MISO Storage Task Force Defines Role, Seeks Plan

By Amanda Durish Cook

After two meetings, MISO’s newly created Energy Storage Task Force has established its charter but not yet developed a plan of action for next year.

While the group spent much of its Nov. 28 meeting finalizing language for its mission statement, it also agreed to schedule an additional conference call in late December to create a 2018 work plan covering storage discussion topics.

During the meeting, stakeholders settled on a sparsely worded charter that stipulates the task force will “engage subject matter experts in the identification of potential issues or topics that are unique to integration of energy storage or challenge the ability to realize benefits of energy storage.”

MISO energy storage task force — Invenergy’s Grand Ridge Battery Storage Facility | *BYD*

The group will also “identify and track issues specific to energy storage that are within the purview of MISO in any of its administrative or functional roles.”

The final version of the mission statement implicitly respects state jurisdiction over storage assets, stakeholders said.

Task force Chair John Fernandes said stakeholders and states were understandably wary of turning over storage assets to MISO’s control. “The 800-pound gorilla in the room is state jurisdiction. There is concern from the states that they don’t want to turn over a piece of hardware, an asset over to MISO,” he said.

Indianapolis Power and Light’s Lin Franks noted that New York has mechanisms in place that allow storage assets to be subject to both state control and ISO regulation, enabling them to participate in wholesale and retail markets “almost simultaneously.”

The charter will now head to the Steering Committee for approval at its Jan. 24 meeting.

A Question of Priorities

Task force leaders have asked stakeholders to help determine the group’s key priorities before the December call. The group expects to also submit an issue prioritization to the Steering Committee, which assigns specific issues to other committees.

Task force members said the group could track storage issues in MISO committees to ensure they are being addressed in order of priority. Some stakeholders cautioned the group that it shouldn’t tread on the Steering Committee’s assignment authority.

Fernandes said the task force will next month take up general education on energy storage issues, identifying what MISO market rules already accommodate storage and reviewing FERC’s Notice of Proposed Rulemaking on storage participation in wholesale markets.

Some stakeholders asked the task force to be mindful of the need to act quickly on storage issues.

“MISO has already indicated that it’s going to model storage in transmission planning. At what point in the calendar is MISO going to start modeling these things?” asked Customized Energy Solutions’ David Sapper. “It seems like the sooner the better.”

In written comments to MISO, DTE Energy asked the task force to make storage modeling in MISO planning its top priority.

The Energy Storage Association asked the task force to avoid “unnecessary administrative burden” and assign issues as quickly as possible, suggesting that the most urgent issue is the development of resource adequacy rules and capacity accreditation for storage resources.

Indianapolis Power and Light suggested that stakeholders this month already begin focusing the discussion on storage participation in the interconnection process and energy and ancillary services markets, and send any readied issues to the Steering Committee. Entergy, however, asked for the first storage issue referrals by the end of the first quarter of 2018.

IPL also asked that MISO create a Gantt chart — a bar chart that illustrates project tasks and their start and end dates — to track storage discussions in the RTO’s different stakeholder committees.

State of MISO Storage

MISO currently has one 1-MW battery that offers regulating reserves under a Stored Energy Resource designation, a market definition for short-term storage that was developed in 2008. However, an additional 50 MW of storage went through the interconnection queue in recent years, 20 MW of which is already in service, while the remaining 30 MW is expected to go live by the end of 2019, according to MISO spokesperson Mark Adrian Brown. The U.S. Department of Energy estimates that even more “distribution-connected energy storage is active or under construction in the MISO footprint,” he said.

The RTO currently has 150 MW of storage in its interconnection queue.

MISO said that while its current rules do not expressly limit storage participation in regulating service, they do not “explicitly define a storage resource or product or fully clarify rules for how storage would integrate under other resource types.” The RTO envisions creating a second type of Stored Energy Resource designation that would allow storage to be eligible to offer energy, capacity, up and down ramping, spinning reserve, supplemental reserve or regulating reserve “to the extent a particular storage resource is technically capable of providing any or all of these products.”

December 5, 2017

PJM Demands Agreement on Tx Replacement Definitions

By Rory D. Sweeney

VALLEY FORGE, Pa. — After years of intractability, can PJM’s Transmission Replacement Process Senior Task Force play nice? The RTO is hoping it can be forced to.

PJM’s Fran Barrett, who administers the task force, told stakeholders at last week’s meeting that transmission owners and customers must agree on a common definition of “end-of-life facilities” to move forward. He said that at its next meeting on Feb. 1, stakeholders will vote to approve a working definition that would apply only to discussions within the task force.

“We’re going to put an end to the end-of-life discussion at the next meeting,” he said.

The directive came after transmission owners declined to endorse a definition developed by Mark Ringhausen of Old Dominion Electric Cooperative. Stakeholders had debated the meaning of the term at previous meetings, and Ringhausen offered to develop a proposed definition.

pjm — Tatum (left) and Ringhausen | © *RTO Insider*

The task force has made little progress since it was chartered in May 2016 to “develop alternatives for providing more transparency and consistency in the communication and review of end-of-life projects in the Regional Transmission Expansion Plan.” FERC issued a show cause order in August 2016 questioning whether PJM TOs’ procedures for planning supplemental projects provided stakeholders opportunity for “early and meaningful input and participation,” as required by Order 890 (EL16-71). That precipitated a 10-month hiatus of the task force, which ended in July. (See Softer Rhetoric as PJM Members Seek Replacement Rules Accord.)

Supplemental projects are proposed by TOs to meet local needs, but they are not required by PJM’s reliability, economic efficiency or operational performance criteria. Their costs are paid by the TO zone and are not regionally allocated, unlike baseline upgrades resulting from the RTEP.

The commission’s show cause order directed the TOs to file rule revisions, or counter with evidence that they were already in compliance with Order 890, within 60 days. The TOs responded Oct. 25, contending that the PJM Operating Agreement already complies with the order, but also proposed a Tariff amendment, Attachment M-3, that they said would improve transparency. Attachment M-3 would add more specificity to annual stakeholder reviews of TOs’ assumptions and methodology, along with TO presentations of their views on local transmission needs and proposed solutions.

FERC, which was without a quorum between February and August, has not ruled on the filing despite promising it would act within about three months of the TOs’ response.

Endorse or Propose

pjm end-of-life facilities replacement — Richardson | © *RTO Insider*

At last week’s meeting, TOs were divided on Ringhausen’s proposal. PPL’s Frank “Chip” Richardson said it “helps define it for me as to what are we really talking about in this task force,” but others hesitated to support it. Tonja Wicks of Duquesne Light said she had not received approval to endorse a definition and asked that the vote be deferred until her company could review it.

“This is a recommendation by one stakeholder of a definition, not the task force definition,” she said.

“And what I’m asking the task force participants: Can you march under this flag for purposes of this discussion to say this is the end-of-life definition?” Barrett said.

“Duquesne is okay with this definition being an ODEC-represented definition,” Wicks said. “We haven’t agreed on any of terms in the definition.”

“That doesn’t help us very much,” PJM’s Steve Herling responded. “We’re trying to have a set of boundaries for the conversation this group needs to have.”

“We can use those words any way you define them, as long as we’re not committing that we agree with those definitions,” Exelon’s Gary Guy said.

Barrett agreed to the deferral requested by Wicks but told stakeholders to come prepared to endorse the definition or propose an alternative.

“One thing that I do not want to get involved in is … trying to parse every component [at a transmission facility] to justify whether it falls within this definition,” Herling warned. “If it has to be replaced, it has to be replaced.”

Analysis Details

Earlier in the meeting, Ed Tatum of American Municipal Power asked PJM to detail its procedures for analyzing projects proposed by TOs.

“With regards to the baseline projects, the narrative is very clear as to what PJM is going to be looking at and thinking about,” Tatum said. “With regard to projects that are not in [FERC] Form 715 and/or are not part of PJM’s baseline — in other words end-of-life and/or supplemental projects — we do not have a narrative evaluation or assessment about how these things work.”

“That actually seems like a fairly trivial thing to fix because the level of analysis that we do is the same, so we can memorialize that somewhere,” Herling said, adding that the analysis is consistent with other studies PJM performs to determine whether retiring a facility will cause a reliability violation. “That’s based on all the tests we do in the RTEP. … I don’t see [that] there’s a documentation issue, but we can make it more clear if people are concerned.”

Tatum continued, asking how certain Form 715 filing requirements are met for supplemental projects, which are submitted by TOs and aren’t necessarily individually vetted by PJM.

“I don’t think that the filing requirements are specific to each facility on the grid individually,” Herling responded. “We don’t try to demonstrate that every facility individually satisfies some criteria. We show the system is reliable and that we have done the appropriate analysis.”

PJM agreed to review its documentation to address both of Tatum’s concerns.

Design Component Changes

AMP also reviewed additional proposed revisions to the task force’s design components. AMP’s Lisa McAlister said the group felt it had “moved” substantially to include TO feedback.

Herling questioned some of the details AMP proposed.

“Some of that level of specificity, we’re going to have to figure out does that actually make sense in the direction that we’re trying to take the [Transmission Expansion Advisory Committee], which is to more dynamic communication, not focused on monthly meetings. Once we see what the proposals are and how they fit together, then we’ve got to figure out is that undoing some of what we’re trying to accomplish with the TEAC.”

Barrett asked that stakeholders begin reviewing the proposed language and formulate positions on what to include in a final supportable package.

December 5, 2017

No Solution for PJM Incremental Auctions

By Rory D. Sweeney

VALLEY FORGE, Pa. — It turns out overtime won’t resolve this jump ball.

PJM Incremental Auction climate change — Chmielewski | © *RTO Insider*

During a September meeting of PJM’s Markets and Reliability Committee meeting, the RTO’s Brian Chmielewski announced that, while no proposal from the Incremental Auction Senior Task Force (IASTF) received the more than 50% approval needed to be moved for endorsement to the MRC, poll results showing that a majority of stakeholders wanted a change indicated a “jump ball” — and that compromise might be possible.

The task force is considering structural changes to the Incremental Auction process to eliminate significant clearing price differences between a delivery year’s capacity auction and its three subsequent IAs.

But at the IASTF’s meeting last week, Chmielewski revealed similar results from a vote taken in November, despite two additional months of meetings and negotiation. PJM’s proposal, known as Proposal A”, was seven votes short of receiving the support needed to move on to the MRC.

The result wasn’t altogether unexpected, as Chmielewski’s early hope for compromise quickly faded at subsequent meetings. (See PJM Members Still Split on Incremental Auctions.)

“I think we’ve kind of come full circle,” he said.

He later confirmed that Proposal A” would nonetheless be presented for a first read at the MRC meeting on Thursday.

While the overall results were similar, Chmielewski noted that there were less total votes the second time around. Exelon’s Sharon Midgley wondered if holding the vote shortly before the Thanksgiving holiday accounted for the voter apathy.

“As a whole, the group has done a lot of compromising,” she said.

The IASTF was also tasked with investigating concerns about market distortion stemming from market participants using replacement capacity to take advantage of the clearing price differences, but stakeholders decided to hold off on that issue until the MRC has decided on the Proposal A” structural changes.

“I would certainly support putting the replacement discussion in abeyance until we see the outcome,” said Carl Johnson, who represents the PJM Public Power Coalition.

“I’m happy to revisit that conversation once that path is clear,” agreed NRG Energy’s Neal Fitch.

Fitch also asked when stakeholders could expect the Independent Market Monitor’s promised update of its report on replacement capacity. An IMM staff member said it would be published shortly.

With those concerns in mind, stakeholders agreed to cancel the task force’s Dec. 18 meeting and instead reconvene at the next meeting scheduled for Jan. 19.

December 5, 2017

NYISO Reports Adequate Capacity for Winter

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.

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.

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.

— Michael Kuser

December 5, 2017

Xcel Can Recover Costs if Minn. 345-kV Project is Canceled

By Amanda Durish Cook

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).

FERC Xcel Energy MTEP — 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.

“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.

December 5, 2017

PJM Markets and Reliability and Members Committees Preview

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)

Members will be asked to endorse proposed revisions to the 2018 day-ahead scheduling reserve requirement. (See “DASR Requirement Drops Again,” PJM Operating Committee Briefs: Oct. 10, 2017.)

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.)

— Rory D. Sweeney

December 5, 2017

Counterflow: Grid Batteries Kool-Aid, Once More with Feeling

Counterflow

By Steve Huntoon

doe grid batteries energy storage — Huntoon

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 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.

If you’re interested in my five prior columns trashing the DOE proposal, they’re available in gruesome detail here: http://www.energy-counsel.com/recent-publications.html. ↑
http://pjm.com/-/media/about-pjm/newsroom/2017-releases/20171129-winter-readiness-release.ashx. ↑
http://www.brattle.com/system/publications/pdfs/000/005/494/original/Stacked_Benefits_-_Final_Report.pdf?1505226490. ↑
http://www.energy-counsel.com/docs/Battery-Storage-Drinking-the-Electric-Kool-Aid-Fortnightly-January-2016.pdf. ↑
http://pjm.com/-/media/committees-groups/committees/elc/postings/performance-assessment-hours-2011-2014-xls.ashx?la=en (highlighting added and footnotes omitted). ↑
“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). ↑
It is important to note as well that efficiency losses are uncertain and vary widely by battery technology. And typically the reported efficiency factors do not include “parasitic load” (cooling system, etc.) which can significantly reduce actual system efficiency. http://www.networkrevolution.co.uk/wp-content/uploads/2014/12/CLNR_L163-EES-Lessons-Learned-Report-v1.0.pdf (page 38). ↑
https://www.aemo.com.au/-/media/Files/Electricity/NEM/Market_Notices_and_Events/Power_System_Incident_Reports/2017/Integrated-Final-Report-SA-Black-System-28-September-2016.pdf ↑
http://www.theaustralian.com.au/news/south-australia-storms-power-blackouts-as-tesla-battery-is-turned-on/news-story/de20d9518b40191381e9534eca722980 ↑

December 5, 2017

ERCOT Technical Advisory Committee Briefs

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.

ERCOT TAC Nodal Protocol Revision Requests nodal pricing — 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.

“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 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.

— Tom Kleckner

December 5, 2017

PJM IMM Opposes Frequency Response Payment Bid

By Rory D. Sweeney

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.

PJM IMM frequency response frequency response — Monitoring Analytics’ Haas (left) and Joe Bowring | © *RTO Insider*

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.

PJM IMM frequency response primary frequency response — Hyzinski | © *RTO Insider*

“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.

December 5, 2017

NYISO Readies Market for Energy Storage, State Targets

By Michael Kuser

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 energy storage wholesale market — | *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.”

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.”

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.

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.