Below is a summary of the issues scheduled to be brought to a vote at the Markets and Reliability and Members committees Thursday. 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.
RTO Insider will be in Wilmington, Del., covering the discussions and votes. See next Tuesday’s newsletter for a full report.
Markets and Reliability Committee
2. PJM Manuals (9:10-9:30)
Members will be asked to endorse the following manual changes:
Manual 19: Load Forecasting and Analysis. Revisions remove outdated rules for legacy air conditioner and water heater cycling programs and correct formulas for end-use/weather variables.
Manual 12: Balancing Operations. Manual, Tariff and Operating Agreement changes incorporate business rules for dynamic transfers.
3. Governing Documents Enhancement and Clarification Subcommittee (GDECS) (9:30-9:40)
Changes eliminate redundant definitions and list definitions in alphabetical order.
4. Demand Response Emergency Energy Settlement Measurement and Verification (9:40-9:55)
New method changes the emergency energy default customer baseline (CBL) from the hour before to the current default economic CBL. (See “Members Endorse New Way to Measure Emergency DR,” PJM Market Implementation Briefs.)
FERC on Friday approved the controversial cost allocation of two PJM projects: a stability fix for New Jersey’s Artificial Island nuclear complex and the Bergen-Linden Corridor upgrade.
“The courts have recognized that no cost allocation method can perfectly assign costs to the beneficiaries of a transmission project, particularly in the case of a transmission grid,” FERC said in its 3-1 order approving the Artificial Island allocation proposal (EL15-95. ER15-2563). “The commission found that where a cost allocation method is accurate in a very high percentage of circumstances to which it applies, then that is a strong indicator that the cost allocation method is just and reasonable.”
Commissioner Cheryl LaFleur dissented, saying, “The record in this case clearly establishes that there is a discrete and identifiable set of transmission projects as to which [the distribution factor cost allocation (DFAX)] methodology produces an anomalous result and does not allocate costs in a manner roughly commensurate with benefits.
“It is a cliché to observe that hard cases make bad law, but unfortunately I believe that is the result of today’s orders,” she said. “Because the instant cases are discrete and identifiable and have significant rate impacts that are not roughly commensurate with benefits, a failure to grant these complaints may actually undermine a cost allocation methodology that is just and reasonable in the vast majority of instances.”
The commission in November called for an inquiry in response to complaints over the allocation for the projects and held a technical conference on the issue in January. (See DFAX: ‘Poison Pill’ or ‘Best Method’ of Cost Allocation?) It asked: Is there a definable category of projects for which the DFAX method might not be appropriate, and could a fair approach be developed for those occasions?
The Delaware and Maryland public service commissions protested the cost allocation of the Artificial Island project, virtually all of which will be paid for by customers in the Delmarva transmission zone.
They cited a study requested of PJM by the Delaware commission that found only about 10%, or $17 million, of the $169 million annual load payment savings would accrue to customers in that zone. However, those customers will be allocated about $246 million of the costs.
Critics said DFAX is inappropriate for non-flow-based fixes, such as those addressing short-circuit violations, storm-hardening or stability limits.
Said FERC: “Comments opposing the solution-based DFAX method can only point to two projects out of over 1,200 identified by PJM as raising concerns.”
The DFAX method, the commission said, “focuses on the benefits of the facility as measured through use of the facility over time rather than the reliability violation that drove the immediate need for the project.”
In the second ruling — in which LaFleur also dissented — FERC denied a complaint from Consolidated Edison and Linden VFT and upheld the assignment of an additional $91 million in cost to Con Edison for the Bergen-Linden Corridor project (ER15-2562, et al.).
“As PJM explains, the costs related to the reconfiguration are necessary to address construction challenges and the elimination of high short-circuit current issues identified by [Public Service Enterprise Group], such as no longer reusing existing underground ducts to install new 345-kV cables and substation expansion for an additional 345-kV line,” the commission said. (See Developer Questions Need for PSE&G Projects without ‘Wheel’.)
Meanwhile, the Artificial Island project faces other hurdles. After Public Service Electric and Gas submitted estimates that nearly doubled the cost of its scope of work to $272 million, PJM planners are considering reconfiguring the project.
The Delaware PSC did not return a request for comment. However, Bob Howatt, the PSC’s executive director, told The News Journal that the PSC is considering filing a motion for rehearing with FERC as a prerequisite for a court appeal. “The court process is not inexpensive,” Howatt cautioned.
Delaware Public Advocate David Bonar has estimated that Artificial Island could result in rate increases of about $3/month for residential and small businesses, while increasing rates for large manufacturers by “tens of thousands.”
Some Alternate Supplier Electric Customers Paying More
The state’s Office of Consumer Counsel says thousands of residential customers who signed up with competitive electric suppliers paid more for power than customers who stayed with the standard offers from Eversource Energy or United Illuminating.
In Eversource’s territory, customers with 18 of the 28 third-party service providers paid $48 million more than the standard offer. In UI’s service area, customers with 18 of 29 competitive suppliers paid $10 million more than standard-offer customers.
Bryan Lee, a spokesman for the Retail Energy Supply Association, said the consumer advocate “is making an unfair apples-to-oranges comparison when it compares a ‘plain vanilla’ utility standard service electricity rates with the varied and complex product offerings of competitive retail energy suppliers.”
BL England Generating Station Looking to Convert to Gas
The owners of the coal-fired B.L. England Generating Station have applied to the Department of Environmental Protection for emissions permits to convert the plant to natural gas, now that a controversial pipeline to the facility has been approved.
“It’s probably the dirtiest plant left in the state,” DEP spokesman Larry Hajna said, adding that the 52-year-old plant is one of “just a handful” that still burn coal. The plant on the Jersey Shore is owned by RC Cape May Holdings, a special purpose entity formed by Rockland Capital, Energy Investors Funds and other investors.
Environmentalists are protesting the conversion. They say the 447-MW upgraded plant actually would increase pollution because the gas-fired plant would operate daily, while only one of the plant’s current coal units is active, and it only operates 60 days a year.
Energy conservation officials have been hit with a flood of applications for the state’s solar tax credit and are on track to meet the $3 million annual cap by July.
This is the last year for the state’s 10% tax credit. A measure calling for extending the incentive through 2024 stalled during the last legislative session.
Gov. Andrew Cuomo on Thursday announced $150 million in funding to support large-scale renewable energy projects across the state to help meet the goal of 50% of electricity from renewable energy by 2030.
“This state is a national leader in combating climate change, and with this investment, we are taking our unprecedented efforts one more step toward a cleaner and greener New York,” he said. “This funding will advance large-scale energy projects, continue build[ing] a clean energy economy and generate opportunity for New Yorkers for generations to come.”
Support will be provided by the New York State Energy Research and Development Authority in its final solicitation through the main tier of the state’s renewable portfolio standard.
The next round of the NY Prize microgrid competition will provide $8 million in awards for engineering designs and business plans for community microgrids, Gov. Andrew Cuomo said.
The $40 million program is part of the Reforming the Energy Vision. The NY Prize engineering design and business plan component will award up to $1 million to each of the eight winners. The deadline for proposals is Oct. 13, 2016. The competition is administered by the New York State Energy Research and Development Authority, which is currently reviewing final reports and conducting an analysis and evaluation of the feasibility studies.
Study Says Preserved Nuclear Plants Cost-effective
Preserving upstate nuclear plants via a proposed Clean Energy Standard provides benefits that exceed the costs, according to an analysis by The Brattle Group for the Public Service Commission. (See NYPSC: Minimal Cost to Meet 50% Renewable Goal.)
The nuclear component of the Clean Energy Standard is responsible for more than 50% of the program’s lifetime financial benefits from carbon avoidance, despite incurring only 21% of the program’s overall costs. Power cost savings enables an additional $3.16 billion in annual gross domestic product, according to the study.
The report was prepared for the New York State IBEW Utility Labor Council, the Rochester Building and Construction Trades Council and the Central and Northern New York Building and Construction Trades Council.
Regulators Side with Duke in NC WARN-Church Solar Deal
The Utilities Commission fined an advocacy group $60,000 for violating state law by installing a solar array on the roof of a Greensboro church and then selling the electricity directly to the church. The commission said NC WARN, by law, should have produced the power, sold it to Duke Energy, which then would have sold it to the church.
The commission said NC WARN’s direct contract with the church was impermissible because the church is located within Duke’s exclusive service area. “NC WARN knowingly entered into a contract to sell electricity in a franchised area and sold electricity without prior permission from the commission, subjecting itself to sanctions,” the commission said. It ordered the group to stop operating the solar array and to turn it over to the church.
NC WARN Director Jim Warren vowed to appeal. “The decision to impose the fine is pretty surprising,” he said. “In the past, that kind of fine has been used against outright lawbreakers.” He said the arrangement was made to test the law on electricity sales.
Health Officials Go Silent on Safety Guidance near Ash Ponds
The Department of Health and Human Services says it has stopped offering any guidance to owners of drinking-water wells near Duke Energy coal ash ponds, citing pending legislative action that would govern water testing and advisories.
“We are carefully monitoring this proposed legislation and are not able to comment further on safety recommendations until the General Assembly takes action,” a department spokeswoman wrote in an email.
The department last year issued do-not-drink notices to owners of hundreds of wells near coal ash basins because their water contained elevated levels of hexavalent chromium, but it recently notified the landowners the water was safe to drink. There are no federal or state standards for hexavalent chromium. Lawmakers say the pending legislation will clear up any confusion. “They scared these folks erroneously,” Rep. Pat McElraft said. “Everybody thought Duke was poisoning them when they weren’t.”
The state Supreme Court upheld most of American Electric Power’s 2012 rate increase, remanding part of the case to the Public Utilities Commission to review if customers should receive any refunds.
The court ruled that PUCO was correct when it approved AEP’s special “capacity charge” to make the utility whole during its transition to market-based pricing.
But the court also ruled that a portion of the rate increase was a de facto “transition charge” that added up to $508 million. Some of that, it said, could be improper.
Public Utility Commissioner Pamela A. Witmer is leaving the commission at the end of April to become vice president of government affairs at UGI Energy Services, a company that comes under the commission’s regulation.
Witmer’s five-year term ended on April 1. A Republican who was appointed by Gov. Tom Corbett in 2011, her departure leaves an important vacancy on the commission, now split evenly between Democrats and Republicans. Democratic Gov. Tom Wolf has yet to nominate a replacement.
The Public Utility Commission wants to focus greater scrutiny on the state’s three public steam heat plants.
The plants produce and deliver steam heat through pipes to business districts in Philadelphia, Harrisburg and the North Shore of Pittsburgh.
Citing the risk for accidents and a thin oversight staff at the plants, the PUC is releasing proposed regulations that will call for more inspections and reporting of steam leaks and emergencies.
The Hunt Group, the would-be buyers of Oncor, are trying to change the terms of a contentious agreement it hammered out only a month ago with the Public Utility Commission. The request for a rehearing offered a bleak assessment of the sale going through.
Minutes after the Hunt Group filed a formal request for a rehearing, PUC staff filed a statement that said the group’s separate application for a rate-setting procedure failed to meet legal requirements necessary to allow the sale to go forward. Legal deadlines loom that could make it difficult to close the purchase. The commission will meet to consider the rehearing on May 4.
The buyers want to split Oncor into two linked companies that could take advantage of a $250 million federal tax break.
The Fort Worth City Council unanimously approved a resolution directing Oncor to explain why its electric transmission and distribution rates should not decrease if its federal tax bill drops under its bankruptcy reorganization plan.
The resolution stems from last month’s approval by the state Public Utility Commission of the Hunt Group’s $18 billion acquisition of Oncor. The PUC last month deferred a decision on the rate question until 2017 at the earliest.
First Commercial Wind Farm Would Top North Mountain
Apex Clean Energy is applying to site 25 wind turbines atop North Mountain in Botetourt County in what would be the state’s first commercial wind farm.
The Department of Environmental Quality has expressed support for the project, though opponents worry that the 550-foot-tall towers and rotating blades might kill birds and bats or contribute to erosion that would contaminate streams.
Richmond Opposes FERC Permit for James River Hydro
The city of Richmond is fighting a company’s attempt to install an 8-MW hydroelectric project at Bosher’s Dam on the James River, saying the generator’s intakes could interfere with fish migration.
Energy Resources USA has filed a request with FERC to give it “priority of licensing” for the hydro project but is not yet seeking a construction permit. It is proposing to divert water at the existing dam through four 2-MW turbines.
The city said the hydro project’s proximity to a fishway might impair fish migration. “The documentation shows the intake for the facility immediately upstream of the ladder, which will adversely impact the function of the ladder,” wrote Patrick Bradley, the city’s water quality manager. “Also, the facility will effectively cut off access to the ladder for operation and maintenance purposes.”
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 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 last week reiterated its 2015 order rejecting New Jersey Energy Associates’ request for recovery of costs incurred during the polar vortex of January 2014.
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.
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.
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.
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.
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.
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.
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.
“The courts have recognized that no cost allocation method can perfectly assign costs to the beneficiaries of a transmission project, particularly in the case of a transmission grid,” FERC said in its 3-1 order approving the Artificial Island allocation proposal (
In Eversource’s territory, customers with 18 of the 28 third-party service providers paid $48 million more than the standard offer. In UI’s service area, customers with 18 of 29 competitive suppliers paid $10 million more than standard-offer customers.
The owners of the coal-fired B.L. England Generating Station have applied to the Department of Environmental Protection for emissions permits to convert the plant to natural gas, now that a controversial pipeline to the facility has been approved.
Preserving upstate nuclear plants via a proposed Clean Energy Standard provides benefits that exceed the costs, according to an analysis by The Brattle Group for the Public Service Commission. (See 
The Utilities Commission fined an advocacy group $60,000 for violating state law by installing a solar array on the roof of a Greensboro church and then selling the electricity directly to the church. The commission said NC WARN, by law, should have produced the power, sold it to Duke Energy, which then would have sold it to the church.
The Department of Health and Human Services says it has stopped offering any guidance to owners of drinking-water wells near Duke Energy coal ash ponds, citing pending legislative action that would govern water testing and advisories.
The state Supreme Court upheld most of American Electric Power’s 2012 rate increase, remanding part of the case to the Public Utilities Commission to review if customers should receive any refunds.
The Hunt Group, the would-be buyers of Oncor, are trying to change the terms of a contentious agreement it hammered out only a month ago with the Public Utility Commission. The request for a rehearing offered a bleak assessment of the sale going through.
Apex Clean Energy is applying to site 25 wind turbines atop North Mountain in Botetourt County in what would be the state’s first commercial wind farm.
“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.
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 (
The commission denied in part and granted in part requests for rehearing by Entergy Services and the Louisiana Public Service Commission (