CAISO’s congestion revenue rights market showed unusual surpluses this summer because of higher congestion rents on Path 26, a major transmission line leading into Southern California.
In particular, there was a roughly $50 million surplus in August with sizable surpluses in July and September as well.
A CAISO forum addressed market performance and planning Wednesday. | CAISO
Deficits in the CRR market were far more typical than surpluses in 2017 and 2018. The atypical CRR revenue adequacy in August and September was one of the more notable revelations in CAISO’s Market Performance and Planning Forum on Wednesday.
“The main reason for the CRR surplus was congestion on Path 26,” said Rahul Kalaskar, the ISO’s manager of market validation analysis.
Kalaskar said there were high flows north to south this summer because of higher temperatures and gas prices. That led to higher energy prices and more expensive congestion pricing, boosting overall congestion revenues.
“The main reason for this high congestion is you had high gas prices, and there were some days where you had local outages,” Kalaskar said.
Western wildfires — and the threat of wildfires — created market uncertainty and contributed to higher prices, he said. Exceptional dispatches (out-of-market operations to ensure adequate generation) spiked in July and August in the ISO’s territory but diminished as the threat of fire and higher loads passed.
Other findings showed integrated forward market prices (which include day-ahead prices) in July and August spiking well above those in real time, but September saw a return of normal patterns. CAISO price correction events stayed high in August and September and Energy Imbalance Market-related price corrections surged in September too.
MISO and SPP could jointly create a smaller category of interregional transmission projects as early as next year to address costly congestion, the RTOs said Tuesday.
But the RTOs have not reached any decisions on the issue and will spend at least part of next year evaluating the effectiveness of a smaller project type to address historical market-to-market congestion, according to RTO staff speaking at an Oct. 23 MISO-SPP joint stakeholder meeting.
MISO Planning Adviser Davey Lopez said the projects could be any voltage and include tie-lines and interconnections or transmission projects wholly contained within the footprint of either RTO.
MISO said potential criteria could limit project costs to less than $20 million and require an in-service date of within four years of approval. The RTO is also suggesting that projects must pay for themselves within four years based on congestion savings. MISO is proposing to measure a project’s future congestion relief benefit against two years of historical congestion prior to the project study.
The criteria closely resemble those of MISO-PJM targeted market efficiency projects (TMEPs), created in 2017, which must cost less than $20 million, cover their costs within four years of service and be in service by the third summer peak from approval.
The RTOs cite high-priced congestion on market-to-market flowgates as the reason for creating a new smaller project type. Lopez said SPP’s Riverton-Neosho-Blackberry flowgate in Missouri may be ripe for such a project after costing MISO $18 million in congestion in 2017 and $9 million so far this year. Its congestion has been chronically expensive since the RTOs created it in 2017. (See “MISO M2M Payments to SPP Exceed $50M,” SPP Seams Steering Committee Briefs: May 2, 2018.)
“We’re getting close to $30 million on that particular flowgate in the last few years,” Lopez said.
He said new, smaller projects aimed at congestion relief are needed because the RTOs’ longer-term transmission planning process misses quicker transmission upgrade solutions.
But some stakeholders said congestion could be better solved by administrative means between the two RTOs rather than transmission buildout.
Lopez promised a “deeper dive” into the causes of congestion as part of the exploration into the project type. “As part of the process, it will cause MISO and SPP to look into the causes of congestion and if it will persist,” he said.
Early this year, Entergy argued that the MISO-SPP seam does not yet have a structured enough coordination process to develop smaller interregional projects. (See “Entergy Critical of MISO-SPP TMEP,” MISO, SPP Look to Ease Interregional Project Criteria.)
Other stakeholders called for more than two years of congestion data to justify creating a new project type, and staff from both RTOs said they will continue to collect flowgate data. Lopez said MISO plans to investigate individual flowgates and speak with transmission owners about the causes of congestion, much like it did in this year’s round of TMEPs.
MISO and PJM have so far recommended seven TMEPs, five of which received approval in 2017, with the other two up for approval this year. The projects are expected to cost under $25 million and reap about $132 million in benefits. (See MISO, PJM Endorsing 2 TMEPs for Year-end Approval.)
But some stakeholders contend that at least some of the market-to-market congestion issues can be traced to the RTOs’ separate interconnection procedures that don’t fully study how new generation projects will affect flowgates before granting grid access.
MISO and SPP current generation queue projects | SPP, MISO
Stakeholders have called for increased coordination in generator interconnection procedures, but the RTOs say they already study for impacts on each other’s systems and facilities in their affected-system study process and that interconnection staff currently meet face-to-face twice a year and hold monthly conference calls.
LITTLE ROCK, Ark. — SPP staff are dialing back an ambitious proposal to beef up the analysis behind generator retirements, promising to take “baby steps” in designing a “holistic process” in the face of stakeholder pushback.
Casey Cathey, who will soon become SPP’s manager of reliability planning, recently promised the Strategic Planning Committee that staff would focus on the “technical aspects” of evaluating generator retirements, saying he wants the issue to be an official item before the Markets and Operations Policy Committee.
“We want to show some traction,” Cathey told the SPC on Oct. 18. “What we really want is an overall process, so people can rally around it and say, ‘This is what we really want to do.’”
Quite the opposite happened when Cathey shared his proposal with the MOPC and SPC earlier this month. Stakeholders reacted negatively to the potential use of reliability-must-run contracts and involving SPP’s Market Monitoring Unit in the evaluation process.
SPC Chair Mike Wise, who told RTO Insider he was surprised by the presentation, was emphatic as he complained about the potential use of RMRs and having to possibly pay other generators’ fixed costs.
“This is a real reach in strategy and dangerous from my point of view,” said Wise, Golden Spread Electric Cooperative’s senior vice president of regulatory and market strategy.
“This could blow this up into a massive issue,” American Electric Power’s Richard Ross said during the MOPC discussion. “I encourage you to walk before you run.”
Cathey took Ross’ advice, saying staff would rely on an in-house white paper to flesh out the RMR process by creating a business practice and revising the Tariff.
“We’re not going to address the RMR contracts or the settlement aspects of fixed costs,” Cathey said. “We’ll get down to the technical aspects of how we figure out this thing. We’ll back this up a little bit.”
The Board of Directors and Members Committee is not scheduled to resume the discussion during their Oct. 30 meeting.
Staff brought the issue before their governance groups, saying an aging fossil fleet has increased the possibility of retirements in SPP’s footprint. Noting that retirements are evaluated in multiple processes with limited coordination, staffers said they want to ensure the RTO has an opportunity to study retirements and any resulting mitigations before the actual retirement date.
SPP generation requirements statistics | SPP
More than 4.1 GW of generation has been retired in SPP’s footprint since 2010, but another 2.4 GW is scheduled through 2019, and staff said they are beginning to see ad hoc studies on other potential retirements. Cathey said 77 different resources have been manually committed for reliability purposes, with the longest commitment for 74 days.
“The only mechanism we have right now is to run the resource,” he said. “You guys would not be properly compensated. Any costs you would incur are not included in our Tariff.”
Best Practices
While staff are proposing planning and operations assessments for retiring units, it was the MMU’s evaluation that drew most of the stakeholder feedback. The Monitor wants to guard against market power issues, focusing its analysis on whether the retirement would result in a scarcity of generation capacity or amount to an uneconomic decision indicating physical withholding behavior.
Executive Director Keith Collins said the MMU will review both technical and economic justifications, looking at the unit’s age and possible state or federal environmental requirements that might force it to retire.
Collins also said the Monitor would intervene, if necessary, in retirement applications before regulatory bodies.
“I’m not comfortable with you testifying as an intervenor in our state cases,” Southwestern Public Service’s Bill Grant said. “I have a lot of concerns with what you’re proposing.”
“My expectations are it would be a dialogue. If there’s a difference of opinion, we would talk about concerns before reaching the point where we’re talking to the state or other regulatory bodies,” Collins responded. “What makes the Market Monitor unique is that we have a particular view no one else does, including the states. It gets to the concept of a structural market issue, where your resource could create market power.”
The MMU’s proposed analysis would rely on a going-forward cost that measures avoidable costs if a generator is retired or mothballed. Going-forward costs include mandatory capital expenditures due to any environmental, safety or reliability requirements, fixed operating and maintenance costs, and property taxes, if applicable.
The Monitor plans to use going-forward costs to help determine whether a generator’s net market revenues cover enough expenses to allow it to operate as long as it financially should.
“The two questions we would ask are, one, does [the retirement] create undue market power, and two, is the retirement economic?” Collins said. “If we have a serious enough issue that comes up as a part of this process, we’ll do what we have to do. We would be questioning the economics. The reality is, we’re reaching out to state commissions and talking about these issues already.”
Collins said the concept is nothing new for Monitors, noting NYISO has a similar process and uses expected net revenues to help determine whether to retire units or build new generation.
Cathey said the RTO would “hopefully” not identify any issues in the process and instead allow a resource to retire.
“We looked at every other ISO in the U.S. This has been crafted on best practices,” Cathey said. “If you’re coming to us to retire, you’ve largely done your own homework. We don’t want to be a barrier to that. If we find something because of the way we operate, we would execute an RMR.”
“My members, my board, [do not] want to pay for fixed costs of other generators in the market,” Wise said. “We don’t have a capacity market; we have a capacity requirement. I pay for my fixed costs; I pay for my fixed requirement. We don’t pay for each other’s fixed costs. This would be a real shift for SPP and problematic for many consumers.”
“Let’s be realistic,” Cathey said. “We’re not looking to circumvent any state authority. RMRs are really a last resort.”
Cathey said staff will continue discussions with several stakeholder groups and begin development of a revision request. SPP plans to return to the MOPC in January with draft revisions.
SOUTHINGTON, Conn. — Battery storage, energy efficiency and offshore wind dominated the discussion at the Connecticut Power and Energy Society’s Future of Energy Conference on Oct. 24, along with the question: Who pays for all this progress?
“Storage is fascinating. Like the shapeshifter, it can do so many things,” said Katie Dykes, chair of the Connecticut Public Utilities Regulatory Authority.
The most cost-effective place to use and operate storage depends on the revenues being sought, Dykes said, noting that both a rate-based distribution plan and the wholesale energy market can provide a lot of services.
“We really need to get our distribution regulatory framework aligned with the wholesale energy market rules to knit together all those different values,” Dykes said. “Trying to get that price signal just right to help people value the benefits from these types of investments [and] doing that in a very holistic way is incredibly important.”
Anthony Marone, CEO of Connecticut-based utility United Illuminating, sees storage as working on both sides of the meter.
“Large-scale storage systems, regardless of who owns them, should be on the distribution side and controlled by the utility,” Marone said. “The stream of benefits should always be maximized for all ratepayers if they’re all paying for that.”
Marone also addressed the need to implement demand charges in planning for the increased use of electric vehicles. He noted that if EV adoption goes “through the roof,” the absence of such charges would mean utilities are “building a system and spending a lot of money where there’s no price signals that recognize that these things are having an impact on the system and everyone’s paying for it.”
Roger Kranenburg, vice president for energy strategy and policy at Eversource Energy, predicted that the coupling of electricity and transportation will change everything in the energy industry.
“The pie that we’re working on is no longer a slice of the pie; it’s the entire pie that we’re looking to modernize,” Kranenburg said. “Engineers love to complain, but they love challenges, and they usually solve them. Look at wind integration onto the system. The biggest challenge is regulators and companies working to balance who pays and who benefits.”
William Murray, vice president for state and electric public policy at Dominion Energy, which owns the Millstone nuclear plant in Connecticut, said New England’s challenge lies in becoming more dependent on natural gas as the pipeline infrastructure appears incapable of being adequately fed or permitted to expand.
Despite the industry’s success in keeping wholesale energy prices low, “we notice that customers don’t really care about the subcomponents of their bill; they want to know what’s … the total bill,” Murray said. “There are times when our residential rates in Virginia and North Carolina are very competitive with your industrial rates [in New England].”
Bill Luchon, senior manufacturing engineer and environmental leader at Hartford-based manufacturer Legrand, said energy conservation at first offers a lot of “low-hanging fruit” but then gets harder.
Legrand has reduced its energy intensity by 48.5% since it joined a Department of Energy initiative for manufacturers in 2011, “which is pretty impressive,” Luchon said.
A few years ago, the company heard about a free industrial assessment audit by DOE, “and they identified a whole bunch of opportunities, which equated to about $55,000 a year in electrical savings for things that we wouldn’t even consider,” Luchon said.
New Haven Public Schools COO Will Clark said he oversees the system’s $400 million annual budget and $1.6 billion construction program. “When I save a million dollars in energy … that essentially goes to pay for teachers and for buying the textbooks,” he said.
Renewable energy, energy savings and carbon footprint reduction are all important to New Haven residents, so good publicity helps win official support for projects, he said.
“If I can get the mayor or the superintendent on [the front page of the newspaper], I get a project put forward,” Clark said.
Mark Wick, a partner in Energy Innovation Park, a $1 billion data center being developed in New Britain, pointed out the project will feature a 19.98-MW fuel cell microgrid. “That is an industry that is very aware of renewable energy … and the amount of energy used.”
Matt Morrissey, vice president of Deepwater Wind, said Connecticut “punched substantially above its weight” in the first round of procurement for offshore wind.
Connecticut officials in June announced they will purchase 200 MW of output from Deepwater’s Revolution Wind project, adding to Rhode Island’s 400-MW procurement. (See Conn. Awards 200-MW OSW, 50-MW Fuel Cell Deals.)
As a result of drafting behind larger procurement processes in Massachusetts and Rhode Island, Connecticut obtained a 600-MW price for 200 MW of offshore wind and was also able to leverage Deepwater’s investment criteria, Morrissey said.
“On a job-per-megawatt-hour basis and investment-dollar-per-megawatt-hour basis, [Connecticut] actually beat both Rhode Island and Massachusetts,” Morrissey said. “Very savvy indeed for the state to do what they did.”
Deepwater will file for the procurement in the next few weeks, and the details will be public, Morrissey said.
Peter Shattuck, vice president for special situations at transmission developer Anbaric, said, “There are not a lot of great interconnection points to land 10 GW of new resources on the Eastern seaboard … so we have to think about how many lines we want to be stringing across the ocean floor.”
There is a potential to oversize the transmission grid in anticipation of the new resources and minimize the number of times needed to go through the complex planning process, he said. (See Anbaric Pushes Offshore Grid Plans.)
“The best economic results are where you plan for the wind, as in Texas … which has allowed them to put as much wind in their one state as we have all generating capacity in New England,” Shattuck said. “We know there’s a lot of offshore wind in Maine, but it’s not a big part of the mix right now. Why? Because we don’t have the transmission.”
President Trump announced Wednesday that he has appointed FERC Commissioner Neil Chatterjee to replace Chair Kevin McIntyre, who stepped down citing a “serious setback” in his battle with a brain tumor.
McIntyre said he would remain on the commission but would relinquish the chair’s role “and its additional duties so that I can commit myself fully to my work as commissioner, while undergoing the treatment necessary to address my health issues.”
McIntyre’s status became the subject of increasing speculation after the chairman missed the commission’s open meeting Oct. 18, the second he has missed since a fall that left him visibly uncomfortable at the meeting in July.
In March, McIntyre issued a statement saying he had undergone “successful surgery” for a “relatively small” brain tumor that was discovered in summer 2017. At the July meeting, he wore a sling after disclosing he had injured his arm and suffered compression fractures in two of his vertebrae in a fall.
‘Full Attention and Vigor’
In a letter to the president, dated Oct. 22, McIntyre said that since taking office in December 2017, he has “pushed full steam ahead with all of the important work of the agency … with full attention and vigor, despite facing some health challenges along the way, including compression fractures in multiple vertebrae this summer.”
“However, I very recently experienced a more serious health setback, leaving me currently unable to perform the duties of chairman with the level of focus that the position demands and that FERC and the American people deserve.”
Chatterjee, a Republican like McIntyre, had served as chair for several months last year before McIntyre’s arrival. In a statement Wednesday, he said he took the chairmanship “with a heavy heart … while my friend and colleague, Kevin McIntyre, focuses on what’s most important: his recovery and his family.”
“I am confident that the commission will continue to benefit from his consummate knowledge of the law and of energy policy through his service as commissioner. On behalf of the entire FERC community, I wish Kevin and the McIntyre family continued strength and resolve at this challenging time.”
Chatterjee praised McIntyre for his “steadfast leadership.”
“Although this is a difficult period for the commission, I want to assure my fellow commissioners, staff within the building and stakeholders outside it that it’s my full intention to build upon Kevin’s hard work. But above all, I look forward to the day when my friend is back at full capacity.”
Commissioners Cheryl LaFleur and Richard Glick also issued statements on the transition.
“I am very sorry to hear about Chairman McIntyre’s decision to step down as chairman. I want to extend my warm wishes to him for his recovery, and I look forward to continuing to work with him. He and his family are very much in my thoughts during this time,” LaFleur said. “I also look forward to continuing to work with Chairman Chatterjee in his new role. This is a time for close cooperation among everyone at the commission, and I will work as hard as I can to keep our work moving forward.
“We have experienced a lot of change and transition during my time at the commission,” she continued. “I know that our wonderful employees will stay strongly focused on their important work and the mission of the organization during leadership changes, as they have in the past. We are very lucky to have such a strong team in place across the commission.”
“It is far more important that Kevin focuses his efforts on recovery than on the additional executive responsibilities of the FERC chairman,” Glick said. “I look forward to continuing our close working relationship. I will continue to work with my colleagues on the commission’s important responsibilities. FERC rightly has a reputation and tradition of being a nonpartisan decision-making body. In the coming weeks, let us reaffirm our commitment to consensus building and to maintaining the agency’s independence as we engage the nation’s energy business.”
“I thank Chairman McIntyre for his leadership at the agency and pray for his swift recovery and return to good health as he continues as a commissioner,” said Sen. Lisa Murkowski (R-Alaska), chair of the Senate Energy and Natural Resources Committee. “I’m confident that Chairman Chatterjee will once again effectively lead the agency, and I will work with my Senate colleagues to restore a full complement of commissioners as quickly as possible.”
McIntyre told Trump he “will forever be grateful for the opportunity to serve as chairman and for the trust and confidence you placed in me to lead FERC at such a critical time in its history.”
2-2 Split Maintained
By stepping down from the chairmanship but remaining on the commission, McIntyre is ensuring that the panel maintains the 2-2 Republican-Democrat split it has had since the resignation of Republican Commissioner Robert Powelson in August.
The 2-2 split could threaten pending gas pipeline certificate cases. Democrats LaFleur and Glick have insisted the commission’s analyses include consideration of downstream greenhouse gas emissions, which McIntyre and Chatterjee have opposed.
Earlier this month, Trump nominated the Department of Energy’s Bernard McNamee as Powelson’s replacement. McNamee is scheduled for a confirmation hearing before the Senate Energy and Natural Resources Committee on Nov. 15. (See Trump Nominates DOE’s McNamee to FERC.)
ClearView Energy Partners predicted in a message to clients Thursday that McNamee will be confirmed during the lame duck session following the mid-term elections.
“However, if the Senate focuses on other business, the White House might nominate a Democrat to take over from Commissioner Cheryl LaFleur, whose term expires on June 30, potentially early in the new year,” ClearView said. “It is often (but not always) easier for a narrowly divided Senate to more expeditiously confirm nominees in bipartisan pairs, as both sides are theoretically motivated to approve both nominees in order to ensure the ascension of their preferred candidate.”
Stakeholders weighed in Tuesday on CAISO’ssecond revised straw proposal to treat storage as transmission assets (SATA) for purposes of accessing market revenues.
The SATA plan deals with storage resources providing reliability-based transmission services, but it specifically excludes consideration of whether those resources are connected to transmission or distribution lines and leaves them out of the transmission planning process, for now.
During a conference call to discuss the proposal, Karl Meeusen, the ISO’s market design and regulatory policy lead, said major questions under consideration include “how to utilize [a storage resource] if it is selected for cost-of-service” recovery as a transmission asset and, once selected, how it could participate in the market to the benefit of ratepayers while ensuring it is used efficiently and effectively.
Transmission assets have traditionally fully recovered their costs through CAISO’s transmission access charge (TAC), but the ISO has proposed three cost-recovery options for regional SATA projects.
The first proposal would provide the assets full cost-of-service-based recovery with ratepayers footing the bill via the TAC. The second would involve partial cost-of-service-based recovery and allow projects to retain energy market revenues, leaving the owner with lower recovery through the TAC but more potential upside — and risk — from the market. The third would allow full cost-of-recovery with market revenue sharing between owners and ratepayers to both offset recovery from the TAC and incentivize the resource to bid into the market.
FERC said in a January 2017 policy statement that energy storage facilities should be permitted to provide multiple services and earn both cost- and market-based revenue streams. (See Storage Can Earn Cost- and Market-Based Rates, FERC Says.)
In the past few years, CAISO has weighed 27 battery storage proposals and one pumped hydro storage project as transmission assets. But it has allowed only two of the projects to move forward, including one in Oakland. Both were approved in the ISO’s 2017/18 transmission plan.
In general, Meeusen said, “We think most storage resources are [better] situated as market resources.”
Deborah Le Vine, the ISO’s director of contracts, said SATA projects would be covered under contracts that ranged from 10 years for battery storage to 40 years for pumped hydro facilities, reflecting the resources’ expected life spans, although most pumped hydro facilities last “a hell of a lot longer” than 40 years, she said.
Storing wind and solar energy to use later is a major challenge for California. | Pixabay
Some stakeholder concerns have already been addressed, but those that remained include the possibility that SATA projects could suppress market prices and have limited competition.
Another concern expressed by stakeholders was whether the resources would be able to adequately participate in the real-time market; for instance, if a pumped hydro facility would have adequate time to pump water to its upper reservoir or if batteries would have enough time to charge.
Maybe storage projects could also be allowed to participate in the day-ahead market, some commenters suggested.
“I think it’s a fair comment to say [a storage project] might need more than three or four hours to charge,” Meeusen said. “We need to think about it hard.”
Meeusen and other CAISO officials asked for some of the comments to be submitted in writing.
Stakeholder comments on the second revised straw proposal are due Nov. 6. The draft final proposal is scheduled to be released Dec. 10, with a stakeholder meeting planned Dec. 17 to discuss it.
The final proposal will likely go to the ISO’s Board of Governors in early February, officials said.
Marcelino Madrigal, one of seven commissioners on the country’s Energy Regulatory Commission (CRE), takes a more glass-half-full approach to the 2014 reforms.
“It has been four years of implementing the electricity energy reforms, but the actual results are there,” Madrigal said during a recent Gulf Coast Power Association breakfast meeting. “The results are clear in terms of success. Basically now, people really have access to this market. We have new companies in the system bringing a cleaner energy supply. … This has provided an opportunity for everyone to invest, from really large companies to small ones, to even the households with solar panels.”
And indeed, there are bright spots in the market. CRE has issued 533 generation permits through September, much of it for rooftop solar. It has also registered 22 power marketers and issued 49 permits for retail market-qualified suppliers and four for basic suppliers. (Basic services are defined as pre-regulatory reform contracts and new contracts less than 1 MW, while qualified services are defined as demand 1 MW or greater, acquired directly or through the wholesale market’s qualified suppliers.)
The Ministry of Energy (SENER) says that clean energy sources were responsible for 21.1% of Mexico’s power in 2017, though large hydro dams accounted for about 85% of that figure. Given that, it would seem the electricity sector is on track to meet its clean energy goals, set by the 2013-14 constitutional energy reforms, of generating 35% of its power from renewables by 2024.
Madrigal said 20.7 GW of clean energy is currently in operation, with another 28.5 GW planned. In comparison, CRE has granted permits for 22.2 GW of new fossil generation.
“We are living in two worlds,” Madrigal told his audience, which included the Mexico chapter of the Women’s Energy Network. “We are seeing a worldwide decrease in the cost of wind and solar. This is the new world, where new generation comes with very competitive prices. It comes quickly and very fast.
“What is the old world? It’s the one we’re used to. Old technologies, coal, fossil fuels, things like that. The rapid development of renewables creates … new opportunities with lower prices and cleaner fuels that the consumer is already accessing.”
Madrigal said the key to the new world is consumer access, which leads to greater comfort as the industry changes.
“The rules to access this new world are already there,” he said, pointing to capacity and clean energy certificate auctions at the wholesale level and the growth of distributed generation.
“You can access those opportunities,” Madrigal said. “We’re seeing those lower prices in the markets worldwide, not only Mexico. The instruments are there, and people are using those instruments. Factories, small enterprises are using rooftop solar. Big companies are accessing the auctions. About 30% of demand comes from private consumers. This is a good signal. The consumers are realizing there is this new world of opportunities.”
Understanding the Opportunities
Madrigal referred repeatedly to the importance of the retail market, where less than 1% of consumers have selected power from a registered qualified supplier. The state-owned utility, the Federal Electricity Commission (CFE), has long been the country’s sole provider and is the second most powerful company in the country, second only to the state-owned oil company, Pemex.
“If you give consumers the opportunity to acquire their own energy, they will do it,” he said. “It’s just a process of understanding the opportunities in the market and a mindset change. You have to now understand you have options in acquiring energy, as you do in any other [market].”
Madrigal doesn’t compare Mexico’s retail market to California’s or PJM’s. He compares it to Chile, Colombia and Peru, which have had retail markets up and running for as long as 30 years. In Chile, qualified suppliers provide fully two-thirds of the retail power, while in Peru and Colombia they account for 46% and 32%, respectively.
“We still have a way to go. We’re at 1%, but it’s only been a year,” Madrigal said. “I expect this market will go gradually, but maybe I’m too ambitious.”
He very well may be. One market participant said consumer choice may be touted as the end game, but there has been “absolutely zero effort” to promote or facilitate the market.
Other challenges abound. Madrigal said a key will be a successful first financial transmission rights auction, which is scheduled for January after months of delay. The auction’s contracts will only cover three years, leading market participants to ask how they finance a 15-year purchase agreement with only three years of pricing security.
Not surprisingly, the lack of clarity over FTR costs means not a single bilateral renewables contract has been signed between a generator and a consumer.
“I believe the FTR market is crucial for the qualified supplier market. You need an instrument to manage congestion risk … that is the key part that this market needs,” he said.
Madrigal also lists better financing instruments for smaller-scale investments in renewable energy and a greater understanding of the retail market by the qualified segment as hurdles to overcome.
“For the most part, the main pieces of the regulatory framework have been completed,” said Madrigal, who was appointed to CRE in 2014. Each commissioner serves a seven-year term, with one rolling off every year.
The Path Forward
Market participants complain about a lack of transparency, especially with retail rates. CRE established a methodology to determine rates earlier this year, but SENER quickly rescinded the new rates and approved a confusing “deferred” application when prices skyrocketed and consumers protested. (See “Market Architect Calls for Increased Transparency,” Overheard at the GCPA Mexico Electric Power Market Conference.)
“Tariffs today are not the same as they were,” he said. “The user needs to be more comfortable with the scheme. Once they understand it, of course, maybe they’ll feel more comfortable in accessing the other options in the market. More renewables are coming online in 2019 and 2020. The market will gradually start to pick up a little bit more. You need fresh energy to be competitive, and that energy is coming online.”
Successful participants in Mexico’s three long-term auctions. | CRE
Indeed. Zuma Energia in August dedicated its $600 million Reynosa 1 project, the country’s largest wind farm at 424 MW of capacity, in the state of Tamaulipas. A result of the second long-term auction in 2016, it’s located on community lands known as ejidos. (See Land Rights a Challenge to Mexico Tx Developers.)
The largest solar plant in the Americas, Enel Green Power’s 232-MW, $160 million Tlaxcala project, is scheduled to open next year.
All indications are the market reforms will continue. July’s election of Andres Manuel Lopez Obrador abruptly brought his left-wing party into power. While Lopez Obrador has talked of taking a wait-and-see approach to the petroleum sector’s reforms, most industry insiders expect him to leave the electricity market alone.
Madrigal said the transition meetings — Lopez Obrador’s administration won’t be sworn in until Dec. 1 — at SENER are going well. He said CRE is represented “in case they want to know something about how the regulations work.”
Staying on message, Madrigal said, “The work continues as normal. We have our regulatory program, and we are implementing it. We’ve been developing a framework where everyone can access this market. There have been clear, good results.
“The implementation of reform is something that takes time, but the benefits for everyone will come with a little bit more time,” he said. “I think the results so far indicate to us that this is the path forward.”
SERC Reliability Corp. on Monday announced Jason Blake, vice president and general counsel of ReliabilityFirst, as its new CEO, effective Nov. 15.
He will replace Gary J. Taylor, who has served in the position since 2016.
“Our search encompassed a variety of industry segments including public power, investor owned utilities, and the electric reliability sector,” Tom Linquist, managing partner of Lyceum Leadership Consulting, SERC’s search firm, said in a statement.
“I have the utmost confidence that Jason will provide the superior level of leadership, management and vision required to take SERC to the next level in our mission of promoting effective and efficient administration of the bulk power system within our jurisdiction,” SERC Chair Greg Ford said, citing Blake’s “extensive experience.”
Blake, who joined Cleveland-based ReliabilityFirst in 2010, led the organization’s legal and regulatory affairs, enforcement and external communications departments. He also was corporate secretary and a member of the CEO’s executive team.
Before ReliabilityFirst, Blake gained business and regulatory experience in private practice in Pittsburgh and Cleveland. He is a graduate of The Ohio State University and the University of Pittsburgh School of Law.
ReliabilityFirst is the NERC-delegated regional entity (RE) for the Great Lakes and Mid-Atlantic regions of the United States. Charlotte, N.C.-based SERC, is the RE for all or portions of 16 Central and Southeastern states.
“This is a great move, not just for SERC, but for the entire [Electric Reliability Organization] enterprise,” ReliabilityFirst CEO Tim Gallagher said in a statement. “Our pride in seeing him named CEO is matched only by our sadness in seeing such a great friend and valued colleague leave the RF family.”
RF has begun a search for Blake’s replacement. Megan Gambrel, managing legal and regulatory counsel, was appointed interim general counsel.
Taylor is departing SERC after a little more than two years as CEO. He joined SERC in 2015 and served as chief operating officer after retiring from Entergy, where he served as group president of Entergy’s utility operations and CEO of its nuclear unit.
Blake and SERC officials did not immediately respond to requests for comment.
RENSSELAER, N.Y. — NYISO on Monday proposed a framework for applying and billing carbon charges to New York energy suppliers under the state’s proposed scheme to price greenhouse gas emissions in the ISO’s wholesale electricity market.
NYISO staffer Nathaniel Gilbraith told New York’s Integrating Public Policy Task Force (IPPTF) emissions from Clean Energy Standard-eligible wholesale suppliers would not be subject to the carbon charge nor would upstream or fugitive CO2 emissions and other greenhouse gas emissions such as methane and nitrous oxide.
Historical NYISO Fossil CO2 Emissions by Generator Type | Brattle Group
Exempt resources would include those participating in the Special Case Resource, Emergency Demand Response, Demand-Side Ancillary Services and Day-Ahead Demand Response programs, he said.
Why Exempt?
“Our rationale for this is because they’re primarily load reduction,” Gilbraith said. “Resources in these programs infrequently produce energy using emitting resources. About 90% of all program megawatts are pure load reduction with no local generation.”
In addition, collecting data from these resources would create potentially sizable new reporting requirements for the resources with few resultant carbon charges returned to loads, he said.
“I don’t want us to lose sight of the optics of creating exemptions from the program we ultimately introduce and the public’s receptivity ultimately to a major new initiative,” said Howard Fromer, director of market policy for PSEG Power New York.
“Sometimes these resources may be seen as emergency resources, but in the neighborhoods in which they exist they’re not always so well received,” Fromer said. “It’s a politically easier sell to say we are not exempting anyone. If you are putting out carbon in this sector, and you’re in the wholesale market … we’re capturing all of this.”
Applicable emissions would include those associated with startups, no-load levels and generation that receives wholesale market compensation. The ISO will work with resources to establish a reference emissions allocation method.
Emissions associated with heat and steam sales fall outside the scope of a wholesale electric sector carbon charge, Gilbraith said. Cogeneration resources will report emissions associated with the provision of wholesale energy and ancillary services, excluding those associated with heat and steam sales.
Verifying Data
NYISO will develop internal processes to verify supplier emissions as reasonable and accurate.
Cogeneration, behind-the-meter net generation (BTM:NG) resources and distributed energy resources in particular, will be required to submit data allowing the ISO to verify the emissions associated with wholesale energy and ancillary service sales, Gilbraith said.
RGGI and Eastern Interconnect (EI) CO2 Emission Reductions (2017–2031) | Brattle Group
Inaccurate, insufficient or untimely data submissions will be subject to penalties administered consistent with the existing penalty review process, he said.
NYISO’s Tariff defines BTM:NG as a “facility eligible to serve both its host load, which is a behind-the-meter load, and then sell excess capability as a wholesale sale into the NYISO markets,” Gilbraith said. “When the resource serves host load … it’s not a wholesale market transaction and therefore it falls outside the scope of a wholesale electric sector carbon charge.”
BTM:NG resources will report emissions associated with the provision of wholesale electric energy and ancillary services — that is, “net generation” — and not emissions associated with serving their host load, Gilbraith said.
Billing and Invoicing
The previous week, the ISO proposed to base the carbon impact on LBMP (LBMPc) on real-time system dispatch to determine carbon charges and credits, as opposed to forecasting the impact. The change would be consistent with the LBMPc used to allocate residuals to loads, and the ISO would also create a new billing code for carbon charge settlements. (See NYISO Proposes Border Pricing Plan for Carbon.)
NYISO would submit emissions data pursuant to explicit timelines aligned with current practice, and for the daily bill and the first monthly invoice, supplier emissions will be automatically populated with an initial emissions estimate based on the carbon component of the reference level, Gilbraith said.
Suppliers’ reference levels will be determined by the ISO’s market mitigation analysis department, which has “means of tracking whether or not bids are competitive at a 10,000-foot level, so they include provisions including heat rate for the supplier,” Gilbraith said. “So we’ll enhance that product to include a carbon component for each bid, and note that will be the basis for the initial carbon charge.”
Suppliers will be required to submit emissions true-ups within 60 days of the initial invoice, which is usually sent five day after the end of the month, he said. There will be a mandatory penalty for failure to submit emissions true-ups on time. Suppliers will be able to further true-up emissions data after the four-month invoice but not after the final bill closeout.
Stakeholder Concerns
The ISO asked market participants to submit written comments on the proposal, but several stakeholders balked at the request without more feedback coming the other way, as in an updated proposal from NYISO.
Michael DeSocio, the ISO’s senior manager for market design, summarized stakeholders’ desire for clarity on the schedule and on exactly what the grid operator is proposing ahead of the planned announcement of a final proposal on Dec. 17.
“If we’re going to go through this process, we’ll probably need more than another meeting or two, and we’ll look to create additional meetings and lay out what that schedule looks like,” DeSocio said.
IPPTF Chair Nicole Bouchez, NYISO’s principal economist, said the task force would release a revised schedule as soon as possible.
The task force next meets at NYISO headquarters Oct. 29 to discuss allocation of carbon charge residuals and the transparency of carbon impacts. That meeting will also hear a Calpine presentation, delayed from this week, on how a carbon charge might affect hedges on transmission congestion contracts.
MISO is currently accepting proposals for a transmission or generation solution to offset reliability issues caused by the planned suspension of a DTE Energy coal-fired plant near Detroit, Mich.
The RTO hopes stakeholder-submitted proposals will prevent the need to create a future system support resource (SSR) agreement for Unit 9 of the 520-MW Trenton Channel Power Plant, in operation since 1968. DTE closed Units 7 and 8 at the plant early last year.
Trenton Channel Power Plant | DTE Energy
The company plans to shutter the remaining plant in June 2023, but in modeling for 2022, MISO found the shutdown could provoke multiple thermal overload and voltage violation issues that cannot be resolved by generation redispatch or new operating guides.
DTE has said the plant will resume operations in mid-2025, but MISO no longer models a return date in suspension studies, contending suspended generation rarely returns. (See FERC OKs New MISO Retirement Process.)
MISO has so far received seven suggested solutions involving transmission upgrades, including submissions from DTE Energy and ITC, although only one solution has been formally submitted to the RTO’s Transmission Expansion Plan (MTEP) for study and modeling. Solutions must be put before the MTEP process before consideration, and the RTO said solutions will be studied in the MTEP 19 cycle.
MISO will also accept new generation solutions to address issues caused by the retirement, but during an Oct. 22 special conference call, staff said new generation proposals must be submitted through the interconnection queue for consideration and study. The generation queue doesn’t currently contain a project that can mitigate issues from a Trenton suspension. MISO staff said a generation solution may require a Trenton SSR designation to keep the plant online until the new generation comes online.
