CAISO, Pacific Gas and Electric, and Calpine have settled their differences over the terms of the reliability-must-run agreements keeping three Calpine gas-fired plants operating instead of retiring.
FERC is likely to issue a decision on the agreements by April 30, Administrative Law Judge H. Peter Young said Tuesday after certifying the uncontested settlements that would reduce the annual revenue the plants receive. The controversial out-of-market RMR payments are opposed by the California Public Utilities Commission and were reluctantly approved by the CAISO Board of Governors in November. (See Board Decisions Highlight CAISO Market Problems.)
The new settlements filed March 21 cover two different FERC dockets, one Calpine’s Metcalf plant (ER18-240), and another for the company’s Feather River and Yuba City plants in Northern California (ER18-230).
Calpine’s Metcalf Energy Center | Calpine
“In general, the offer of settlement would substantially reduce Metcalf’s RMR service rates and would change the MEC facility’s operating status,” Young said of the Metcalf settlement. (See FERC Orders Hearing, Settlement Talks for Calpine RMRs.)
The Metcalf settlement would reduce the plant’s annual fixed revenue requirement to $43 million from about $72 million through 2020 if it retains its RMR status, and make the plant operator responsible for routine repairs and capital expenses. It would set recovery for planned 2018 capital items to $8 million, to be recovered in 12 installments of $675,000 beginning on Jan. 1, 2018.
If the RMR agreement is extended, capital recovery would remain at about $8 million per year. The settlement would also grant the plant $8 million in 2019 and 2020 if the revised agreement is not renewed and the unit shuts down.
The settlements would also take all three plants from Condition 2 (eligible for full cost-of-service payments) to Condition 1 (eligible for only a portion of their revenue requirement) status, and impose a must-offer requirement, which the ISO’s Department of Market Monitoring has recommended for all RMR units. CAISO is working to revise its RMR program to establish a must-offer requirement for resources. (See CAISO, Stakeholders Debate RMR Revisions.)
The Feather River and Yuba City settlements would reduce each plants’ 2018 revenue to about $3.5 million from the previous $4.4 million, with a 2% hike for 2019 and 2020 if the RMRs are renewed. They would also impose a must-offer requirement on the plants.
After CAISO approved the RMRs last November, the CPUC issued an order directing PG&E to use energy storage to meet the needs currently served by the plants. (See CPUC Targets CAISO’s Calpine RMRs.) The storage resources must be online before 2019.
CARMEL, Ind. — FERC on Wednesday approved MISO’s plan to permanently double its hard offer cap but told the RTO to clarify some details about the proposal in a compliance filing within 60 days (ER17-1570-001).
The proposal marked MISO’s second attempt to comply with FERC Order 831, which required RTOs and ISOs to raise their hard caps for verified cost-based incremental energy offers to $2,000/MWh. The commission issued the order in response to the 2014 polar vortex, which sent natural gas prices soaring and left some generators unable to cover fuel costs.
MISO control room | MISO
FERC late last year rejected MISO’s first attempt at complying with the rule, saying the RTO wrongly proposed a provision that prohibited resources from submitting cost-based offers above the required $2,000/MWh hard cap. (See MISO’s Plan for Wintertime Offer Caps Stalled by FERC.)
The commission had also ruled that MISO:
failed to describe what factors it would consider when verifying cost-based offers or distributing uplift;
was silent on its treatment of external supply offers in excess of the cap;
neglected to specify a verification process for demand response; and
failed to limit the cap on all adders above cost to $100.
On Wednesday, FERC determined that MISO’s second filing had cleared up the offer validation process, which gives the Independent Market Monitor discretion to validate market participants’ data. The RTO additionally complied with a requirement that external energy transactions not exceed the hard cap but also not be subject to validation.
However, FERC said MISO still must pledge to apply the new hard cap to adjusted energy offers from fast-start resources.
The commission acknowledged that its previous ruling mistakenly understood “proxy offers” to include fast-start resources’ adjusted offers, but it said it now recognizes the term applies to resources deployed during emergency operating procedures.
“The commission did not intend to change the definition of ‘proxy offers,’” FERC said.
MISO had proposed to apply the $2,000/MWh hard cap to most proxy offers used during emergency conditions for price-setting purposes, but it said emergency demand response proxy offers would not be included. The RTO has long allowed emergency DR resources to exceed the hard price cap up to the value of lost load, which is currently $3,500/MWh.
FERC said it viewed MISO’s value of lost load as an “administratively determined pricing mechanism beyond the scope of the offer cap reforms in Order No. 831.”
The commission also accepted the RTO’s plan to have its Monitor verify offers from DR resources above the $1,000/MWh soft offer cap before market clearing in order to allow them to set the LMP. FERC also approved edited Tariff language that allows resources to submit cost-based incremental energy offers above $2,000/MWh and recover verified costs through make-whole payments, although such offers are barred from setting LMPs.
But the commission is requiring MISO to provide more detail on the Monitor’s verification process for resources that submit incremental energy offers above $1,000/MWh that cannot be verified prior to the market clearing. FERC said MISO must also describe when the Monitor will verify the prices and revise reference levels, and when a market participant can dispute revenue sufficiency guarantee make-whole payments.
“Additionally, we direct MISO to propose Tariff language describing how the amount of the make-whole payment will be determined,” FERC added.
FERC also ordered MISO to update its Tariff to include references to its Operating Cost Survey, which is used to determine reference levels by collecting more than 200 “pieces of data for a single plant,” according to the RTO.
FERC additionally said MISO must clarify the use of its adder for “outage risk,” a term the RTO used in its amended offer cap filing but is not found in Tariff provisions that define reference levels, which instead employs the term “legitimate risk.”
FERC also said MISO appeared to violate a rule that limits to $100/MWh the sum of any adders for cost-based incremental energy offers above $1,000/MWh by allowing two types of adders within its offer cap: the legitimate risk adder and a fuel cost uncertainty adder. The commission gave the RTO 60 days to explain the differences, if any, between the two terms and describe how it will stay within the $100/MWh adder limit.
Massachusetts on Wednesday revoked its selection of Northern Pass as the sole winner of a massive clean energy solicitation, saying it will instead enter contract negotiations with the rival New England Clean Energy Connect (NECEC) project.
The decision capped a tumultuous two months since the state chose Northern Pass in its MA 83D solicitation for 9.45 TWh per year of hydro and Class I renewables (wind, solar or energy storage). The joint project between Eversource Energy and Hydro-Quebec won the contract Jan. 25, only to see the New Hampshire Site Evaluation Committee (SEC) unanimously reject the 1,090-MW transmission line a week later. (See New Hampshire Rejects Permit for Northern Pass.)
Eversource said it understood why Massachusetts needed to move on with its clean energy plans but that “despite recent delays, we continue to believe that Northern Pass is the best project for the region and New Hampshire, and we intend to pursue all options for making it a reality.”
The company had appealed the New Hampshire decision, but the SEC voted March 12 to wait until its permit denial is published later this month before considering the appeal, effectively killing the 192-mile HVDC line’s chance to meet Massachusetts’ March 27 contract deadline. Any contract awarded under the request for proposals must be submitted to the state’s Department of Public Utilities by April 25.
The Massachusetts committee charged with reviewing proposals selected the NECEC as an alternative to Northern Pass. (See Mass. Picks Avangrid Project as Northern Pass Backup.) The committee consists of representatives from the state’s Department of Energy Resources and distribution utilities Eversource, National Grid and Unitil.
| Eversource, Central Maine Power
Central Maine Power, an Avangrid subsidiary, partnered with Hydro-Quebec on NECEC, a 145-mile transmission line that would deliver up to 1,200 MW of Canadian hydropower to the New England grid. The partners estimate the project will cost $950 million.
No Free Pass for NECEC
Massachusetts Sierra Club Director Emily Norton on Wednesday lauded the rejection of Northern Pass as “good news,” saying the project “would have increased electricity costs in the state, destroyed pristine wilderness in New Hampshire and continued the destruction of traditional hunting and fishing grounds of First Nations in Quebec, all while failing to reduce climate pollution in the region.”
During a three-day hearing in February, New Hampshire’s SEC voted 7-0 to reject Northern Pass after expressing concerns that it would harm property values, tourism and land use.
Testifying on behalf of the city of Concord, N.H., during the hearing, wetlands scientist Rick Van de Poll said that the project’s temporary and permanent impacts to wetlands in the city would be significantly greater than the developers assumed in their October 2015 wetlands permit application.
Van de Poll said permanent impacts would include reduced habitat fish and aquatic life habitat; loss of habitat for rare and endangered species; and reduced scenic quality, flood storage and groundwater recharge.
But NECEC is not getting a free pass from environmentalists and other industry stakeholders. New Hampshire Sierra Club Director Catherine Corkery joined Norton in saying, “It is too soon to celebrate, however.” NECEC “carries many of the same problems as Northern Pass.”
“MA has gone from the fatally flawed Northern Pass to the nascent NECEC, which doesn’t have any permits,” New England Power Generators Association President Dan Dolan tweeted. “If the original goal was to meet 2020 climate targets, that’s now out the window. All while leading to potentially the largest electric rate increase in state history.”
Three top generators in Maine are already contesting the NECEC. Calpine, Dynegy and Bucksport Generation, which together own one-third of the state’s installed electric generating capacity, have asked the Public Utilities Commission to allow them to intervene late as full parties in the proceeding to review the project. (See Generators Challenge HVDC Line at Maine PUC.)
A FERC administrative law judge ruled Tuesday that municipal utilities and commission staff failed to prove that the New England Transmission Owners’ (NETOs) base return on equity of 10.57% (11.74% with incentives) is unjust and unreasonable, rebuffing requests to reduce it.
The March 27 initial decision by ALJ Steven A. Glazer found that the discounted cash flow (DCF) analyses by the complainants — the Eastern Massachusetts Consumers-Owned Systems (EMCOS) — and FERC staff were “fatally defective” because they failed to include Algonquin Power & Utilities in their proxy groups, “despite this company’s ample qualifications to be included” (EL16-64-002).
| Avangrid
The EMCOS, whose case was supported by state regulators and industrial consumers, asked FERC in a April 2016 complaint to reduce the NETOs’ base ROE to 8.93% or lower (11.24% with incentives). It was the fourth challenge since September 2011 to the ROE for the NETOs, which include Emera Maine, Northeast Utilities, Central Maine Power, National Grid and NextEra Energy. (See FERC Denies New England Tx Owners ROE Rehearing.)
The 2011 challenge resulted in FERC lowering the base ROE to 10.57% from 11.14% in 2014. But the ruling was vacated by the D.C. Circuit Court of Appeals last April, which found that the commission failed to prove the higher rate was unjust and unreasonable, as required before setting a new rate (Emera Maine et al. v. FERC). (See Court Rejects FERC ROE Order for New England.)
The commission has not responded to the court’s remand.
Setting the Proxy Group
Glazer sided with the NETOs in ruling that the EMCOS’ and staff’s DCF analyses should have included Algonquin because the company pays dividends and operates within the contiguous U.S., and its credit ratings are within the “comparable risk band” for the NETOs. Glazer said FERC staff improperly rejected the company because it is headquartered in Canada and also broke with commission precedent in ignoring the credit ratings of the NETOs’ parent companies.
The EMCOS’ economist rejected Algonquin because it was not included in the Value Line Investment Survey and did not have a five-year Institutional Brokers Estimate System (IBES) earnings growth rate published in Yahoo Finance, the source of earnings growth forecasts used by the commission. IBES later added the company to its ratings; inclusion in the Value Line survey is not required by FERC, the judge said.
Including Algonquin’s IBES-based ROE of 16.14% would significantly alter staff’s and EMCOS’ DCF analyses, making the current 10.57% base ROE within the zone of reasonableness, Glazer said.
“Their zones of reasonableness would shift upward from approximately 6 to 11% to approximately 7 to 16%, and the midpoint of their zones would shift from approximately 8.4% to approximately 11.8%,” Glazer wrote.
Moving the Goal Post
The judge was particularly critical of the EMCOS’ analysis, saying it contained “numerous errors and changed significantly throughout this proceeding,” including on the last day of the hearing in the case. “Both the EMCOS and staff made several unwarranted changes to the commission’s typical DCF analysis,” he said. “In short, the goal post was moved repeatedly by the EMCOS and staff to wherever the football was in order to score points.”
Glazer said he did not need to determine a new ROE because of the inability of staff and the EMCOs to provide reliable analyses that proved the existing rates were not just and reasonable. “The failure of the EMCOS and the staff to meet their burden of proof means that the case is over, because they have produced no DCF analysis that is usable in this case for any purpose.”
He also said that their failure also “renders moot the EMCOS’ further argument that the base and maximum ROEs should be adjusted downward in order to mitigate alleged harm to consumers” caused by the NETOs’ maintenance of equity–heavy capital structures.
Exceptions to the decision are due in 30 days, with objections to the exceptions due 20 days later. If no party objects, the ALJ’s decision would take legal effect without further action by the commission.
That’s unlikely, ClearView Energy Partners said in an analysis of the ruling, which predicted challenges to the inclusion of Algonquin.
Response to Remand
The analysts said FERC could respond to the D.C. Circuit’s remand of the 2014 ruling by opening a Notice of Inquiry or by issuing a revised decision.
“If the remand proceedings ahead for the Emera Maine decision result in the FERC upholding the June 2014 revision of the ROE to 10.57%, then we expect the commission might also affirm the ALJ’s finding here that the most recent complaint fails,” the analysts wrote.
RENSSELAER, N.Y. — NYISO’s Management Committee on Wednesday approved Tariff revisions intended to provide external resources with Rest of State (ROS) deliverability rights to improve their ability to participate in the ISO’s capacity market.
The March 28 vote recommended that the ISO’s Board of Directors authorize staff to file the revisions with FERC under Federal Power Act Section 205.
Ethan Avallone, NYISO senior market design specialist, said Hydro-Quebec US (HQUS) proposed the ISO develop a method for awarding capacity resource interconnection service (CRIS) to entities that create increased transfer capability through transmission upgrades over external interfaces. (See “External Deliverability Rights,” NYISO Business Issues Committee Briefs: March 15, 2018.)
| NYSEG
FERC last year granted HQUS eligibility to receive CRIS in proportion to the incremental transfer capability created by its Cedars Rapids Transmission intertie project (ER17-505). National Grid also stands to benefit from the change after it completes upgrades on its 115-kV Dennison-Alcoa line in Zone D in Q4 2019.
2017 CARIS Report Moves to Board
The committee also approved the 2017 Congestion Assessment and Resource Integration Study (CARIS) Phase 1 draft report on the potential costs and benefits of relieving congestion on the transmission system through generic transmission, generation, demand response and energy-efficiency solutions. (See “2017 Congestion Assessment and Resource Integration Study,” NYISO Business Issues Committee Briefs: March 15, 2018.)
Tim Duffy, economic planning manager, said NYISO has identified three main areas of the state where transmission congestion is: Edic-Marcy, Central East and New Scotland-Pleasant Valley.
To provide additional value to stakeholders, Duffy said the ISO developed a system resource shift case, which assumed retirement of the Indian Point nuclear plant by 2020/2021 and all coal units in the state by 2020, and a resource mix consistent with attaining Clean Energy Standard targets by 2026.
Pacific Gas & Electric is requesting proposals for the development of up to 45 MW of “clean energy” resources including at least 10 MW of energy storage, as the centerpiece of its plans to replace the aging Dynegy Oakland jet fuel-fired power plant.
The utility said it will open a two-month request for offers process in spring, inviting “innovative and competitive solutions for the portfolio.” It hopes to bring the new mix of resources online in mid-2022; the procurement total will depend on the exact resource mix, the company said.
A historical photo of the Oakland Power Plant, which went into operation in 1888. The current jet-fueled generators, owned by Dynegy, went into service 40 years ago. | PG&E
The 165-MW Dynegy plant currently operates under a CAISO reliability-must-run contract to meet local reliability needs.
CAISO identified PG&E’s proposal, the Oakland Clean Energy Initiative, as a preferred solution in CAISO’s 2017/18 transmission plan approved by the ISO’s Board of Governors last week. (See CAISO Moves Ahead With Market Changes.)
The plan includes:
transmission line rerates and system upgrades to remove limiting elements;
at least 10 MW of 4-hour utility-owned in-front-of-the-meter storage in the Oakland C and Oakland L 115-kV substation pocket;
competitive procurement of 10 to 24 MW of “preferred resources” — energy efficiency, demand response, renewable generation and storage — in the substation pocket, at least 19.2 MW of which is “load modifying in nature;”
continuing to rely on transferring Alameda Municipal Power load from Cartwright (North) to Jenny (south) during peak load conditions and after an N-1 contingency, in preparation for an N-1-1.
The project marks the first time that clean energy resources would be deployed as an alternative to fossil fuels for transmission reliability in the PG&E area. It will be working with local community choice aggregator East Bay Community Energy to determine the clean energy and reliability solution.
“PG&E and the system operator worked collaboratively over the last several transmission planning cycles to study how distributed clean energy resources could become part of the solution,” the company said in a news release. The utility said it will seek cost recovery for the battery storage facility from FERC and for distributed energy resources from the California Public Utilities Commission. It expects to file with the PUC by the end of the year.
Since 2010, CAISO has increasingly focused on non-transmission alternatives in its planning. The ISO cannot specifically approve non-transmission alternatives part of its annual plan, but it can identify them as preferred solutions, as it did with the PG&E proposal.
CAISO’s transmission plan said the closing of the 40-year-old generator would cause thermal overloads on the Oakland 115-kV system without new local generation. The estimated cost of the PG&E proposal is about $102 million (2022 dollars), while other alternatives, including transmission lines and generation, ranged from $367 million to $574 million.
Forecast load in PG&E Transmission Access Charge Area 2011-2017 | CAISO
The Dynegy plant’s RMR agreement with CAISO was renewed in September 2017, based on local reliability analysis. The ISO said that based on real-time operations data for 2015 and 2016 there is a need for at least 98 MW for a one-in-three heatwave scenario that would cause heavy loads. It also cited instances where all three 55-MW Oakland units were running for local reliability. A 2018 forecast showed a need of 56 MW because of a discrepancy in substation load forecast distribution that the ISO said it would work with PG&E to correct.
AUSTIN, Texas — ERCOT’s Technical Advisory Committee last week approved staff’s recommendation to remove reliability unit commitment (RUC) capacity from the grid operator’s operating reserve demand curve (ORDC), passing a revision request with minimal discussion.
Staff’s other binding document revision request (OBDRR) revises the online and offline capacity reserves for those resources online during a RUC instruction, and meets the Public Utility Commission of Texas’ directive to remove RUC capacity from the ORDC as part of its project assessing the Texas market’s price formation rules (No. 47199). (See “Commission Directs ERCOT to Revise ORDC,” Marquez to Depart Texas PUC.)
The OBDRR, which passed unanimously, will go to a vote of the Board of Directors during its April 10 meeting. Kenan Ogelman, ERCOT vice president of commercial operations, said staff will work “expeditiously” to get the change made by July 1.
“We’ve committed to the PUC that we would implement this as early as possible,” Ogelman said during the TAC’s March 22 meeting.
The ORDC creates a real-time price adder to reflect the value of available reserves and is meant to incentivize resources to produce more energy and reserves. PUC staff recommended removing both RUC and reliability-must-run capacity from the ORDC, saying it would ensure that scarcity pricing is accurate and reflective of market dynamics.
ERCOT staff said it would take two or three months and $30,000 to $40,000 to make the software changes, an increase from the $15,000 to $25,000 estimate ERCOT gave the PUC earlier this month. The affected systems include Market Management Systems, data and information products, and analytic data.
ERCOT’s legal staff said they need a two-month delay to complete changes to the grid operator’s bylaws and articles of incorporation to include additional feedback from stakeholders. Staff was to share with the TAC comments and its recommendations for the board’s April 10 meeting but will now not make a final recommendation until the June board meeting.
Vickie Leady, ERCOT’s assistant general counsel and assistant corporate secretary, said staff have received “extraordinarily helpful” comments from stakeholders on issues such as definitions of affiliates and membership segments. The bylaws were last revised in 2000.
Some of the market’s largest players — American Electric Power, CenterPoint Energy, Exelon, Oncor and Luminant Generation — banded together to provide joint comments.
The delay puts a hold on Southern Cross Transmission’s (SCT) bid to become ERCOT’s first merchant DC tie operator. (See “Members Debate Southern Cross’ Bid to be Merchant DC Tie Operator,” ERCOT Technical Advisory Committee Briefs: Feb. 22, 2018.)
Oncor and Texas Industrial Energy Customers filed comments recommending SCT be placed in the independent power market segment, while SCT reiterated that it should be placed in the investor-owned utility segment. ERCOT continues to believe that those are the two most appropriate segments for SCT.
ERCOT procured 9.17 MW of weather-sensitive emergency response service (ERS) last summer, about half the amount procured in each of the two previous summers, despite the disruptions caused by Hurricane Harvey.
Weather-sensitive ERS was implemented in 2014 to capture the demand response potential of summer residential and commercial air conditioning loads.
Mark Patterson, manager of market operations support, said the decrease resulted because several transmission and distribution service providers recently modified their standard-offer programs to allow more participation from residential loads — reducing the load that bid to serve as weather-sensitive ERS.
Patterson said on Harvey’s worst day, Aug. 29, the hurricane only reduced 20 MW of capacity obligated to provide service from the 2,300 ERS sites in the storm’s area.
The grid operator projected it will have spent $49.4 million procuring ERS during the year, leaving more than $577,000 unspent.
TAC Unanimously Approves Protocol Changes
Members unanimously endorsed a nodal protocol revision request (NPRR868) that modifies the hub bus and load zone definitions and price calculations to account for the current usage of power flow buses — as opposed to electrical buses — in the day-ahead market and congestion revenue rights auction systems.
Staff sponsored the NPRR, noting there can be differences between power flow buses and electrical buses, making it more suitable to use power flow buses.
Electrical buses — physical transmission elements that use breakers and switches to connect loads, lines, transformers, generators and related infrastructure — are defined statically. A power flow bus — a collection of points on the system that are electrically connected and have zero impedance between them — is identified dynamically based on the status of transmission equipment.
However, electrical buses are used for real-time hub and load zone calculations.
The rewritten formulas will clarify the scenario when buses are de-energized in contingency analyses and align the protocols with ERCOT systems. For the day-ahead and CRR calculations, the LMP of the hub bus is the simple average of the LMPs for each energized power flow bus in the hub. If all power flow buses within a hub bus are de-energized, the LMP does not include the de-energized hub bus. If power flow buses are de-energized under a contingency, the disconnected megawatts are redistributed among the remaining energized buses.
Staff designated the NPRR as urgent and said it would be implemented as soon as possible following board approval.
The TAC also unanimously approved three other NPRRs, two system-change requests (SCRs) and a change to the retail market guide (RMGRR):
NPRR858: Requires ERCOT to publish all current operating plans (COPS) data that are submitted by generators, once its confidentiality has expired, a change from the limited subset currently available. The change provides transparency into all intra-hour updates to COPS data, as generators can update them at any time and change aggregate information available to the market.
NPRR864: Modifies the RUC engine to scale down commitment costs of fast-start resources with less than one-hour starts. Following the change, the RUC engine will recommend slow-start resource commitments only if redispatching online resources and market-based self-commitments of fast-start resources will not resolve the reliability issue. With the change in the generation portfolio, market-based commitment decisions could be made much closer to real time than in the past, allowing more self-commitments to materialize in real time than is reflected in COPS many hours earlier.
NPRR865: Requires ERCOT to publish shift factors for hubs, load zones and DC ties for the real-time market, mimicking the day-ahead market’s current practice and providing more information on the inputs used to calculate pricing aggregations.
SCR793: Gives transmission service providers access to the same ERCOT-generated status telemetry as the ISO’s operators in monitoring line outages with calculated subsynchronous resonance condition monitoring points.
SCR795: Updates the resource limit calculator’s formula for calculating dispatched generation by including the addition of a predicted five-minute wind ramp (PWRR). The PWRR will be calculated from the intra-hour wind forecast and a configurable factor to capture the forecasted five-minute wind ramp, relieving regulation service’s burden to cover the five-minute gain or loss of generation from variations in wind, and instead dispatch this energy economically.
RMGRRR0150: Clarifies the content and format of the competitive retailer safety net spreadsheet within the market guide and removes Section 9, Appendix A1: Competitive Retailer Safety Net Request, which eliminates conflicts between the appendix and language found in Sections 7.4 (Safety Nets) and 7.10 (Emergency Operating Procedures for Extended Unplanned System Outages).
PJM is at odds with some stakeholders over whether existing units should be under the same obligation to provide primary frequency response (PFR) that FERC ordered for new units in February.
Sides clashed at last week’s meeting of the Primary Frequency Response Senior Task Force (PFRSTF) over what Order 842 actually requires.
Though it has evolved since Order 842 came out in February, the debate has been raging in PJM since the commission issued a Notice of Proposed Rulemaking on the topic in November 2016. Staff want to require PFR from all units capable of providing it, but some stakeholders believe PJM is overreaching. (See FERC Finalizes Frequency Response Requirement.)
PJM argues it doesn’t preclude being applied to existing units, while generation owners say it doesn’t explicitly order it either. Stakeholders questioned the RTO’s confidence in its stance, given that staff have filed a request with FERC to clarify the order. Jim Burlew, a PJM attorney, said staff is confident but made the request “out of an abundance of caution.” He said the RTO’s position is that FERC felt the issue was addressed by ordering new units to provide PFR because it assumed current units are already providing it.
Staff attempted to counteract an argument that PJM would be shouldering others’ frequency response responsibilities by showing how other balancing authorities are handling FERC’s order. However, the presentation seemed only to strengthen some stakeholders’ belief that it’s unnecessary for existing units to have the capability.
PJM’s presentation showed that surrounding BAs maintain some PFR requirement for existing units, but stakeholders argued those procedures were more collaborative than the RTO’s plan, which includes referrals to FERC’s Office of Enforcement for units that don’t measure up.
“They’re not looking at a FERC hammer” in the other BAs, GT Power Group’s Dave Pratzon said.
AEP Energy, a subsidiary of American Electric Power, presented a proposal that would maintain the status quo for existing units to provide PFR if they are capable. It would also allow for seeking cost-of-service revenues from FERC for providing the service. A PFR performance evaluation like one that PJM has proposed would go into effect in 2021, and there would be a recommendation that transmission owners and the RTO study localized restoration-related issues.
Jim Fletcher with American Municipal Power pointed out that several of the other BAs are regulated utilities that can unilaterally implement changes — unlike PJM, where individual unit owners will need to make economic decisions.
“They seem to have an advantage about how they optimize frequency response,” he said. “I think it’s important that we continue to keep some form of compensation in the mix here as we talk about [implementation].”
Howard Haas with the Independent Market Monitor noted that regulated utilities have a different cost-recovery model than ISO/RTO markets. Regulated utilities have cost-of-service arrangements subject to regulators’ approval or rejection while PJM’s approach uses markets, where recovery is possible but not guaranteed, he said. The Monitor’s position is that units are already compensated to have and provide PFR through PJM markets and that the cost of new entry (CONE) unit includes the costs of having the capability because the service is a requirement of new units.
“PJM’s markets provide opportunities to recover these costs; and if you don’t, you have to make a business decision about whether or not to exit,” Haas said.
A stakeholder who asked not to be identified asked whether PJM was implying that units that can’t provide PFR should retire.
“That’s the IMM’s position. I don’t think PJM has ever said that,” PJM’s Dave Souder said.
However, Haas noted after the meeting that PJM’s proposal for exemptions from offering PFR specifically states that “economics cannot be used as exemption criteria.”
Pratzon called it “a bit of a stretch … to lay a sidebar obligation” of PFR on a resource that was designed and built for “the primary value” of producing energy, but Haas argued that if it’s a rational decision within PJM’s markets for new units, it’s a “rational decision for existing resources as well.”
Where to Recover?
Pratzon noted concerns that recovering the costs of PFR was also affected by another ongoing stakeholder discussion about variable operations and maintenance (VOM) costs. Stakeholders will vote at the April meeting of the Market Implementation Committee on three proposals that revise how cost-based offers can be submitted. (See “Maintenance in Cost-Based Offers,” PJM Market Implementation Committee Briefs: March 7, 2018.)
PJM’s Tom Hauske assured stakeholders that none of the proposals disallows including PFR costs in offers, but Pratzon noted they differ with whether they are recovered through the capacity or energy market.
“Some generators might think they have more certainty recovering [the costs] in [the energy market] than [in the capacity market],” he said.
Pratzon also questioned PJM’s plan to exempt units that have wholesale market participation agreements (WMPAs) rather than interconnection service agreements. WMPAs are for resources that are governed by state tariffs and aren’t under FERC’s jurisdiction.
“By doing what you’re doing, you’re setting up a system where people who are first in get a break that nobody else gets,” he said.
Pratzon also had concerns with parts of PJM’s proposal to assess PFR performance. Staff will be able to perform assessments up to 30 times per year but would aim for two or three events per month. Staff agreed to accommodate an AEP request to make the factors triggering an event less sensitive, which would reduce the number of events to assess, but said they would need at least three quarterly events for the assessment.
Pratzon argued that it was unfair to allow units that lack real-time telemetry capability to submit data from a selected event because they could cherry-pick their best performance.
Units would receive a pass/fail grade, and PJM would discuss the issue with failing units. If units that fail are intentionally not responding, they could be referred to FERC. PJM plans to put the details in its operating manuals so they can be revised as necessary; the requirement to provide PFR will be in its Tariff so units are required to respond.
Stakeholders agreed to update their proposals based on feedback and have them prepared for a nonbinding poll that will be open between April 4 and 11. The results will be reviewed at the task force’s next meeting on April 26.
Berkeley, Calif. — Electric vehicles are increasing on California highways, but future growth is dependent on solving critical issues around standardization of charging infrastructure, a state regulator said last week.
“The electric vehicle market is transforming on a daily basis,” California Public Utilities Commissioner Carla Peterman said on Friday at the annual POWER Conference at University of California Berkeley. There are about 376,000 light duty EVs, 43 models and 22,000 public charging stations in the state, she said.
“Our investor-owned utilities have a critical role to play in this market,” Peterman said, noting that utilities provide EVs fuel, manage the electric distribution system and help build related infrastructure. The vast majority of charging in California happens at home, she said.
Correctly addressing the standardization of charging infrastructure is extremely important, Peterman said, and there are often worries of stifling innovation because of regulations and cybersecurity, she said. (See Visibility Key as EVs Seek Growth Beyond Early Adopters.)
Gov. Jerry Brown in January issued an executive order to pursue 5 million zero-emission vehicles in the state by 2030, including 250,000 plug-in EV chargers and 10,000 DC fast-chargers. A 2013 executive order encouraged development of dual-compatibility charging infrastructure using the two main types of charger connections.
“We are scaling at the rate that we see some benefits of standardization,” Peterman said.
Peterman discussed an issue paper on EV charging standards presented at the conference by Massachusetts Institute of Technology researcher Jing Li. The research showed that under mandatory compatibility standards, companies would reduce duplicative investment in charging infrastructure, but the size of the electric vehicle market would expand.
Peterman, who has been on the CPUC since 2012, holds a doctorate in energy and resources from Berkeley and is also a former member of the California Energy Commission.
The CPUC in January approved 15 utility projects designed to speed EV adoption, including the installation of fast-charging infrastructure and electrification of school buses and delivery vehicles.
Former FERC Chairman Norman Bay also spoke Friday, commenting on a paper by researchers at the University of Maryland College Park and Harvard University on the role of energy markets and environmental regulations in reducing coal-fired power plant profits and electricity emissions.
“Energy policy can really drive environmental objectives,” Bay said, mentioning FERC rulemakings on transmission planning, energy storage, distributed energy resources, demand response and competitive wholesale markets. Well-functioning markets send the signals needed for investment and retirement, reducing the curtailment of renewables, he said.
Bay also discussed how CAISO’s Energy Imbalance Market (EIM) is growing and helping to address the state’s “duck curve.” Obstacles to expanding markets includes their voluntary nature, getting governance correct, jobs, energy costs and reservations about markets in the West.
“I think there is some residual fear of markets, so thank you Enron and the Western electricity crisis,” Bay said, adding that educating people on the benefits of markets is key to their growth.
At the conference, Matthew Zaragoza-Watkins of Vanderbilt University discussed his research into what he said was withholding behavior by natural gas pipeline operators in New England. The research showed that some nodes were disproportionately served by specialized types of contracts that allow firms to call for gas on demand and to make large adjustments without notice in the last few hours of the day.
The behavior strongly affected gas and electricity prices, he said, and transferred $3.6 billion from ratepayers to generators and fuel suppliers over a three-year period, about half of which occurred in the winter of 2013-2014, he alleged.
FERC staff looked into the allegations, after the research was presented by the Environmental Defense Fund in an August 2017 paper. There was no withholding of pipeline capacity, and the EDF study was flawed and led to incorrect conclusions, FERC said on Feb. 27.
An energy consulting firm thinks MISO has the potential for several gigawatts of demand-side energy savings by 2038, stakeholders learned Thursday.
The 20-year estimates of MISO’s future demand response, energy efficiency and distributed generation were produced by Applied Energy Group (AEG), with near final results presented to stakeholders at a special March 22 conference call. The commissioned study will inform the RTO’s 2019 Transmission Expansion Plan, with researchers using the conditions from four MTEP future predictions to project likely demand-side management.
By 2038, total demand-side management could reduce MISO peak summer demand by 22.5 GW, or about 15%, with 11.3 GW of the energy savings from energy efficiency, 7.2 GW from DR and 4 GW from distributed generation. Next year, AEG predicts MISO will save about 8.2 GW on summer peak demand from demand-side management.
Summer peak demand savings | Applied Energy Group
In two decades, energy efficiency will be responsible for a 69,899-GWh annual energy savings in MISO; distributed generation will account for a 19,566-GWh annual savings; and DR programs will yield a 539-GWh annual savings. The 89,971-GWh savings total by 2038 is a more than seven-fold increase from AEG’s expected 12,764-GWh savings in 2019.
AEG predicts that Michigan, Minnesota, Iowa and Wisconsin have the most potential for energy savings through the next 20 years.
Annual energy savings | Applied Energy Group
Some stakeholders commented that there was virtually no way to verify AEG’s forecasted values with what transpires because behind-the-meter activity is expected to remain largely undocumented.
AEG Managing Director Michael Daukoru said his firm examined both regional and state-specific customer adoption trends along with various state incentives, costs of programs, utility-provided forecasts and capacity growth rates in the study.
MISO staff have said the trickiest part of load forecasting is capturing and projecting the footprint’s unknown amount of demand-side management. (See MISO Looks to Align Load Forecasting, Tx Planning.)
The study found that energy efficiency provides the most significant magnitude of demand and energy savings resources.
“Energy efficiency in our view will continue to play a critical role in demand-side management,” Daukoru said. “EE is quite significant in terms of savings.”
Daukoru predicted that residential behavioral programs that encourage improvements in energy efficiency and home weatherization programs will continue to gain popularity within MISO. New federal lighting standards in 2020 and efficiency upgrades to existing buildings and equipment will also play a role in energy efficiency, the study found.
Distributed resources, driven by rooftop solar, will impact peak loads. MISO will continue to see rapid adoption of distributed generation with the rapidly declining cost of residential rooftop solar, Daukoru said. Distributed wind, on the other hand, is expected to remain prohibitively expensive for most residents.
Combined heat and power is already at high saturation point in parts of MISO, including Texas, Louisiana and Michigan. Expensive installation costs limit more adoption, Daukoru said.
The study found that MISO has room for “significant” DR opportunities, despite “several mature” programs in certain states. AEG expects residents in the footprint to participate in expanded direct load control programs within two decades, installing connected thermostats and smart water heaters that can be automated to turn off in response to reliability threats or energy price spikes.
AEG said utility-led dynamic pricing programs will be emerging only “from isolated pilots.”
“There is enormous potential for dynamic pricing, but it requires political will,” said AEG Senior Vice President Ingrid Rohmund.
Customized Energy Solutions’ David Sapper asked if AEG considered how the federal push to value resilience might affect the adoption of demand-side management in MISO.
“I have not given that much thought,” Daukoru said. “That was not accounted for in our analysis.”
Daukoru added that demand-side resources could be valuable to resilience given their ability to deliver energy savings and render loads more flexible.
AEG’s study will be finalized in June and included in the MTEP studies. MISO and AEG will continue to refine study assumptions for behind-the-meter participation and the potential impact of electric vehicle adoption over the next few weeks.
