NERC: ERCOT, CAISO Face Summer Reliability Concerns
By Tom Kleckner
NERC said Wednesday that its annual summer reliability assessment indicates ERCOT and CAISO will face operational challenges and potential reliability concerns this summer, thanks to the two ISOs’ respective loss of baseload generation and lack of fuel assurance.
According to the agency’s summer assessment, ERCOT faces a generation shortfall “due in part” to the retirement of about 4.5 GW in coal-fired generation last fall and construction delays of about 2.1 GW in new resources. California is facing a limit on natural gas output due to Aliso Canyon storage facility constraints, NERC said.
“It’s very important to focus on the operational aspect,” said Thomas Coleman, NERC’s director of reliability assessments, during a conference call with reporters Wednesday. “We can’t do much at this point [about resource adequacy]. We want to draw attention to how we are prepared … from an operational standpoint.”
FERC earlier this month said it would be closely monitoring ERCOT and Southern California for reliability issues this summer. Both regions lie in a portion of the Western United .States. expected to be warmer than usual. (See FERC Keeps Eye on ERCOT, CAISO as Hot Summer Approaches.)
Coleman said the majority of NERC’s assessment areas “maintain sufficient resources” to meet their reference planning reserve margins this summer. The exception is ERCOT, which saw its reserve margins drop from 18% last year to a projected 10.9% this year with the coal plant retirements and delay in new resources. Given the ISO’s 13.75% planning reserve margin, ERCOT faces a capacity shortfall of 2 GW, NERC said.
No Cause for Alarm?
A Texas Reliability Entity assessment expects the ISO could be required to deploy ancillary services and contracted load control programs during peak demand periods. NERC’s study cautions that “typical generator outages expected under normal conditions” could limit ERCOT’s ability to maintain operating reserves.
Coleman said NERC took it one step further and ran an operational risk analysis that looked at typical maintenance or forced outages, extreme forced outages, extreme weather and a low-wind scenario.
“Any one of those events would drop [ERCOT] below its operating reserve margin” (of 2.3 GW) and lead to energy emergency alerts,” Coleman said, noting that operational challenges occur during times of peak demand, low wind output, and generator outages.
“When we don’t have the wind available, those are the types of scenarios we want to pay attention to,” he said.
NERC’s study finds the risk of load shedding caused by insufficient reserves in ERCOT’s footprint would increase under extreme summer conditions, such as above-normal temperatures and higher-than-expected generation outages.
However, the Texas grid operator has assured stakeholders there is no reason for alarm, and said it plans to address the projected generation shortfall by seeking voluntary load reductions from utilities, if needed. (See ERCOT Gains Additional Capacity to Meet Summer Demand.)
Asked about a repeat of severe weather, as ERCOT experienced last August with Hurricane Harvey, Coleman said NERC was “encouraged by the level of resilience in the system last year.”
“We’ve gotten better about handling those types of events,” he said, noting most outages occur at the distribution level and don’t affect the bulk electric system. “During hurricanes, when we have distribution outages, there’s less load, so that doesn’t necessarily pose challenges.”
California Challenges
Coleman said NERC feels “very comfortable” about CAISO’s reserve margins, but also noted the Aliso Canyon operational constraint continues to affect the availability of natural gas in Southern California, increasing ramping requirements. Below-normal hydro generation is also projected to exacerbate the potential reliability concern, according to the NERC assessment.
“If we don’t have [the] ability to get the fuel there, we could have operational challenges,” Coleman said.
NERC said the need for fast-ramping gas generation and other flexible resources across California also presents a reliability challenge for the bulk power system this summer because of the state’s high penetration of renewables. CAISO in March set an all-time record when 49.95% of demand was served by transmission-connected solar.
The California grid declared its first stage 1 emergency in 10 years last May. In October, it activated demand response measures, but did not require any load shed.
NERC’s study saysid MISO has a summer reserve margin of 19.1%, above its target reserve margin of 17.1%, due to increased forced outage rates. It is expected to increasingly rely increasingly on emergency operating procedures to access resources needed to meet load and operating reserves.
MISO’s actions are anticipated to provide sufficient energy or load relief to cover the normal forecasted system conditions, the agency said. Coleman said the ISO acknowledges a 79% chance it will experience at least one level 1 emergency this summer.
NERC conducts its reliability assessments to “provide a high-level view of resource adequacy and to identify issues that have the potential to impact bulk power system planning, development and system analysis over the summer months.” The summer assessment covers June through September.
FERC last week granted Brookfield Energy Marketing a one-time NYISO Tariff waiver allowing the company to avoid paying a penalty for a clerical error related to its external capacity resource interconnection service (CRIS) rights offer obligation (ER18-1177).
External CRIS rights provide their holder with a long-term ability to import capacity into the New York Control Area but require the holder to commit to supplying a specified number of megawatts of external installed capacity (ICAP) to the NYCA for a period of at least five years through one of NYISO’s auctions.
Brookfield’s 296-MW Holtwood Hydropower Station in Pennsylvania.
Any entity failing to offer capacity in accordance with Tariff requirements incurs a financial penalty equal to 1.5 times the ICAP Spot Market Auction clearing price, multiplied by the number of megawatts committed.
Brookfield said that an employee submitting the company’s offer for the ISO’s January 2017 ICAP auction inadvertently omitted a detail that would have automatically associated the offer with the company’s CRIS rights and satisfied the remainder of its offer obligation. The company contended that it discovered the error too late to be remedied by other means.
Brookfield claimed it acted in good faith and that the waiver would be limited in scope. The ISO did not oppose Brookfield’s waiver request, stating the problem did not affect market outcomes or impair other market participants’ capacity import offers.
The commission agreed but reminded “Brookfield, and other entities holding external CRIS rights, of the importance of fulfilling NYISO’s Tariff requirements in a careful and timely manner.”
FERC last week ordered Entergy and the Louisiana Public Service Commission to provide it with more information to determine whether its past decision not to order refunds in the ongoing dispute over the company’s equalization of production costs remains appropriate.
FERC’s voluntary remand of its decision revives the possibility that Entergy may be required to issue refunds over its multistate system agreement (EL01-88-019).
Galvez Building housing the Louisiana Public Service Commission | LA.gov
“Having re-examined the matter, the commission seeks further submissions by the parties on whether refunds are appropriate given the circumstances presented in this case,” FERC said in a May 22 order.
The commission set the matter to a paper hearing and ordered Entergy and the Louisiana PSC to submit initial briefs and evidence on refunds within 30 days.
The issue dates to 2001, when the PSC and the New Orleans City Council filed a complaint with FERC, arguing that Entergy’s allocation of production costs among its operating companies in its 1982 multistate system agreement had become unfair.
In the past, the operations of Entergy’s subsidiaries were more integrated, with different transmission and generation facilities functioning as a single electric system. Entergy’s system agreement consisted of several service schedules that allocated costs among the operating companies according to a responsibility ratio.
In a 2005 order, FERC found that Entergy’s allocation of production costs across its subsidiaries was no longer in rough equalization. And while the commission required Entergy to employ a “bandwidth” remedy that ensured no operating company had production costs more than 11% above or below the system average, it declined to order refunds for the years prior to the bandwidth calculations.
The commission originally found that the Federal Power Act prohibits refunds among electric companies of a registered holding company “to the extent that one or more of the electric companies making refunds cannot surcharge its customers or otherwise obtain retroactive cost recovery.” FERC also said that there was no evidence in the record that the operating companies making refunds could receive a retroactive recovery of their costs and rejected the PSC’s request for a rehearing over refunds.
The D.C. Circuit Court of Appeals in 2008 remanded the case back to FERC, questioning whether the commission had adequately supported its decision not to order refunds. However, by 2014, FERC had again declined to order refunds in another rehearing requested by the PSC.
FERC now says the PSC’s past arguments are influencing its decision to revisit the possibility of refunds.
In March, the D.C. Circuit decided that no refunds were necessary in a closely related case involving Entergy’s multistate system agreement. In that case, FERC also determined Entergy’s practices were unfair because the company’s formula for determining peak load responsibility included interruptible load in addition to firm load. (See No Refunds in 20-Year-Old Entergy Rate Complaint.)
Public Service Electric and Gas appears to be out of targets to help it pay for its $1.2 billion Bergen-Linden Corridor (BLC) project. FERC last week denied a complaint from the New Jersey Board of Public Utilities to reallocate the project’s costs, leaving PSE&G to pay for most of the project meant to support the “wheeling” arrangement Consolidated Edison terminated in April 2017 (EL18-54).
For decades, Con Ed paid to wheel 1,000 MW of power through PSE&G’s facilities in northern New Jersey for delivery to New York City. But Con Ed terminated the deal after PJM attempted to allocate $720.4 million of the project’s costs to it through the RTO’s Regional Transmission Expansion Plan. Two merchant transmission facilities that connect northern New Jersey to New York City — Hudson Transmission Partners and Linden VFT — were allocated $103.2 million and $9.6 million, respectively, and PSE&G was assigned $88.4 million.
FERC initially approved reassigning $530.8 million of Con Ed’s allocation to Hudson and $122 million to Linden. But that was nixed after the merchants successfully petitioned FERC to amend their interconnection service agreements and reduce their responsibility. (See NJ Merchant Tx Operators Win Relief on Upgrade Costs.)
| PJM
The BPU filed its complaint just days after FERC allowed the ISA changes, arguing that PJM’s Tariff and its joint operating agreement with NYISO don’t properly allocate the costs of some RTEP projects to merchant transmission facilities and other transmission customers.
After the “wheel” was canceled, PJM and NYISO agreed to maintain a smaller 400-MW version, called the operational baseflow (OBF), until the separate systems were stabilized to operate without the flow. The BPU argued that the way the grids interact provides a benefit to NYISO for which PJM customers, specifically those in New Jersey, aren’t being compensated.
“NYISO continues to model flows over the lines previously used for the Con Edison wheeling arrangement for purposes of determining its resource adequacy requirement, while PJM models its system with little or no support from NYISO,” the BPU told FERC.
Therefore, NYISO doesn’t need to maintain as much capacity while New Jersey must procure more. PSE&G’s zone often clears separately from the rest of the RTO in PJM capacity auctions. In last week’s Base Residual Auction for the 2021/22 delivery year, for example, it cleared at $204/MW-day versus $140/MW-day for much of the RTO. (See Capacity Prices Jump in Most of PJM.)
The BPU complaint said that without the relief the regulators requested, the PSE&G locational deliverability area’s capacity costs will jump by as much as 78.6%, “or an increase of $275 million in a single year and reoccurring annually for the foreseeable future.”
Because the Bergen-Linden project was meant to address reliability issues created by the “wheel,” it’s only fair those beneficiaries should pay for them, the BPU said.
“Parties have sought to escape those costs by terminating or otherwise amending contracts,” the BPU told FERC.
NYISO responded that costs can’t be allocated in New York because the project is fully within PJM’s boundaries, and that it no longer relies on the facilities for reliability. PJM said that “it is the physical features of the transmission system in northern New Jersey that are driving the need for the BLC project.”
Con Ed, Linden, Hudson, the New York Power Authority and several other New York stakeholders argued against the complaint. PSE&G, the New Jersey Division of Rate Counsel, the Public Power Association of New Jersey, PJM’s Independent Market Monitor and other RTO stakeholders supported the complaint.
The commission agreed with opponents of the complaint that the BLC was planned solely through PJM’s RTEP, that NYISO never agreed to pay for any of it and that the PJM-NYISO JOA “does not preclude the sharing of these benefits without compensation, even if those benefits are not equal at a given point in time.”
It also said the merchant transmission facilities can have their service curtailed for reliability or economic reasons now, so they can’t effectively replicate the firm priority benefits they had before and therefore shouldn’t be held accountable for any upgrades that support that priority.
FERC declined to rule on whether those facilities should be eligible to sell capacity in NYISO, saying that was out of the scope of the complaint.
VALLEY FORGE, Pa. — PJM doesn’t plan to contest a FERC ruling that may have contributed to the increase in demand response clearing in last week’s Base Residual Auction, Senior Vice President of Operations and Markets Stu Bresler told Thursday’s Markets and Reliability Committee meeting.
On May 8, the commission rejected rule changes PJM developed to discourage market participants from selling capacity in the BRA and buying back their obligations at lower prices in Incremental Auctions, a practice that has led to concerns that arbitrageurs are offering capacity they have no intention of providing. The Independent Market Monitor says DR providers disproportionately replace BRA commitments in the IA. (See FERC Closes Book on PJM’s ‘Paper Capacity’ Concerns.)
“At this point, PJM does not intend to seek rehearing,” Bresler said, noting FERC’s “strongly worded” rejection of the filing to revise IA rules, which also terminated a related Section 206 proceeding.
PJM plans to allow the 30-day rehearing window to expire and then meet with FERC to discuss the RTO’s next steps, he said. FERC staff had told PJM that they wouldn’t entertain a prefiling meeting on the IA revisions because of the outstanding 206 proceeding on the issue. By letting both expire, Bresler said he believes FERC will be willing again to discuss the issue.
“We do intend to bring this back to stakeholders about how to move forward,” he said. “We think a discussion with FERC would be very valuable.”
FERC’s May 8 ruling may have played a role in why more DR cleared as annual resources in the BRA for delivery year 2021-22. DR offered into the auction increased almost 21% to 11,887 MW, nearly 94% of which cleared. Of the 11,126 MW of DR that cleared — up 3,305 MW from last year — 96% cleared as annual Capacity Performance and 452 MW cleared as summer-only resources that were aggregated with other products to meet CP’s requirement for year-round commitment. (See Capacity Prices Jump in Most of PJM.)
DR participants have complained that they can’t receive a capacity commitment because they struggle to meet CP’s year-round requirement and have requested seasonal products. But several MRC members speculated they might have been more emboldened to take the risk because FERC’s decision ensured at least one outlet remains. PJM’s IA revisions were meant to close a loophole that allows market participants to receive higher prices for supply obligations in the BRA and pay less in subsequent IAs to offload those commitments.
VOM Remanded
Stakeholders at last week’s MRC meeting were spared an expected showdown on variable operations and maintenance (VOM) cost accounting after Rockland Electric’s Brian Wilkie indicated an interest in deferring the vote. The idea ended up being motioned and seconded by others, but stakeholders were happy to endorse it and return the issue to the Market Implementation Committee.
Monitor Joe Bowring was prepared to make a presentation in defense of his proposal on the issue, but stakeholders preferred to address it at the lower committee, where the proposal earlier failed to receive an endorsement to be considered at the MRC. (See “VOM Proposal,” PJM Market Implementation Committee Briefs: April 4, 2018.)
Offer Cap Revisions Stalled Again
Two sets of changes to Manual 11: Energy & Ancillary Services Market Operations were approved by acclamation, but a third set dealing with offer caps was sent back to the MIC for additional review.
The approved changes focused on bidding and unit-parameter submissions. The first set includes conforming changes regarding bidding locations for virtual transactions. The second set expands the window for when generators can make intraday offers. (See “Intraday Offers,” PJM Market Implementation Committee Briefs: May 2, 2018.)
The revisions returned to the MIC were developed to ensure consistency between the manual and Operating Agreement regarding price-based offers over $1,000/MWh. The change was necessitated by FERC Order 831, which required RTOs and ISOs to raise their hard caps for verified cost-based incremental energy offers to $2,000/MWh. (See “Offer Cap Resolution,” PJM Market Implementation Committee Briefs: May 2, 2018.)
PJM’s Susan Kenney said the discrepancies occurred because the Order 831 compliance filings failed to appropriately update the Tariff and OA, so the manual’s $1,000/MWh cap conflicts with the OA, which permits price-based offers to exceed $1,000/MWh if they are less than a verified cost-based offer. As an immediate fix, PJM is proposing capping all offers at $1,000/MWh by default and allowing higher offers to submit a request for verification. The system will be automated once the capability has been developed.
For price-based offers, PJM is “strongly” suggesting operators allow a “switch to cost” option that excludes price schedules from dispatch. Otherwise, they can request the ability to submit price-based offers in line with verified cost-based offers, but they are then on the hook to ensure price-based offers at each segment remain compliant with verified cost-based offer caps.
The Monitor argues the solution should be holistic to include a full implementation in PJM’s offer submission software and related manual changes. Until then, PJM should seek an exception from FERC to use the revised “switch to cost” method, which includes the $1,000/MWh cap, the Monitor said.
Last month, Manual 11 revisions to correct inconsistencies with PJM’s governing documents regarding offer caps failed to receive MRC endorsement and were sent back to the MIC as well.
Long-term FTRs
PJM and the Monitor presented members with separate proposals to revise the long-term financial transmission rights market.
The proposals are meant to correct current processes that allow participants in the long-term FTR market to obtain the rights to congestion on transmission paths before the owners of the underlying auction revenue rights. Both proposals would do away with the “year all” product in the market and only offer annual products for each of the next three years.
PJM’s proposal would model all ARRs that clear in the annual model as fixed injections and withdrawals in the long-term auction model. Any transmission outages that would impact the ARRs would be removed. PJM argues this would accurately represent any residual capability left on the system.
The Monitor’s proposal would set the residual capability for the auction at zero and require all prevailing-flow capability to be generated from counterflow FTRs. The Monitor’s Howard Haas argued this would eliminate the risk of any overallocation between the long-term auction and annual auctions and establishes counterparties in the market.
“We think it’s going a little too far,” PJM’s Tim Horger said of the Monitor’s proposal.
“We think PJM’s going in the right direction … but it does not go far enough,” Haas said in response.
Horger said he was interested in seeing what the “true capability” is in the long-term model.
Members will be asked to endorse one of the proposals at the June MRC.
Stakeholders Approve Changes to Manuals, Operations
Stakeholders endorsed by acclamation several manual revisions and other operational changes:
Manual 36: System Restoration. Revisions developed as part of the manual’s annual review; includes clarifications regarding synchro-check relays, blocking governors and black start generators.
Manual 3: Transmission Operations. Biannual review to update operating procedures. Revisions update remedial action schemes, sectionalizing schemes and definitions for the Cleveland and Eastern interfaces; designate voltage limits for Ohio Valley Electric Corp.’s impending integration; add language regarding reactive reserve check submittals; and clarify notes on load shed activity.
Manual 14A: New Services Request Process. Annual review. Revisions developed to introduce the Queue Point software for submitting data for feasibility and system impact studies.
Manual 7: Protection Standards. Revisions developed by the Relay Subcommittee to add clarity, update terms and add reliability requirements.
OA revisions allowing PJM to share member confidential information with the Eastern Interconnect Data Sharing Network (EIDSN) in addition to NERC and other reliability entities. EIDSN was created in 2014 to develop industry tools that NERC has decided it no longer wants to create and maintain.
Comments filed with FERC last week indicate most stakeholders oppose ISO-NE’s Tariff waiver request to keep the Mystic generating plant running despite Exelon’s plans to retire the facility (ER18-1509).
Commenters also questioned the RTO’s rationale that an out-of-market mechanism is needed to financially support the nearby Distrigas LNG terminal being acquired by the company.
Mystic Generating Station, on the Mystic River in Everett, Massachusetts. A wind turbine owned by the local water authority to power a pumping station is on the right.
Massachusetts Attorney General Maura Healey raised “significant questions regarding the legality of using the commission waiver process in the expansive way ISO-NE seeks to do here.”
The RTO is asking to do something it has never been allowed to do before, Healey said, namely to “retain a generation facility pursuant to the [Forward Capacity Market] process not for capacity needs but to ensure ‘fuel security,’ a term that is not defined in the Federal Power Act, and a concept for which there is no settled or universally accepted definition.”
Healey also opposed the request as “sweeping in its breadth” in seeking to waive for one generator almost all of the Tariff’s FCM retirement requirements and existing retirement deadlines, and take away its existing limits on Exelon’s ability to recover costs under a cost-of-service agreement.
New England local distribution companies supported the waiver request in order to maintain reliability in the region and took no position on the cost-of-service representations made by Mystic.
“The lack of sufficient natural gas infrastructure makes facilities that rely on LNG particularly valuable in the region,” the LDCs said. “There is no immediate, viable replacement should the [Distrigas] terminal shut down and efforts to replace the products and services provided from Distrigas would be lengthy and difficult.”
ISO-NE’s Reasoning
| ISO-NE
ISO-NE last month announced the plan to keep Mystic running after Exelon said in March that it planned to retire the 2,274-MW plant when its capacity obligations expire on May 31, 2022. (See ISO-NE Moves to Keep Exelon’s Mystic Running.) On May 1, the RTO filed a motion to waive its Tariff to retain resources to address fuel security risks — an option currently allowed only in response to local transmission security issues.
The RTO said the loss of Mystic 8 and 9’s 1,700 MW of combined cycle capacity that don’t rely on pipeline gas would lead to it depleting 10-minute operating reserves — a violation of NERC standards – “on numerous occasions” and shedding load during the winters of 2022/23 and 2023/24.
Shuttering Mystic also would mean the loss of the Distrigas LNG facility’s biggest customer, raising doubts about its financial viability, the RTO said.
Exelon’s proposed cost-of-service agreement for Mystic, filed May 16, seeks an annual fixed revenue requirement of almost $219 million for capacity commitment period 2022/23 and nearly $187 million for 2023/24 (ER18-1639).
ISO-NE asked the commission to approve the waivers by July 2 to meet market participants’ deadlines for committing to Forward Capacity Auction 13.
Exelon said it would continue operating Mystic 8 and 9 only if it receives a two-year reliability-must-run contract ensuring it can recover its full cost of service for 2022/23 and 2023/24.
While ISO-NE will not implement the full payments and penalties under its Pay-for-Performance program until 2025, even then the program “cannot be expected to resolve the region’s fuel security challenges by itself, particularly in light of the significant opposition in the region to investments in fuel supply infrastructure,” the RTO told FERC in its waiver petition.
ISO-NE could implement a market-based fuel security solution as early as 2020, if it is decoupled from the FCM, or as late as 2024 if it’s included in the capacity market, but it’s still unclear what form the solution will take and therefore difficult to predict when the market will mature enough to resolve the fuel security issues that require Mystic 8 & 9’s retention, the petition said.
Market Failure?
New England Power Pool said it took “no substantive position” on the RTO’s request and that its “keen interest is in ensuring that ISO-NE engages fully with its stakeholders before seeking any change to the New England Tariff or market rules.”
NEPOOL said it expected the RTO to honor its commitment that the full participant processes would be completed prior to any filing of a longer-term market-based approach to fuel security issues.
The Environmental Defense Fund said in its filing that “the need for cost of service is indicative of market failure. Cost of service for the purpose of ensuring fuel availability (i.e., maintaining Distrigas’ natural gas supply capability), compels the commission and New England stakeholders to assess whether the market elements relevant to fuel supply for electric generators are functioning effectively. It is clear they are not.”
Distrigas Terminal | ENGIE
EDF recognized the Mystic/Distrigas units play a critical reliability role in the region but asserted that the “out-of-market workaround runs counter to ISO-NE’s dual mission of ensuring reliability and the long-term sustainability of competitive markets.”
The Northeast Gas Association said that while the waiver is a short-term solution supporting market reliability, “a longer-term remedy still needs to be enacted.” It urged the commission to consider “the importance of maintaining regional LNG access” over the coming capacity commitment periods.
Price Suppression
The Electric Power Supply Association said the “premature and overbroad” request should be rejected without prejudice, allowing the RTO to submit another short-term proposal if it is unable to develop a market-oriented solution.
The RTO “is being too quick to give up on such a solution for the nearer term and, specifically, for the 2022-2023 and 2023-2024 commitment periods,” EPSA said. “Additionally, this near-term fix may have the adverse effect of hastily establishing a new reliability criteria to be used to underpin RMR-type arrangements going forward, in the absence of any formal process, stakeholder input or Tariff revision proceeding.”
While the two-year term of the proposed RMR or cost-of-service agreement “is both unprecedented and will severely suppress capacity prices over that longer term,” EPSA said it also risked, by artificially dampening capacity prices, creating “the very dynamics” that cause the fuel security concerns raised by the RTO.
The New England Power Generators Association said allowing the RTO to offer the Mystic units as $0/kW-month price takers in FCA 13 would suppress prices by $214 million to $652 million, displacing 1,050 to 1,285 MW of other resources, “with the potential for even greater price suppression and displacement in FCA 14.”
Instead, NEPGA said ISO-NE should conduct a Substitution Auction to reprice Mystic, the same way it plans to reprice state-sponsored renewable resources under the Competitive Auctions and Sponsored Policy Resources design approved by the commission. The trade group made the same arguments in a Section 206 complaint (EL18-154) also filed last week.
Why Hurry?
Calpine said it did not oppose the RTO’s request but questioned the need for action now, as the Mystic units have capacity supply obligations through May 31, 2022.
Nevertheless, Calpine said the waiver request “is a symptom of broader price formation issues that are preventing” the FCM from attracting sufficient investment in new and existing resources to maintain reliability.
Until these issues are resolved, Calpine said, it is likely that New England “will continue to experience premature retirement of resources critical to ensuring fuel security and that ISO-NE will increasingly be forced to rely on out-of-market procurement to maintain reliability.”
NRG Energy said waiver of the RTO’s capacity market rules “is not the appropriate approach to address the lack of fuel security in New England” and that the commission should order the RTO to develop a market response to procuring the necessary attributes.
Rejecting the waiver “does not mean blacking out New England,” NRG said. “Even should efforts to develop a market-based solution to the fuel security conundrum fail, the Federal Power Act includes a reliability ‘fail safe.’”
NRG concluded that the reliability product the RTO wants is not what the waiver aims to procure: “ISO New England argues that the waiver will allow it to procure additional winter energy production from non-pipeline gas-fired resources; yet the waiver is focused on allowing Mystic to continue selling a capacity product.”
Pipeline Constraints
The Industrial Energy Consumer Group said the RTO has warned of the danger of gas pipeline constraints since 2001. “Despite the obvious nature of this need, ISO-NE has repeatedly either brought forward market-based solutions that have failed to provide sufficient financial support to promote the construction of necessary pipeline facilities or offered interim out-of-market solutions, such as its Winter Reliability Program and the waivers requested in this proceeding,” the group said. “None of these have succeeded in causing pipeline capacity to be built.”
It asked FERC to order ISO-NE to file Tariff amendments allowing electric utilities to collect gas pipeline capacity costs.
“In addition, the commission should open a proceeding to facilitate new gas pipeline capacity resources into and within the New England region,” the group said. “Such a proceeding could also address, if necessary, the apparent refusal of New York to issue federally delegated permits for pipelines from Pennsylvania to New England.”
The Eastern New England Consumer-Owned Systems said the proposal could cause “permanent, structural damage” to ISO-NE’s capacity market.
“The waiver requested by ISO-NE is actually a stalking horse for injecting an untested, undefined and undebated construct of ‘fuel security’ into the pricing of capacity in New England,” the group said.
It said it believes Exelon is overstating Mystic’s financial problems and that the company’s planned acquisition of Distrigas from ENGIE raises competitive concerns because of the facility’s role in providing east-to-west gas when high heating demand constrains west-to-east capacity.
“The market power implications of consolidating that kind of critical-period capability with significant regional generation ownership deserve careful evaluation before the consolidation occurs,” the group said.
California will need between 229,000 and 279,000 electric vehicle chargers at locations other than single-family homes by 2025 to meet the state’s goals for adoption of zero-emission vehicles, the Energy Commission said in a new report.
The higher range of the estimate includes 133,000 workplace and public chargers, 9,000 to 25,000 fast chargers and 121,000 chargers at multifamily dwellings, the commission said. The numbers do not include chargers in single-family homes.
There is a projected need in California for up to 279,000 non-single family home chargers by 2025.
A March 2012 order by Gov. Jerry Brown directed the commission to support the goal of 1.5 million zero-emission vehicles on state roadways by 2025. Another January 2018 order by Brown called for the construction and installation of 250,000 zero-emission vehicle chargers, including 10,000 DC fast chargers, by 2025.
According to the new CEC study, the state’s goal is to allow drivers to maximize the number of electric miles they can drive, provide guidance on plug-in electric vehicle (PEV) and plug-in hybrid charging, and ensure the effectiveness of private and public sector investments. As of the end of last year, the state had about 14,000 public chargers — 1,500 of them DC fast chargers — serving 350,000 PEVs.
For the study, CEC staff worked with the National Renewable Energy Laboratory to develop a computer simulation tool known as the Electric Vehicle Infrastructure Projection Tool (EVI-Pro). The commission plans to add an EVI-Pro portal to its website to allow users to view charging station quantities, load shapes, infrastructure cost estimates and other information.
At a CEC workshop on Tuesday, analysts discussed three central questions around charging infrastructure: how many chargers to deploy, what kind of chargers and where to locate them. A big part of determining where to place chargers is understanding the behavior of vehicle operators and studying patterns such as worker commutes and rural versus urban settings.
“What we’re really talking about is trying to reduce range anxiety as a barrier to increased PEV sales,” NREL’s Eric Wood, one of the study’s authors, said at the workshop.
EVI-Pro focuses on behaviors of mainstream drivers, such as origins, destinations and schedules, as opposed to those of early EV adopters. Mainstream drivers are more likely to favor convenience and less likely to alter driving habits, for example. The modeling also studied how different charging locations such as home or work might be chosen based on the price of electricity, and how users charging for free at work might block other chargers and drive up costs of workplace charging.
The study used four major inputs: vehicle attributes, charger attributes, county-level household travel data and composition of the vehicle fleet. It calculated several charger-per-1,000-PEVs ratios under differing technology and market scenarios.
The transportation sector is the largest polluter in California, responsible for 80% of nitrogen oxide emissions and 90% of diesel particulates. Including indirect emissions from fuel refining and production, transportation accounted for “nearly half” of the state’s greenhouse gas emissions as of 2015, the report said.
The study showed that weekday charging peaks occur when vehicles arrive at work in mornings and when they arrive home in evenings. By 2025, workplace chargers on weekdays will draw more than 200 MW at 9 a.m. and residential chargers nearly 900 MW at 8 p.m. By 2025, aggregate demand from residential, workplace and fast-chargers will push up demand by 500 MW from 4 to 7 p.m., with a maximum demand of nearly 1,000 MW before 8 p.m.
The commission said that an important conclusion of the study is assuring drivers that charging infrastructure will be visible, accessible and reliably maintained, with real-time networking technologies being a valuable tool. Networked technologies will enable shared usage of chargers and reduce the size of the network needed to support the growing electric fleet.
CAISO’s first-quarter revenues were $1.2 million more than it had budgeted, primarily because of entrance fees it collected for the Western Energy Imbalance Market, the ISO reported last week.
About $1.6 million in EIM entrance fees were partially offset by grid management charge (GMC) revenues that were $400,000 less than budgeted. CAISO did not specify from whom it had collected the EIM fees, but Idaho Power and Canadian power marketer Powerex both began transacting in the market last month. (See Idaho Power, Powerex Begin Trading in Western EIM.)
CAISO’s total market settlement collections in 2017 were about $4 billion.
The ISO’s operating costs, capital expenditures, debt service and an operating reserve are recovered through the GMC. Most charges other than the GMC collected by the ISO are distributed to the appropriate market participants.
CAISO “monitors changes in GMC revenues and will adjust rates, if necessary, to align actual GMC revenues closer to budget, as required by the Tariff,” the ISO said in its first-quarter report.
Total market settlement transactions collected by the ISO were about $4 billion last year, including about $3.8 billion in market settlements and $200 million collected through the GMC, according to the ISO’s continuing disclosure report posted May 22. This compared with $3.4 billion in settlements and GMCs collected in 2016.
| CAISO
CAISO reported audited operating income of $26 million for the year, compared with $14 million in 2016. Operating expenses were at $195 million, “other expenses” were $5 million and operating revenues were $221 million.
The ISO in February had reported unaudited operating income of $47.4 million for 2017. (See CAISO Sees 2017 Revenue Boost.) The new operating income figure of $26 million includes depreciation and amortization of about $29 million.
Each year, CAISO establishes a revenue requirement that is allocated to the three GMC service categories: market services, system operations and congestion revenue rights services. Other financial collections come from EIM participants, generator interconnection studies and for operation of the California-Oregon Intertie.
The two largest of the 160 participants in the market, Pacific Gas and Electric and Southern California Edison, paid a little more than half of GMC revenue in 2017. The 10 largest participants were responsible for about 75% of the charge and the top 25 participants paid 89%. These levels have remained about the same since 2015.
Operating expenses last year included $118 million in salaries and benefits, $20 million in communications and technology costs, $18 million legal and consulting and $12 million in leases, facilities and administrative costs.
The ISO increased its number of full-time employees to 599 in 2017 from 584 in 2016.
CAPE NEDDICK, Maine — New England state regulators agreed last week that their region faces a growing winter reliability challenge but expressed skepticism over ISO-NE’s proposed solutions.
Speaking at the New England Conference of Public Utilities Commissioners’ (NECPUC) 71st annual symposium May 21, a panel of regulators pressed ISO-NE CEO Gordon van Welie on the need for an out-of-market contract for Exelon’s Mystic Generating Station, asking why it can’t be replaced through the capacity market and its Pay-for-Performance program.
The proposed Mystic contract represents the first of ISO-NE’s “three-track” plan for addressing its winter fuel reliability concerns. Last week, dozens of intervenors filed comments in response to the RTO’s request for a Tariff waiver needed to authorize the procurement, most of them in opposition (ER18-1509). (See related story, Mystic Waiver Request Spurs Strong Opposition.)
‘A Point at Which We Can’t Hold Things Together’
Van Welie said that Pay-for-Performance — which was premised on gas plants adding oil-fired capability — has been hampered by its stop-loss provisions and states’ resistance to oil-fired generation.
The CEO also said there isn’t enough oil storage or allowable air permits to rely on the fuel as the region’s backstop. During the Dec. 26-Jan. 8 cold snap, oil prices fell below gas, making oil-fired generation effectively baseload for two weeks, he said. The region burned about 2 million barrels of oil during that period — more than it used in all of 2016 and 2017 — drawing down supplies from 68% of tank capacity on Dec. 1 to 19% by Jan. 9. “The ISO had to step into the market to slow down the burn rate,” he noted.
Fuel delivery logistics also are a concern. Heating customers get priority for oil as well as gas. Oil deliveries can be delayed by storms and drivers’ working hour limits.
Van Welie said the RTO must firm up fuel deliveries and ensure that the market “uniformly” values all resources with such service, including its Millstone and Seabrook nuclear plants, which produce one-quarter of the region’s power during winter.
In addition to the region’s precarious fuel infrastructure, ISO-NE is concerned that state-sponsored renewable resources will reduce energy market revenues, causing increases in capacity market costs and plant retirements.
“Our concern is there’s a point at which we can’t hold things together,” van Welie told the regulators.
ISO-NE is seeking to delay Mystic’s retirement because its analysis indicated the loss of Units 8 & 9’s 1,700 MW of combined cycle capacity that don’t rely on pipeline gas would leave the RTO depleting its 10-minute operating reserves “on numerous occasions” — a violation of NERC reliability rules. The analysis also predicts load shedding during the winters of 2022/23 and 2023/24.
The RTO has asked FERC to waive its Tariff to retain resources to address fuel security risks — an option currently allowed only for local transmission security issues (Track 1). It hopes to file a Tariff change by the end of the year to make fuel security a reason resources can be retained (Track 2). In addition, the RTO is seeking a long-term plan to ensure sufficient firm energy for winter that would compensate needed resources through the market rather than reliability contracts (Track 3).
A Menu, not a To-Do List
Despite the hand he’s been dealt by the region’s resistance to oil generation, additional gas pipelines and electric transmission, van Welie was careful to couch his comments not as a “To Do” list but as a series of questions and menu choices for the states.
“We are an energy-constrained region. Do we want to maintain that constraint going forward, or do we want to do something about that? And specifically, can the states shape their resource procurements … in a way that they get at the winter constraint? Because I think in doing that the states can help us as well as maintaining or meeting their other policy goals.”
“The magnitude of that problem is in [question] but there is a problem,” said Bob Stein, vice chair of the New England Power Pool’s Reliability Committee, who joined regulators on the panel.
NEPOOL has “a range of positions [on the RTO’s plans], and they’re not fully formed,” said Stein, principal of Signal Hill Consulting Group. The range, he noted, is framed by the two types of NEPOOL members: “Those that are long and those that are short. And you can instantly tell what people are going to say by where they are.”
Maine Public Utilities Commission Chairman Mark Vannoy and other commissioners pressed the RTO for a “definition” of the problem, saying he is concerned that “New England is on a course to a very expensive future.”
“I’m not arguing that there is not a problem,” Vannoy said. “But we need to define what the problem is and then — if our intent is to use market mechanisms to solve that — we have to be precise … so that we can move to those market solutions.
“We have a very complex and dynamic market, and as price signals drive fuel procurement questions … [as fuels] substitute for other fuels … we need to understand how that dynamic market reacts before we move to the Markets Committee for a solution.”
Vannoy said New England helped create its dilemma by “separat[ing] itself from the rest of the country’s energy … potentially, to our economic peril.” He cited states using their EPA-delegated authority under the Clean Air Act to prevent access to Marcellus shale and other gas supplies.
As an example, Vannoy later cited the Atlantic Bridge pipeline project. In the face of local opposition, Massachusetts officials said in December that they would take up to a year to review the impact of a compressor station in Weymouth, Mass., that is part of the project.
Seeking an Honest Conversation
Angela O’Connor, chair of the Massachusetts Department of Public Utilities, called for an “honest” conversation.
“Whether you want to reduce greenhouse gases or simply reduce the rising outrageous cost of energy … burning 2 million barrels of oil in five days and killing baby seals to get to expensive Russian gas cannot and should not be part of any intelligent conversation about energy policy in this region,” she said. “It clearly does not meet any of our New England collective goals for the states. We need to have an intelligent and honest — emphasis on honest — conversation to develop the right solutions, and we need to do it all together.”
Is Pay-for-Performance Broken?
New Hampshire Public Utilities Commissioner Kathryn Bailey said her state is not convinced that the out-of-market contract with Mystic is the only possible solution to the region’s near-term concerns. She said the Operational Fuel-Security Analysis released by ISO-NE in January suffered from “problems with the assumptions and the lack of analysis on how likely scenarios are to play out.” (See Report: Fuel Security Key Risk for New England Grid.)
She said maintaining Mystic could create incentives for other non-gas generators to seek cost-of-service agreements.
“I have to ask: What happened to the market-based solution to fuel security? Just a few short years ago, ISO-NE reported to FERC that Pay-for-Performance was a long-term, market-based solution designed to address generator availability concerns and the region’s vulnerability to interruptions in gas supply. … What changed? Why does the ISO think it won’t work, even before the incentives take effect next month? Where’s the analysis that demonstrates it won’t work? When the ISO originally brought this plan to FERC, there was a lot of analysis.
“If Pay-for-Performance had worked as expected … and Mystic announced its retirement, prices in [Forward Capacity Auction] 13 would likely separate to provide incentive for new resources to take on the supply obligation in that zone. But apparently Pay-for-Performance can’t work.”
Bailey also noted “the irony that ISO-NE refused to allow a 200-MW renewable exemption backstop to integrate state public policies because of the impact it would have on the market. But now they want to waive the Tariff and allow a 1,700-MW out-of-market contract.”
In a period of low gas and renewable prices and flat load growth, Connecticut Public Utilities Regulatory Authority Chair Katie Dykes asked: “Why is everybody so unhappy?”
Her theory: “Legacy” deals, conflicting state policies, and overlapping jurisdictional authority between FERC, state legislators, state commissions, siting councils and the courts make it difficult for economic regulators to achieve the “fairness” they seek.
“We were one of a few states that got our legislature to give us fresh, brand new authority to procure not only gas pipelines but LNG storage. We got all of that authority. We opened a [request for proposals]. …
“We opened up the bids. We were ready to go. [Then] we looked at the costs and we realized that if we didn’t have all the states moving with us that Connecticut was going to pay 100% of the cost of these resources and only get 25% of the benefit because that’s our share of load. And so, the bids are still sitting in a desk drawer somewhere.
“The challenge of the multi-jurisdictional process is it is guaranteed to be unfair to some parties. … There’s a temptation to retreat within our own borders and pursue this sort of righteous unilateralism. … But that’s not really an acceptable tactic. If it comes to those outcomes, everyone in this room is going to be blamed for that occurring. No matter how hard you’ve been working on this issue, no matter how small your slice of the jurisdictional pie is, you’re all going to share responsibility for [reliability problems], which will hurt people and drive businesses out of New England,” she said, raising her arms like a cheerleader waving pom-poms. “So, what we really need to do is buck up, little soldiers. We can do this. This is New England.”
Rhode Island Public Utilities Commissioner Abigail Anthony stressed affordability, saying customers are best served by investments that “prioritize highly cost-effective measures that improve the reliability resiliency of both the distribution system and the [transmission] system.”
“So, the resources that we invest in need to do double or even triple duty to improve the energy system on multiple levels,” she said. She added, “Some of the best solutions to maintaining and improving reliability resiliency and affordability may lie outside the power system.”
She noted that 16,000 of her state’s residential electric accounts were terminated for nonpayment in 2016. “Rhode Island’s experience, consistent with national data, shows that the vast majority of customer outages are the result of disruptions of the distribution system or due to affordability,” she said.
Vermont Public Utility Commissioner Sarah Hofmann said she would like more data on resilience risks, the costs of reducing them and residential customers’ willingness to accept outages.
“The tolerance of consumers for the bad thing happening, such as rolling blackouts, that’s a conversation that … I don’t think we have as much as maybe we should, in terms of what can a residential customer tolerate as opposed to … a commercial customer.”
Enough LNG? Rewrite Capacity Market?
Van Welie said the two top sensitivities for its fuel study was the timing of retirements of its non-gas fleet and the size of LNG injections.
Over the last five winters, ISO-NE says the region has received an average LNG injection of 0.2 Bcfd, only occasionally spiking to the 1-Bcfd level assumed in the baseline case. In its recent analysis, Synapse Energy Economics said import terminals could handle 1.5 Bcfd.
ISO-NE CEO Gordon van Welie says New England’s growing price volatility since the winter of 2012-13 reflects the region’s increasingly constrained fuel infrastructure. | ISO-NE
“We’re talking about unprecedented levels of LNG imports into this region,” van Welie said. “And the big question is: Is the market signal strong enough to incent that behavior?”
Of New England’s 17 GW of combined cycle capacity, only 5 GW have dual-fuel capability. “There are three with large tanks. The biggest one is 10 days’ [capacity]. The next one down is five or six days. The next one down from that is three days. The tanks that are being built, if they do get built today, are [only] two days.”
“So, the issue is, Pay-for-Performance was calibrated to the economics around dual fueling, [which] may not be a good assumption in the long term.”
Van Welie also questioned Pay-for-Performance’s annual and monthly stop-loss limits for generators that fail to perform, which he said has many of them rolling the dice that they won’t need firm fuel. “Is that the right incentive to send generators? That they could end up still collecting capacity payments without necessarily having to feel that they need to run for the winter?”
Van Welie also said the decisions the RTO made when it designed its capacity market 14 years ago need to be reconsidered. The market’s design is based on meeting the summer peak rather than the winter peak, which is now the bigger risk. A seasonal construct that acquires resources separately for the winter and summer would be preferable, he said.
“Do we throw out the capacity market — go back to blank sheet of paper and redesign the seasonal capacity market? Or do we … do something complimentary, really specifically targeting … the firmness of energy that we required during the winter period?
“We have not landed on … the specific solution to this problem. … But we recognize that … some of the things that we assumed as far back as 14 years ago may not be valid.”
AUSTIN, Texas — It’s finally official. Southwestern Public Service can now begin construction on its 478-MW wind farm in West Texas.
The state’s Public Utility Commission on Friday quickly approved a second draft order of the utility’s request for a certificate of convenience and necessity and a power purchase agreement with Bonita Wind Energy. The commissioners had given their verbal approval in April but delayed a final order to allow parties in the docket additional time to provide written responses to their questions (No. 46936). (See Texas PUC Delays Final Approval of SPS Wind Farm.)
“We’re just pleased we now have a resolution in hand and a final order,” said SPS CEO David Hudson, noting it was the fourth time the utility has appeared before the commission in hopes of receiving a final order. “We can now begin construction on the Hale [County] project and the Sagamore project” in New Mexico.
SPS expects to have the Hale project in service no later than 2019, at a cost of $769 million, so that it will be able to receive 100% of its federal production tax credits.
PUC Chair DeAnn Walker had expressed concerns over SPS’ proposal to recover costs by flowing PTCs through fuel, but she was satisfied with the parties’ responses.
The wind farm is part of a 1.23-GW project by SPS parent Xcel Energy that will provide renewable energy to SPS customers in Texas and New Mexico. The utility says the project will save its retail customers about $1.6 billion in energy costs over its 30-year life.
SPS had reached a settlement agreement in February with all parties in the docket but two, the International Brotherhood of Electric Workers Local 602 and Lea County Electric Cooperative. However, neither opposed the settlement.
Commission Streamlines Smart Meter Texas Portal
The PUC also approved a final order streamlining Smart Meter Texas (SMT), the state’s web portal, and aligning it with national data-transfer standards (Docket No. 47472).
SMT is maintained by utilities AEP Texas, CenterPoint Energy Houston Electric, Oncor and Texas-New Mexico Power. It allows customers to download and view their energy data or share them with competitive service providers (CSPs), companies that market energy efficiency, demand response, distributed generation and other services.
Transmission and distribution providers are prohibited from selling, sharing or disclosing advanced meter data but are required to provide “convenient, secure, read-only access” to a customer, the customer’s retail electric provider and other entities authorized by the customer. The data include meter readings used to calculate charges for service, historical load and other proprietary customer information.
The order requires the utilities to support the portal’s home area network (HAN) functionality through their advanced metering systems. It also forbids them from disconnecting an existing HAN device from the meter without the customer’s requests. The HAN devices are costly and have had few takers for their services.
PUC staff last year requested the commission determine what changes, if any, should be made for SMT’s continued operation while its contract was being renegotiated. The four utilities signed a joint development and operations agreement for SMT that dates back to December 2008.
The utilities reached a unanimous settlement agreement in January, with the only contested issue related to the maximum time period that a residential customer or smaller commercial customer may grant a CSP access to the customer’s SMT data, without the customer affirmatively renewing the access.
The commission adopted an administrative law judge’s recommendation that the maximum time period remain 12 months.
PUC to Intervene in SPP-AEP Filing Before FERC
Following its executive session, the PUC moved to intervene in SPP’s recent FERC filing on behalf of American Electric Power (ER18-1541, ER18-1542).
SPP made a compliance filing on May 8 to revise AEP West’s transmission formula rate to reflect the recent change in the federal corporate income tax rate (ER18-63). The filing was made on behalf of AEP Service Corp. and its AEP Oklahoma Transmission and AEP Southwestern Transmission affiliates.
The Oklahoma Municipal Power Authority and DC Transco have already intervened.
