water bodies, even after the FERC ruled that Constitution could not cut trees in the right of way.”

New York, Constitution Pipeline
First sections of Constitution Pipeline arrive in New York Source: Constitution Pipeline

Constitution said that allegation is “completely inaccurate and contradicts the third-party environmental monitors working on behalf of FERC.”

The DEC said it conducted a “rigorous review,” including receipt of 15,000 public comments.

Environmentalists lauded the decision.

“Gov. [Andrew] Cuomo’s rejection of the Constitution Pipeline represents a turning of the tide, where states across the nation that have been pressured into accepting harmful gas infrastructure projects by FERC may now feel emboldened to push back,” said Roger Downs, conservation director for the Sierra Club’s Atlantic Chapter. “Cuomo’s leadership could inspire a domino effect of related pipeline rejections as other states begin to put the protection of water and our climate before flawed energy projects that do not serve the public interest.”

Constitution’s rejection came two days after Kinder Morgan announced it was shelving its Northeast Energy Direct pipeline, which was to deliver Pennsylvania shale gas through New York, Massachusetts and New Hampshire. It cited an uncertain regulatory climate for the project as well as a lack of commitments from electric utility customers. (See Kinder Morgan Suspends Northeast Energy Direct Pipeline.)

Kinder Morgan Board Suspends Work on Northeast Energy Direct Pipeline

By William Opalka

Kinder Morgan said Wednesday it has suspended work on the Northeast Energy Direct pipeline, citing an uncertain regulatory climate and a lack of commitments from New England power generators to reserve capacity.

The $3.3 billion project, being developed by subsidiary Tennessee Gas Pipeline, was to deliver shale gas from Pennsylvania into New York, with a line also running through Massachusetts and New Hampshire. The Kinder Morgan board approved the project last summer and it sought federal approval late last year (CP16-21). (See Northeast Energy Direct Files for FERC Certificate.)

“The board’s initial approval was based on existing contractual commitments at the time by local gas distribution companies to purchase natural gas from the project, as well as expected commitments from additional LDCs, electric distribution companies and other market participants in New England,” the company said in a statement. “Unfortunately, despite working for more than two years and expending substantial shareholder resources, TGP did not receive the additional commitments it expected. As a result, there are currently neither sufficient volumes, nor a reasonable expectation of securing them, to proceed with the project as it is currently configured.”

The company conducted an open season last year to engage potential customers and received commitments for only 751,650 dekatherms per day of the pipeline’s 1.3 million dekatherms per day capacity.

Kinder Morgan's Northeast Energy Direct project

A controversial aspect of the project, and that of another proposed pipeline, Access Northeast, is the proposal to have EDC ratepayers foot some of the project costs through their utility bills. (See Massachusetts Regulators Endorse Pipeline Contracts.) Massachusetts Attorney General Maura Healey has opposed the move, and similar proposals in other New England states have yet to be enacted.

“The New England states have not yet established regulatory procedures to facilitate binding EDC commitments, that the process in each state for establishing such procedures is open-ended and that the ultimate success of those processes is not assured,” Kinder Morgan added in its statement.

Project opponents were elated.

“It’s a rare thing to see a fossil fuel company admit there simply isn’t enough need for what they’re selling,” Conservation Law Foundation President Bradley Campbell said. “It is increasingly apparent that free market forces are rapidly driving us toward a clean energy future, and today’s decision by Kinder Morgan is a telling sign of things to come. Our environment, our economy and the health of our communities depend on continuing to see fossil fuels out the door.”

Supreme Court Rejects MD Subsidy for CPV Plant

By Rich Heidorn Jr.

WASHINGTON — The U.S. Supreme Court today unanimously rejected Maryland regulators’ attempt to subsidize Competitive Power Ventures’ combined cycle plant in Charles County, saying it interfered with FERC’s jurisdiction over wholesale electric markets.

The court upheld a ruling by the 4th Circuit Court of Appeals, which found that Maryland’s contract for differences with CPV could distort price signals in PJM’s annual capacity auctions (Hughes v. Talen, 14-614, 14-623).

“We agree with the 4th Circuit’s judgment that Maryland’s program sets an interstate wholesale rate, contravening the [Federal Power Act’s] division of authority between state and federal regulators,” Justice Ruth Bader Ginsburg wrote for the court. She said the contract also violated the Constitution’s Supremacy Clause, which establishes that federal law preempts contrary state law.

In April 2012, the Maryland Public Service Commission ordered Baltimore Gas and Electric, Potomac Electric Power Co. (PEPCO) and Delmarva Power and Light to enter into a contract that guaranteed CPV — winner of a PSC competitive solicitation — an income stream so that it could finance the facility.

Contract for Differences

Under the contract for differences, CPV St. Charles’ revenues for the sale of 661 MW of energy and capacity would be compared to what the company would have received had the contract prices been controlling. If the contract prices were higher than the market prices, the three electric distribution companies would pay the difference to CPV; if market prices were higher than the contract, CPV would make payments to the EDCs.

The contract was challenged by Talen Energy’s predecessor, PPL, and other generators. The opponents said Maryland’s action would suppress capacity prices and that allowing the contract to stand would mean that eventually only subsidized units would enter the auction because those without support could not compete.

FERC has approved the PJM capacity auction as the sole rate setting mechanism for sales of capacity to PJM and has deemed the clearing price per se just and reasonable,” the court said. “By adjusting an interstate wholesale rate, Maryland’s program invades FERC’s regulatory turf.”

Maryland and CPV contended the contract for differences was no different than traditional bilateral contracts for capacity, which FERC allows.

But the court said Maryland’s contract with CPV “does not transfer ownership of capacity from one party to another outside the auction. Instead, the contract for differences operates within the auction; it mandates that [load-serving entities] and CPV exchange money based on the cost of CPV’s capacity sales to PJM.”

The Supreme Court had declined to review a ruling by the 3rd Circuit Court of Appeals finding New Jersey regulators’ subsidy of a CPV generating plant also in violation of the Constitution’s Supremacy Clause (PPL EnergyPlus LLC, et al. v. Hanna, 11-0745).

Guidance for States

But the court did provide state regulators’ guidance for crafting their programs in the future, saying it rejected Maryland’s initiative only because it disregards FERC’s wholesale rate.

“We therefore need not and do not address the permissibility of various other measures states might employ to encourage development of new or clean generation, including tax incentives, land grants, direct subsidies, construction of state-owned generation facilities or re-regulation of the energy sector,” it said. “So long as a state does not condition payment of funds on capacity clearing the auction, the state’s program would not suffer from the fatal defect that renders Maryland’s program unacceptable.”

Justice Clarence Thomas concurred in the judgment but said the court did not need to cite “implied preemption” under the Supremacy Clause.

“To resolve these cases, it is enough to conclude that Maryland’s program invades FERC’s exclusive jurisdiction” under the Federal Power Act’s division of federal (wholesale) and state (retail) jurisdiction, Thomas wrote.

The court’s ruling was unsurprising. At oral arguments in February, none of the justices showed any support for Maryland’s stance. (See Supreme Court Offers Little Support to CPV, Md.)

EPSA, APPA, NARUC React

The Electric Power Supply Association, which had filed amicus briefs in support of federal preemption of the Maryland and New Jersey subsidy programs, called the ruling “a victory for the economic integrity and viability of wholesale power markets. The unanimous decision strengthens FERC’s hand at a critical time when it comes to properly defining the appropriate roles for federal and state actions impacting wholesale power markets.”

The American Public Power Association (APPA) called the decision “another regrettable setback for restructured states in Regional Transmission Organization regions that take seriously their obligations to ensure that their state’s retail customers have reliable, affordable and environmentally responsible electric service.”

The group said it was pleased, however, that the ruling was narrowly drafted “and does not impair the ability of public power utilities to serve their own retail customers with owned and contracted-for generation resources.”

Travis Kavulla, president of the National Association of Regulatory Utility Commissioners, said “the line between the federal and state jurisdictions appears largely unaltered” by the ruling.

“Following the Supreme Court’s logic, it seems possible that the state of Maryland could have accomplished substantially the same result of obtaining new generating capacity in the state, just so long as it did not condition the generator’s compensation on the wholesale market’s clearing price for capacity,” he said in a statement.

But Kavulla said the ruling will “inevitably will result in further litigation of these issues by leaving many open questions.”

“Someday soon, consumers, utilities, power generators, and regulators alike will need greater certainty about what is and is not permissible on the part of federal and state regulators. But today is not that day.”