INDIANAPOLIS — FERC last week accepted a generation interconnection agreement between MISO and the first utility-scale battery storage project in the footprint.
The commission approved a GIA for Indianapolis Power & Light’s Harding Street Station Battery Energy Storage System, which is planned to go online this month, in spite of IPL’s protests that the project was being mischaracterized. IPL had urged the commission to view the storage facility as a transmission asset.
The agreement isn’t a straightforward storage-to-grid situation. The contract includes Harding Street’s two existing gas turbine generators — designated as black start resources — alongside the newly constructed 20-MW storage facility. The batteries — eight 2.5-MW blocks — will use the existing interconnection facilities of the two existing gas turbine generator units, which connect to the Harding Street South substation. The commission accepted the GIA “in the interest of expeditiously connecting the battery facility to MISO’s transmission grid” but said that it will not create a precedent for future storage facilities (ER16-1211-001).
“The Harding Street GIA is narrowly focused on the terms necessary to interconnect Indianapolis Power’s battery facility and two existing combustion-turbine generators; the commission’s action in this proceeding, therefore, does not prejudge potential improvements to the procedures or agreements that govern the interconnection of electric storage resources in the future,” FERC explained.
Comprehensive Market Rules Needed
The commission also said that more comprehensive market rules for storage are needed.
“Although we accept the Harding Street GIA … we appreciate that MISO’s pro forma GIA was not originally intended to govern the interconnection of electric storage resources to MISO’s transmission grid,” the commission said.
MISO and IPL disagreed over whether the pro forma agreement was an appropriate vehicle for the project. The RTO contended interconnecting under the GIA was correct, while the utility insisted that the storage facility should not be subjected to GIA provisions or referred to as a “generating facility.”
FERC said a “generating facility” designation was appropriate because the pro forma definition includes “device(s) for the production and/or storage for later injection of electricity identified in the interconnection request.” The commission also pointed out IPL’s battery storage was bundled with two other generating units. However, the commission ordered MISO to add one instance of “energy storage resource” to the agreement.
MISO regarded the battery facility as an upgrade because it shares the same interconnection facilities as the existing generation. IPL had objected to this treatment, maintaining that the non-generating battery facility is a transmission asset that provides ancillary services.
IPL had also argued that the GIA’s appendix does not apply to storage, but FERC decided it was unnecessary to “delete non-applicable provisions of a pro forma GIA.”
The agreement was approved as MISO is considering expanding its definition of demand response resources to include medium-term energy storage. In April, stakeholders urged MISO to develop a cost of new entry for storage technology. MISO said a final proposal to change Tariff or Business Practices Manual revisions to accommodate near-term storage would be presented late summer or early fall. (See MISO Stakeholders Provide Ideas on Incorporating Storage.)
MISO next month will implement two new offer floors for emergency pricing to alleviate what the RTO calls “price depression.”
MISO filed the measures with FERC seeking a July 1 effective date and intends to implement by then even if the commission doesn’t respond in time — leaving the plan subject to refund or recalculation.
“We don’t anticipate that since [FERC] already accepted the [emergency pricing] Tariff revisions,” Bob Merring, MISO’s manager of market engineering, said at last week’s Market Subcommittee meeting. The filing is what MISO refers to as a “true-up” between the Tariff and the already-accepted emergency pricing construct complete with offer floors, which won FERC approval in August (ER15-1776).
Merring also noted that the comment period on the filing has passed without any responses.
Accurate emergency pricing is needed “as we move into a world of tightening resources,” he said.
After issuing an emergency alert, MISO would establish a first emergency pricing floor representing the highest economic offer in the market. A second, higher price floor based on offers would be established after the declaration of an emergency event requiring the call-up of emergency generation.
The RTO discussed raising offer floors last year and again at MISO’s May 6 summer readiness workshop. (See MISO Sees Enough Capacity for Summer.)
MISO’s extended LMP allows demand response to set prices under emergency conditions, but the RTO says the construct needs to be expanded to include more emergency resources. Prices can remain depressed if emergency offer prices are lower than prices for economic dispatch prior to an emergency declaration.
Merring said the gap could result in emergency resources entering the market at $0/MWh. “That’s an undesired outcome,” he added.
MISO Clarifying Network Resource Designation
MISO has reworked portions of its Tariff to address stakeholder concerns with a proposal to remove duplicate network resource designations found in Module B and Module E.
The RTO earlier this year proposed changes that would define network resources simply as those that clear in the annual capacity auction. MISO’s Kun Zhu said stakeholders were concerned that resources failing to clear would lose their network resource status. Others pointed out that the resource designation in Module E — dealing with resource adequacy — lasts just one year, while Module B — which focuses on network service — covers multiple years.
MISO is now proposing a new resource designation that would include those with interconnection service, a transmission service request or a scheduling right.
“Whatever we propose here will not disqualify any current network resource,” Zhu said.
The revised designation also specifies that network resources are “owned by market participants but dispatched by MISO.”
Zhu said the new designation will not impact other future uses of network resource status, including transmission planning, auction revenue rights nomination and MISO’s possible “freeze date” reference point change.
Valy Goepfrich, WPPI Energy’s vice president of operations and analytics, said the revised proposal alleviated some of her company’s concerns with the March version of the proposal.
Feedback on the revised proposal must be submitted by June 17. No filing date has been set.
Changes to Uninstructed Deviation Thresholds Longer than Anticipated
MISO’s work with its Independent Market Monitor to re-examine thresholds for uninstructed deviation by generators is taking longer than anticipated. Implementation of a new approach to the issue is not expected until the first half of 2017 because of a delay in scoping the project.
MISO earlier said an alternative to the existing practice would be in place by the fourth quarter of this year.
“While we initially intended to begin briefing stakeholders … as early as this month, the fact that it’s taking longer means a later implementation,” said Jeff Bladen, MISO executive director of market services and liaison to the Market Subcommittee.
The Monitor first recommended tightening thresholds in 2012. Last year, Monitor David Patton said MISO is losing as much as 400 MW to derates during peak conditions because of a “lenient” tolerance band of 8%, with measurement based on four consecutive dispatch intervals. (See MISO Monitor Debates Capacity Rules with Board.)
The RTO will provide an update on the issue at the June 28 MSC meeting.
MSC Tweaks Charter to Avoid Stepping on Resource Adequacy Subcommittee’s Toes
The MSC approved a motion to remove all mention of “capacity” from its charter following a recommendation from the Steering Committee.
“The rationale [is] all things capacity belong in the Resource Adequacy Subcommittee,” said Kent Feliks, MSC chair. “To avoid that overlap, we’re simply moving capacity from the mission statement.” (See “Market Subcommittee won’t Undergo Name Change, will Modify Charter,” MISO Steering Committee Briefs.)
The nine Northeastern and Mid-Atlantic states that participated in the 32nd Regional Greenhouse Gas Initiative auction of carbon dioxide allowances on Wednesday sold more than 15 million at a clearing price of $4.53.
Bids for an allowance, which allows for the emission of one ton of CO2, ranged from $2.10 to $12.65 each. It was the second of four quarterly auctions of 2016 and generated $68.3 million for energy efficiency, renewable energy and other programs in the member states.
Cumulative proceeds from all RGGI CO2 allowance auctions since 2008 exceed $2.5 billion.
Aliso Canyon Shutdown Prompts SCE Energy Storage Procurement
State regulators have ordered Southern California Edison to expedite procurement of large-scale energy storage to deal with possible service interruptions stemming from the closure of the Aliso Canyon gas storage facility.
The utility’s request for offers states that straight storage projects must be a minimum of 500 kW, and a separate “design, build and transfer” category seeks projects capable of delivering four hours of energy in increments of 5, 10, 15 and 20 MW.
Projects must be grid-connected, meaning behind-the-meter storage is excluded. SoCalEd is expected to select winners by mid-September, with Dec. 31 being the deadline for commencing operation. The Public Utility Commission acknowledges the timelines could be too aggressive.
Boulder Intervenes in Xcel’s Plans for $1B Wind Farm
The City of Boulder and more than a dozen other agencies and government bodies have asked to intervene before the state Public Utilities Commission in Xcel Energy’s bid to build a $1 billion wind farm. The Rush Creek Wind Project would cover 90,000 acres in the state and would be among the state’s largest wind energy producers.
Boulder, which is engaged in an ongoing dispute with Xcel before the PUC over its municipalization efforts, said its primary contention is that Xcel filed the wind farm application more than two weeks before filing its electric resources plan (ERP), which sets what facilities it will need in order to serve its customers. “Our issue is that we think that this proposal should be evaluated in the context of the ERP,” said Boulder spokesperson Sarah Huntley.
The connection of the wind farm to Boulder’s efforts to take over Xcel’s assets is indirect, Huntley said. “The only linkage to municipalization we’re making is that the amount of energy they need to be able to provide could change if the city is no longer drawing our energy from them,” she said.
United Illuminating will file for stepped-in annual increases of about $9/month for each of the next three years later this summer.
The company told the Public Utilities Regulatory Authority on Wednesday that it needs $141 million in new revenue to pay for ongoing modernization of its distribution network, tree trimming and infrastructure improvements.
Regulators froze rates until 2017 as a condition of its approval of UI’s merger last year with Iberdrola USA to form Avangrid.
The Utilities Board allowed the Dakota Access Pipeline to proceed on parts of the route not covered by federal authority. It is the last state regulatory body to get aboard the $3.8 billion, 1,168-mile pipeline to deliver crude oil from North Dakota to Illinois.
Some obstacles remain for project developer Energy Transfer Partners. The state chapter of the Sierra Club filed a suit to block the pipeline, along with some local landowners and Native American tribes.
Energy Transfer Partners says it has received permission from 96% of the landowners along the route. It is awaiting approval from the U.S. Army Corps of Engineers to work on 2.5% of the route it controls.
The Public Service Commission will allow Baltimore Gas and Electric to raise its rates for gas and electricity by $89.5 million, about 40% of the utility’s request of $224.5 million.
The new rates will increase monthly bills by $2.67 for electricity customers and $4.86 for gas customers. Had the PSC granted the full request, customers would have seen a bump of $7.05 for electricity and $8.01 for gas.
The commission denied BGE’s request for a bill surcharge to cover an increase of $30.7 million in conduit fees for the City of Baltimore.
The Senate adjourned last week without voting on a utility-supported package of bills to reform the state’s energy market.
Senate Majority Leader Arlan Meekhof said most legislators were unfamiliar with the complicated legislation and it was too much for them to digest. “For folks that don’t serve on the committee and aren’t engaged in this every day, it’s a lot of stuff,” he said.
The bill aims to cut emissions 35% by 2025 through increased use of renewables, to give the Public Service Commission control in utilities’ rate changes and to place restrictions on alternative energy suppliers. Businesses, schools and government agencies say the legislation would remove the state’s retail choice, currently capped at 10%.
Anti-fracking Petition Falls Short Before Deadline
The Committee to Ban Fracking collected about 82% of the 252,523 signatures it needed to get an anti-fracking measure on the ballot for November’s election before a deadline expired.
The group says it will sue to challenge the constitutionality of a 180-day limit for petition signature drives. It says it will continue to collect petitions in hopes of getting the measure on the 2018 ballot.
But under a bill recently passed by the House and Senate, the 207,000 signatures already gathered would be considered “stale” and the group would have to start over. Gov. Rick Snyder has yet to sign the bill, however.
The Public Service Commission decided not to vote on opening a working case that would have studied the impacts of a bill that has stalled in the General Assembly.
The bill would dramatically change ratemaking for utility companies, with Chairman Daniel Hall calling it “a radical departure from 100 years of ratemaking.” But the legislation was filibustered in the Senate.
Another factor in the PSC’s decision to pull the vote from the agenda was Ameren Missouri, which said it would not participate in the working case for fear that it could be used against it in future rate cases.
A second wind farm in the state has been put on hold after it attracted public opposition. The Cherry County Planning Commission has delayed consideration of a 50-MW farm planned by Bluestem Sandhills, pending a review of public notice requirements.
The commission delayed a vote on a conditional use permit until it can decide whether the state Game and Parks Commission, which operates the nearby Cowboy Trail, should have been informed of the meeting. That legal review could take a few weeks, officials said.
Consideration of a 350-MW farm near Brunswick was also postponed to allow for more consideration of testimony about the project.
Public Service Electric and Gas’ $275 million plan to add 100 MW of solar power through 10 new solar farms has drawn kudos from environmentalists, but others are concerned about the potential effect on solar credits.
Part of the company’s Solar 4 All program, the farms will be sited on old landfills and industrial brownfields.
PSE&G’s application includes a 10% guaranteed rate of return. “PSE&G is asking ratepayers to assume the risk for this solar generation,” said Stefanie Brand, director of the Division of Rate Counsel.
Ground Broken on State’s Largest Community Solar Farm
State officials broke ground last week on the state’s largest solar array, near Fargo. The 102-kW project has 324 panels, with room on the 350-by-150-foot lot to double in size if demand from Cass County Electric Cooperative increases.
The co-op received a $140,000 grant from the state Commerce Department, much of which came from the federal Department of Energy. That subsidy cut the project’s cost by 58%.
About 70 co-op members have purchased panels, and applications from 100 more members are in the works, said Paul Matthys, Cass County Electric’s vice president for member and energy services. The solar array will produce an estimated 142 MWh a year.
Sierra Club Director Among 19 Applying for PUCO Seat
Sawmiller
Daniel Sawmiller, senior representative with the Sierra Club’s Ohio Beyond Coal campaign, is one of 19 applicants for a vacancy on the five-member Public Utilities Commission. Others to apply included State Rep. Dave Hall and a Columbus utilities attorney, Howard Petricoff.
Sawmiller was a vocal opponent of both the FirstEnergy and AEP Ohio power purchase agreements and eventually joined in a settlement for the AEP plan after the company vowed to commit resources to renewable energy.
The 19 will be interviewed by the PUCO nominating council by June 16, and four finalists will be forwarded to Gov. John Kasich for consideration.
Current and former Omaha Public Power District executives defended their decision to continue to invest in the Fort Calhoun nuclear plant, even as all market signals pointed to nuclear power being uncompetitive in the face of declining natural gas prices.
The Omaha World-Herald interviewed eight current and three former OPPD board members, questioning why the utility sunk $300 million in an effort to restart Fort Calhoun in December 2013 only to conclude last month that the plant “is not financially sustainable.” The board is expected June 16 to vote on a recommendation to close the plant by the end of the year. (See Omaha PPD Recommends Closing Fort Calhoun.)
A judge struck down a lawsuit by natural gas leaseholders who said anti-drilling activists had interfered with their rights by filing an unsuccessful legal challenge that they said had caused costly delays.
Judge Michael Yeager of the Butler County Court of Common Pleas ruled that the critics’ objections to a pro-drilling ordinance were protected by the right to free speech.
The decision does not affect the judge’s previous order in which he rejected the environmental group’s challenge and upheld the town’s zoning ordinance, which opened up nearly much of the township to potential shale gas drilling.
Public Utility Commission investigators have filed its first formal enforcement action against a power broker operating without a license.
Electricity supplier Fair View Energy, based near Erie, has signed up hundreds of commercial customers. Investigators say the supplier’s principals should have known they needed a license, as they’ve worked for other suppliers.
The commission’s enforcement arm is seeking $89,800 in civil penalties as well as refunds of fees paid by customers.
Archeologists Uncover Artifacts In Path of Mountain Valley Pipeline
Archeologists surveying properties in the path of the proposed Mountain Valley Pipeline in Franklin County have found a trove of Native American artifacts, calling into question the job done by archeologists hired by the pipeline company.
The Mountain Valley Pipeline is a proposed $3.5 billion, 301-mile pipeline to transport natural gas from West Virginia through five Virginia counties to feed into a larger pipeline.
Pipeline opponents hope that the discovery of the artifacts may help them obtain historic designations for properties and impede the pipeline. The artifacts include arrowheads, tools and pottery shards.
Dominion Virginia Power Advances Coal-Ash Storage Project
State regulators last week issued a draft of one of two permits Dominion Virginia Power needs to store more than a million tons of coal ash at the site of a defunct power plant in Chesapeake, the state’s third most populous city.
The draft of the other permit is expected to be issued this week.
Meanwhile, Chesapeake officials are fighting to have a say in how the site is regulated, and Dominion is battling a federal lawsuit by environmentalists who say the ash should be removed, not stored onsite.
The Seattle City Council has passed a resolution calling for its city-owned utility to seek power from non-nuclear sources and push provider Energy Northwest to investigate non-nuclear, carbon-neutral sources.
Energy Northwest operates the Columbia Generating Station, the region’s only nuclear station. Its power goes to the Bonneville Power Administration, which supplies about 4% of the Seattle City Light Department’s electricity.
The company says the council only heard one side of the story before its vote. “They just got a lot of really bad information that went unchallenged and, unfortunately, they acted on it,” a company spokesman said.
After allegations of management interference led PJM to replace its internal market monitoring unit with an independent monitor in 2008, FERC had an opportunity to prohibit other RTOs from using the internal structure. Because it chose not to do so, the temptation for RTO officials to muzzle their MMUs remains.
‘The Most Troubled Period in the History of PJM’
Second in a Series
Joe Bowring’s allegations at a FERC technical conference in 2007 that PJM management had attempted to muzzle his internal market monitoring unit shook the RTO to its roots.
It was “the most troubled period in the history of PJM,” Irwin “Sonny” Popowsky, then Pennsylvania state consumer advocate, told The Washington Post at the time. Patrick McCullar, president of the Delaware Municipal Electric Corp., said confidence in PJM management “seems to be at an all-time low.”
But it wasn’t the finest moment for FERC in the view of state regulators, who contended the commission conducted only a half-hearted investigation.
Bowring made his allegations in April 2007 after then-CEO Philip Harris said he was considering replacing Bowring and his team with an outside firm. Bowring accused PJM management of censoring his reports, preventing him from presenting his views to a stakeholder committee and raiding his staff.
The allegations prompted PJM’s Board of Managers to hire a law firm to conduct an internal investigation and FERC to issue data requests to Bowring and the RTO.
By May, PJM COO and executive vice president Audrey Zibelman had resigned, followed by Harris’ retirement two months later. Zibelman, now chair of the New York Public Service Commission, and Harris, now CEO of Tres Amigas, later married.
Restoring Confidence
Harris
Based on its review of 2,700 pages of documents produced by the data request, the commission issued an order in September 2007 concluding that PJM had not violated its Tariff but that RTO management exerted an “unusual degree of supervision” over the monitor. While ordering Bowring and PJM to seek a settlement to the dispute, the commission made a preliminary finding that the monitor should report to the board rather than management.
“A consensual resolution is most likely to restore confidence in the efficient, impartial and competitive operation of PJM’s markets and in the monitoring of those markets, confidence that has been jeopardized by the recurring controversy over the role of PJM’s MMU,” FERC said.
The commission noted that although Bowring had sent an email in January 2007 to a member of the commission’s Division of Energy Market Oversight alleging “a clear infringement of MMU independence and a violation of the Tariff Attachment M,” he had softened his criticism in his response to the commission’s data request. Instead, he said that he was concerned that “left unchecked, such PJM actions [as described at the technical conference] will escalate to the point where PJM would violate the Tariff.”
Bowring had complained the MMU’s full-time staff was reduced from 15 to 13 after two employees accepted job offers in the RTO’s Markets Department. FERC concluded that the employees left because of their expertise in the development of cost-based rates, a function that PJM had recently assigned to the department.
The commission cited emails in which Bowring accused Andy Ott, then PJM’s vice president of markets, of threatening one of the MMU employees if he refused to transfer. But FERC said PJM human resources interviewed the employee and “reported that the transferee did not feel intimidated” by RTO management or Ott, now CEO, “and, in fact, agreed that the cost-based rates function should properly be in the Markets Department.”
The commission also looked into Bowring’s allegation that Zibelman ordered him to remove from the 2005 State of the Market report his conclusions regarding an absence of structural competition in the regulation market. Bowring’s analysis ultimately was included in the final SOM report, although without his earlier conclusion.
“It is unclear whether PJM was attempting to influence Dr. Bowring to alter his conclusion, or whether it was simply trying to make sure his revised analysis was sound,” the commission said.
FERC concluded that there was a “systemic problem in the relationship between Dr. Bowring and PJM management, as well as a fundamental disagreement between them as to the appropriate balance between independence and accountability of the MMU.”
The Organization of PJM States Inc. (OPSI), which represents state regulatory commissions, filed a request for rehearing of the order, criticizing the “scant” record developed by FERC and calling for a broader probe in which the state commissions would take part.
“OPSI simply has not been permitted to look into these allegations at all, and the commission has not looked very hard,” it said.
“It is clear from the record that does exist that PJM has engaged in a pattern of conduct with the express intention of interfering with the independent operation of its MMU, conduct which does violate both PJM’s Attachment M and general commission policy.”
OPSI said PJM’s questioning of the two employees who transferred from the MMU was insufficient and that they should be interviewed “away from the senior RTO management upon whom the livelihood of such employees depends … to fully establish whether MMU personnel were pressured to leave the MMU.”
The regulators also cited evidence of a “secret internal set of procedures” governing the implementation of Attachment M.
“These procedures specifically intend to muzzle the MMU. … These procedures were and are wholly incompatible with any notion of independence and subject the PJM market monitor to detailed day-to-day review, objection and the exercise of editorial powers by PJM senior management in the smallest matters, effectively placing the PJM market monitor directly under the day-to-day control of [Zibelman] and requiring the market monitor to seek prior approval for almost any significant action or communication.”
After allegations of management interference led PJM to replace its internal market monitoring unit with an independent monitor in 2008, FERC had an opportunity to prohibit other RTOs from using the internal structure. Because it chose not to do so, the temptation for RTO officials to muzzle their MMUs remains.
Second in a Series
By Tom Kleckner and Rich Heidorn Jr.
LITTLE ROCK, Ark. — Alan McQueen, head of the SPP internal Market Monitoring Unit, says the best evidence of the MMU’s independence is in the filings it has made to FERC staking out positions contrary to the RTO and market participants.
“The proof is in … our record,” he said. “And that’s what’s important.”
The record shows that until the last 18 months, the MMU generally filed only testimony packaged with RTO filings. Since then, it has filed comments opining on SPP filings or policies in nine dockets: six times siding with the RTO and three times proposing different rules. FERC sided with the MMU in two of the three challenges.
Catherine Mooney and John Hyatt, formerly two of McQueen’s three direct reports, say that the three challenges were exceptions and that McQueen discouraged them from opposing positions held by SPP and its stakeholders. Hyatt and Mooney, who were fired in December, say they were dismissed for resisting pressure to conform to policy positions of SPP management and members. (See Part 1: SPP Squelching MMU Independence, Former Monitors Say.)
Former SPP market monitors Catherine Mooney and John Hyatt say MMU Director Alan McQueen only allowed them to challenge SPP proposals before FERC after pressure from commission staff. Hyatt said SPP board member Harry Skilton discouraged the MMU from such filings, saying, “we like to handle these [disputes] within the SPP family.” Noman Williams, now chairman of the Markets and Operations Policy Committee, called for the MMU to “become much more engaged in the process” of reaching consensus solutions rather than merely observing and critiquing. Former MOPC Chairman Rob Janssen voiced concerns about a “PJM-style train wreck” if the MMU filed comments with FERC, Mooney said.
Half-Hearted Opposition
Mooney said that while the MMU would often disagree with RTO proposals at Market Working Group meetings — where market-design revisions are hashed out — it would drop its opposition if members approved them, despite its responsibility to notify the commission of such disagreements.
Mooney
The former monitors say SPP’s FERC filings started only after commission staff questioned whether the MMU was fulfilling its obligations.
“It became clear to us that FERC expected us to file,” she said. “Until late 2014, we had not been doing it.” A FERC audit that began in April 2015 brought increased scrutiny.
FERC detailed its expectations of MMUs when it issued Order 719 in 2008. “We do expect the MMU to advise the commission, the RTO or ISO, and other interested entities of its views regarding any needed rule and tariff changes,” the commission said. “Likewise, in the event an RTO or ISO files for a proposed tariff change with which the MMU disagrees, we expect the RTO or ISO to inform the commission of that disagreement, although not necessarily to include a written MMU proposal with its filing.” (See Order 719: FERC Balanced MMU Independence Against RTO Autonomy.)
SPP spokesman Dustin Smith said the increase in MMU filings was the natural result of SPP’s developing, and more complex, markets.
“I think it is important to note that SPP did not have a day-ahead market until March of 2014. Prior to March 2014, SPP operated its [Energy Imbalance Service] market, which had a much more simple structure than SPP’s new Integrated Marketplace. The nature of developing market rules for a new marketplace necessitates more filings than does operating the more simple EIS market. The number and frequency of filings has less to do with time and more to do with the type of market SPP operates.”
However, FERC records show that SPP made its first Tariff filing on the marketplace in February 2012 (ER12-1179), more than two years before the MMU began commenting separately in FERC dockets. SPP records show the MMU began attending Market Working Group discussions on the development of the marketplace in September 2009.
Surprising Admission
FERC records show that the first listing of the MMU as the author of a substantive policy filing was in December 2014, when it requested rehearing of a September 2013 commission order requiring the removal of its market impact test from the MMU’s monitoring for physical withholding. The MMU said eliminating the test would “produce excessive false positive screen failures for the MMU to analyze” (ER15-21).
The December filing, which was signed by Mooney and Hyatt, included a surprising admission: The MMU had delayed raising the issue for more than a year after FERC’s order.
Hyatt
“We apologize for the delay in raising this to the commission’s attention,” they wrote. “In 2013 and early 2014, SPP’s staff maintained a focus on supporting the effort to launch the Integrated Marketplace by March 1, 2014, for the greater benefit of SPP and its members.” The changes the MMU sought “were not seen as critical for the market to launch,” they said, adding that the MMU believed it could make changes after market launch.
Mooney and Hyatt said SPP had warned staff against doing anything that could delay the launch of the marketplace, which gave the RTO a day-ahead market, real-time balancing market and a centralized balancing authority. “If the market is delayed, it better not be your fault,” they said RTO employees were told by management.
When the marketplace opened, SPP boasted in a press release that it was the first RTO “to design, build and deliver a Day 2 market on time.”
FERC rejected the belated rehearing request in August 2015.
Three Challenges
The MMU’s first direct challenge to SPP came in April 2015, when Mooney asked FERC to reject proposed Tariff changes that would prevent the RTO from canceling commitments of gas-fired generators if they are not needed. SPP’s proposal, Mooney wrote, would result in “an inefficient transfer of gas market risks to SPP’s load.” (See SPP Market Monitor Protests Make-Whole Promise for Gas Units.)
FERC rejected the monitor’s concerns and accepted the Tariff changes in August (ER15-1293). The commission said the RTO’s proposal “provides additional certainty about how SPP will operate during extreme conditions” and that it was “not proposing fundamental changes to the way it administers de-commitment of resources.”
The MMU fared better in September 2015, when it helped persuade FERC to reject an SPP proposal to change what costs are included in mitigated offers, which are required when a generator is deemed to hold market power (ER15-2268).
In February 2016, FERC again sided with the MMU over SPP in the solution to an underfunding problem in the RTO’s transmission congestion rights market (ER16-13). As recommended by the MMU, the commission set the amount of transmission system capability to be offered during the annual auction revenue rights allocation process at 60% for October through May, rejecting SPP’s proposal of an 80% allocation. (See FERC Rejects SPP’s Proposed 80% ARR Allocation.)
‘Obstructing SPP’s Progress’
Hyatt said McQueen often complained “‘You don’t understand the pressure I’m under.’”
McQueen declined to say whether he had made such a comment.
The mitigated offer case provided a vivid illustration of the pressures.
SPP filed its proposed Tariff changes after more than a year of stakeholder meetings failed to reach consensus on the issue. The RTO acted in response to generators who became upset after the Integrated Marketplace opened that the MMU was not including general operations and maintenance in its calculations of cost-based offers.
In April 2014, SPP created the Mitigated Offer Task Force to address the generators’ concerns. Mooney and Hyatt said they opposed concessions to the generators in defense of “efficient market economics.”
The monitors argued that SPP’s proposed changes would allow mitigated offers to include recovery of variable operation and maintenance (VOM) costs that are not short-run marginal costs. FERC had required the RTO in an October 2012 order to “establish that offers are to be mitigated to their short-run marginal costs of the generating unit.”
Mooney said the monitors’ position brought a rebuke from McQueen, who told Mooney that they were “obstructing SPP’s progress.”
There were a “lot of messages to not say this or that, because it’s a hot button and it makes the members upset,” Mooney said. The term “short-run marginal costs” was one such hot button. “I was told to stop using those words altogether,” she said. The term is “in SPP’s Tariff. It’s hard to have an intelligent conversation about short-run marginal costs without saying the words.”
McQueen did not respond to requests for comment for this article.
Hyatt recalled a lunch that members of the MMU had with several SPP board members last June, at which he said Vice Chairman Harry Skilton expressed disappointment that the MMU was considering a FERC filing differing from the RTO’s position. “We like to handle these [disputes] within the SPP family,” Skilton said, according to Hyatt’s recollection.
“These types of comments were very common,” Hyatt said.
Skilton declined to comment.
Lobbying the Oversight Committee
Such messages also were delivered by members.
In September 2014, Noman Williams, then of Sunflower Electric Power, attended a meeting of the Board of Directors’ three-member Oversight Committee “to represent the member perspective” on the issue, according to meeting minutes.
The Oversight Committee is responsible for monitoring compliance with SPP and regulatory policies. It also is assigned to supervise the MMU. Attachment AG of SPP’s Tariff states that “management representatives on the Board of Directors will be excluded from the Board of Directors’ oversight of the market monitor.”
Nevertheless, until recently, SPP management regularly attended Oversight Committee meetings with the MMU. Stacy Duckett, then vice president and chief compliance officer, was in attendance when Williams made his pitch.
Williams “suggested MMU be more overt on its positions and intent to resolve matters through the SPP process,” according to the minutes.
Williams, now chairman of the Markets and Operations Policy Committee, said in an interview that he was encouraging the MMU to “become much more engaged in the process” of reaching consensus solutions rather than merely observing and critiquing. He said he was not suggesting the MMU not file opposing comments before FERC.
Mooney recalls then-MOPC Chairman Rob Janssen, of Dogwood Energy, saying at a meeting in December 2014 that he feared a “PJM-style train wreck” if the MMU filed comments with FERC opposing a Tariff change supported by members. Janssen formerly worked at D.C. consulting firm Boston Pacific, where he helped McQueen and Director of Market Design Richard Dillon structure the MMU.
His remark was an apparent reference to what transpired in 2007, after PJM Market Monitor Joe Bowring — then a PJM employee — complained at a FERC technical conference that RTO management was attempting to muzzle him. Following an investigation, PJM’s CEO resigned and Bowring formed his own company to become the RTO’s external monitor.
Janssen declined to comment.
Dueling Proposals
In July 2014, American Electric Power’s Richard Ross proposed market protocol revision request (MPRR) 197, which would allow generators that did not use FERC accounts or separate variable costs from fixed costs in their commission filings the ability to “include some level of variable costs in their mitigated offers.”
At McQueen’s direction, Mooney helped develop a compromise, MPRR 213, that was submitted by ACES Power in September. The proposal included a table of costs that was less generous than the AEP proposal but still higher than Mooney wanted. “These numbers were drawn up to be large enough to get the members to stop complaining,” Mooney said.
In December 2014, the MOPC recommended that the Board of Directors approve the AEP proposal, but the board declined, citing the MMU’s opposition. Instead, the board created the Mitigated Offer Strike Team to reach a compromise.
The team was composed of Dillon, McQueen and representatives from Westar Energy, ACES and the Oklahoma Municipal Power Authority. Mooney, AEP’s Ross and other members of the earlier task force were excluded from the strike team, which met in private, not open to any other stakeholders.
The strike team sent a written recommendation to the MOPC that called for implementing default VOM costs for mitigated offers as an interim measure and adapting MISO’s approach for mitigated offers as the long-term solution.
At a testy MOPC meeting on Jan. 13, 2015, Dillon presented the recommendation, which was described as unanimous.
But an uncomfortable-looking McQueen was reluctant to give the proposal his endorsement. “I think the approach was a sound way to do it” was as far as he would go, according to RTO Insider’s contemporaneous notes of the meeting.
Doug Collins of the Omaha Public Power District complained that the costs the MMU wanted to include were “one-tenth of 1% of the costs I want to include,” he said, hyperbolizing for emphasis. (See SPP Moves Forward on Change to Generator Mitigation Rules.)
Two months later, in an apparent effort to straddle the divide, McQueen told the MWG that the MMU supported the default costs but wanted the Tariff change to include the words “short-run marginal costs.” Mooney protested that the MMU’s position was illogical because the default levels were not representative of short-run marginal costs. “This is not about logic,” Mooney said McQueen told her. “This is about people.”
In July 2015, SPP filed a Tariff change that largely mirrored the compromise MPRR 213. SPP’s filing drew protests and interventions from nearly two dozen market participants, including the New Jersey Board of Public Utilities, which said it feared an “adverse precedent that spills over to other regions.”
The MMU responded with a filing Aug. 14 that disagreed with several aspects of the change. Two subsequent filings were stronger in their criticism.
“The audit made it very clear that FERC was watching what we were doing,” Mooney said. “I do think that contributed to the strength of the statements.”
SPP proposed generators be able to recover VOM costs that included maintenance overhauls, long-term service agreements, insurance and inspection services.
The MMU, in contrast, said recoverable costs should be limited to the cost of inputs “directly consumed” as a result of a generator’s decision to produce in a given hour: fuel, emissions, opportunity costs, “a small amount of maintenance and, on occasion, labor.”
The MMU also disputed assertions by SPP and generation owners including AEP and Westar Energy that “all variable costs and short-run marginal costs are synonymous terms or otherwise interchangeable.”
“The decision to incur major maintenance costs, as well as many of the other costs included in the FERC maintenance accounts that the SPP filing seeks to include in mitigated offers, are long-term decisions,” it said.
The SPP proposal included a default start-up VOM cost for industrial frame gas turbines of $15/MW. Monitoring Analytics, which was advising SPP as a consultant, had recommended setting the short-run marginal costs for such plants at only $0.12/MW — or less than 1% of what SPP proposed.
SPP’s proposal, the MMU said, would result in unjust preferences to generators with market power, allowing the RTO to obtain excessive “cost-based” rates. It noted that “competitive pressure prevents those without market power from similarly raising offers to obtain higher revenues.”
“We find that SPP’s proposal to base mitigated offers on variable costs may lead both to inefficient dispatch outcomes, characterized by higher production cost, and to distorted locational marginal prices that do not reflect competitive conditions,” the commission said.
FERC said SPP failed to define the term “variable cost” or to “describe with specificity what costs may be included in mitigated offers as variable costs that were not previously regarded as short-run marginal costs.”
“As such,” the commission said, “SPP proposes to replace one phrase that SPP contends is undefined (short-run marginal cost) with another phrase that is not well defined (variable cost).”
Monitoring Analytics, PJM’s Independent Market Monitor, also had weighed in on the case, filing a protest that backed the MMU’s position.
The IMM said the proposed changes raised questions about whether SPP was protecting its MMU’s independence. “When the SPP market monitor made interpretations with respect to mitigated offers that SPP market participants did not like, the response was that market participants initiated a stakeholder process to apply pressure on the SPP market monitor to compromise or change those interpretations,” FERC said, paraphrasing the IMM’s filing.
The commission rejected the PJM monitor’s call for an examination of the MMU’s independence as outside the scope of the docket. “We note, however, that the SPP market monitor’s participation in this case demonstrates the importance of having an independent market monitor … to ensure that markets are competitive.”
[Editor’s Note: SPP/ERCOT Correspondent Tom Kleckner worked as an SPP spokesman from 2011 to 2015; Editor-in-chief Rich Heidorn Jr. is a former member of FERC’s Office of Enforcement.]
While FERC’s technical conference last week was ostensibly focused on reliability, resiliency became the theme as many panelists agreed: It’s not possible to avoid a major grid disruption forever (AD16-15).
Speaking from recent experience, Miranda Keating Erickson, vice president of operations for the Alberta Electric System Operator (AESO), put a fine point on it.
“We must remember that no amount of standards can prevent all events from happening that will impact the reliability of our electricity system. Snow storms will happen. Ice storms will happen. Tornados and hurricanes will happen. As I well know, floods and wildfires will happen,” she said, referring to the Fort McMurray wildfire, which has destroyed 2,400 homes and buildings and caused the largest wildfire evacuation in the province’s history since it began May 1.
“And let’s not kid ourselves; at some point, somewhere, cyber and physical attacks will happen. That means resiliency is just as important as prevention. It is critical that we also focus on our ability to minimize impacts and improve response and recovery time when these events do occur.”
FERC called the conference to mark the 10 years since Congress gave the commission the power to impose mandatory reliability standards. The commission asked speakers to identify the accomplishments of the last decade and the challenges of the future.
Gerry Cauley, CEO of NERC, which was designated by FERC to develop and enforce the standards, started the conference by noting that the 10 largest grid “integrity events” each year from 2012 through 2015 were caused by weather. The last operational issue to make the list was in September 2011.
Cauley, however, cautioned that the shift to natural gas and intermittent generation will require renewed focus on issues such as ramping, frequency control, voltage control and inertia. “As we move forward with this evolution, however, we are experiencing a change of operating characteristics for the grid,” he said.
He highlighted measures being recommended by NERC’s Essential Reliability Services Task Force that would provide better monitoring and control of frequency and voltage.
Others agreed that the increasing dependence on natural gas generation is impacting grid stability.
FERC Commissioner Tony Clark noted that it’s a “challenging prospect to conceive how those [gas] assets can be physically protected.”
Paul Koonce, CEO of Dominion Generation Group, who spoke on behalf of the Edison Electric Institute, urged the importance of building out the necessary natural gas infrastructure, including long-haul pipelines, to ensure the gas can be moved easily.
Paul Stockton, the managing director of D.C.-based consulting firm Sonecon, thanked FERC for its recent reports on the interdependence of the natural gas and electricity industries, calling them “terrific work.”
“I would ask you to continue to focus on the challenges of the resilience of black-start capabilities … [and] the increasing reliance of many companies on natural gas as a source of fuel for their generators,” said Stockton, former assistant secretary of defense for homeland defense. “This, my friends, deserves careful attention.”
Stockton was among several speakers who noted growing concerns with cyber and physical security. Cauley cited the threat of a physical attack on infrastructure as his greatest worry “because of the potential long-term impact and the difficulty recovering, possibly lasting weeks and months.” (See Critics: Koppel Doomsday Scenario Ignores Prep.)
Patricia Hoffman, the Energy Department’s assistant secretary for electricity delivery and energy reliability, said the growing impact of distributed energy resources has created new needs. “The need for new metrics, new kinds of data and new data-sharing protocols is just as important at the distribution level as at the bulk-power level,” she said. “In fact, this need is probably more challenging than at the bulk-power level, if only because we are starting from a less developed base.
“The grid is the battery for the system. It’s basically the backup for the system,” she said. She voiced concern that security threats will be “malicious in nature” and not addressed simply by preparing for N-1 contingencies. “Unfortunately, these investments are not valued by the market.”
Clark expressed hope that NERC’s cost-effectiveness method pilot program will result in new strategies. “Personally, I hope [it] will lead us to some important discoveries regarding how costs can be better contemplated and assessed in the standards-development process.”
Koonce also supported many of NERC’s recommendations and counseled that FERC review issues in a “broad context and with systemwide considerations.”
“Corporate strategic and management actions rest on a strong foundation, and decisions are made with great care and deliberation. Application of these business principles to NERC and electric reliability would naturally invite broad long-term strategic questions, questions that will very likely yield different answers when compared to looking at day-to-day problems or events, or individual components,” he said.
Koonce said that EEI believes version 5 of NERC’s Critical Infrastructure Protection standards is an “appropriate and reasonable approach.” But, he added, “vendor management risks under consideration by the commission for potential new NERC requirements to address cyber-related asset procurement raises some broad questions on the business risks beyond the control of jurisdictional entities, as well as the reach of commission jurisdiction.”
Flexibility was also a big concern for Erickson, who noted AESO’s ability to consider NERC standards and decide if they want to adopt them.
For Joseph Eto, a staff scientist with Lawrence Berkeley National Laboratory, the question was what’s not being considered? “Not all that counts can be counted and not all that can be counted counts,” he said, quoting an adage. He urged expanding metrics on interruptions to calculate the economic impacts on customers.
Carnegie Mellon University professor Marija Ilić summed it up, saying what worries her most is the sheer complexity of the system. The 2003 blackout could have happened anywhere, she said, but also could have been prevented if complexity were handled in more systematic way.
“It’s my belief that we’re going to have more of those events,” she said.
While there was consensus on the importance of maintenance and tree trimming, there was disagreement over whether the industry should standardize equipment. Several industry representatives noted that equipment is sized specifically for its intended use. Arizona State University professor Anna Scaglione, however, said resistance to standardization was as much about lack of vision as engineering — a “cultural problem of industry,” she called it, where no one is considering the interoperability of equipment.
Chris Murray, the project support lead for the Navy’s Renewable Energy Program Office, said the military branch is highly supportive of efforts to increase energy security and is open to having infrastructure projects sited on its properties throughout the country. “If there’s land on our base that you think makes sense, let us know,” he said. “We are marching down a path that most folks haven’t done in the government. … Things are changing and we need your help.”
Hector Beltran, the director general of Mexico’s Energy Regulatory Commission, said his country is making strides to develop its bulk-power systems and hopes to create a system reliable enough to integrate with the North American system very soon.
Mexico awarded its first round of long-term generation contracts in March, he said, and plans to build a series of interconnections along the border with the U.S. so that the networks can freely interact with each other. He noted that the following day, representatives from both the Mexican and American power industries were meeting in Mexico City to identify collaboration opportunities.
Barely a year after it went public as an independent company, Talen Energy is going private.
The company announced Friday that it had agreed to be acquired by Riverstone Holdings, which is offering $14/share in cash for the company’s outstanding shares, a $2 premium to the closing price Thursday. While the total cost of the stock will be approximately $1.8 billion, the deal has a total value of approximately $5.2 billion including assumed debt. It is expected to close by the end of the year.
Talen was formed last June from the merger of PPL’s generation assets with some of Riverstone’s power plants. Through its affiliates, Riverstone already owns a 35% stake in the Allentown, Pa.-based competitive power producer, which owns or controls 16 GW of capacity in eight states. Most of Talen’s capacity — which is divided between gas (47%), coal (39%) and nuclear (14%) — is in PJM and ERCOT.
Tough competition and tight profit margins battered Talen’s valuation from the beginning, and analysts saw Riverstone’s move as a chance to buy the assets at a bargain.
Formed during a period of historically low natural gas prices, Talen’s stock started to drop the day it hit the exchange and never fully recovered, losing more than half its initial value of $21.23/share within five months. On news of the deal, Talen’s stock — which had been rising amid rumors of the deal — jumped nearly $2/share to settle just shy of the $14 Riverstone is offering.
Talen noted in its announcement that the purchase price represents a 56% premium to the closing price of $9/share on March 31, 2016, the last trading day before public reports of the potential sale CEO Paul Farr said the deal “offers compelling value to our stockholders.”
The agreement provides a 40-day period for Talen to find a better deal and another 20 days to enter into a transaction. Should Talen accept a superior proposal during the “go-shop” period, Talen will pay $25 million to Riverstone. Otherwise, its cost to terminate the agreement for a superior proposal will be $50 million.
The deal is being funded by conversion of Riverstone’s existing Talen stock, Talen’s cash on hand and a $250 million new secured-term loan.
In a research note Friday, UBS Securities suggested Talen shares might rise further on expectations of a better offer.
“With a relatively small go-shop fee and even more secured debt capacity … we would not be surprised to see shares even trade above $14,” UBS said.
UBS said Talen fared worse than its peers in last month’s PJM capacity auction, with fewer assets clearing than last year. It estimated that Talen’s PJM capacity revenue will decline by $230 million to $320 million.
The deal is subject to approval by FERC and the Nuclear Regulatory Commission as well as the 65% non-Riverstone shareholders.
“The scenario under which a deal might not be approved [by shareholders] is if commodities rallied prior to shareholder approval date such that the bid was no longer commensurate with the market environment,” UBS said.
But the analysts said shareholders are unlikely to see another suitor willing to pay more because other independent power producers already have concentrations of generation that would likely trigger market power screens. Talen’s coal generation is anathema to Calpine, and its Susquehanna nuclear plant is likely to scare off anyone not already running a nuclear fleet, UBS said. Dynegy and NRG Energy are in restructurings and unlikely to be able to make a purchase, they added.
“Despite the argument that the company is being bought effectively using its own liquidity and leverage capacity, we do not see an obvious outside bidder desiring to pay such a premium,” they said.
A New Hampshire court has dismissed a complaint by a conservation organization seeking to block development of land alongside a state highway needed to bury a section of the Northern Pass transmission line.
The Coos County Superior Court said the Society for the Protection of New Hampshire Forests cannot deny access to project developers in its attempt to halt the line, saying the decision ultimately rests with state transportation officials (15-CV-114). (See Northern Pass Facing Challenges over Siting.)
The organization owns a parcel of land along Route 3 in northern New Hampshire known as the Washburn Family Forest, and it granted easements to the state Department of Transportation in 1931 for road construction through the land.
The society argued that those easements did not include underground construction, but the court disagreed.
“The court finds that under the plain language of [state law], NPT’s proposed use is a proper use of the public highway easement … [and] the DOT has exclusive jurisdiction over whether to grant NPT a permit to install the proposed transmission line below the stretch of Route 3 at issue,” Judge Lawrence A. MacLeod Jr. wrote in the May 26 opinion.
The court also declined to consider the merits of the 192-mile line, which would transmit 1,090 MW of Canadian hydropower to the New England market. It said such questions were “speculative” until the DOT gave its approval.
“The DOT, not this court, must decide … whether a proposed project meets the ‘public good’ requirement of” state law, the court said.
The society said it was not surprised by the ruling.
“The decision effectively kicks the can down the road relative to the ultimate resolution of important property rights issues involving Northern Pass, the DOT and private landowners,” spokesman Jack Savage said in a statement. “We note that the state Constitution expressly prohibits the use of the state’s power of eminent domain for elective transmission projects and would have preferred not to wait for the DOT to potentially issue a license before resolving that constitutional conflict.”
Savage told RTO Insider on Wednesday an appeal to the New Hampshire Supreme Court is one option under consideration.
Project developer Eversource Energy lauded the ruling.
“We are pleased the court recognized long-standing New Hampshire law that allows for the use of public roadways for projects like Northern Pass,” Bill Quinlan, president of Eversource Operations in New Hampshire, said in a statement. “We look forward to continuing the permitting process and moving one step closer to delivering the clean energy and economic benefits to New Hampshire and the region.”
Developers Seek Shorter Schedule
On Tuesday, Northern Pass Transmission, an Eversource subsidiary, asked the state’s Site Evaluation Committee for a written decision on its application by June 30, 2017.
“The proposed schedule seeks to strike a balance between the statutory requirement to complete the evaluation within 12 months and the need for adequate time to evaluate a project the size and scope of Northern Pass,” NPT said in a statement.
The committee last month informally indicated it would need nine more months than the year required by state law for its study of the project route, which would push its decision back to about Sept. 30, 2017. In a motion filed Monday, NPT is asking for a ruling three months earlier. A formal ruling by the committee on its schedule is pending. (See Northern Pass Decision Delayed Nine Months.)
FERC on Wednesday approved CAISO’s plan to temporarily alter its market rules and operations in response to natural gas pipeline restrictions stemming from the closure of the Aliso Canyon storage facility (ER16-1649).
The grid operator last month sought expedited approval for the Tariff changes, designed to ensure reliable operations in Southern California in the face of potential gas shortages this summer — the region’s peak period for power generation. (See CAISO Board Approves Aliso Canyon Response.)
The commission also directed staff to convene a technical conference to evaluate the effectiveness of the provisions and determine the need for additional longer-term measures, addressing a concern of a number of CAISO stakeholders.
“Substantial efforts have been made by CAISO, California regulators and the energy companies to enhance planning and preparation, communication and coordination, and situational awareness,” FERC Chairman Norman Bay said in a statement. “That being said, the situation remains a serious one, and we will continue to monitor Aliso Canyon very carefully.”
Under new pipeline requirements effective June 1, Southern California Gas customers face penalties as high as 150% of daily gas indices when their daily burn deviates from nominated flows by more than 5%. The region’s generators have complained they would likely incur financial losses when the ISO’s real-time dispatch instructions cause them to burn more or less gas than planned for on a given operating day.
The new market rules will help generators manage their burns to avoid system-balancing penalties and allow them to recover costs after the fact, while ensuring the ISO is capable of moving generation into the region when gas supplies are constrained.
Key provisions of the plan include:
The release of advisory schedules by CAISO two days ahead of an operating day to help scheduling coordinators plan for gas procurement further in advance;
Inclusion of a gas adder and an after-the-fact cost recovery mechanism for generators connected to the SoCalGas system, allowing those units to recover costs based on same-day gas prices — including potential penalties — rather than day-ahead gas indices;
Implementation of a new constraint in the CAISO market that limits the minimum and maximum amount of gas that can be burned by generators in the affected area during periods of restricted gas supply;
Reservation of transmission capability on the Path 26 transmission line linking the Pacific Gas and Electric (PG&E) and Southern California Edison service territories in order to ensure adequate capacity to deliver energy into the southern part of the state during gas restrictions; and
Suspension of virtual bidding in circumstances when CAISO determines the practice could produce market inefficiencies.
FERC rejected a request by NV Energy and Calpine for CAISO to develop a gas adder for generators located outside the SoCalGas network. The two companies contended that limited gas supplies in that system would likely drive up fuel prices in neighboring areas. The commission instead determined that the adders are designed to specifically address the conditions confronted by Southern California gas-fired generators, which “need a mechanism by which to manage gas-balancing requirements within tightened tolerance bands.”
“This is not the case with resources outside of Southern California,” the commission said.
The commission also rejected PG&E’s request that the ISO perform a market simulation before rolling out the plan, saying that “timely implementation of these market changes outweigh the potential benefits of requiring market simulation in this instance.”
The commissioners additionally declined a request by NRG Energy that CAISO be ordered to implement long-term changes to its market rules related to gas cost recovery by Dec. 1, 2016. During stakeholder calls earlier this year, the company repeatedly raised concerns about its exposure to increased gas costs and balancing penalties.
“We find that it is premature to require CAISO to implement long-term changes by a date certain when the scope and duration of any potential problems are currently unknown,” the commission said, adding that those measures should be addressed in the upcoming technical conference.
Exelon will close its Clinton and Quad Cities nuclear plants after the Illinois General Assembly adjourned this week without acting on a bill that would have subsidized the money-losing stations, the company said Thursday.
Clinton will shut down next June 1, and Quad Cities will close the following year. Together, the plants have lost $800 million in the past seven years, Exelon said.
Clinton Nuclear Plant Source: Exelon
The company will be submitting permanent shutdown notifications to the Nuclear Regulatory Commission within 30 days. Among other steps toward closure, Exelon will be ending capital investment projects at the plants, taking a one-time charge of $150 million to $200 million for the year, accelerating about $2 billion in depreciation and amortization and canceling fuel purchases and outage planning, Exelon said.
Ceasing the investment projects will impact more than 200 workers, and more than 1,000 outage workers will be affected, according to the company.
“We have worked for several years to find a sustainable path forward in consultation with federal regulators, market operators, state policymakers, plant community leaders, labor and business leaders, as well as environmental groups and other stakeholders,” CEO Christopher Crane said. “Unfortunately, legislation was not passed, and now we are forced to retire the plants.”
Crane had given legislators a May 31 deadline to help shore up the struggling generators if the 1,819-MW Quad Cities station did not clear the PJM Base Residual Auction for delivery year 2019/20. It failed to do so. (See Absent Legislation, Exelon to Close Clinton, Quad Cities Nukes.)
While the 1,065-MW Clinton plant won contracts in the MISO auction, its clearing price was insufficient to cover operating costs, Crane said.
According to Exelon, their closures will represent a $1.2 billion loss in economic activity and 4,200 direct and indirect jobs. The plants employ 1,500.
Next Generation Energy Plan
The Exelon-backed legislation, called the Next Generation Energy Plan, incorporates pieces of a similar bill the company proposed last year as well as part of the competing Clean Jobs Bill. The latter proposal aimed to reduce energy demand by 20% through energy efficiency; increase the renewable portfolio standard from 25% by 2025 to 35% by 2030; and create an estimated 32,000 jobs annually by creating a market mechanism to reduce carbon emissions.
A key element of the new plan is a shift to a zero-based emission standard, which would provide financial support for struggling nuclear plants in recognition of their lack of carbon emissions.
Exelon said the standard would address stakeholder concerns by requiring state regulators to review plants’ expenses to ensure that only those whose revenues are insufficient to cover their costs and “operating risk” would receive compensation.
On Friday, the bill received the endorsement of Ameren Illinois, but on the condition of an amendment changing energy efficiency targets that could make it unpalatable to environmentalists.
Quad Cities Nuclear Plant
In introducing the energy plan, Exelon said it was an outgrowth of discussions among it, Commonwealth Edison and members of the Clean Jobs Coalition, a group representing Illinois’ environmental, business and faith communities.
The coalition supports the bill’s expansion of ComEd’s energy efficiency programs, which it said would save customers at least $4 billion over a decade. But it said the Ameren amendment would exclude that utility’s customers from the expansion.
“While ComEd has offered a strong energy efficiency plan, the Ameren proposal … is a half-measure that will leave downstate customers with fewer jobs and higher bills than people in Chicago and Northern Illinois. Ameren is really leaving Central and Southern Illinois in the dark,” the coalition said in a statement.
Exelon said it will continue to push the legislation.
“While these needed policy reforms may come too late to save some plants, Exelon is committed to working with policymakers and other stakeholders to advance an all-of-the-above plan that would promote zero-carbon energy, create and preserve clean-energy jobs, establish a more equitable utility rate structure and give customers more control over their bills,” it said.
A ‘Tragedy’
Marvin Fertel, CEO of the Nuclear Energy Institute, issued a statement calling the plants’ closure “a tragedy” that threatens the “nation’s ambitious clean air commitments.”
“At-risk nuclear plants are struggling because the electricity markets do not appropriately value the attributes of nuclear plants, including reliable electricity generation and their carbon-abatement value. This is fixable, but federal and state policymakers, the Federal Energy Regulatory Commission and regional electric system operators must address these shortcomings with urgency to prevent other power plants from shutting down prematurely.”
The commission approved a GIA for Indianapolis Power & Light’s Harding Street Station Battery Energy Storage System, which is planned to go online this month, in spite of IPL’s protests that the project was being mischaracterized. IPL had urged the commission to view the storage facility as a transmission asset.
The nine Northeastern and Mid-Atlantic states that participated in the 32nd Regional Greenhouse Gas Initiative auction of carbon dioxide allowances on Wednesday sold more than 15 million at a clearing price of $4.53.
State regulators have ordered Southern California Edison to expedite procurement of large-scale energy storage to deal with possible service interruptions stemming from the closure of the Aliso Canyon gas storage facility.
The City of Boulder and more than a dozen other agencies and government bodies have asked to intervene before the state Public Utilities Commission in Xcel Energy’s bid to build a $1 billion wind farm. The Rush Creek Wind Project would cover 90,000 acres in the state and would be among the state’s largest wind energy producers.
United Illuminating will file for stepped-in annual increases of about $9/month for each of the next three years later this summer.
The Utilities Board allowed the Dakota Access Pipeline to proceed on parts of the route not covered by federal authority. It is the last state regulatory body to get aboard the $3.8 billion, 1,168-mile pipeline to deliver crude oil from North Dakota to Illinois.
The Public Service Commission will allow Baltimore Gas and Electric to raise its rates for gas and electricity by $89.5 million, about 40% of the utility’s request of $224.5 million.
The Committee to Ban Fracking collected about 82% of the 252,523 signatures it needed to get an anti-fracking measure on the ballot for November’s election before a deadline expired.
The Public Service Commission decided not to vote on opening a working case that would have studied the impacts of a bill that has stalled in the General Assembly.
A second wind farm in the state has been put on hold after it attracted public opposition. The Cherry County Planning Commission has delayed consideration of a 50-MW farm planned by Bluestem Sandhills, pending a review of public notice requirements.
Public Service Electric and Gas’ $275 million plan to add 100 MW of solar power through 10 new solar farms has drawn kudos from environmentalists, but others are concerned about the potential effect on solar credits.
State officials broke ground last week on the state’s largest solar array, near Fargo. The 102-kW project has 324 panels, with room on the 350-by-150-foot lot to double in size if demand from Cass County Electric Cooperative increases.
Current and former Omaha Public Power District executives defended their decision to continue to invest in the Fort Calhoun nuclear plant, even as all market signals pointed to nuclear power being uncompetitive in the face of declining natural gas prices.
Public Utility Commission investigators have filed its first formal enforcement action against a power broker operating without a license.
Archeologists surveying properties in the path of the proposed Mountain Valley Pipeline in Franklin County have found a trove of Native American artifacts, calling into question the job done by archeologists hired by the pipeline company.
State regulators last week issued a draft of one of two permits Dominion Virginia Power needs to store more than a million tons of coal ash at the site of a defunct power plant in Chesapeake, the state’s third most populous city.
The Seattle City Council has passed a resolution calling for its city-owned utility to seek power from non-nuclear sources and push provider Energy Northwest to investigate non-nuclear, carbon-neutral sources.
