AUSTIN, Texas — ERCOT said Thursday that it expects to have enough installed generating capacity available to meet fall and winter peak demand, thanks to the addition of 915 MW.
The Texas grid operator now has more than 81 GW capacity that should be available for peak demand into next spring. Two natural gas-fired power plants, one wind project and three solar projects have come online since ERCOT issued its last seasonal assessment of resource adequacy (SARA) in April. Another 265 MW of capacity is expected to become available by fall.
ERCOT resource adequacy | ERCOT
ERCOT forecasts a demand peak of 58.6 GW for October and November, based on normal weather conditions for those months. The ISO’s preliminary assessment for December through February projects a peak of 61.8 GW, below the winter demand record of 65.9 GW set last January.
“Our assessments show a healthy amount of operating reserves heading into the fall season,” ERCOT Manager of Resource Adequacy Pete Warnken said in a release.
The new generating capacity helped offset the mothballing of several older fossil-fired units. The grid operator has issued notifications of suspension of operations for 572 MW of gas- and coal-fired capacity, effective in early October. (See “Garland Generating Units Return to Mothballs,” ERCOT Briefs: Week of July 2, 2018.)
San Antonio’s CPS Energy has also publicly announced it will mothball its coal-fired J.T. Deely plant by year-end. The plant’s two units were built in the late 1970s and have a combined capacity of 850 MW.
ERCOT’s installed reserve margin has fallen to about 11% with the retirement of 4 GW of coal capacity in 2017. It has survived summer demand that peaked at 73.3 GW without resorting to emergency measures.
The final winter SARA report for 2018-19 will be released in early November.
WASHINGTON — The FERC commissioners who approved the New England Power Pool as ISO-NE’s stakeholder body in 2004 were unaware at the time that NEPOOL barred the public and press from its meetings.
Former FERC Chairman Pat Wood III and former Commissioner Nora Mead Brownell said in interviews they would have insisted on allowing press access had they known of the ban when they approved ISO-NE as an RTO in March 2004 (RT04-2, ER04-116, et al.).
Former Commissioner Joseph T. Kelliher, the third vote on the order, declined to comment but did not dispute Wood’s and Brownell’s accounts. Former Commissioner Suedeen Kelly did not take part in the order.
FERC commissioners also were unaware of the ban in 2008 when they approved Order 719 (RM07-19, AD07-7), according to former Chairman Jon Wellinghoff. The order set requirements for the responsiveness of RTOs and ISOs “to their customers and other stakeholders, and ultimately to the consumers who benefit from and pay for electricity services.”
“I do not recall this ever coming up when I was at FERC, and I do not remember the issue in 719,” Wellinghoff said via email. “Stakeholder meetings should absolutely be open to all, including the press.”
The other former commissioners who joined Wellinghoff and then-Chairman Kelliher in voting on Order 719 — Kelly, Marc Spitzer and Philip Moeller — did not respond to requests for comment last week.
New England is the only one of seven U.S. regions served by RTOs or ISOs where the press and public are prohibited from attending stakeholder meetings.
On Aug. 31, RTO Insider filed a complaint asking FERC to overturn NEPOOL’s press ban or terminate the group’s role and direct ISO-NE to adopt an open stakeholder process like those used by other RTOs. The Section 206 complaint (EL18-196) came two weeks after NEPOOL submitted a proposal to FERC seeking to codify an unwritten policy of banning news reporters and the public from attending the group’s stakeholder meetings. (See RTO Insider Seeks Repeal of NEPOOL Press Ban.)
Media Family
Wood, attending an industry conference in D.C. on Wednesday, told RTO Insider that it was inconceivable that he and Brownell would have approved NEPOOL’s press ban. Brownell’s family owned the Erie Times-News in Pennsylvania until 2015.
“If Nora Brownell signed off on that — her being from a media family — I’m sure it did not come up,” Wood said. “Nora would be kind of the canary in the mine on anything [dealing with media]. Any time that you came up with transparency stuff, she kind of had my proxy.”
Brownell, now a board member of National Grid, confirmed Wood’s recollection in a phone interview.
“Pat is absolutely right,” Brownell said. “I did not know and would never have approved. Shame on me if it was out in the open, but it couldn’t have been obvious. I remember expressing concerns over SPP’s stakeholder process.
“I just can’t imagine why the meetings have to be closed,” she continued. “I think it is critically important for people to have confidence in the outcome of what is being recommended and what the RTO/ISO ultimately adopts. … If the consumer is paying a bill [for RTO actions], as they are, directly or indirectly, they have a right to have access to the process.”
Wood said ensuring stakeholder meetings are open to the public and press is essential. “The very first step of transparency is doing the sunshine,” he said. “You know, most things done in the dark do start to smell.”
Two Dockets
RTO Insider also filed its complaint as a protest in the docket NEPOOL opened in August (ER18-2208). Comments in the NEPOOL docket are due Sept. 14.
The commission set a Sept. 20 deadline for comments in the docket opened by RTO Insider. NEPOOL on Thursday requested that deadline be extended seven business days to Oct. 1 “to align the timing of any appropriate NEPOOL response to pleadings submitted on these same issues in Docket No. ER18-2208.” RTO Insider responded that it did not oppose the request.
The 2004 order approved by the three commissioners, all Republicans, includes three references to “transparency” but no mention of NEPOOL’s then unwritten press ban. It noted, for example, the promise of ISO-NE and the New England transmission owners that the revised ISO-NE board procedures “would promote greater transparency by requiring board agendas to be posted, the opportunity for stakeholders to provide written input on agenda items, and for reports on board meeting actions, and proposed revisions to market rules or other tariff provisions.”
NEPOOL moved to codify its unwritten ban on press and public attendance at stakeholder meetings after RTO Insider reporter Michael Kuser, who lives in Vermont, applied for membership in NEPOOL’s Participants Committee as an end-user customer in March. NEPOOL’s proposed amendments to the NEPOOL Agreement would add a definition of “press” and bar anyone working as a journalist from becoming a NEPOOL member or alternate for a participant.
Most transmission operators in the Western Interconnection are faced with choosing either CAISO or SPP to provide reliability coordinator (RC) services after Peak Reliability winds down its operations in late 2019. The Western Area Power Administration will go with both.
WAPA said Tuesday that it has selected CAISO’s new RC arm to serve its Sierra Nevada region after Peak’s closure, while its Rocky Mountain (RM), Desert Southwest (DSW) and Upper Great Plains (UGP) regions will use SPP’s RC services. (See Peak Reliability to Wind Down Operations.)
| WECC
The Sierra Nevada region already functions as a transmission operator within the Balancing Authority of Northern California, which in July was the first BA in the West to announce it would sign up for CAISO’s RC services. (See CAISO Board OKs RC Rate Plan, RMR Change.)
The RM, DSW and UGP regions contain the Western Area Colorado Missouri, Western Area Lower Colorado and Western Area Upper Great Plains-West BA areas, respectively.
WAPA has in recent years been consolidating functions among its Interior West BAAs and said keeping those regions under one RC would avoid introducing “operational and compliance complexities.” It also noted that UGP is currently a transmission-owning member of SPP and is “fully engaged” in the RTO’s stakeholder process.
WAPA said the transition is dependent on SPP and CAISO becoming certified by NERC and the Western Electricity Coordinating Council as RC providers in the Western Interconnection. (See Sept. 4 Key Date for Potential Western RC Providers.)
In a Sept. 4 memo signed by Chief Operating Officer Kevin Howard, WAPA said the move could produce more benefits than Peak’s services: “Initial analyses have determined that SPP and CAISO should be able to provide reliable RC services comparable or superior to the services provided by Peak, and the costs for such services are expected to be lower than Peak’s.”
SPP will initially cap the charge for RC services at 5.5 cents/MWh, and CAISO estimates its services will cost anywhere from 3.4 to 4.1 cents/MWh depending on total load, according to WAPA.
WAPA’s regional offices promised Howard performance check-ins during and after the transition. “Given the dynamic nature of the situation and the need for ongoing analysis, each region will keep you informed of their progress. If any significant issues arise, we will bring those matters to your attention,” WAPA said. In a separate statement, Howard promised to work with neighboring utilities “to ensure an orderly transition to the SPP and CAISO RCs.”
WAPA said its switch to SPP could contribute to the creation of an organized Western market: “Participating in the SPP RC will preserve and facilitate options for the potential development of an organized electricity market in the West.”
At press time, neither CAISO nor SPP had provided a full list of customers taking their RC services. Representatives from both grid operators have said that they would not necessarily time announcements to Sept. 4 — the unofficial deadline NERC and WECC placed on Western BAs and transmission operators to declare their RCs. CAISO said it would only announce customers only as they sign agreements. In addition to BANC, Idaho Power and PacifiCorp have also committed to CAISO.
“At this time, announcements of entities committing to ISO RC services are being coordinated by the individual entities … since each entity has a different approval process and varying timelines, based on their specific business decisions and operations. We plan to share our customer list as agreements are signed,” CAISO spokesperson Anne Gonzales said in an email to RTO Insider.
WECC last week told RTO Insider that it will provide a more complete list of Western Interconnection RC selections at its annual meeting on Sept. 11.
CAISO moved to update its rules Wednesday to make it easier for energy storage and distributed energy resources (ESDER) to participate efficiently in its markets.
The ISO’s Board of Governors adopted the ESDER Phase 3 Tariff changes at its monthly meeting in Folsom.
Among the technical updates were new bidding and real-time dispatch options for demand response resources. Stakeholders had expressed concern that many resources couldn’t respond to ISO dispatches in real time because they didn’t have enough notice.
Currently “they only have two-and-a-half minutes of notification time to respond to that dispatch,” which isn’t feasible for many, Greg Cook, CAISO’s director of market and infrastructure policy, told the board.
The new bidding options give DR resources more time to respond by letting them provide real-time market bids as an hourly block or a 15-minute dispatch resource. (See CAISO Updates ESDER Phase 3 Proposal.)
Another provision adopted Wednesday simplifies rules for aggregated DR resources.
CAISO currently requires DR resource aggregation to be contained in a single load-serving entity with a 100-kW minimum. That minimum threshold has been a problem, especially with the proliferation of community choice aggregators, Cook told the board. The new rules will remove those requirements.
CAISO adopted rules to ease the integration of distributed energy resources to California’s grid, including electric-vehicle battery storage. | U.S. Air Force/Sarah Corrice
Other changes will make it easier for behind-the-meter battery storage to absorb excess electricity and return it to the grid, and will allow for electric vehicles’ charging performance to be measured separately of their host facilities.
The changes are detailed in a memo to the board. The revisions must still be approved by FERC.
MISO announced it has received 12 complete proposals from nine developers seeking to construct and own the Hartburg-Sabine Junction 500-kV project, the RTO’s second competitively bid transmission expansion.
MISO had been screening proposals for the Hartburg-Sabine project since it closed the request for proposals window on July 20. As a practice, the RTO does not reveal which developers may have submitted incomplete proposals. (See “MISO Reviewing Hartburg-Sabine Proposals,” MISO Informational Forum Briefs: July 24, 2018.)
| MISO
MISO said it only reviewed the proposals for completeness and has not vetted the content of the proposals.
“With the final list of complete proposals, we now begin our competitive evaluation phase, which is outlined in the MISO Tariff,” Aubrey Johnson, MISO executive director for system planning and competitive transmission, said in a statement.
MISO said it expects to announce the selected developer by Dec. 31.
The completed proposals come from Avangrid Networks; EasTex TransCo; GridLiance Heartland (with Cleco Energy); Midwest Power Transmission Arkansas; NextEra Energy Transmission Midwest; Transource Energy; Verdant Plains Electric; Xcel Energy Transmission Development Co.; and a joint bid from ITC Midcontinent Development, Hunt Transmission Services and Texas Infrastructure Holdings. MISO did not reveal which developers submitted multiple proposals.
The estimated $129-million, 500-kV line and substation project, intended to alleviate system congestion in eastern Texas, is expected to be in service by 2023. The RTO opened the submittal window in early February after MISO’s Board of Directors approved the project as part of MISO’s 2017 Transmission Expansion Plan. (See MISO Board Approves Texas Competitive Tx Project.)
WASHINGTON — ERCOT’s energy-only market survived the summer of 2018 with surprisingly modest prices and no generation shortfalls, but 2019 may be a tougher challenge, the RTO’s market monitor said Wednesday.
Beth Garza, director of ERCOT’s independent market monitoring unit, credited better-than-expected generation performance and an early summer system peak that took advantage of above-normal wind for the positive results.
Coal plant retirements reduced ERCOT’s installed reserve margin to below 11%, by far the lowest in the market’s history, leading on-peak forward prices for August to rise as high as $250/MWh. But although real-time prices briefly peaked at more than $2,000/MWh, average real-time prices in July were about $50/MWh and about $38/MWh in August, Garza said.
She acknowledged one competitive retailer was forced to surrender tens of thousands of customers to the provider of last resort when it was unable to meet collateral requirements in early summer. But disruptions were minimal, Garza told the inaugural Future Power Markets Summit, sponsored by the American Wind Energy Association and several other trade groups.
“There was certainly a high level of awareness across the market, across the state legislature, across the regulators [of the tight market], and with that high level of awareness I think came a high level of preparedness, certainly from the generators,” she said. “As it turned out … generator availability was higher than normal this summer. We also had — I think because of the timing when our system peak was — we had the … contribution from higher-than-expected wind generation this summer.”
ERCOT recorded its summer peak at 73,259 MW on July 19, while loads in August — normally the peak month — never exceeded 71,110 MW. The 2018 Long-Term Demand and Energy Forecast projected a 2018 summer peak of 72,974 MW.
Garza said generators responded to the potential for prices up to ERCOT’s $9,000/MWh cap. “Having that opportunity for our energy price to rise to very high levels creates that natural incentive for availability at the time when we need generation resources the most.”
But it won’t get any easier for ERCOT in 2019, Garza said, as its load — unlike that of other markets — continues to grow. In addition, two announced coal plant retirements will reduce capacity by more than 1 GW by the end of the year. The system has added no significant thermal capacity although there have been wind and solar additions.
“So, I think we’ll go into 2019 in a very similar state as we went through this summer,” Garza said. “And that raises all kinds of questions about outcomes … if generation availability [is] lower than expected, if wind [is] average, if load [is] a little higher.”
“The good part about this job is I get to monitor the market,” she laughed. “I don’t have to forecast the market.”
In addition to AWEA, the summit was sponsored by the American Council on Renewable Energy, the Solar Energy Industries Association, the American Public Power Association, the National Rural Electric Cooperative Association, the Large Public Power Council and the Energy Systems Integration Group, a non-profit educational association for engineers, researchers, technologists and policymakers.
[Editor’s Note: RTO Insider will have additional coverage from the conference later in Tuesday’s newsletter.]
Hot and humid weather some 5 degrees higher than forecast and 1,600 MW of unplanned generator outages sent ISO-NE power prices soaring last Monday and led the RTO to purchase emergency energy from New York and Canada.
Temperatures hit 96 degrees Fahrenheit in Boston on Sept. 3 with a dew point of 73 as load peaked at 22,956 MW, almost 2,400 MW above the initial forecast of 20,590 MW. The bulk power system saw a five-minute peak of 23,106 MW at 5:50 p.m., according to a Sept. 7 article published on the RTO’s website.
Real-time energy prices rose to $2,454.57/MWh between 4 and 5 p.m., and reserve prices peaked at about $2,500/MWh at times between 3 and 6 p.m.
| ISO-NE
Similar weather conditions, with a heat index at or near 100, were forecast for the following Tuesday. Load peaked at about 23,000 MW, in line with forecasts, and no alerts were issued. Boston peaked at 85 degrees.
When the dew point is above 70, every 1-degree increase can cause load to rise by about 500 MW, with rising temperatures causing similar effects on load.
The RTO implemented Master/Local Control Center Procedure No. 2 (M/LCC 2) at 3:15 p.m. Monday, declaring an Abnormal Conditions Alert and directing generators and transmission owners to stop or postpone any maintenance activities that could jeopardize system reliability.
Fifteen minutes later, the RTO implemented Operating Procedure 4, Actions 1 and 2. Action 1 declares a Power Caution, saying available capacity resources are insufficient to meet anticipated demand plus operating reserve requirements. Action 1 also allows the RTO to begin depletion of 30-minute operating reserves. Action 2 declares a Level 1 energy emergency alert.
At 4 p.m., system operators issued a Power Watch and implemented two other actions of OP4, asking market participants to reduce energy consumption at their own facilities and arranging for purchase of emergency capacity and energy from neighboring systems.
All of the alerts were lifted by 9 p.m.
ISO-NE spokeswoman Marcia Blomberg told RTO Insider that the Labor Day heat resulted in “higher-than-expected demand, as well as some generator outages” and that the RTO purchased emergency power from New Brunswick and New York for a short time. “While we implemented Action 4 of OP4, declaring a Power Watch, we didn’t issue a request for voluntary conservation. We were monitoring the system and could have issued an appeal if conditions had deteriorated.
Emergency purchases from NYISO totaled 251 MW from 5 to 5:30 p.m. and 100 MW in the following half-hour, while emergency purchases from New Brunswick totaled 150 MW from 4:20 to 5:14 p.m. and 229 MW from then until 6 p.m.
“However, conditions improved rapidly as demand began to decline in the late afternoon and offline generators were able to come online quickly,” Blomberg added.
ISO-NE’s operations shift supervisor or one of its six local control center system operators can declare an abnormal condition under several scenarios, including a forecasted or actual deficiency of operating reserves. The local control centers, which are run by transmission owners, are generally responsible for transmission facilities rated 69 kV and below.
The RTO reported “underperforming resources will be penalized at a rate of $2,000/MWh for failing to meet their obligation during energy shortfalls, while resources that overperform (including resources with no obligation) will receive $2,000/MWh of additional revenue.”
The performance payment rate will increase to $5,455/MWh over the next six years.
Responding to stakeholder demands to resolve a yearlong dispute, PJM’s Stu Bresler has sent a letter outlining his requirements for accepting the Independent Market Monitor’s opportunity cost calculator.
The public pronouncement of PJM’s terms was unexpected but welcomed. “I’m surprised that PJM has apparently decided to negotiate this publicly,” Monitor Joe Bowring said. “We will respond.” Bowring declined to address whether PJM’s terms were acceptable and detailed enough.
For more than a year, PJM and its Monitor have been unable to agree on a single calculator for opportunity costs included in generation offers. PJM argues that FERC Order 719, issued in October 2010, allows the Monitor to provide input on cost determinations but that “PJM retains the ultimate decision-making authority.” From then until “the latter part of 2016,” both calculators produced consistent results, Bresler said in his letter, but have since diverged substantially.
PJM says it can’t endorse the Monitor’s calculator until staff understand how and why it produces different results. For that reason, PJM announced in August it would only accept opportunity cost calculations using its calculator.
The Monitor argues that it has continued to enhance its calculator while PJM hasn’t changed its methodology since 2010.
PJM staff have asked to understand the calculator’s inner workings, but Bowring has been reluctant to fully throw back the curtain, arguing that PJM staff haven’t specifically detailed their requests and that the underlying computer code is proprietary intellectual property.
Generators say the dispute has left them in a bind, fearing a referral to FERC enforcement for using an unapproved number.
At the Aug. 23 Markets and Reliability Committee meeting, generators attempted to force a resolution by threatening Tariff revisions that would require PJM to accept the Monitor’s calculator. (See Stakeholder Proposal Aimed at Ending PJM-IMM Dispute.)
Bresler’s letter details three requests to the Monitor:
the design requirement specification documents for the Monitor’s calculator, including descriptions of steps taken to calculate adders and accompanying mathematical formulas.
alternatively, the calculator’s output from pre-defined sample inputs and parameters so PJM can compare the results with its calculator’s output using the same inputs.
a commitment to notify PJM of any changes to the calculator and to rerun the comparative analyses afterward.
Bresler, PJM’s senior vice president of operations and markets, shot down an earlier suggestion from Bowring that they allow a third-party auditor to compare the calculators, saying it was less efficient and more expensive than his solutions. He gave Bowring a Sept. 10 deadline to respond to the proposal.
The Members Committee is set to vote on the proposed Tariff revisions on Sept. 27, barring an agreement before then.
Order 890’s transparency provisions do not apply to “asset management” projects that provide only “incidental” increases in transmission capacity, FERC ruled in two orders Friday.
The commission rejected complaints by California regulators and others who contend Pacific Gas and Electric and Southern California Edison are violating Order 890’s transparency provisions because much of their transmission planning is done without stakeholder input or review.
The California Public Utilities Commission, Northern California Power Agency, the city and county of San Francisco, the State Water Contractors and the Transmission Agency of Northern California filed the complaint against PG&E in February 2017.
The agencies complained that PG&E offered no stakeholder or external review on almost 80% of its transmission capital projects, including substation upgrades, replacement of deteriorating transmission equipment, system reliability and automation, and technology infrastructure.
| PG&E
But the commission said such activities were generally not subject to Order 890 because they provide no more than incidental increases in transmission capacity — such as replacing a 1940s-vintage transformer with modern equipment “which could be of a higher capacity if the PTO [participating transmission owner] has standardized transformer sizes across its system to allow for sparing should the transformer fail” (EL17-45).
“While Order No. 890 does not explicitly define the scope of ‘transmission planning,’ the commission adopted the transmission planning requirements in Order No. 890 to remedy opportunities for undue discrimination in expansion of the transmission grid,” FERC said. “Based on the information in the record, we find that the specific asset management projects and activities at issue here [are designed to] maintain [PG&E’s] existing electric transmission system and meet regulatory compliance requirements.”
The commission acknowledged asset management could result in significant transmission capacity increases, “for example, where a PTO determines that it can address a CAISO-identified transmission need by expanding the scope of an asset management project or activity to result in a capacity increase.”
“Accordingly, the incremental portion of the asset management project or activity would be subject to the transmission planning requirements of Order No. 890 and would have to be submitted for consideration in CAISO’s [transmission planning process] through the request window. If CAISO did not approve the incremental work, then the PTO should not expand the scope of the original asset management project or activity without that work being subject to consideration through an Order No. 890-compliant transmission planning process.”
The commission also said it “strongly encourage[s] PG&E to continue its efforts to work with complainants and other stakeholders to develop a process to share and review information with interested parties regarding asset management projects and activities that are not considered through the” CAISO transmission planning process.
SoCal Edison Review Process OK’d
FERC used the same reasoning in rejecting the PUC’s request for a show-cause order finding that Order 890 governs transmission owners’ planning for self-approved projects.
Instead, the commission approved SCE’s tariff change creating a process for sharing information with stakeholders about its asset management projects not subject to Order 890 (ER18-370, AD18-12).
The commission said the transmission maintenance and compliance review process “offers transparency and the opportunity for stakeholders to have input into the development of SoCal Edison’s transmission rates.” It ordered SCE to make a compliance filing within 30 days adding provisions the company proposed in response to protesters’ concerns.
FERC has granted PJM’s request to delay its annual Base Residual Auction, from May to Aug. 14-28, 2019, after recently extending filing deadlines for its paper hearing on the RTO’s capacity construct (ER18-2222).
| AdobeStock
The initial and reply testimony deadlines were extended to Oct. 2, 2018, and Nov. 6, 2018, respectively, at the request of the Organization of PJM States Inc. (OPSI). FERC ordered the hearing after rejecting both proposals PJM offered in its “jump ball” filing and ruling that the RTO’s existing capacity construct isn’t just and reasonable. FERC instead suggested a fixed resource requirement (FRR) hybrid.
PJM asked for the delay because the extended comment deadlines indicated that FERC would be unlikely to issue a ruling on the hearing by Jan. 4, 2019, the date that PJM previously said would accommodate holding the BRA as planned in May while still including whatever revisions FERC orders.
Several PJM stakeholders have proposed revisions to the capacity auction. PJM recently unveiled to stakeholders and nondecisional FERC staff its proposal, which it dubbed the Resource-specific Carve Out (ReCO). It would start with a subsidized generation resource exiting the capacity market with a corresponding amount of load rather than the FRR’s inverse of a designated amount of load exiting the capacity market with a corresponding resource. (See PJM Unveils Capacity Proposal.)
On Aug. 29, the commission issued a procedural order granting itself more time to consider motions requesting rehearing of its order recommending the capacity market changes (EL16-49, et al.).
