MISO’s system operated as intended in June, which saw the usual early summer increase in loads, lower-than-expected natural gas prices and near-normal temperatures.
The RTO on June 13 hit a 111-GW peak for the month, 1 GW under the June 2016 peak, MISO Vice President of System Operations Todd Ramey reported during a July 25 Informational Forum. Average load was about 80 GW, up 10 GW compared with May and an expected outcome of the transition into summer, he said.
The increase in load was offset by the return of about 21 GW of generation from spring maintenance outages.
Prices averaged $29/MWh in the day-ahead market and $28.13/MWh in real time, lower than in May, where average prices for both hovered around $30/MWh. The small reduction resulted from natural gas prices averages staying below $3/MMBtu, a 7% decline from the prior month, Ramey said.
| MISO
Two events caused real-time prices to deviate sharply above the day-ahead during the month, including a forced transmission outage in Louisiana on June 19 and a June 23 “contingency-related” event affecting the entire system.
While conditions in June were largely in line with norms, the MISO footprint experienced stresses from a mid-July heatwave that likely affected price and load, which will be reflected in the RTO’s July operations report, due out later this month.
“We just came off a week where parts of the footprint experienced some pretty extreme conditions,” CEO John Bear said.
Bear commended MISO control room staff and generation operators for successfully managing the high summer heat. He attributed smooth operations to the training and skill of operators.
Indianapolis Power and Light’s Lin Franks asked if MISO is considering turning to a dual-peak model using separate winter and summer dual peaks. The RTO currently models its peak using only summertime conditions.
“We have seen a narrowing of the gap between the summer peak and the winter peak,” Ramey said. “We observed that a couple of years ago in the polar vortex” and continue to see it, he said, adding that MISO staff may consider modeling the separate peaks.
The PJM Board of Managers on Wednesday approved about $417 million in reliability-related transmission projects, more than half of which will go to Public Service Electric and Gas to replace a substation in downtown Newark, N.J.
Newark Switch property exterior | PJM
“The board’s approval of these projects reinforces both PJM’s fundamental mission of preserving reliability and the value of PJM’s independent assessment of transmission needs,” CEO Andy Ott said. “Planning is evolving in PJM to consider impacts of new trends. However, studying and planning for reliability remains the top priority.”
The PSE&G substation rebuild is expected to cost ratepayers $275 million. A new gas-insulated substation will be built adjacent to the existing station, which will be torn down. (See “New Proposal Shaves $78M from PSE&G Switch Fix,” PJM Planning Committee and TEAC Briefs.)
Newark Switch property interior | PJM
The board also approved projects for American Electric Power, Dominion Energy, Atlantic City Electric, PECO Energy, Pennsylvania Electric, American Transmission Systems Inc., East Kentucky Power Cooperative, Exelon Generation and Dayton Power & Light. Most projects are estimated to cost less than $5 million, but a 31-mile reconstruction of a 230-kV line in Dominion’s territory is expected to run $31 million. Two ATSI reconductor projects are estimated at a combined $33.43 million.
NextEra Energy CEO Jim Robo said Wednesday that the Florida-based company would “vigorously” pursue a $275 million termination fee it says it is owed following a failed attempt to acquire Texas utility Oncor.
The Public Utility Commission of Texas in April ruled that NextEra’s $18.7 billion acquisition of the state’s largest utility wasn’t in the public interest, and then rejected two subsequent rehearing requests. Warren Buffet’s Berkshire Hathaway Energy has since announced it has reached an agreement to buy Oncor’s parent, bankrupt Energy Future Holdings (EFH), which would give it control of Texas’ largest utility. (See PUCT Staff Welcomes Buffett’s Oncor Bid; Debtor Miffed.)
During a conference call with financial analysts following the company’s release of second-quarter earnings, Robo said the termination fee was triggered when NextEra was unable to agree to a list of what it called “burdensome conditions,” which included protective ring-fencing around Oncor and an independent board of directors for the company.
“The agreement has been terminated by EFH … in that the burdensome conditions had not been satisfied, which was one of the precursors to obtaining regulatory approval,” Robo said. “As a result of the termination of merger agreement, we will vigorously pursue our rights to termination of the fee.”
NextEra has also filed a lawsuit in Texas state court against the PUC, asking the court to reverse the regulators’ rejection of the proposed acquisition. Robo declined to address the lawsuit, saying the petition it filed “speaks for itself.” (See “NextEra Sues over Regulators’ Rejection of Oncor Acquisition,” Company Briefs.)
Asked about the Department of Energy’s grid reliability study and its focus on baseload power, Robo said it was too early to speculate about the final report’s conclusions. He said the “data is pretty clear” that the grid does not have any reliability issues.
“The facts are, the grid is very reliable in America right now, particularly as storage prices come down and make renewables more reliable,” he said. “Our industry has a choice of hanging on to the techs of the past or adopting and embracing the technology of the future. We know what our strategy is. We’re going to embrace renewables and embrace them hard.”
NextEra reported an 11% increase in adjusted earnings during the second quarter, from $777 million last year to $881 million this year. Earnings per share were $1.86, up from $1.67, beating Nasdaq’s consensus analysts’ forecast of $1.76.
The company’s stock price jumped almost 2%, from $142.62/share to $145.35/share, after the market opened. It was trading at $144.94/share by late afternoon.
WASHINGTON — RTO officials acknowledged Wednesday that they are challenged by low power prices and a shifting generation mix but insisted they are up to the task, asking Congress not to abandon its support of wholesale markets.
“Although debate on various market rules is perfectly appropriate, we caution against the potential to add greater uncertainty to the markets by signaling some kind of wholesale retreat from the competitive market model that has been in place since the mid-1990s and has worked well to keep prices low and investment certain,” Craig Glazer, PJM’s vice president of federal government policy, told the House Energy and Commerce Committee’s Subcommittee on Energy.
“The markets are working very well,” agreed SPP CEO Nick Brown, who said his RTO provides net benefits of more than $1.7 billion annually — a benefit-cost ratio of 11:1, he said. MISO provided $3 billion in benefits last year and $18 billion over the last decade, said Chief Operations Officer Richard Doying.
Representatives from all six FERC-regulated RTOs and ISOs appeared along with an ERCOT executive at the nearly two-and-a-half hour hearing, the third in a series of fact-finding sessions that began last year with a letter to FERC and a hearing in September on the 1935 Federal Power Act. On July 18, the committee heard from stakeholders representing public power, independent power producers and integrated utilities. (See Public Power Takes PJM Gripes to Congress.)
A Republican committee aide, speaking on background, said the bipartisan hearings will resume after the August recess. Although some witnesses and committee members at last week’s hearing called for changes to the 1978 Public Utility Regulatory Policies Act, “consistently what we’ve heard is that there’s no immediate need” for changes in the FPA, the aide said.
The aide said, however, that the May 1-2 FERC technical conference on tensions between wholesale markets and out-of-market procurements and subsidies “got more attention [from House members] than any other technical conference in recent history.”
Criticism Nothing New
As at the technical conference and the July 18 House hearing, much of the focus was on PJM, NYISO and ISO-NE, the three eastern grid operators facing the most acute challenges from state policies.
PJM has perhaps the toughest challenge of the three grids in threading the needle between stakeholders pushing for supports for coal and nuclear “baseload” power and efforts to insulate the markets from price suppression. Unlike the single-state NYISO and the environmentally activist New England states, PJM’s footprint is particularly diverse, encompassing both consumer choice states and traditional, vertically integrated states; only some states have renewable portfolio standards; some states are coal producers, while others are heavily reliant on nuclear power.
But Glazer, a former Ohio utility regulator and PJM’s longtime voice in D.C., said the conflicts are nothing new for the RTO. “The PJM markets have weathered many challenges to the industry, ranging from the impact of EPA’s Mercury and Air Toxics rule on the coal fleet to the threats of cyberattacks on the grid itself. We are stronger as a result and are confident that innovative market-based solutions, which have been the hallmark of PJM since its inception, can continue to serve us well in addressing our new set of 21st century challenges.”
He appealed to his congressional inquisitors by holding up photos of new generation in several of the committee members’ districts.
On several occasions, he attempted to rebut criticism by public power providers who say their self-supply option has been eroded since the settlement that created PJM’s capacity construct. Lisa McAlister, senior vice president and general counsel of regulatory affairs for American Municipal Power, told the committee July 18 that PJM rule changes “have stripped away guaranteed clearing for self-supply.”
Glazer cited 1,375 MW of new generation or uprates to existing public power-owned generation since the inception of the capacity market. The RTO has added more than 46.5 GW of new generation over the same period.
The order “did not overturn the specific agreed-to arrangement that PJM and its stakeholders worked out with public power entities,” Glazer said. “As a result, the right to self-supply in our capacity market and energy market has been negotiated with public power and fully honored by PJM and its stakeholders. To suggest otherwise is simply not consistent with those facts.”
“Absolutely, we have self-supply today,” Glazer reiterated in response to a question from Rep. John Shimkus (R-Ill.). “We have no intention of changing that.”
But Glazer rejected public power’s call to abandon the capacity market and use bilateral contracts to fill most of its capacity needs, saying it would eliminate price transparency.
Glazer had an exchange with Rep. Morgan Griffith (R-Va.), who complained that coal-fired generation was “under severe assault.” Glazer said PJM’s proposal that FERC change its price formation rules “to better recognize the attributes that key generators — including those which have come to be labeled ‘baseload generation’ — bring to the grid” would provide financial help for struggling coal plants. He said the proposed changes would “ensure that all resources needed to serve load are able to set wholesale prices.”
But he rejected Griffith’s claim that stranded costs resulting from premature coal plant retirements were falling on ratepayers. “We moved to the markets to try to not put it all on the backs of the customer,” he said.
Ranking member Frank Pallone (D-N.J.) took PJM to task for what he called excessive transmission spending and a lack of transparency in the RTO’s Regional Transmission Expansion Plan. Glazer noted that the Transmission Expansion Advisory Committee meetings are open to the public and sought to distinguish PJM’s role from that of state siting authorities. “Maybe we need to do more to reach out,” he offered.
ISO-NE CEO Gordon van Welie recalled his testimony before the committee in March 2013, when he cited the “serious operational challenges” facing New England because of its changing generation mix.
“As New England has increased its reliance on natural gas [since 2013], we have not seen a corresponding increase in the region’s natural gas transportation and storage infrastructure, which is currently stressed to meet demand for natural gas for both home heating and power generation during the coldest weeks of the year,” he said. “The shift from power plants with on-site fuel supply (e.g., oil, coal and nuclear) to plants relying on the natural gas transportation network to deliver fuel when needed has exposed the limitations of New England’s fuel infrastructure system and highlights the challenge of securing fuel in advance of power system demands.”
Van Welie said the RTO has concluded that the Pay-for-Performance capacity incentives developed in 2013 “may not be sufficient to ensure fuel security during the winter” because of opposition to siting dual-fuel facilities and tighter emission limits that restrict the amount of time generators can operate on oil. That, he said “is likely to create greater dependency” on LNG imports.
NYISO CEO Brad Jones briefed members on the ISO’s proposed transmission expansions to connect upstate renewables to downstate loads and its plan to incorporate carbon prices in its energy market — a response to the zero-emission credits approved for three upstate nuclear plants. (See New York ZEC Suit Dismissed.)
The ISO said it expects to release The Brattle Group’s report on the carbon plan within two weeks. That, Jones said, will be the basis for discussions with market participants and state officials. He said the ISO hopes to implement the plan in the markets within three years.
Unlike the other grid operators, ERCOT is still seeing strong load growth, said Chief Operating Officer Cheryl Mele. After growing at 2% annually in recent years, ERCOT expects annual growth of 1.5% for the next five years.
One thing it does have in common with the other regions: Low energy prices are pinching the finances of thermal and nuclear units. “We also have seen that, for several years, investors and unit owners of every type of generation were watching to see if there would be federal environmental policies that would materially affect their investments or retirement strategies,” Mele said. “That conversation has since changed. Nevertheless, aside from regulatory concerns, ongoing changes in the generation resource mix and market dynamics may have major impacts on potential unit retirement decisions.”
Keith Casey, CAISO’s vice president of market and infrastructure development, told the committee the effects of low power prices — which have sparked calls for nuclear and coal subsidies in the eastern markets — also have led “conventional” plants in California to request “backstop” contracts to maintain their financial viability. (See CAISO Stakeholders Question Risk-of-Retirement Initiative.)
Casey, too, defended the markets. “We have almost 20 years of operating experience and have evolved our markets since the Western Energy Crisis occurred 17 years ago,” he said. “Consequently, the California ISO’s electricity markets have matured significantly and are in far better shape now than they were then to serve electric demand in an efficient and reliable manner. Indeed, our success has encouraged other transmission providers in the West to join our real-time energy market and form the Western Energy Imbalance Market.”
Connecticut Gov. Dannel Malloy on Tuesday ordered state regulators to assess the economic viability of the Millstone nuclear power plant and determine whether the state should provide it financial support. Millstone supplies about half of Connecticut’s electricity.
The Connecticut General Assembly in June failed to pass a bill that would have allowed the 2,111-MW nuclear plant in Waterford to bid into the state procurement process (S.B. 106). Millstone owner Dominion Energy had sought the legislation to boost the plant’s revenues, which have suffered from low-priced natural gas. Gas-fired generators often set LMPs in New England.
Malloy’s executive order also directs the state Department of Energy and Environmental Protection and the Public Utilities Regulatory Authority to assess the role of large-scale hydropower, demand-reduction measures, energy storage and emissions-free renewable energy in helping Connecticut meet its ambitious targets to cut its carbon output.
The state’s Global Warming Solutions Act of 2008 mandates cutting greenhouse gas emissions to 10% below 1990 levels by 2020, and to 80% below 2001 levels by 2050.
Show us the Books
The governor’s July 25 order directed DEEP and PURA to use “the best available information, including such facilities’ audited financial statements and such other financial data that is reasonably requested by [regulators]” in their economic analysis of Millstone.
Matt Fossen, spokesman for the Stop the Millstone Payout coalition, said “it is essential that Dominion fully disclose the plant-level financials of Millstone; otherwise the investigation won’t be truly comprehensive or accurate.”
The coalition — sponsored by competitors Calpine, Dynegy and NRG Energy and the Electric Power Supply Association (EPSA) — had argued S.B. 106 would be a burden on ratepayers and an unnecessary handout to a power plant that had not been proven to be unprofitable.
The group in April released a study by energy consultancy Energyzt that showed the Millstone plant has earned at least $3 billion in profits since Dominion bought it in 2001 and will likely earn an additional $2.2 billion in after-tax income from now through 2030. Dominion spokesman Ken Holt criticized the Energyzt report as “loaded with gross assumptions and preposterous claims, with no real data.” (See Millstone No Dead Weight for Dominion, Says Opponents’ Study.)
New York ZEC Suit Dismissed
The legislation would have made Millstone the only eligible nuclear generator in Connecticut’s competitive bidding process and awarded it a five-year contract if it bid lower than competing renewable resources. The bill would have set an annual limit on nuclear energy purchases at 8.3 million MWh, equivalent to half of Millstone’s output.
The Connecticut measure would have been similar in effect to the zero-emission credit programs that EPSA and its members are contesting in New York and Illinois.
EPSA and its members in Illinois on July 17 filed an appeal with the 7th U.S. Circuit Court of Appeals. They argued they stood to lose millions because the subsidized nuclear plants would suppress capacity and energy prices. The plaintiffs are expected to also appeal the New York decision to the 2nd Circuit.
PJM’s Independent Market Monitor last week filed a complaint with FERC requesting fast-track revocation of the RTO’s decision to exempt a generator from a rule meant to combat market manipulation.
The complaint said PJM was “incorrect” in providing an unnamed generating unit with a competitive-entry exemption from the minimum offer price rule (MOPR).
The RTO developed the MOPR to prevent subsidized units from suppressing market prices by offering bids that are below a unit’s competitive operational costs. The rule creates a price floor at which all new units must offer into the market unless they receive one of three types of exemptions from PJM. The competitive-entry exemption allows a unit to offer in at any bid, provided the generator can prove it receives no direct or indirect subsidies. (See PJM: No Change on MOPR Yet; Remand May Have Little Impact.)
“The stakes in this case are high. This generation is clearly not merchant generation, is clearly not competitive generation and represents exactly the type of subsidized generation that the MOPR was intended to address,” the complaint said.
The complaint asks FERC to rescind the exemption before the generator submits “a noncompetitive offer” into any of PJM’s Reliability Pricing Model auctions. The RTO holds annual Base Residual Auctions for capacity required three years into the future, along with incremental auctions each year leading up to the delivery year.
The Monitor declined to name the exempted generator to avoid disclosing market-sensitive information, but it described it as “a non-regulated company wholly owned by a parent company that wholly owns a regulated, vertically integrated electric utility.” The Monitor told both the generator and PJM that the generator wasn’t eligible for the exemption because it indirectly recovers costs from customers through a non-bypassable charge, according to the complaint.
Because the generator’s construction was financed entirely by the parent, the cost of capital was lower than if the generator’s operating company had sought financing on its own, the Monitor said, and that difference is the cost the generator indirectly recovered from customers through a non-bypassable charge.
However, PJM still granted the exemption.
The Monitor contended that allowing an exemption in this situation “would create a significant loophole” in the MOPR that would render it “ineffective” in similar situations because the unit is not “purely a merchant resource” as the exemption rule requires.
“Competitive market participants who invest in new generating facilities without the backing of a regulated utility or other nonmarket support” receive “essential protection” from the MOPR and would be “inappropriately disadvantaged” by the loophole, the complaint argues.
The issue was amplified by a July 7 decision from the D.C. Circuit Court of Appeals that vacated PJM’s current MOPR provisions and remanded the order back to FERC. Among the topics at issue is one of the three MOPR exemptions, which PJM and its stakeholders had jointly requested that FERC eliminate.
If FERC reverses its position and now decides to approve the request, that would make having an exemption more advantageous and the precedent of an approved loophole more problematic, the IMM said. There would be just two exemption types, and the second — known as the “self-supply exemption” — is very limited.
“This would enhance the need for an effective MOPR and correct application of categorical exemptions to the MOPR,” the complaint argues. “If the requested application of the competitive-entry exemption were approved, it would provide an easy way to avoid the defined limits on the self-supply exemption that applies to regulated utilities and to the utility in this case.”
Southern California Gas Co.’s Aliso Canyon gas storage facility resumed injections Monday, despite Los Angeles County officials’ request that a state appeals court prevent the reopening.
“SoCalGas must begin injections to comply with the [state’s] directive to maintain sufficient natural gas inventories at Aliso Canyon to support the reliability of the region’s natural gas and electricity systems,” the company said in a statement sent to Porter Ranch residents, according to the Los Angeles Times.
Following a series of back-and-forth court rulings over the weekend, the county filed a petition with the 2nd District Court of Appeal for a stay preventing gas withdrawals until more analysis is done. A judge on Saturday ruled that operations can resume.
The volley of court actions occurred after the California Division of Oil, Gas and Geothermal Resources (DOGGR) issued an order July 19 allowing SoCalGas to resume injections into the facility. The county does not object to withdrawals on an emergency basis, which is currently allowed.
Location of Aliso Canyon Storage Facility
The county wants the court to forestall any withdrawals until it can determine whether DOGGR complied with the law in clearing the facility to resume operations. SoCalGas refused the county’s request.
“Before the prohibition on injections can be lifted, SoCalGas must show — and DOGGR must determine — that all necessary steps to ensure the safety of the facility have been completed,” the county said in its original filing in Los Angeles County Superior Court last week. Conditions have not been met regarding a risk-of-failure review and emergency response plan, the county contended.
Withdrawals were halted at the facility following the massive methane release there, detected in October 2015 and finally plugged in February 2016. DOGGR and other state agencies recently issued findings that it is safe to resume withdrawals. (See California Officials: Aliso Canyon Safe to Open.)
The court filing says county officials met with DOGGR and SoCalGas on July 20, when the company refused to refrain from withdrawals and to disclose when they would resume. SoCalGas did not immediately return a request for comment.
Residents near Aliso Canyon still report health problems they say are related to the leak, including headaches, nosebleeds and nausea. A few dozen residents recently protested resuming gas withdrawals in roadside gatherings reported on local news stations.
Aliso Canyon protest | Food and Water Watch
California Energy Commission Chairman Robert Weisenmiller and Gov. Jerry Brown have asked for the state to explore permanent closure, and the California Public Utilities Commission has a proceeding underway that is analyzing whether the facility is needed for system reliability. (See Study to Weigh Aliso Canyon Shutdown.)
On July 19, SoCalGas issued a statement that it has completed the state’s required safety reviews and has implemented a host of safety measures and procedures. The company argues that loss of the facility will create reliability problems in times of severe weather and peak electricity usage.
The county also argues that there is a risk of gas leaks caused by seismic activity in the area, which is prone to earthquakes. “DOGGR and SoCalGas have acknowledged the well-known and very serious risk of a catastrophic earthquake shearing multiple wells at Aliso Canyon,” county officials said.
Although the appeals court did not issue a stay, Deputy County Counsel Scott Kuhn told the Times on Monday that the courts have yet to rule on the county’s request that the state complete their analyses before continuing injections. “We hope that some court will get to the merits and when they do get to merits, they will see that further study of the seismic risk and the environmental risk is necessary before [the utility] can proceed with business as usual,” Kuhn said.
A federal judge on Tuesday dismissed all claims in a suit against New York’s zero-emissions credit program, the second such victory for state nuclear subsidies after a complaint over the Illinois ZEC program was thrown out July 14.
Judge Valerie Caproni of the U.S. District Court for the Southern District of New York granted motions to dismiss the case from the Public Service Commission, the defendant, and intervenor Exelon, owner of the three New York nuclear plants that would receive ZEC payments (16-CV-8164).
“Although no individual state can reverse the trend all by itself, New York and many other states have decided that they will do their part to reduce the emissions that contribute to global warming,” Caproni said. “The issue in this case is whether the method New York has chosen to facilitate its doing so is constitutional. … The court concludes that the New York [ZEC] program is constitutional.”
Her 47-page decision rejected every one of the plaintiffs’ arguments, including claims that the program intruded on FERC’s authority to regulate wholesale prices, and that New York violated the Constitution’s dormant Commerce Clause by favoring in-state generators.
The Electric Power Supply Association (EPSA), which filed the New York challenge with several members, said it will appeal the ruling. “We’ll continue to fight these nuclear bailouts, which cost ratepayers billions, crowd out investments in true renewables, and distort and could eventually destroy the established wholesale power markets,” said David Gaier, spokesman for EPSA member NRG Energy. On July 17, EPSA and its members appealed the dismissal of the Illinois suit to the 7th U.S. Circuit Court of Appeals. (See Illinois Zero-Emission Credit Suit Dismissed.)
Affirmation of CES
Gov. Andrew Cuomo praised Tuesday’s ruling in a statement: “The court forcefully ruled that the Clean Energy Standard (CES) and its zero-emissions credit program are valid tools to use to combat climate change. At a time when the federal government has abdicated its leadership on climate change, New York will continue to do all that we can to ensure that current and future generations have a clean and safe environment in which to live and prosper.”
The ZEC program, initiated as part of the CES last August, requires utilities in New York to procure ZECs that are generated by Exelon’s three in-state nuclear power plants. The PSC claimed that the program helps avoid the closure of the upstate nuclear plants, which the state needs to meet its goal of reducing carbon emissions and having 50% of energy produced by renewable resources by 2030.
Nine Mile Point Nuclear Plant | Constellation Energy Nuclear Group
EPSA, and members Dynegy, Eastern Generation and NRG Energy, joined Roseton Generating and Selkirk CoGen Partners in arguing they would lose millions because the subsidized nuclear plants would suppress capacity and energy prices.
Caproni used colorful language to frame her decision, citing President Trump’s description of climate change as a “hoax” and paraphrasing a famous line from “Romeo and Juliet”: “A rose by any other name still smells as sweet.”
On the plaintiffs’ argument that the ZEC program is directly tied to NYISO’s wholesale markets, Caproni said: “This argument is no more than an attempt to fashion a ‘tether’ by jamming a square peg into a round hole; plaintiffs’ argument rewrites the CES order. The CES order itself does not require the nuclear generators to sell into the NYISO auction.”
The Illinois and New York decisions are the latest in a string of federal court cases testing the boundaries between state and federal jurisdiction over electricity markets.
“Under current law, states have broad authority to advance a cleaner electric grid,” said Ari Peskoe, senior fellow in electricity law at Harvard Law School, who tracks constitutional challenges to state energy policies. “If courts rule against the states on appeal, their decisions might limit the scope of future state clean energy programs.”
MISO will begin using its Transmission Expansion Plan dispatch modeling in interconnection queue studies beginning Aug. 1, when the first cycle of definitive planning phase (DPP) studies is set to begin.
“The decision to move to a new methodology was my decision, so if you want to throw tomatoes, it’s me,” Patrick Brown, executive director of transmission asset management, said at a July 18 Interconnection Process Task Force (IPTF) meeting.
The new method moves MISO from modeling dispatch at a generator’s expected level of output to its maximum requested interconnection service level.
The decision made sense because the models are already “well vetted through the stakeholder process” and used for NERC reliability assessments, according to Brown.
“It’s hard for me to explain why we weren’t already using them in the interconnection process,” Brown said.
Great River Energy’s Mike Steckelberg pointed out that the dispatch question runs into an issue of reliability and therefore should be put before another committee. “You can’t really implement that without putting it to the Planning Subcommittee,” he said.
Planning Advisory Committee Chair Cynthia Crane said the change should be presented to her group. “This is a policy-level change that should be brought forward to the PAC,” she said. Wisconsin Public Service’s Chris Plante agreed.
Brown said the change will be presented to the PAC at the August meeting. “As far as it being a policy change … MISO has the purview to develop the models as we see fit,” he added.
Michigan Public Service Commission staffer Bonnie Janssen said she appreciated MISO’s effort make interconnection and MTEP modeling consistent with each other.
Entergy’s Yarrow Etheredge said the RTO is not allowing enough time for local transmission owners to adjust their planning criteria and suggested a stakeholder workshop on adopting the new methodology.
MISO Director of Resource Utilization Vikram Godbole said local planning criteria would be unchanged.
“We’re only changing the starting point of a study. Nothing else,” he said. “Is it a perfect solution? I don’t know. It’s a step in the right direction to accommodate all new queue generators.”
Interconnection Rights Transfer
MISO is also mulling how it should allow generator owners to retain and transfer interconnection rights when retiring older generation and building new units.
MISO engineer Brett Furuness said the RTO and stakeholders could pursue a “nuclear” option that would entirely prohibit the practice, requiring interconnection rights to be “released back into the wild” to other takers in the interconnection queue.
But MISO is instead proposing to implement rights transfer based on an interconnection request and out-of-cycle study. Any unused rights found after the study will be “permanently relinquished,” and the RTO would initiate a full DPP study cycle if it finds a significant change between the original and replacement generation, which must use the same point of interconnection and commence operation within three years.
The three-year timeline is important because it aligns with the maximum amount of time allowed for a generator suspension, Furuness said.
Some stakeholders questioned the three-year limit, pointing out that it can take longer to build new generation.
Furuness agreed that resource owners actively working through a construction plan would probably be given more time than an owner with a less distinct plan.
“But that’s about step 700, and we’re at step 2 here,” Furuness said.
IPTF Future
During its July 26 meeting, MISO’s Steering Committee will decide whether to extend the life of the nearly four-year-old IPTF until December or convert it into a working group. The IPTF was supposed to sunset this month, but PAC members voted in June for an extension. As part of the RTO’s stakeholder redesign, all task force sunsets or extensions are put before the Steering Committee for final approval.
SAN DIEGO — CAISO expects new aggregated distributed energy resources to enter its markets this year, creating new technical and regulatory challenges as the grid operator works to integrate them without affecting reliability.
Industry officials discussed the development in detail at a July 17 panel at the National Association of Regulatory Utility Commissioners Summer Policy Summit.
FERC in June 2016 conditionally approved CAISO’s proposed rules to allow aggregated resources to participate in the wholesale markets. (See CAISO Tariff Change Would Extend Market to DER.) Later in November, the commission also issued a separate Notice of Proposed Rulemaking (RM16-23, AD16-20) that would allow DER to participate in other wholesale electricity markets across the country.
AES energy storage facility | SDGE
CAISO is ironing out implementation policies so that DER aggregators can begin operating in its markets this year. DER aggregators can be generators, load-side participants, storage devices or a mixture, and they can also participate as scheduling coordinators that distribute CAISO dispatch instruction from their individual energy sources.
DER is dispatched without knowledge of the exact impact on grid operations, and the effect on the system is difficult to quantify because of many different interconnections and ways to connect, said Mark Esguerra, director of integrated grid planning for Pacific Gas and Electric. It also requires more coordination between the transmission and distribution system operators.
Visibility into DER behavior “is something we are trying to wrap our arms around,” Esguerra said, adding that DER “creates new operational challenges that we all have to consider here.”
Manal Yamout, vice president of policy and markets for Advanced Microgrid Solutions, said DER can provide a suite of services at the transmission and distribution levels. The company is developing 50 MW of DER with Southern California Edison, among other projects.
“This is happening now,” she said, saying the discussion around DER is often conceptual or forward-looking. “Even though this might seem far away … these projects are here, and in many ways, we are kind of breaking down the barriers as we go. … This isn’t just about California.”
DER is often discussed in the context of balancing intermittent renewables, but they can also provide capacity, ancillary services, resource adequacy to the utility and demand-side management to energy customers, Yamout said.
D.C. Public Service Commissioner Willie Phillips said he is often asked about the reliability impacts of DER and aggregation.
Esguerra said that reliability officials are looking at the integration of DERs, and that there is an ongoing shift from the central power station model.
“I think there is work that still needs to be done, in terms of certifications and standards,” if the grid is going to rely more on DER, Esguerra said.
So far, Apparent Energy, Galt Power, Olivine and San Diego Gas & Electric have applied to become DER providers in California, according to CAISO.
