ERCOT staff told members of the Supply Analysis Working Group (SAWG) on Friday that the Texas grid’s summer peak demand is expected to reach 85 GW by 2027, a 22.36% increase over this summer’s peak.
But ERCOT is in good shape to meet the coming demand. The ISO’s November Generator Interconnection Status Report shows 20.6 GW worth of projects with interconnection agreements through 2020. Another 47.32 GW of capacity is being studied.
| ERCOT
And despite the pending loss of more than 4 GW of coal-fired generation, ERCOT said it has more than 80 GW of available capacity to meet load this winter and spring. (See ERCOT: Sufficient Capacity for Winter, Spring.)
Staff’s 2018 long-range load forecast sees stronger growth along the coast and in Far West and South Texas, compared to the 2017 forecast, but weaker growth in North Central and South Central Texas. Based on Austin Energy forecasts and the utility’s focus on energy efficiency, staff project a 0.5% annual growth rate for the Austin area.
ERCOT’s most recent Capacity, Demand and Reserves report indicated the ISO will have an 18.9% reserve margin for next summer, with margins remaining above 18% the following three years. A revised CDR report incorporating the latest retirements will be released Dec. 18.
Texas is the fastest growing state in the country, having registered the nation’s largest annual population growth between 2010 and 2016, according to the U.S. Census Bureau. The state has been adding more than 200,000 people a year and will soon top 28 million.
NRG to Retire 806 MW of Mothballed Resources
Greens Bayou Unit 5
NRG Texas Power notified ERCOT last week it plans to retire Greens Bayou Unit 5 and three other previously mothballed gas-fired units with a total capacity of 806 MW.
Greens Bayou Unit 5 dates back to the early 1970s and had a reliability-must-run agreement with ERCOT — the ISO’s first since 2011 — that was terminated in May. The unit was mothballed in 2010 and 2011. (See ERCOT Ending Greens Bayou RMR May 29.)
NRG also said it would retire three gas units at its Houston-area S.R. Bertron plant. The company shut down two 230-MW units and a 13-MW quick-start unit in 2011 for economic reasons. All three units were more than 50 years old.
The retirements will be effective Dec. 31, NRG said in its Dec. 5 filing.
LITTLE ROCK, Ark. — SPP’s Board of Directors and Members Committee on Dec. 5 approved a 1-cent increase in the RTO’s administrative fee, keeping an eye on projected future reductions with the expected integration of the Mountain West Transmission Group.
Finance Committee Chair Larry Altenbaumer said the committee expects the fee to peak in 2019, “before we realize the benefits that would come from the potential integration with Mountain West.”
SPP and Mountain West have targeted Oct. 1, 2019, as the latter’s membership date.
The RTO’s administrative fee shot up 13.2% for 2017, from 37 cents/MWh to 41.9 cents, compensating for a lack of load growth. With this year’s increase, the 2018 fee will stand at 42.9 cents, just under its Tariff cap of 43 cents.
Last year it projected annual fee increases through 2021, topping out at 49.9 cents/MWh in 2021. This year’s budget forecasts flat load through 2020 and a corresponding admin fee of 47.7 cents, without assuming any benefits from Mountain West’s integration.
“We’re sensitive to the concerns of our members,” Altenbaumer said.
The 2018 increase is based on a net revenue requirement of $164 million, compared to the 2017 budget of $160.9 million. The Finance Committee said the increase is driven by the dissolution of the SPP Regional Entity and associated NERC funding — the committee assumes the RE will terminate its services after June — and by increases in various operating expenses.
| SPP
Altenbaumer said the Finance Committee would bring back another budget once a memorandum of understanding is signed with Mountain West.
SPP is budgeting 383 million MWh in annual billable energy through 2022, after having previously projected as much as 407 million MWh for 2017. The RTO saw a 1.6% year-over-year growth in average monthly peaks through July 2017 but is modeling 2% reductions in monthly peaks for August through November and a 12% reduction in December peak demand compared to 2016.
The board and stakeholders also approved the committee’s recommended budget, which reduces expenses by 2.85% to $190.8 million. Net income is forecast at $194.2 million, within $100,000 of this year’s budget and up from $176.2 in 2016.
Using SPP’s three-year budget as the basis for a five-year forecast, the Finance Committee assumed capital expenditures to be consistent with the 2020 forecast, adjusted for inflation. The committee projects income will increase to $204.2 million in 2019, and then again to $215.6 million in 2021 and $222.8 million in 2022, with expenses reaching $210.2 million in 2022.
The RTO estimates a headcount of 609 employees, reflecting the loss of the 17 RE positions.
Golden Spread Electric Cooperative’s Mike Wise, chair of the Strategic Planning Committee, told the board and members that he and his committee “fully expect” SPP to integrate Mountain West.
“Nobody’s trying to rush it. We want to get it right,” Wise said.
Wise said the SPC has met five times behind closed doors with Mountain West members since the formal integration stage began in September. Two more meetings have been scheduled: one on Dec. 19 in Dallas and another in the first week of January in Denver. Staff has developed a list of issues to be discussed, some of which are likely to drop off the list, he said.
“Some [issues] are more difficult than others, in that there is a gap between what Mountain West desires and things it needs, and what our current Tariff and members agree to,” he said. “The committee is interested in balancing the benefits and the costs, and to ensure we fully weigh those in the decisions that are made. We want to very jealously protect our culture. It’s been developed over the years, and we know what it means to be a member. It’s a very important ingredient in this discussion.”
SPP has projected a total net present value benefit to its current members of approximately $209 million, much of it from reduced administrative fees, for the first 10 years of Mountain West’s membership. Separate studies for Mountain West have determined the group could save up to $71 million annually through 2024 by participating in SPP’s day-ahead market and replacing its nine tariffs with one, along with annual net production cost savings ranging from $11.7 million to $28.8 million. (See SPP, Mountain West Integration Work Goes Public.)
Board Approves New MOPC Vice Chair, SPC Members
The board approved a consent agenda that included several nominations for stakeholder groups and their leadership positions, as submitted by the Corporate Governance Committee (CGC).
Northeast Texas Electric Cooperative’s Jason Atwood was selected from several candidates as vice chair of the Markets and Operations Policy Committee. He replaces Todd Fridley, who resigned from the position in October. His term commences Jan. 1.
Other organizational group chairs, all incumbents unanimously approved by their groups, were confirmed for two-year terms also beginning Jan. 1:
Grant Wilkerson, Westar Energy (Business Practices Working Group)
Eric Ervin, Westar (Security Working Group)
Jennifer Flandermeyer, Kansas City Power & Light (Event Analysis Working Group, Reliability Compliance Working Group)
Allen Klassen, Westar (Operating Reliability Working Group)
David Kays, Oklahoma Gas and Electric (Regional Tariff Working Group)
Jim Jacoby, American Electric Power (Seams Steering Committee)
Brad Hans, Municipal Energy Agency of Nebraska (Supply Adequacy Working Group)
Travis Hyde, OG&E (Transmission Working Group)
The committee also nominated Westar’s John Olsen and AEP’s Richard Ross to the SPC. They replace Southwestern Electric Power Co.’s Venita McCellon-Allen, who resigned from the committee, and OG&E’s Jake Langthorn, who has retired.
The CGC’s annual review of each group resulted in a name change for the Critical Infrastructure Protection Working Group, which now becomes the Security Working Group. The committee recommended the change to differentiate between NERC critical infrastructure protection standards and cyber and physical security infrastructure protection.
The committee also recommended minor tweaks to the scopes of the Finance and Human Resources committees.
Two Industry Experts Added to SPP’s Order 1000 Panel
The board and members also approved two new candidates for SPP’s Industry Expert Pool (IEP), which will evaluate and recommend competitive-upgrade projects. Joining the 12 incumbents approved in October 2016 are Sriram Kalaga, a Fellow of the American Society of Civil Engineers and holder of a doctorate in structural engineering, and Tom Bozeman, a director with civil engineering firm Atwell who has long experience designing and building transmission and substation projects.
SPP will select three to five experts from the IEP to evaluate and recommend competitive upgrades under FERC Order 1000. Two previous panels have recommended one project, which was eventually withdrawn in 2016. (See SPP Awards First Order 1000 Project — But it May Not be Needed.)
Stakeholders welcomed Jody Sundsted, vice president of market for Western Area Power Administration-Upper Great Plains Region, to the Members Committee. Sundsted gives the committee 20 members.
SPP set several new records for wind generation last week, lending further credence to its claims that it can handle wind-penetration levels as high as 75%.
Wind resources peaked at 13,587 MW at 7:55 a.m. on Dec. 4 and then again at 14,150 MW at 9:55 p.m., bettering the old record of 13,342 MW, set on Feb. 9.
| SPP
SPP also set new standards for wind penetration (56.25%) and renewable energy penetration (58.23%) Dec. 4. Coal accounted for 28.94% of the energy produced at that time and gas for 11.58%.
The RTO has nearly 18 GW of wind capacity in service and almost 44 GW of additional capacity in all stages of development. Staff said earlier this year it could serve up to 75% of its load with wind energy and other renewable resources. (See SPP Eyes 75% Wind Penetration Levels.)
SPP staff told the Seams Steering Committee (SSC) last week they plan to meet with FERC staff in January to resolve a seams project recently rejected by the commission.
FERC in October nixed SPP’s proposal for regionwide/load-ratio share funding for its portion of two projects with Associated Electric Cooperative Inc. (AECI) and City Utilities of Springfield, Mo. The commission ruled SPP had not shown they were “roughly commensurate with the projects’ benefits.” (See FERC Rejects Cost Allocation for SPP-AECI Seams Project.)
SPP Interregional Coordinator Adam Bell said staff would perform additional analysis on the AECI project before meeting with commission staff. SPP and AECI agreed to build a new 345/161-kV transformer at AECI’s Morgan Substation and uprate an existing transmission line, with the RTO covering $17.1 million of the $18.75 million cost.
“Once we have direction from that meeting, we’ll come back and make a decision on the best way forward,” he said.
A second seams project with City Utilities, the installation of a new 345-kV 50-MVAR reactor at the city’s Brookline substation that was also rejected by FERC, has been included in the 2018 Integrated Transmission Planning Near-Term (ITPNT) assessment.
SPP and AECI are meeting Dec. 20 to discuss a joint and coordinated system planning study. Under terms of their joint operating agreement, the two systems are to conduct such a study every other year.
Bell said the study scopes have varied in the past, from “full-blown joint models to participating in a study SPP is already doing.”
MISO Incurs $5M Hit on Single M2M Flowgate
MISO is on the hook for $6.1 million in market-to-market (M2M) payments to SPP for October, the largest bill in the 32 months since the two grid operators began the coordination process.
| SPP
A single flowgate in the Empire District and Westar Energy control zones that was binding for 329 hours in October was responsible for $5.1 million alone. SPP said high wind flows from MISO and local outages made the flowgate difficult to control.
Several stakeholders expressed confusion as to why MISO is not taking steps to resolve the situation on its side of the seam.
“MISO has not come to us and suggested we consider any joint transmission projects to mitigate the congestion,” said David Kelley, SPP’s director of interregional relations. “If it was us, we would go to them.”
Asked for comment, MISO spokesman Mark Brown responded, “As part of MISO’s ongoing planning process, we regularly evaluate historic congestion and assess feasible ways to address those issues.”
Through October, MISO has paid $27.7 million to SPP. The two RTOs began the M2M process in March 2015.
The Illinois Commerce Commission heard two very different views of MISO’s Zone 4 at a workshop last week, with some speakers claiming the region has sufficient reserves and others saying it is in dire straits.
The ICC convened the Dec. 8 workshop to hear continuing discussion on the future of resource adequacy in the RTO’s Southern Illinois zone. The commission will hold another workshop next month and then issue a summary report of stakeholder positions to Gov. Bruce Rauner by Feb. 26. It was Rauner’s office that in part sparked the workshop after sending the ICC an Oct. 26 letter asking the commission to produce a white paper and stakeholder comments on the structural challenges of Zone 4 within five days.
Dynegy representatives repeated warnings that the company could shutter one of its eight plants in Zone 4. The company operates about 6.5 GW of capacity in the zone, which contains 57 utility-scale generating stations with a combined 16 GW of nameplate capacity. Dynegy said unprofitable plants could shut down as early as the 2018/19 planning year unless changes are made to support local generation. Merchant generator owner Rockland Capital also warned in workshop comments that merchant plants will be forced to exit the market in Illinois without MISO capacity market improvements.
“We are the bearers of the risk of deregulation,” said Dean Ellis, Dynegy executive vice president of regulatory and government affairs.
Ellis also criticized the short lead time MISO provides for its annual capacity auction, with the auction taking place in early April and the planning year beginning June 1. “We have to make investment decisions involving millions or tens of millions of dollars with as little as six weeks’ notice,” he said.
Dynegy said MISO and the Organization of MISO States’ (OMS) projected capacity surplus through 2022 includes all of the company’s at-risk downstate generating units — except for Baldwin Unit 3 near St. Louis — as available capacity. The OMS-MISO resource adequacy survey predicts Zone 4 will have an average 2.62-GW surplus through 2022.
The company also warned the ICC not to count on MISO’s system support resource program, which enables the RTO to keep units online for reliability purposes: “It might be asserted that … MISO could invoke its system support resources tariff to require Dynegy to keep one or more of the retiring units in operation, while compensating Dynegy through cost-of-service-based payments under an SSR agreement. However, the MISO SSR tariff as written only provides for generating units to be designated as SSRs in order to maintain transmission system reliability (including compliance with thermal and voltage limitations under applicable NERC standards) and not to maintain resource adequacy.”
MISO Executive Director Melissa Seymour confirmed Dynegy’s assessment, saying the RTO could only pursue SSR agreements in cases where reliability is threatened, but not for resource adequacy.
Ameren Illinois said it didn’t see an immediate need for action, arguing that only mid- and long-term resource adequacy is a concern for the zone.
“There are sufficient resources in the market today, and sufficient resources are forecasted to be available in the market in the next three to five years. Thus, the problem identified is mid- and long-term resource adequacy in MISO Zone 4,” the company said in comments.
AARP Senior Legislative Representative Bill Malcolm said Illinois customers should “celebrate” because energy costs are low and the wholesale market is finally working as designed in Zone 4.
Malcolm urged a slower timeline to develop a resource adequacy solution and recommended a full independent study of capacity in all of Illinois, not just the downstate market.
“This seems to be a solution in search of a problem. There is no urgent issue; we have time,” Malcolm told the commission.
Activist Tracy Fox, representing several community groups in the state, also argued for a measured response and called for an independent analysis. “If you watch these plants, they’re always broke, there’s always a fix on the horizon, and once they get it, they’re broke again,” Fox said.
Speaking on behalf of Rockland Capital, Travis Stewart of Gabel Associates cautioned against a study that relies solely on publicly available data, saying it might not paint a full picture.
RA not a Problem
Jim Dauphinais, representing Illinois Industrial Energy Consumers, said Southern Illinois does not have a resource adequacy problem.
“There has not has been a serious resource adequacy issue in the state since 1998,” Dauphinais said, referring to the premature shutdown of Commonwealth Edison’s two large Zion nuclear reactors.
Malcolm said supplies in the Midwest are so plentiful that We Energies is shutting down its Pleasant Prairie plant in southeastern Wisconsin.
Direct Energy said, if anything, there’s an oversupply issue in Zone 4, noting the $1.50/MW-day clearing prices in MISO’s most recent capacity auction. The retail electric supplier urged the ICC not to “disrupt the entire market and potentially subject customers to escalating and uncontrolled capacity costs.”
“I don’t mean to be critical, but [MISO CEO] John Bear’s letter was weak. It doesn’t present any evidence at all of a resource adequacy problem,” Fox said, referring to a May letter Bear penned to Rauner, urging the state to continue to seek solutions to a possible capacity shortfall after FERC rejected MISO’s separate three-year capacity auction proposal for retail choice areas. She conceded Bear’s point that Zone 4’s resource adequacy conditions change from year to year.
No Greener Pastures
Last month, Dynegy drafted legislation that would have the Illinois Power Agency hold a separate competitive capacity auction for Central and Southern Illinois, but the proposal failed to advance in the Illinois House of Representatives after hearings. (See Dynegy Auction Proposal Fails to Gain Ill. Lawmaker Support.) In workshop comments, Exelon said it generally supported the plan, contending it “would have ensured that Illinois would no longer be subject to the annual one-year cycle of capacity auctions and the volatility that ensues.”
A recent ICC white paper concluded that state has four options: continue to rely on existing competitive forces and market structures; impose additional capacity requirements on load-serving entities; create a reliability portfolio standard; or encourage or require utilities to switch RTOs.
Fox criticized the white paper as too heavy on MISO Zone 4 backstory and light on an examination of the solutions. “We came out with four solutions, but the solutions aren’t analyzed at all,” Fox said.
During a Dec. 4 conference in Indianapolis hosted by EUCI, ICC Commissioner John Rosales said it was interesting that the white paper offered RTO defection as an option while other Illinois generators outside of Zone 4 are considering moving from PJM to MISO. “The grass is always greener on the other side. I hate for that to be the end-all option. That’s the North Korea option. There’s a lot of repercussions to move from one RTO to the other, and I’d hate for that to happen.”
Ameren has also said it believes that reconfiguring RTO participation will “not necessarily guarantee long-term resource adequacy for downstate Illinois.”
Questions Remain as PJM Continues Push for Price Formation Revisions
PHILADELPHIA — Stakeholders hoping to influence PJM’s plans for revising its price formation methodology had better move quickly. RTO staff unveiled their problem statement and issue charge on the topic at last week’s Markets and Reliability Committee meeting and hope to have it approved at the next one on Dec. 21.
“If you are going to follow up … please do so soon,” PJM’s Stu Bresler said of the proposal, which would create a senior task force “investigating energy and reserve price formation enhancements [to] … more transparently reveal the true cost of meeting system reliability needs.”
In advance of a decision looming at FERC to provide price supports for nuclear and coal-fired units, PJM has been campaigning for support of an alternative. It would remove the prohibition on letting inflexible generators — often large coal and nuclear plants — be the price-setting marginal unit in its real-time and day-ahead energy markets. It would also factor in start-up and no-load costs, which are currently set aside.
PJM says these “simplifications” were used during the development of LMPs to reduce the time necessary to successfully dispatch the system. Large inflexible units are often dispatched despite clearing prices that are below their offers and receive uplift payments that compensate them for their costs. Out-of-market uplift payments have been a source of stakeholder frustration for years. (See PJM MRC OKs Uplift Solution over Financial Marketers’ Opposition.)
“From the initial implementation of locational marginal pricing, given that it is an optimization … we made some simplifying assumptions up front,” Bresler said.
PJM’s plan wouldn’t eliminate uplift and calls for making additional lost opportunity cost (LOC) payments for flexible units with lower offer prices to reduce their output to balance load and generation. But the RTO argues that the reduced uplift and LOC payments combined would be a fraction of the current uplift payments.
Still, stakeholders have been cautious to endorse the plan and asked that it not be rushed into implementation.
James Wilson of Wilson Energy Economics, who consults with several consumer advocates within PJM’s footprint, said the RTO’s proposed timeline for completing the task force before the fourth quarter of 2018 is too ambitious.
Joe Bowring, PJM’s Independent Market Monitor, echoed that.
“This is a massive change. There’s no reason to not have thought it through carefully,” he said, listing other market components beyond the energy and reserve prices that would be “impacted” by the change, including financial transmission rights and rules for Capacity Performance, market-power mitigation and uplift.
“I ask you to get stakeholder input and consider other options,” said Greg Poulos, the executive director of the Consumer Advocates of the PJM States (CAPS).
Bob O’Connell of Panda Power Funds asked PJM to “reserve judgments” about what causes and solutions the task force could discuss.
“Impairing flexibility because of the way we’re paying suppliers, that’s something we need to talk about,” he said.
Gabel Associates’ Mike Borgatti requested education for market participants to update their modeling assumptions.
Susan Bruce, who represents the PJM Industrial Customer Coalition, asked that load receive “fair notice” of the changes and a way to measure what the impact will be. “We have a lot of load that’s locked in because of low energy prices,” she said.
DER Charter Endorsed
After several contentious discussions at previous MRC meetings, members endorsed by acclamation the charter for the Distributed Energy Resources Subcommittee, which will consolidate PJM’s efforts on DER.
The charter had been contentious because of an addition that required all rules to “adhere to all pertinent jurisdictions” and regulators. Some stakeholders saw it as stating fact, while others were concerned it could be used to stifle discussion.
Bruce asked the group to be “extremely cautious” and that its proposals could result in costly requirements for “people who are not represented in this effort because they have chosen not to be in the PJM markets.”
PRD Rules Deferred
Stakeholders voted to defer a planned vote on new rules for price-responsive demand (PRD) pending the deliberations of the recently formed Summer-Only Demand Response Senior Task Force.
The RTO wants to change the PRD rules to comply with its CP requirements. PJM’s Pete Langbein attempted to characterize it as “just another [supply-side] option that would be out there that folks could elect to choose.” But state representatives complained that the proposed changes fail to acknowledge PRD’s value.
“It’s not a capacity product. It’s a mechanism to refine the load forecast,” said Morris Schreim of the Maryland Public Service Commission. “It’s not competing with supply.”
He argued against a change in the PRD rules that would “close the door” on solutions in the task force and suggested tabling the vote pending the outcome of the task force. Gregory Carmean, executive director of the Organization of PJM States Inc. (OPSI), agreed with Schreim that “it is time to take a pause,” saying it’s “hard to reconcile” the RTO’s justifications.
Langbein clarified that PRD displaces resources, either generation or demand response, with year-round capacity on a one-for-one basis. “That is the reality,” he said.
Calpine’s David “Scarp” Scarpignato called PRD “inferior” to generation in the context of CP and urged a vote. Waiting will make it harder to adjust the rules later as companies make decisions based on the current rules, he said. “We need this in place for the next [Base Residual Auction].”
EnerNOC’s Katie Guerry said it’s “alarmist” and “unproductive” suggest that all DR on the system would convert to PRD without the rule changes and said she was “looking forward to analyzing the opportunities” through the task force.
“Please participate in that process regardless of what sector you’re in,” she said, because that is where she sees any “real solution” being developed for summer-only DR that can no longer qualify as a capacity resource.
The deferral passed with just enough votes to clear the two-thirds threshold, receiving a 3.44 score (out of 5) in a sector-weighted vote.
Stakeholders Have Questions Before Approving MOPR-Ex
The Monitor will hold a question-and-answer session Tuesday to address stakeholder concerns on its proposed revisions to the capacity construct. The changes to the minimum offer price rule (MOPR) are expected to be brought to a vote at the Dec. 21 MRC meeting.
The IMM’s proposal was the only one to receive more than 50% approval in a poll of the Capacity Construct/Public Policy Senior Task Force, which has been meeting throughout the year to address concerns about market distortions from subsidized generators. The proposal would extend the MOPR to cover all units indefinitely, though it would include several exemptions.
Bowring said the proposal is meant to create an incentive for subsidized units “not to exist in the first place.” He fielded enough questions that stakeholders asked for a separate forum before voting. Jason Barker of Exelon, which had submitted its own proposal to the task force, questioned Bowring’s contention that the proposal is nondiscriminatory.
“Why do you think it’s appropriate to allow an overbuild?” he asked of one of the rule exemptions.
“I hear the point, and you’re right,” Bowring responded. “Let us think about that; it’s a good point.”
“You don’t have an answer to that? We’re going to have to vote on this,” Barker pressed.
“You’re not going to have to vote today,” Bowring replied. “We’ll have something out well ahead of the vote.”
PJM agreed to shorten its Dec. 12 Operating Committee meeting to make time for the Q&A.
For the second time in three months, no proposal from the Incremental Auction Senior Task Force received enough support to be proposed at the MRC, a fact that American Municipal Power’s Steve Lieberman argued should preclude PJM from automatically bringing its proposal for MRC review, even if it was just seven votes shy of the threshold at the task force. But Exelon’s Sharon Midgley moved for a vote on PJM’s Proposal A” and Bruce seconded it. The proposal received a first read and will be voted on at the next MRC.
“This is a compromise … but it’s all in the interest to try to get something before FERC so the issue of excess capacity and the sellback can get addressed, favorably for load,” Bruce said.
CPower’s Bruce Campbell argued the proposal doesn’t maximize the value of IA returns for load and said he was prepared to back another proposal “if others are interested,” but he received no support.
Other Voting Results
Stakeholders endorsed by acclamation several manual revisions and other operational changes:
Manual 11: Energy & Ancillary Services; Manual 18: PJM Capacity Market; Manual 27: Open Access Transmission Tariff Accounting; Manual 28: Operating Agreement Accounting; and Manual 29: Billing. The revisions implement PJM’s transition to five-minute settlements under FERC Order 825.
2018 day-ahead scheduling reserve (DASR) requirement. The final DASR calculation dropped to 5.28%, which was even lower than PJM’s preliminary estimates in October. The 2017 DASR was 5.48%. PJM attributed the year-over-year drop to reductions in average seasonal load forecast errors and the forced-outage rate. (See “DASR Requirement Drops Again,” PJM Operating Committee Briefs: Oct. 10, 2017.)
Tariff and Operating Agreement revisions to modify credit requirements for regulation and FTRs:
Regulation credits are accrued daily and billed monthly, while energy charges are accrued daily and billed weekly. Although the regulation-only resources’ credits are much greater than the charges, the weekly bills for charges create a credit requirement, even though the much larger credit is due to the provider at the end of the month. Daily regulation credits will now be included in weekly instead of monthly activity for calculating credit requirements. The change will apply to all resources, not just regulation-only resources.
FTR credit requirements for prevailing paths currently are based on weighted historical congestion on those paths, but transmission system upgrades can reduce congestion, decreasing the value of prevailing-flow FTRs. PROMOD simulation results will now be incorporated into the FTR credit calculator prior to the bid window to incorporate consideration of major upgrades and reduce default exposure to PJM’s members. (See “Give Them Some Credit,” PJM Market Implementation Committee Briefs: Oct. 11, 2017.)
Members Committee
Stakeholders Endorse Consent Agenda
Stakeholders endorsed by acclamation the committee’s consent agenda along with several other OA and Tariff changes:
OA revisions associated with PJM sharing of restoration planning generator data with transmission owners. (See “TOs to Receive Confidential Generation Data for System Restoration,” PJM Operating Committee Briefs: Sept. 12, 2017.)
Tariff revisions related to a proposed change in credit requirements for regulation resources. (See “Other Voting Results” above.)
Tariff revisions to FTR credit requirements to reduce exposure posed by congestion changes resulting from major transmission upgrades. (See “Other Voting Results” above.)
Nominees Approved
Members elected new representatives to the Finance Committee, sector whips and the Members Committee vice chair for 2018. It is the Transmission Owners sector’s year to choose a vice chair, and Chuck Dugan of the East Kentucky Power Cooperative was nominated.
California regulators are set to vote next month on a proposal that community choice aggregators (CCAs) be subject to the resource adequacy requirements of electric utilities.
The California Public Utilities Commission’s approval would require CCAs to comply with resource adequacy rules “in order to ensure that sufficient energy supply for customers is being procured by the appropriate utility.”
Yellow dots = Operational CCAs; green dots = CCAs launched in 2017; blue dots = CCAs in process or being explored | California PUC
The proposal modifies the timelines for the creation of CCAs so that they are coordinated with the annual CPUC and CAISO resource adequacy and reliability programs. It would require CCAs to submit to a process that includes a timeline for submission of implementation plans; a ‘meet and confer’ requirement between the CCA and the incumbent utility that can be triggered by either; a registration packet including a CCA’s service agreement and bond; and a commission-authorized date to begin service.
It also calls for “universal access” to CCAs, equitable treatment of all customers and compliance with state laws regarding aggregated service. All prospective and expanding CCAs would be subject to the requirements for implementation plans received after Dec. 8, 2017.
CCAs are growing rapidly, creating some controversy over the stranded costs for regular utility customers. California legislators expressed surprise last summer when they were told that utility customers will be on the hook for hundreds of millions of dollars in long-term energy contracts procured by investor-owned utilities for customers who have departed for CCAs. (See California CCAs Spur Worry of Regulatory Crisis.)
The idea has been embraced by cities surrounding the San Francisco Bay Area that promote CCAs as “green” electricity programs. It was municipalities in the San Francisco and Los Angeles areas that lobbied for CCAs in response to a failed deregulation effort that in part caused the Western Energy Crisis of 2000/01. AB 117, enacted in 2002, allows local governments to form CCAs by aggregating retail customers and securing electricity supply contracts to serve them. CCAs also exist in Ohio, New York, Massachusetts, New Jersey, Rhode Island and Illinois.
Pacific Gas and Electric, which has opposed CCAs, argued to state lawmakers in August that about $180 million has been shifted from CCA customers to IOU customers — an amount it said will grow to $500 million by 2020.
California CCAs include Apple Valley Choice Energy, CleanPower San Francisco, Lancaster Choice Energy, Marin Clean Energy, Peninsula Clean Energy in San Mateo County, Redwood Coast Energy Authority, Silicon Valley Clean Energy and Sonoma Clean Power.
WASHINGTON — A panel on investing in grid innovation and clean energy infrastructure last week gave Congress low marks and said emerging economies are proving quicker to adopt some technologies. But speakers at the GridWise Alliance’s GridCONNEXT conference said they are bullish on the future.
David Yeh, a White House adviser during the Obama administration who is now managing director of Capitol Hill, an advisory firm for high net worth individuals, global asset managers and start-ups, said he is not overly concerned with the Base Erosion Anti-Abuse Tax (BEAT) provision in the tax bill passed by the Senate earlier this month. Some renewable advocates fear the language, which is intended to prevent multinational corporations from moving profits and jobs out of the U.S., will reduce the value of wind and solar tax credits.
“Right now clean energy, especially at the utility scale, is competitive, if not cheaper than, fossil fuel energy. So, you can talk about regulation; you can talk about policy. But economics will trump all of that.
“This year, clean energy funds raised about $5 billion, while fossil fuels have raised about $2 billion. That’s showing what the demands are from the … capital providers [and allocators] of this world. … These are sovereign wealth funds; these are pensions; these are large, super high net worth families. … This is how the capital markets — and these are capital markets that start with a ‘T’ — trillions — view clean energy infrastructure. When they move their allocation from 1% to 5%, that’s a game changer. And they’re moving towards that.”
Nancy Pfund, founder and managing partner of DBL Partners, predicted that there will be few gas-fired peaking plants built in California in the future.
“They’re expensive. People don’t like them. They’re [crude] compared to solar and storage or wind or demand response or any combination. That’s an example that you have to let go of what the 20th century was all about. This is really different and if you stand in the way … of consumers who want their solar or want batteries, they are going to run you over.”
An ‘F’ for Policymakers
Policymakers in D.C. haven’t heard that message, however, she said, as reflected in “the $4 billion worth of annual subsidies that the fossil industry gets.”
“If the people on Capitol Hill were in a public policy class or business school course, they would get an ‘F’ because [they are subsidizing] an industry that’s 100 years old. I think anyone in our [clean energy] industry would say we would love a level playing field. Get rid of all incentives. But it’s kind of a ‘David and Goliath’ story at this point.”
Puon Penn, executive vice president and head of technology capital for Wells Fargo, said investors would be wise to look past the U.S. to China and other growing economies that have committed to abandoning the internal combustion engine in favor of electric vehicles.
“Do you think the [original equipment manufacturers] … the Fords and the GMs are looking at the United States as their primary market today? They sell more vehicles in China. And if you’ve got to make electric vehicles for the Chinese market, you’re damn well not going to make a bunch of internal combustion vehicles for the United States. You’re just going to build one platform that you’re going to distribute across the planet. It’s inevitable. But people are still behaving like we’re still [the] Jolly Green Giant walking the earth and determining the order of things. We’re not anymore.”
Penn said new technologies are allowing greater capacity utilization in the electric industry than in the past. “There’s no other industries where you have high [capital expenditures] and such low capacity utilization,” he said. “Today we do have the wherewithal to increase capacity utilization and therefore benefit the entire economy.”
WASHINGTON — Speakers at the GridWise Alliance’s GridCONNEXT conference last week left no doubt: Electric storage is long past the “tipping point.”
Moderator Ram Sastry, vice president of infrastructure and business continuity for American Electric Power, had posed the question: “Are we going to see large-scale deployment of energy storage systems? And if not, what’s stopping that?”
“I think we’re at or past that tipping point,” responded Andy Marshall, practice director for distributed energy resource management at Landis & Gyr. “I think you see the flexibility of storage and its ability to get deployed relatively quickly. You have not only the stuff that’s going on down in Australia, but you also have the things that are happening most recently in California.”
On Dec. 1 — the first day of summer for Australia — Tesla turned on a 129-MWh lithium ion battery, the world’s largest, to help the nation’s fragile electric grid. California deployed 100 MW of storage in just six months in response to natural gas constraints following the Aliso Canyon leak.
Praveen Kathpal, vice president of AES Energy Storage, said “the technology is mature,” noting that his company entered the business a decade ago. AES claims 500 MW of storage already deployed or in development.
“There haven’t been any components that needed to be invented for any of the deployments that we’ve done, because they’re all based on lithium ion battery technology, which was commercialized 25 years ago and has benefited from its use in the consumer electronics and transportation sector,” Kathpal said.
“The tipping point we see in storage is really meshing with some of the other megatrends facing our industry right now. We have the accelerated growth in renewables, and we also have the electrification of more sectors including transportation.”
Kathpal predicted new storage technologies will break below the current pricing floor for lithium ion. “So, 10 years from now, do I think we’ll have a commercially available storage technology that’s below $100/kWh? Sure. And that’s exactly why at AES the technology platform we’ve developed is forward compatible with technology change.”
“I think you could argue that the tipping point was several years ago when big PJM systems started to come online,” said Luke Witmer, lead research engineer for Wärtsilä’s Greensmith Energy. “More and more markets continue to value the fast-ramping and bidirectional capability that energy storage provides. And I think as … systems continue to decline in cost, we will compete in more and more markets. A lot of the market prices basically clear according to the natural gas price. … So it’s really just a matter of getting renewables plus storage to below that threshold in more and more places.”
Richard Brody, director of sales and marketing for Lockheed Martin Energy’s energy storage unit, said storage is still relatively expensive when compared with energy efficiency and demand response.
“Whether we’re talking about a C&I customer or a distribution utility, when we come look at an energy problem, we look not just at storage, but we start with efficiency, permanent load reduction, load control, demand response, demand management, grid analytics — all the tools you can bring to solve an energy problem. … We tend to look at other things first because storage — despite the declining costs — remains the most expensive way to address these problems.”
But he is nevertheless bullish on storage. “In terms of the tipping point — oh yeah, we’re passed it. This is a rapidly growing market.
“We’re seeing very strong growth in interest in doing large solar and wind coupled with storage. Most of the large developers we’re working with aren’t contemplating any large development of solar — and increasingly wind — without some way to firm it up with a fairly significant storage system.”
Brody said the demands are exceeding the four-hour maximum life for lithium ion batteries. “We’re looking at much more ambitious efforts that would require the attributes of a flow battery, which is a minimum of six to 12 hours of energy.”
A Sierra Club report released last week that said captive customers of SPP utilities are paying for uneconomical coal plants has drawn considerable pushback from the RTO and some of its members.
But the head of SPP’s Market Monitoring Unit (MMU) says the environmental group has a point in its criticism of utilities that self-commit coal generators when the RTO’s market prices don’t cover their operating costs.
When a utility self-commits a unit, it operates the plant regardless of whether SPP’s market clearing prices are sufficient to cover the plant’s marginal costs. Although self-committed units are ineligible to receive make-whole payments from SPP, the Sierra Club says, some units are apparently recovering losses from captive customers through state ratemaking proceedings.
The Sierra Club report, “Backdoor Subsidies for Coal in the Southwest Power Pool,” alleges that utilities in the footprint operate coal plants outside the wholesale markets, generating $300 million in excess costs that consumers were forced to pick up in 2015 and 2016.
SPP and its members responded by saying the Sierra Club’s analysis relied heavily on wholesale rates, which aren’t the same as retail rates that are subject to public policy and regulations. Nor do wholesale rates consider the cost of long-term supply contracts or ensuring grid reliability, they said.
Keith Collins, executive director of the MMU, says that while the report took some of the MMU’s observations out of context, self-commitment is a problem in the RTO’s markets. MMU staff raised the issue in their 2016 State of the Market report, which Collins reviewed with SPP’s Board of Directors and Members Committee in July.
The Sierra Club said it conducted a “high-resolution analysis” of 14 coal plants in SPP’s footprint. It used hourly market data to develop each plant’s cash flow analysis.
“All 14 units operated for extended periods of time when, objectively, it would have been less expensive for the electric bills of utility customers for the plants to sit idle,” the group’s report said. “The utilities that own each of the 14 coal units we examined would have saved its customers money if the coal units had operated less often.”
The report said all but one of the 14 units studied were owned by state-regulated utilities, municipal utilities or an electric cooperative with captive customers.
Utilities should be purchasing electricity for its captive customers in the SPP Integrated Marketplace (IM), the report said. But it said some utilities “appear to be going back to state commissions and using rate cases and other dockets to obtain ratepayer-funded subsidies for costs incurred in operating otherwise uneconomic coal plants.”
“In the SPP market, where nearly half of the resources are self-committing, how much of an energy market can SPP really be claiming to operate?” the report asked. “The consequence of these facts is that the SPP Integrated Market is possibly a market in name only. The impact of utility self-commit and underbidding energy offers within the SPP IM might be the most anticompetitive and anti-consumer behavior in any integrated electricity market anywhere in North America.”
The report also says self-committed coal units are denying revenues to independent merchant generators. “RTOs are supposed to create nondiscriminatory rates, but allowing coal units to self-commit discriminates against those operators that don’t have captive customers to fund a ratepayer subsidy. Moreover, it is discriminatory and unreasonable for the market to ask one subset of customers to pay above-market costs while all other customers pay market costs.”
Collins told the board and members that self-commitment of resources has declined but is “still very big.”
“When resources are self-committing, it can put downward pressure on prices also,” he said at the time, referring to the effects of incorporating uneconomic resources in wholesale prices.
“The point of the [Sierra Club’s] report is consistent with what we noted in the 2016 annual report,” Collins told RTO Insider. “Self-commitment can distort the market. It’s a message we’ve been presenting as well.”
The MMU report noted generation offers in the day-ahead market averaged 48% as “market” commitments and 35% for “self-commit” in 2016. Those numbers were 46% and 39%, respectively, in 2015. Outages accounted for the remainder.
The Sierra Club report quoted the MMU report, which said plants self-commit because of contract terms, low gas prices “that reduce the opportunity for coal units to be economically cleared in the day-ahead market,” long start-up times, and “a risk-averse business practice approach.”
Collins took exception to the Sierra Club’s claim that “reliability isn’t one” of the reasons why a unit might self-commit.
Although the MMU’s report didn’t cite reliability, Collins said, “reliability could play a factor where some of these resources self-commit. Our report identified a set of reasons for self-committing, rather than a complete list.
“We have been discussing this essentially since I’ve been here,” said Collins, a former FERC staffer who joined SPP in June from CAISO. “What are the factors [behind self-commitment]? What can we do to promote more market commitment? Some of it is education and creating awareness. At least there’s a dialogue there that’s begun.”
SPP Disagrees
SPP General Counsel Paul Suskie said in a statement that the RTO disagreed with the report’s fundamental assertion that “utilities’ option to either self-commit resources or purchase from the market equates to a subsidy and undermines the effectiveness and cost-efficiency of SPP’s Integrated Marketplace.”
Suskie said that “assessing the market’s fairness and effectiveness based on wholesale cost of electricity to consumers does not take into consideration a number of factors that may lead utilities to self-commit.” He listed contractual obligations, capital investments, public policy and fossil fuels’ contribution to renewable resources’ deliverability as among those factors.
“Our day-ahead market has functioned successfully for four years and, in that time, has reduced the cost of energy in our region by more than $1.25 billion while continuing to ensure the reliability of the grid,” Suskie said.
Peter Main, a spokesman for SPP member Southwestern Electric Power Co., said the company bids its generation into the RTO’s markets under its market protocols and will continue “to seek opportunities” to produce net energy revenues benefiting its customers.
“The Sierra Club report does not provide an accurate portrayal of the incremental (variable) costs and revenues associated with offering generation into the SPP Integrated Marketplace,” Main said in a statement.
Plant Operators Dispute Findings
According to the report, SWEPCO’s Dolet Hills and Pirkey plants in the East Texas-Louisiana region burdened customers with $210 million in costs in 2015 and 2016. However, SPP said the plants serve load in “locations in northeast Texas without significant wind.”
Oklahoma Gas and Electric, which owns two of the plants identified in the study, has said the units stopped self-committing into the market more than two years ago. Two other generators — Entergy-owned or co-owned plants in Arkansas — serve load in MISO.
Al Armendariz, with the Sierra Club’s Lone Star chapter, said he was confident the group has a “good handle on the cost to run these coal plants in SPP.”
Armendariz, who worked in EPA under President Barack Obama, said the Sierra Club compared the SPP LMPs paid to power plants in the immediate vicinity of the coal plants studied. The organization obtained operating data from S&P Global Market Intelligence, the U.S. Energy Information Administration and SPP in running its analysis.
“Our report is really a comparison of the revenue for electricity, compared to what it costs to actually run the power plant,” Armendariz said.
Rule Changes Sought
The Sierra Club would like to see several things happen, Armendariz said. “We think SPP should clarify its rules to require power plants to bid in their real cost of fuel and other variable [operations and maintenance] … in the day-ahead market.”
Armendariz also said the Sierra Club would like to see state commissions in SPP’s footprint “investigate this problem of self-commitment and disallow the recovery of costs borne by consumers when uncompetitive coal plants are operating.”
“Vertically integrated utilities should not be forcing their customers to pay the variable costs,” he said. “State commissions should not allow the recovery of those costs through the rate base.”
Asked whether the group planned to file a complaint with FERC, Armendariz told RTO Insider that the Sierra Club “is evaluating all avenues of legal recourse that may be available to rectify the problems.”
Both Armendariz and Collins agreed the problem of self-commitment is not unique to SPP. Collins said he saw self-dispatch at CAISO and “knows” it occurs in other markets. Armendariz said although uncompetitive coal plants are running in “virtually every market … the problem seems most acute in SPP.”
The MMU believes that will change as market participants continue to familiarize themselves with SPP’s day-ahead and real-time markets, which have been in operation for less than four years.
“It appears that resource owners are becoming more confident in the market and allowing the market to commit the resource instead of self-committing their resource,” the State of the Market report said.
The Monitor also said the market systems’ optimization algorithm is restricted to a 48-hour window. “Hence, large baseload resources with long-lead time and substantial start-up costs may not appear economic to the day-ahead market commitment algorithm,” the report said.
Collins said SPP’s Market Working Group has discussed a potential multiday optimization approach. A Tariff change has yet to materialize, he said, “but that could help address some of the concerns.”
WASHINGTON — Almost 190 investors, utility officials, technology company executives and others gathered for the GridWise Alliance’s two-day GridCONNEXT conference last week. Here’s some of what we heard.
FERC Enforcement, Tx Investment, Cybersecurity
Former FERC Commissioner Philip Moeller, a Republican, and Spencer Gray, a Democratic aide on the Senate Energy and Natural Resources Committee, talked about the newly reconstituted commission, transmission investment and the limited prospects for bipartisan action in Congress.
“We are at a low ebb in bipartisan relations,” Gray said.
But he said there was one exception. “I think there’s broad bipartisan consensus in the Senate to … focus more funds on cyber[security],” Gray said. “We’ve gotten [feedback] from a lot of groups in recent years that the federal government should have a more robust R&D program to develop new cyber tools and understanding of emerging cyber threats. That just seems like the lowest hanging fruit to me. It’s not a partisan issue at all.”
Moeller, who oversees the Edison Electric Institute’s business operations group and regulatory affairs, said the industry is “actually doing a very good job” on cybersecurity through the Electricity Subsector Coordinating Council. “But I’m not sure as an industry we necessarily tell our story well, partly because of the sensitivity” of the subject matter.
Moeller lamented the court rulings that rejected FERC’s “backstop” transmission siting authority in the 2005 Energy Policy Act. But he acknowledged the commission’s efforts to encourage transmission investment haven’t always been helpful.
“Our feeling is that the capital is out there but perhaps some of the [investment] signals need to be clarified. Whether it’s the [return on equity] mess at FERC, which I helped create unintentionally. But in trying to solve a problem, we’ve probably made it a little bit worse. I think there’s some uncertainty on the future of Order 1000. And it took a while I think for people to, like it or not, have the Clean Power Plan more in the rear-view mirror before they could focus on the expansion of the transmission grid.”
On Wednesday, EEI released a report suggesting changes to FERC’s ROE calculations that ClearView Energy Partners said could increase the model’s results by approximately 50 basis points.
Gray said Sen. Maria Cantwell (D-Wash.), ranking member of the ENR Committee, will be watching “what happens under the new leadership of FERC to the Enforcement office.” In response to the abuses that contributed to the 2000-2001 Western Energy Crisis, Cantwell helped draft language in the 2005 Energy Policy Act that gave the commission increased authority over market manipulation.
Scott Prochazka, CEO of CenterPoint Energy and chairman of the GridWise Alliance, said Hurricane Harvey — “our third 500-year storm in two and a half years” — proved the “incredible” value of mobile substations. The company also is likely to add airboats and trucks able to drive through high water, he said. (See Weeks Later, Utility Officials Still Awed by Scale of Hurricane Harvey.)
Robert Schimmenti, senior vice president of electric operations for Consolidated Edison, recalled how the utility was “humbled” by the 14-foot storm surge that drenched parts of Brooklyn and Lower Manhattan during Superstorm Sandy in 2012.
“All the weather predictions were around 12 feet. We did all the math and all the projections, and we thought we were good for about a 12-and-a-half-foot storm surge. It was only until a bunch of bright engineers linked the buoy data in the East River to a map of storm projections that they created — and this is well before high tide — and as they created these projections, we were like ‘Hey, wait a second. This doesn’t look good.’”
More than 1 million Con Ed customers in New York City and Westchester County lost power during the storm. The company has spent $847 million to make its system more resilient, including the addition of “smart switches” to isolate and clear trouble on lines, flood gates, pumps and 3 miles of flood walls around critical equipment.
Hurricane Maria took down “only” 220 230-kV towers in Puerto Rico, said Bruce Walker, assistant secretary for the Department of Energy’s Office of Electricity Delivery and Energy Reliability. But replacing each tower is a five- to seven-day project requiring ferrying of workers and equipment by helicopter, Walker said.
“One of the things that was striking to me regarding their system is their transmission lines; while very well built, [they’re] built right through the mountains. There are no rights of way; there are no roads. There is no tree clearing in those areas.”
Praveen Kathpal, vice president of AES Energy Storage, said his company recently outlined for the Puerto Rico Energy Commission “a vision of how 10 GW of solar plus 2.5 GW of storage, arranged in essentially sectionalized grids across the island, could provide both resilience and lower costs, because those [investments] break even with how much Puerto Rico would spend on burning oil for power generation over the next 10 years.”
Kathpal said AES’ 10-MW battery installations in the Dominican Republic “rode through all the grid disturbances of Hurricanes Irma and Maria” despite damage to transmission lines and generation outages. “A battery installation is physically resilient. It’s not as subject to the factors that during an intense storm would cause other resources to disconnect. So even as 40 to 60% of the generation in the Dominican Republic tripped off, the batteries continued to operate. And as you can imagine with those kinds of generation trips, the frequency was flopping all over the place. So they actually did more work to restabilize the system.”
