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November 5, 2024

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PJM Market Monitor’s Q3 Report Finds Markets Competitive

By Rory D. Sweeney

PJM’s capacity and regulation market results were “generally competitive” in the first nine months of 2016 but remain vulnerable to stress, according to the Independent Market Monitor’s third-quarter State of the Market Report.

The report by Monitoring Analytics added five new or modified recommendations on uplift, the capacity market and demand response.

The load-weighted average real-time LMP was $29.32/MWh in the first nine months of 2016, lower than for any corresponding period since 2000, reflecting both lower fuel prices and lower demand. It was 25% lower than the first nine months last year.

pjm market monitor
| Monitoring Analytics

If all things, including fuel and emissions costs, had remained constant in 2016 from 2015, the load-weighted LMP would have been $31.67/MWh, still below the 2015 mark of $38.94/MWh. PJM’s average real-time load in the first nine months of 2016 decreased by 1.4% from the first nine months of 2015, to 90,599 MW.

The structures for all but the aggregate energy, day-ahead schedule reserve and financial transmission rights markets were uncompetitive, the report said. The PJM region and all locational deliverability areas in almost every market have failed the three pivotal supplier market power test for almost every auction since at least 2007.

Market design received a “mixed” evaluation. Although the Reliability Pricing Model design and Capacity Performance modifications have “many positive features,” the report said, several features “still threaten competitive outcomes.” Among them: the definition of DR, which allows “inferior” products to substitute for capacity; the definition of unit offer parameters; and the inclusion of imports as substitutes for internal capacity resources.

The Monitor also raised concerns over replacement capacity, recommending against allowing retroactive replacement capacity transactions.

Market performance and participant behavior during high-demand hours raised several concerns, the report said, including potential economic withholding.

“In particular, there are issues related to aggregate market power, or the ability to increase markups substantially in tight market conditions, to the uncertainties about the pricing and availability of natural gas, and to the lack of adequate incentives for unit owners to take all necessary actions to acquire fuel and generate power rather than take an outage,” it explained.

In addition to its suggestion on replacement capacity, the Monitor added four other new or amended recommendations.

First, it recommended that PJM initiate a stakeholder process if it plans to modify its price-setting logic — a software change the RTO made in 2014 to reduce uplift by selecting as marginal any unit committed by PJM to provide reactive services, black start or transmission constraint relief if that unit would otherwise run with an incremental offer greater than the LMP.

The recommendation was one of several that the Monitor said could have reduced the uplift rate paid by decrement bids in the Eastern Region by 93% — to $0.032/MWh instead of $0.446/MWh — in the first nine months of 2016.

The Monitor also recommended that capacity released by PJM in incremental auctions should be offered at the Base Residual Auction clearing price or not have the offer price revealed at all to avoid suppressing the IA price. (See “Proposal Chosen for Capacity Release,” PJM Markets and Reliability and Members Committees Briefs.)

Energy efficiency resources shouldn’t be included on the supply side of the capacity market, the Monitor concluded. “PJM’s load forecasts now account for future EE, but did not when EE was first added to the capacity market. If EE is not included on the supply side, there is no reason to have an add back mechanism,” the Monitor said. “If EE remains on the supply side, the implementation of the EE add-back mechanism should be modified to ensure that market clearing prices are not affected.”

Finally, the Monitor also recommended not removing any defined subzones and maintaining a public record of all created and removed subzones.

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Texas PUC Sets Hearing Schedule for NextEra-Oncor Merger

By Tom Kleckner

The Public Utility Commission of Texas last week scheduled hearing dates on NextEra Energy’s proposed acquisition of Oncor.

PUCT Commissioner Ken Anderson | © RTO Insider
PUCT Commissioner Ken Anderson | © RTO Insider

The commission set a prehearing conference for Friday at the commission’s offices in Austin. The parties will discuss the docket’s (No. 46238) procedural schedule, pending motions and any other matters “that may assist” in the proceedings.

The order also set Feb. 21-24 as potential hearing dates before the commission. That would keep the merger on course to receive PUC approval by the end of the second quarter.

The commissioners could have assigned the case to the State Office of Administrative Hearings (SOAH), but they chose to keep it within their jurisdiction instead. However, a SOAH administrative law judge will be responsible for conducting discovery in the case.

“I would have preferred SOAH, because I don’t think it’s that complex,” Commissioner Ken Anderson said. “Maybe we just start holding our holidays in Oncor’s headquarters in Dallas.”

NextEra announced in late July it had reached an agreement to acquire an 80% interest in Oncor; on Oct. 31 it announced it would acquire the remaining 20%.

Other Matters

The commission punted most of the other meaty issues on its agenda to its next open meeting on Dec. 1.

The PUC debated jurisdictional issues related to distributed generation interconnection agreements, before agreeing to resume the rulemaking’s discussion in December (No. 45078).

Citing a “gut instinct,” Chair Donna Nelson said she was reluctant to rule against staff’s opinion that interconnection agreements do not give the PUC jurisdiction over customer complaints.

PUCT Chair Donna Nelson (left) and Commissioner Marty Marquez | © RTO Insider
PUCT Chair Donna Nelson (left) and Commissioner Marty Marquez | © RTO Insider

“When I read the comments,” Anderson said, “a lot of the [market] participants who staff believe we would not have jurisdiction over have said they don’t mind the jurisdiction.”

“That’s what I struggle with,” Nelson responded. “I met with some companies, including solar companies, who said ‘we think the interconnection agreement, where we’ve agreed to be subject to your jurisdiction, gives you jurisdiction,’ but staff doesn’t agree with that.”

Nelson said she was concerned solar customers would come to the commission seeking redress from potential “bad actors” but that it would be unable to take up the matter.

“To that end, if we did adopt this with staff’s language, we’ve got a bunch of stuff out there that says we don’t have jurisdiction, and we’re asking the Legislature to potentially give us jurisdiction,” Commissioner Brandy Marty Marquez said. “Waiting until the next meeting to make a final decision is a prudent idea, but it kind of sounds like this might be something we need to pull down until we get through the legislative session.” The Texas Legislature’s next session begins Jan. 10.

The commission also decided to take more time to review a report on alternative ratemaking mechanisms that’s due to the Legislature in January (No. 46046), giving the commissioners an opportunity to agree on any recommendations.

“I got a call from a legislator who asked what recommendations were going to be made,” Anderson said. “I said, ‘I’m not sure I have any. We did the report you asked for.’”

“I’d like to see if there’s a recommendation we can make regarding appropriate reforms,” Nelson said.

The PUC also took no action on Lone Star Transmission’s proposal to cut its transmission costs by $6 million, providing the company files its settlement agreement by the end of the year. The settlement will negate the need for a rate case (No. 45636).

The commission approved a rehearing over the City of Garland’s request to amend a certificate of convenience and necessity for a 345-kV line in East Texas, allowing it to “tackle the merits” after the holidays, Anderson said.

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PJM Markets and Reliability and Members Committees Preview

Below is a summary of the issues scheduled to be brought to a vote at the 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.

NOTE: The meetings this week will NOT be in Wilmington, Del., as is customary. They will be held at PJM’s Conference and Training Center in Valley Forge, Pa. RTO Insider will be there covering the discussions and votes. See next Tuesday’s newsletter for a full report.

Markets and Reliability Committee

2. PJM Manuals (9:10-10:10)

Members will be asked to endorse the following manual changes:

A. Manual 3: Transmission Operations. Revisions, the result of a periodic review, include updating voltage control at nuclear stations, certain special protection scheme references and the BC/PEPCO operating procedure.

B. Manual 14A: Generation & Transmission Interconnection Process. Revisions resulting from special Planning Committee sessions, set new service request cost allocation and study methods. To ensure manual language allows cost allocation to occur for all projects, the word “interconnection” is replaced with “new service” in section B.2 of Attachment B.

C. Manual 14B: PJM Region Transmission Planning Process. Revisions will update the Capacity Import Limit calculation procedure. Starting with the 2020/21 delivery year, the CIL will no longer be applied as part of the Reliability Pricing Model. As part of new long term firm transmission service study procedures approved earlier this year, the CIL will be considered during interconnection studies associated with new transmission service requests.

D. Manual 15: Cost Development Guidelines. Revisions will implement updates the fuel-cost policy procedures, part of PJM’s compliance filing on hourly offers, which is awaiting FERC action (ER16-372-002). Major changes include an annual review of the policies, reasons for updating a policy outside of the annual review and a process for submitting undefined costs. (See “Fuel-Cost Policy Revisions Approved,” PJM Market Implementation Committee Briefs.)

E. Manual 18B: Energy Efficiency Measurement & Verification. Revisions, the result of a periodic review, include updates to incorporate the implementation of Capacity Performance.

F. Manual 21: Rules and Procedures for Determination of Generating Capability. Revisions, the result of a periodic review, include clarifications to testing rules and terms.

G. Manual 28: Operating Agreement Accounting. Revisions made to align with recent Manual 1 revisions clarify metering language and define a “fully metered EDC” as one that “reports hourly net energy flows from all metered tie lines to PJM via Power Meter and revenue meter data for the hourly net energy delivered by all generators within that EDC’s territory via Power Meter, for the purposes of energy market accounting.” The changes were developed in response to a stakeholder request.

3. Day Ahead Scheduling Reserve Requirement (10:10-10:25)

Members will be asked to endorse the 2017 day-ahead schedule reserve requirement. (See “Day-Ahead Scheduling Reserve Eligibility to be Studied,” PJM Market Implementation Committee Briefs.)

4. Manual 35 Retirement (10:25-10:35)

Members will be asked to endorse the retirement of Manual 35 and receive an update on its proposed replacement, the new Glossary section of PJM’s website. (See “PJM to Retire Manual 35,” PJM Planning Committee Briefs.)

5. Underperformance Risk Management Sr. Task Force (URMSTF) (10:35-10:50)

Members will be asked to endorse a package of revisions and updates to address underperformance risks. (See No End in Sight for PJM Capacity Market Changes.)

6. Base Capacity Extension (10:50-11:05)

Members will be asked to endorse a proposed one-year extension of Base Capacity made by Jeff Whitehead of Direct Energy. (See No End in Sight for PJM Capacity Market Changes.)

7. Excess Capacity Release Problem Statement/Issue Charge (11:05-11:20)

Members will be asked to approve a problem statement and issue charge presented by Jeff Whitehead of Direct Energy regarding PJM’s sell back of excess capacity in the incremental auctions. (See No End in Sight for PJM Capacity Market Changes.)

8. Combined Cycle Modeling Problem Statement (11:20-11:35)

Members will be asked to approve a problem statement presented by Bob O’Connell, of PPGI Fund A/B Development, regarding combined cycle unit modeling that was developed in the Combined Cycle User Group.

9. Winter-Season Resource Adequacy and Capacity Requirements Problem Statement/Issue Charge (11:35-11:50)

Members will be asked to approve a problem statement and issue charge presented by James Wilson on behalf of the Maryland Office of the Peoples’ Counsel regarding requirements for resource adequacy and capacity needs in the winter. (See No End in Sight for PJM Capacity Market Changes.)

10. Pumped-Storage Hydropower Tariff/OA Revisions (11:50-12:00)

Members will be asked to endorse Tariff and Operating Agreement revisions recommended by the Governing Document Enhancement & Clarification Subcommittee regarding the day-ahead scheduling of pumped-storage hydropower.

11. Revisions to Manual 18 Regarding Replacement of Capacity Obligations (12:00-12:15)

Members will be asked to endorse revisions presented by Barry Trayers of Citigroup Energy (and an accompanying friendly amendment from PJM) proposed for Manual 18: Capacity Market regarding the immediate replacement of capacity obligations.

Members Committee

Consent Agenda (2:20-2:25)

Members will be asked to endorse:

2016 Installed Reserve Margin study results. (See “IRM Study Approved but Criticized for Lack of Winter Analysis,” PJM Markets and Reliability and Members Committees Briefs.)

Proposed clarifying updates to the credit policy in Tariff Attachment Q. (See “Credit Policy Changes Approved,” PJM Markets and Reliability and Members Committees Briefs.)

1. Elections (2:25-2:40)

Members will be asked to elect new representatives for the Finance Committee, sector whips and the vice chair of the Members Committee for 2016-17.

2. Fuel Cost Policy and Hourly Offers (2:40-3:00)

Members will be asked to endorse revisions to Manual 15: Cost Development Guidelines. See MRC item 2.D. above.

— Rory D. Sweeney

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Overheard at the TREIA GridNEXT Conference

GEORGETOWN, Texas — Almost 150 national and regional renewable energy industry representatives gathered here for the Texas Renewable Energy Industries Alliance’s GridNEXT conference. ERCOT CEO Bill Magness and NYISO CEO Brad Jones both delivered presentations, and panel discussions focused on distributed generation, storage technologies, renewable power and the various challenges facing the ERCOT grid.

Future Prices in the Texas Market

Magness opened the conference with a SWOT analysis of ERCOT. In listing the strengths, weaknesses, opportunities and threats facing the ISO, Magness’ focus became apparent: the ability to keep track of distributed energy resources (DERs) and their integration.

He noted ERCOT has about 900 MW of distributed generation connected in its retail-choice areas and “roughly” another 200 MW in the market’s noncompetitive areas.

“That’s not a huge penetration at this point. These resources don’t raise a long-term reliability issue and we’re not waving a red flag, but we expect to see more,” Magness said. “We need to come up with a process to map those DERs. It’s the distribution service provider’s job to model the system, but we want to map those things into things we’re responsible for.”

Magness said ERCOT will soon be issuing a white paper on DERs and asked for stakeholders’ help with improving the resources’ visibility. “We want to work with you on that. We’ve got to get an answer, because it’s holding up the usefulness of the ERCOT system.”

He likened the ISO to an Austin-area moving company. “Their motto is, ‘If we can get it loose, we can move it,’” Magness said. “If we can see it, we can integrate it.”

NYISO CEO Explains 50-by-30

Magness’ counterpart at NYISO, the Texas-native Jones, delivered the conference’s keynote address. Jones detailed the ISO’s plan to meet New York’s “50-by-30” goal: 50% renewable energy use by 2030. To meet that goal, NYISO would have to add either 25,000 MW of solar, 15,000 MW of wind or 4,000 MW of hydro by 2030; it currently has 1,700 MW of wind and 3,000 MW of hydro.

“It’s a significant overall goal, but this is the goal, economy-wide,” Jones said. “It includes transportation, it includes home heating, it includes all those elements. Electric generation would have to decrease production by 60% to account for increases in transportation.”

He said New York’s recent actions to protect the region’s aging nuclear plants will help the transition to a lower-carbon fuel mix. “The state has been very firm: We need to maintain nuclear generation,” Jones said.

The state “had a real concern it would lose these real low-carbon facilities, and that it would make it almost impossible to achieve this 50-by-30 goal. [The nuclear facilities] did it by making a side arrangement with the government. Utilities will charge the customers for it to provide enough financial support to keep them in N.Y. If we’re going to be a low-carbon [grid operator], we have to make sure we’re paying for the attributes we want, whether that’s fast-ramping capacity or baseload gen or low carbon or renewable facilities.”

Renewable Energy Credits: All About the Money?

Addressing the issue of corporate procurement of renewable energy, Jessica Adkins, a partner with the Bracewell law firm, said there are differences among major corporations seeking renewable energy credits (RECs). “If your goal is to say you’re buying green energy, that’s easy for people to do,” she said.

“If all your goal is to claim you’re buying renewables, you can offset usage with RECs. Where Amazon is going is additionality. They want do to more than go green. They want to tell their customers they’re putting renewables on the grid.”

“In our business and outside our business, I’m seeing a further diversification of companies doing these kind of deals,” said Adkins’ fellow panelist, Hans Royal, associate vice president of strategic renewables for Renewable Choice. “They don’t really have an environmental goal, but they see the fixed price of energy. Education is the No. 1 hurdle to why we’re not seeing a faster adoption. It’s coming … industry organizations are actively sharing information and trying to create a community in the purchase-power space. Getting information out to those companies is key.”

Texas Energy Aggregation’s T.J. Ermoian said the issue is the color of money, no matter where customers are. “If they see the government investing in [renewables], they’ll be more comfortable,” he said.

“Being in Texas, we’re energy-rich. I tell people I’m in the middle [of the state] between George Bush’s ranch and Ted Nugent. We’re in the reddest of red states,” Ermoian said. “I start talking about climate change in Texas, and the eyes start to glaze over. Money is the greenest thing people understand. If we can give them a compelling economic vision and quantify what they’ve been paying and say, ‘Here’s what you could be paying.’ … Well, most people are pretty good at math.”

Energy Storage a Positive ‘Disruptive Technology’

Referring to energy storage as a “disruptive technology,” Narrow Gate Energy President Darrell Hayslip was one of several panelists who predicted a brighter future for the technology.

“We’re all trying to figure out where will storage go. Where will it play?” he said. “We’ve done a lot to prove out this technology. The trick now is how are we going to apply it in the system. These are disruptive technologies that require some changes.

“It’s something new we’ve never had before. Cars wouldn’t do any good without highways, cell phones without infrastructure. We’ve got to see infrastructure catch up. The builders don’t make that investment unless they see benefits come out.”

Fractal Business Analytics CEO Judy McElroy said she is finding “compelling reasons” for solar and storage in ERCOT. She predicted one of the largest municipal utilities in Texas — thought to be San Antonio’s CPS Energy, with nine solar farms already generating 230 MW of energy — would be issuing a request for proposals within a week for energy storage solutions.

“We’re seeing in ERCOT the evolution a utility goes through. They’ll do solar first, then storage,” McElroy said. “You have to take into account that from a utility’s perspective, things take a lot of time. It’s sometimes more complex than it needs to be.”

“A lot of people are looking at RFPs in the future,” said Bradley Feuge, head of project management for German solar manufacturer KACO new energy. “Once this big RFP comes out … this municipality kind of sets the pace in the state. They’re seen as a leader nationally, and once they take the leap, you’ll see more people stepping out there as well.”

“Once you add solar to storage, then you essentially have a microgrid that can sustain an hour or so of outages,” said Hugo Mena, Electric Power Engineers’ vice president of business development. “EPE has seen this coming for a couple of years because the integration of storage, whether to a solar plant or a wind farm or storage as a transmission asset, is positive for the grid. The question now is, when it is going to be economically feasible for developers or utilities to implement this technology in their systems. We’ve seen at the municipal level that it’s become economically feasible, but some [investor-owned utilities] are also installing storage for microgrid purposes.”

Transmission Planning: More Complicated than Rocket Science

Bill Bojorquez, Hunt Power’s vice president for transmission planning, said during a panel focused on Texas transmission that continued solar and wind development in the state will not be able to take advantage of initiatives like ERCOT’s Competitive Renewable Energy Zone (CREZ). The $7 billion project facilitated the construction of 3,600 miles of transmission lines, connecting West Texas wind farms with the state’s huge metropolitan load centers.

“We have a lot of solar development coming into West Texas, but this area has a weak transmission grid,” Bojorquez said. “Without CREZ, wind and solar are going to have to follow the same process of any other generation. You’re going to have to commit before we can plan for you.”

“Twenty-five years ago, transmission couldn’t get funding in a company. It was all about generation and keeping things patched together so we didn’t get into trouble at the commission,” said Calvin Crowder, president of GridLiance’s South Central Region. “The returns in Texas are attractive considering what else you’ve seen. There’s been a lot of transmission invest in the investor-owned utilities, the municipal power utilities and the municipal power agencies, as well as the co-ops.”

“Texas knows about energy in every single form. We know how to manage it, we know how to control it, we know how to develop it,” said Ken Donohoo, Oncor’s director of system planning, distribution and transmission. “We as planners have to think about a lot more changes and complexity. Communications and control is key.”

As an example, Donohoo said Oncor has more than 9,300 rooftop solar installations on its system. “We know where every one of those is on our system,” he said.

“Transmission planning isn’t rocket science,” Crowder said. “I talked to a planner once and they said, ‘That’s right. It’s a lot more complicated than putting a rocket in the air.’”

Distributed Generation and Microgrids: Evolving Business Models

Thomas McAndrew, whose Enchanted Rock company provides on-site, natural gas-fueled backup power, said his business provides what is essentially a microgrid control system.

“Our primary job is reliability,” said McAndrew, Enchanted Rock’s managing director. “We’re creating a portfolio of quick-response natural gas assets. We think that’s incredibly important in our current environment, especially in ERCOT. We’re going to have periods of time in the shoulder months where we can displace almost all thermal generation. You may have wind at 90% of the supply stack, but we think it’s important to have quick-start assets. We’re there to buffer when we have sudden changes in either wind or solar generation.”

Brandon Middaugh, a senior program manager with Microsoft, described what she saw as “an interesting trend” in the high-tech industry.

“You have these large, concentrated customer loads,” she said. “When that’s one of your main operating costs, it really drives an organization to build up capacity to interact more directly with the markets, to be more about this collaboration and understand how [electric] markets work today, how they’re evolving and how that affects customers like Microsoft.

“There’s more of a need on our part to interact directly with the whole market,” Middaugh said. “That actually serves the grid operators and the utilities well. Apple, Google and others are registering to self-supply and become wholesale participants. I think you will see more of that, and it can be a boon to grid operators.”

Distributed PV Modules Taking off in San Antonio, Elsewhere

San Antonio’s burgeoning solar market was also a topic of conversation during a panel on distributed PV pricing. Rick Luna, CPS Energy’s senior manager of product development, said under the city’s rebate program, customers are paid to host rooftop solar systems.

CPS Energy’s board recently extended the seven-year-old program, though it is gradually reducing the rebate’s amount. Luna said 500 systems will be eventually installed, noting the $30 million program was expected to sell out next year. However, he said, there are downsides to the explosion of interest.

“That $30 million will be spent by January,” he said. “We’ve seen new market players from other markets coming to San Antonio and aggressively marketing to customers. We welcome them, but it’s not always a fair game. Customers don’t always know what solar should cost … they sign these contracts with $20,000, $30,000 commitments. We’ve updated our rules to try and educate our customers and give them some information to arm them and help them make a more informed decision.”

“There’s been some significant PV module pricing decreases this year,” said Eric Cotney, vice president of sales and marketing for Dallas-based Axium Solar. He attributed the 30% in cost reductions to better technology and lighter modules.

“PV modules are continuing to creep up in the power ratings. What used to be a 25-W power module is now a 275-W power module,” Cotney said. “You add labor efficiencies into that because [technicians] are now able to work with smaller modules. And then racking companies are making their systems more minimalist with fewer bolts, making them lighter and faster to put together. As more of our crews are up on roofs and encountering different installation challenges, we’re getting better at what we do.”

Solar Marketers Debate Texas Market’s Future

Another panel debated whether there’s still room for growth in the Texas market, with ERCOT showing 2,000 MW of solar generation with signed interconnection agreements and the ISO’s long-term studies showing another 20,000 MW in potential additions.

“In states like Texas, where the overall weighted power prices are low, it’s a race to deliver solar at prices that compete with traditional generation,” said Preston Schultz, director of development for Chicago-based Hecate Energy. “Everything is definitely bigger in Texas. You’ve got landowners who control large chunks of land, you’ve got an educated landowner base. In [the Southeast] we’re having to educate landowners most of the time what the technology is. They just haven’t seen it. We come to Texas, they know renewables, they know wind, they know solar on the utility scale. That just makes our job easier.”

David Dixon, of renewable energy company Native, said his company sees the same growth opportunities in the Texas market. He pointed to the Public Utility Commission of Texas’ Power to Choose website, where some retail electric providers are offering to buy customers’ excess renewable energy.

“We expect to see double-digit growth, especially in the residential market. We’re still seeing prices come down,” Dixon said. “What we’re not seeing is solutions for home storage aligning with the homeowner’s expectations. We’re in the early adopter’s stage, but I do think in the future, we’ll be installing storage solutions.”

“The commercial markets have grown due to projects in North Texas, thanks to Oncor rebates,” said Mark Begert, executive vice president and director for Meridian Solar. “Even 1- to 2-MW projects represent a pretty meaningful lift to the overall commercial market in Texas. The lower prevailing electricity rates are a challenge. Rooftop solar return requirements for solar customers are significantly higher than you see in the residential market. Commercial customers want their [internal rates of return] in the mid to high teens. They want payback in five years. The residential customer is more comfortable with eight to 10 years. That’s a significant return threshold solar has to overcome.”

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MISO 2017/18 Planning Reserve Margin at Nearly 16%

By Amanda Durish Cook

MISO will have a 15.8% planning reserve margin for the 2017/18 planning year, up slightly from last year, according to the RTO’s loss-of-load-expectation study.

Jordan Cole, of MISO’s resource adequacy coordination group, told a Nov. 9 conference call of the Reliability Subcommittee that the reserve margin increased by 0.6% over last year’s 15.2%. MISO’s unforced capacity reserve margin is 7.8%, representing a 0.2% increase. In MISO, unforced capacity represents installed capacity minus forced outage rates. MISO’s systemwide installed capacity is at about 151 GW, while unforced capacity is at about 140 GW. The analysis predicts peak demand to hit 128 GW in early August 2017.

Cole said an increase in MISO’s forced outage rate and a forecasted reduction in load are driving the reserve margin increases. He added that local requirements have remained “mostly stable” from the 2016/17 planning year. MISO’s zonal installed capacity ranges from 23,642 MW in Michigan’s Zone 7 to 7,090 MW in Mississippi’s Zone 10.

w2pd9xglrdume0z1ixf2_full_local-resource-zones-miso-content
| MISO

Cole said MISO will return in the spring with results comparing the planning reserve margin to the planning reserve margin requirement, a value that’s calculated by factoring MISO systemwide load into the reserve margin; the requirement is yet to be announced.

Winter Seasonal Assessment All Clear

In the meantime, the MISO footprint should navigate the remainder of 2016 without major challenges, according to the RTO’s coordinated seasonal assessment, which did not identify any outstanding issues for the upcoming winter.  Katherine Hulet, of MISO’s resource adequacy planning group, said the RTO does not predict any major constraints or thermal or voltage issues during the winter season. The assessment included studies of four MISO interfaces and six transfers. (See “Winter is Coming and Coordinated Seasonal Assessment is Scoped,” MISO Reliability Subcommittee Briefs.)

MISO predicts a 104-GW peak load this winter and expects to easily meet it with 142.9 GW of available supply. The RTO easily handled a mild October with a monthly peak at 90.4 GW on Oct. 17, said Steve Swan, senior manager of dispatch and balance.

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Michigan Senate Increases RPS; Keeps 10% Retail Choice Cap

By Amanda Durish Cook

The Michigan Senate last week approved legislation that would increase the renewable portfolio standard while maintaining the 10% cap on retail choice and increasing requirements on alternative suppliers.

michigan senate dte energy
Nofs | Michigan

Senate Bill 438 requires utilities to meet progressive benchmarks of 12.5% renewable energy in 2019 and 15% by 2021, up from the current 10%. The language also includes a non-mandated goal of 35% renewable power and energy efficiency by 2025. Earlier versions of the legislation did not include renewable mandates, but Senate Democrats pushed for the measure.

Senate Bill 437 leaves Michigan’s 10% retail choice cap unchanged while requiring alternative suppliers to pay a capacity charge to utilities if they don’t produce their own power or have contracts with other producers. The state’s two major utilities, DTE Energy and Consumers Energy, say they plan on expanding their capacity, but only enough to serve their existing customers.

After more than two-thirds support in the Senate, the package now heads to Michigan’s House of Representatives.

“All Michigan ratepayers were thrown under the bus today by Senate leadership, forcing a vote on a bill that will increase costs on all ratepayers,” Wayne Kuipers, executive director of Energy Choice Now, a coalition of businesses, trade associations and others seeking to increase competition, said in a statement.

The legislation also requires Consumers and DTE to file integrated resource plans as they retire coal facilities and look to make new generation investments. Consumers and DTE have said that they support the legislation.

Republican Sen. Patrick Colbeck voted against SB437 after his amendment to expand competition failed. “In this case, after all the work that was put into this legislation, there is simply still not enough here to protect ratepayers,” he said. “The bills that we have voted on today not only keep the utility monopolies that are already in place but strengthen their grip on the ratepayers of this state.”

Michigan’s energy policy has not undergone major change since the 10% RPS standard was enacted in 2008. The Nov. 10 votes came after more than two years of work.

michigan renewable portfolio standard
Gratiot County Wind Farm | Michigan Energy Michigan Jobs

“This legislation is not about what’s best for a few companies, organizations, or individuals — it’s about what’s best for the entire state of Michigan,” said Republican Sen. Mike Nofs, chair of the Senate Energy and Technology Committee.

Gov. Rick Snyder (R) issued a statement after the passage, praising the bills. He said energy policy is a “major priority” this term and said he hoped to complete work on the policy before year-end. “These policies have the potential to save Michiganders billions of dollars and make our state’s energy future much brighter,” Snyder tweeted.

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RTOs See Storage as ‘Niche’ Player in Transmission

By Amanda Durish Cook

WASHINGTON — The opening panel of FERC’s technical conference on energy storage last week featured a discussion on whether storage can be a versatile transmission asset or will be limited to “niche applications.”

ferc technical conference energy storage
Kormos | © RTO Insider

Exelon Senior Vice President of Wholesale Markets and Transmission Policy Mike Kormos said storage can change the way transmission planners develop solutions for thermal and voltage overloads because batteries can respond instantaneously to the loss of a transmission line that would cause a reliability violation.

“We operate everything in what we call pre-contingency. We start moving generation, we start spending money before the actual contingency happens because we need a certain amount of time to make sure it happens,” said Kormos, a long-time PJM executive who joined Exelon earlier this year. “The battery can basically respond immediately, and that’s a very unique transmission opportunity that exists for batteries that a lot of other potential infrastructure investments don’t bring us.”

Kumaraswamy | © RTO Insider
Kumaraswamy | © RTO Insider

Kiran Kumaraswamy, market development director at AES Energy Storage, agreed, saying batteries can provide “targeted transmission relief” in a matter of months, not years, and can delay expensive transmission upgrades.

Ed Tatum, American Municipal Power’s vice president of transmission, said that FERC Order 890 admitted that storage cannot provide the same level of reliability and availability as transmission. He said the industry would have to set minimum levels of charge requirements if storage is used. However, Tatum added, the industry “could clearly use more imagination in transmission planning.”

‘Niche Applications’ Only

paul-mcglynn-pjm
McGlynn | © RTO Insider

PJM’s Senior Director of System Planning Paul McGlynn was skeptical, saying using storage post-contingency to respond to reliability problems seemed like a “remedial action scheme.”

He said storage devices have only have “niche applications” as a transmission asset. Beyond voltage and thermal issues, there are only “a couple of other categories,” including resolving short-circuit issues and stability remediation, that PJM would consider a transmission asset.

PJM currently has more than 300 MW of storage, including batteries and flywheels, all of which are compensated through the RTO’s ancillary services markets.

“The circumstances where an electric storage resource could be considered as a transmission asset would be rare and highly location-specific,” the RTO said in its written testimony. “The commission … should not let the technology drive the compensation model but instead allow these resources to realize their potential through the market by offering services that they are capable of providing.”

It said storage could be a cost-effective “last resort” in highly constrained areas of PJM’s system where construction of new generation or transmission may not be possible, adding the resource should be permitted to participate in competitive solicitations under Order 1000.

“If they are both more effective and cost-efficient than a traditional transmission solution (and where the proposal does not carry with it significant technology risk), they could serve as the appropriate solution for inclusion in the [Regional Transmission Expansion Plan] to either defer or displace a competing transmission solution,” PJM said.

But “given the current maturity of battery technology,” PJM said storage is “far more likely” to be limited in the near-term to low-voltage solutions that would be submitted by transmission owners and thus not open to competition.

CAISO also expressed skepticism that storage will have a big role in transmission, saying that although it has studied storage projects as potential reliability solutions in its transmission planning, its “experience reflects that electric storage has more effectively fit within the framework of market resources providing local capacity rather than as transmission assets.”

PJM also raised some operational concerns, saying a battery installed as a non-transmission alternative to address an N-1 reliability violation would need time to recharge between injections, particularly in the winter when there are two peak loads daily. “The applicability of storage to contingencies involving networked portions of the grid should not be ruled out, but could involve much greater complexities related to operational and availability requirements,” it said.

Who’s in Control?

AMP’s Tatum said if a battery is going to serve a transmission function, it should be under the control of the transmission provider. “If we’re going to have something out there that is a low-cost, more effective solution than actually throwing traditional wires in the air, we need to think about it and treat it in the same way,” he said.

Kormos said resource owners might hand over “state-of-the-charge” management — determining when a battery recharges and injects — to RTOs. “If its primary purpose is to avoid a transmission problem, whatever criteria that violation is, I think we should handle it like any other transmission asset at that point in that it is turned over to the ISO/RTO,” he said.

But CAISO said in its written comments that it “prefers that operation of these resources occur through the CAISO’s energy and ancillary services market processes rather than the CAISO controlling the operation of a resource outside of its market processes.”

“This approach ensures that system resources or resources within a transmission-constrained area operate together to meet grid reliability needs and enables the resource to participate most broadly in providing value to the market,” the ISO said.

Compensation and Cost Allocation

One of the questions raised by FERC staff in calling the conference was how storage should be compensated and its costs allocated.

Sundararajan | © RTO Insider
Sundararajan (left) and Tatum | © RTO Insider

Raja Sundararajan, vice president of regulatory services at ‎American Electric Power, said storage that provides transmission services could be compensated for their ancillary services through a separate commercial contract to ensure transmission ratepayers are not paying for them.

Tatum warned that compensating storage with more than one revenue stream could result in “trying to serve two masters.”

“It’s kind of hard to … have one foot in the competitive world and one in the regulated world,” he said.

Tom Kaslow, director of market design and policy for FirstLight Power Resources, said his company “finds it difficult to separate the transmission support functions into what might be classically called transmission equipment functions.”

Kaslow | © RTO Insider
Kaslow | © RTO Insider

Although storage can perform a wholesale transmission function, “this single aspect of service does not warrant compensation as a transmission asset,” Kaslow said in his written testimony. “All electric storage resources should participate on a level playing field in the wholesale competitive market.”

Kaslow questioned why a storage resource would be solely dedicated to transmission use when additional efficiencies could be provided. “We want [compensation] done in a way that makes sure there isn’t disruption to the other market revenues that other storage resources are going to rely on,” he added.

FirstLight owns 1,400 MW of generation in Connecticut and Massachusetts, 1,200 MW of which are pumped storage.

“Currently, our facilities can provide performance well beyond what [competitive wholesale] markets define as a minimum level of performance. We can come online, the whole station, within 10 minutes; we can provide single-unit response and much shorter time frames,” he said. He suggested an entirely new “very fast reserve” product compensation rate, similar to a payment category in use in the U.K.

However, he said using a regulated payment for compensation could have the unintended consequence of causing barriers to further investment “if you are not part of whatever RTO planning exercise identifies your storage resource.”

PJM suggested allowing storage resources to have any market revenues deducted from the costs of the resource included in transmission rates. “In this way, the resource would not simply lie unused in those hours when it otherwise could provide energy or ancillary services. Transmission ratepayers could then receive the value of those market revenues as an offset to the entity’s revenue requirement,” PJM said.

To prevent transmission owners from becoming market participants and potentially violating corporate separation rules and FERC’s Standards of Conduct, PJM said storage assets could be housed in a separate company, which would have a contract for reliability-based services with the transmission owner.

Test Cases

PJM said the commission will need to provide guidance on issues such as defining undue discrimination and designing compensation models that avoid distorting markets. “In order for the commission to address these issues in an informed way, the industry may need to present specific situations that planning authorities and ultimately the commission can use as ‘test cases’ to help further develop future policy,” the RTO said.

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FERC Panelists Debate Storage Uses, Compensation

By Rory D. Sweeney, Amanda Durish Cook and Robert Mullin

WASHINGTON — FERC’s technical conference on energy storage Wednesday featured debates over the breadth of its potential uses and discussions on ways to avoid over-compensating resources performing multiple functions simultaneously.

More than 20 witnesses spoke during the daylong conference, including representatives of PJM, CAISO, NYISO and several utilities, storage operators and technology companies (AD16-25).

Storage, all agreed, is unique in its ability to perform both load- and supply-type functions and to provide services to distribution and transmission operators as well as end-use customers.

“It’s incumbent upon us to … not treat storage like other things because it simply isn’t. It’s the one thing that’s not like any other thing,” said Commissioner Colette Honorable at the opening of the conference.

While the commissioners didn’t run the conference, they found it important enough to attend part of the morning session. “We all know that storage is a group of technologies that is evolving and has abilities to contribute to the provision of electric service to customers that I’m not sure we can fully understand,” Commissioner Cheryl LaFleur said.

| © RTO InsiderM/em>
All three FERC commissioners attended part of the technical conference | © RTO Insider

“I think it’s very important that FERC continue to work on removing barriers to entry” for energy resources, Chairman Norman Bay said.

‘Old Duality’

Lorenzo Kristov, principal of market and infrastructure policy at CAISO, said the versatility of storage upends the “old duality” of resources and load because loads can become resources by installing devices behind the meter that enable “storage-like behavior.”

“Storage-like resources on the grid, we think, really have the potential to really multiply in their volume and variations and scope,” Kristov said. “There are lots of opportunities for multiple-use applications,” he said.

ferc energy storage compensation
Nielsen | © RTO Insider

Heidi Nielsen, an attorney in FERC’s Office of the General Counsel, started the discussion with a reference to FERC’s 2010 rulemaking on storage, which designated Western Grid Group’s storage batteries as transmission facilities, reflecting their function of providing thermal overload protection (EL10-19).

The commission barred Western Grid from making sales into wholesale organized markets to address cross-subsidization concerns — fears that markets could be distorted if some participants can recover cost-based rates, allowing them to potentially underbid those that have no cost-based assets.

The commission also expressed concerns that RTO independence could be compromised if the grid operator is responsible for the profitability of the electric storage project’s charging and discharging, “rather than simply carrying out a market participant’s instructions.”

Millar | © RTO Insider
Millar | © RTO Insider

The grid operators said storage is not an option for providing black start service.

“We have had experiences where we had to look at how much volt current the battery can produce when you’re starting up systems because the rest of the transmission system is counting on adequate volt current to be able to tell the difference between running load versus if there has been a fault on the system,” said Neil Millar, CAISO’s executive director of infrastructure development. “Without enough volt current, the protection challenges really climb.”

DeSocio | © RTO Insider
DeSocio | © RTO Insider

Having a dispatchable negative load, on the other hand, is “very helpful to a grid operator,” said Michael DeSocio, senior manager of market design for NYISO. Pumped storage in particular is “a tool that grid operators love to have,” he said.

Kiran Kumaraswamy, market development director at AES Energy Storage, said that when storage is deployed to respond to overloads, it tends to be “severely underutilized.”

“We do think there are definitely opportunities for us to pursue both [ancillary and transmission service] in a manner that doesn’t invade market operations,” he said.

Clarifying Concepts

Cleve | © RTO Insider
Van Cleve | © RTO Insider

Sarah Van Cleve, energy policy advisor at Tesla Motors, asked panel participants to consider what the industry means by the term “multiple-use.” She defined it as a device that can provide services across at least two of the four “traditional buckets” of services, which she described as transmission, distribution, wholesale market and customer-located services — such as backup power or energy price arbitrage.

“There is really a spectrum of what’s meant by dual-use or multiple-use” with respect to energy storage devices, said Jeff Nelson, director of FERC rates and market integration at Southern California Edison, which has already signed contracts for about 500 MW of storage. Nelson said storage can simultaneously serve such functions as voltage support, reactive power and capacity. At the same time, on the retail side, a storage resource can provide end-users the ability to shave peak demand, helping to reduce retail demand charges and shift consumption patterns under time-of-use rates.

And storage can further furnish reliability services at the distribution grid level — by reducing voltage constraints, preventing voltage overheating and improving voltage quality.

“So, done properly, they can provide all these services, to a certain degree, at once,” Nelson said.

Old School, New Technology Storage

Aparna (left), Narang | © RTO Insider
Narang (left) and Nelson (SoCalEd) | © RTO Insider

Aparna Narang, director of short-term electric supply at Pacific Gas and Electric, provided examples of how two very different storage resources fulfill multiple, simultaneous functions.

The first is old-school technology: PG&E’s 1,200-MW Helms pumped storage facility east of Fresno, Calif., which bids energy and ancillary services into CAISO’s wholesale market and is capable of simultaneously providing regulation and spinning reserve services.

The facility is also equipped to absorb volt-ampere reactive (VAR) power while generating electricity, which makes the pump side of the plant available for emergency out-of-market dispatch for voltage support.

Ko | © RTO Insider
Ko | © RTO Insider

PG&E’s more modern example is a 4-MW battery located in Yerba Buena that mostly provides frequency regulation services but can also function concurrently as spinning reserve.

It also has an additional use: The seven-hour battery offers one of the utility’s large customers the ability to “island” — or temporarily separate from the grid — in the case of grid instability.

Narang acknowledged that managing storage for multiple uses can be complicated. “The level of complication really varies based on numerous dimensions associated with each of the storage devices, including the duration of the resource and the services it provides, whether there are multiple users, whether it’s on the transmission or distribution system [and] whether it’s predictable,” she said.

“The simultaneous nature is really just a physics question,” said Ted Ko, director of policy at battery system designer Stem. But there’s a fundamental limitation to any battery system that restricts the type of electricity market services that can be provided simultaneously.

Kintner-Meyer | © RTO Insider
Kintner-Meyer | © RTO Insider

“You can’t do one service that causes you to discharge and one service that causes you to charge [simultaneously]. That doesn’t make any sense,” Ko said.

Michael Kintner-Meyer, a researcher with the Pacific Northwest National Laboratory, said the “pitfall” of simultaneity is “that we’re just adding up too many services at the same time,” creating the risk of overcompensating for a resource’s contribution to the energy market when that resource is technically incapable of delivering if called upon.”

“We still have to obey the laws of physics there and not go over the rate of capacity in terms of power, as well as in terms of electric energy,” Kintner-Meyer said.

Primary Obligation

The panelists generally agreed that while storage may be able to perform multiple functions, it should be managed with an eye to fulfilling its primary obligation. “If you’re going to do other things, you need to have enough capacity for your priority,” said Troy Miller, director of grid solutions at S&C Electric, a Chicago-based company that provides energy management and grid-scale storage to transmission and distribution network operators.

PG&E’s Narang pointed out that the key function of the Yerba Buena battery is to provide islanding services for the utility’s customer. For that reason, the system always maintains a 50% state of charge, with the balance of the capacity offered into the CAISO market. “And when you island, you take [the battery] out of the market,” Narang said.

Who is in Control?

For SoCalEd’s Nelson, grid safety and reliability should be foremost.

Nelson offered a hypothetical example of a distribution-located resource that at times provides ancillary services to an ISO. In that situation, the distribution service operator (DSO) puts the storage resource through an interconnection process designed to allow safe operation, Nelson said. But as the resource begins to provide multiple services, the DSO — in an attempt to maintain reliability — might impose restrictions that prevent the resource from participating in the wholesale market.

The control of the storage should depend on whether the device is interconnected into the transmission or distribution network, Nelson said. “The direct connector needs to have the ultimate say on what’s safe or not safe to operate.”

Nonperformance Penalties

ferc energy storage compensation
Kristov (left) and Miller (S&C)| © RTO Insider

CAISO’s Kristov said that ensuring a storage device acts as promised will require specifying its obligations and setting penalties for not performing.

Kristov said the industry might need to define nonperformance penalties and incentives in ways that “capture” the priorities for a particular storage device, which could change over time. And penalties should be commensurate with the overall effect on the grid.

“How serious is the impact of nonperformance and how strong are the incentives we need to have?” Kristov asked.

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Renewables Win Some, Lose Some in State Election Results

By William Opalka and Rich Heidorn Jr.

Donald Trump’s election wasn’t the only race to have major implications for electricity policy. Renewable energy advocates claimed a victory in Florida while losing in Vermont and Washington state.

Nevada voters, meanwhile, took a step toward retail choice. And Trump’s promise to scrap EPA’s Clean Power Plan threatens to undercut Exelon’s lobbying to raise electric rates in Illinois to subsidize its struggling nuclear plants.

Vermont

Wind power was dealt major blows in Vermont in statewide and local elections.

Incumbent Lt. Gov. Phil Scott, a Republican, who ran on an anti-wind power campaign, won the governor’s office with 54% of the vote.

Although Scott said he supports the regional clean energy goals advocated by the rest of New England, his website pointedly left out wind energy and emphasized solar, hydro and natural gas. Scott advocated a moratorium on wind turbines and endorsed more local control over siting in a series of questions posed by VTDigger.org. He campaigned to “protect ridgelines” from wind power development and said the focus on economic development should lie elsewhere.

| Renewable Energy Vermont
| Renewable Energy Vermont

“During the campaign, Governor-elect Phil Scott expressed support for Vermont’s 90% total renewable energy goal. It may not be possible to achieve the state’s clean energy and climate goals without wind power, [which] offers affordable and price-stable renewable energy,” Olivia Campbell Andersen, executive director of Renewable Energy Vermont, said Friday. “With new wind projects being developed in our neighboring states of Maine and New York, it would be a loss to Vermont’s economy, climate and renewable energy progress to entirely forgo future consideration of clean wind power in our state.”

In local elections, nonbinding referenda in two towns in the southern part of the state rejected a 24-turbine project proposed by Avangrid Renewables.

“We are disappointed by the unfortunate outcome,” Avangrid spokesman Paul Copleman told RTO Insider. “We are confident that the project would be a valuable and significant benefit to the local communities of Grafton and Windham, while also making an impact towards energy independence and climate change. However, as we have indicated, we plan to cease development unless the communities reconsider their decision.”

In Grafton, the wind project was voted down 235 to 158. In Windham, the vote was 181 to 101.

New Hampshire

Democratic Gov. Maggie Hassan defeated incumbent Republican Sen. Kelly Ayotte by about 750 votes out of more than 700,000 cast in a Senate campaign in which the Northern Pass transmission project was one of the issues.

Ayotte had advocated burial of the entire 192-mile route, which project developer Eversource Energy said would make the project unfeasible. Hassan’s campaign sought to increase the undergrounding of the line beyond the current 60-mile plan, but she did not indicate how much.

“I think it played a role, but in the general scheme of things the fundamental issues surrounding the presidential race took precedence over specific issues, whether those were gun control, abortion rights, Northern Pass or others,” said Jack Savage, spokesman for the Society for the Protection of New Hampshire Forests, which has taken the project to court. “Hassan won the Senate seat by a narrow margin because [Hillary] Clinton took New Hampshire by an equally narrow margin.”

Northern Pass is undergoing review until next year by the state’s Site Evaluation Committee. In addition, a U.S. Department of Energy presidential permit, required because the line would cross international boundaries, is pending.

Florida

In Florida, voters rejected a proposal backed by Florida Power & Light and Duke Energy that critics said would have hamstrung solar’s growth.

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| SolarCity

Amendment 1 received 51% of the vote, below the 60% required. It would have added language to the Florida constitution that critics said could raise fees on solar users and inhibit competition with utility solar.

Current state law already allows homeowners to own or lease solar panels. By inserting Amendment 1 into the constitution, it would be harder for legislators to change it. But it also would have added new fees on rooftop solar owners, saying that “consumers who do not choose to install solar are not required to subsidize the costs of backup power and electric grid access to those who do.”

The bill also would have inhibited third-party solar panel leasing.

The campaign may have been turned by the disclosure by the Miami Herald last month of a leaked audio recording in which one prominent supporter of Amendment 1 is heard saying it was “political jiu-jitsu” — a seemingly pro-solar measure that in fact would “negate” solar advocates’ work.

The Orlando Sentinel reported that FPL, Duke Energy and Gulf Power, a Southern Co. subsidiary, spent $25.5 million to promote the amendment.

The utilities, which also contributed at least $9 million to legislative campaigns and Gov. Rick Scott this cycle, may seek relief from current net metering rules from the legislature or state regulators.

Washington

Washington state voters rejected Initiative 732, which would have created the first state carbon tax in the U.S. The measure won only 42% support after a dispute between two environmental groups over its impact on poor communities.

The measure would have charged a tax that would begin at $15/ton beginning in July 2017, rising to $25/ton a year later and 3.5% plus inflation annually until it reached $100/ton. The tax would have allowed a cut in the state sales tax from 6.5% to 5.5%. The top five contributors to the opposition campaign reportedly included Puget Sound Energy.

Nevada

Nevada voters approved an initiative to break up NV Energy’s monopoly and create retail choice. The Energy Choice Initiative was primarily backed by large companies that have been blocked by high exit fees from seeking cheaper options, data center company Switch and the Las Vegas Sands casino company among them. The initiative must be approved again in 2018 to amend the state constitution.

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Storage Won’t End RMR Generators, FERC Panelists Say

By Rory D. Sweeney

WASHINGTON — Despite its virtues, energy storage won’t eliminate the need to pay unprofitable generators to continue operating for grid support, speakers said in the second panel of FERC’s technical conference on storage Wednesday.

In its notice of the conference (AD16-25), FERC noted that storage resources are modular and easily transportable — meaning they could provide local voltage support in situations that would otherwise result in contracts with generators as reliability-must-run (RMR) or system support resources. Building transmission to alleviate such problems following a plant retirement often takes years.

But grid operators questioned whether storage will be a cheaper option.

Hsia | © RTO Insider
Hsia | © RTO Insider

“It’s going to be very difficult for any new resource to compete with [a generating plant] that’s already essentially heavily depreciated,” said Neil Millar, CAISO’s executive director of infrastructure development. “I just think we need to be realistic about expectations.”

Eric Hsia, PJM’s manager of performance compliance, was also skeptical. “I totally agree that markets for storage are good things and what we should be focused on, but we know these RMRs are going to continue to get done and they’re not going to go away necessarily,” he said.

Representatives of CAISO, PJM and NYISO said they all recover RMR contract costs in the zones that will eventually pay for the necessary transmission upgrade and not as part of region-wide transmission rates.

Lead Time

Capp | © <em>RTO Insider</em>
Capp | © RTO Insider

Witnesses also questioned whether storage could be implemented quickly enough to replace RMRs.

Capacity Performance units in PJM are required to give three years’ notice in advance of retirements, but non-CP units only need to give 90 days.

That might not be enough time to get storage in place, said Bill Capp, president of Grid Storage Consulting.

Millar said nine months is the fastest deployment he’s seen and that included several implementation teams working in parallel. “If we’re talking a smaller battery storage project, like sub-transmission, the ability to interconnect that project more quickly is higher,” he said, but for larger installs, “months is very tight.”

DeSocio | © RTO Insider
DeSocio | © RTO Insider

He said CAISO is identifying areas where future retirements will likely create reliability issues and is developing plans to address the potential.

Michael DeSocio, senior manager of market design for NYISO, said running a competitive process for such situations “extends the timeframe … because it’s going to take us longer to go through all the projects to figure out reliability and sufficiency and what we can deal with.”

“Not a bad idea,” DeSocio added. “Just it will add time to the process.”

Little Experience

Millar | © <em>RTO Insider</em>
Millar | © RTO Insider

Grid operator representatives acknowledged they haven’t had much experience with such projects. Millar was the only one who provide an example, saying about 110 MW of storage will be used to respond to the closure of the Aliso Canyon natural gas storage facility. “That was probably the most expedited procurement of storage we’ve seen,” he said.

The California Public Utilities Commission ordered the procurement in August, and projects are required to be completed by Dec. 31.

Part of the issue, developers said, is that the grid operators aren’t prepared to handle the flexibility of storage, so developers haven’t made the effort to propose projects.

Fernandes | © RTO Insider
Fernandes | © RTO Insider

“I think generally speaking, most of your ISOs/RTOs right now have an open-mindedness toward storage as a non-transmission alternative,” said John Fernandes of Renewable Energy Systems Americas. “Not everyone might be far enough along to do the complex modeling that’s needed to optimize the system. … I think there’s possibly a little bit of a disconnect between ‘sure, we’ll go in to take a look’ and ‘yes, we will actually deploy this.’ Until the developer community has some level of certainty that there is at least some likelihood that non-transmission alternatives will be selected, it’s hard for us to justify spending the time, the resources, the effort to really put together viable projects.”

Getting the Green Light

Storage isn’t likely to get special consideration from operators. “Looking at all the variables, if energy storage meets that cost, the lowest methodology, that’s fine if we go with energy storage. But if some other technology can meet the same solution at a lower cost, then we would favor that,” said Charlie Bayless, of the North Carolina Electric Membership Corp., who represented the National Rural Electric Cooperative Association.

Bayless (left) | © RTO Insider
Bayless (left) and Burwen | © RTO Insider

“A competitive process is of interest if we can, one, agree on a manner in which it is able to happen expeditiously, but also two, we should be looking at this as a manner that is in fact adding value by reducing the costs of this particular solution to the system,” said Jason Burwen of the Energy Storage Association.

“We’re looking to compete at cost with all the other resources being considered,” Fernandes said. “[We’re] not looking to shoulder ratepayers with a neat little experiment here. We’re justifying this in front of regulators everywhere.”

However, storage needs to be able to serve multiple functions to make it economical, he said. The single RMR revenue stream is insufficient. “I might also want to participate in the real-time market at certain times,” he said.