CARMEL, Ind. — MISO will roll a 35% share of the capacity from resources sitting in the definitive planning phase of its interconnection queue into the annual resource adequacy survey conducted with the Organization of MISO States — over the objections of some stakeholders who seek inclusion of a greater portion of capacity.
The survey currently counts only future resources that have already executed a generator interconnection agreement.
Indianapolis Power and Light’s Lin Franks said MISO’s 35% completion estimate is too conservative, especially when considering projects submitted by state-jurisdictional utilities that are obligated to serve load and whose projects might be more reliably completed than other queue entrants. (See Stakeholders, MISO at Odds over Resource Adequacy Survey.)
“You know the damn thing is going to be built — it needs to be included” in the survey, Franks remarked during a March 8 Resource Adequacy Subcommittee meeting.
She also warned of the “self-feeding” problem of developers entering the queue long before they are certain that a resource will be constructed — the product of long queues.
Franks suggested that MISO examine rates of withdrawal based on resource type.
“If you don’t take a look at which resources are withdrawing, you don’t have a transparent picture,” she said. “You’ve got to be more transparent and not convince people that the sky is falling.”
Madison Gas and Electric’s Gary Mathis said he did not see evidence of stakeholder advice in MISO’s proposed improvements.
“This issue has been around for a number of years, and MISO has been aware for a while of the improvements that are needed. … Certain projects in the queue will be realized,” he said. “I’m disappointed that we didn’t come further, and I question whether we were listened to in this process.”
The RTO says it will consider adding more resources in other phases of the queue as it carries out queue reforms.
Darrin Landstrom, MISO’s resource forecasting adviser, said the terms “committed” and “potential” will replace the “high certainty” and “low certainty” descriptors currently used for resources in the queue’s definitive planning phase.
Bonnie Janssen, a Michigan Public Service Commission staffer, said OMS could additionally include a “probable” category. MISO will send out questionnaires by March 31, with detailed results expected to be released in June.
Laura Rauch, manager of resource adequacy coordination, said MISO can provide stakeholders with mockups of survey results at the April RASC meeting.
RASC Chair Chris Plante plans to present MISO and stakeholder differences over the survey’s improvements to the Board of Directors during its March 23 meeting.
CAISO last year paid out $47 million more to congestion revenue rights holders than it took in from its auctions, the ISO’s internal Market Monitor has found.
That deficit — a persistent problem since the ISO instituted CRR auctions five years ago — could buttress the Monitor’s call for ending the auctions, which it says allows financial speculators to reap hundreds of millions of dollars at the expense of California electricity ratepayers. (See CAISO Monitor Proposes to End Revenue Rights Auction.)
“The [Department of Market Monitoring] believes that the trend of revenues being transferred from electric ratepayers to other entities warrants reassessing the standard electricity market design assumption that ISOs should auction off these financial instruments on behalf of ratepayers after the congestion revenue right allocations,” the Monitor said in its quarterly market issues and performance report covering the fourth quarter of last year.
The Monitor’s suggestion: Replace the auction with a bilateral or exchange market for contracts-for-differences for pairs of ISO nodes — also known as locational basis price swaps.
Under that arrangement, swaps would be traded among willing counterparties, rather than leaving ratepayers as unwitting parties in a market in which they are outmatched by more sophisticated traders, the Monitor says.
CAISO management has responded to the Monitor’s concerns by agreeing to consider a stakeholder initiative on potential changes to the auction, a move that has been met with mixed reactions from market participants. (See CRR Initiative Elicits Mixed Reviews from CAISO Participants.)
Proposal Unwarranted?
“While I don’t believe DMM’s latest findings warrant their specific proposal to replace the CRR auction with a bilateral market or locational price swaps … I think the CAISO’s study is absolutely an opportunity to make improvements to the current CRR auction and identify practices and transparency issues that may be causing some inefficiency in the CRR auction pricing,” Carrie Bentley, a principal with Resero Consulting, told RTO Insider.
Bentley’s firm frequently works on behalf of the Western Power Trading Forum (WPTF), an energy trader interest group that opposes the suggestion to scrap the auction. It has called the proposed stakeholder initiative a “pet project” of the Monitor.
The Monitor’s most recent findings show that last year’s CRR deficit increased by $1 million over 2015, with auction revenues representing just 68% of CRR payments made to auction participants, compared with 73% during the previous year.
While total payments to auction rights holders declined 15% to $147 million, auction revenues also fell 21% to $99 million year over year.
Financial traders last year took in $33 million from the auctions, paying 63 cents for every dollar made from their CRRs. Their overall take was down 30% from the previous year, but it still represented the largest share of all participants. The Monitor has contended that “purely financial entities” are the main beneficiaries of the auction program.
Power marketers saw their auction profits increase by 43% to $10 million, while generator profits fell by 29% to $5 million.
Load-serving entities, which CAISO provides an annual allocation of CRRs, made about $3 million from rights they sold into the auction, down sharply from $14 million earned the previous year.
CAISO’s congestion revenue rights auction revenues have consistently come up short of payments to rights holders, leaving ratepayers to foot the difference. | Q4 2016 Report on Market Issues and Performance, March 6, 2017; CAISO Department of Market Monitoring
Transmission congestion dropped last year as drought conditions resulted in decreased electricity use for moving water supplies across California. Transmission usage also was undercut by growth in behind-the-meter rooftop solar.
The fourth quarter saw the resumption of the prevailing pattern of CRR payments outpacing auction revenues, following a short-lived surplus during the third quarter (see chart).
WPTF Comments
In comments filed with CAISO earlier this year, WPTF contended that auction revenues increased as a percentage of payments in the third quarter after the ISO implemented practices that improved transparency into how it represents transmission outages in its market models.
“I think the fourth-quarter results were due to unexpected transmission outages and nomograms [prediction tools] that were not included in the CRR model or known by participants in advance of the auction,” Bentley said.
She cited as evidence the ISO’s own monthly market performance reports for October, November and December, which attributed at least a portion of auction revenue shortfalls each month to unexpected binding constraints on the transmission system.
Unlike other RTOs that have imposed penalties for “late, unnecessary or nonemergency outages that impact the day-ahead market, but were not modeled in the monthly auction,” CAISO has no such policies, Bentley said.
“Therefore, events like this last quarter are frequent, where outages impact CRR shortfalls with no repercussions on those causing the shortfall,” she said.
Bentley added that the ISO may compound the issue by not providing sufficient notice in advance of auctions about nomograms created to account for outages.
“While the majority of nomograms understandably may not be done in advance sufficient to notify market participants, a tightening up of transparency policies would enable better CRR auction outcomes in those cases that the CAISO could have given advance warning,” Bentley said.
Analysis Challenged
Ryan Kurlinski, manager of the Monitor’s analysis and mitigation group, rejected Bentley’s analysis. “There is no evidence to support WPTF’s suggestion that improvements in the ISO’s transmission outage reporting accounted for the reasons that CRR auction revenues exceeded payouts during the third quarter of 2016,” he said.
Kurlinski said the third quarter was “very anomalous” and that lower payments to auction participants stemmed from “unusually low” congestion appearing in the ISO’s day-ahead market during the period.
“During periods of this quarter, virtually no congestion appeared in the day-ahead market,” Kurlinski said. “DMM is working with the ISO to understand factors which might have caused this.” That lack of congestion likely accounts for last year’s overall drop in payouts to CRR holders.
Kurlinski doubted that adjustments to the auction model could ultimately improve outcomes for ratepayers.
“Even if the CRR auction model includes all outages known by CAISO [transmission owners] at the time the model is completed, there will be outages that cannot be adequately modeled,” Kurlinski said. “For instance, if an outage is scheduled for only a few days, this outage cannot be accurately represented in the monthly CRR model.”
WASHINGTON — PJM Independent Market Monitor Joe Bowring on Thursday warned that state plans to subsidize unprofitable generating resources present “a very real threat” to wholesale electricity markets.
The subsidies in question come in the form of zero-emission credits for uneconomic nuclear plants, which were included as part of New York’s Clean Energy Standard and are intended to aid the state’s transition away from fossil fuels and into renewables.
Exelon has been pushing for similar treatment for its nukes in Illinois, while FirstEnergy has said it will seek financial assistance for its Ohio plants.
“I don’t believe that any of the subsidies are being driven initially by state policy,” Bowring said during his PJM 2016 State of the Market Report presentation. “They’re being driven by the specific requests of generation owners about particular units because those units are not profitable. We would not be talking about the units in Illinois or Ohio if the capacity market prices had been higher and those units were profitable.”
| Monitoring Analytics 2016 State of the Market Report
Social goals — such as the reduction of carbon emissions to reduce the effects of climate change — can be accomplished through market-based solutions, such as a price on carbon, Bowring contended.
“Economists everywhere agree that … the most cost-effective way to do that is have a carbon price,” Bowring said. “It’s certainly not by picking individual power plants that are low carbon.”
To protect the markets from the effects of the subsidies, Bowring advocated for applying PJM’s minimum offer price rule (MOPR) to all existing resources. The rule currently covers only new subsidized gas-fired plants.
“Action is needed to correct the MOPR immediately,” the Monitor said in its report. “An existing unit MOPR is the best means to defend the PJM markets from the threat posed by subsidies intended to forestall retirement of financially distressed assets. The role of subsidies to renewables should also be clearly defined and incorporated in this rule.”
Bowring expressed concern that Illinois and Ohio could set a precedent for other states, calling the subsidies “contagious.” The Monitor views the threat as so severe that in January it filed as an intervenor in support of independent power producers opposing New York’s ZEC program.
“The ZEC program is not consistent with the operation of a competitive wholesale electricity market,” the Monitor told the New York Public Service Commission, adding that the program would artificially suppress NYISO, dissuade the construction of new generation and, if extended, “result in a situation where only subsidized units would ever be built.”
Record-low LMPs in PJM
The Monitor found that PJM’s energy, capacity and regulation markets were competitive during 2016. The average real-time, load-weighted LMP was $29.23/MWh, 19.2% below the previous year and the lowest since the competitive wholesale market commenced operation in 1999 — “which is fairly astonishing,” the Monitor noted.
| Monitoring Analytics 2016 State of the Market Report
Fuel prices were the main drivers: Gas prices were very low, while those for coal remained flat. High output from efficient combined cycle units — despite flat load growth — also played a significant role.
All those factors translated into a competitive market, Bowring said.
“New combined cycles have been added because of competitive markets,” he said. “They’ve been added because of the fact that we have a capacity market. … But for PJM overall markets, we probably would not have seen that level of entry of highly efficient combined cycles.”
As a result, net income for new combustion turbine and combined cycle units were up 21% and 14%, respectively. Meanwhile, profits decreased for new coal (54%), diesel (86%), nuclear (26%), wind (19%) and solar (28%).
Total transmission congestion costs fell by $361.6 million (26.1%), the result of low prices and smaller price differences across constraints.
Capacity Market
Capacity prices were lower last year than in 2015, except in the PSEG zone. Capacity revenue accounted for 43% of total net revenues for new combustion turbine plants, 32% for new combined cycles and 23% for new nuclear.
Total installed capacity last year rose 2.7% to 182,449 MW. As of Dec. 31, 101,474 MW were in the generation interconnection queue, with combined cycle units accounting for 68.3% and wind projects 14.4% of capacity. The Monitor expects gas to surpass coal in installed capacity this year.
Demand Response
Total payments to demand response resources decreased by $163.2 million (20.1%) to $655.7 million. Bowring attributed the decline to low prices, which undercut incentives to reduce power usage.
The capacity market remains the primary source of income for DR, making up 99% of its revenue — something Bowring is still not happy with, as he continues to advocate its removal from the capacity market. He said stakeholders are seriously considering the “best way” to manage those DR resources within the market.
“It’s important to understand our perspective here, which is not anti-DR at all,” Bowring said. “We’re very much pro-DR. We think it’s essential to making markets work. We want more people to have the option … to reduce demand and save capacity revenues.”
The New York Public Service Commission on Thursday adopted a new “value stack” pricing mechanism for solar and other distributed energy resources, along with two other orders to transition utilities into “distributed system platforms” and align their incentives with DER providers.
The Value of Distributed Energy Resources order approved March 9 (Case 15-E-0751) begins the transition away from net energy metering and toward an approach that aggregates specific value components. The number of those components will be raised over time to increase the granularity and accuracy of the valuation.
“This order achieves a major milestone in the Reforming the Energy Vision (REV) initiative by beginning the actual transition to a distributed, transactive and integrated electric system,” the commission wrote.
It would replace existing DER business models based on net energy metering, which the commission called “inaccurate mechanisms of the past that operate as blunt instruments to obscure value and are incapable of taking into account locational, environmental and temporal values of projects.”
“By failing to accurately reflect the values provided by and to the DER they compensate, these mechanisms will neither encourage the high level of DER development necessary for developing a clean, distributed grid nor incentivize the location, design and operation of DER in a way that maximizes overall value to all utility customers,” it said.
Continuing NEM, which can overcompensate distributed resources by transferring their share of fixed costs to other customers, would prevent wide-scale DER deployment “as the inherent subsidies reach a level that is oppressive to non-participants,” the order said.
| New York Public Service Commission Staff Report on Value of DER Proceeding, Oct. 2016
“The system obeys not the law of contracts, but the laws of physics,” said PSC Chair Audrey Zibelman, in her final commission meeting. “Following those, that’s how you’ll get the best outcome. DER, rather than being a problem, can be a solution to where we want to get to, which is a clean energy future.”
Transition Period
The order initiates a transition period with a VDER Phase One tariff in which projects currently in “advanced stages of development” will receive NEM compensation, but for only their first 20 years.
“While Phase One NEM contains inefficiencies similar to NEM as a compensation methodology, the term limitation will offer some incentives for developers and customers to consider the impacts of the location, design and operation of DER on the electric system,” the commission said.
| New York Public Service Commission Staff Report on Value of DER Proceeding, Oct. 2016
The order directs Department of Public Service staff to work with utilities and other stakeholders to develop the new value stack compensation “based on monetary crediting for net hourly injections,” which the commission hopes to act on as early as this summer.
Value stack compensation would include:
Energy value, based on the day-ahead hourly zonal LMPs, including losses;
Capacity value, based on retail capacity rates for intermittent technologies and the capacity tag approach for dispatchable technologies based on performance during the peak hour in the previous year;
Environmental value, based on the higher of the latest Clean Energy Standard Tier 1 renewable energy certificate procurement price or the federal government’s social cost of carbon; and
Demand reduction value and locational system relief value, based largely on utility marginal cost of service studies and performance during 10 peak hours.
Decision Draws Praise from Solar Advocates
Clean energy supporters and solar industry advocates hailed the decision.
“The order will provide a framework for more precisely valuing new clean energy while balancing the need for a predictable price,” said Anne Reynolds, director of the Alliance for Clean Energy New York. “This is the right approach and can serve to support the market for solar and other emerging clean technologies.”
In a blog post, Natural Resources Defense Council attorney Miles Farmer called the order “a bold experiment.”
“Rather than offsetting the retail rate, projects will generate credits according to an estimate of the value they provide to New York customers,” he wrote.
Sean Garren, a regional director for Vote Solar, a nonprofit solar advocacy organization, lauded the “consumer savings, local jobs and a healthier environment” implied in the decision. “While this order has yet to fully expand clean energy access to all New Yorkers, we look forward to doubling down on that commitment to make community solar work throughout the state,” he said.
Incentives for Utilities to Collaborate
The PSC also approved an order (Case 16-M-0411) on utilities’ transition to the distributed system platform combining planning and operations with enabling markets.
The order directs Central Hudson Gas & Electric, Consolidated Edison of New York, New York State Electric and Gas, Niagara Mohawk Power (National Grid), Orange and Rockland Utilities, and Rochester Gas & Electric to submit filings by Oct. 1 documenting that they have completed their analyses of the hosting capacity for all circuits at and above 12 kV and implemented Phase 1 of their online portal for DER developers seeking to access the grid.
The companies also were ordered to submit filings within 60 days describing how the “suitability criteria” — a framework for identifying distribution infrastructure projects most suitable for non-wires alternatives — will be incorporated into their planning procedures and applied to current capital plans.
It set a Dec. 31, 2018, deadline for documenting that each utility has deployed at least two energy storage projects at separate distribution substations or feeders.
Tammy Mitchell, PSC chief for electric distribution systems, said, “The phased approach is right but too slow. This order directs hosting utilities to provide the hosting capacity data needed to manage the variable DER inputs.”
“Today the advanced energy economy industry is worth $200 billion in the U.S.,” Zibelman said. “This order points in the right direction, gives utilities the right incentives, and gives investors the transparency and data they need to put money at risk.”
Helping Utilities See DERs as Customers
In its third and last vote on its regular agenda, the PSC approved an order (Case 16-M-0429) for an interconnection earnings adjustment mechanism, which aims to change the way utilities earn revenues.
The order requires the utilities to build on their previous filings with additional proposals within 60 days on customer service surveys and other metrics that will determine their future compensation.
“This is a good start to change the business model so that DER providers are customers of the utility, which want to attract them and not see them as competitors,” said Zibelman. “Utilities should look at DERs as customers and see how they can exceed customer expectations.”
Department of Public Service Deputy Director Michael Worden said the order “addresses the market in four categories: system efficiency, energy efficiency, consumer engagement and interconnection.”
Depending on how they perform against targets in those categories, said Worden, the PSC will either “reward them with a carrot, or show the stick.”
Zibelman’s Swan Song
Thursday’s meeting marked the end of Zibelman’s more than three-year tenure, as she has accepted an offer to lead the operator of Australia’s largest gas and electricity markets. (See NY REV Won’t Lose Momentum, Departing Zibelman Says.)
Gov. Andrew Cuomo on March 8 appointed Commissioner Gregg C. Sayre as interim chair. The only other commissioner is Diane X. Burman.
Zibelman’s departure, the recent retirement of Commissioner Patricia Acampora and a two-year-long vacancy means the commission now has three openings for new members.
FERC’s loss of its quorum has members of Congress and the natural gas industry feeling anxious, but anti-fracking activists said Wednesday they will oppose any nominations to the commission in order to keep it paralyzed.
Ted Glick, a founder of Beyond Extreme Energy, said his group and more than 130 others were inspired to act when Chairman Norman Bay resigned Feb. 3 after President Trump named Cheryl LaFleur acting chair. Bay’s departure left the commission with only two members, one short of the minimum needed to approve natural gas pipeline projects.
The commission approved seven natural gas pipelines worth 7 Bcfd before Bay left this year, according to the U.S. Energy Information Administration. The commission approved 17.6 Bcfd of capacity last year.
Besides lobbying senators to vote against nominees, the activists’ efforts will include nonviolent civil disobedience, which his group has used to disrupt the commission’s open meetings, Glick said during a news teleconference. (See Meet the People Making Life for FERC a Little More Difficult this Week.)
In a March 2016 protest outside FERC headquarters, Beyond Extreme Energy and other activists ate pancakes with the last syrup from Megan Holleran’s maple trees, which were cut down for a pipeline in New Milford, Pa. Holleran, “Gasland” filmmaker Josh Fox and five others were arrested. | Beyond Extreme Energy
Beyond Extreme Energy and its allies see FERC as a rogue agency that ignores communities’ input on pipeline projects and is cozy with the industry that it is supposed to regulate. Their opposition is nonpartisan, with the activists yesterday lambasting Democrats for their failure to rein the commission in.
“The appointment of one new commissioner could put that agency back in business and able to inflict incredible and irreparable harm on communities and our environment,” said Maya van Rossum, leader of the Delaware Riverkeeper Network.
“Gasland” filmmaker Josh Fox and Tim DeChristopher make pancakes on a solar-powered cooktop during a March 2016 “pancakes not pipelines” protest outside FERC headquarters. | Eleanor Goldfield, ArtKillingAction
Preventing the restoration of FERC’s quorum is virtually impossible, however. Republicans control the Senate 52-48, and Democrats can no longer filibuster the president’s nominations except for the Supreme Court.
“The best outcome right now for the communities being abused by these pipeline projects and these pipeline companies and by FERC is to prevent” a quorum, and give Congress “the breathing room” to holding hearings “investigating the abuses that are happening at the hands of FERC, identifying the needed reforms and putting in place those reforms before a quorum is restored,” van Rossum said. “We get that’s a heavy lift. We totally get that.”
Joining Glick and van Rossum on the call was Todd Larsen, executive co-director of Green America; Josh Fox, director of the Oscar-nominated documentary “Gasland;” and Maggie Henry, a former organic farmer. (See Organic Farmer Turned Fracking Protester.)
“It’s not just that we will oppose the FERC nominees,” Fox said. “Citizens all across this nation are gathering to build protest camps like the one at Dakota Access, and you will see a state of protest against fossil fuel infrastructure unlike anything we’ve ever seen in the United States of America.”
Cantwell, Dems Urge ‘Nonpartisanship’
Sen. Maria Cantwell (D-Wash.), ranking member of the Senate Energy and Natural Resources Committee, has other ideas.
She and 15 other Democrats wrote Trump on Wednesday urging him to respect the commission’s tradition of nonpartisanship, noting that less than 2% of the orders issued in 2016 included a dissenting opinion. “We hope that your nominees will be prepared to continue this tradition, and we intend to review them through that lens during the confirmation process,” the senators wrote.
They also said that both Republican and Democratic presidents have nominated people recommended by the Senate leader of the party that does not hold the presidency — Senate Minority Leader Chuck Schumer (D-N.Y.). “We expect you will honor this long-standing practice in nominating individuals to serve on the commission,” the senators said.
CAISO wants to use an out-of-market measure to keep two Northern California gas-fired peaking plants operating after their long-term contracts expire in December.
The ISO is seeking to designate Calpine’s Yuba City and Feather River plants as reliability-must-run resources after identifying that both 47-MW peakers will be needed to support local grid reliability after they fall off their current contracts with Pacific Gas and Electric, which manages the service territory where the plants are located.
CAISO is seeking to provide Calpine’s Yuba City and Feather River peaking plants with reliability must-run designations next year after the December 2017 expiration of their contracts with Pacific Gas and Electric. | Yuba City photo source Calpine
The issue arose last November when Calpine notified CAISO that expiring operating agreements would require the company to shut down four of its combustion turbine peakers.
Calpine asked CAISO to study whether loss of the units would cause grid reliability problems. The company said that its capital outlay and resource planning requirements required that it learn of any reliability need for the plants before this fall, when the ISO would release its 2018 resource adequacy assessment. Such a determination would make the plants eligible for longer-term resource adequacy payments under CAISO’s capacity procurement mechanism (CPM).
“On that basis, we did do the review that was requested and concluded that there is a reliability need for two of the four generators,” Neil Millar, CAISO executive director of infrastructure development, said during a March 7 call to discuss the issue. Two plants farther to the south, King City and Wolfskill, failed to make the cut.
Pease Area Deficient
| CAISO
Under an RMR arrangement, CAISO has the right to call upon a generator to provide energy, black start services or voltage support to meet reliability needs. The ISO compensates the generator for keeping capacity available for dispatch, with costs allocated to benefitting load-serving entities.
“Without the 47 MW from Yuba City, we would be deficient” in the Pease local capacity requirements sub-area, Millar said.
The ISO performs an annual analysis to determine each local area’s minimum capacity requirement to meet reliability standards. Other generators can provide only 82 of the 100 MW required in Northern California’s Pease sub-area, leaving the Yuba City unit to make up the difference.
Feather River is not needed to supply capacity, but the plant does play a key role in controlling voltage in its surrounding region by absorbing reactive power from the system. Without the unit, 115-kV bus voltages in the area would rise to “significantly beyond” the upper limit of the normal range, CAISO has found.
“We will be looking at longer-term mitigation in that area in future transmission planning process cycles,” Millar said. “We’re working with PG&E, and also recognizing that this is a combination transmission and distribution issue.”
Millar pointed out that a one-year RMR designation would not prevent the plants from entering into longer arrangements with the ISO if the need is identified.
“Just because the units may be designated as reliability-must-run in the spring [of 2018], [that] doesn’t preclude them getting some longer-term resource adequacy contract that would obviate all or parts of the need for an RMR agreement,” he said.
Carrie Bentley, a consultant representing the Western Power Trading Forum, wondered why the two plants wouldn’t be covered under the ISO “risk-of-retirement” CPM.
“I understand that they can’t wait for the annual, but I thought that the risk of retirement didn’t have such timing issues,” Bentley said.
“It’s not totally within the ISO’s ability to direct that,” said Sidney Mannheim, CAISO assistant general counsel. “The CPM is voluntary on the part of the resource owner, where [with] the RMR authority, we literally have the Tariff authority to designate a resource as RMR.”
Impact on Local Capacity Requirements
Erica Brown, senior analyst with PG&E, asked about the impact of the RMR designations on local capacity requirements.
“So, going into our next [resource adequacy] year, if there’s an RMR resource [in a local area], would that subtract from the overall quantity that’s needed for the local area?” Brown asked.
Millar clarified that the Yuba City plant would count toward the area’s capacity requirement because the unit’s RMR designation would be based on a capacity need, while Feather River, which is needed for voltage support, would not.
Michele Kito, a regulatory analyst at the California Public Utilities Commission, asked about Calpine’s need to make investments in the peaking units to keep them online next year. “At what point would there be some independent engineering assessment that those long-term investments need to be made that would justify a long-term RMR agreement?” she asked.
Mannheim clarified that the RMR agreements would only run year-to-year, although they could ultimately cover a multiyear need.
“The RMR process does involve the responsible transmission owner and the PUC to review any proposed capital improvements,” Mannheim said. “That is the process we would undertake following any designation — and the PUC would be involved in that.”
CAISO plans to present the Yuba City and Feather River RMR designations for approval by the Board of Governors on March 16. Upon approval, Calpine would be expected to draw up a cost-of-service proposal, including any capital improvements, for review by PG&E, the ISO and the PUC.
The U.S. Supreme Court announced March 6 it would not hear a challenge seeking to reinstate the federal right of first refusal in transmission construction, letting an appellate ruling sustaining FERC Order 1000 stand.
In April, the 7th U.S. Circuit Court of Appeals in Chicago upheld Order 1000’s removal of the federal ROFR in a challenge by Ameren and other MISO transmission owners (14‐2153). The case was combined with two challenges by LSP Transmission Holdings that contended FERC did not go far enough in injecting competition into transmission development (14‐2533, 15‐1316).
Laying the foundations for Ameren’s Three Rivers Transmission Line | Plocher Construction
Ameren filed a petition for certiorari with the Supreme Court in October. The company, with Northern Indiana Public Service Co. and Otter Tail Power, argued that the April ruling is at odds with the Mobile-Sierra doctrine, and said FERC should assume the ROFR is reasonable unless the commission proves it is contrary to the public interest. The companies warned that failing to reverse the 7th Circuit’s ruling would allow FERC to ignore the Mobile-Sierra presumption in the future.
FERC decided in 2011’s Order 1000 that federal ROFRs that give incumbent transmission owners first pass on new project construction were anti-competitive and should be removed from all FERC-approved tariffs. Order 1000 did not, however, pre-empt state or local ROFRs.
“The Mobile-Sierra doctrine is based on the assumption that sophisticated parties with competing interests and equal bargaining power will usually reach a compromise that is reasonable and fair. The opposite is true when parties collude with one another to restrain competition and maintain a monopoly. … There is no reason to believe that a contract negotiated by parties with a shared interest in excluding third-party competition is similarly just and reasonable,” FERC wrote in a brief to the Supreme Court in February.
MISO still honors state and local rights of first refusal and can use a limited federal ROFR for certain grid reliability projects. The RTO does not have a competitive project scheduled in 2017 because the year’s lone market efficiency project — the $80.9 million Huntley-Wilmarth 345-kV line in Minnesota — is covered by the state’s ROFR. (See MISO Board Approves MTEP 16’s $2.7B in Tx Projects.)
ALBANY, N.Y. — A New York State Assembly hearing Monday to explore the Cuomo administration’s subsidies for upstate nuclear plants left lawmakers frustrated as the Public Service Commission and the New York State Energy Research and Development Authority declined to attend and Exelon sent no senior executive with knowledge of the subsidy negotiations.
“I’m disappointed that they chose not to attend,” said Assemblyman Jeffrey Dinowitz (D-Bronx), the head of the Committee on Corporations, Authorities and Commissions, who chaired the meeting. “It’s important to hear from PSC and the executive branch.”
Exelon, owner of all the nuclear plants set to receive the zero-emissions credits, sent five witnesses, most of them engineers, with the highest rank being a plant vice president. “Maybe you can take notes and send your answers later,” Dinowitz told them sarcastically.
Exelon also submitted testimony from Joe Dominguez, executive vice president of governmental and regulatory affairs and public policy, who said the company would spend $700 million on the plants because of the financial assurance provided by the ZECs. The ZECs would benefit Exelon’s R.E. Ginna, and Nine Mile Units 1 and 2 generators — and the James A. FitzPatrick plant it is purchasing from Entergy — for more than 12 years.
‘Staggering Increase’ in Pollution
“The closure of these plants would have resulted in a staggering increase in air pollution throughout New York because the electricity void created by the closures would have been filled by coal, oil and gas plants operating in and around New York,” Dominguez said.
The PSC said it was unable to attend because of scheduling problems.
“Unlike the 24 public hearings that the Public Service Commission held across the state in developing the Clean Energy Standard [CES], which were scheduled many weeks in advance, the Assembly only informed us of this hearing late last week, and so we were unable to attend due to scheduling conflicts,” PSC spokesman James Denn said in a statement. The Assembly issued the public notice for the hearing on Monday, Feb. 27.
Instead, the state agencies submitted written testimony from PSC Chair Audrey Zibelman, NYSERDA CEO John Rhodes and Richard Kauffman, Cuomo’s top energy adviser. The statement defended ZECs, part of the CES, which also requires that the state generate 50% of its electricity from renewable resources by 2030.
“Fossil fuel generators and anti-nuclear activists have attempted to mischaracterize the Clean Energy Standard as a bailout or a tax,” they wrote. “But … it is unquestionable that the Clean Energy Standard benefits all New Yorkers across the state and, moreover, charts the most responsible path forward on combating climate change and growing our clean energy economy. … Simply put, without the ZEC program, New Yorkers would pay more for dirtier power.”
$7.6 Billion Cost
Several New York City-area legislators have questioned the wisdom and process of last August’s decision by the PSC to approve the CES and ZECs.
The program distributes costs statewide; in its first two years, all New York energy consumers will pay an additional $965 million to keep the nuclear plants running. The costs may rise by as much as 10% in each successive two-year tranche, for a potential total of $7.6 billion.
Dinowitz chaired the hearing in place of Energy Committee Chairwoman Amy Paulin, who was unable to attend. The other committees participating in the hearing were Environmental Conservation, chaired by Assemblyman Steve Englebright (D-Setauket), and Consumer Affairs and Protection, chaired by Assemblyman Brian Kavanagh (D-Manhattan).
Englebright said that he remembered when nuclear power was being touted as being “too cheap to meter, which doesn’t seem to be the case today.” Kavanagh said he was concerned whether the ZEC charges are fairly imposed and in a transparent manner.
Subsidies Too Generous to One Company?
Blair Horner, director of the New York Public Interest Research Group (NYPIRG), testified first and focused on “a public information gap, which seems like a deliberate strategy. A year ago, we were talking about a $100 million bailout of the upstate plants. Then, as soon as the Assembly went into recess, a significantly more expensive program appears. Is this democracy? It’s no surprise the executive branch chooses not to testify.”
Horner said that the state already has 800,000 electricity users who are 60 days or more in arrears on their electric bills and that the CES-related rate hikes would be a hardship for them. The Cuomo administration says the CES, including the ZECs, will add less than $2/month to the average residential customer’s bill.
Exelon expects the New York ZECs and a similar program in Illinois will add 17 cents/share to its 2017 earnings, 6% of its total profits, according to Crain’s Chicago Business.
“We view the CES charges as a tax being imposed by the wrong branch of government,” said Horner. “Even if you disagree with our view, at least the process should be changed to create a meaningful public process. It’s your duty as a co-equal branch of government. The beneficiary of this program is one company, and $7.6 billion seems overly generous to me. Hit the pause button.”
Assemblyman Will Barclay (R-Pulaski) responded that NYPIRG “seems more anti-nuke than pro-public. There were no complaints about zero-emissions credits for renewables.”
Legislature Should Set Energy Policy
Former Assemblyman Richard Brodsky, a longtime opponent of the Indian Point nuclear plant, testified as a private citizen and reminded lawmakers that the PSC was indeed “a legislative agency, not an offshoot of the executive.”
Brodsky urged the Assembly to reconsider the decision to spend an estimated $303,000 per job per year in subsidizing “decrepit” nuclear facilities. “They’re fixer-uppers, and it costs more to do that than to live in a new house,” he said.
The social cost of carbon used by federal agencies to value the climate impacts of rulemakings — and used to set New York’s ZEC values — was not meant as a policymaking tool and has massive limitations, Brodsky said. “I didn’t know the Constitution had a pause button — it’s time for the legislature to set energy policy. The ISO’s market clearing price is the most idiotic policy ever.”
Not ‘Decrepit’
Exelon sent five witnesses to the hearing: Joseph Pacher, site vice president at the Ginna plant; James Vaughn, senior engineering manager at Nine Mile Point; Adam E. King, radiation protection supervisor at FitzPatrick; John Scalzo, engineer; and James Melville, senior radiation safety operator at FitzPatrick.
Pacher said that, far from being decrepit, “all three stations are performing better than when new,” citing their capacity factors of more than 90%. “Preserving nuclear plants upstate is good sense. These plants could be run safely for decades.”
Dinowitz asked about the costs of operating each plant, but none of the witnesses could answer. Vaughn said that the “$7.6 billion is an estimate, and keep in mind that without natural gas prices so depressed, we wouldn’t need any subsidy at all. It’s not to line our pockets but to keep the plants profitable. The ZEC program establishes a floor price, so if gas prices go up we’ll take less in subsidies.”
Englebright said, “ZEC is supposed to be a transition program, not preserve the status quo. When did Exelon first think they would need a subsidy?”
2015, Pacher replied, which was when the company began negotiating a reliability support services agreement at Ginna, which FERC approved in March 2016.
Kavanagh asked if the upstate plants were safer than Indian Point, which is slated to close by 2022 under an agreement between the Cuomo administration and plant owner Entergy. Cuomo has long sought the plant’s closure because of its proximity to New York City. (See related story, NYISO, PSC: No Worries on Replacing Indian Point Capacity.)
“We don’t operate Indian Point, so I don’t want to say,” Pacher responded. “There’s public perception of aging, decrepit nuclear plants upstate, but people who take tours are always impressed with our facilities.”
Kavanagh asked if the Ginna reactor wasn’t the same design as that at the Fukushima Daiichi plant in Japan, which failed when it was flooded by a tsunami in March 2011. Pacher admitted the similar designs but said it was the Japanese plant’s location on the Pacific Ocean that was its biggest vulnerability. “The worst thing for Fukushima was its location, but examining their experience did lead us to re-evaluate our event amelioration strategies,” he said.
Exelon says its nuclear plants, with a total capacity of 3,350 MW, employ 2,600 full-time workers and pay more than $45 million in annual property taxes and $144 million in “direct and secondary state tax revenues.”
In a separate action, a group of energy companies and trade groups in October filed a suit in U.S. District Court for the Southern District of New York, claiming the ZECs intrude on FERC’s jurisdiction over interstate electricity transactions. The suit asks the court to find the ZECs invalid and order the PSC to withdraw them from the CES.
AUSTIN, Texas — When Diego Villarreal looks north across the Rio Grande toward Texas, he sees a deregulated energy market that looks very much like his country’s.
That stands to reason: Mexico has borrowed the best elements of competitive markets from around the globe and learned from U.S. “success stories” — including ERCOT.
In less than four years, Mexico’s electricity sector has been transformed from a state-run monopoly into a burgeoning marketplace where energy, capacity, financial transmission rights and clean-energy certificates are traded in day-ahead, real-time and capacity markets.
Villarreal, the deputy managing director of electric industry coordination for Mexico’s Ministry of Energy, takes understandable pride in the transformation.
“Where we are right now … that basically took Texas about 10 years,” he said during last week’s Infocast ERCOT Market Summit. “We have been working nonstop to get it where it is in only three and a half years. Yes, there are some elements missing, but keep in mind, it’s only been three and a half years.”
Key to the market’s reform, Villarreal told his audience, was the concept that Mexico “is not an isolated island,” but part of a regional market where “integration can lead to lower prices and more generation” — all of which could be quickly disrupted if the Trump administration continues to insist on building a large physical wall, or “larga barrera física,” along the border.
“It goes without saying that integrating with the United States … is, and was, an essential assumption of the reform,” Villarreal said. “But recent political changes have put that into question.”
Mexico already has five DC ties with the U.S. — three across the Texas border and two with California — with a total capacity of 1,086 MW. Another eight interconnections provide an additional 788 MW of capacity of emergency power.
Mexico-US interconnections are in two main regions: Baja California / California and Tamaulipas-Coahuila / Texas. There are 5 interconnections (1086 MW) in permanent operation; and 8 interconnections (788 MW) for emergency backup. | Mexico Ministry of Energy
Mexico’s natural gas market is just as integrated, with more than a dozen pipelines connecting with the U.S.
Noting that he is not part of Mexico’s negotiating team with the U.S., Villarreal told RTO Insider, “The idea is to find a way for both countries to keep on having a positive relationship with respect to energy trade. The underlying assumption is this will still happen.”
But Villarreal also thinks there’s now a “wild card”: Changes to the free-trade agreement between the two countries could result in “strange consequences” — such as a “very onerous” process for permitting gas exports south of the border.
The Comisión Federal de Electricidad (CFE), the government electricity monopoly, has been broken up into seven generating subsidiaries, which bid into the day-ahead market along with several international generators. Those independent producers include Spain’s Iberdrola and Global Power Generation and several new Mexican companies, and could potentially include American generators.
“Some very large [American companies] that you’re very well aware of … will be transacting in the market very soon,” Villarreal promised. He pointed out that LMPs in Mexico are double those in ERCOT, which averaged $24.62/MWh last year, and said a “very healthy price differential” has been driving flow from Texas across DC ties that are “half-used” during summer’s high demand.
Mexico’s forecasted load growth can serve as a buffer for ERCOT’s oversupply and aggressive wind program, Villarreal noted.
“It’s money lying on the floor,” he said. “Someone has to pick it up. It’s going to go away as people come into the market.”
Gas trade between the two countries is much more mature, and Mexico is a natural sink for the U.S., Villarreal said, noting that his country’s supplies are rapidly being depleted and are bedeviled by high quantities of nitrogen. As the Mexican gas market goes, so goes the electricity market: Half of the country’s generation capacity (68 GW) comes from combined cycle plants.
“If the USA no longer considers Mexico a free trade partner [under the North American Free Trade Agreement], then exports will require a public-interest review … and then an environmental review,” Singer said. “Getting a permit to export gas to Mexico today is a very simple process. Representing the Mexican government, if we can’t get that gas, it will really be problematic for the system. But it’s also really problematic for Texas.”
But Villarreal prefers a more optimistic outlook.
“I think the underlying assumption is that the gas trade between Mexico and the U.S. will continue to flourish,” he said. “No investment on the gas infrastructure has been stopped. Nobody is saying, ‘Oh, don’t build that pipeline.’ On the power side, we’re working under the assumption that gas will not stop flowing from the U.S. into Mexico.”
MISO and PJM staff broke their silence Tuesday on ongoing efforts to solve the RTOs’ pseudo-tie congestion double-counting problem.
At a Feb. 28 MISO-PJM Joint and Common Market Initiative meeting, Kevin Vannoy, MISO director of forward operations planning, said the RTOs would solve the double counting of congestion for pseudo-tied resources in the near term by providing congestion rebates, while they would develop a way to allow pseudo-ties in the day-ahead scheduling process by 2018.
The fix may also be applied to pseudo-ties between MISO and SPP.
“MISO now has over 5,000 MW of pseudo-ties in and out [to PJM and SPP] that could be subjected to this congestion overlap,” Vannoy said.
MISO and PJM said they hope to roll out the first phase of the changes by June 1. They will include accounting for market flows in market-to-market settlements so attaining balancing authorities have enough revenue to issue refunds. The congestion overlap will be addressed by allowing attaining BAs to provide congestion rebates for generators.
Beginning in June 2018, the RTOs plan to have Tariff and joint operating agreement changes in place that let pseudo-ties schedule and settle in the source BA’s day-ahead market. The day-ahead coordination will take significantly more work than the near-term rebate plan.
“Right now, the day-ahead markets in MISO and PJM might not be aligned,” Vannoy said, adding that each RTO is only aware of the other’s constraints in real time.
MISO and PJM officials acknowledged that creating a rebate process by June 1 is ambitious. “This is a very aggressive timeline. For something to be in place by June, we have to work on Tariffs and JOAs,” Vannoy said. He asked for stakeholder comments by March 7.
Both MISO and PJM staff said they could convene a special meeting to discuss the proposal before the next scheduled Joint and Common Market meetup in May.
SPP Also?
The process could also be applied to MISO and SPP’s pseudo-tied generation and load. Unlike MISO and SPP, MISO and PJM don’t share any pseudo-tied load; all pseudo-ties are generation-based. Vannoy said the proposed rules could apply to MISO and SPP’s pseudo-tied generation and load “to the extent that we can get to a solution.”
Solution to FERC Complaints
Vannoy said MISO and PJM will also discuss the proposed solutions with two municipal power agencies and a generator that have filed complaints with FERC over the double counting to “explore resolution outside FERC.”
Tilton Energy, the owner of a 180-MW natural gas generator in Eastern Illinois, filed a complaint in August arguing that MISO is violating its Tariff by assessing congestion and scheduling fees on Tilton’s pseudo-tied transactions that have already been assessed by PJM (EL16-108).
In a late December complaint, the Northern Illinois Municipal Power Agency asked for a “full evidentiary proceeding involving PJM, MISO and the numerous pseudo-tying entities being harmed by the implementation of MISO-PJM pseudo-ties” (EL17-31).
And in January, American Municipal Power asked FERC to stop PJM from collecting charges from generators pseudo-tied out of the MISO balancing authority area where congestion charges were already assessed (EL17-37).
MISO Assistant General Counsel Michael Kessler has said FERC might combine the complaints.
Asked whether the RTOs would share with stakeholders details of their discussions with the plaintiffs, MISO Managing Assistant General Counsel Erin Murphy said the current meeting’s discussion might solve the complaints.
“I can’t say that there won’t be separate discussions,” she added.
Generator Skeptical
Tilton representative Elena deLaunay asked why PJM would be the appropriate side of the double count to be refunded, saying that MISO’s congestion charges were more inappropriate for PJM-based Tilton. She asked why PJM should have to provide refunds when its congestion is in the market the generator is being settled in, is created through the market-to-market process and flows through the make-whole calculation.
“We are being dispatched into price signals on the MISO side that we can’t follow as a PJM resource,” deLaunay said.
She also said the long-term solution to solve congestion double counting may be flawed: “Forcing us to speculate on which market we will be dispatched in [day-ahead or real-time] can create additional risk rather than mitigating it.”
Vannoy said the rebate will be based on physical transmission usage charges, and not on a pseudo-tie transaction basis. He also said MISO already provides congestion rebates through financial transmission rights, so he didn’t see it as “appropriate” that the RTO would only charge once and offer rebates twice.
Stricter Rules Coming
Both PJM and MISO are also focused on introducing stricter pseudo-tie rules.
Vannoy said MISO’s more stringent pseudo-tie process will be filed with FERC in the “near term,” despite staff putting the proposal on hold to better explain it to its stakeholders. (See “RTO Delays Filing Pseudo-Tie Proposal,” MISO Advisory Committee Briefs.)
Tim Horger, manager of interregional coordination at PJM, said his RTO will soon file its own more stringent pseudo-tie rules with FERC as well. Last month, stakeholders approved more stringent rules for new pseudo-tie applications but declined to endorse them for existing pseudo-tied units. PJM announced last week that it is going to file the new rules for FERC approval for both new and existing pseudo-ties. (See PJM to Tighten Pseudo-Tie Rules Despite Stakeholder Pushback.) A first-ever PJM pseudo-tie pro-forma agreement, however, was postponed last week after stakeholder concerns.
PJM and MISO pseudo-tied 2,061 MW of transfers for the 2016/17 planning year, compared with 156 MW during the previous year.
The increased pseudo-ties have produced more congestion and brought more attention to pricing discrepancies along the border between the RTOs, which can result in revenue imbalances between RTOs and increased uplift payments in addition to the double counting of congestion. The RTOs last year said MISO would use data from December 2016 to begin an analysis of pseudo-tie congestion in mid-2017.
The RTOs will also adopt a new common interface definition beginning June 1, moving from about 1,800 nodes inside PJM to a common interface consisting of 10 nodes close to the seam. Beibei Li, of MISO’s market evaluation and design team, said the change will reduce congestion overlap.
“We’re moving from a fairly large interface definition to something closer to the seam,” Li said.
A MISO 2016 study shows the new common interface definition affects real-time and day-ahead prices by less than $5/MWh in almost all cases, she added. The interface definition change is meant to eliminate overlapping congestion pricing incentives.
“The price incentive on June 1 shouldn’t differentiate all that much,” Li said.
The RTOs have made 23 successful day-ahead firm-flow entitlement exchanges since the exchange process began in January 2016. None of PJM’s 15 requests or MISO’s eight have been refused by the other RTO. (See “Regions Begin FFE Exchanges,” MISO/PJM Joint and Common Market Meeting Briefs.)
Ted Glick, a founder of Beyond Extreme Energy, said his group and more than 130 others were inspired to act when Chairman Norman Bay resigned Feb. 3 after President Trump named Cheryl LaFleur acting chair. Bay’s departure left the commission with only two members, one short of the minimum needed to approve natural gas pipeline projects.
