Page 1441 – RTO Insider

December 7, 2017October 31, 2023

ISO-NE Preparing for Energy Storage Growth

By Michael Kuser

ISO-NE is working to ensure that its wholesale markets can accommodate an expected exponential growth of energy storage resources, an RTO manager said Tuesday.

“We want to be sure that our wholesale markets are favorable to all resource types equally, so when we think about energy storage, we want to make sure it fits in the box,” Carissa Sedlacek, ISO-NE director of market development, said during a Dec. 5 energy storage seminar hosted by the Northeast Energy and Commerce Association in Boston.

iso-ne energy storage wholesale electric market

| ISO-NE as of December 1, 2017

With 20 MW of energy storage already interconnected in ISO-NE and nearly 80 MW in the interconnection queue, the RTO is adjusting some of its market rules to accommodate the new and flexible resources coming online, Sedlacek said. (See ISO-NE Plans for Hybrid Grid, Flat Loads, More Gas.)

“How is that energy storage facility going to operate?” Sedlacek said. “Is it going to operate at full capacity for one hour, or is it going to operate at quarter-capacity for four hours? How is it going to respond if it’s coupled with wind or solar? Is it going to be there for longer durations? Is it going to be used more in the winter than in the summer? These are the types of questions we ask in the planning department as we consider new resources, especially something like energy storage.”

Spreading the Risk

ISO-NE predicts energy storage providers will largely focus participation in the RTO’s ancillary services market because many of them are not prepared to assume the financial burden of qualifying for the Forward Capacity Market (FCM) — or to confront the risk of coming up short on a capacity supply obligation (CSO), Sedlacek said.

| ISO-NE

“If you get a megawatt CSO that you cannot achieve, there will be a financial penalty,” Sedlacek said, noting that penalties go into effect June 1, 2018, leaving some storage developers “a little gun shy” about offering into the FCM. She noted that solar and wind participants in the FCM don’t typically attempt to qualify for their nameplate capacity, but only a percentage of nameplate (usually 40 to 42%) to ensure their obligation is achievable.

“Because under the [FCM], you’re on the hook to provide those megawatts,” she said.

Sedlacek explained how energy storage developers might hedge their risk by pursuing incentives offered for over-performing in the FCM.

“So you can figure out what your output would be over a four-hour period, because that’s what you have done analysis on and you think might actually last for a shortage of that [capacity amount],” she said. “That’s the megawatts you want to actually take on as the CSO, but be happy to take on additional megawatts or have more output on real shortage events, days or hours, and kind of scoop up the additional revenue.”

Wholesale Market Revenue

ENGIE subsidiary Green Charge Networks recently signed a 20-year agreement to supply Holyoke Gas & Electric with power from the first combined solar and storage project in Massachusetts, according to Jonathan Poor, Green Charge’s director of business development. While the 5-MW solar farm on the site of the retired coal-fired Mount Tom Station in Holyoke is currently in operation, the 3-MW battery will interconnect around May 2018, Poor said.

The storage project is particularly suited to organized markets in New England and New York because it will help firm up output from the solar farm and reduce capacity costs, he said.

“We see, at least in New York ISO and ISO New England, some of the business case coming from wholesale market revenue,” Poor said.

Future solar projects will likely include storage in the interconnection request, given the value of storage, he said.

“We appreciate how holistic the [Solar Massachusetts Renewable Target] program is in Massachusetts for energy storage, and we see a real opportunity to deploy solar and storage and are looking for repeatable use cases that we can scale,” Poor said.

Massachusetts Programs

Massachusetts Clean Energy Center CEO Stephen Pike said that most people know the state’s 2016 Energy Diversity Act for its solicitation for 9.45 TWh of clean energy, but the legislation also included an energy storage mandate, leading the state’s Department of Energy Resources earlier this year to set a 200-MWh storage target for 2020.

While some industry participants considered that goal to be less than ambitious, Pike said there were only 2 MW of storage deployed in Massachusetts when the department began preparing its 2016 State of the Charge report and 4 MW by the time of publication. (See Massachusetts Underwhelms with 200-MWh Storage Target.)

The state’s $10 million in grant funding from its Energy Storage Initiative spurred nearly 70 proposals for storage demonstration projects, Pike said, hinting that awards could be announced within a couple of days.

Richard Stuebi, president of Future Energy Advisors, said improving economics is driving the energy storage market.

“Batteries were $1,000/kWh a few years ago, and now they’re $300/kWh,” Stuebi said. “And, alongside declining cost of batteries, largely driven by the growing market demand for electric vehicles, the costs of all the other components of a complete energy storage system — inverters, control systems and racks — are falling too.”

| MOR-EV

Most of the 700 MW of energy storage currently deployed in the U.S. is utility-scale, and California dominates with 60% of the installed base and a mandate for nearly 2 GW in storage to be operational by 2020, Stuebi said.

But even places like Florida and Michigan, which Steubi hadn’t initially considered promising areas, could get interesting pretty quickly for behind-the-meter storage applications, he said.

December 7, 2017January 31, 2024

EUCI Panelists: Midwest Tx Plans Must Address Wind, Seams

By Amanda Durish Cook

INDIANAPOLIS — Two topics dominated the discussion this week among industry leaders, RTO officials and transmission planners attending EUCI’s Transmission Expansion in the Midwest conference.

One: The region must focus its transmission expansion efforts on moving wind output from vast resource areas in the west to population centers in the east.

And two: To support that effort, industry participants must overcome ineffective interregional processes among RTOs.

“You’ve got a lot of cheap wind resources where not a lot of people are — Minnesota, the Dakotas, Iowa — and you have to get this clean, affordable energy to where the people are,” Betsy Beck, director of transmission policy for the American Wind Energy Association, said during a Dec. 4 panel discussion. “There’s not enough transmission capacity to move it east where it’s needed.”

Beck said 35 GW of wind capacity is expected to come online in the U.S. by the end of 2020, joining the nearly 85 GW of current wind capacity. She noted that 20-year power purchase agreements are being signed in the Great Plains for less than $20/MWh.

Adam McKinnie, chief economist with the Missouri Public Service Commission, said he has observed a pattern of central states trying to push wind energy toward eastern states where power is more expensive. The eastern states, in turn, claim they can solve their resource adequacy and public policy goals by building new generation and won’t need the imports.

“How do you solve that?” McKinnie asked.

“That’s kind of the million-dollar question,” Beck laughed. “D.C. and the East don’t have a lot of space in their backyards for renewable development, and I think these states are starting to realize that.”

MISO interregional adviser Adam Solomon said the RTO’s 2018 Transmission Expansion Plan will include a new study on the impacts of renewables while also focusing on wind development needs and seeking to predict where future projects are likely to be sited. “We’ll try to find the trend within our footprint and better predict how that’s going to move in the future,” he said.

Seams and Order 1000

An effective wind transmission network in the Midwest will require interregional projects, conference panelists agreed.

Over the past year, MISO has worked with both PJM and SPP to identify large interregional projects, but the two separate efforts failed to produce a viable candidate after identifying just two serious contenders. (See MISO Confident in Tx Process with SPP Despite Lack of Projects.)

“Interregional projects have remained elusive,” Solomon said.

PJM Manager of Interregional Planning Chuck Liebold said MISO and PJM will try again next spring to identify a large interregional project, commencing another two-year coordinated system plan between the RTOs. Officials from both RTOs last week announced that the next Order 1000 project submission window will open in November 2018.

“All that study, hours and hours of analysis, and we have yet to pass a big interregional project,” Liebold said. “We have 200-something joint coordinated flowgates on the MISO-PJM seam. … It seems like there’s a natural area where there could be joint coordination on a project, but that hasn’t happened yet. There are some issues with our process that we keep ironing out over the years.” He also reminded attendees that “there’s no measuring stick that says you have to have an interregional project.”

“I don’t think people understand how jagged the seams are,” McKinnie said.

“I think it’s safe to say that meeting the goals of Order 1000 so far today have been elusive,” said Alan Meyers, ITC Holdings director of regional planning.

Order 1000 has failed to “uniformly encourage” transmission development and may actually be stifling it, he said. “I think there’s a tendency to focus on the competition rather than the planning and cost allocation. The competition is only the sizzle, but the planning and cost allocation is the steak.” ITC has transmission holdings in MISO, PJM, SPP and NYISO.

Meyers criticized RTOs’ past “arbitrary” cost allocations and voltage thresholds on interregional projects but said practices are improving. He said that while RTOs excel at regional transmission planning, they come up short when trying to plan interregional projects. “It may be the biggest area we can improve on,” he said.

Some audience members asked about the next steps for the $2.3 billion Grain Belt Express, a 780-mile HVDC transmission line that would move wind energy from the Midwest to eastern markets. Developer Clean Line Energy Partners last week asked the Missouri Supreme Court to review state regulators’ decision to refuse a development permit. The Grain Belt Express did not result from an RTO process and is not seeking cost allocation.

Mark Lawlor, Clean Line’s vice president of development, said that while SPP and MISO are creating small west-to-east lines, those projects don’t go far enough — literally.

“They’re needed, but they’re not connected. There’s failure to create a process that allows for interregional projects such as the one Clean Line is developing. There’s not a place for us. … Perhaps that’s for Order 1001,” he joked. “I don’t want to say this hasn’t gone right, but there’s no mechanism to facilitate these projects.”

Lawlor added that Order 1000 is still young and “really only created competition for a fraction of the transmission projects out there. There could be more room for competitive projects.”

TMEPs

MISO and PJM are poised to approve a five-project interregional portfolio this year, but it doesn’t contain the extended HVDC lines for which some in the industry had hoped.

This month, the RTOs’ boards of directors are expected to individually approve their targeted market efficiency project (TMEP) portfolio, composed of smaller, congestion-relieving interregional projects. PJM and MISO worked for three years to define the project type before getting FERC approval this year. (See FERC Conditionally OKs MISO-PJM Targeted Project Plan.)

All five TMEP projects this year are upgrades to existing systems. The projects, which have individual $20 million cost caps, will coincidentally cost $20 million combined.

On average, project costs will be allocated 69% to PJM and 31% to MISO, based on projected benefits, which are expected to reach $100 million.

“I think what MISO and PJM have done with TMEPs is prove that they can get something done. And I hope they’re not too discouraged that they don’t yet have a large interregional project,” Beck said.

However, Beck maintains that large, public policy interregional projects are going to be vital for the future of the Midwest, but unwieldy seams criteria and differing public policies will hold them back. “By having different rule sets, they create a lot of impediments,” she said.

“A lot of consensus will be needed,” Solomon said.

“As soon as they solve public health care, they’ll start in on public transmission policy,” Liebold joked.

“In the future though, we need to really look at what the Eastern Interconnect looks like and how we can move large amounts of power,” Beck said. She predicted that a handful of new HVDC lines will begin to take shape in the next few years, with others to follow.

“There’s a lot of folks out there that also think that microgrids are the wave of the future, and we don’t need any more transmission projects, and we should begin to take lines down, so I’m not betting just yet,” Liebold said.

McKinnie asked why MISO and SPP haven’t created their own TMEP process to deal with smaller congestion issues along their seam. Solomon said the TMEP process was largely driven by Northern Indiana Public Service Co.’s 2013 complaint against the MISO-PJM interregional planning process, but that MISO would like to implement a similar smaller interregional project type with SPP.

“So if I went back to commission and said the ‘squeaky wheel gets the grease,’ would that be correct?” McKinnie asked.

Solomon said that SPP is a relatively young RTO with less historical data, and while he thinks some SPP stakeholders might not be ready for such a cross-seams project type, he is hopeful they will be convinced of the benefits by observing the progress between MISO and PJM.

“I don’t want there to have to be a FERC complaint for this to get attention. We used to joke that the MISO stakeholder process was a FERC comment period. … We sometimes feel that we’re the kid sibling over on the SPP-MISO seam,” McKinnie said.

Bob Pauley, chief technical adviser with the Indiana Utility Regulatory Commission, urged gentler treatment of RTOs that must plan transmission systems with sometimes limited information.

“I don’t know of any empirical evidence where an RTO developed transmission where there was a better option available.

“I think it behooves us to remember the time before RTOs,” he reminded attendees, before adding jokingly, “When I worked with Thomas Edison and others, each utility had to plan their own needs as if they were an island.”

Pauley said “everyone would be better off” if utilities used the same degree of candor with RTOs as they do with their respective state regulatory bodies. He also said states should take a more active role in forecasting load.

Wind Catcher

American Electric Power’s Raja Sundararajan said his company’s $4.5 billion Wind Catcher project in Oklahoma is also bypassing the RTO transmission planning process in favor of self-funding to ensure it is realized. The project includes what will be the largest wind energy facility in the U.S at 2 GW and a dedicated 350-mile, 765-kV tie-line from the panhandle to Tulsa.

“This is the largest investment AEP has ever made; $4 billion is a massive amount, and we understand that,” Sundararajan said. He pointed out the project circumvented the RTO process because AEP did not have enough time to mount a complex transmission planning process for an expensive 765-kV line before wind production tax credits expire in 2020.

AEP settled on a 765-kV rating because it minimizes transmission line losses and doesn’t require converters, he said. Although AEP has not yet established a preferred route, most of the 350-mile stretch is located on farmland in Oklahoma, Arkansas, Louisiana and Texas. The company is planning to use 25-year extendable land leases with landowners. Regulatory approval is needed in all four states, which AEP hopes to obtain by April.

“Are we the only ones doing this? No. Especially in the Midwest, wind farms are so economical, especially for the ratepayer,” Sundararajan said, pointing to current wind projects by Public Service Company of Colorado, Northern States Power, Southwestern Public Service, MidAmerican Energy, PacifiCorp and Empire District Electric.

One audience member asked how AEP balances the massive wind project with apparently competing support for coal and nuclear subsidies.

“I’m not aware of it. I’m a transmission guy,” Sundararajan replied.

December 7, 2017

DOE: German Energy Struggles Sparked NOPR

By Rory D. Sweeney

PHILADELPHIA — The U.S. Department of Energy’s proposal to save coal and nuclear generating plants is intended to avoid a repeat of Germany’s energy woes, Under Secretary Mark Menezes told a PJM General Session on Wednesday.

DOE NOPR nuclear power German Energy — PJM’s Craig Glazer moderated the first panel at the PJM General Session, featuring FERC Commissioner Rob Powelson, DOE Undersecretary Mark Menezes and Jason Stanek, senior counsel for the House Energy Subcommittee. | © *RTO Insider*

Menezes recounted an international energy meeting this spring, where he said Energy Secretary Rick Perry and Secretary of State Rex Tillerson listened as German officials recounted economic hardships created after the country renounced nuclear power following the 2011 Fukushima nuclear disaster. To mitigate the price spikes, Germany built plants to burn lignite, a lower-quality coal than the traditional anthracite used at most coal-fired facilities.

“They are digging up lignite all over Germany. I have nothing against lignite, but you’ve got to dig up an awful lot of lignite to get the BTU content to produce [power],” Menezes said.

He said German officials told Perry: “If in fact you believe in what you’re saying in [using] ‘all of the above’ [energy resources], please stick to ‘all of the above.’ Try to avoid what happened here.”

FERC Commissioner Robert Powelson, speaking after Menezes, said PJM looms large in his deliberations on DOE’s Notice of Proposed Rulemaking. The NOPR called for additional compensation for “fuel-secure” power stations that sell electricity into organized energy markets and maintain a 90-day fuel supply.

“I think [the commissioners are] working constructively to put forth a potential solution and really work with our RTOs around problem-solving. … We’ll be able to address this issue in a way that, as I said, respects the balance within the organized markets … continues to deliver the value proposition of these organized markets” and maintains a balanced resource portfolio.

He said he discussed the issue with Perry and guaranteed an eloquent solution.

“I said to him, ‘I took high school calculus,’ and he said, ‘I didn’t.’ But, I said, ‘I hopefully can solve this one.’ … I’ve been in this rodeo long enough. I know how to calibrate and make decisions, and those decisions will be defensible.

“We are now seeing what we never thought we’d see, and even Democratic DOE secretaries have admitted it,” Powelson continued. “We’re seeing nuclear plants close, and we’re seeing them close at a rapid pace. And we’ve got to look at those issues. … I agree with the secretary when he says these markets aren’t pure. … As a state commissioner, I didn’t understand that back then until Mark gave me this homework assignment.

“I sat through plant closure announcements; it’s not a fun thing,” he added. “You’re going to see more state interventions. Get ready.”

Jason Stanek, senior counsel for the House Subcommittee on Energy and a former FERC staffer, said the committee isn’t planning a hearing on the issue, but it’s “looking forward to [FERC’s] thoughtful and deliberative process.”

“We have yet to have a hearing on that topic, and it’s one that has split our members not necessarily by party but by region,” he said. “They recognize that the entire industry is in a state of flux right now.”

Powelson also announced that incoming FERC Chairman Kevin McIntyre would be sworn in Thursday at 10 a.m.

“Tomorrow, we’ll have five” commissioners, he said. He added later that he did not know how that would affect FERC’s decision on the NOPR.

“If I knew, I would tell you. I’m usually very candid,” he said.

McIntyre’s arrival beats — by one day — the 120-day deadline before interim Chairman Neil Chatterjee could start appointing FERC staff.

Menezes also suggested that FERC might miss DOE’s requested deadline for a decision by one day.

“I think we have a big deadline you gave us; Dec. 11?” Powelson said to Menezes.

“I understand FERC may have a different date, maybe the 12th,” Menezes replied.

“The 12th? ’Tis the season,” Powelson responded.

December 6, 2017

FERC Claims Jurisdiction on EE, OKs Ky. Opt-Out

By Rich Heidorn Jr.

FERC has waded into yet another state-federal jurisdictional dispute, claiming “exclusive authority” over the participation of energy efficiency in wholesale markets but preserving a carveout it approved earlier for Kentucky utilities.

The commission’s ruling came in response to Advanced Energy Economy’s request for a declaratory order on FERC’s authority over energy efficiency resources (EER). AEE, which represents companies such as General Electric, Nest and Johnson Controls, filed the petition in June after the Kentucky Public Service Commission ruled that retail customers cannot participate in any PJM wholesale market without the state’s permission.

The PSC’s order was in response to a filing by East Kentucky Power Cooperative, which said it was buying more capacity than needed because of providers bidding EER products from its service territory into PJM’s capacity auction.

wholesale markets energy efficiency ferc kentucky utilities — | *Enervee.com*

AEE’s concerns focused on third-party EERs, such as those created when an aggregator contracts with the manufacturer and retailer of high-efficiency appliances, light bulbs or heating and cooling systems.

FERC energy efficiency — | *Enervee.com*

FERC sided with AEE, saying the commission “has exclusive jurisdiction over the participation of EERs in wholesale markets,” and that relevant electric retail regulatory authorities (RERRAs) “may not bar, restrict or otherwise condition the participation of EERs in wholesale electricity markets unless the commission expressly gives RERRAs such authority.” Commissioner Richard Glick, who was sworn in Nov. 29, did not participate in the Dec. 1 order (EL17-75).

PJM Integration

However, FERC said it would honor its 2004 order approving Kentucky Power’s integration into PJM, which granted the utility the right to prevent its customers from participating in the RTO’s demand response or load interruption programs. The opt-out stipulation was later extended to Duke Energy Kentucky and EKPC when they joined PJM.

FERC rejected opponents’ claims that AEE’s petition was premature. “We agree with AEE that the novel issues of federal and state jurisdiction presented here warrant commission guidance,” FERC said, noting that PJM also asked the commission to weigh in.

The commission also said that FERC Order 719 “does not provide for a RERRA to exercise an opt-out and bar or restrict the sale into the wholesale electricity markets of EERs originating in their state or local area.” The 2009 order required RTOs and ISOs to permit aggregators to bid DR on behalf of retail customers directly into the grid operators’ markets unless the RERRA bars participation by retail customers.

“Although in Order No. 719 and Order No. 745 the commission granted RERRAs an opt-out from allowing resources to participate as wholesale demand response, we find that the commission was not obligated to do so,” FERC said, citing the Supreme Court’s 2016 ruling in FERC v. Electric Power Supply Association. The EPSA ruling upheld Order 745, which required RTOs to pay DR the same LMPs as generation. (See Supreme Court Upholds FERC Jurisdiction over DR.)

The commission also said the effects of EER participation on the retail markets “are not substantial.”

“Unlike demand response resources, EERs are not likely to present the same operational and day-to-day planning complexity that might otherwise interfere with [a load-serving entity’s] day-to-day operations. Even if PJM’s add-back mechanism failed to ensure that an LSE’s procurement obligation was unaffected, we agree with AEE that any such impacts should be addressed through PJM’s tariff provisions and not through a broad prohibition on EER participation in wholesale markets.”

But FERC said it was “appropriate” to allow the Kentucky opt-out “as a longstanding agreement relied upon by the parties and entered into prior to the clarification of jurisdiction over wholesale demand-side management in EPSA and this order.”

The commission said although some EERs originating in Kentucky have cleared in PJM capacity auctions, “we find that any necessary market changes should be implemented in a manner that does not require changes to the [auction] results.”

The commissioners declined to state the requirements they would impose in the future if a retail regulator seeks to restrict third-party EER sales.

Back to the Courts?

The Supreme Court has issued three rulings interpreting state-federal jurisdiction under the Federal Power Act since 2015. The commission’s preservation of the carve out would seem to foreclose a court challenge by Kentucky regulators. But it’s no guarantee that other states lacking such agreements won’t seek to overturn the ruling. (See Court’s Reticence Frustrates Energy Bar.)

AEE nevertheless praised FERC’s ruling as a “win for advanced energy innovators and consumers alike.”

FERC’s assertion of jurisdiction “is critical for maintaining free and open competition, with all technologies competing on price and performance,” the group said.

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.

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 forced 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. 9 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.)

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.