VALLEY FORGE, Pa. — FERC wants PJM’s capacity rules to be resolved by Jan. 4 and has dispatched staff to help the RTO and its stakeholders adhere to that timeline.
Three FERC representatives attended Thursday’s special session of the Markets and Reliability Committee on responding to the commission’s June 29 ruling rejecting PJM’s “jump ball” capacity filing.
Office of General Counsel attorney Matthew Estes, one of the three FERC representatives, stressed that they were non-decisional and therefore not speaking to or for the commission. He advised all stakeholders to address the commission directly with their interests by filing comments in the docket.
“We’re happy to give our input, but that’s not going to get to the commission,” he said.
He described the representatives’ role as “historians” who could explain what they understand the current situation to be and to provide insight into what stakeholders might consider proposing because it would be “helpful to the commission to have things they can realistically consider.”
FERC rejected both of PJM’s proposals to revise its capacity market (ER18-1314), partially granted a 2016 complaint led by Calpine (EL16-49) and initiated a Section 206 proceeding for a “paper hearing” on an alternative approach in which the RTO would expand its minimum offer price rule (MOPR) to all subsidized resources (EL18-178). (See FERC Orders PJM Capacity Market Revamp.)
Comments prior to the hearing are due on Aug. 28. FERC said that it hoped to issue a final ruling by Jan. 4, 2019, in time for the 2019 Base Residual Auction.
The size of the task led several stakeholders to file for extensions on the Aug. 28 deadline. But PJM staff said they plan to provide comments by the deadline and still accept input from stakeholders. Thursday’s meeting, along with a follow-up scheduled for Aug. 15, are intended for that purpose.
“That doesn’t leave a whole lot of time for extension. I know people want more time,” Estes said.
PJM plans to file a proposal that would follow FERC’s suggestion of combining an expanded MOPR with a unit-specific fixed resource requirement (FRR). The MOPR would have few exceptions and would include units receiving out-of-market payments, such as state subsidies for nuclear units. Such units could then use the FRR option to be removed from the capacity auction, if they can take with them an “appropriate corresponding quantity of load.”
Four Proposals
PJM solicited comments from stakeholders as part of developing its proposal and was surprised to receive four other proposals among the 19 responses. At Thursday’s meeting, representatives of the four proposals outlined their ideas.
Calpine has advocated for a “strong” MOPR with no exceptions, the company’s Sarah Novosel said, but recognizes that other stakeholders don’t agree.
“We’re ready to work on an accommodation, but we think there’s a better accommodation than FRR,” she said, suggesting an approach like ISO-NE’s Competitive Auctions with Sponsored Resources.
LS Power proposed combining the MOPR with a “resource specific requirement” that would be similar to the FRR but remove load based on where the resource’s generation is “electrically delivered” rather than its physical location. It would subject the load and generation that remains in the auction to increased reliability requirements. Those costs would be borne by the resource electing to leave the auction.
Panda Power Funds offered an alternative to FRR that would identify and mitigate subsidized resources and allow those that don’t clear the auction an opportunity to buy capacity commitments in a second auction phase.
Consultants Rob Gramlich of Grid Strategies and James Wilson of Wilson Energy Economics presented a proposal for the Resource Specific FRR developed for the Sierra Club, Natural Resources Defense Council, D.C. Office of the People’s Counsel and American Council on Renewable Energy. They characterized it as “very close” to PJM’s proposal and said it makes the process “as usable as possible” for states. [Editor’s Note: An earlier version of this story incorrectly quoted the consultants as favoring an expanded MOPR.]
Joe Bowring, PJM’s Independent Market Monitor, warned that the unit-specific FRR results in price suppression if the
subsidized resource would not clear in the auction without FRR — and could affect clearing prices either up or down if it would have cleared.
Estes confirmed that FERC had not required an FRR to be part of any proposal, nor has it ruled on whether self-supply units should get a MOPR exemption. He advised stakeholders to file their requests along with substantiation that goes beyond assuming the way things have been traditionally should continue because “FERC found the way it’s always been to not be just and reasonable.”
PJM’s Jen Tribulski agreed with Estes’ analysis on FERC’s FRR proposal.
“We don’t view it as a strict mandate, but we do view it as the commission looks at it as a viable option to accommodate state actions,” she said.
Calpine also agreed.
“I think it’s clear that we at Calpine do not believe that the partial FRR was a mandate, just a suggestion. We think they’re open to other alternatives as well,” Novosel said.
BOSTON — This year’s legislative sessions in New England produced clean energy developments ranging from Connecticut’s “most important energy bill” in seven years, to Massachusetts taking “baby steps,” to Rhode Island taking what might turn out to be a “regrettable pause.”
Vermont even passed a bill requiring the installation of electric aircraft charging stations at state-owned airports.
One unresolved issue among most of the six states in the region relates to the siting of renewable energy resources, Northeast Clean Energy Council (NECEC) Executive Vice President Janet Gail Besser said Thursday at the group’s annual legislative roundup, hosted by Boston-based law firm Pierce Atwood.
“Should there be different siting standards for renewables than for other kinds of development?” Besser said before the group’s state coordinators provided an overview of new clean energy legislation in New England. “How do you preserve farmland and forestland and how do you have compatible uses of land?”
Connecticut Expands RPS, GHG Targets
Mike Martone, of law firm Murtha Cullina, said one new Connecticut law, SB9, “was hotly contested throughout the year… [and] was the most important bill this session and arguably the most important clean energy bill since Public Act 11-80 was enacted seven years ago,” which established the state’s Department of Energy and Environmental Protection.
The law revoked net metering guarantees that ensure rooftop solar owners earn retail prices for their excess electricity. (See Connecticut Energy Bill Draws Mixed Reviews.) It calls for the state’s Public Utilities Regulatory Authority to set up a docket by Sept. 1 “to select the netting time between real time, one day or a fraction of a day, which is still going to be very problematic,” Martone said.
But it also increased the state’s renewable portfolio standard to 40% by 2030; extended the low- and zero-emission renewable energy credits program an additional year; and established a new tariff-based program for low- and zero-emissions projects, shared clean energy, and virtual net metering. The legislature also restored $10 million in energy efficiency funding to the 2019 state budget, Martone said.
Another new law (Public Act 18-82) establishes an interim target of reducing greenhouse gas emissions to 45% below 2001 levels by 2030, and updates Connecticut’s Comprehensive Energy Strategy, the state’s triennial plan to meet its energy needs, to include planning for climate change and a strategy to meet the new GHG target.
It also established the Connecticut Council on Climate Change, which is charged with coordinating the efforts on emissions among businesses, state and municipal agencies, and nonprofits.
Massachusetts on Track
Massachusetts concluded its two-year legislative session July 31 by passing a bill (H. 4756) to increase renewable energy usage and reduce high-cost peak hours. The bill includes a clean-peak standard, the first in the nation to promote the use of renewable resources to shave peak loads.
The bill, one of 175 energy-related ones considered in the session, also allows the Department of Energy Resources to solicit an additional 1,600 MW of offshore wind by 2035 and increases the state’s energy storage target to 1,000 MW by 2025.
“I don’t want to say we had a good two years, but we had a great 48 hours at the end of the session,” said Dan Bosley of NECEC. “A lot of people were disappointed, but the more we looked, the more we realized we got a lot of our initiatives in this bill.”
The legislation mandates that clean energy sources supply an additional 2% of the state’s electricity each year, dropping to 1% in 2030 in order to “bring the business groups on,” he said.
While the bill did not raise the cap on solar net metering, it did modify language related to the monthly minimum reliability contribution charge, which will compel everybody to refile with state regulators, Bosley said.
NECEC President Peter Rothstein called the bill “a step in the right direction,” but the state’s Sierra Club director, Emily Norton, said it represented “baby steps on clean energy legislation when what is needed are giant strides.”
The environmental bond bill (H.4599) authorized $211 million to be spent on climate programs and state hazard mitigation, Bosley said. (See New England Women Talk Climate Change, Resilience.) That includes $10 million for a clearing house “to monitor, project and collate information so that we can do things that we want in an intelligent way,” Bosley said.
The bills have not been signed into law yet.
Rhode Island Pauses
Rhode Island had two landmark years for clean energy legislation in 2016 and 2017, and an exciting time this year in procuring 400 MW of offshore wind, but it was “not a banner year for legislation,” NECEC Policy Analyst Jamie Dickerson said.
“I think it’s going to shape up as a regrettable pause in what has otherwise been a tremendous three or four years of strong and steady growth,” he said.
Legislation that failed to pass would have tweaked the state’s renewable energy growth program to allow additional megawatts to be allocated to the residential solar, Dickerson said. In the 2017 program year, 6.5 MW were allocated for residential solar, and that capacity sold out in six months.
Other bills on the siting of renewables, harmful forest siting, capping energy efficiency program investments, and carbon pricing were either not taken up before the end of the session or referred to committee.
A substitute version of one bill, providing for independent review and verification of ongoing energy efficiency programs, was passed and signed by the governor, Dickerson said.
Northern New England
Kate Epsen, executive director of the New Hampshire Sustainable Energy Association, provided an overview of the conclusion of the Granite State’s second year of a biennium session.
SB 321, signed into law in June, removed the requirement that members of a net-metering group use the same default supplier as the group’s host, allowing residents to use both net metering and retail choice. “This is really helpful because it allows a lot of those larger end users who clearly shifted to competitive supply years ago, and don’t want to go back, to also engage in rural renewable energy projects through net metering,” Epsen said.
On the other hand, Gov. Chris Sununu vetoed SB 446, which would have raised the net metering cap to 5 MW from 1 MW and set the price at the default rate, which changes every six months. The Senate already has the two-thirds majority needed to override the veto on Sept. 13, “Override Day,” she said.
“The veto was unfortunate, for the Republican governor had a lot of cover, with many Republicans favoring it, so this veto happened for about five people in one company,” Epsen said. “That’s how local some of these relationships can get.”
In Maine, Gov. Paul LePage in his two terms since 2010 has vetoed more bills, 642, than all other Maine governors in the past century combined, said Melissa Winne, executive director of the Environmental & Energy Technology Council of Maine.
All energy-related bills, save one, either died in committee, died in special session or were vetoed. The exception was a bill, enacted without the governor’s signature, that extends Maine’s participation in the Regional Greenhouse Gas Initiative through 2030.
Olivia Campbell Andersen of Renewable Energy Vermont highlighted H.676, a law eliminating state fees for rooftop solar and removing mandatory setbacks for solar parking lot canopies, as well as a law that maintained net metering for up to 500 kW.
“Utilities have made it very clear that they would like to have net metering only go up to 150 kW,” Andersen said.
NRG Energy reported net income of $24 million ($0.23/share) in the second quarter, compared with a $16 million loss (-$1.98/share) a year earlier. Earnings from continuing operations were $121 million in the quarter, up 22% from the same period last year.
The company credited cost-cutting measures, the sale of assets and the consummation of a settlement with its spun-off GenOn Energy business. “Our portfolio is demonstrating once again the value of integration between retail and generation during the volatile summer months, particularly in Texas,” CEO Mauricio Gutierrez said during an earnings call Thursday.
The company has realized $225 million in cost savings through the second quarter of 2018 and is on track to close up to $3 billion in asset sales this year.
Record Peak in Texas
Gutierrez noted that the supply/demand balance in ERCOT is the tightest it has been in many years because of steady load growth and the retirement of nearly 5 GW of generation in the past 12 months.
| NRG
“This market tightening led to an increased probability of scarcity conditions this summer, which was reflected in higher forward prices,” he said. “So far, demand has not disappointed, setting a new record peak of over 73 GW in July. However, this record load was met with equally impressive reliability across the grid, which tempers real-time pricing.” (See ERCOT Sets New All-time Demand Record; Prices Spike.)
“In other words, it took nearly perfect systemwide reliability to meet the summer peak demand,” he said.
“These conditions create an opportunity for both sides of our business and highlight the longer-term value of our integrated approach.”
Big East
Results from the PJM capacity auction this past May reflected fewer new builds and significant amounts of uncleared capacity, signaling more disciplined development and bidding behavior, Gutierrez said. On a “same-store” basis, NRG cleared more megawatts at higher prices than the previous auction, he added.
| NRG
Going forward, the company will seek assets in “premium locations,” Gutierrez said, noting that NRG now has 85% of its PJM fleet in the ComEd zone, which separated to clear at $196/MW-day.
“Throughout the East, we are encouraged by the multiple regulatory avenues for market reform that could benefit both our generation and retail businesses,” Gutierrez said.
NRG increased its bet on retail sales in June, when it completed its acquisition of XOOM Energy, an electricity and natural gas provider with more than 300,000 customers primarily in the East, for $208 million. The company expects XOOM to add $11 million of net income and $45 million of adjusted EBITDA annually.
Faster Asset Sales
NRG Headquarters in Princeton, NJ. | NRG
The company also highlighted its progress in unwinding its relationship with GenOn, the product of the merger of RRI Energy and Mirant, which NRG purchased in 2012 for $1.7 billion. GenOn filed for Chapter 11 bankruptcy in 2017. NRG executed a settlement in July that included releases from GenOn and will terminate shared services on Aug. 15. Other than certain pension and post-retirement obligations and certain claims for REMA, an indirect GenOn subsidiary, the settlement provides NRG full releases from GenOn and its debtor and non-debtor subsidiaries.
GenOn is planning to exit bankruptcy on Oct. 1.
NRG closed on the sale of Boston Energy Trading and Marketing, as well as on its Spanish Town asset, a solar facility in the Virgin Islands, while reaching an agreement to sell its interest in two additional assets, the Keystone and Conemaugh coal-fired power plants in Pennsylvania.
“We actually had anticipated selling these assets in 2019, but we were able to accelerate this timeline and execute on the opportunity to monetize these assets ahead of schedule,” Gutierrez said.
The sale of NRG Yield has received all necessary regulatory approvals and should close in the third quarter, he said. The company’s sale of its South Central portfolio — 3,555 MW of gas- and coal-fired generation on the Gulf Coast — is also expected to close in the second half of this year.
Consolidated Edison earned $188 million ($0.60/share) in the second quarter, a 7% increase from $175 million ($0.57/share) in the same period last year.
The company reported about $2.7 billion in revenue for the quarter, a 2% increase over last year.
Adjusted earnings, which exclude the effects of a gain on the sale of a solar electric production project in 2017 and the net mark-to-market effects of Con Edison Clean Energy Businesses, were $189 million ($0.61/share) compared with $178 million ($0.58/share) in 2017.
Following a proceeding investigating a New York City subway power outage (Case 17-E-0428), the state Public Service Commission last year required Con Ed’s primary utility subsidiary, Consolidated Edison Company of New York (CECONY), to upgrade electrical equipment that serves the system. Costs related to that matter totaled $180 million, including $30 million in capital and operating and maintenance costs reflected in the company’s electric rate plan and $150 million deferred as a regulatory asset.
Following a settlement with state regulators over a New York City subway outage, CECONY has spent $180 million upgrading equipment serving the system. | Joren via Unsplash
Through June 30, CECONY’s costs related to March 2018 storms amounted to $126 million, while fellow subsidiaries Orange and Rockland Utilities (O&R) and Rockland Electric Co. had storm-related costs of $48 million and $18 million, respectively. Recovery of those costs is subject to review by the PSC and the New Jersey Board of Public Utilities. Con Ed and CECONY are unable to estimate the amount or range of their possible loss in connection with the storms, they said.
(a) average rate base for 12 months ended 6.30.2018 | ConEd
In May 2018, PSC staff recommended a $10.6 million increase in O&R’s electric rates and a $6.7 million decrease in O&R’s gas rates, both reflecting an 8.6% return on equity. In June 2018, O&R filed an update to its requested rate increases, changing its request to a $30.4 million increase for electric and a $0.5 million decrease for gas, seeking a 9.75% ROE.
Con Ed reported its Clean Energy Businesses having 1,383 MW of renewable energy production projects in service and 218 MW under construction.
OMAHA, Neb. — SPP’s Board of Directors last week approved a Tariff change requiring non-dispatchable variable energy resources (NDVERs) to register as dispatchable variable energy resources (DVERs), prompting a discussion on the value virtual trades offer the markets.
Staff said the Tariff change (MWG-RR272), which will require resources to reduce their output when instructed, will improve SPP’s ability to manage congestion and lead to an increased convergence between day-ahead and real-time prices.
However, several directors wondered aloud whether the measure would lead to unintended consequences. Virtual transactions are driven by market inefficiencies, so the more efficient the market, the less value in virtuals.
Director Bruce Scherr noted that staff cited as one benefit an expected reduction in profits for virtual traders.
“I never really understand whether we are encouraging or discouraging the participation of virtuals in our market,” he said during the board’s July 31 meeting with the Members Committee. “I think we flip and we flop on that. It’s never been clear to me whether we find virtual participation a positive or a negative.”
Fellow Director Graham Edwards pointed out virtuals are a small part of SPP’s market and asked, “If we start driving the virtuals out, is there a negative?”
SPP’s Market Monitoring Unit said in its most recent market assessment that virtual transactions as a percent of load increased to 17% this spring, compared to 10% in 2017.
“There are times when virtuals can be a help, there are times when virtuals can be parasitic,” responded Keith Collins, the MMU’s executive director. “In this scenario, if they are benefiting as a result of something that is a result of modeling inconsistency, are they really adding a benefit or value to the market? Yes, they are making money, but they’re making money on consistent modeling differences.”
Collins said virtuals can make the day-ahead market more efficient when load is under-scheduled.
“The value here [with RR272] is switching from virtuals to other resources and reducing uplift payments everyone around this table is paying,” he said.
Resources must convert by Jan. 1, 2021, or the 10-year anniversary of its original commercial operation date, whichever is later. Qualified facilities under the Public Utility Regulatory Policies Act and run-of-river hydro projects incapable of following dispatch instructions are exempt.
Staff’s analysis of RR272’s economic effects found the change would improve congestion management and convergence of real-time and day-ahead prices. The analysis projects about $15,000 in additional monthly real-time energy payments to converted NDVERs and about $20,000 in additional revenue to other resources.
“The more dispatchable resources we have, the easier it is to solve congestion,” said Gary Cate, SPP’s manager of market design. “NDVERs are generally located in areas where they are one of the few that are dispatchable. Opening them up allowed us to get rid of those breaches … by a fairly significant amount.”
Liberty Utilities, Omaha Public Power District (OPPD) and Walmart opposed the measure, which also received a pair of abstentions.
“This is an after-the-fact rulemaking scenario, where we’re required to upgrade equipment on older facilities,” said OPPD’s Joe Lang. “We’re concerned about the oppressive nature of this on wind power and setting precedent for other generation. The EPA has new-source-review requirements that properly limit the applicability of new rules on older facilities that give us concerns about walking down this path.”
The Wind Coalition’s Steve Gaw, who didn’t have a vote, said his group is “very supportive” of market efficiency, but he also expressed his concerns about RR272’s wording. He pointed to ambiguity as to when the conversions should take place for non-SPP generator interconnections and the excessive burden it places on the conversion of certain older wind farms.
“There are two issues of substance,” Gaw said. “One, whether or not SPP should be directly stating the conversion costs should be on the interconnection customer, as is stated in the new language. And two, the lack of any kind of exception for resources that have a substantial cost to convert.”
In written comments, the coalition said the conversion of fixed-speed (Type 1) and variable-slip (Type 2) turbines “can amount to millions” in capital expenditures.
SPP, MISO Resolving Jan. 17 Issues
CEO Nick Brown told stakeholders during his president’s report that SPP has reached an agreement with MISO on “specific operating procedures pursuant to our operating agreement” that arose during a Jan. 17 severe-weather event staff refer to as “The Big Chill.”
Colder-than-normal weather and generation shortfalls in MISO South led to MISO exceeding its regional dispatch limit on transfers between its northern and southern footprints across SPP’s system. The ISO made emergency energy purchases from Southern Co. before operations returned to normal.
“I, for one, get extraordinarily nervous when there is a disagreement or misunderstanding between our operators,” said Brown, who noted the meetings are continuing.
He said SPP added three new members during the previous quarter, bringing its membership to 97. The newest members include the Crocker Wind Farm, Walmart and NextEra Energy Transmission Southwest. Walmart joined as the RTO’s first large retail customer, a segment that has existed since 2003.
Brown also said that halfway through SPP’s fiscal year, the RTO has over-collected $8.4 million from members. Revenues are up because the number of completed interconnection studies and network services billing have both exceeded projections, Brown said.
An over-recovery this year will reduce rates in 2019, when this year’s actuals are reconciled with budgeted figures.
Board, Members Honor SPP RE Leadership
The board and members recognized SPP Regional Entity Trustees Mark Maher and Steve Whitley and RE President Ron Ciesiel with resolutions and applause following a final report. Dave Christiano, the trustees’ chair, was not present, spending his time instead in Ecuador following his passion for botany.
Maher said the RE successfully transferred 825 GB of data and more than 687,000 files to the Midwest Reliability Organization, SERC Reliability Corp. and NERC. The RE ended all compliance monitoring and enforcement activities for its 122 registered entities on June 29, with the MRO and SERC taking over those duties. (See SPP RE Ending Compliance Monitoring, Enforcement Activities.)
The trustees will hold a conference call Aug. 30 to officially terminate the RE’s regional delegation agreement.
Stakeholders Look at Changing Admin Fee’s Recovery
MOPC Chair Paul Malone said John Olsen of Evergy will chair the task force charged with developing a new rate structure allowing SPP to recover its administrative costs from energy transactions. (See SPP Stakeholders to Study Admin Fee Changes.)
The Schedule 1A Task Force is holding its first meeting Aug. 8 at the Dallas/Fort Worth International Airport. It is expected to report back with recommendations in January.
Stakeholders Add 3 to Members Committee
Members approved three new representatives to the Members Committee during a special meeting of the committee: Northwestern Energy’s Bleau LaFave (Investor Owned Utilities), NextEra Energy Resources’ Holly Carias (Independent Power Producer) and Walmart’s Chris Hendrix (Large Retail Customer).
LaFave’s term ends in 2019, those of Carias and Hendrix in 2020.
Members also approved removing from the bylaws references to the RE, while incorporating a de minimis investment requirement. FERC’s Orders 888 and 2000 bar grid operators, staff and non-stakeholder directors from holding financial interests in any market participant and require them to maintain independence from “any entity whose economic or commercial interests could be significantly affected by the RTO’s actions or decisions.”
Board Approves $47M in Near-term Projects
As part of its consent agenda, the board unanimously approved the Integrated Transmission Planning process’ 2018 near-term assessment portfolio, a package of 13 projects in six states with an estimated total investment of $47 million.
The portfolio is expected to resolve 101 reliability needs resulting from increased load in the Texas Panhandle and announced generation retirements along the Kansas-Missouri border. Notices to construct will be issued by Aug. 21, staff said.
The projects include a new 345-kV, 50-MVAR reactor at City Utilities of Springfield’s (Mo.) Brookline substation, originally identified as an interregional project with Missouri’s Associated Electric Cooperative, Inc. (See SPP: No Need for Joint Study with AECI in 2018.)
Six previously approved projects, expected to cost $85 million, were removed from the assessment because they were no longer needed.
Consent Agenda Includes 11 Revision Requests
The consent agenda also included a recommendation that Oklahoma Gas & Electric’s Jerry Peace fill a vacancy on the Finance Committee; a new baseline cost estimate for Southwestern Public Service’s 115-kV loop rebuild in West Texas; approval of NorthWestern Energy’s sponsored upgrade of a new 115-kV line in Aberdeen, S.D.; charter changes to the Model Development and Reliability Compliance working groups; and 11 revision requests:
CTPTF RR279: Modifies the competitive project proposal process to allow a re-evaluation request before awarding a notice to construct.
MWG RR177: Clarifies references to NERC standards in the Integrated Marketplace’s protocols and the Tariff’s Attachment AE, the marketplace’s governing rules to eliminate confusion over whether entities are performing obligations for market reasons or compliance with NERC standards. The change also modifies the attachment’s definition of operating reserve to that defined in the Tariff.
MWG RR266: Allows any resource to elect to be a combined ownership resource through the modeling option. Those that choose this option will be run through the market-clearing software as a single resource, with post market revenue allocations dispersed to each share based on designated ownership percentages.
MWG RR277: Corrects language in Attachment AE to accurately reflect the settlement formula for the auction revenue rights daily amount by reversing the sequence of the source and sink.
MWG RR304: Streamlines the process by which frequently constrained areas are re-evaluated, to make adjustments in a timely manner.
MWG RR306: Minimizes potential gaming opportunities identified by the MMU. The change allows market-committed resources that have a minimum run time extending beyond initial reliability unit commitment or day-ahead commitment periods to be eligible for make-whole payments after their initial commitment period.
MWG RR310: Adds three reporting requirements to comply with FERC Order 844: zonal make-whole payment reports, resource-specific make-whole payment reports and operator-initiated commitment reports. Also requires public posting of transmission constraint penalty factors; the circumstances in which violation relaxation limits (VRLs) could set prices; and procedures for temporarily changing VRLs in the Tariff.
ORWG RR309: Removes section 7.3.1 (FAC-011-3 System Operating Limits Methodology) from SPP’s planning criteria and places it in a separate document for reliability coordination purposes.
RTWG RR278: Corrects Attachment O’s Addendum 1 to include only current and applicable interregional coordination agreements and an update link to the joint operating agreement with MISO.
RTWG RR314: Adds clarifying language to the ITP manual addressing ambiguity in the base reliability and short-circuit model builds.
RTWG RR315: Removes references to the RE from governing documents.
ERCOT executives said Tuesday that system generation has overperformed during the summer, helping the grid operator meet demand during July’s record heat and loads.
| ERCOT
“We saw a real test of the system,” CEO Bill Magness told the ISO’s Board of Directors. “The fleet performed well, and everyone in the market was very aware of what was coming and what we needed to do. It was a good testament to how the participants in the market can perform and how they worked in a stressed situation.”
ERCOT, which manages about 90% of the Texas grid, set a new systemwide peak of 73.3 GW on July 19, breaking the record set in August 2016 by more than 2 GW. Its new weekend demand record of 71.4 GW on July 22 also broke the old mark of 71.1 GW.
All told, demand exceeded the old record during 14 intervals over July 18-23. Demand exceeded 70 GW between July 16 and 24 as a dome of high pressure settled over the state and sent temperatures into triple digits and some heat indexes to about 110 degrees Fahrenheit.
Staff this spring projected a summer peak of 72.97 GW in August.
Having plenty of generation to call on was key, said ERCOT Senior Director of System Operations Dan Woodfin. He noted generation outages in July were “significantly lower” than what the grid operator has historically seen.
ERCOT began the summer with 78.2 GW of available capacity and added 612 MW of gas generation in July. Wind power averaged daily output of 6.6 GW in July, above pre-summer expectations of 4.1 GW.
“The peak day, the 19th, the outages were almost 2,000 MW less than on the peak day last year. We saw that pretty consistently over that period,” Woodfin said. “The cooler weather that we’ve had the last couple of weeks has allowed the units to regroup and fix some things.”
The availability of generation helped minimize tight conditions and keep prices stable. Forward contracts for August delivery reached $239/MWh in May, but they have since fallen back into double digits.
Kenan Ogelman, ERCOT’s vice president of commercial operations, said the operating reserve demand curve (ORDC) has worked as designed. The ORDC creates a real-time price adder reflecting the value of available reserves; it is meant to incentivize resources to produce more energy and reserves.
“The pricing outcomes we’ve seen in the market are associated with expectations,” Ogelman said. “The incentives are also there to put power online, at the times they’re needed.”
He said congestion in the West region, driven by high load growth and combined with the way ERCOT produces load distribution factors, did lead to more than $30 million in uplift costs in June alone. “Wow!” one board member near an open mike exclaimed.
Staff shared operational data from May and June but promised additional information during the board’s October meeting.
“We’re pleased with how it all went, but it’s only Aug. 7,” Magness reminded the board. “We have a lot more August and September to go.”
Below-normal temperatures and rain have helped cool things off over the last week.
“This week has sort of been a dud, and next week won’t be much different,” said the ISO’s senior meteorologist, Chris Coleman. He said “there’s always an opportunity” that extreme heat will return in the next three or four weeks.
FERC on Friday rejected CMS Energy’s plan to boost a 60-MW qualifying facility to 263 MW, saying the change is too large to qualify for recertification under the Public Utility Regulatory Policies Act (EL18-123, QF87-481-002).
The company sought to recertify as an existing cogeneration QF its T.E.S. Filer City Station facility in Manistee County, Mich. The facility has two boilers that can burn coal, tire-derived fuel and waste wood and creates 60 MW of electricity that is sold to CMS subsidiary Consumers Energy. It also provides about 50,000 pounds per hour of process steam to the facility’s thermal host, a paper mill owned by Packaging Corporation of America.
T.E.S. Filer City Station cogeneration facility | T.E.S. Filer
CMS proposed replacing the solid fuel boilers with a natural gas-fired combustion turbine and heat recovery boiler to be used with the existing steam turbine that would produce approximately 263 MW of net electrical output while providing the same thermal output to the mill. The company said a smaller turbine and boiler would not provide enough waste heat to efficiently operate the existing steam turbine and serve the mill.
The 2005 Energy Policy Act modified PURPA, requiring that any new cogeneration facility demonstrate that its “thermal energy output … is used in a productive and beneficial manner,” and that its electrical output be used fundamentally for industrial or other permitted uses “and is not intended fundamentally for sale to an electric utility.”
To implement the changes, the commission in Order 671 created a “fundamental use test,” allowing the thermal output from a replacement cogenerator to be considered to be “used in a productive and beneficial manner” if at least 50% of the total energy output (the electric, thermal, chemical and mechanical output) is used for industrial or other permitted purposes.
Order 671 said that an existing QF does not become a new facility “merely because it files for recertification. However, we caution that changes to an existing cogeneration facility could be so great (such as an increase in capacity from 50 MW to 350 MW) that what an applicant is claiming to be an existing facility should, in fact, be considered a ‘new’ cogeneration facility at the same site.”
FERC said CMS’ proposed changes are too significant to qualify for recertification as an existing facility.
“The increase in net capacity from 54 MW to 263 MW constitutes so substantial an increase in capacity that … it cannot be considered the same facility that was previously certified,” the commission ruled. “Rather, the converted facility, as proposed, is a ‘new’ cogeneration facility.”
The commission said CMS had not provided information demonstrating that it meets the fundamental use test. “Accordingly, on the record before us, we cannot certify the facility, if converted as proposed, as a cogeneration QF. T.E.S. Filer is free to file such information with the commission by either submitting a self-certification or applying for a commission certification of QF status.”
Dissent by LaFleur
Commissioner Cheryl LaFleur dissented.
“I do not read [Order 671] as requiring any significant increase in megawatt output to be treated as a change so great as to consider a facility a ‘new cogeneration facility at the same site,’” she said. “The record here shows that the conversion was designed to meet the needs of the thermal host, and that the increased megawatt output is simply a byproduct of meeting that existing need with a modern, efficient gas turbine. I believe those facts are the pertinent ones for determining here whether the changes are ‘so great’ as to warrant denying recertification.”
LaFleur noted that PURPA requires the commission’s rules to encourage cogeneration facilities. “Unfortunately, interpreting Order No. 671 in a manner that requires rejection in this instance may in fact discourage other cogeneration resources from updating and optimizing their systems, for fear of no longer maintaining their QF status. I do not believe that outcome is justified on this record.”
Separately, FERC approved CMS’ request for a declaratory order confirming that its power purchase agreement with Consumers will remain exempt from Federal Power Act Sections 205 and 206 after the PPA is amended to reflect the upgrades to the facility (EL18-124, QF87-481-003). “Assuming for the sake of this discussion that T.E.S. Filer is a QF, sales made pursuant to the PPA, as amended … will continue to be exempt from commission oversight pursuant to FPA Sections 205 and 206.”
FERC last week rejected MISO’s proposal to create external zones for its annual capacity auction but left the door open for the RTO to submit a revised version of the plan in the future.
Under the proposal, MISO would have altered its Planning Resource Auction to include external resource zones based on neighboring balancing authority areas. In cases of price separation, the RTO would also distribute historical supply arrangement credits from excess auction revenues as a refund to external resources with long-term and consistently used historical supply agreements.
The proposal also included two new external resource subcategories: border external resources and coordinating owner external resources, which would be modeled and priced according to the existing local resource zone with which the resource shared a direct electrical connection. MISO had said that both types of resources are comparable to its internal resources and can meet physical and operational criteria that allow them to continue to be treated as if they were inside a local resource zone. (See MISO Closing in on External Capacity Zones.)
| MISO
The RTO had hoped to implement the new external zones by the 2019/20 planning year.
The first provision would have allowed an external resource bordering more than one local resource zone to choose which zone to participate in during the auction. The second would have permitted holders of evergreen contracts — supply contracts that include extension or renewal options written prior to MISO’s capacity construct — to receive historical supply arrangement credits collected from excess auction revenues to cover price separation. FERC said both provisions were unreasonable.
No Zone Toggle
FERC’s order said it was problematic for MISO to allow resource owners to toggle between zones in search of the best capacity prices.
“MISO’s proposal provides resource owners with new optionality that could lead to uneconomic behavior. For instance, a market participant could decide to move a lower cost capacity resource from one local zone to another in order to increase the likelihood that an affiliated higher-cost capacity resource clears in the local zone from which the capacity resource was moved. The ability to effectively move capacity resources from one local zone to another is not contemplated by the Tariff’s market power and mitigation provisions.”
MISO also proposed allowing internal capacity resources that border more than one local resource zone the option to choose their zone of participation, providing the “same flexibility” as similarly situated border external resources. The RTO said it contains 20 eligible internal resources and only one border external resource, the Joppa Power Plant in southern Illinois, with ties to multiple local zones.
But FERC said that rather than allowing market participants to select local zones, MISO could divide the resource’s capacity credit between the zones it borders using historic or forecasted system flows. The RTO could also propose a new system that determines how capacity credit is assigned to a resource that borders multiple local zones, the commission said.
Evergreen Contracts
FERC also determined that MISO should not make evergreen contract extensions eligible for excess auction revenues, saying the option would “embed inefficiencies into MISO’s resource adequacy construct for an indefinite period of time.”
“LSEs with evergreen contracts could continue to extend those contracts indefinitely to avoid the locational price signal that MISO’s locational resource adequacy construct was designed to provide,” the commission said.
Rejection in Full
FERC said it rejected the filing in full because MISO had instructed it to evaluate the contract as a cohesive whole. In its filing, MISO had said the elements “were created as a complete and balanced package based on discussions and adjustments made during the stakeholder process” and “are intended to be an integrated set of elements to improve MISO’s existing resource adequacy construct and should not be viewed in isolation.”
The RTO plans to discuss the proposal during an Aug. 8 Resource Adequacy Subcommittee meeting.
PJM and FERC must reconsider how they allocate the costs of high-voltage transmission projects developed to satisfy individual utilities’ planning criteria, the D.C. Circuit Court of Appeals ruled Friday (17-1040, 17-1041).
Old Dominion Electric Cooperative, Dominion Energy Services and Virginia Electric and Power Co. challenged FERC’s approval of a PJM Tariff revision that resulted in the RTO assigning all the costs for two transmission projects proposed by the companies to the Dominion zone.
Dominion had initiated both projects in July 2013 as part of its FERC Form 715 criteria, which allow utilities to set planning criteria for their zones that go beyond NERC or RTO requirements. At the time, PJM’s rules required that half of the cost of high-voltage projects be assessed on a pro rata basis to all 24 utilities in the RTO based on customer demand, with the remainder allocated to zones based on benefits, as determined by a distribution factor (DFAX) analysis.
Dayton Power & Light objected to using the 50% pro rata allocation for Dominion’s initial Elmont-Cunningham project.
| Dominion
PJM then proposed a Tariff amendment that would prohibit cost sharing for projects proposed to satisfy TOs’ own planning criteria. FERC initially rejected the proposal, saying it violated Order 1000 and was inconsistent with the commission’s earlier finding that high-voltage transmission lines provide “significant regional benefits that accrue to all members of the PJM transmission system.” (See FERC Rejects PJM Cost Allocation on Dominion Project.)
After a technical conference, however, the commission reversed its decision, ruling that projects such as Elmont-Cunningham belonged in a new category of projects included in the Regional Transmission Expansion Plan for coordination but not selected for cost allocation. The commission then used the amendment to reject regional cost sharing for the Elmont-Cunningham and a subsequent Cunningham-Dooms project. (See FERC Does 180 on Local Tx Cost Allocation in PJM.)
Commissioner Cheryl LaFleur dissented, saying that the commission should preserve regional cost allocation “for certain high-voltage projects, even if those projects are selected solely to address local planning criteria.”
‘Severe Misallocation’ of Costs
The court agreed, saying FERC’s approval of the Tariff change was “arbitrary” and would result in a “severe misallocation of the costs” of high-voltage projects. It noted that the Dominion zone would receive less than 50% of the benefits of each of the two projects.
“FERC’s reasoning would replace a cost-allocation formula about which FERC had expressed no concerns with another one that is less accurate overall, as well as grossly inaccurate with respect to high-voltage projects, in return for no countervailing regulatory benefit,” the court said.
Because FERC has already acknowledged the regional benefits of high-voltage infrastructure, it “could hardly say that trying to distinguish between high- and low-voltage facilities was not worth the trouble.” By holding to a principle of cost causation, “FERC must make some reasonable effort to match costs to benefits,” the court said. “The cost-causation principle focuses on project benefits, not on how particular planning criteria were developed.”
“We fail to see how a categorical refusal to permit any regional cost sharing for an important category of projects conceded to produce significant regional benefits can be reconciled with the background [cost-causation] principle,” the court added. “We are sensitive to the concern, pressed by Dayton and the other amici supporting FERC, that individual utilities should not have free rein to impose unjustified costs on an entire region by unilaterally adopting overly ambitious planning criteria. However, nothing we say here prevents PJM or its member utilities from amending the Tariff, the Operating Agreement or PJM’s own planning criteria to address any problem of prodigal spending, to establish appropriate end-of-life planning criteria or otherwise to limit regional cost sharing — as long as any amendment respects the cost-causation principle.”
The court remanded the three orders back to FERC for further review.
“The legal or economic merit of Dominion’s particular end-of-life planning criteria, and the appropriateness of the Elmont-Cunningham and Cunningham-Dooms projects under those criteria, remain open issues on remand,” the court said.
OMAHA, Neb. — SPP met last week with Western entities that have expressed interest in its reliability coordinator (RC) services, further evidence the RTO is intent on becoming a serious player in the Western Interconnection.
The grid operator hosted the first meeting of its new Western Interconnection Reliability Coordination Working Group (WIRCWG) Aug. 2 in Westminster, Colo. It said the WIRCWG (suggested pronunciation: work-wig) will eventually become a forum for Western customers and other stakeholders of the RTO’s RC services “to engage in matters of RC-related governance and strategy.”
COO Carl Monroe said SPP hopes WIRCWG’s initial meetings and a “transparent, open-door policy that welcomes questions and concerns from any interested party” will demonstrate “our dependability and customer-focused attitude in the West, where we understand our potential customers may still be feeling us out.”
“SPP has more than 75 years of experience as a regional grid operator, and we’ve built a reputation as a reliable, effective and relationship-based organization among our members, market participants and other contract customers,” he said in a press release.
SPP has already scheduled an Aug. 14-15 meeting at its corporate headquarters in Little Rock, Ark., restricted to entities who have signed a letter of intent (LOI) for RC services. The grid operator says it has received 28 LOIs from Western entities, representing 200 TWh of net energy for load. SPP announced in June that it intends to provide RC services in the Western Interconnection by late 2019. (See Westward Ho: SPP Plans to Become RC in West.)
CEO Nick Brown told stakeholders last week that SPP is intent on establishing agreements with the companies and is following the necessary certification steps “to serve in this capacity.”
“Certainly, we have a good track record of incorporating folks in our RC services,” Brown said, referring to the 2009 and 2014 additions of Nebraska utilities and the Integrated System, respectively. “Our primary goal is to use the expertise we have, and to reach out to other entities and reduce the overall operations costs to our members. We very much expect that to be the case here.”
SPP said that while service agreements are still being negotiated, WIRCWG meetings will help those interested to learn about SPP and have a say in its service offerings in the West. It said 53 attendees were present in Westminster, a number that included members of the RTO’s Operating Reliability Working Group, which met before the WIRCWG meeting. It declined to give a breakdown of the 53 attendees.
Once the group is formally created, future meetings will be posted in advance and it will function like all other SPP working groups, an RTO spokesperson said.
“We’re eager to meet with potential customers, work with them to develop systems and processes to address their distinct needs, and begin a new chapter in the evolution of the power grid in the West,” said Bruce Rew, SPP’s vice president of operations.
With Peak Reliability’s recent decision to end its operations as early as Dec. 31, 2019, SPP and CAISO are now competing to offer RC services across the West. (See Peak Reliability to Wind Down Operations.)
CAISO last month received its first public commitment from an RC customer, the Balancing Authority of Northern California, a joint powers authority that provides balancing services for six California publicly owned utilities, including the Sacramento Municipal Utilities District. (See Most of West Signs up for CAISO RC Services.)
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The Western Electricity Coordinating Council, which is responsible for the region’s bulk electric system compliance monitoring and enforcement, has asked its BAs and transmission operators to confirm which RC they will be using by Sept. 4.
SPP is still interested in integrating the Mountain West Transmission Group into its market, work that has been overshadowed by the competition for RC services and Xcel Energy’s April announcement that it was leaving the Rocky Mountain group. The RTO’s executives told stakeholders last month they expect to hear from the remaining participants in September, once they redo their cost-benefit studies.
