Page 1442 – RTO Insider

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, 2017October 21, 2025

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.

December 5, 2017

Mexico Market Director Seeks Increased Participation

By Tom Kleckner

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.

CENACE mexico capacity market — Attendees gather for the GCPA’s November breakfast meeting in Mexico City | © *RTO Insider*

“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.

Jose Maria Lujambio kicks off the GCPA’s breakfast meeting in Mexico City | © *RTO Insider*

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.

December 5, 2017

NERC Parts Ways with Chief Security Officer

By Rich Heidorn Jr.

Just days after losing its CEO, NERC has seen another senior management departure.

NERC Chief Security Officer Marcus Sachs — Sachs | © *RTO Insider*

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.

December 4, 2017

No Unanimity in ‘Coal Country’ Hearing on CPP Repeal

Last week’s public hearings on the repeal of the Clean Power Plan provided EPA Administrator Scott Pruitt the stage he sought for coal industry supporters to blast the Obama administration’s environmental policies. But not everyone stuck to the script.

Pruitt said he chose to have the hearings in “the heart of coal country to hear from those most impacted” by the CPP. During two days of hearings at the West Virginia State Capitol in Charlestown, coal magnate Robert Murray, West Virginia Attorney General Patrick Morrisey and other CPP critics derided the regulation as two dozen miners in hard hats and overalls looked on in support.

epa clean power plan — Audience view of the Clean Power Plan hearing | *EPA*

But the hearings also attracted many supporters of the CPP, as well as business groups who argued for replacing the CPP with less stringent rules to provide regulatory certainty and protection against litigation.

Pruitt announced the repeal of the CPP in October, saying the Obama administration overstepped its authority by regulating beyond the “fence line” of individual generators. The question facing the Trump administration now is what the replacement — required by EPA’s 2009 finding that CO₂emissions endanger public health — should be. (See EPA to Announce Clean Power Plan Repeal.)

Morrisey said the CPP “would impose a top-down reordering of state energy economies … and would be disastrous for West Virginia and the country as a whole.”

Murray, CEO of Murray Energy, said EPA should repeal the power plan “in its entirety,” including overturning the endangerment finding.

But utilities and business groups urged EPA to leave the endangerment finding in place and focus on a replacement for the CPP.

The U.S. Chamber of Commerce asked for “durable and achievable standards.”

Scott Segal, director of the Electric Reliability Coordinating Council, which represents utilities including Duke Energy and Ameren, said he supports a regulation that would require efficiency improvements in fossil fuel plants.

“While ERCC believes that absent specific guidance in legislation from the U.S. Congress, market principles are the most sound basis upon which to proceed, we nevertheless support the process advanced by EPA,” Segal said. “Federal guidance of sufficient flexibility, and limited to actions within the fence line, can provide regulatory certainty, diminish frivolous litigation, and can aid in planning.”

Richard Revesz, director of the Institute for Policy Integrity at the New York University School of Law, told the Los Angeles Times that repeal without replacement “could open the floodgates for litigation,” leaving power companies vulnerable to “significant and highly uncertain liabilities.”

“The EPA is required to publicly regulate these pollutants. Therefore, repealing the [CPP] without a replacement is illegal,” Connecticut Department of Energy and Environmental Protection Commissioner Robert Klee testified. “Ignoring these facts won’t make the problem go away; it will only serve to make it worse and delay the solutions we desperately need to meet this local, regional, national and international challenge.”

future of energy conference climate change epa clean power plan — Klee | © *RTO Insider*

Klee told RTO Insider later that while the first day of the hearing was dominated by many coal miners in the audience, EPA’s strategy to hold the meetings in coal country “backfired” on the second day when dozens of ordinary West Virginians spoke out against repeal. Klee and others called for additional hearings in other regions of the U.S.

The Obama EPA held public hearings in four states before issuing the CPP. An EPA official said last week that the agency was considering whether to hold additional hearings and had not set a schedule for announcing what kind of replacement rule it will propose.

“As a West Virginian, I’m insulted at the choice of this location,” resident David Lillard said. “It doesn’t make for great TV to have coal executives and some coal barons speaking about saving a few pennies per ton of coal, but it’s great theater to have desperate coal miners carrying the message for the coal barons and the coal companies that have lied to them repeatedly. They were told their pensions were safe, and that was a lie. They were told they would always have health care; that promise was broken.”

Nick Mullins, a fifth-generation coal miner from Kentucky, said the CPP will lead to safer and better job options for his son. “I don’t want him to be a sixth-generation coal miner,” Mullins said, citing the physical toll of the work.

“As long as I can draw a breath, I’m going to keep working to fight climate change and protect the land and country I love,” said Stanley Sturgill, a Kentucky resident who said he suffers from black lung disease after more than 40 years as a coal miner.

“The coal miners I talk to seem to know coal jobs will continue to dry up, with or without a Clean Power Plan,” said Angie Rosser, executive director of the West Virginia Rivers Coalition. “We’ve been pitted against each other by being told we’ll either have coal, or we’ll have nothing. This administration seems to thrive on public anger and conflict. It’s a distraction. When people are fighting, they are not talking. … The clock is ticking to do something different than leaning on a dying industry.”

Indeed, just last week PPL said its Kentucky utilities will retire their aging coal units and replace them with natural gas and renewables — even without carbon regulations. The company said it projects CO₂ reductions of 45 to 90% by 2050.

More: Fairmont Times; Charleston Gazette-Mail; The Washington Post; Los Angeles Times; Washington Examiner; The Associated Press

— Michael Kuser and Rich Heidorn Jr.

December 4, 2017

Besieged CPUC Denies SDGE Wildfire Recovery

By Jason Fordney

Utilities are at the epicenter of public battles between the California Public Utilities Commission and its critics over wildfires, public safety and ethics that have major financial implications for companies and ratepayers.

Those controversies surfaced at a Nov. 30 CPUC meeting at which the commission denied San Diego Gas & Electric’s request to recover from ratepayers $379 million in costs related to the 2007 Southern California wildfires. SDG&E quickly vowed to vigorously fight the commission’s unanimous decision.

california puc wildfire — The CPUC denied SDG&E’s request for $379 million in ratepayer cost recovery for the 2007 California wildfires | © *RTO Insider*

Following recommendations by an administrative law judge, the CPUC said the utility “did not reasonably manage and operate its facilities prior to the 2007 Witch, Guejito and Rice Wildfires,” which killed two people and destroyed homes and property. SDG&E’s $379 million request was separate from other court proceedings, settlements, insurance payments and federal cost recovery regarding the fires.

Commissioner Liane Randolph said the SDG&E case turned on the specific question of equipment maintenance, including faults on a transmission line, a communications wire and vegetation management.

“There is no dispute that each of the fires were caused by SDG&E facilities,” she said. Randolph noted the decision is not a final statement of the doctrine of inverse condemnation, the legal tool that SDG&E leaned on in its claim. The logic is that “the costs of a public improvement benefiting the community should be spread among those benefited rather than allocated to a single member of the community.”

But Randolph said it is appropriate to put the costs on Sempra shareholders, not ratepayers, and the case has nothing to do with the utility’s current management of the system. “The decision is specific to the 2007 incident and the facts of this case,” she said.

Commissioner Clifford Rechtschaffen added that inverse condemnation “is somewhat of a theoretical issue in this matter.”

“The decision does not hold the utilities to a standard of perfection,” he said. “We can’t apply a standard that provides an incentive for a utility to act imprudently or unreasonably,” adding that would send the wrong signal to the utility.

In a written statement, SDG&E Chief Regulatory Officer Lee Schavrien said: “SDG&E strongly disagrees with today’s decision. The CPUC got it wrong. The 2007 wildfires were a natural disaster fueled by extreme conditions including the worst Santa Ana wind event this region has ever seen, combined with high heat, low humidity and hurricane-force winds as high as 92 mph.”

During its third-quarter earnings call, SDG&E parent Sempra Energy vowed to take legal action if denied the cost recovery. (See SDG&E’s Wildfire Costs Undercut Sempra Profits.) The commission did receive praise from The Utility Reform Network and the California Office of Ratepayer Advocates for denying the cost recovery.

During the meeting, commissioners also discussed the increased risk of fires attributed to climate change in California. PUC President Michael Picker noted that areas of elevated or extreme fire hazard are growing in California, to almost 42% of the state, and more people are moving into those areas with higher wind and lightning.

“This is become an increasingly complex area for us,” Picker said, adding that the decision “may or may not” set a precedent for future cases.

As the battle over the 2007 fires continues, the CPUC is preparing to evaluate a similar situation for Pacific Gas and Electric regarding the particularly destructive fires that ravaged California’s wine country this summer, from which the death toll rose to 44 this week. The cause of the fires is still under investigation. (See Wildfires Color California PUC Utility Decisions.)

Embroiled in Controversy

The CPUC issued the ruling amid a swirl of legal battles, regulatory proceedings and public accusations that focuses heavily on the tenure of former President Michael Peevey, who resigned from the commission in January 2015 and has been under investigation by the state’s attorney general for engaging in back-channel discussions with Southern California Edison over the financial terms of the San Onofre nuclear plant’s closure.

The environment around the current CPUC has been increasingly darkened by years of public allegations of other ethics violations. State lawmakers last week renewed their call for Attorney General Xavier Becerra to file charges regarding improper communication between the PUC and PG&E concerning the 2010 explosion of the company’s gas pipeline in San Bruno. The request came soon after the discovery of old email communications between the PUC and former PG&E consultant and Commissioner Susan P. Kennedy regarding the San Bruno settlement. (See Probe Reveals More CPUC-PG&E Contacts on Pipeline Blast.)

The situation led to a confrontation at last week’s meeting between Picker and San Diego attorney Michael Aguirre, a frequent CPUC critic who is involved in the San Onofre case.

As Aguirre approached the microphone during the public comment period at the San Francisco hearing, Picker asked him if he was there to apologize for his “rude, abusive and disruptive behavior” at a recent hearing regarding the San Onofre plant. Aguirre ignored Picker and instead spoke of recent wildfire deaths, the San Bruno explosion and the natural gas leak at the Aliso Canyon storage facility near Los Angeles.

Aquirre said the victims of the Tubbs Fire in Napa and Sonoma Counties “are not here to ask why the California Public Utilities Commission did not enforce the safety rules against PG&E that could have saved our lives.” Picker told Aguirre he himself was a party to one of the proceedings and his appearance might violate commission rules.

Commission Response

The commission on Dec. 1 issued a lengthy public statement saying, “The CPUC has cooperated with the attorney general’s office through every step of the investigation as well as with federal investigators whose demands for documents preceded those of the attorney general. Throughout the process, the CPUC has produced more than 1 million documents to the attorney general.”

The CPUC said the agency had fully complied with a search warrant as of December 2016. “The case is in the hands of the attorney general’s office, and the next steps are up to the office,” the commission said.

At its Nov. 30 meeting, the commission also voted to defer consideration of a related $86 million settlement between it, PG&E and other parties over improper ex parte communications in the wake of the San Bruno blast.

December 4, 2017October 31, 2023

Mass. Prepares for EV Growth, Alternative Energy Standard

By Michael Kuser

BOSTON — Massachusetts’ $2,500 rebates are increasing electric vehicle sales, and state officials are preparing for the shift in demand now, the state’s Department of Energy Resources said Thursday.

“We do have a goal for 300,000 electric vehicles to be registered in the state by 2025,” DOER Director of Emerging Technology Will Lauwers said in a briefing to the Environmental Business Council of New England on Nov. 30. “Providing the charging infrastructure for that is crucial.”

EV registrations have grown from 782 in July 2013 to 3,770 as of March 31, 2017, according to the state Department of Environmental Protection. In the same period, the number of gas-electric hybrids has increased more than five-fold, from 1,034 to 5,701. The state launched its rebate program, which covers both EVs and hybrids, in June 2014.

Although the alternative transportation sector includes biofuels and gas-electric hybrids efforts, electric vehicles and transportation electrification dominate the state’s efforts, Lauwers said. The DEP’s program to incentivize workplace charging stations exhausted its funding this year.

“Utilities have shown interest in helping to reduce the cost of entry to deploying EV charging, so they would help to cover more of the associated costs with new meters, new pads and new connections,” Lauwers said. “Then there’s the VW funding.”

As penance for having rigged diesel emissions test results, Volkswagen is spending $2 billion to install more than 300 vehicle chargers in 15 metro areas, including Boston.

Resiliency, not Totality

Lauwers said Massachusetts is “a nation-leader” in its commitment to reducing greenhouse gases and fostering new renewable energy resources and has “made a lot of progress in the past 12 months” on energy efficiency, energy storage and demand reduction.

He cited the DOER’s June announcement of $10 million in incentives for energy storage demonstration projects, a 200-MW storage deployment target and a $40 million initiative that awards grants to cities and towns to use clean energy technologies to mitigate the risks of power outages arising from severe weather. Award announcements on the storage incentives are expected by early 2018. (See Massachusetts Underwhelms with 200-MWh Storage Target.)

Michael Judge, the DOER’s director of renewable and alternative energy, said storage is key for both grid stability and reducing emissions. Without storage “you end up keeping all these fossil fuel units going because they can’t ramp that fast,” Judge said.

In discussing resiliency studies that the department conducted on 12 state medical centers, Lauwer said resiliency doesn’t mean 100% of normal power availability, just enough to run core functions. For example, a nursing home might lose its heat in a power outage just because it needs 9 V to run the pilot light.

Infrequently used back-up generators at hospitals often fail in the first few hours of running, so energy storage can make a big difference in such situations, he said in discussing the agency’s analytical tools that help facility administrators understand what energy resiliency steps are economically viable for them. In addition, DOER will soon be clarifying how much energy storage utilities can own and how they will be compensated, Lauwers said.

Massachusetts is funding incentives to include energy storage in solar installations, as well as grants for peak demand reduction. Pairing energy storage with solar panels is meant to enhance grid resiliency by reducing the demand curves. Peak reduction grants cover a wide range of projects, from utilities improving the efficiency of substations, to municipalities working to reduce the energy consumption of big-box retail stores, to a thermal energy storage project on Nantucket that will delay the need for a new undersea transmission cable.

| Mass. DOER

The state this year launched its Solar Massachusetts Renewable Target (SMART) program to provide incentives for “long-term sustainable … cost-effective solar development.” The program provides adders based on location, and to projects that provide unique benefits, including community solar and energy storage.

Judge said the state’s new Alternative Energy Portfolio Standard is the only one of its kind in the country. The final draft regulations, expected to be promulgated on Dec. 29, include combined heat and power, flywheel storage, renewable thermal, fuel cells and waste-to-energy thermal technologies. The regulations oblige all retail electric suppliers to acquire a certain percentage of their power from eligible technologies, starting at 4.25% in 2017 and increasing by 0.25% each year.

“Heating is behind the electric sector in decarbonizing and amounts to about 30% of GHG emissions,” Judge said. “DOER incentives for renewable thermal energy and heat pumps are paying off, with nearly 500 MW of combined heat and power systems installed as of the end of October 2017.”

Energy Efficiency Peaking?

Arah Schuur, DOER director of energy efficiency, said the state will deliver $8 billion in efficiency benefits from 2016-2018 and that those savings will continue to grow.

“You put in a light bulb, you put in an efficient piece of technology and it lasts for five, seven, 11 or 20 years, and those benefits accrue as we add more to the portfolio,” Schuur said.

Lighting savings comprise 83% of residential energy efficiency gains and 23% of overall savings. Although the state has nation-leading goals for both electric and natural gas, efficiency savings seem to be peaking, she said.

“That’s because of the change in the lighting market and the change in federal lighting standards. So, screw-in light bulbs are nearing market saturation. There’s natural uptake of LED lights. This [is a] great good news story overall for energy efficiency,” Schuur said.

The limits to lighting’s contribution to efficiency savings will “require a whole new way of thinking about energy efficiency,” she said. The DOER is exploring new ways to achieve efficiency results, such as addressing demand through utility programs, looking at the residential contractor market and driving innovation.