CARMEL, Ind. — MISO’s Independent Market Monitor said Wednesday that PJM has for years been committing two market-to-market operations errors that have possibly cost MISO millions of dollars.
Monitor David Patton contended that PJM has been “overstating” its response to transmission loading relief (TLR) requests and — more seriously — failing to order mandated tests required to define M2M constraints between the two RTOs.
As a result, PJM’s neighboring balancing authorities have been forced to make up for the RTO’s TLR shortfall and spend more on congestion, incurring costs they are not likely to recover.
Neglected M2M Constraint Test
The test cited by Patton uses real-time system topology to measure the congestion generating resources in a non-monitoring RTO (in this case MISO) contribute to a PJM flowgate, and is mandated by the joint operating agreement between the two RTOs.
“This has not been instituted since it was introduced, which I don’t know, is a decade or more,” Patton said during a Nov. 29 Joint and Common Market meeting between MISO and PJM. “It was an error that was known and is a serious violation of the JOA.”
PJM Director of Energy Market Operations Tim Horger said his RTO is still examining the potential impacts of failing to request the tests but cautioned against labeling the failure to act a Tariff violation.
“PJM is not in a position to say that by not requesting the study it is in a Tariff violation,” Horger said.
It would be “very difficult to quantify the impacts” of PJM’s neglected tests, Patton said, but he thinks they explain some of the past gaps his monitoring firm has observed in M2M coordination. The Monitor’s 2016 State of the Market report showed that substantial volumes of congestion were not coordinated because constraints were not properly identified as being M2M. From January 2016 to October 2017, Patton detected $341 million worth of congestion on constraints that should have been coordinated by PJM.
“Not all of this amount is due to this violation of the JOA; some are likely due to simply not testing constraints or not testing them in a timely manner,” Patton said.
But in consistently failing to evaluate constraints affected by its neighbor’s generators, PJM couldn’t capture transmission outages, “frequently the cause of severe binding constraints,” he said.
“Not only did this undermine efficient dispatch and congestion management, but [it] also effectively granted PJM an unlimited entitlement to MISO transmission” because it did not test for constraints causing congestion, Patton said.
He added that it would be impossible to eradicate all congestion from MISO and PJM’s M2M coordination.
“We know that some of this uncoordinated congestion in MISO is because some constraints weren’t requested to be identified. To be honest, we think that all issues that prevent a constraint from being quickly identified are problematic,” Patton said.
PJM Miscalculation
Patton also contended that PJM’s TLR calculation — which enables MISO, PJM and SPP to acknowledge and receive credit for relief provided during TLR procedures — has been incorrect since 2009. MISO first noticed PJM’s error in September, when binding constraints during TLR procedures in the Tennessee Valley Authority area alone boosted MISO Midwest real-time monthly average prices by almost 8%, according to Patton.
“This has been very costly for MISO because MISO has incurred extreme costs attempting to provide the relief requested in response to a TLR,” Patton said. “If it raised the relief obligation that MISO had, we’re talking a lot of money.”
MISO officials believe PJM has since corrected the problem, although they continue to investigate.
Patton and MISO seams management expert Ron Arness said no precedent exists for resettling energy prices because of TLR errors, but the Monitor thinks the impact could easily reach into the millions of dollars.
“In any particular month, the cost may not be big, but this has been happening for years,” Patton said.
Horger pointed to the challenge of resettling prices influenced by TLRs.
“If after investigation, PJM decides that prices were affected, that doesn’t change the fact that the dispatch reflected the generation movement [in response to TLRs]. That’s a dangerous slope,” he said.
BOISE, Idaho — Integration into the Western Energy Imbalance Market (EIM) can present challenges for resources that don’t fit neatly into CAISO’s existing market model, market participants said during a regional conference Tuesday.
Speakers at the Nov. 28 Regional Issues Forum discussed their approach to effectively integrating hydropower, coal and jointly owned plants into the market. The group, which includes representatives from 10 sectors that gather to discuss various EIM topics, can produce opinions and other documents for CAISO, the EIM Governing Body or the ISO Board of Governors.
Khai Le, senior vice president at generation supply management software developer PCI, told the forum that hydropower units are ideally suited to balance the variable output of renewables in the EIM, but could be much more effective with some operational changes to the market. Most EIM participants have a fairly rich mix of hydro and renewables, and “properly coordinated, that could be a very good marriage between the two,” Le said.
But hydro operators believe “there is lots of room for improvement in terms of hydro dispatch in the EIM market,” he said.
EIM hydro operators include PacifiCorp, Pacific Gas and Electric, Portland General Electric, Puget Sound Energy and Southern California Edison. Their hydro resources vary, and include pumped storage and “cascading hydro” systems in which the discharge from one hydro plant is used as intake for another. Seattle City Light will be the first EIM participant to offer 100% hydro resources when it joins the market in April 2019.
Modeling hydro resources can also be more difficult than other types of generation, Le said. Hydro owners cannot model their plants using CAISO’s “multi-stage generator” (MSG) model because some MSG parameters might only be updated one or two times a month, while hydro units have much more dynamic characteristics that require modeling on an hourly basis.
And while MSG allows for modeling of so-called “forbidden regions” — the different configurations, characteristics and overlapping regions that constrain the operations of many hydro resources — the CAISO system does not recognize cascading hydro and does not understand hydro topology and constraints, Le said.
Integrated properly, hydro operators will get more value in the EIM for the same output they had prior to joining the market, he said. Flexible capacity payments from the EIM are not sufficient for hydro operators to modify their operating rules for the market, he said, constituting just about 5% of the market’s revenue, which is mostly energy payments.
“The greatest challenge in operating your hydro resources is somehow trying to use your bid parameters to reflect the real-life hydro constraint that you have,” Le said.
Operating jointly owned units in the EIM can also be a challenge, according to Kelcey Brown, PacifiCorp manager of market and analytics. When it first joined the market, PacifiCorp modeled the full output of its jointly owned Jim Bridger plant but ran into problems with modeling schedules, ramping, heat rates and other issues.
“There were a lot of problems, actually,” she said. “We just could not get it right.” So in February 2016, the company began modeling only its share of the plant, which has made the situation much smoother, she said.
CAISO does not have the ability to model one unit as separate, individual units, she said, creating the need for PacifiCorp to modify the model to show its individual share of each unit. The company is exploring participation with its Hunter 1 and 2 coal units, which would require a similar approach.
Clay MacArthur, vice president of power marketing at Utah-based Deseret Power Electric Cooperative, met resistance from plant operators and others when he proposed joining the EIM, which the company finally did in August. Deseret’s primary coal resource is the 500-MW Bonanza coal-fired plant, located in EIM member PacifiCorp’s balancing authority area.
“There was a pitchfork-and-torches moment when I announced to the coal plant, ‘Hey, I would like to take the plant into the EIM,’” MacArthur said. The company wanted to optimize its resource portfolio and improve reliability while gaining experience in organized markets.
“Everybody said ‘You’re insane, this is a huge mistake, you can’t do this,’” MacArthur said, because of worries about engineering and responding to the market. The co-op had to be careful to model the Bonanza units for the EIM in a way that would not destroy the unit, he said.
Co-op members visited a PacifiCorp coal plant that was already participating in the EIM and explored what he called “tribal knowledge” about transitioning into the market, which helped convince the doubters.
The EIM does not require owners to completely turn over control of their plants, MacArthur said, but for Deseret, joining the market did involve plant upgrades, simplifying market modeling and using bidding strategies and operational expertise.
“We had to just kind of cross the Rubicon, and hope for the best.”
Richard Glick was sworn in at FERC on Wednesday, giving the commission four members as it awaits the arrival of its new chairman, Republican Kevin McIntyre.
Glick, the general counsel for the Democrats on the Senate Energy and Natural Resources Committee, and McIntyre, the co-leader of the global energy practice at the law firm Jones Day, were confirmed by the Senate on Nov. 2.
Glick, who will serve a term ending in June 2022, did not respond to a request for comment. The term for McIntyre, who will replace fellow Republican Neil Chatterjee as chairman, ends in June 2023. A FERC spokesman said the agency had no information on when McIntyre will be sworn in.
No Conspiracy
The delays in the commissioners’ arrival led some observers to speculate that the Trump administration was purposely dragging its feet so the two could not take part in a vote on the Department of Energy’s proposed price supports for struggling coal and nuclear generators.
On Tuesday, Chatterjee attempted to quash that notion after speaking at a Consumer Energy Alliance event.
“I do want to be clear with everybody: You guys are reading way too much into this,” Chatterjee told reporters, according to an account in The Hill. “There is no conspiracy here. There is no intentional delay or dragging things out to some nefarious end.”
Chatterjee has proposed “interim” protections for threatened generators while the commission considers the department’s Notice of Proposed Rulemaking. Chatterjee, the only commissioner who has publicly supported the NOPR, said FERC will act on the rulemaking by Dec. 11. (See Chatterjee ‘We’ve Moved Past’ DOE NOPR.)
Commissioners Rob Powelson, a Republican, and Cheryl LaFleur, a Democrat, have reacted more warily to the NOPR, expressing concern it could damage wholesale markets. They have declined to take a position on Chatterjee’s “interim” proposal. (See DOE, Pugliese Press ‘Baseload’ Rescue at NARUC.)
Glick and McIntyre have not commented publicly on the NOPR. During his Senate confirmation hearing, however, McIntyre said, “FERC is not an entity whose role includes choosing fuels for the generation of electricity.”
Glick’s Experience
Left to right: FERC Commissioner Cheryl LaFleur, Glick, Chief Administrative Law Judge Carmen Cintron, Commissioner Rob Powelson | FERC
Before joining the Senate staff, Glick was vice president of government affairs for Iberdrola’s U.S. renewable energy, electric and gas utility, and natural gas storage businesses. Earlier, he served as a director of government affairs for PPM Energy and PacifiCorp, and legislative director and chief counsel to Sen. Dale Bumpers (D-Ark.). During the Clinton administration, he was a senior policy adviser to Energy Secretary Bill Richardson.
He is a graduate of George Washington University and Georgetown Law. He and his wife, Erin, have a son.
FERC on Tuesday approved CAISO’s request to extend temporary market measures instituted last year in response to natural gas pipeline restrictions stemming from the 2015 closure of the Aliso Canyon gas storage facility.
But the commission rejected the ISO’s proposal to make other gas-related measures permanent throughout the ISO and the Western Energy Imbalance Market (EIM), in addition to the Southern California region affected by the gas constraints (ER17-2568).
Aliso Canyon | California Governor’s Office of Emergency Services
Aliso Canyon was cleared to resume normal operations in July, but is still operating at reduced capacity. CAISO sought to implement the permanent Tariff provisions to prepare for potential operational issues in other areas it oversees. (See Plan Would Apply Aliso Canyon Measures Across CAISO, EIM.)
In its ruling Tuesday, FERC accepted the ISO’s bid to extend a measure allowing Southern California generators to reflect gas cost expectations in day-ahead bids by using an approximation of next-day gas prices, which are published after the ISO’s day-ahead market runs. ISO rules typically require generators to incorporate the previous day’s gas prices into energy bids.
The commission also approved continued use of a gas adder and an after-the-fact cost recovery mechanism for generators connected to the Southern California Gas system to tie cost recovery and penalties to same-day gas prices rather than day-ahead gas indices.
“As CAISO reports, Aliso Canyon will continue to experience limited operability for the foreseeable future, which presents the risk of curtailments to gas-fired generators and, potentially, the interruption of service to load,” the commission said. “We find that continuation of the interim measures for an additional year should improve scheduling coordinators’ ability to manage their gas procurement and enhance their ability to recover gas procurement costs, while also providing CAISO with flexible tools to maintain reliability and avoid adverse market outcomes related to the limited operability of Aliso Canyon.”
The temporary provisions will remain in effect until Nov. 30, 2018.
Gas Burn Cap
FERC rejected CAISO’s proposals to make other interim measures permanent and to extend their application to the EIM. Chief among them was the ISO’s proposal to limit the amount of gas that generators can burn during periods of restricted gas supply.
Within its own balancing authority area, the provision would have allowed CAISO to develop the constraint on its own motion, then require it to publish details about the constraint and provide market participants an opportunity to comment.
In the EIM, the ISO would have enforced constraints “at the request of and in coordination” with the relevant EIM balancing authority. The EIM currently includes Arizona Public Service, NV Energy, PacifiCorp, Portland General Electric and Puget Sound Energy.
In rejecting the proposal, the commission found that CAISO failed to demonstrate how it would a prevent an EIM entity from having “too much discretion” over the development and enforcement of a constraint. “This raises the concern that an EIM entity would be able to develop a constraint to help it manage gas supply issues of its affiliated resources while other market participants would have to rely on appropriate bidding and contracting,” the commission wrote.
The commission also said that CAISO had not explained how it would monitor and enforce maximum burn constraints in the EIM, nor did it define the role of the relevant natural gas company within the Tariff.
Still, FERC left the door open for CAISO to develop a gas burn cap for its own BAA, saying such a measure could be a “useful tool” to help manage gas limitations “more efficiently than relying solely on manual dispatch.”
The commission also rejected CAISO’s proposals to make permanent two other interim measures: One allows the ISO to suspend virtual bidding in the face of gas constraints; the other permits it to release two-day-ahead advisory schedules to certain scheduling coordinators.
“These solutions may be appropriate for an interim Tariff provision to address an identified problem, such as Aliso Canyon’s limited availability, but CAISO has not provided justification that they are appropriate or adequate in their current form as permanent features of CAISO’s market,” the commission said.
FERC acknowledged that its denial of the permanent Tariff changes would leave CAISO without some existing tools designed to address limited operations at Aliso Canyon.
“Our rejection of these permanent Tariff provisions does not foreclose CAISO from proposing an extension of these interim Aliso Canyon-specific Tariff provisions for an additional year, as CAISO did with the three Tariff provisions that we accept on a temporary basis in this order,” the commission said.
WASHINGTON — The Market Monitors for CAISO and PJM told a House subcommittee Wednesday that their respective financial transmission rights markets are significantly flawed and need fixing, although they stopped short of asking for congressional action.
Appearing before the House Energy Subcommittee, Eric Hildebrandt, director of CAISO’s Department of Market Monitoring, said electricity ratepayers in RTOs/ISOs nationwide are not receiving the full amount of congestion revenues as intended, losing more than $400 million a year instead.
After allocating an initial round of FTRs to load-serving entities that use the instruments as a hedge, RTOs auction off additional FTRs to third parties, typically sophisticated financial entities seeking to speculate on the potential to collect high rents from congested transmission segments.
“Unfortunately, revenues that ISOs collect from auctioned FTRs are consistently much lower than what the ISOs pay out to entities purchasing these FTRs,” Hildebrandt said. “This makes FTRs highly profitable for financial entities, but these profits directly reduce the congestion revenues that would otherwise be refunded back to transmission ratepayers.” He said that ratepayers only receive 52 cents in auction revenues for every dollar an RTO/ISO pays out to FTR holders, representing a nearly 100% profit for buyers.
In written testimony, PJM Independent Market Monitor Joe Bowring explained his RTO’s auction revenue rights construct before echoing Hildebrandt’s criticism.
“The current ARR/FTR design does not serve as an efficient way to ensure that load receives all the congestion revenues or has the ability to receive the auction revenues associated with all the potential congestion revenues,” Bowring said. “The goal of the ARR/FTR design should be to return 100% of the congestion revenues to the load. But the actual results fall well short of that goal.”
Opposing Hildebrandt at the hearing was TPC Energy CEO Noha Sidhom, appearing on behalf of the Power Trading Institute.
“The problem [in CAISO] is not with the FTR product; the problem is with the market design,” Sidhom said. “They’ve got significant modeling issues. … There’s something wrong with their pricing model. Also their outage scheduling is a real problem.”
Sidhom said that more than 50% of network outages are not identified in time to be modeled in the ISO’s FTR auctions. These problems result in inadequate revenues to ratepayers, but “you absolutely need the auction, because the auction is how you actually price the allocated rights.”
“It’s absolutely incorrect that the allocated FTRs are priced based on the auction,” Hildebrandt responded. “They’re allocated out, load-serving entities hold them and they get paid the congestion revenues.” Those who purchase FTRs through the auctions pay nearly half the price, and “the payout directly reduces the pot of congestion revenues that otherwise get fully refunded back to transmission ratepayers,” he said
He also disputed that the problem was unique to CAISO, saying it exists in every RTO/ISO in the U.S., although he admitted it is more severe in California. In his letter to the subcommittee, Bowring said that PJM ratepayers have missed out on more than $1.7 billion in congestion revenues over the last seven planning cycles.
The hearing was the latest in the subcommittee’s “Powering America” series, which has included discussions on reliability in the wake of a severe hurricane season, consumer advocates in energy markets and the Public Utility Regulatory Policies Act. Several congressmembers at the hearing admitted they were unfamiliar with FTRs and other virtual transactions, asking for basic explanations of their role in electricity markets.
The panelists also included Red Wolf Energy Trading CEO Wesley Allen, PJM General Counsel Vince Duane, former FERC General Counsel Max Minzer and Chris Moser, senior vice president of operations with NRG Energy.
FERC on Monday ordered settlement judge procedures for a dispute involving an American Electric Power subsidiary’s transmission rates (EL17-85).
In August, East Texas Electric Cooperative (ETEC) and Northeast Texas Electric Cooperative (NTEC) filed a joint complaint asking the commission to reduce Southwestern Electric Power Co.’s (SWEPCO) current base return on equity from 11.1% to 8.41% — a 269-basis-point reduction. In granting the co-ops’ request for a hearing on the issue, the commission set a refund effective date of Aug. 31, 2017.
East Texas Electric Cooperative member Cherokee County Electric Cooperative transmission lines | Cherokee County Electric Cooperative Association
ETEC and NTEC buy power from SWEPCO under a revised supply agreement among the three parties, while NTEC and SWEPCO also have a separate agreement. The 11.1% base ROE in the contracts originated in a formula rate settlement filed by SWEPCO in 2001 for the NTEC contract, and the utility carried over that rate when it filed the ETEC-NTEC agreement in 2009.
The co-ops now contend that capital costs for electric utilities have declined significantly since the ROE was set in the initial agreement. As a result, their ratepayers are overcompensating SWEPCO by $2.43 million annually.
Linemen for Sam Houston Electric Cooperative, a member of the Northeast Texas Electric Cooperative, work on a line | Sam Houston Electric Cooperative
ETEC and NTEC filed testimony from independent consultant J. Bertram Solomon, who argued the 11.1% ROE rested on the commission’s previous one-stage discounted cash flow (DCF) methodology and outdated assumptions about utility debt costs. Updated financial data and the two-step DCF method adopted by FERC in 2015 produced a zone of reasonableness of 6.42 to 10.62% and a median of 8.41%, Solomon’s analysis showed.
SWEPCO asked the commission to dismiss the co-ops’ complaint, saying the 8.41% ROE falls 216 and 191 basis points below the ROEs the commission approved in previous cases involving ISO-NE and MISO, respectively. The utility requested FERC delay any proposed refund effective date by five months, if it set the complaint for hearing.
The commission said it found the co-ops’ DCF analysis to be “adequate” in establishing a sufficient case that SWEPCO’s cost of equity “may have declined significantly below the level of its existing 11.1% base ROE.” FERC said it was unpersuaded by SWEPCO’s arguments against the zone of reasonableness, and it rejected the utility’s request to delay refunds.
“We find no merit in [SWEPCO’s] assertions that the commission should delay any appropriate relief to [its] customers,” FERC said, “and we expressly decline to do.”
The commission said that barring a settlement agreement, it expects to issue a decision by Sept. 30, 2019.
ETEC separately filed complaints against SWEPCO and three other AEP subsidiaries in June, arguing the companies’ base ROE in SPP’s AEP West pricing zone should be reduced from 10.7% to 8.36%. FERC earlier this month established hearing and settlement judge procedures in that case (EL17-76). (See AEP Base ROE Complaints Ordered to Settlement.)
FERC on Tuesday approved NYISO’s request for a 30-day extension for submitting additional reliability-must-run tariff revisions. The ISO must now file the changes no later than Jan. 16, 2018 (ER16-120).
The ISO said the additional time would enable it to develop compliance revisions that fully address the directives and allow New York stakeholders an opportunity to review any changes and provide feedback. It also said the extension would help it avoid disputes with stakeholders and obtain input from its Independent Market Monitor.
The D.C. Circuit Court of Appeals on Tuesday denied Kansas regulators’ challenge to a 2014 FERC order approving SPP’s merger with the Integrated System (IS) (15-1447).
SPP & the Integrated System | SPP
In its petition for review, the Kansas Corporation Commission contended that FERC’s approval of the merger allowed SPP to integrate Basin Electric Power Cooperative and Heartland Consumers Power District into its transmission footprint under agreements that shielded the two new members from paying certain transmission facility costs (ER14-2850, ER14-2851).
The Kansas commission argued that FERC “wrongly accepted a rate structure that disadvantaged the SPP participants” and “unreasonably accepted” what it called faulty data in the RTO’s calculation of the merger’s benefits.
At issue was the allocation of costs for SPP legacy facilities in the agreement between the RTO and the Integrated System parties. The KCC said FERC’s approval would establish inequitable precedent that entities desiring to join an RTO can negotiate “sweetheart deals” in exchange for reducing administrative rates.
In an opinion authored by Senior Judge Stephen F. Williams, the court rejected the KCC’s request to review FERC’s decision, saying the court found no basis for a claim of undue discrimination.
“Kansas argues, in effect, that by accepting these provisions, SPP got taken for a ride,” Williams wrote, pointing to a KCC expert’s calculations that SPP would have received almost $360.5 million in revenue (net present value) over 10 years were the Integrated System parties required to pay for the use of its legacy facilities. The system comprises its own transmission zone within SPP’s footprint, which is divided into 18 different zones.
While a Brattle Group study of the merger estimated the RTO would reap $220 million in benefits over 10 years, the KCC said the foregone revenue meant the integration will actually cost existing SPP members almost $141 million during that period.
1. SPP said the addition of the Integrated System would produce net benefits of almost $220 million over 10 years. The Kansas Corporation Commission said the integration actually will cost existing SPP members $141 million. | Kansas Corporation Commission
The court noted FERC’s determination reflected “prior investment decisions and the fact that existing facilities were built principally to support load within the [pre-merger SPP] sub-region,” and said the commission’s approval of similar arrangements “has withstood judicial review in analogous circumstances.”
“FERC accurately described the agreement as reciprocal,” Williams wrote. “It would be difficult to label it otherwise, as the agreement and FERC’s approval assigned each side’s legacy costs to the power consumers in that side.” He said the arrangement’s reciprocity undermined the KCC’s contention that SPP left $475 million (nominal) lying on the table.
“Kansas never suggests any reason to believe that the IS parties would have agreed to share SPP members’ legacy costs without demanding that SPP members share the IS parties’ legacy costs,” Williams wrote.
The court also said the KCC overlooked other benefits to the merger, such as increased efficiency and reliability; improvement in SPP’s dispatch of power on its western edge; and a lower price of energy by virtue of reduced generation curtailment.
Williams said the Kansas regulators’ claim of lack of access to the Brattle study was “somewhat exaggerated.” The commission had access to a redacted, electronic version before the start of the FERC proceedings and other public data, he said, but it never pinpointed either a special reason to question the study “or some debilitating feature of the redaction.”
The KCC also asserted its expert’s testimony was “simply ignored” by FERC in disputing the proposed integration and SPP’s cost/benefit analysis.
“Not true,” Williams wrote. “As the … discussion demonstrates, the testimony was considered, but rejected on the merits.”
The court also found no fault in FERC’s decision not to order a hearing on the issue, noting the Kansas regulator was unable to point to any vulnerability in SPP’s expert witness testimony that could have been “better resolved” with cross-examination rather than the analysis of written testimony.
“We therefore find no abuse of FERC’s discretion,” Williams wrote.
A KCC spokesperson said the commission is still reviewing its options.
FERC approved cost allocations for projects involved with northern New Jersey’s Bergen-Linden Corridor (BLC) last week (ER17-725) but left room for revisions based on a challenge to the original allocation (EL15-67).
In last week’s order, FERC denied requests for clarification and rehearing and accepted PJM’s Tariff revisions that allocate costs for the BLC projects to Neptune Regional Transmission System, Hudson Transmission Partners and Linden VFT.
FERC’s offices in Washington, D.C.
Linden and the New York Power Authority had requested clarification on PJM’s allocations. NYPA noted that Hudson’s responsibilities for the projects increased by $10.17 million after the company previously carried no responsibility for the upgrades. PJM failed to explain how modeled flows on the system could have changed so significantly since the RTO last performed its analysis, the agency contended. Hudson owns the merchant transmission facility NYPA uses for energy exports into New York City.
Linden argued that the solution-based distribution factor (DFAX) method bases its allocation on power flow, making it “particularly ill-suited” for non-flow-based projects, like the BLC.
FERC dismissed these complaints, explaining that they “challenge the cost allocation method in PJM’s Tariff rather than whether PJM properly applied its Tariff,” but it conditioned the approval on the outcome of Linden’s separate challenge to the allocation method itself.
“We find that PJM has correctly applied its Tariff, and the question of whether the Tariff provision regarding cost allocation is just and reasonable is pending before the commission in other proceedings,” the order said.
FERC Commissioner Cheryl LaFleur concurred with the order but wrote separately to note her dissent on the denial of Linden’s original challenge to the allocation methodology. Several organizations, including NYPA and Linden, requested rehearing of the issue, which FERC granted in June 2016.
New York is fine-tuning plans for meeting its 2030 renewable energy target and closing the books on the energy efficiency programs that it has used since 2008.
The New York Public Service Commission earlier this month approved orders implementing the second phase of the state’s Clean Energy Standard (CES) and approving the conclusion of its Energy Efficiency Portfolio Standard (EEPS).
| NY DPS Webcast
The CES adopted last year by the PSC mandates that 50% of the electricity used in New York be generated by renewable energy sources by 2030. In a Nov. 16 order, the PSC largely approved its staff’s recommendations for implementing Phase 2 of the CES, which will add quarterly renewable energy credit (REC) auctions (Case 15-E-0302).
The order also continues limits on the sale or transfer of Tier 1 RECs and institutes a “divergence test” to identify and correct REC supply/demand imbalances.
The New York State Energy Research and Development Authority will continue monitoring generators’ carbon emissions, managing REC procurement and setting Renewable Energy Standard (RES) targets for load-serving entities three years in advance.
Rhodes | NY DPS Webcast
PSC Chair John Rhodes said the new order “sets out the procedures and methods and fund management rules for NYSERDA to implement the next phase of the Clean Energy Standard, and including, importantly in my view, providing rolling future visibility for the Renewable Energy Standard targets for 2018 through 2021.”
Burman | NY DPS Webcast
Commissioner Diane Burman abstained, saying the PSC’s instructions were “not detailed enough.”
The order “still is leaving holes for decision-making that I’d like to see a lot more finality in, including the state energy plan and other things we need to address more holistically,” she said.
Under the new rules, NYSERDA will offer for sale all the Tier 1 RECs in its account quarterly, with unsold RECs offered in the next auction. NYSERDA had two auctions in 2017, one each at the end of the first and third quarters.
The quarterly sales will allow LSEs “greater awareness of the actual load served during the preceding quarter, which may encourage LSEs to purchase NYSERDA’s RECs when offered, thereby improving NYSERDA’s cash flow and reducing NYSERDA’s working capital requirements,” the commission said.
The commission rejected a request by the state’s utilities to allow LSEs to trade NYSERDA-procured Tier 1 RECS for the 2018 compliance year, continuing the existing ban. “A near-term change in REC sales and trading under the Renewable Energy Standard program would be out of alignment with the [Value of Distributed Energy Resource Proceeding, Case 15-E-0751] order and the expected evolution of REC trading rules in future years,” the commission said. “The implementation of the quarterly REC sale process will limit the potential exposure of an LSE over- or under-procuring RECs from NYSERDA, thus eliminating the need of trading NYSERDA-purchased RECs among LSEs.”
The commission also rejected proposals by environmental groups that the 2018-2021 targets be evenly distributed to allow developers to take advantage of expiring federal tax credits. Instead, the commission continued the state’s back-loaded approach, saying it “is based on the expected three-year development and construction cycle between the receipt of a NYSERDA award for Tier 1 RECs and a facility’s ability to start producing RECs upon commercial operation. In other words, the targets reflect realistic expectations regarding availability of Tier 1 RECs as the RES program ramps up.”
The PSC disagreed with the environmental groups’ criticism that the staff proposal lacked LSE targets through 2030. “Providing a mandated trajectory out through 2030 at this time would undoubtedly require adjustments in the later years to account for changes in statewide electric load, and other factors. … Therefore, the trajectory through 2021 for the revised LSE targets provided in the Phase 2 proposal is deemed sufficient to provide enough certainty for planning purposes for LSEs, renewable developers and other market participants.”
As part of its annual compliance reporting, NYSERDA will publish its methodology for calculating the statewide fuel mix to provide “transparency in accounting for the historic renewable baseline, the mandated targets, the voluntary market and other activities for measuring progress towards the 50-by-30 goal,” the commission said.
Palmero | NY DPS Webcast
NYSERDA will report on the program’s finances, including REC sales, alternative compliance payments, program expenses and surpluses or shortfalls, annually. If any cumulative surplus is more than 25% of the contractual Tier 1 REC payment obligation to generators for the current year, NYSERDA must propose a use for the excess portion that is in the ratepayers’ interest.
“We don’t expect there to be a lot of [alternative compliance payments], at least in the near term, because we’re trying to match the amount of RECs that will be available to the LSE obligation, but if there is a fund sitting there, NYSERDA will propose what they will do with the excess,” said Christina Palmero, deputy director of the state Department of Public Service’s Office of Clean Energy.
NYSERDA also was directed to develop criteria for combining aggregated and co-located facilities into a single Tier 1 bid for 2019. “Allowing aggregated and co-located facilities to bid as single facility for Tier 1 solicitations appears to be a prudent addition to the rules,” the commission said.
Concluding the Energy Efficiency Portfolio Standard
In a separate order, the PSC also voted to conclude the EEPS program and award 11 investor-owned utilities $56.5 million in shareholder incentives for meeting the electric savings targets and $12.4 million for meeting gas targets (Case 07-M-0548).
| NY DPSSayre | NY DPS Webcast
“EEPS was a good program and a successful program and we’ve learned from it,” Commissioner Gregg Sayre said. “I believe our replacement programs are better.” The commission’s Reforming the Energy Vision order of 2016 requires each utility to submit an annual Distributed System Implementation Plan and Energy Efficiency Transition Implementation Plan showing how they propose to meet the energy efficiency budgets and targets set by the PSC.
The program paid most utilities $38.85/MWh for reduced consumption. Consolidated Edison was paid $100,000/MW, capped at $5 million (50 MW) annually. All but Orange and Rockland Utilities (98%) exceeded their electric targets for the program.
Burman dissented, saying the commission had to learn from EEPS “the need to be more prudent and measured in making our demands, the need to be more realistic and thoughtful ahead of time about how quickly goals can be accomplished, and the need to truly understand what the financial implications may be to run the programs, and to prepare in case programs are more in demand than anticipated.” [Editor’s Note: An earlier version of this article failed to note that Burman had voted no and improperly prefaced her quote by saying “the commission had learned” from EEPS.]
The order directs utilities to file an EEPS financial reconciliation report no later than June 30, 2018, documenting program expenditures, unspent funds and accrued interest.
RG&E, NYSEG Face Penalties over Wind Storm Response
The commission also completed its investigation into the March 8 wind storm that left 123,000 Rochester Gas and Electric customers and 48,000 New York State Electric and Gas customers without power, finding the companies are liable for millions in penalties for violating their emergency response plans (Case 17-E-0594).
wind storm damage | Avangrid
The commission said both companies failed to fully secure downed wires reported by municipal officials within the required 36-hour period; to keep the public informed about restoration times; and to coordinate communications with customers on life-support equipment.
In addition, the commission said RG&E: began its damage assessment too late; failed to create a list of critical facilities such as fire and police stations to be prioritized in restoration efforts; did not update its automated voice messaging services to reflect storm conditions; and did not staff its call center adequately.
The commission directed the companies to respond within 30 days to show why penalties should not be initiated and show how they will improve their response.
The commission said National Grid was not subject to penalties because it restored more than 90% of its 113,000 outages within 36 hours.
Other Rulings
The PSC also approved:
ORU’s plan to spend $98.5 million to install smart meters for all its electric and gas customers. The new meters are expected to produce a net benefit of nearly $16 million. The utility will replace approximately 230,000 electric and 135,000 gas meters (Case 17-M-0178).
NYSEG’s and RG&E’s plans to offer light-emitting diodes (LED) street lighting to municipal customers. Replacing all of the utilities’ combined 93,000 old-style street lights could save municipalities as much as $5.8 million a year based on reduced costs of $63 per light. Street lights may account for up to 40% of total electricity use for a local government, but prior rules required municipalities to take ownership of the lights to switch to LED. The order allows municipalities to switch to the cheaper LEDs while NYSEG and RG&E retain the responsibility for maintaining them (Cases 16-E-0710, 16-E-0711).
