Illinois’ nuclear generation subsidies do not interfere with FERC-regulated wholesale power markets, the 7th U.S. Circuit Court of Appeals ruled Thursday in the latest judicial pronouncement on state-federal jurisdiction over the electric industry.
The 7th Circuit ruling in Electric Power Supply Association v. Anthony M. Starr upheld a July 2017 district court ruling and was consistent with an amicus brief by FERC that said the Illinois zero-emission credits program did not violate the Federal Power Act. Starr is director of the Illinois Power Agency. (See Analyst: FERC Asserts Role in Handling Nuke Subsidies.)
Exelon’s Clinton nuclear facility, which benefits from Illinois’ zero-emissions credit program. | Nuclear Regulatory Commission
The court’s opinion cited the Supreme Court’s 2016 Hughes v. Talen ruling, in which the court rejected Maryland regulators’ attempt to subsidize a combined cycle plant, saying that the state’s contract for differences — which required the generator to bid into and clear the PJM capacity market — could distort prices. The court cautioned that its opinion should not “be read to foreclose [states] from encouraging production of new or clean generation through measures ‘untethered to a generator’s wholesale market participation.’”
“And that’s what Illinois has done,” the 7th Circuit said Thursday. “To receive a credit, a firm must generate power, but how it sells that power is up to it. It can sell the power in an interstate auction but need not do so. It may choose instead to sell power through bilateral contracts with users (such as industrial plants) or local distribution companies that transmit the power to residences.”
EPSA had contended that the ZEC program infringed on FERC’s jurisdiction by indirectly regulating interstate energy markets by using average auction prices as a component in a formula that affects the cost of the ZECs. But the court said the value of ZECs does not depend on the generators’ auction offers.
“Every successful bidder in an interstate auction receives the price of the highest bid that clears the market. The owner of a credit receives that market‐clearing price, with none of the adjustments that Maryland law required,” the court wrote. “The zero‐emissions credit system can influence the auction price only indirectly, by keeping active a generation facility that otherwise might close and by raising the costs that carbon‐releasing producers incur to do business. A larger supply of electricity means a lower market‐clearing price, holding demand constant. But because states retain authority over power generation, a state policy that affects price only by increasing the quantity of power available for sale is not preempted by federal law.”
The court also rejected claims that Illinois’ program violated the dormant Commerce Clause, saying “the cross subsidy among producers may injure investors in carbon-releasing plants, but only those plants in Illinois (for the state’s regulatory power stops at the border).”
The court noted FERC’s June ruling requiring PJM to change its minimum offer price rule to address capacity market price suppression from state subsidies for renewables and nuclear power. (See FERC Orders PJM Capacity Market Revamp.)
EPSA had contended that FERC’s ruling was proof that the Illinois statute must be pre-empted. “But that’s not what the commission said,” the court noted. “Instead of deeming state systems such as Illinois’ to be forbidden, the commission has taken them as givens and set out to make the best of the situation they produce.”
EPSA said it was reviewing the order and hadn’t decided whether to seek a Supreme Court review. A similar court challenge is pending in the 2nd Circuit over New York’s ZEC program. (See 2nd Circuit Hears New York ZEC Appeal.)
“Today’s decision confirms that state subsidy programs such as nuclear bailout ZECs can harm wholesale markets,” EPSA said in a statement. “FERC told the 7th Circuit the commission can mitigate these negative effects and today’s opinion relies on that representation. EPSA now expects FERC to act promptly in the pending PJM capacity market docket to prevent the acknowledged harms state ZEC programs inflict on federally-regulated wholesale power markets.”
Analysts at ClearView Energy Partners issued a research note Thursday predicting the 2nd Circuit will also uphold the New York ZECs. “If the ZEC’s opponents seek review at the U.S. Supreme Court (via a petition for a writ of certiorari), we think they face an uphill battle,” ClearView said.
The analysts acknowledged however, that the 2nd Circuit’s rejection of the New York ZEC program “could meaningfully improve the prospects for Supreme Court review” to resolve the split rulings.
TEMPE, Ariz. — The Western Electricity Coordinating Council’s effort to clarify its mission will no longer include a name change, the group’s new chief said Wednesday.
Under previous CEO Jim Robb, WECC last year revived a proposal to change its name to “Reliability West” as part of a broader campaign to rebrand its image to reflect its refocus on its core reliability assurance mission after the 2014 bifurcation that divided WECC in its current form from what would become reliability coordinator Peak Reliability. (See WECC Finding New Direction in Old Mission.) The business case for the name change was set out in a November 2017 white paper.
The WECC Board of Directors tabled the name change in June after an advisory vote among the group’s members and also in light of WECC’s continued search for a replacement for Robb, who left his role to take over the top post at NERC. (See NERC Names WECC Chief to Top Post.)
“The rationale for the name change had some substantive content to it,” Chair Kris Hafner said during a quarterly meeting of the WECC board Sept. 12. “It was thought to basically bring to closure any lack of clarity posed by bifurcation and the respective roles of Peak and WECC and to avoid any role confusion.” That latter point became “a moot issue” after Peak’s July announcement that it would cease operations at the end of 2019, she noted. (See Peak Reliability to Wind Down Operations.)
“The hope Jim Robb had was to recast WECC in light of its new mission, to remove the ‘coordinating’ term from its name to avoid confusion with reliability coordinator — or planning coordinator,” Hafner said.
She added that brand clarity was another factor driving the change, given that other organizations share the WECC acronym, particularly the Wisconsin Energy Conservation Corp., which operates in four Western states in the electric power space.
Despite those issues, it turns out WECC’s name will remain unchanged.
Frye | WECC
“I appreciate the decision that the board made back in June, coming in as a new CEO to have an opportunity to be part of the conversation that I think is really thoughtful,” new CEO Melanie Frye told the board. “I think that it makes sense at this time to not proceed with a WECC change in name, but to do some things … to mitigate the risks and those things that we identified in the business case.”
Key among those things: changing the organization’s web address from a .biz to a .org to reflect its status as a non-profit.
“With that it would give us the opportunity to refresh the brand — the look and feel when someone visits our webpage, and know that they’re dealing with a reliability organization, not a conservation council,” Frye said, adding that WECC could refresh its logo and color palette in what that would “really identify and distinguish ourselves” from the other “WECC” entities. It would also build relationships with those organizations to handle situations when correspondence is misaddressed to them, she said.
Frye also suggested that WECC’s rebranding emphasize use of the shorthand version of its name, rather than the spelled-out version.
“I think the goal would be to not divert focus from our staff or from the industry in trying to address any change of name of the organization,” Frye said.
She told board members she would report back to them in December on any progress staff make in addressing the issues identified in the name change business case, and how they plan to proceed in 2019.
MISO hopes to become more customer- and employee-focused in 2019, unveiling plans for a new feedback tool, a data gathering project and a new committee.
The RTO plans to create a Customer Experience Steering Committee next year that will examine customer perceptions of it and explore improvements it can make in interacting with them. It has yet to decide who will sit on the committee.
MISO also said it will create and introduce a “Voice of the Stakeholder” program to gather both customer and employee opinions. Senior Vice President and Chief Customer Officer Todd Hillman said MISO plans this year to begin “journey mapping” — collecting data by following customer requests or comments from submittal to the RTO’s response and eventual outcome. MISO has hired management consulting firm West Monroe Partners to assist on the project.
Hillman said MISO will create a “centralized platform” for capturing feedback from customers and employees to transform itself from a “service provider to a collaborative entity to a trusted RTO adviser and partner.” Speaking during a Sept. 11 conference call of the Corporate Governance and Strategic Planning Committee of the Board of Directors, Hillman said MISO will eventually examine and rank customer- and employee-experience improvements similarly to how it uses the Market Roadmap process to set priorities for market improvements.
MISO Director Mark Johnson asked if stakeholders will really offer ideas using the Voice of the Stakeholder program.
“They’re actually eager to provide the feedback, but the mediums we provide are limited,” Hillman responded. “We need to make this more routine.”
Hillman also said MISO’s current employee feedback tool was put in place in the early 2000s and is now “feeble.”
“There’s nothing more dangerous than asking employees what they think and not being able to act on it,” he added.
Meanwhile, MISO is circulating a survey through Sept. 26 to identify possible improvements on its current customer training process.
CARMEL, Ind. — The Resource Adequacy Subcommittee has allowed MISO to use last year’s capacity export limit for Missouri’s Zone 5 after the RTO could not identify the limit.
MISO recently released zonal capacity import and export limits from this year’s loss-of-load-expectation study but said it could not find transmission constraints or a capacity export limit for Local Resource Zone 5. In its place, the RASC by consent allowed the Loss-of-Load-Expectation Working Group to use last year’s 2,122-MW export limit for the zone in the 2019/20 Planning Resource Auction.
MISO’s capacity export limits determine a local resource zone’s export capability on transmission for the PRA. When MISO cannot determine a transmission limit, it uses a generation-limited transfer study, which simulates further stressing of the transmission system after the RTO hypothetically runs out of generation to dispatch in the zone. The study is meant to discover whether a zone’s first transmission constraint would occur only after all the zone’s generation is dispatched at maximum levels.
In Missouri’s Zone 5 this year, no constraints were found even after the generation limited transfer study, said Laura Rauch, MISO director of resource adequacy coordination.
“We did run into an issue with Missouri capacity export limit,” Rauch told stakeholders attending a Sept. 12 RASC meeting.
Rauch also said MISO’s current process doesn’t provide for another analysis if it is unable to determine zonal transmission limits after an initial analysis and a generation-limited transfer study. “This is a situation that is not documented in our process,” she said. “We wanted to bring this to the RASC because this is a policy issue.” Rauch said the LOLEWG will begin working on a solution and codifying a new process.
Customized Energy Solutions’ David Sapper asked for more discussion on MISO’s options. He said because the RTO could find no constraint, the zone’s capability is hypothetically unlimited.
“I think it’s worth a round of feedback,” Sapper said.
“For the auction clearing, we do need to input some number, whether that’s 9,999” or another value, Rauch said.
RASC Chair Chris Plante said it was unlikely that imposing a limit as low as 2,000 MW or as high as 9,999 MW would affect auction clearing results.
Sapper pointed out that MISO using the previous year’s limit potentially opens the doors to using other previous capacity auction values. It could become that the “past is not prologue,” he said.
Consumers Energy’s Jeff Beattie asked the room if anyone thought the one-year adoption would violate MISO’s standard to value reliability first. Rauch said that standard does contain language allowing use of historic capacity limits when appropriate.
“Our view of Zone 5 is that there isn’t significant change from last year,” Rauch said.
New CONE values
MISO has also made its annual FERC filing to update its cost of new entry values for the 2019/20 planning year. The RTO’s CONE now ranges from a low of $81,640/MW-year ($223.67/MW-day) in Louisiana and East Texas’ Zone 9 to a high of $89,960/MW-year ($246.47/MW-day) in Missouri’s Zone 5.
“The estimates are down from a year ago, as they were last year, about $2,000 to $3,000 across the board,” MISO adviser Mike Robinson said.
CONE represents the estimated annualized capital cost of constructing a 237-MW nominal capacity combustion turbine plant in different locations in the footprint. MISO uses CONE as the maximum offer and maximum clearing price in its PRAs.
RENSSELAER, N.Y. — NYISO has asked FERC to reject a complaint by the Independent Power Producers of New York (IPPNY) seeking to bar the ISO from allowing PJM resources to sell installed capacity into Zone J using unforced capacity deliverability rights (UDR) facilities (EL18-189).
Presenting the monthly Broader Regional Markets report, Rana Mukerji, senior vice president for market structures, told the Business Issues Committee on Wednesday that IPPNY incorrectly assumes that transactions across Zone J merchant transmission facilities (MTF) would be subject to curtailment on the same basis as non-firm service within PJM. IPPNY also has not shown that transactions across the Zone J MTFs are no longer deliverable to the New York Control Area interface, Mukerji said.
“Whether the Zone J MTFs have firm TWRs [transmission withdrawal rights] or non-firm TWRs makes no practical difference for curtailment purposes,” NYISO said in its Aug. 20 response to IPPNY’s July complaint. “It was therefore reasonable for the NYISO to conclude that the TWR conversions do not impact the deliverability of transfers across the Zone J MTFs.”
The BIC endorsed changes to NYISO’s unsecured credit scoring model following its first review of the methodology since 2009.
John Jucha, senior credit analyst for corporate credit, said that to qualify for unsecured credit, a market participant must meet financial, credit rating and on-time payment history requirements.
The review found that the model was still performing “within an acceptable range” overall but that the calculation of revenue/market capitalization was not a reliable predictor of default for public companies, Jucha said. It also found that size variables were not represented in the model despite their “strong predictive power.”
Rating all market participants — including corporates, financial institutions and government entities — on the same scorecard may mask differences between them, the analysis found.
Under the new model, the 12.7% weighting for revenue/market cap will be replaced with a measure of total assets. The ISO also will consider using third-party credit ratings for non-corporate segments such as municipalities and financial institutions. It will also create additional rules for the qualitative assessment of market participants to reduce subjectivity under the current “open-ended assessment.” Additional changes were made to automate data entry and improve model transparency.
The BIC vote urges the Management Committee to recommend the changes to the Board of Directors.
Revisions to OATT Attachment L
The BIC voted to recommend the Management Committee approve revisions to Attachment L of NYISO’s Open Access Transmission Tariff updating terms regarding transmission congestion contracts (TCCs).
Gregory R. Williams, manager of TCC market operations, said the updates to Section 18.1.1 (Table 1A) of Attachment L followed an annual review. Among the changes were revising contract expiration dates from Dec. 31, 2017, to Dec. 31, 2027.
The ISO will seek approval of the revisions at the MC meeting Sept. 26.
Updating 2017 CARIS Database
Senior Planning Engineer Chen Yang reviewed changes NYISO is making in its Congestion Assessment and Resource Integration Studies (CARIS) Phase 1 database for Phase 2 studies extending through 2036. The Phase 1 base case covers the years 2017-2026.
Phase 2 of the Congestion Assessment and Resource Integration Studies (CARIS) database will aid in evaluating economic transmission projects through 2036. | NYISO
The Phase 2 base case, which will be used to evaluate regulated economic transmission projects and optional studies, incorporates retirements, additions and changes to in-service dates for more than a dozen generating facilities. The new model also reflects transmission capacity increases or other changes regarding six grid projects.
The ISO’s rules require it to review the changes with the BIC but do not require committee approval.
ISO to Begin Incorporating 100+kV Tx Facilities in Markets
Shaun Johnson, director of market mitigation and analysis, briefed stakeholders on a project to begin scheduling and pricing lower-voltage transmission in the day-ahead and real-time markets, beginning with four 100+kV facilities in November and 18 in December.
NYISO is the NERC transmission operator (TOP) for 230-kV and higher transmission in the state while the transmission owners are the TOPs for the lower-voltage system. The ISO helps the TOs manage constraints on the lower transmission lines through transaction curtailments, phase angle regulator adjustments, day-ahead reliability unit (DARU) commitments and other out-of-market actions, which can harm price formation efficiency and price transparency.
Johnson said the project will reduce out-of-market actions by allowing the market software to use more efficient solutions to thermal overloads when such solutions are available. It also will more accurately represent the cost in locational-based marginal prices to secure the system, he said.
NYISO’s Market Monitoring Unit, Potomac Economics, had recommended the move in each of its State of the Market reports since 2014, leading the ISO to publish a white paper on the topic in June 2017.
The MMU said that incentives to invest in resources on the 115-kV system in upstate New York are inadequate and that managing lower-voltage facilities through out-of-market actions has increased power supplier uplift payments and contributed to the need for cost-of-service contracts to keep older resources operating. At times, transfer limits on internal and external interfaces are reduced to manage 115-kV security.
LBMPs up 40% Year-on-Year
NYISO LBMPs averaged $42.56/MWh in August, up 7.5% from $39.58/MWh in July 2018 and nearly 40% higher than the same month a year ago, Mukerji said in his monthly operations report.
Year-to-date monthly energy prices averaged $46.37/MWh in August, a 30% increase from a year ago. August’s average sendout was 537 GWh/day, higher than 529 GWh/day in July and 477 GWh/day a year earlier.
Transco Z6 hub natural gas prices averaged $3/MMBtu, up about 10.5% from July and up 39.2% from a year earlier. Distillate prices climbed slightly compared to the previous month but were up 33.8% year-over-year. Jet Kerosene Gulf Coast and Ultra Low Sulfur No. 2 Diesel NY Harbor averaged $15.67/MMBtu and $15.36/MMBtu, respectively.
Total uplift costs and uplift per megawatt-hour came in higher than July, with the ISO’s 59 cents/MWh local reliability share in August up from 44 cents the previous month, while the statewide share dropped from -57 cents/MWh to -61 cents. Uplift, excluding the ISO’s cost of operations, was -2 cents/MWh, higher than -13 cents in July.
Thunderstorm alert (TSA) costs in New York City were 14 cents/MWh, down a third from 21 cents in July. TSAs are called when actual or anticipated severe weather conditions lead the ISO to reduce transmission limits on the UPNY-SENY interface, which often leads to severe congestion. Because a TSA may alter the capability of the transmission system in ways that are difficult to hedge in day-ahead markets, day-ahead prices reflect the probability-weighted expectation of infrequent high-priced events in the real-time market.
TEMPE, Ariz. — CAISO is poised to take the lion’s share of the West in the competition for reliability coordinator (RC) customers, the Western Electricity Coordinating Council revealed Wednesday.
Speaking during the Regional Entity’s Wednesday board meeting, WECC CEO Melanie Frye said her organization has received tentative RC commitments from balancing authorities and transmission operators representing all but 2% of net energy load in the West.
The results: 72% of the region’s load will likely sign on with CAISO’s new RC, while 12% of load will go with SPP.
WECC and NERC requested that Western BAs and TOs declare their RCs by Sept. 4. The action became necessary when Peak Reliability, which has been providing the Western grid’s RC function following a major outage in 2011, announced in July that it will wind down its services by the end of 2019.
Frye also confirmed that BC Hydro is moving ahead with plans to set up an RC covering its own territory in British Columbia, Canada, representing about 7% of WECC load. Its neighbor to the east, the Alberta Electric System Operator (another 7% of load), will continue to provide for its own RC needs.
“Clearly, we need to follow up with the uncommitted to see where their intentions lie,” Frye said.
Among the uncommitted are Avista in northern Washington and Public Service Company of New Mexico (PNM), the state’s largest utility.
Frye said PNM was “leaning in one direction, but after hearing what their neighbors were doing, they are back into consideration.” The utility last month announced that it intends to join CAISO’s Western Energy Imbalance Market, while its neighboring BAs have recently signaled they are selecting SPP as their RC. (See PNM Seeks to Join Energy Imbalance Market.)
WECC declined to list the BAs’ RC selections, telling RTO Insider it would instead defer to each BA to make its own announcements.
But a map released by WECC at the meeting shows the SPP RC will still grab a big slice of the inland West, largely a product of the Western Area Power Administration’s decision to deepen its relationship with a market operator that already serves part of its sprawling transmission network. (See WAPA to Divide RC Services Between CAISO, SPP.)
CAISO’s RC will dominate the West Coast, Idaho, Montana, Nevada and Utah — areas heavily represented in the EIM. Frye offered a caveat regarding the map: “These are the draft nonbinding footprints that came in at our request. … Official commitments aren’t due into CAISO until Nov. 1.”
On Monday, SPP confirmed that 15 Western utilities have indicated they will use the RTO’s RC services:
Arizona Electric Power Cooperative
Black Hills Energy’s three electric utilities: Black Hills Power; Cheyenne Light, Fuel and Power; and Black Hills Colorado Electric
City of Farmington, N.M.
Colorado Springs Utilities
El Paso Electric
Intermountain Rural Electric Association
Platte River Power Authority
Public Service Company of Colorado (PSCo)
Tri-State Generation and Transmission Association
Tucson Electric Power
WAPA’s Desert Southwest, Rocky Mountain and Upper Great Plains-West regions.
The list did not include some utilities that WECC’s map indicates have also chosen SPP, including two small pockets in the Pacific Northwest which align with Avangrid’s recently inaugurated wind-heavy “Green Balancing Authority” on both sides of the Columbia River. Southern California’s Imperial Irrigation District, which has historically had a contentious relationship with CAISO, also appears to have selected SPP as its RC.
The RC elections will give SPP a presence in 21 states, adding Arizona, California, Colorado, Oregon, Utah, Washington and what appears to be a thin slice of Nevada to the 14 states where it currently has members: Arkansas, Iowa, Kansas, Louisiana, Minnesota, Missouri, Montana, Nebraska, New Mexico, North Dakota, Oklahoma, South Dakota, Texas and Wyoming.
PSCo had announced Sept. 11 that it had selected SPP as its RC provider. Ironically, the company in April all but put the kibosh on SPP’s planned integration of the Mountain West Transmission Group, announcing that it was withdrawing from the Rocky Mountain group and its efforts to join the RTO. (See Xcel Leaving Mountain West; SPP Integration at Risk.)
SPP COO Carl Monroe said he welcomed the news that PSCo has joined others in selecting the RTO as its RC. Those committing to SPP include all of the original Mountain West entities except Basin Electric Power Cooperative and two WAPA regions.
“We’ve worked hard over the last several months to demonstrate the quality and breadth of our service in terms of technical expertise, a customer-centric approach to doing business and the integrity of our people and processes,” Monroe said.
The RTO has said it remains committed to adding the rest of the Mountain West as members. However, that work has been overtaken by the Western RC initiatives. It said it will soon finalize plans for the governance and operation of its Western RC services, taking input from customers, neighboring RCs and regulatory stakeholders.
SPP plans to become certified as an RC in the second half of 2019 and to begin offering services in December 2019.
Frye said WECC will now begin “analytical work” related to transmission that crosses RC boundaries and look into whether there are “different types of studies we can do around frequency” issues. She said her organization also wants to convene a monthly call with BAs and TOs to consider a Western Interconnection-wide plan for transitioning to the new RC arrangements.
WECC will work with NERC to ensure the new RCs are certified and their members are properly registered.
“We’re also working with BC Hydro and [British Columbia] officials to see what kind of certification-like activity they will want to do in that province,” Frye said.
FERC and NERC announced Wednesday they are conducting a joint inquiry into the January cold snap that resulted in generation outages and loads that approached summertime highs in MISO South.
Uncharacteristically frigid weather prompted MISO to initiate a maximum generation alert for the South region for Jan. 17-18. With low temperatures averaging 13 degrees Fahrenheit on Jan. 17, MISO South’s peak load hit 32.1 GW, just short of the region’s all-time high of 32.7 GW set in August 2015.
| MISO
MISO South reported about 17 GW of generation outages and derates that day, including nearly 10 GW in forced generation outages. Entergy Louisiana reported that about 32,000 homes and businesses lost power.
The FERC-NERC announcement cited “reports of multiple forced generation outages, voltage deviations and near overloads during peak operations.”
The inquiry, which FERC and NERC said is not an enforcement investigation, will seek to identify the causes and contributing factors to the event along with recommendations for improving operations in the future.
“This inquiry is timely as it will allow us to identify and share any potential lessons learned as we approach the coming winter season,” NERC CEO Jim Robb said. “It is also especially relevant that as the Western Interconnection reliability coordinator function fragments among multiple providers that we understand and underscore the importance of seamless RC-to-RC interactions.”
The Midwest Reliability Organization, ReliabilityFirst, SERC Reliability and utilities in the region will work with FERC and NERC staff on the inquiry.
The RTO declared conservative operations and a cold weather alert for MISO South — which spans Arkansas, Louisiana, portions of Mississippi and part of eastern Texas — beginning Jan. 15, when most of Louisiana was under a winter weather advisory.
Independent Market Monitor David Patton told stakeholders in March that if the RTO had not made emergency power purchases for South, regional supply would have dipped below load for several hours.
MISO spokesman Mark Brown said the RTO doesn’t mind re-examining the event.
“While MISO and its neighbors worked together to maintain system reliability during the event, we recognize the opportunity to collaborate on changes that improve coordination during extreme events. We welcome the opportunity to advance the understanding within the industry and how MISO and its neighbors can continue to work together to support reliable and efficient operations,” Brown said in an emailed statement to RTO Insider.
FERC and NERC announced Wednesday they are conducting a joint inquiry into the January cold snap that resulted in generation outages and loads that approached summertime highs in MISO South.
Uncharacteristically frigid weather prompted MISO to initiate a maximum generation alert for the South region for Jan. 17-18. With low temperatures averaging 13 degrees Fahrenheit on Jan. 17, MISO South’s peak load hit 32.1 GW, just short of the region’s all-time high of 32.7 GW set in August 2015.
| MISO
MISO South reported about 17 GW of generation outages and derates that day, including nearly 10 GW in forced generation outages. Entergy Louisiana reported that about 32,000 homes and businesses lost power.
The FERC-NERC announcement cited “reports of multiple forced generation outages, voltage deviations and near overloads during peak operations.”
The inquiry, which FERC and NERC said is not an enforcement investigation, will seek to identify the causes and contributing factors to the event along with recommendations for improving operations in the future.
“This inquiry is timely as it will allow us to identify and share any potential lessons learned as we approach the coming winter season,” NERC CEO Jim Robb said. “It is also especially relevant that as the Western Interconnection reliability coordinator function fragments among multiple providers that we understand and underscore the importance of seamless RC-to-RC interactions.”
The Midwest Reliability Organization, ReliabilityFirst, SERC Reliability and utilities in the region will work with FERC and NERC staff on the inquiry.
The RTO declared conservative operations and a cold weather alert for MISO South — which spans Arkansas, Louisiana, portions of Mississippi and part of eastern Texas — beginning Jan. 15, when most of Louisiana was under a winter weather advisory.
Independent Market Monitor David Patton told stakeholders in March that if the RTO had not made emergency power purchases for South, regional supply would have dipped below load for several hours.
MISO spokesman Mark Brown said the RTO doesn’t mind re-examining the event.
“While MISO and its neighbors worked together to maintain system reliability during the event, we recognize the opportunity to collaborate on changes that improve coordination during extreme events. We welcome the opportunity to advance the understanding within the industry and how MISO and its neighbors can continue to work together to support reliable and efficient operations,” Brown said in an emailed statement to RTO Insider.
TEANECK, N.J. — Joe Fiordaliso, president of New Jersey’s Board of Public Utilities, is not alone in his concerns about the state’s perceived lack of influence at PJM.
State Assemblyman John Burzichelli (D) told attendees at Infocast’s Offshore Wind Implementation Summit last week that he too has concerns.
“I have issues with PJM,” he said. “I’m talking about procedurally. I’m not sure they always have New Jersey issues in mind. We’re going to want a larger voice in what takes place” at PJM.
Burzichelli moved on to other energy-related topics in his featured address. But he elaborated further in an interview, saying he supports Fiordaliso’s demands for increased recognition from the RTO’s staff.
“There’s no question that they are polite and listen, but … they don’t really don’t recognize the state of New Jersey as an entity,” he said. “The short answer is I think it should change. I have a lot of faith in the leadership at the BPU. I would be supportive of the president’s lead in this.”
He suggested that state representatives should get a vote on stakeholder issues because “my observation is that [the interests of] those utilities that are based in New Jersey and New Jersey’s public interests at times are a little different.”
Fiordaliso Cites Progress
Reached on Monday, Fiordaliso said he wouldn’t respond to Burzichelli’s comments because he hadn’t yet spoken with the legislator. But he disputed an Aug. 31 report by Morning Consult that his threat to leave PJM is off the table.
“I wouldn’t say we’ve buried the hatchet. We’re moving the right direction. I think everything is on the table. Right now, I think that has eased a bit. We’re engaging in more dialogue,” he said. “I think PJM is trying to take a step in a positive direction. I think I’m starting to see a turnaround.”
On Burzichelli’s suggestion to seek voting rights at PJM, Fiordaliso acknowledged that would require states being able to become PJM members, which he said “is certainly worth looking into.”
“I think voices are heard when you do have a vote, but I’d like to look into it and see how beneficial it would be to New Jersey. … I don’t expect to win every battle, but as long as there’s an honest exchange of ideas, we can forge a relationship here.”
He said PJM showed it’s “willing to exchange ideas with us” in its comments on the Independent Power Producers of New York’s FERC complaint requesting NYISO prohibit installed capacity withdrawals from PJM into New York City across merchant transmission lines (EL18-189).
In its comments, PJM explained that curtailments necessary for reliability would happen concurrently between the merchant facilities and PJM load on a pro rata basis. This supported comments made in the docket by the BPU, along with the New Jersey Division of Rate Counsel and the Public Power Association of New Jersey. They said NYISO couldn’t consider the merchant facilities as capacity resources because they had recently reduced their PJM transmission withdrawal rights from firm to non-firm.
In fact, it was the docket in which the transmission facilities sought to downgrade their transmission rights that initially prompted Fiordaliso’s threat to leave PJM. The move left Public Service Electric and Gas to pay for most of the Bergen Linden Corridor upgrades that were designed to help facilitate “wheeling” power through northern New Jersey to New York City.
Offshore Wind
Burzichelli said his concern with PJM began with what he felt was a lack of support from the RTO in the state’s attempts to develop offshore wind during Gov. Chris Christie’s administration. The state was looking for guarantees of regional cost allocation for developing the infrastructure that would bring offshore wind generation to the RTO, but “we lost [Christie’s] attention” before anything could be built, he said. Fiordaliso’s “concerns and mine are the same; they just happen to be a separate topic,” Burzichelli said.
He also took issue with what he believed was PJM’s “failing” that required the state to act to save its nuclear plants. “As painful and as expensive as it turned out to be” to subsidize the plants, which are in his district, he “felt very strongly that it was in the public interest … because they’re reliable.”
“It’s sort of an insurance policy that has a price tag to it,” he said, predicting natural gas prices will rise once the regional glut of supply is reduced.
“It will creep. It’s just a question of when,” he said.
Burzichelli said he faults PJM rather than the nuclear owners because the owners were providing for their own interests. PJM should have revised its market rules because the power from the plants gets distributed throughout the RTO, he said.
“I have a comfort level in this case that [plant co-owner Public Service Enterprise Group] is sensitive toward ratepayers. They are also sensitive toward stockholders,” he said. “I think some of the stabilization should have been borne by a wider [RTO-wide ratepayer] base, but PJM did not step up at a pace that was satisfactory to the business model of the utility, so we acted.”
AUSTIN, Texas — Infocast’s Texas Renewable Energy Summit attracted developers, potential off-takers and other industry insiders to the state’s capital Sept. 5-7 for discussions on the uncertainties and risks of the renewable energy market. Panel discussions focused on the continued growth of wind energy and the coming wave of solar energy, the transmission facilities needed to accommodate renewables, and the market’s ability to incorporate them.
The summit’s clear consensus? Solar power is a better play now than wind energy in Texas. ERCOT, which manages about 90% of the state’s grid, projects it will add 3 GW of solar capacity by 2020 and 20.2 GW of utility-scale solar by 2031, double the additions expected from wind.
The state still leads all others in installed wind capacity with nearly 22.6 GW, according to the U.S. Department of Energy. However, the 2.3 GW of capacity Texas added in 2017 was below the 3.6 GW installed in 2015 or the 2.6 GW added in 2016.
Asked why the state presents such an inviting market for solar, Shalini Ramanathan, vice president of origination for RES Americas, repeated the question. “Why Texas?” she asked. “Because it’s hot and flat.”
And there’s so much open space in Texas, said Paul Turner, who sites solar developments for Hecate Energy as vice president of business development.
“If I see a pump jack, I go 3 miles away. I see a wind farm, I go 3 miles away,” he said. “At this point, there are so many options, I just avoid [other infrastructure].”
“It just feels like it’s time. Solar has a lot of headroom to grow,” Ramanathan said, pointing to dropping prices for solar panels and rising natural gas prices. “The challenge is getting off-takers. A lot of the utilities have already bought a lot of wind and solar, but the munis and co-ops are still interested. Corporate off-takers are great. We’ve seen a lot of interest in Texas that directly corresponds to the prices.”
Turner referenced a recent ExxonMobil offer to purchase up to 250 MW of solar and wind energy in Texas.
“Our industry is like lemmings. If ExxonMobil starts doing it, other companies are going to do it as well,” he said. “They don’t want to be left behind. Their shareholders are going to ask, ‘Why aren’t we doing it? Why aren’t we putting it on the cover of the proverbial annual report?’
“The genie’s out of the bottle,” Turner said.
ENGIE Solar North America Managing Director Marc-Alain Behar said potential buyers from El Paso, which is outside ERCOT’s market, have been “pretty stunned” by the low prices they’ve seen for solar.
“If you can make it here, you can make it in a lot of places,” Behar said.
Developers Still High on Texas’ Wind Resources
Wind developers agreed that there is still room for projects in Texas, saying as much as 5 GW of capacity may be built before the federal tax credits expire in 2019.
“It seems there are a plethora of projects, but good projects will get built,” said Matt Jacobs, who is responsible for Tradewind Energy’s portfolio siting. “We’re really excited about the ERCOT market. From a national perspective, ERCOT is a market we see as attractive as any market in the U.S.”
Jacobs lauded the ease of navigating ERCOT’s interconnection queue, while others pointed to falling prices of the technology and shorter construction timelines in Texas than in other RTOs. That makes it easier for developers to put up with transmission congestion and curtailments, particularly in the Panhandle.
“We have well over a decade or more of experience working in this market. There’s always opportunities, but there’s always some headwinds,” EDF Renewables’ Caroline Mead said. “Today, it’s really about the economics. The economics speak volumes. The pricing of wind is so compelling … that’s the main driver at this point.”
Tri Global Energy President Tom Carbone agreed, pointing to renewable energy’s ever-increasing share of ERCOT’s fuel mix. “When [you] have 17% of the load being served by renewables, that says something,” he said.
“We’re at a point now where there’s a value proposition for these sources of generation,” Recurrent Energy’s Jacob Steubing said. “We’re not being driven here in Texas by carbon goals or renewable goals. Economics are driving the buyers. This is probably the only room where a lot of folks consider low prices a bad thing. The general public doesn’t see that as a problem.”
Philip Moore, vice president of development for Lincoln Clean Energy, said ERCOT’s market is unique, a place “where ideas are tested out and challenged,” despite a natural resistance to change. Longer blades, larger turbines and other technological advancements have lowered prices, improved efficiency and opened new areas to wind development, he said.
“With a 40% drop in CapEx, you can go closer to where demand is … but it’s not without its challenges. We’re starting to see new encroachment issues,” Moore said, referring to military aviation training routes and organized political opposition. “We have to be better at explaining the investment benefits of a lot of capital coming to rural areas — and slightly less rural areas — and what the tradeoff is. We need to do a better job, because technology allows us to go to more places.”
Texas’ electric cooperatives are finding their business models are changing. Where once they sold meter boxes and security lights to their members, they are now meeting customer demand for high-speed Internet service and adding wind and solar to their portfolios, Bandera Electric Cooperative CEO Bill Hetherington said.
Bandera is the second largest certified Tesla Powerwall installer in the state. It is promoting the results of a Bloomberg New Energy Finance (BNEF) study that found lithium-ion storage batteries prices have dropped by 80% in the past eight years and projects a $548 billion investment in energy storage by 2050.
“The cost is important, but a small percentage of our customers want to support renewables and buy Tesla Powerwalls,” Hetherington said. “We’ve retooled ourselves and focused on our renewable subsidiaries.”
Bandera serves more than 27,000 members in its footprint northwest of San Antonio. “Our service territory is pretty rural. There are areas where it would actually be cheaper to put in a microgrid rather than pay the cost of extending a service line,” Hetherington said.
He said that the co-op’s work with microgrids caught the National Rural Electric Cooperative Association’s attention, and it selected Bandera for a project to create microgrids in Liberia and Uganda.
Hetherington said 662 million Africans don’t have access to electricity, but that the continent also presents the second fastest growing economy in the world. “Investing in the future pays dividends for our customers and our members,” he said.
The state’s more than 75 electric cooperatives are still cognizant of their members’ concerns and wants, Hetherington and his fellow panelists said.
“Our membership looks at the bottom line. They don’t want to pay a premium to feel good. They want to do it because it makes economic sense,” Golden Spread Electric Cooperative COO J. Jolly Hayden said. “Some members have done community solar on their own. We have a 1-MW model that gives them a pretty good price. We’re also looking at a larger project, but the members haven’t signed off on it.”
“We’re small enough and flexible enough to make changes, from a commodity-based entity to a service-based company that is connected to its customers,” Hetherington said, adding he never thought he would have 1,800 Internet customers. “The technology has changed. What doesn’t change is the support our members expect from us.”
Economic Realities Driving Municipal Supply Decisions
Denton Municipal Electric General Manager George Morrow, a newcomer to the Texas market after years in California, said the city’s recent announcement that it intends to become the state’s second 100% renewable-powered municipality was driven by the market’s realities.
As part of the Texas Municipal Power Agency, the city owns the coal-fired Gibbons Creek plant, a 35-year-old, 454-MW unit that has provided more than half of its generation for a decade. The plant, which environmentalists would like to see permanently retired, will return to seasonal mothballs in October.
Morrow said in looking for replacement energy, he was surprised by the prices he was seeing for renewables. “‘Wow, look at what you’re offering us!’” Morrow recalled. “It just made sense. We were kind of in a sweet spot. Not everybody can be 100% renewable. The system can’t survive.”
John Bonnin, who manages CPS Energy’s supply and market operations, recalled his own experience with request-for-proposal prices in trying to secure power for San Antonio. He likened the situation to one of the final scenes in the 1987 film “Predator,” when the titular alien hunter removes its helmet.
“‘You are one ugly…’” Bonnin said, stopping short of parroting Arnold Schwarzenegger’s entire line. “That’s kind of what it was like year after year, because the [RFP] prices kept going up. There was no thought of solar energy at the time, because people were talking about $250, $300/MWh prices.
“So fast forward a few years. What is our plan now? We have older coal plants ready to retire, so how do you replace that capacity on peak? Wind and solar can give you some peak, but you’re not paying an out of market price for that [any longer]. The big change in our company is we’re not doing this because it’s a mandate, we’re doing this because it’s economic.”
“We were chasing environmental goals before. We were chasing goals, but we were trying to minimize the price effect,” Austin Energy’s Khalil Shalabi said. “That’s changed with recent pricing we’ve seen. We’ve gone more into a mode of risk mitigation. How do [prices] fare under different regulatory paradigms? … We can’t predict the future, but we can look at the risks and quantify those for our customers.”
Jim Briggs, the utilities manager for Georgetown, the other 100% renewable Texas city, said regulatory considerations played a role in the city’s decision to go green when it ended a coal-heavy supply contract in 2012.
“My recommendation to the [City] Council and [utility] board was that renewables needed to be a portion of our energy mix,” he said. “We don’t know what’s coming out of Washington for renewable standards, but I can tell you that, in 30 to 40 years of doing this, they have never been reduced. … You can expect greenhouse gas legislation is going to continue. It might subside during one administration, but it’s going to be back again.”
ERCOT’s Reserve Margin not Expected to Grow
Several panelists agreed ERCOT may have been lucky to escape the summer heat with a reserve margin of only 11%. They pointed out the generators performed when called on, and though the system exceeded its previous peak-demand record 14 times during July, it also benefited from cooler-than-normal weather in June and August.
“Maybe it was some combination of market performance by ERCOT and luck,” said Kathleen Spees, a principal with The Brattle Group. “The wind performed, and the traditional generators showed up. We had some scarcity pricing, but it wasn’t [that] extreme. We skated through a summer that could have been very bad in terms of reliability, but very good for the money. Did we just get lucky? Was that the market working as intended? Or are we at a very low reserve margin, and the prices just didn’t get high?”
“We feel like everything worked out as intended,” said Erika Bierschbach, Austin Energy’s manager of market operations. “The market is vibrant. With regard to most concerns before the summer started, there is still risk in the market.”
ERCOT’s Dave Maggio was quick to point out the grid operator didn’t have to declare any emergencies during the summer and saw a lack of scarcity pricing.
“A big part of the story is going to be the resource performance. We got a lot of support from generation resources and transmission resources. When supply was tight, we didn’t have resources offline,” Maggio said. “The upshot was, we took less out-of-market actions, which is what everyone prefers.”
“From the ERCOT perspective, part of the success we had was effective communications with everyone,” said Pete Warnken, the ISO’s manager of resource adequacy. “The expectation is, as we continue to have lower reserve margins, the market and ERCOT and all the participants need to continue that discussion. We always focus on the summer peak, but fall and winter is coming up, and lowered reserve margins affect that as well.”
Spees called ERCOT’s summer performance with tight reserve margins “one roll of the dice.”
“I don’t think we would get lucky that often,” she said. “One big outage, or the wind doesn’t show up during peak load, or something a little closer to 2011’s [record-breaking hot] weather … if we see a similar reserve margin next year, we could see something very different.”
But don’t expect ERCOT’s market prices to remain depressed for the rest of 2018, BNEF Power Market Analyst Joshua Danial said.
“Some of the least healthy units run when spark spreads are negative, under arcane contracts where their power is guaranteed to have an off-taker,” said Danial, who expects more fossil retirements in the near future. “When those contracts fall off, there’ll be a lot of reconsidering whether to keep them running or not.”
Manan Ahuja, senior director of North America power analytics for S&P Global Platts, said he expects to see reserve margins of 12 to 13% by 2022.
“The supply increase is tracking pretty closely to the load increase,” he said, pointing to an ERCOT interconnection queue that numbers more than 19 GW of projects with signed agreements. “There are small gas projects in the queue, about 4 GW of wind that could come online in 2019. … We expect to see reserve margins that are pretty similar [to 11%] next year.”
