FERC last week issued decisions related to CAISO’s resource adequacy program and markets, as well as transmission service in the Pacific Northwest.
The commission approved six tariff revisions related to CAISO’s resource adequacy program (ER18-1). The order allows resources in a local capacity area to provide substitute capacity based on how that capacity is reflected in resource adequacy plans. It also accepted the ISO’s proposal to cap a load-serving entity’s monthly local capacity and system requirements at the same levels.
FERC granted Wheatridge Wind Energy’s request for an order directing Umatilla Electric Cooperative to interconnect with Wheatridge’s proposed wind energy project
The order is a follow-up to FERC’s October 2015 acceptance of a CAISO filing regarding updates to its reliability services initiative stakeholder process. The filing included criteria for qualifying capacity values of certain resource adequacy resources, must-offer obligations and other modifications.
In another order, FERC (ER17-1459) addressed modifications it had directed CAISO to make regarding its 2006 Market Redesign and Technology Upgrade (MRTU). CAISO’s latest compliance filing was on April 21, 2017.
FERC considered six directives it had issued, saying “we find that CAISO has either complied with the outstanding directives in the September 2006 MRTU order or has provided information demonstrating circumstances have changed such that further revisions are not necessary.”
In the Northwest-related order, FERC granted Wheatridge Wind Energy’s request to direct Umatilla Electric Cooperative to interconnect with Wheatridge’s proposed 500-MW project and provide it with transmission service to the Bonneville Power Administration balancing area (TX17-1).
The project would serve a collector substation in the service territory of Columbia Basin Electric Cooperative, which had protested Wheatridge’s application, arguing that it must be the exclusive provider of transmission service to the project. Umatilla supported the Wheatridge filing.
New York regulators last week approved the state’s third community choice aggregation (CCA) program, authorizing energy consultant Good Energy to provide five upstate municipalities with bulk purchasing of electricity and natural gas.
The Public Service Commission’s Jan. 18 order allows the new CCA to serve the villages of Fayetteville and Minoa in central New York, along with the village of Coxsackie and the towns of Cairo and New Baltimore near Albany.
NY DPS Staff and audience at the January 18th PSC session | NY DPS
Authorized by the PSC in 2015 under Gov. Andrew Cuomo’s Reforming the Energy Vision, CCAs can provide communities with lower energy prices as well as clean energy options, according to the PSC.
“Residential and small business customers can reduce their energy bills, take advantage of renewable energy choices and enjoy other money-saving services thanks to the leverage enabled by the bulk purchasing available through these community-based associations,” PSC Chair John B. Rhodes said.
Rhodes | NY DPS
While the five towns represent Good Energy’s first programs in New York, the company has helped create CCAs for more than 60 communities in other states, serving nearly 400,000 households and providing 3.3 billion kWh annually.
The commission previously allowed 20 municipalities in Westchester County to form a CCA (14-M-0224), and last year it approved a CCA by the Municipal Electric and Gas Alliance for several towns in central and upstate New York.
Burman | NY DPS
Commissioner Diane Burman supported the measure, but she urged that all stakeholders affected by the decision be heard, especially low-income residents and consumer advocates.
“Out of the seven states that have done community choice aggregation, New York is the only state that has done this outside of the legislative process,” Burman said.
Communities can pass local laws to join or establish a CCA, but they must ensure that residents and small businesses can choose to remain a customer of a utility or energy service company (ESCO). Good Energy will help each of the five communities select an ESCO to manage its CCA, which could begin operating during the second quarter of 2018.
PSC Approves 4th Tranche of VDER
The commission last week also approved implementation of the fourth tranche in its Value of Distributed Energy Resources (VDER) tariff, continuing the transition away from net energy metering (NEM).
“Several transition mechanisms were in that order,” Ted Kelly, assistant counsel for the Department of Public Service, told the commission. “Onsite mass market customers such as rooftop solar continue to receive net metering for all projects built before Jan. 1, 2020. Mass market customers — that’s residential customers as well as small businesses —participating in community-generated distribution projects, community solar for example, receive a market transition credit, or MTC, on top of the value stack.”
The commission’s Jan. 18 order recognized that several utilities had exceeded the limits of their capacity allocations under the program. Orange and Rockland Utilities last April filed a letter notifying the commission that 85% of the total megawatt capacity for its tranches had been allocated, but the utility continued to assign projects to Tranche 3, which is now 28 MW over its original 12-MW size.
| NY DPS
In December, Central Hudson Gas and Electric told the PSC that it had reached 85% of its total allocation, and then subsequently filed an update that Tranche 3 had exceeded its 19-MW capacity, with 29.7 MW currently allocated.
Burman supported the measure but said, “I continually have felt that we are doing a delicate dance of being unwilling to admit that we may have a problem in going from net metering to [VDER] and the transition of that and what that means for when we lift and completely get rid of NEM and the grandfathering issue.”
Burman nonetheless said she supported the majority position of not disrupting the distributed generation effort and agreed that REV should ultimately decide alternatives to net metering.
MISO obtained a one-time waiver of the deadline for its 2017/18 capacity auction after FERC last week agreed that technical difficulties on the RTO’s market platform was reason enough to extend the offer window.
While MISO normally closes the three-day offer window for its Planning Resource Auction at 11:59 p.m. ET, it said last year network connectivity issues caused by a hardware failure forced it to extend the window until 12 p.m. on April 1. Without the extension, at least one market participant would have been unable to submit or modify its offers during the final hours of the auction on March 31, according to the RTO.
| MISO
In its ruling last week (ER17-2113), FERC said that extending the offer deadline ensured “all market participants had the requisite time under the Tariff to submit their auction offers.” The additional time “provided sufficient, but not excessive, time for market participants to submit or modify offers,” the commission said.
MISO had assured the commission that the waiver will “not have undesirable consequences and that no third parties are harmed.”
Consumer rights watchdog Public Citizen questioned the waiver, claiming MISO failed to adequately describe what caused the connectivity issues or to explain what corrective actions it has planned “to avoid such disruptions in the future.” FERC disagreed with the group’s contention that MISO should have to provide additional evidence or detail any future plans stemming from the mishap.
FERC last week approved SPP’s request to issue price corrections and resettlements for a two-week period in December 2016, stemming from Omaha Public Power District’s retirement of its Fort Calhoun nuclear plant (ER17-2495).
After OPPD deregistered Fort Calhoun from SPP’s Integrated Marketplace on Dec. 1, 2016, the RTO established a replacement settlement location to recognize previously awarded transmission congestion rights (TCRs) at the plant. However, the market software did not model the replacement location’s correct shift factors, resulting in an overstated marginal congestion component and understated TCRs. The error was not corrected until Dec. 14.
Fort Calhoun in 2016 | OPPD
In a September 2017 filing with FERC, SPP said the error did not affect other settlement locations. It requested commission approval for the repricing because it did not notify market participants of the contemplated price correction within five calendar days of the operating day, as required by its Tariff.
SPP told FERC the modeling errors were associated with the Fort Calhoun deregistration and were “human performance anomalies that have since been corrected.” The RTO said it can recalculate the prices “with accuracy,” ensuring that market participants that “unfairly suffered” from the error will be made whole and creating only a “minor monetary impact” for other participants.
The resettlements will amount to $145,000 in net payments to TCR holders at the location, and a net charge of $400 to the virtual transactions.
FERC on Thursday again rejected a challenge to Ameren Illinois’ formula rate while tamping down a rehearing request from Ameren itself (EL16-1169-001).
| Ameren Illinois
The ruling denying rehearing lays to rest a challenge by Southwestern Electric Cooperative and Southern Illinois Power Cooperative to Ameren’s 2015 $214.4 million projected net revenue requirement. FERC largely upheld the rate in a September 2016 order while ordering Ameren to change how it accounts for contributions in aid of construction; include net operating loss carryforward in its rate base; and exclude some charges for allowance for funds used during construction from its 2016 true-up. (See FERC Finds No Significant Problems in Ameren Rate Filing.)
Both Ameren and the cooperatives sought rehearing of the 2016 ruling, with the company arguing that FERC should have dismissed the cooperatives’ first challenge outright because of “nebulous and undocumented assertions.” The cooperatives said FERC had broken with commission precedent that allows “parties to challenge the inputs to the formula rate in the same way as they can challenge costs in a stated rate case” because the commission declined to investigate whether the challenged costs were recoverable.
FERC rejected both arguments. “The commission’s power to dismiss a pleading summarily is discretionary, and declining to exercise that power here is therefore not legal error,” it told Ameren. It told the cooperatives that their interpretation of commission precedent was inapplicable because they were challenging the rate itself and not seeking “after-the-fact corrections and updates.” Finally, the commission refused the cooperatives’ request to expand the proceeding into a broader investigation of Ameren’s expenses. Initiating such an investigation, FERC said, would be beyond the scope of the complaint.
Louisiana regulators are questioning why MISO called a maximum generation event and issued instructions for conservative operations in its South region during an extreme cold snap last week.
Eric Skrmetta, chair of the Louisiana Public Service Commission, told The Advocate that he’ll seek an investigation into last week’s actions in MISO South, saying there was “no reason in the state of Louisiana for electricity to become short.” Commissioner Craig Greene said the agency would examine the electricity supply during the cold snap and look to identify ideas for better utility response in future frigid weather.
Reached by phone, a member of the PSC’s staff told RTO Insider that they were in the process of reviewing the event and declined to comment further.
MISO spokesperson Mark Brown said the RTO was able to maintain grid reliability even as extreme temperatures gripped the South and multiple generation outages posed challenges.
The RTO declared conservative operations and a cold weather alert for MISO South — which spans Arkansas, Louisiana, portions of Mississippi and part of eastern Texas — beginning Jan. 15, when most of Louisiana was under a winter weather advisory. It cautioned operators in the natural gas-heavy region to prepare for fuel restrictions.
The region set a new winter demand record of 32.1 GW on Jan. 17 as temperatures dipped to about 30 degrees Fahrenheit below normal and winter storm warnings were issued in Louisiana. The region’s all-time summer peak is 32.6 GW.
That same day, Entergy Louisiana reported that about 32,000 homes and businesses had lost power because of the winter storm, and it later thanked customers for responding to the conservation plea.
Entergy crews in snow | Entergy
The South region resumed normal operations late on Jan. 18, after the Louisiana PSC had issued a public appeal on behalf of MISO and Entergy Louisiana asking customers to conserve energy by lowering thermostats, sealing households against outside air as much as possible and postponing laundry and bathing during the unusually cold temperatures.
Louisiana tops all other U.S. states in energy consumption per capita, in part because of the number of oil refineries and manufacturing plants on the Gulf Coast, according to a report last year by the U.S. Energy Information Administration.
MISO South Executive Director of External Affairs Kent Fonvielle said the RTO shared the Louisiana PSC’s concerns about reliability.
“In extreme conditions such as this week’s bitter cold in the South, MISO delivers the value of a large footprint with a diverse energy mix and greater redundancies to address various challenges to operations,” Fonvielle said in an email to RTO Insider. “As the generation resources available to serve these extreme load conditions become strained, MISO has a set of procedures to ensure adequate supply and to keep the transmission grid stable.”
He added that, in such situations, MISO South calls on support from MISO Midwest and makes purchases from other RTOs. It’s also common for MISO to request that members activate their load control programs and issue public appeals for conservation, he said.
“It is rare for MISO to ask for conservation efforts, but ultimately those conservation efforts help protect the larger grid,” Fonvielle said. “Our role is to coordinate the best use of the power resources available across the MISO footprint so that it is reliable and cost-effective.”
Fonvielle said MISO appreciated the cooperation it received from South members, stakeholders and consumers to conserve energy during the peak conditions. He added that the RTO would perform its own review of the week’s events and have staff discussions on possible areas of improvement.
The D.C. Circuit Court of Appeals on Friday rejected New England generators’ challenge to FERC orders on scarcity prices, saying the commission had properly considered their complaints (16-1023, 16-1024).
The New England Power Generators Association had asked the court to review two FERC orders related to ISO-NE’s scarcity pricing rules and the peak energy rent (PER) adjustment, which is used to claw back some revenues earned by capacity suppliers when prices in the real-time energy market are very high.
Adjustment Events
ISO-NE each day calculates a strike price set just above the marginal cost of the RTO’s most expensive generation. It also estimates PERs — essentially the difference between the real-time energy price and the strike price — for any hour in which the real-time price exceeds the strike price (“adjustment events,” the court called them).
The PER value is deducted from each capacity supplier’s monthly payments, regardless of whether it sold energy in the real-time market at the high price. NEPGA says most capacity suppliers clear their electricity offers in the day-ahead market, receiving the day-ahead market price, rather than the real-time price on which the adjustment is based.
The commission has acknowledged that this is a “potential inefficiency” and has approved elimination of the adjustment for the 2019/20 capacity commitment year.
Procedural Failure
The D.C. Circuit dismissed on procedural grounds NEPGA’s challenge to FERC’s May 2014 order rejecting a joint filing by ISO-NE and the New England Power Pool Participants Committee.
That “jump ball” filing contained two alternate proposals to address generator performance problems. The commission said neither proposal was sufficient alone, ordering ISO-NE to submit a modified version of its proposal along with increased scarcity prices suggested by NEPOOL (ER14-1050, EL14-52).
The D.C. Circuit said NEPGA lacked standing to seek review of the order because it had not previously sought rehearing from the commission.
Not Arbitrary or Capricious
The court did act on the merits of NEPGA’s complaint alleging that the interaction between the scarcity prices and the PER is unjust and unreasonable.
FERC said the group had not met its burden under Section 206 to prove that the existing Tariff provisions were unjust and unreasonable (EL15-25). The commission said NEPGA’s evidence — data from a Dec. 4, 2014, adjustment and a back-cast analysis — failed to consider the likelihood and size of future adjustments. It also said NEPGA did not address whether increases in day-ahead energy prices and capacity price floors might offset expected increases to the PER. (See FERC Denies Rehearings on ISO-NE Pay-for-Performance.)
The court said the commission’s rejection of the complaint was not arbitrary and capricious, noting that “because we are dealing here with technical and policy-based determinations, the commission’s judgment is entitled to judicial respect.”
Second Complaint
NEPGA said the court should overturn the commission’s rejection of its complaint because of the outcome of the group’s second complaint challenging the PER, filed in September 2016.
In that filing, NEPGA provided an additional 20 months of data in arguing that the PER had become unjust and unreasonable because of the increased scarcity rates.
An uncontested settlement in that docket is pending before the commission. It would require ISO-NE to increase the daily PER strike price hourly based on the difference between actual five-minute reserve shadow prices and the pre-December 2014 scarcity prices for 30-minute operating reserves and 10-minute non-spinning reserves ($500/MWh and $850/MWh, respectively). The adjusted PER strike price would be effective Sept. 30, 2016, through May 31, 2018, when the PER is abolished.
“We note that any settlement would not fully moot this case because the second complaint proceeding has a refund effective date of Sept. 30, 2016, whereas the complaint in this case requested a refund effective date of Dec. 3, 2014,” the court said.
FERC last week denied the Louisiana Public Service Commission’s request for clarification on one matter related to a sprawling Entergy-related case before the federal commission.
The PSC was seeking to learn what specific proceeding would determine the return on equity that would apply to amended power purchase agreements that were the subject of an August 2016 order (ER16-1251). It requested the clarification following a January 2017 FERC order denying its request for a rehearing of the 2016 ruling. FERC had said the proceeding regarding the amended PPAs was not the right forum for determining the appropriate ROEs to be applied under a replacement tariff, finding the issues raised by Louisiana regulators to be outside its scope.
The PSC said “that if the appropriate ROE … is outside the scope of the instant proceeding, it does not appear the ROE will be addressed in any [FERC] proceeding.”
In its Jan. 18 ruling, FERC told the PSC it had explained in the 2016 order that issues concerning the application of ROE under Entergy’s unit power sales and PPAs are pending in the massive ER13-1508 docket. FERC also noted that it had already dismissed concerns by the PSC about applying a generic ROE to the amended PPAs.
MISO North and MISO South | MISO
FERC last week also approved an uncontested partial settlement related to adjustments in MISO Tariff transmission formula rate templates for Entergy’s operating companies (ER17-2579), directing the company to file a revised rate template in eTariff and terminating four related dockets (ER17-2579, ER16-1528, ER15-1453 and ER15-1436).
Entergy Services had objected to FERC trial staff’s October 2017 recommendation that it file a revised rate template for Entergy Gulf States Louisiana, but a settlement judge in November certified the partial settlement as uncontested.
The settlement memorializes adjustments to three items in the Entergy operating companies’ rate templates: excess accumulated deferred income taxes; certain permanent differences in income taxes; and the Entergy operating companies’ post-retirement benefit costs other than pensions for 2014 and 2015.
FERC on Thursday denied requests by New England transmission owners and the Edison Electric Institute for rehearing of its September 2016 ruling regarding complaints over the TOs’ base return on equity.
Since September 2011, numerous parties have filed complaints seeking reductions in the New England TOs’ base ROE.
The commission’s 2016 order established hearing and settlement judge procedures and a refund effective date for a complaint filed by an ad hoc group of municipal utilities, Eastern Massachusetts Consumers-Owned Systems, which contended that the New England TOs’ 10.57% base ROE (11.74% including incentives) should be reduced to 8.78% and 11.38%, respectively.
| ISO-NE
The commission’s Jan. 18 order rejected every argument made by the TOs, saying it “has repeatedly rejected the assertion that every ROE within the zone of reasonableness must be treated as an equally just and reasonable ROE in [a Federal Power Act] Section 206 proceeding” (EL16-64-001).
FERC in October rejected a bid by the TOs to increase their ROEs to the levels before they were lowered by a 2014 commission order vacated by an appellate court in April 2017. The commission said it would address the actual rate in a later remand order (ER15-414, EL11-66). (See FERC Rejects New England Tx Owners on ROE.)
The TOs also argued that constant litigation over the ROEs introduces risk and uncertainty in the ratemaking process.
They contended that the 15-month refund limitation in Section 206, as amended by the 1988 Regulatory Fairness Act, requires the commission to deny a complaint when a similar complaint is already pending.
“While Congress’ adoption of a 15-month refund limitation in the Regulatory Fairness Act gave public utilities some rate certainty in FPA Section 206 proceedings, the New England TOs misinterpret the level of certainty that Congress provided,” the commission said.
Following such logic “would prohibit any party from challenging a utility’s ROE as long as there is another complaint involving that utility’s ROE pending before [FERC], the commission said. “The language of FPA Section 206 does not support such a finding.”
The commission also rejected the TOs’ assertion that it had ignored “countervailing evidence regarding the cost of equity capital and the fact that the capital markets continue to remain unusual,” insisting it “had reviewed the pleadings and evidence submitted by all parties and found that the evidence raises issues of material fact that could not be resolved based upon the record before the commission. The hearing and settlement judge procedures established in the September 2016 order are the product of that review and are the appropriate vehicle to resolve the dispute.”
FERC on Thursday denied Bear Swamp Power’s request for a waiver of the requirement to include certain affiliate information in its market-based rate filings (ER17-603).
Bear Swamp, which is controlled by Brookfield Renewable Energy Group, operates the 600-MW Bear Swamp Pumped Storage Development and the 10-MW Fife Brook Development on the Deerfield River in northwestern Massachusetts.
Bear Swamp Project Map | Brookfield
In December 2016, the company filed a notice of change in status, reporting that Nova Scotia-based Emera had acquired an indirect 50% ownership in the company. Bear Swamp requested a waiver of the requirement to include Emera generation and transmission assets in its change-in-status notice and future market-based rate filings.
The company argued that Emera’s affiliates should not be included in its horizontal market power analysis and other filings because its generation capacity is fully attributed to Brookfield, and Brookfield is not privy to Emera’s acquisition activities. Emera affiliates include Emera Maine and Tampa Electric.
Bear Swamp Reservoirs | Google Maps
“Bear Swamp has not presented any compelling reason for its request,” the commission said in its Jan. 18 order. “The facts that Brookfield and its affiliates are not privy to the acquisition activities of Emera and its affiliates, and that a Brookfield affiliate controls day-to-day operations of Bear Swamp’s generation facility, [do] not affect the affiliate relationship between Emera and Bear Swamp.”
The commission directed the company to submit an updated market power analysis including Emera affiliates within 30 days.
Under FERC’s market-based rate regulations, any company controlling 10% or more of another company is considered an affiliate.
