PJM and Monitoring Analytics, its Independent Market Monitor, have agreed on a deal that will extend the Monitor’s contract through 2025 and require the Monitor to submit to an annual independent audit. The agreement was filed for FERC approval Friday (ER18-2402).
In a concurrent filing, the parties also agreed the Monitor will provide to PJM more of the data market participants submit into MIRA, the Monitor’s online database, so participants don’t have to send the data to both the RTO and the Monitor. The additional sharing includes data used in generators’ fuel-cost policies. The filing also requires both parties to inform the other of changes to their systems (ER18-2403).
The new audit requirement “provides for a review intended to ensure that the services being provided to PJM by Monitoring Analytics are being completed consistent with the systems and controls in place for the provision of those services, similar to the reviews PJM conducts of its own systems and controls,” the RTO said in the filing.
The Monitor’s current contract runs through 2019, and stakeholders — particularly state regulators and consumer representatives — have been urging the parties to come to agreement early. (See “IMM Support,” Advocates Push PJM Board for Explanations at Annual Meeting.)
The early agreement also avoids some of the drama of the previous contract, which began in September 2013. As the initial six-year contract, which went into effect on June 30, 2008, neared its expiration, PJM’s Board of Managers announced plans in March 2013 to issue a request for proposals. The Organization of PJM States Inc. joined industrial consumers and cooperatives in protesting the decision, and the parties eventually agreed to an extension. By PJM’s annual meeting in October, a potential crisis had passed. (See Board, OPSI Bury the Hatchet over Monitor Contract.)
FERC on Thursday rejected financial stakeholders’ request for rehearing of its Feb. 20 ruling reducing the number of bidding nodes for virtual transactions (ER18-88-002).
The commission also upheld its rejection of PJM’s proposal to allocate uplift to up-to-congestion transactions (UTCs) as it does to increment offers (INCs) and decrement bids (DECs) (ER18-86).
Virtual Transaction Nodes
The commission said that XO Energy and the Financial Marketers Coalition merely rehashed arguments they had made against the node reduction proposal. (See FERC OKs Slash in Virtual Bidding Nodes for PJM.)
The changes reduce by almost 90% the number of bidding nodes, limiting INCs and DECs to those where either generation, load or interchange transactions are settled, or at trading hubs where forward positions can be taken. They also barred UTCs from zone, extra-high-voltage and individual load nodes. The changes reduced the number of INC/DEC trading nodes from 11,727 to 1,563, and UTC nodes from 418 to 49.
PJM said this trading pattern is “indicative of the low-risk positions that can be extremely lucrative without adding commensurate value to the market,” justifying its proposal to reduce the trading nodes for UTCs. | PJM
FERC did accept PJM’s request to change the effective date for the changes from Jan. 16 to Feb. 22, 2018. PJM said it intended to make the changes prospectively and that in its Dec. 22 response to a deficiency letter the RTO had neglected to change its requested effective date. PJM said the January date would be disruptive to the market, as it would have to remove all virtual transactions at points no longer eligible for bidding and re-execute the day-ahead market.
Commissioner Cheryl LaFleur issued a partial dissent, repeating her assertion that PJM had not justified reducing nodes for UTCs.
“As I stated in my partial dissent, I believe that UTCs provide value to the market and that reduced granularity in their use is a move in the wrong direction,” she said. “I would, however, be open to other solutions more targeted to the specific problems that PJM has identified.”
Uplift for UTCs
PJM complained that in its Jan. 12 rejection of the RTO’s uplift proposal, FERC dismissed the proposal outright, without setting it for hearing, or considering parts of the proposal separately. (See FERC: PJM Uplift Proposal for UTCs Falls Short.)
PJM claimed that, unless its filing was deficient, the commission could only accept the proposal or suspend it for hearing. But FERC said it was under no obligation to set the proposal for hearing. The RTO failed to demonstrate that the proposal would result in just and reasonable rates under Federal Power Act Section 205, the commission reiterated, “as it proposed to treat different financial transactions, with differing characteristics and effects, as if they were the same.”
However, FERC did reverse itself to accept PJM’s proposal to exclude internal bilateral transactions from uplift calculations, which the RTO said the commission should have considered separately. The commission directed PJM to submit a compliance filing in 30 days implementing the change.
PJM can still propose a different way to allocate uplift to UTCs, as FERC had dismissed the proposal without prejudice. “We also note, however, that any such hypothetical, future filing must address the concerns noted above, including the commission’s concern with PJM’s proposal to allocate uplift to a UTC as though it were two separate transactions, an INC and a DEC,” the commission said.
WASHINGTON — Public power representatives reiterated their case against mandatory capacity markets last week, teaming with wind and solar advocates for a one-day conference as a forum for their criticism.
“After spending or committing over $130 billion … in capacity payments in ISO-NE and PJM, I can safely say that almost nobody is happy with the state of those markets, which remain in a state of flux,” Sue Kelly, CEO of the American Public Power Association, told the inaugural Future Power Markets Summit.
“We think it’s time to rethink them. We believe that a resource adequacy regime that’s based on longer-term planning, bilateral contracting [as in MISO and SPP] and increased respect for state and local decision-making and autonomy — with a residual market capacity market for those who feel the need to go there — actually makes more sense,” she said during a lunch keynote at the conference.
Brian Forshaw, who represents public power systems at the New England Power Pool, used almost identical language. “The consensus of stakeholders throughout the [New England] region is that out of all of our market constructs, the energy market is probably the only one that’s working reasonably well,” he said. He acknowledged concerns that the region is “overly reliant” on natural gas.
James Wilson, a consultant who has worked for environmental groups and state consumer advocates in PJM, lamented that the capacity market — intended as “training wheels” to be removed once the markets found their balance — have remained, saying he would prefer an energy-only market.
Jay Morrison, vice president of regulatory issues for the National Rural Electric Cooperative Association (NRECA), compared capacity markets to a different method of conveyance, likening RTOs’ efforts to tweak the markets to attempting to convert a Ford Pinto into a Formula One race car. “It’s the wrong tool,” he said.
Not everyone at the Sept. 5 conference was critical, however. Katie Guerry, vice president of regulatory affairs for demand response aggregator EnerNOC, noted that DR gets virtually all of its revenue from the “availability payment” from capacity markets and very little from energy or ancillary services.
Although PJM’s capacity market “is the subject of a lot of concern and criticism, it is the gold standard when you go into countries around the world,” Guerry said. She noted that Alberta is adopting a capacity market with DR on the supply side, like PJM.
Aside from losing DR revenue, “it would significantly increase our costs to serve if there were no centralized markets at all,” Guerry said. “It would be very prohibitive for us.”
The conference, which attracted about 80 people, came after a summer that observers expected to stress test ERCOT’s energy-only market because of its reduced capacity reserves. In addition to APPA and NRECA, the summit’s sponsors were the American Wind Energy Association, American Council on Renewable Energy, Solar Energy Industries Association, Large Public Power Council and Energy Systems Integration Group, a nonprofit educational association for engineers, researchers, technologists and policymakers.
Texas survived the summer with surprisingly modest prices and no generation shortfalls, thanks to better-than-expected generation performance and an early summer system peak that took advantage of above-normal wind.
The capacity market provides certainty that resources acquired will be available, Garza said. “In ERCOT you don’t get that certainty. And [certainty] comes with some cost: Any of us who have a fixed-price mortgage are paying for that certainty.”
Fallacy of Fungibility
The latest challenge for capacity markets has been the effort to accommodate state preferences for renewable and nuclear generation without suppressing auction prices.
Morrison said state subsidies are only an issue because of the fallacy that capacity is a single fungible product.
“The RTOs do a good job of focusing on short-term reliability and low short-term marginal costs, and that’s great. But we need a lot more than that. We need long-term reliability; long-term price stability; environmentally favorable resources,” he said. “And if the one product that’s available is this fungible capacity product that the RTO has bought because they know better than us and our states, that doesn’t meet our needs.”
In June, FERC ordered PJM to expand its minimum offer price rule (MOPR), which now covers only new natural gas generation. The commission’s 3-2 ruling rejected both PJM’s capacity repricing proposal and the Independent Market Monitor’s MOPR-Ex proposal. (See PJM Unveils Capacity Proposal.)
Wilson was optimistic about the “resource specific” fixed resource requirement (FRR) proposal that he and consultant Rob Gramlich developed on behalf of environmental groups and the D.C. Office of the People’s Counsel.
“With a strong MOPR and this resource-specific FRR, we can have our RPM [Reliability Pricing Model] capacity market that is completely free of the impact of any subsidized resources because [they have] all been pulled out. It’s only the competitive resources [that remain]. And off to the side [are] those policy resources … they’re matched up with a commensurate amount of load, so customers are not paying twice. We’re … potentially getting to a pretty good place if we can make this FRR RS-thing work.”
Attorney Susan Bruce, who represents the PJM Industrial Customer Coalition, was less sanguine. “This is a case where there’s no good answer from my clients’ perspective. [We’re] just trying to find the least bad option,” she said.
She and Guerry expressed concerns over the modified FRR suggested by FERC.
“The FRR alternative, at least as it was put into the stakeholder process, would provide a very easy platform to sort of sink centralized capacity markets,” she said, predicting it would result in a “patchwork quilt of state policies” and a temptation to save uneconomic resources.
Guerry said the FRR alternative “makes us very nervous,” noting bilateral trades “are not transparent” to her company.
“Bilaterals are perfectly transparent to those in the market,” Wilson insisted.
But Devin Hartman, manager of electricity policy at the free market think tank R Street Institute, also was skeptical. He said it’s unworkable to administratively correct for subsidies in a pricing mechanism, calling it “a recipe for unintended consequences.”
“What constitutes a material subsidy?” he asked. “We’re going to have some fun with that — in perpetuity. It’s important to recognize that these markets have always had subsidies. Every resource has some degree of price subsidy. I don’t see how [PJM Monitor] Joe Bowring is going to come up with a screen to price correct for Price-Anderson,” referring to the law limiting liabilities for nuclear plant operators. “Where are you going to draw the line?”
Three times in three years, proponents of an organized market in the Western Interconnection have tried and failed to turn CAISO into an RTO.
Opponents say it’s time to give up, but supporters of CAISO regionalization say they’ll likely keep at it until they succeed.
Zichella | NRDC
“The benefits of a regional grid integration are so great that, frankly, we’re talking about something inevitable,” said Carl Zichella, western transmission director at the Natural Resources Defense Council. The environmental group was a main backer of this year’s CAISO regionalization effort along with Gov. Jerry Brown and ISO leadership.
The movement’s supporters argue that the future of renewable energy lies in Western states trading wind, solar and hydropower resources across state lines as easily as energy is now distributed within California.
Zichella said proponents believed they had a combination of Democratic and Republican votes needed for their measure — AB 813 — to pass the State Senate this year but that Democratic leaders wouldn’t let the bill out of the Senate Rules Committee on the last night of the State Legislature’s 2017/18 session on Aug. 31.
The bill would have started the process of turning CAISO into an RTO by initiating changes in its governance structure.
It languished in the Rules Committee, where Senate leaders had sent it, and never reached a floor vote because of a lack of Democratic unity on the bill, advocates on both sides of the issue said.
“In California, we feel like there’s a future for this legislation,” Zichella said. “We’ll probably take another run at it.”
Freedman | UC Berkeley
Matthew Freedman, a staff attorney for The Utility Reform Network (TURN), said he hopes that won’t happen. The ratepayer advocacy organization strongly opposes an effort to make CAISO a multistate organization.
“The Legislature has emphatically rejected regional proposals put forth by the governor over the last several years, which suggests it’s time to consider alternative approaches to regional coordination,” Freedman said.
Those alternatives could take multiple forms, including expanding the Western Energy Imbalance Market to include more participants and moving it from a real-time exchange to a day-ahead market, he said.
“We’d prefer incremental steps toward regional coordination” that are easier to undo if necessary, the lawyer said.
TURN and other opponents are against the idea of changing CAISO’s governance structure from one overseen by officials in Sacramento to a multistate conglomerate with an independent board of directors that they contend would be more susceptible to meddling from Washington and to influence from the coal-burning states of the Interior West.
The governor is termed out of office this year, and his replacement will be elected in November.
Brown has been the main proponent of regionalization as a means to further his green energy goals across the West, Freedman noted, but “he won’t be the governor in January,” when the Legislature reconvenes for the start of a new two-year session.
Whether a new governor will support CAISO regionalization remains to be seen.
It’s also unclear if a majority of Democratic lawmakers can be persuaded to vote for a measure that would remove CAISO’s leaders from their oversight and is opposed by labor unions, publicly owned utilities and other powerful interests, Freedman said.
Many Democrats, who control the Legislature, had reservations about AB 813 and didn’t want to be forced to vote against it on the Senate floor for fear of angering the governor, he said.
Senate President Pro Tempore Toni Atkins may have kept the bill in the Rules Committee, but she wouldn’t have done so without her caucus’s backing, Freedman said. “Had there been an overwhelming amount of support, she would not have held it,” he said.
WASHINGTON — Former FERC Chairman Pat Wood III used his keynote speech at last week’s Future Power Markets Summit to “re-serve the Kool-Aid” on the value of competitive markets threatened by state subsidies and the Trump administration’s push for price supports for coal and nuclear generation.
He referred to the “economic carnage” caused by the over-budget Vogtle and Summer nuclear plants in Georgia and South Carolina and the Kemper “clean coal” project in Mississippi, citing estimates that they will saddle ratepayers in the cost-of-service Southeastern states with $123 billion in excess costs over 40 years.
Wood contrasted that with the savings seen in ERCOT’s competitive energy-only market, where retail power prices have declined to about 8 cents/kWh, down from 10.5 cents before competition. Wood credited the savings to cheap wind and natural gas generation, dozens of competitive retail suppliers and lower profit margins.
“When I was a regulator, we would give a utility a 16% pretax rate of return on equity. … When I was [chairman] at Dynegy, we were happy to get 3[%].”
The conference was sponsored by the American Wind Energy Association, American Council on Renewable Energy, Solar Energy Industries Association, American Public Power Association, National Rural Electric Cooperative Association, Large Public Power Council and Energy Systems Integration Group (ESIG), a nonprofit educational association for engineers, researchers, technologists and policymakers. (See related story, ‘Almost Nobody is Happy’ with Capacity Markets at Conference.)
Wood told the 80 attendees he feared grid modernization could lead to a “gold plating” of the distribution and transmission systems that erodes the savings from cheap natural gas and renewable generation. “I don’t want to see all the savings I get from crunching down on the [generation] be offset by adding a lot to” transmission.
Beth Garza, director of ERCOT’s Independent Market Monitor, expressed a related concern. “We can spend dimes on transmission to save dollars in generation costs, and we’ve done that,” she said, referring to the competitive renewable energy zone (CREZ) transmission built to deliver West Texas wind. “I think, though, that over the years … we’ve reached a point now where we’re starting to spend quarters on transmission to potentially [save] quarters on the energy side. I’m not sure there’s the appropriate discipline and review on the regulatory side to bring those two in balance.”
Garza also questioned the distinction between “the big poles and wires [transmission] and small poles and wires [distribution].”
“Distribution utilities have a fixed investment in the small poles and wires and transformers and that is recovered through a variable rate, and so of course they don’t want people with PVs on their roof diminishing their consumption and diminishing their payment,” she said. She suggested the variable rates on distribution be replaced with fixed rates to acknowledge that both transmission and distribution enable the connection between customers and resources.
Jeff Bladen, MISO’s executive director for market design, discussed three “mega trends” that he said must be addressed by RTO markets: digitalization, including the Internet of Things; decentralization of generation; and “demarginalization” resulting from the rise of low- and no-marginal-cost resources.
“Our markets are moving away from the marginal cost of energy being the primary means for signaling the operational needs of the grid,” he said. “As we move forward, our history of everyday scheduling our generation and forecasting our load is beginning to switch. We’re going to look at a future where much more of our supply is a forecast and much more of our demand is something we try to schedule — digital devices and the like.”
Robin Hytowitz, an electrical engineer for the Electric Power Research Institute, noted that FERC-jurisdictional RTOs and ISOs “have started to integrate fixed operating costs from fast-start resources into prices.”
But she lamented that “demand-side bidding versus retail choice isn’t very active in most markets.”
“I think that actually having a demand curve for these markets would help advance some of the price formation efforts. So, we could get the demand side in addition to the supply-side curve.”
Mark Ahlstrom, board president of ESIG, argued for maximizing the granularity and flexibility of resources that provide ancillary services.
“Suppose I need 100 MW on reserve and in order to qualify to even offer it into the market, I have to be able to provide a four-hour sustained duration. Do I really want to have one product — 100 MW for four hours of sustained duration? Or would I rather have four 100-MW units that can each sustain duration for only one hour? I would argue that — without question — you want the latter, because … I can also use those building blocks in other ways.”
Ahlstrom said although more granular resources should be cheaper, pricing them is a challenge.
“Any time we block those capabilities into hourly type products or anything like that in order to price them … we are leaving a lot of the capability and flexibility on the cutting room floor. An engineer in the control room would like to have continuous control over everything if we can figure out how to run markets that way.”
Ahlstrom said he previously thought it unwise to combine storage with a renewable resource because it increases the cost of energy. “The market should be the cheapest source of flexibility if it’s working right,” he said.
“I’ve had to eat my words on that because we’re seeing huge demand; we’re going to see a ton of these hybrid projects,” he continued. “And why is that? It’s because in the markets as they’re operating today, it’s way too tough to get through the interconnection process and connect new resources separately. … A lot of this is a reflection that we can’t just have a frictionless way of adding resources to the markets.”
FERC Chairman Kevin McIntyre has defended Chief of Staff Anthony Pugliese, saying his controversial remarks did not reflect commission policy or threaten its independence and impartiality.
Rep. Frank Pallone (D-N.J.) and Sen. Maria Cantwell (D-Wash.), the ranking members of the House and Senate energy committees, sent McIntyre a letter Aug. 22 complaining of Pugliese’s “highly partisan political remarks” at a conference of the American Nuclear Society in August and in an interview with right-wing media outlet Breitbart in July.
On Thursday, Cantwell released McIntyre’s Aug. 24 response, in which he praised Pugliese’s “outstanding management skills and his unparalleled talent for coordinating the activities of a complex, multi-faceted agency.”
Pallone and Cantwell cited Pugliese’s praise of President Trump and criticism of Democratic governors for blocking pipelines. They also cited his statement to ANS that FERC is working with the Department of Energy and National Security Council on the Trump administration’s proposal to provide price supports for at-risk coal and nuclear generators. (See Democrats Call Out ‘Partisan’ Remarks by FERC Chief.)
Pugliese, a former lobbyist in Pennsylvania’s capital, and an unsuccessful state legislative candidate, joined FERC in August 2017 after a stint at the U.S. Department of Transportation as a member of Trump’s so-called “shadow cabinet.”
McIntyre said he had authorized Pugliese to make the Breitbart and nuclear conference appearances but that “the specific subjects of his remarks were not subject to review and were not identified in advance.”
The chairman said none of Pugliese’s comments reflected FERC policy because “the commission speaks exclusively through its orders. Consequently, neither the public statements of Mr. Pugliese nor those of any other FERC staff member can state the views of the commission, particularly in connection with proceedings on which the commission has not issued an order on the merits.”
“While I understand your concerns, I can assure you that this commission remains independent and impartial,” McIntyre said.
McIntyre joined in a 5-0 vote in January rejecting Energy Secretary Rick Perry’s Notice of Proposed Rulemaking to save at-risk coal and nuclear plants and instead opened a docket to consider resilience concerns (AD18-7). In June, however, Trump ordered Perry to save coal and nuclear plants under an obscure Korean War-era law. (See More Questions than Answers for FERC, RTOs on Bailout.)
In his response to Cantwell, McIntyre said commission staff “has not discussed the merits of any ‘grid resilience’ proposal that would seek to prefer one form of generation over another with executive branch officials. Commission staff does, however, have regular contact with our counterparts in the Department of Energy on a host of matters of shared responsibility including intelligence, personnel and legal process.”
Cantwell said in a statement that she was encouraged “to hear Chairman McIntyre clarify that the commission’s official orders, like the 5-0 rejection of the Trump coal bailout, are what count. However, speeches and interviews by the commission’s top staffer that are laced with bad-faith partisan attacks serve to undermine FERC’s traditional impartiality and neutrality.”
Pallone said he was “disappointed that [McIntyre] failed to acknowledge that the partisan comments of his chief of staff, Anthony Pugliese, were wholly inappropriate, unhelpful and distasteful. To my knowledge, no other FERC chief of staff under either Republican or Democratic administrations has used that position as a platform for partisan attacks.”
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.
