Page 1447 – RTO Insider

April 25, 2016

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.

The 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

April 25, 2016

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

April 25, 2016

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.

“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.

April 25, 2016

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.

The 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.

April 25, 2016

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.

The 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:

Was the commission correct in finding the system agreement permitted the opportunity sales?
Did Entergy violate the agreement in accounting for the sales?
Was FERC correct in ordering refunds?
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.

April 23, 2016

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

The 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.)

April 21, 2016

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.

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.”

April 19, 2016January 23, 2024

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.”

April 18, 2016

FERC Approves Changes to ISO-NE Retirement Rules

By William Opalka

FERC last week accepted rule changes meant to prevent generation owners in ISO-NE from exercising market power by retiring resources that are still economic (ER16-551).

The commission approved revised Forward Capacity Market rules that will require retiring generators to declare their intention with de-list bids in March rather than October, while moving the “show of interest” deadline for new capacity market entrants from February to April.

The order also gives the Internal Market Monitor greater leeway in determining whether an economic generation resource is being retired to raise capacity prices.

“ISO-NE’s proposal includes several changes to the FCM timeline, which will benefit the market,” FERC wrote. “By requiring retirement bids to be submitted in March and by requiring ISO-NE to post shortly afterwards information regarding the amount of existing capacity that may exit the FCM, project sponsors that are considering developing new resources will have better and more timely information about when and where new capacity may be needed.

“By moving the show of interest window to a date after the retirement bid deadline, new entrants will be able to use the information about potential retirements to inform their decision on whether to enter the FCM in the next auction,” the commission said.

The rules will take effect with the 11th Forward Capacity Auction next year for the 2020/21 commitment period.

Generators submit de-list bids that specify a price below which an existing resource would not provide capacity. A static de-list bid signifies a one-year absence from the capacity market; a permanent de-list bid means the resource will exit the market. A capacity supplier wishing to permanently retire an existing resource regardless of price would submit a non-price retirement request.

IMM Review

The order also approved rule changes to address premature retirements of economic resources, a need ISO-NE said was identified by both its IMM and External Market Monitor. The RTO defines “uneconomic” retirement as the retirement of a capacity resource that would be expected to remain profitable if it continued running.

ISO-NE proposed that its IMM issue a determination on the reasonableness of generators’ cost assumptions and the appropriateness of their proposed bids. Based on that, the RTO will file with the commission either the supplier’s original bid or a mitigated bid.

Generators objected, saying the IMM should not be given such discretion, but FERC was not persuaded.

“The proposed reforms permit flexibility in the submitted forecasts and inputs of a retirement bid, so long as a supplier can show that those forecasts and inputs are reasonable,” FERC said. “We find that this process will not result in an undue preference for the IMM’s estimates of a supplier’s retirement costs, but rather will initiate a dialogue whereby suppliers would have the opportunity to demonstrate that their proposed inputs to their retirement bids are reasonable.”

Generators also contended there was no evidence of market power abuses in New England. But the commission said such proof was unnecessary.

“It is irrelevant whether suppliers have previously used physical withholding through retirement as a means to exercise market power. Our review here is limited to whether ISO-NE’s proposal is just and reasonable and not preferential or unduly discriminatory,” FERC wrote.

Brayton Point Allegations

The backdrop for the rule changes is the Utility Workers Union of America’s contention that the 1,517-MW Brayton Point plant in Massachusetts is being closed to raise capacity prices.

Energy Capital Partners did not offer the plant in capacity auctions for 2017/18 and 2018/19 after announcing the plant would close in 2017. Brayton Point was sold last year to Dynegy, which said it would close the plant as scheduled.

The commission has repeatedly denied union complaints seeking to have the results of FCAs 8 and 9 voided. (See FERC Again Rebuffs Brayton Point Union.)

On April 14, the union filed a new challenge, citing ISO-NE’s retirement rule changes to bolster its case for throwing out the results of FCA 10 (ER16-1041).

“As both ISO-NE and the commission have recently recognized … omitting ‘retiring’ capacity entirely from the calculation of the Forward Capacity Auction price, as has occurred here, rather than including it at a ‘proxy’ or other price which represents its true costs, results in the auction being non-competitive and the resulting prices not just and reasonable,” the union wrote.

April 18, 2016January 30, 2024

Company Briefs

A conservation group named the Susquehanna River as the nation’s third-most endangered, blaming Exelon’s Conowingo Dam for allowing pollutants and sediment to flow into the Chesapeake Bay. American Rivers said the 88-year-old dam’s ability to capture those materials is exhausted.

The Susquehanna, which runs nearly 500 miles from Cooperstown, N.Y., drains half of the state of Pennsylvania and provides more than half of the Chesapeake’s fresh water. Nitrogen from farm runoff feeds algae blooms, creating dead zones.

Maryland officials have asked the U.S. Senate to reject legislation they say would allow Exelon to avoid complying with state water quality standards. Exelon, which is seeking to renew its federal license for the dam, said the company is working with stakeholders to protect the bay’s health.

More: The Baltimore Sun; American Rivers

Documents Show ExxonMobil, Others Hid Climate Change Info

Documents released by the Center for International Environmental Law as part of its ongoing project on the energy industry’s studies of climate change suggests industry insiders had hard knowledge of carbon dioxide’s effect on the global climate as early as 60 years ago.

“From 1957 onward, there is no doubt that Humble Oil, which is now Exxon, was clearly on notice” about rising CO₂levels, said Carroll Muffett, the center’s director. Muffett and others involved in the project say the industry put together a group to monitor pollution studies and to encourage public skepticism to fight against environmental legislation.

The documents are the latest released by the center, which have led four attorneys general to begin investigating Exxon.

More: The New York Times

400-MW Wind Farm to Serve Kansas City, Google

A European utility company is teaming up with a Kansas developer to build a 400-MW wind farm in the southwest portion of the state. Enel Green Power North America, the American subsidiary of Italy’s Enel, and Tradewind Energy announced the project April 8.

The $613 million Cimarron Bend project will be the largest wind farm Enel has ever built, and it will be the second largest wind farm in Kansas. The developers say the project will create 350 construction jobs and produce enough energy to power 150,000 households.

The project will consist of 200 wind turbines on 60 square miles. It will sell power to the Kansas City Board of Public Utilities, which serves as the municipal electric utility for the city, and Google.

More: Lawrence Journal-World

FirstEnergy Customers Offered 100% Wind Power at SOS Price

FirstEnergy is offering a limited number of Ohio customers the opportunity to switch to 100% wind-generated energy at the same price as standard power. The program, Switch2Green4Free, is open to the first 1,000 residential customers who enroll.

The power will be sourced through a contract with subsidiary FirstEnergy Solutions from wind farms throughout the country.

But Trish Demeter, managing director of Energy & Clean Air Programs at the Ohio Environmental Council, was skeptical about the promotional program’s aim, saying that FirstEnergy still appears committed to fossil fuel generation. “We’re not really seeing any clear path forward for FirstEnergy as far as making any real and substantial transition to a cleaner portfolio,” she said.

More: The Plain Dealer

Exelon’s Nine Mile Point Unit 2 Refueling Begins

Exelon removed Nine Mile Point Unit 2 from service last week for a planned refueling outage. For several weeks, more than 2,000 workers will replace nearly one-third of the reactor’s fuel and perform thousands of inspections and maintenance activities.

The Unit 2 outage comes as Exelon is urging state utility regulators to implement new “clean energy” subsidies to help its nuclear plants survive the financial stresses caused by low-cost natural gas-fired power plants.

Nine Mile Point Unit 1 will continue to generate electricity during the Unit 2 outage.

More: Syracuse.com

Marathon Oil Selling Wyo. Holdings to Merit Energy

Marathon Oil announced last week it is selling its Wyoming oil-producing assets to Merit Energy for $870 million. It is selling leases in the Big Horn and Wind River basins, a reflection of the continued downturn in oil operations in those regions.

Marathon, which has a 100-year history of oil production in Wyoming, announced its intention earlier this year to sell up to $1 billion in assets in order to concentrate on wells that produce higher returns. Its core assets are in North Dakota and Texas.

“Ongoing portfolio management continues to drive the simplification and concentration of our portfolio to lower-risk, higher-return U.S. resource plays and support our 2016 objective of balance-sheet protection,” Marathon CEO Lee Tillman said.

More: Casper Star Tribune

Duke Retires Wabash River Station Units After 63 Years

Four coal-fired units at Duke Energy’s Wabash River Generating Station near Terre Haute, Ind., have gone cold after 63 years of service. Units 2, 3, 4 and 5 shut down about a week before their air permits expired Friday.

One unit at Wabash Station is still active. Duke says it is investigating a possible fuel switch to natural gas.

More: The Journal Gazette

Purdue Scientists Pursue Hybrid Solar-Hydrogen Tech

Purdue University scientists are working with Swiss researchers to develop “hydricity,” a term they’ve coined for a thermal-solar system that generates electricity and produces hydrogen to generate power when solar power is unattainable.

Hydricity uses concentrated solar energy to superheat water to produce steam for immediate power generation, as well as hydrogen, which is stored for generating electricity when there’s little to no sunlight. Although the process is expensive, researchers see value in the project because stored hydrogen doesn’t lose energy over time, unlike batteries.

“Here what we’re doing by co-producing hydrogen, we avoid a step of making electricity and then storing it,” said Purdue chemical engineering professor Rakesh Agrawal. “We directly make hydrogen from sunlight, and that’s what makes it more efficient. We can do almost anything: purify water, produce chemicals, create fertilizer for food production.”

More: Inside Indiana Business

Merger Credits Begin Rolling Out to Md., DC Pepco customers

Pepco customers in Montgomery and Prince George’s counties will begin receiving the first of two $50 bill credits this month as part of the company’s recent merger with Exelon. The second credit will be applied to bills in 2017.

D.C. ratepayers also should see a $54.59 credit in their bills this month.

Pepco said information about credits for customers in Delaware and New Jersey, also affected by the merger, will be forthcoming.

More: Washington Business Journal

Exelon Power Plant Site in Boston Sold

Exelon has agreed to sell its century-old New Boston Generating Station to Hilco Global and Boston developer Redgate Real Estate for undisclosed terms. The sale is set to close by the end of June.

The buyers have not disclosed their redevelopment plans, said a spokesman for Hilco, a Chicago-area financial services conglomerate whose redevelopment arm specializes in “maximizing the value of obsolete industrial sites.” Hilco and Redgate beat out at least six other bidders for the property.

The plant, built in 1892 to burn coal, was later converted to oil and then to natural gas before being largely retired in 2007.

More: The Boston Globe