New York’s electric system has the capacity to meet demand for electricity during extreme cold weather conditions through the 2017-2018 winter season, according to NYISO.
The ISO forecasts peak demand this winter of 24,365 MW, slightly higher than the 24,164-MW peak of last winter, when weather was milder than the 10-year and 20-year averages, Vice President of Operations Wes Yeomans said in a review of the ISO’s 2017-2018 winter outlook Thursday.
| NYISO
New York set its record winter peak in 2014, during polar vortex conditions that pushed demand to 25,738 MW. If extreme weather produces colder conditions, with composite statewide temperatures in the 5 to 6 F range, peak demand across the state could increase to approximately 25,989 MW.
| NYISO
Total capacity resources, which include generation, imports and demand response, are expected to total 44,557 MW this winter, including 41,454 MW of generation, 2,311 MW in net external capacity purchases and 792 MW of DR. The ISO maintains 2,620 MW of operating reserves — generation resources above the amount needed to meet projected demand for electricity on any given day.
Xcel Energy can recover its investment in a recently approved 345-kV line project in southern Minnesota if the project is abandoned for reasons beyond the company’s control.
“We agree that the project faces certain regulatory, environmental and siting risks that are beyond the control of management and which could lead to abandonment of the project,” FERC said in a ruling Friday (ER18-12).
Huntley Wilmarth preliminary route options in pink |
Xcel put the incentive request to FERC on behalf of subsidiary Northern States Power, which will design and construct the $108 million Huntley-Wilmarth 345-kV line. The company will be able to recover all “prudently incurred costs” associated with its investment in the line. The abandoned plant incentive was effected Dec. 1.
Northern States Power is investing $54 million with project partner ITC Midwest contributing the other half. Earlier Xcel estimates pegged project cost around $81 million. (See MISO Board Approves MTEP 16’s $2.7B in Tx Projects.)
The line will connect Xcel’s Wilmarth Substation and ITC Midwest’s Huntley Substation in south central Minnesota near the Iowa border. The project, which is expected to be in service by the end of 2021, needs permitting approval from the Minnesota Public Utilities Commission.
FERC can consider the abandoned plant incentive if the transmission project “results from a fair and open regional planning process” or if a project “has received construction approval from an appropriate state commission or state siting authority.”
The Huntley-Wilmarth project was part of the 2016 MISO Transmission Expansion Plan, though some stakeholders objected to the RTO’s decision not to open the project up to competitive bidding. MTEP 16’s only market efficiency project, it would have been put to a competitive process save for Minnesota’s right of first refusal law. FERC cited the planning studies from MISO’s annual MTEP process as grounds for approval.
Transmission line | Xcel Energy
“In this case, the MTEP transmission planning process, through which the project was approved, evaluated whether identified transmission projects will enhance reliability and/or reduce congestion,” FERC said.
Below is a summary of the issues scheduled to be brought to a vote at the PJM Markets and Reliability and Members committees Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.
RTO Insider will be at the Cira Centre in Philadelphia covering the discussions and votes. See next Tuesday’s newsletter for a full report.
Markets and Reliability Committee
Price Formation Problem Statement and Issue Charge
In addition to the voting items listed below, PJM will present a problem statement and issue charge on revising its price formation procedures. The initiative, which would seek ways to allow inflexible units to set LMPs, will be brought to a vote at the next MRC meeting, scheduled for Dec. 21. The RTO has scheduled four education sessions on the topic, which began on Dec. 4 with an explanation of the price formation status quo. The remaining sessions are scheduled for Dec. 11 and morning and afternoon sessions on Jan. 17. (See PJM: Energy Price Formation Addresses DOE NOPR.)
2. PJM Manuals (9:10-9:30)
Members will be asked to endorse changes to Manual 11: Energy & Ancillary Services; Manual 18: PJM Capacity Market; Manual 27: Open Access Transmission Tariff Accounting; Manual 28: Operating Agreement Accounting; and Manual 29: Billing. The revisions implement PJM’s transition to five-minute settlements under FERC Order 825.
3. Distributed Energy Resources Update (9:30-9:45)
Members will be asked to endorse a proposed charter to convert stakeholders’ work on distributed energy resources into a subcommittee reporting to the MRC. It includes a revision FirstEnergy offered on respecting relevant regulatory authorities. (See “Big Support for Jurisdiction Mention in DERS Charter,” PJM Market Implementation Committee Briefs: Nov. 8, 2017.) The subcommittee was created because of concerns that previous DER discussions — which had been conducted in special sessions of the Market Implementation Committee — were hampered by an overly narrow problem statement and issue charge.
4. 2018 Day Ahead Scheduling Reserve (DASR) Requirement (9:45-9:55)
5. Credit Requirements for Regulation (9:55-10:05)
Members will be asked to endorse Tariff revisions to address a billing mismatch affecting credit requirements for regulation-only resources.
Regulation credits are accrued daily and billed monthly, while energy charges are accrued daily and billed weekly. Although the regulation-only resources’ credits are much greater than the charges, the weekly bills for charges create a credit requirement, even though the much larger credit is due to the provider at the end of the month. The proposal would include daily regulation credits in weekly instead of monthly activity for calculating credit requirements. The change will apply to all resources, not just regulation-only resources.
6. FTR Credit Requirements for Transmission Upgrades (10:05-10:15)
Members will be asked to endorse proposed revisions allowing PJM to use modeling to improve its financial transmission rights credit requirements. FTR credit requirements for prevailing paths currently are based on weighted historical congestion on those paths, but transmission system upgrades can reduce congestion, decreasing the value of prevailing-flow FTRs.
The proposal would incorporate the PROMOD simulation results into the FTR credit calculator prior to the FTR bid window to incorporate consideration of major upgrades and reduce default exposure to PJM’s members. (See “Give Them Some Credit,” PJM Market Implementation Committee Briefs: Oct. 11, 2017.)
7. Price-Responsive Demand (10:15-10:30)
Members will be asked to endorse one of three proposals developed at the Demand Response Subcommittee to adapt price-responsive demand (PRD) to Capacity Performance rules.
PRD, which lets customers reduce their loads in response to energy prices in exchange for reduced capacity requirements, was developed before CP rules changed the requirements for demand response.
PJM says PRD bids should be available year-round, the same as generation resources under CP. But state regulators argue they should be allowed the option to make only seasonal contributions because PJM’s summer peak loads exceed winter peaks by more than 20,000 MW.
The RTO’s proposal and a similar one from Calpine would require PRD to reduce load in the winter like other CP resources. The status quo would relieve PRD resources from having to reduce winter loads. (See PJM Grilled on Price-Responsive Demand Rule Changes.)
Members Committee
Consent Agenda (1:20-1:25)
Members will be asked to endorse Operating Agreement revisions associated with PJM sharing of restoration planning generator data with transmission owners. (See “TOs to Receive Confidential Generation Data for System Restoration,” PJM Operating Committee Briefs: Sept. 12, 2017.)
1. Elections (1:25-1:35)
Members will be asked to elect members of the Finance Committee, sector whips and the Members Committee vice chair for 2018.
2. Credit Requirements for Regulation (1:35-1:45)
Members will be asked to endorse Tariff revisions related to a proposed change in credit requirements for regulation resources. (See MRC Item 5 above.)
3. FTR Credit Requirements for Transmission Upgrades (1:45-1:55)
Members will be asked to endorse Tariff revisions to FTR credit requirements to reduce exposure posed by congestion changes resulting from major transmission upgrades. (See MRC Item 6 above.)
4. Price-Responsive Demand (1:55-2:15)
Members will be asked to endorse proposed Reliability Assurance Agreement revisions to address PRD. (See MRC Item 7 above.)
I’m taking a break from trashing the Department of Energy’s Notice of Proposed Rulemaking to return to another of my favorite punching bags: grid batteries.
Sorry, I Lied a Little
But before punching grid batteries again, can I drive another stake in the heart of the DOE proposal?[1] It’s a PJM press release from last week.[2] Here are a couple of my favorite sentences (emphasis added):
“Mild or severe weather, no matter what the winter brings, we are prepared and expect to have more than enough power available to meet consumers’ demand for electricity.” And: “PJM expects to have 184,926 MW of electric resources to meet the forecasted peak demand of 135,526 MW.” By my math, that’s about 50,000 MW to spare, the equivalent of 60 large power plants.
So consumers should pay billions to subsidize clunkers and destroy markets that work?
It’s not too late for Energy Secretary Rick Perry to say “never mind.” Not that I’m holding my breath.
Back to Grid Batteries
OK, where was I? Oh yeah, grid batteries.
The Brattle Group recently joined the herd for “stacking” (adding) the values of batteries for different functions.[3] The study, even called “Stacked Benefits,” finds that the stacked values are equal to or more than the cost of batteries.
This conclusion then prompts the search for “barriers” to batteries — if they’re so darned valuable, why aren’t more getting deployed? And this relative inactivity then supports a call for mandates and subsidies so that the supposedly true economic outcome is imposed by fiat.
Yikes, didn’t I puncture the battery fantasy a couple years ago? Yes, I did.[4]
But let’s hit the high points again. I will try to be succinct.
This figure from the Brattle study is what we’ll focus on:
| Brattle Group
Brattle adds up almost all of the individual “values” left of the dotted line to get the total “Value with Stacked Benefits” to the right.
There are at least four screaming errors in the Brattle analysis: (1) adding energy arbitrage value and generation capacity value, (2) energy arbitrage value, (3) generation capacity value and (4) magnitude of frequency regulation market.
Adding Energy Arbitrage and Capacity Values
As I pointed out in the earlier article, a battery can provide energy arbitrage value or capacity value — but not both. This is not rocket science.
A battery cycled daily for energy arbitrage is going to be partially or totally discharged most of the time, and thus cannot be relied upon to provide its rated capacity on demand in the event of a capacity emergency. It’s just that simple.
Some may claim that the need for capacity will neatly match up with the highest energy prices, so that a battery can be assumed to be discharging when capacity is most needed. This is just wrong.
To see why please take a look at this chart of actual capacity emergencies in PJM.[5]
Please note from the far right column all the emergencies that lasted more than four hours. A battery with four hours of maximum discharge — like that of the sponsor of the Brattle study — cannot possibly provide its rated discharge capacity for more than four hours.
And even for emergencies of four hours or less, a battery discharging for four hours of maximum energy price would have discharged prematurely for two other emergencies, and thus not been able to cover the emergency period.
In other words, batteries would have failed to provide reliability in seven of the 17 emergencies (these seven are highlighted). And this generously, and unrealistically, assumes that the battery operator could each day predict the four highest-priced hours (supposedly the highest-risk hours) of the next day — which it can’t as discussed later.
Now let’s look at the individual benefits that Brattle stacks up.
Energy Arbitrage Value
For energy arbitrage, even in what it calls the “Limited Foresight Case,” Brattle assumes that the battery operator can, each day, predict the four highest-priced hours of the next day for discharge, and pick the lowest-priced hours of the next day for charging.[6]
This is not possible. There is no forward hourly energy market revealing day-ahead prices in advance. Brattle should have simulated a realistic attempt to forecast the highest- and lowest-priced hours, and then used the actual day-ahead prices at those hours to estimate energy arbitrage revenue.[7]
Generation Capacity Value
The discussion above about adding energy and capacity value applies here as well. A four-hour battery simply can’t provide capacity value because capacity emergencies often are longer.
(Of course, a battery shouldn’t need to have 90 days of charge like the DOE proposal implies, but definitely more than four hours.)
Frequency Regulation
Brattle is correct that a battery can provide frequency regulation. But what Brattle leaves out is that frequency regulation is a small niche market that, for example, is already saturated in PJM. And that a battery providing frequency response can’t provide other benefits like energy arbitrage at the same time — no multitasking!
And From the Land Down Under
I suppose this is as good a place as any to lambaste the media hype around the Tesla battery project in South Australia. The blackout precipitating that project had nothing to do with inadequate resources.[8] The events in the blackout involved many hundreds of megawatts, whereas the Tesla battery is only 100 MW of capacity. And its 129 MWh of energy means it would last for little more than an hour.
Last week when the battery was energized, The New York Times led the media fawning, calling it “one of this century’s first great engineering marvels.” Can anyone seriously compare stringing together a bunch of off-the-shelf battery cells with, say, the tallest building in the world (Burj Khalifa), the biggest dam in the world (Three Gorges Dam), the tallest bridge in the world (Millau Viaduct), the Mars rovers, the mapping of the human genome, the Large Hadron Collider, smartphone proliferation, Wi-Fi proliferation, 3D printing, re-floating of the Costa Concordia, Bluetooth, ride-sharing, home-sharing, Google — all marvels of this century? C’mon Times, get a grip.
And in the category of “you can’t make this stuff up”: The day after the battery was brought online, bad weather brought down power lines causing blackouts in areas around the battery.[9] The battery was no help.
Bottom Line
Grid batteries aren’t useless. They are an excellent way to separate utility customers from their money. And they come in shiny boxes.
Steve Huntoon is a former president of the Energy Bar Association, with 35 years of experience advising and representing energy companies and institutions. He received a B.A. in economics and a J.D. from the University of Virginia. He is the principal in Energy Counsel, LLP, www.energy-counsel.com.
“In the Limited Foresight case, the battery is operated with realistic constraints around the ability to predict prices. Specifically, the battery dispatch schedule is optimized across all [day-ahead] value streams with perfect foresight into prices over the next 24 hours.” (page 8, emphasis added). ↑
ERCOT’s Technical Advisory Committee endorsed two previously tabled nodal protocol revision requests (NPRRs) following lengthy discussions last week.
NPRR815 increases from 50% to 60% the limit on load resources providing responsive reserve service (RRS) and requires them to provide at least 1,150 MW of primary frequency response (PFR). Changing the constraint will allow additional resources to provide RRS at lower costs, the Protocol Revisions Subcommittee said.
The ERCOT Technical Advisory Committee meets | ERCOT
Lower Colorado River Authority’s John Dumas questioned claims the higher limit would realize about $3 million annually. He said the analysis overlooked the costs of paying combined cycle units to pick up the inertia responsibilities of coal plants that will be retiring early next year. (See Vistra Energy to Close 2 More Coal Plants.)
“We all know combined cycle units are not going to run unless the energy price supports them running,” Dumas said. “If you need combined cycles to run, you’re going to have to cover their cost to run, which is going to have a cost impact on the energy price. So, I’m a little skeptical of the cost savings [ERCOT] has touted.
“I’m more worried about the reliability impact,” he added. “This is not the time to ‘un-table’ this.”
“Once again, we have the people that get fired for reliability saying they looked at it, they looked at 4,100 MW retiring, and they don’t see a problem with it,” said ReSolved Energy Consulting’s Bob Wittmeyer. “The question I have for ERCOT is, if we implement this today and once it is implemented, how long would it take you to say, ‘Uh oh, we need to back up and take 50% of generation again.’ Is this a four-month process to reverse, or can you do it overnight?”
Dan Woodfin, ERCOT’s senior director of system operations, reminded stakeholders that the NPRR approves methodology for determining the minimum ancillary service requirements that can be procured in the day-ahead market. The ISO’s new reliability desk can issue reliability unit commitment instructions or resort to the supplemental ancillary service market should the ISO be short in the intraday.
ERCOT’s Dan Woodfin (left) and Troy Anderson explain a revision request | ERCOT
“We can change [the minimum ancillary service requirement] on a daily basis, if need be,” Woodfin said. “I realize that’s not preferable, and that’s why we try to cover 70% of the requirement in the ancillary services market.”
Woodfin said staff tested its methodology by taking out the retired resources and found there were some instances in the shoulder months when it would have had to buy an additional 50 MW of ancillary services.
Citigroup Energy’s Eric Goff was among the independent power marketers who opposed tabling the NPRR, saying, “We know ERCOT says it will save money. … We know ERCOT says it’s not needed for reliability. It has expressed that without reservations or doubt. This should be a noncontroversial vote.”
The Texas Industrial Energy Consumers (TIEC), which argued successfully for tabling the change in September, again pointed out that NPRR848, currently being debated in the Wholesale Market Subcommittee (WMS), would create separate pricing for load resources and PFR-capable resources providing RRS.
However, a roll call vote to keep the NPRR on the table was split down the middle, failing to gather a two-thirds majority. The ensuing vote to endorse the revision passed by a 78-22 margin.
Members also endorsed NPRR825, which had also been tabled in September to allow staff to rework its impact analysis. Staff said the revision, which requires ERCOT to issue a DC tie curtailment notice before curtailing the tie’s load, would result in a “more efficient operation of the grid.” It also addresses the ISO’s concerns about declaring an emergency condition before curtailing DC tie load for any reason, rather than using an automated process, staff said.
Staff estimate the NPRR’s requirements will add $200,000-300,000 in development costs for a software tool it would build with or without the NPRR, Woodfin said. “We need a robust tool … not just for this NPRR, but for a multiple of things, including future NERC requirements,” he said.
ERCOT currently issues curtailment watches instead of notices, doing so 48 hours in advance of the day-ahead market. Woodfin said automating the process would be a better option.
“We set limits [before the day-ahead market] and update them every hour going forward, so it’s sort of a rolling 48-hour limit,” he said. “Things change during the course of the day. Lines trip, that sort of thing. We need a mechanism to [automate] that.”
The motion passed despite opposition from the consumer segment, receiving eight no votes and two abstentions.
ERCOT Staff Preparing for New RMR Rules
ERCOT COO Cheryl Mele told the committee that staff are refining protocol revisions to incorporate the Texas Public Utility Commission’s September order on reliability-must-run service rules. (See “Commission Approves RMR Rule Change,” Texas PUC Resistant to NextEra’s Minority Interest in Oncor.)
The order adjusts the suspension-of-operations notice requirements and complaint timeline, requiring written notification to ERCOT at least 90 days before a generating resource is mothballed on a seasonal basis. It also gives the ISO discretion to decline entering RMR service agreements based on the economic value of lost load and requires Board of Directors approval of staff recommendations regarding must-run-alternative (MRA) service. Capital expenditures made under the service agreements could be refunded by the resource owner if the resource participates in the energy or ancillary service markets.
“Effective Jan. 1, we’ll have this new process going forward, despite not having all of the protocol changes defined,” Mele said.
Scott Ends 10 Years as RMS Chair, Vice Chair
CenterPoint Energy’s Kathy Scott | ERCOT
CenterPoint Energy’s Kathy Scott received a standing ovation from her fellow members after delivering her last Retail Market Subcommittee report. Scott is cycling off the group’s leadership after 10 years as either its chair or vice chair.
“It’s a lot of work to lead a subcommittee,” said Sharyland Utilities’ B.J. Flowers. “We’re very happy Kathy has stayed with it for that long.”
TAC Approves 2 Changes to Ancillary Methodology
The committee endorsed staff’s recommendations to make two changes to its 2018 ancillary service methodology for determining non-spinning reserve needs.
The committee approved including solar generation in net load calculations and forecasts, and adjusting for additional over-forecast uncertainty from projected increases in installed wind capacity.
Goff, who chairs the Qualified Scheduling Entity Managers Working Group, asked that the WMS and the Retail Operations Subcommittee be directed to evaluate the non-spin procurement methodology, reflecting conversations taking place within his group and the WMS.
“Our deployments of non-spin aren’t closely correlated with the procurement of non-spin because we don’t typically forecast for error,” he said.
TAC Vice Chair Bob Helton, of Dynegy, reminded Goff that reviewing ancillary service methodology is a TAC goal for 2018.
Staff did not propose any changes for determining regulation service and responsive reserve quantities.
The TAC also unanimously approved four other NPRRs and a verifiable cost manual revision.
NPRR834: Clarifies processes associated with ERCOT’s repossession of congestion revenue rights following a payment breach or other default by a market participant. The change specifies data transparency requirements; documents the disposition of auction revenue funds above amounts owed to ERCOT; clarifies that the one-time auction bids must be positive; and allows the immediate transfer of CRR ownership to the winning bidder should an auction be necessary.
NPRR839: Updates the protocols to clarify that, upon receiving meter data transactions from transmission or distribution service providers, ERCOT will forward the transactions to the designated competitive retailer.
NPRR843: Addresses four reporting items in Section 3 of the Nodal Protocols (Management Activities) by:
Changing the short-term system adequacy reports’ logic for more consistent treatment of resource status; adding language to provide clarity to the reports’ end users;
Creating a new report that will show the portion of ancillary service (AS) offers at or above 50 times the fuel index price (FIP) when the market-clearing price for capacity of the service exceeds 50 times FIP;
Adding elements to the “48-hour highest price AS offer selected” report, including the highest-priced AS offer selected in a supplemental AS market (SASM); and
Creating a SASM disclosure report to provide transparency into AS offers and awards for any SASMs executed within an operating day.
NPRR846: Allows previously committed emergency response service (ERS) resources to participate in must-run-alternative agreements and modifies the methodology for evaluating the performance during the first partial interval for ERS loads on the alternate baseline. The change also defines acceptable parameters for an ERS generator’s self-serve capacity, sets the ERS test performance factor to significantly lower values and in some instances to zero for resources with three consecutive test failures in a 365-day period, along with additional administrative changes and clarifications to existing ERS protocol language.
VCMRR019: Provides clarifications needed following the incorporation of NPRRs 485 and 617 by shortening the timeline for acceptance or rejection of approved verifiable costs from five to three business days.
VALLEY FORGE, Pa. — PJM’s Independent Market Monitor and the RTO are at odds over whether generators should receive additional compensation for providing FERC-mandated primary frequency response.
PJM led most of last week’s meeting of the Primary Frequency Response Senior Task Force because, aside from the compensation issue, the Monitor’s proposal is nearly identical to the RTO’s. But that single issue attracted criticism from stakeholders. (See “Market-Based Frequency Response Solution Hard to ID,” PJM Operating Committee Briefs: Nov. 7, 2017.)
The Market Monitor argued that compensation for primary frequency response, in terms of capacity costs, avoidable maintenance costs and any heat rate loss is already accounted for in PJM’s existing capacity and energy markets. That position is “kind of a nonstarter from a generator side,” American Electric Power’s Brock Ondayko said. The payments are necessary because the revenue provided by PJM’s capacity and energy auctions are “nowhere near the supporting levels for those types of resources,” he said.
Howard Haas of Monitoring Analytics argued that all of the costs involved in providing primary frequency response are baked into the market already through the cost of new entry calculation and should be included in resources’ capacity auction offers. PJM’s interconnection agreement requires all new units to provide the service.
“There is an obligation to provide the service,” Haas said. “To the extent that you’re eligible to participate in the capacity market … you have the opportunity to recover associated capacity costs and any going-forward, avoidable costs. … The capacity market does not make a distinction between new and old units, and the CONE unit includes the capability to provide the service.” (See FERC Has More Questions on Frequency Response NOPR.)
Providing primary frequency response isn’t new to PJM, and any heat-rate losses can be accounted for in the 10% adder included with energy-market offers, he said.
Ondayko dismissed that, saying the only way to receive auction revenue is to offer well below the unit’s costs.
Haas acknowledged that the natural gas boom “turned the market upside down” and that “the prices are low.” But he said prices are low, in part, because “the market is long on supply” and uneconomic units should retire.
“You can get up to one-and-a-half times CONE if the market is short. It’s not,” he said.
Tom Hyzinski of GT Power Group questioned Haas on competition from demand response, which doesn’t provide the inertial benefits necessary for frequency response. Haas agreed that DR should be a demand-side product rather than supply and said more needs to be done to address speculative DR offers. However, load is not required to sign an interconnection agreement.
The Argument for Compensation
PJM’s Glen Boyle said “there is a cost” to providing primary frequency response. “We want to offer a way to recover it similar to reactive supply,” he said.
He envisioned a process similar to PJM’s current payment for reactive power in which market participants make an informational filing with FERC, which directs the RTO on how much to compensate the filer. The requests would need to be newly incurred costs that are not included in the unit’s variable operations and maintenance (VOM) calculations.
“We really need stakeholder feedback on what they think the costs would be,” Boyle said.
Those determinations might get tricky. When one stakeholder calling into the meeting suggested there might be ongoing costs for maintaining the operational flexibility to increase or decrease output, PJM’s Eric Hsia said those sounded like lost opportunity costs, which FERC likely wouldn’t accept.
He said compensation would have to focus on operations and maintenance costs like those incurred for maintaining a heat rate. He said care would be taken to write the rule such that generators can’t “double dip” on costs they’ve already recovered.
Carl Johnson, who represents the PJM Public Power Coalition, questioned the wisdom of having generators file at FERC. “We’re going to struggle with just allowing anybody going in with anything they deem reasonable,” Johnson said.
Stakeholders also debated whether traditional generators with large rotating masses that produce synchronous inertia provide different benefits than renewables with converter-based “synthetic” inertia and should be compensated differently.
Ondayko said such issues should be included in the primary frequency response discussion; otherwise the discussion would be “missing out” on the “mix of resources” necessary to provide grid-scale inertia, he said.
Other Factors
PJM’s proposal would analyze primary frequency response performance by measuring the difference between the RTO’s requested action during a frequency event and how the unit responds when called. Units would have to be online and providing energy, operating between their minimum and maximum real-power output, with available headroom or footroom and assigned Tier 1 or Tier 2 reserves. The analysis would include a pass-or-fail threshold.
“We would take into account the available headroom or footroom and the expected response would reflect that,” said PJM’s Danielle Croop, adding that the analysis wouldn’t “nitpick” on small changes in performance.
Units that are providing frequency regulation wouldn’t be assessed. Nuclear units would still be exempted, as would units that are going to be deactivated and units with technical limitations. Operators would need to submit exemption requests within six months of the rule going into effect.
Stakeholders noted that some units can’t set their deadband operation — which represents the upper and lower bands of acceptable operation — and that retrofits would be prohibitively expensive on units with exceptionally low capacity factors, particularly because they usually run when there are plenty of other units online to provide primary frequency response.
PJM’s Vince Stefanowicz hesitated to agree, saying that during a restoration scenario where frequency regulation hasn’t yet been established, “primary frequency response is kind of our first line of defense.”
Johnson asked if there was a frequency event during the expectedly cold temperatures in the winter of 2014 often referred to as the polar vortex. Hsia said staff are looking into it.
The task force’s next meeting is Dec. 20, when stakeholders will discuss implementation details, including concepts proposed by Dominion Energy.
NYISO has developed a three-phase approach to opening its wholesale electricity market to storage resources, the ISO said Monday upon release of a comprehensive energy storage report describing the plan.
The plan will complement whatever energy storage target New York regulators set later this month for the state’s electricity providers. Gov. Andrew Cuomo on Nov. 29 signed legislation requiring the Public Service Commission to establish targets by the end of the year. (See NY Bill Sets Stage for Storage Targets.)
| NYISO
The ISO report, “State of Storage: Energy Storage Resources in New York’s Wholesale Markets,” lays out three stages to facilitate storage participation — integration, optimization and aggregation with other distributed energy resources, NYISO Senior Vice President of Market Structures Rana Mukerji said Dec. 4.
“The intermittent outputs of renewable solar and wind resources have to be balanced to provide reliable electricity to consumers,” Mukerji said. “Storage resources will be increasingly important in this environment and help balance the intermittency of renewables and provide valuable grid services.”
| NYISO
New York’s electricity grid is in the midst of change driven by the state’s Clean Energy Standard and Reforming the Energy Vision initiatives, designed to transition the state from an aging mix of gas and steam turbines to a greener and more distributed grid.
“We are trying to remove barriers for storage to enter into the market, and actual penetration levels for the various technologies will depend on other factors, such as the price of natural gas, the intermittency in the system — which drives price fluctuations, and also what level of incentives storage is getting from the state public policy initiatives,” Mukerji said.
Grid Flexibility
Michael DeSocio, NYISO senior manager for market design, said the ISO is working on incorporating the latest technological advances in storage, as well as developments in public policy, to allow the grid operator to take better advantage of the capabilities of storage resources.
“Energy storage is not a new concept, but advances in technology have brought energy storage within reach as a viable, competitive energy asset,” DeSocio said. “These new storage technologies can offer the flexibility that quick-start gas turbines provide, while also helping absorb the excess energy that is produced from intermittent resources like solar and wind.”
| NYISO
The ISO’s new report distinguishes between storage in front of the meter and behind the meter (BTM), with the former more likely to participate in wholesale market transactions, although BTM storage could become a wholesale player when aggregated with other distributed resources. Storage developers and utilities in New York have been working with NYISO to establish dual participation of storage in retail and wholesale markets. (See New York Sees Storage in Retail and Wholesale Markets.)
“Today energy storage resources have to choose between providing only one or two ancillary services, and must be at least 1 MW in size,” De Socio said. “NYISO’s future energy storage model will allow storage resources to provide all of the grid services that they’re capable of, while also reducing the minimum participation size from 1 MW to 0.1 MW, thereby increasing the facility for storage to be integrated into the grid.”
Market-Ready by 2020
The ISO has kicked off the integration phase with stakeholders and “plans on having market rules ready for commercial use in 2020,” which will complement the ISO’s DER Roadmap issued in February, DeSocio said.
“A lot of the work that is already being contemplated in the DER program will inform this effort — things like how to aggregate resources — will be reused for integrating storage into the markets as well,” DeSocio said. “So as we think about how to integrate smaller and smaller resources, leveraging a lot of that work has already been done.”
DeSocio also addressed how the new market design will affect capacity bids.
“Today, storage resources that are participating in the wholesale markets must identify their desire to inject or withdraw electricity well in advance of the operating horizon,” De Socio said. “Today, they have to tell us that roughly 75 minutes before that operating horizon.”
The first phase envisions storage resources being able to provide a single offer indicating their willingness to inject or withdraw over the next hour. The markets could then help the resources group their utilization because market operators will have better information than is available 75 minutes before delivery, he said.
“That’s the main improvement: allowing a single offer to be considered and letting the ISO select whether they should be withdrawing or injecting in any particular [interval],” DeSocio said.
| NYISO
As to how quickly storage will come online in 2020, DeSocio said, “We haven’t particularly forecast the future of storage, but we are aware of storage resources today that are looking to participate, and we expect there will be more of them as they become more cost-effective and as policies evolve.”
The ISO’s new storage policies will not eliminate the need for peaking plants but complement them as storage provides a “more environmentally friendly” alternative, Mukerji said.
MEXICO CITY — A top official with Mexico’s wholesale electricity market accepted praise last week for the outcome of the country’s latest capacity auction, but he said he is still intent on increasing participation in the effort.
“There are barriers to true efficiency in the market,” Marcos Valenzuela, director of the National Energy Control Center’s (CENACE) wholesale market, said during a Gulf Coast Power Association breakfast Nov. 30. “I think we need to incorporate more participants, more qualified suppliers, to give more offers to the end users.”
Valenzuela, one of three top directors for CENACE, made his comment after telling his audience that competition had helped narrow offer spreads and drive down prices during Mexico’s third long-term auction in November. Only 16 offers were completed, though in larger packages than in the first two auctions.
According to Mexican energy consulting firm Zumma rg+c, the auction resulted in a world-record low price for wind energy, at $17.76/MWh. But the company said solar energy still accounted for 55% of the energy and clean energy certificates in the auction, with a price of $18.93/MWh.
Only three load-serving entities participated on the buyer-side: the state-owned Federal Electricity Commission (CFE); Spanish multinational Iberdola; and Mekent, an electricity retail division of CEMEX Energia, the second-largest construction materials company in the world. Together they bought a combined 593 MW/year of capacity in the national interconnected system, 5.49 TWh/year of energy and 5.95 million clean energy certificates per year.
Valenzuela said he has focused on increasing the number of private buyers by aggregating qualified buyers. CENACE hopes to attract more participants by establishing a clearinghouse like those used by U.S. RTOs, he said. The clearinghouse is designed to allow buyers other than CFE to participate in the auction process.
Valenzuela said implementing Mexico’s market reforms has been a “big challenge” but pointed to the speed with which the market has ramped up operations. Market reform was written into the country’s constitution just three years ago, and CENACE was able to implement a short-term market in less than a year and a half and run its first long-term auction within five months, he said.
Roll-out of Mexico’s spot market has been postponed to give market participants more time to develop market-rate — rather than cost-based — bids.
“The [timing] is very tight. Not just for us, but even for the participants, because they need to understand … the process,” he said.
Valenzuela’s comments came during the second of what Mexican representatives hope will be a recurring breakfast. Jonathan Pinzon, a partner with Zumma, said he and fellow consultant, Que Advisors’ Peter Nance, hope to schedule eight to 10 meetings in 2018, focusing on intimate gatherings that avoid “death by PowerPoint.”
“We bring together different actors from across the industry,” Pinzon said. “We’ve always thought that small-group partnerships help develop further relationships in the market. It also brings out some good questions not reflected in PowerPoint.”
Pinzon credited GCPA Executive Director Tom Foreman for helping the new effort, recognizing that Mexico is also part of the Gulf Coast. The GCPA has scheduled its next conference on the Mexican power market for May 16 in Mexico City.
Senior Vice President and Chief Security Officer Marcus Sachs, one of seven direct reports to NERC’s CEO, “resigned” effective Nov. 27, the organization said in a statement.
However, three sources knowledgeable about the matter said Sachs was forced to leave. One former NERC staffer said Sachs was ousted because of concerns by industry officials on the Electricity Subsector Coordinating Council (ESCC) that he lacked the background to lead the planned expansion of the Electricity Information Sharing and Analysis Center (E-ISAC).
“The ESCC didn’t have confidence in him taking the ISAC forward,” the former staffer said. “I don’t know if it was GridEx-related; I don’t know if it was storm-related or that Marc came from a communications background.”
Sachs joined NERC in May 2015 from Verizon, where he was vice president of national security policy. Prior to Verizon, he was deputy director of the computer science lab at SRI International and the founder of a computer security consultancy. He also worked for several months as cyber program director at the U.S. Department of Homeland Security and served more than 20 years in the U.S. Army. He has degrees in civil engineering and computer science in addition to a Ph.D. in public policy.
A second former NERC official said he was told Sachs was fired out but that he didn’t know the reason. “All I heard was that NERC forced him out,” the ex-staffer said. “My understanding is his departure was very sudden.”
But the first ex-staffer said the resignation “was supposed to be in the works before” Cauley’s Nov. 10 arrest on domestic abuse charges.
NERC did not respond to a request for comment Monday.
Sachs has joined Ridge-Lane LP, a merchant bank co-founded by former Homeland Security Secretary and Pennsylvania Gov. Tom Ridge. In an email, Sachs called his departure from NERC “a strategic move for me, which will allow me to assist other companies and organizations as they grow and develop.”
“I look forward to the next chapter of my career, and to be able to give back to others many of the lessons I have learned,” he added.
The ESCC, which serves as a liaison between industry and the federal government, is dominated by CEOs of investor-owned utilities.
Tim Roxey, a NERC vice president who serves as chief operations officer for the E-ISAC, was named interim chief security officer with responsibility for overseeing the E-ISAC and directing security risk assessment and mitigation activities. Bill Lawrence, a senior director with the E-ISAC who led GridEx IV last month, will assume day-to-day management of the center. (See Ukraine Attacks, ‘Fake News’ Color NERC GridEx IV Drill.)
MidAmerican Energy CEO William Fehrman, vice chair of the NERC Members Executive Committee, will provide “strategic counsel and guidance” on the E-ISAC’s expansion during the search for Sachs’ replacement, NERC said. Fehrman referred an interview request to NERC.
The E-ISAC is the primary security communications channel for the electricity sector, helping grid operators and others prepare for and respond to cyber and physical threats.
NERC’s 2018 Business Plan calls for improving the E-ISAC’s “technical and analytical capabilities with a goal of becoming the electricity industry’s leading, trusted source for analysis and sharing of security information.” The E-ISAC’s staffing will increase to 29 full-time equivalent employees from less than 20, funded by a $21.9 million budget, a $3.3 million increase from 2017.
“The long-term strategic plan is to transform the E-ISAC into a world-class intelligence collecting and analytical capability for the electricity industry,” according to the plan.
NERC General Counsel Charles Berardesco, who was appointed interim CEO following the Nov. 20 resignation of former CEO Gerry Cauley, said in a statement that he was “confident the E-ISAC, under Tim and Bill’s leadership, will continue to effectively carry out its responsibilities.” (See Cauley Resigns; NERC Launches Search for Replacement.)
Ridge-Lane says it sponsors “public-private partnerships to finance social infrastructure and advance modern urban developments across the U.S., as well as specialty venture capital and corporate development services to commercialize and scale innovative technology companies.”
The company did not respond to a request for comment.
NYISO third-quarter energy prices fell 16 to 30% compared with the same period a year ago because of mild summer conditions, lower natural gas prices and higher output from nuclear and hydropower plants, the ISO’s Market Monitoring Unit reported last week.
Reduced congestion into Long Island and increased congestion out of NYISO’s North Zone contributed to the decline, as well as to “substantially lower” ancillary service prices and uplift costs, MMU Director Pallas LeeVanSchaick, of Potomac Economics, told the ISO’s Market Issues Working Group on Nov. 29.
| Potomac Economics
While the Q3 report showed that NYISO’s market was competitive and that most prices and costs were down substantially compared with last year, the Monitor continued to identify potential improvements to market performance.
The report noted that a mild summer helped reduce loads by 1.8 GW on average, while natural gas prices in most of eastern New York and New England fell 12 to 19%. Nuclear and hydro units increased their average output by up to 640 MW.
Day-ahead congestion revenue fell 20% to $104 million partly because of the lower loads. West Zone lines accounted for the largest share of the congestion (25%) during the quarter, as imports from Ontario and hydro output met with bottlenecks while flowing east. New York City lines accounted for 20%, increasing because of higher gas prices relative to other regions and the expiration of the Con Ed-PSEG wheel. Long Island’s share was down sharply to 17% because of fewer major transmission outages.
Flows from the North Zone accounted for 21% of congestion, as transmission outages and derates and hydroelectric output increased, leading to several extreme negative pricing events.
| Potomac Economics
Actions used to manage 115-kV congestion in western and northern New York led to import limitations from Ontario and Quebec, as well as congestion on the higher-voltage system in other parts of the state. The MMU said the costs and reliability effects of this congestion could be reduced by modeling the 115-kV constraints in the day-ahead and real-time markets.
Capacity Market Spot Prices Down
Third-quarter spot prices for capacity ranged from $2.21/kW-month in Rest of State (ROS) to $9.97/kW-month in New York City. Average spot prices were down 18% in the city and 41% in ROS, but up 6% in the G-J Locality and 51% on Long Island. Demand curve revisions reflecting changes to assumptions about the unit net cost of new entry were a primary driver for the increased prices.
While an increase in installed capacity (ICAP) was a dominant factor in the ROS price rise, supply was up only modestly from a year ago, reflecting higher test values for dependable maximum net capability, the revival of the Greenridge 4 coal unit and new wind capacity upstate. Cleared import capacity rose 350 MW from a year ago, primarily from PJM. Import capacity from Ontario increased by an average of 105 MW, offset by a similar reduction from New England.
Reserve margin and locational capacity requirements rose in all regions as a result of a recent study by the New York State Reliability Council. However, peak load forecasts fell across all regions, neutralizing the price impact from higher installed reserve margins and locational requirements.
Sharp Fall in Reserve Prices
The report also showed that day-ahead reserve prices fell by 28 to 44% from a year ago, consistent with lower load levels and lower locational-based marginal prices and primarily attributable to a decrease in reserve offer prices. After reserve market design changes in November 2015, the MMU observed offers above the standard competitive benchmark (i.e., estimated marginal cost), which it said is partly attributable to the difficulty in accurately estimating the marginal cost of providing operating reserves. However, day-ahead reserve offer prices have gradually fallen as suppliers gain more experience.
| Potomac Economics
In the third quarter, a large number of units offering reserve capacity — particularly fast-start resources in eastern New York — further reduced their offer prices. The MMU said it continues to monitor day-ahead reserve offer patterns and consider potential rule changes, including whether to modify the existing $5/MWh “safe harbor” for reserve offers in the ISO’s market power mitigation measures.
Congestion Management and Pricing
The MMU noted that the ISO’s market-to-market phase angle regulator (PAR) coordination process expanded in May after the expiration of the 1,000-MW Con Ed-PSEG Wheel. (See NYISO Members OK End to ConEd-PSEG Wheel.) Congestion increased through Millwood and into New York City. In general, transmission lines in the A/B/C and J/K zones were operated more efficiently. However, the MMU observed that PARs in those areas were often not utilized to help manage congestion, being adjusted only one to five times per day on average.
The Monitor found that NYISO improved its transmission shortage pricing in June by modifying the second step of the graduated transmission demand curve (GTDC) from $2,350/MW to $1,175/MW, removing the feasibility screen and applying the GTDC to all constraints with a non-zero constraint reliability margin. As a result, constraint relaxation has been much less frequent, with violations occurring in 6% of interval during the third quarter, compared with 59% last year.
Average constraint shadow prices during transmission shortages fell moderately in most areas. Constraint relaxation leads to inefficient prices that are volatile and uncorrelated with the severity of congestion, the MMU said. Despite improved pricing outcomes, constraint shadow prices still did not properly reflect the importance of some transmission shortages. Accordingly, the MMU continues to recommend developing constraint-specific transmission demand curves.
