CAISO day-ahead prices hit all-time highs for the second time this year during the third quarter, and the frequency of price spikes in the 15-minute and five-minute markets increased, the ISO’s Department of Market Monitoring said in its quarterly market performance report.
| CAISO
High temperatures in California drove up demand at the beginning and end of August and into September, according to the report. Load peaked at 50,116 MW on Sept. 1, just short of the 50,270-MW peak record set in July 2006. Trading that day also saw day-ahead system marginal prices soar over $200/MWh during a four-hour period and hit $770/MWh in one interval.
| CAISO
“These outcomes were primarily driven by tight supply conditions as a result of a number of factors in combination with high demand while a significant amount of solar production is ramping down during sunset hours,” the report said. Average 15-minute market prices increased during every month of the third quarter from about $34/MWh in June to more than $45/MWh in September because of higher temperatures and loads.
The Monitor also confirmed that software problems had caused day-ahead prices to hit record highs in the second quarter even after being mitigated. In its second-quarter report, the department had noted that prices should not rise after mitigation and said it was investigating the cause. (See Monitor: CAISO Q2 Prices Hit Record Despite Mitigation.) The third-quarter report said the error was fixed on July 22.
“The ISO has determined that a software error introduced in 2016 resulted in infeasible energy and ancillary service awards for resources in the market power mitigation run but not the binding market run in the day-ahead market,” the Monitor said in the third-quarter report. “The software error resulted in an erroneous increase in supply available in the market power mitigation run, causing prices in that run to be lower than they would have been had all awarded schedules been feasible.”
CAISO is “currently evaluating the impact of this error on the market power mitigation process on affected days,” the report said.
Day-ahead prices appeared to be competitive in most hours, the Monitor said, and total year-to-date wholesale energy costs are close to 2016 totals, after the prices are adjusted for natural gas and greenhouse gas prices. Higher gas prices resulted in larger overall energy costs for 2017.
Transmission congestion was low in the day-ahead market in the Pacific Gas and Electric and Southern California Edison service areas but caused prices to drop about 2% in San Diego Gas & Electric’s area. Congestion in the 15-minute market pushed up prices in PG&E and SCE and decreased SDG&E prices. Frequent congestion on the Doublet Tap-Friars 138-kV constraint created an export-constrained area, undercutting prices in San Diego.
The Monitor said its analysis of natural gas price volatility shows a limited need for increased bidding flexibility created by raising commitment cost and default energy bid caps. CAISO followed the department’s recommendation and reduced the Aliso Canyon real-time gas scalars to zero beginning Aug. 1, raising them again temporarily Aug. 4-7 because of hot conditions.
Congestion revenue rights auctions took in $9 million less than payments to entities purchasing those rights, increasing year-to-date ratepayer losses to $38 million and to more than $680 million since the market began in 2009. The Monitor for more than a year has been calling for CAISO to eliminate CRR auctions. (See CAISO Monitor Proposes End to Revenue Rights Auction.)
The Monitor will discuss the third-quarter report with market participants during a Dec. 20 conference call.
A Nuclear Regulatory Commission official said Tuesday that a team of the federal agency’s reactor safety engineers would likely recommend that the commission continue working on replacing a portion of its inspections with a self-assessment regime for operators of commercial nuclear power plants.
Tony Gody, NRC director of reactor safety in Region II (Southeast), said Dec. 12 that “the working group agrees that self-assessment, if implemented properly, can be very effective in finding latent conditions” and probably will be recommending further exploration of how to get there via a pilot program.
| NRC
Gody made his remarks at the end of the agency’s second public hearing in two months on the use of licensee self-assessments in the NRC engineering inspection program and other changes in the reactor oversight process.
The Director of the Office of Nuclear Reactor Regulation formed the working group in February 2017 to review the commission’s engineering inspections that verify the adequacy of facility design, operations and testing, and make recommendations on improving both their effectiveness and efficiency. The commission has a webpage with related documents, including public comment.
The Good and the Bad
“We need to collectively as an industry own our own licensing design basis and regulatory performance,” said Greg Halnon, vice president for regulatory affairs at FirstEnergy, which owns two nuclear power plants in Ohio and one in Pennsylvania. The plants are the Davis-Besse plant in Oak Harbor, Ohio, the Perry plant in Perry, Ohio, and the two-unit Beaver Valley plant in Shippingport, Pa., which collectively generate 4,000 MW.
“We’re not abdicating our responsibility; we’re maintaining and owning that licensing basis,” Halnon said.
Dave Lochbaum, director of the Nuclear Safety Project for the Union of Concerned Scientists, said the 17 years of the reactor oversight process “have resulted in safety improvements, there’s no doubt about that, but achieving success loses value if backsliding occurs. … Our concern is, some of the measures being contemplated are banking on that success at risk of undermining it.”
NRC Inspectors: (L-R) NRC inspectors Robert Krsek, Annie Kammerer and Steve Campbell check emergency diesel generators at the Kewaunee nuclear power plant in Carlton, Wisconsin in 2012, one year before the plant closed | NRC
Gody said that if whoever is doing an inspection or a self-assessment applies scientific principles, “it’s going to be a good inspection or self-assessment. And the fact that your own folks are already so familiar with your procedures, and the fact that your own folks already have computer accounts, already know the processes at the facility, already know the licensing basis, is a good thing and a bad thing.”
The good thing is they’ll be more efficient, he said.
“The bad thing is they may have preconceived conclusions,” Gody said. “It’s critical that when that checklist is developed that critical thinking is considered. If you accomplish that one thing, you potentially eliminate the human factor disposition to not challenge your own conclusions.”
Lochbaum said he wanted to push back on the “fanciful notion that there aren’t any more legacy, latent issues out there. There seem to be plenty of latent issues from long ago that we still haven’t found. Fort Calhoun [in Nebraska] is a perfect example, which shut down in 2011 and didn’t restart for 30 months. During that time, they submitted something like 18 LERs [licensee event reports], with the youngest of those being 15 years earlier, so they were at least 15 years old. Several of those involved engineering issues.”
Getting to the point of metrics, Lochbaum said “we recommended before and recommend again that the NRC should have looked at those LERs to see if the expectations were that the engineering inspections should have or may have identified those before they were found during an extended plant shutdown.”
NEI Supports
The Nuclear Energy Institute supports self-assessments, saying plant operators already do their own inspections in advance of NRC visits. “We believe that licensee self-assessments could be an important part of a modernized approach to engineering inspections. Such a solution would be rooted in our cultural value of self-identifying issues,” Greg Cameron, NEI’s senior project manager for regulatory affairs, wrote the commission in July. “We hold ourselves accountable to identify conditions at our stations early and to resolve them in a timely fashion commensurate with their safety significance; the NRC verifies that accountability through regular resident inspector interactions and the biennial Problem Identification and Resolution inspection. Transitioning from direct inspection to oversight of self-assessment activities, where appropriate, strengthens this accountability.”
Concerns in Mass.
But the self-assessment concept is unpopular with some neighbors of Entergy’s Pilgrim nuclear plant in Massachusetts, one of three plants in the country classified in Column 4 — the worst performers in NRC’s grading system.
A citizens group, Pilgrim Watch, cited an email written by the leader of a federal inspection team, who wrote that “the plant seems overwhelmed just trying to run the station.” The internal email became public mistakenly.
“Pilgrim provides the perfect example why NRC nuclear safety inspections are necessary and why industry self-assessments would be dangerous,” the group wrote NRC. “Pilgrim cannot be counted on to conduct any complete or accurate self-assessment. The NRC’s own records prove that Pilgrim has regularly and consistently failed to follow established procedures, to report problems, or to take corrective actions even when the NRC tells it to do so.”
ALBANY, N.Y. — When pricing carbon into the wholesale electricity markets, remember to keep it simple.
Also: avoid unintentional emissions increases, mind the transmission needed, incent new renewable resources, abate emissions efficiently without hurting consumers, allocate revenues fairly, and leave the legal hassles for the due processes of regulators and NYISO.
Those were some of the stakeholder comments Monday at the first technical conference of the Integrating Public Policy Task Force (IPPTF), which was established in October by NYISO and the state’s Public Service Commission to explore the carbon pricing issue as laid out in a Brattle Group report.
Paul Hibbard of The Analysis Group facilitated two roundtable discussions, each with 23 stakeholders. The morning session addressed border adjustment mechanisms to prevent “carbon leakage,” a parallel increase in emissions in regions neighboring New York.
“You don’t have to have the absolute perfect solution to leakage to go forward,” said Mark Reeder, an economist who represents the Alliance for Clean Energy New York at NYISO. “You just need to get most of the way there. Say if you can knock out 80 to 85% of the leakage problems at a $40 carbon price, you bring it down in essence to the latest we have now with a fairly small [Regional Greenhouse Gas Initiative] price and you’ve done the job.”
In looking at leakage issues in RGGI states and California, Reeder said “the unit-specific approach and the resource shuffling is a real bad idea and does create a lot of problems. The example here is that a nuclear plant in Pennsylvania that’s just selling spot-in in Pennsylvania could sign a contract to sell it to New York, and if New York declares that clean, we could work on that later, but it doesn’t work.”
Resource shuffling refers to the practice of utilities scheduling their lowest-emission generators to serve areas with emissions caps, while letting heavier polluters simultaneously serve customers in other regions.
“It’s important to move forward with carbon pricing principles and not use leakage as a way to delay,” said Gavin Donohue, president of the Independent Power Producers of New York. “We don’t need to reinvent the wheel.”
“You really get different answers depending on how you think about the question,” said David Clarke of the Long Island Power Authority. “For example, if you have a uniform carbon tax on all sectors, you’d be thinking about offsets; you think about where are the places where folks can make the investments that have the largest carbon reduction at the lowest cost.”
Baseline Leakage
“When you’ve got regions surrounding New York with such a wide range of marginal emissions rates, to start with a broad-brush approach, applying the New York rate to all of them will have pretty obvious unintended consequences,” said Stephen Molodetz, vice president of Hydro-Quebec. “Quebec is zero or near zero and Ontario is close to that; then you’ve got PJM, which is a higher emitter than New York.”
Don Tretheway, CAISO senior adviser for market design and regulatory policy, said some power producers outside the ISO have a resource portfolio with a significantly lower emissions profile than the default emissions rate for their region. In those cases, the ISO wants to give them the benefit of having cleaner resources.
“That’s relatively straightforward to implement from a market standpoint,” Tretheway said. “We can have each of the individual resources put their estimate of carbon compliance costs into their energy bids and we can dispatch away and everything works.”
Tretheway noted how the roll-out of the Western Energy Imbalance Market (EIM) further complicated CAISO’s treatment of greenhouse gas costs.
“The complexity CAISO introduced with the Energy Imbalance Market is that, not only did we need to solve to meet load in California that has a [greenhouse gas] program, but we had to actually solve to meet load in other states that don’t, and that’s where we had to separate those greenhouse gas costs into separate bids,” Tretheway said.
Mark Younger of Hudson Energy Economics said “what California is doing now is probably a mistake. [New York] should have a very high bar on resource-specific carbon pricing. Just because you can contract with what is nominally a clean resource, doesn’t mean that you in any way affected what the emissions were in the neighboring area other than by the fact that there was a bigger import to New York, regardless of resource.”
Allocating Carbon Revenue
The afternoon roundtable discussed how — and whether — New York would allocate revenues collected from a carbon pricing scheme.
NYISO Executive Vice President Rich Dewey said, “We’re conflating a couple issues here. First and foremost, we need to decide if there’s going to be a fund. When I think about how the NYISO settlements process works today, that revenue amount only exists for the microsecond it takes to do the calculation in the settlement itself, so there is no actual fund.
“At NYISO we’re not setting the policy, we’re administering the market,” he continued. “Be that as it may, you may have the desire, for the greater good, to create a fund in some capacity. Then we have to decide where is that fund.”
Miles Farmer of the Natural Resources Defense Council said that if the PSC determines what load-serving entities must do with carbon revenues, “that’s bounded under the legal constraints of PSC ratemaking, and you can’t have just general slush funds of money the way that it happens with RGGI.”
NYISO Senior Manager for Market Design Michael DeSocio said that when considering a carbon revenue fund, “we haven’t actually talked about what does the rate look like. And there are components of the rate that go into various funds already — a congestion rent fund, there’s a loss fund — all of that money is already allocated in some way based on various other markets. We want to do this in a way that doesn’t unnecessarily increase the cost to customers.”
Kelli Joseph, NRG Energy’s director of market and regulatory affairs, said that making carbon pricing sustainable requires considering how RGGI moneys have been used for energy efficiency and incenting renewables in to help reduce greenhouse gases.
“The [Brattle] report assumes a certain marginal emissions rate that may not be true over time,” Joseph said. “Over time, those marginal emission rates are going to decrease and there’s probably not going to be anything left to refund because there’s not going to be a lot of carbon-emitting resources on the system.”
Scott Weiner, Department of Public Service deputy for markets and innovation, cautioned roundtable participants about getting caught up in the legal details so early in the planning process.
“It’s going to be a collaborative effort and will be vetted legally,” Weiner said. “We will subject everything to the governance processes of NYISO, so there are a lot of legal issues, and in the absence of specific facts … I urge you to leave the legal discussion to another day.”
Task force co-chair Nicole Bouchez, a NYISO market design economist, said they had decided to cancel the Dec. 18 task force meeting and will next meet on Jan. 8, 2018.
CARMEL, Ind. — While MISO sector representatives express uncertainty about the next stage in the evolution of the grid, they do think it will involve energy storage, distributed resources and heightened security measures.
But they’re hesitant to speculate about the size of future investments driven by the developments.
MISO Executive Director of Strategy Scott Wright last week said the RTO believes the grid is facing its biggest change “perhaps in a hundred years.” It envisions the grid becoming a two-way delivery system and generation becoming more distributed and intermittent, he said during a MISO “hot topic” discussion on the grid’s future during a Dec. 6 Advisory Committee meeting.
Staying ‘Happy’
Discussion facilitator Julia Johnson, president of regulatory advising firm Net Communications, opened the discussion with positivity, playing Pharrell Williams’ “Happy” music video and displaying screenshots featuring people dancing with transmission lines in the background.
MISO’s Advisory Committee members generally agreed that low bills are keeping customers content for now, but a changing resource mix will mean future grid investment. No stakeholders, however, are comfortable yet in guessing the cost or predicting what technology advances will reign.
“Consumers are happy because their electric bills are the lowest percentage of their income, I think, ever,” said Arkansas Public Service Commission Chair Ted Thomas. But he cautioned that consumers’ preference for renewables isn’t static in the market. “If you double electric bills and double unemployment, the number of customers willing to pay more for sustainability drops.”
Alcoa’s DeWayne Todd, representing MISO’s Eligible End Use Customers sector, said customers are generally happy and are demanding renewables for future pricing certainty and independence. However, while energy costs have decreased, the costs of transmission have “almost doubled.”
“I’ve seen my transmission percentage go from a whopping 7% to a whopping 10%,” said Wind on the Wires’ Beth Soholt of MISO’s Environmental sector. “What benefits does the grid provide to me? We need to make it clearer to our customers. I think the grid is the enabler of all of these choices and options. … I think there’s a misnomer that if you have the grid, you can’t do distributed energy options. The grid is the enabler; it ties it all together.”
‘FOG’
MISO’s Competitive Transmission Developers sector agreed that the ability of the transmission system to deliver will only become more important as customers use more types of generation. In written comments, the group warned that the energy industry may be undervaluing transmission: “Today … the transmission grid often goes unrecognized in planning and policy decision-making. This increases the risk of costly future outcomes, driven by repeated ‘just-in-time’ incremental grid investments.”
Northern Indiana Public Service Co.’s Paul Kelly said that while distribution-level changes are rapidly evolving, MISO has time to plan changes to the transmission system. He said NIPSCO is now training employees to be aware that generation installed at the distribution level may be live and not simply there for back-up purposes — a sign of the times.
“Making big bets right now about what the grid is going to look like is extremely fraught with risk,” Entergy’s Matt Brown said. “There’s definitely a balance to be struck between big-goal visions with big-goal price tags and making sure that our customers are served at the lowest reasonable cost.
“We need to realize that everyone at this table is thinking something that will prove to be wrong,” he added.
Dynegy’s Mark Volpe pointed out that, two years ago, MISO held a hot topic discussion in which members were certain the Clean Power Plan was going to become the law of the land. “None of us really know what the grid is going to look like. When you look at the phrase ‘future of the grid,’ if you shorten that up a bit and ignore the ‘the,’ you have ‘FOG.’”
Soholt also cautioned about the “cost of inaction,” where generation and transmission developers, after not adopting new technologies, will be faced with obsolescence or hurried investments.
Avangrid Renewables’ Adam Sokolski, of the Independent Power Producers sector, said MISO should look to its own interconnection queue to gauge future grid trends. “The queue is really the barometer of the grid.”
MISO’s queue currently contains about 60 GW of proposed generation, which includes about 30 GW of wind, 15 GW of solar, 12 GW of natural gas and 600 MW of other resources. The queue also holds about 140 MW of prospective battery storage capacity.
Predictions and Suggestions
The Environmental, Public Consumer Advocates and End Use Customers sectors, and sole Coordinating Member Manitoba Hydro, all predicted future penetration of clean energy, storage, distributed resources, demand-side management, home automation gadgets and energy efficiency.
End Use Customers expect that the growing prominence of demand management, self-generation, energy storage and a focus on environmental sustainability will afford customers “more independence from the utility.” Manitoba Hydro predicted use of coal will continue to decline “despite efforts to maintain its historical importance” and said state-originated carbon pricing may be enacted. The Consumer Advocates sector said it’s expecting microgrids and AC-DC transmission lines. The Transmission Owners sector said saturation of distributed resources will not be consistent across the footprint, grouped instead in states with distributed energy resource-friendly policies and incentives.
IPPs called for more customized interconnection procedures for a more diverse assortment of generation types. “MISO should be prepared to offer tailored interconnection processes based on operating parameters such as DER capability to inject energy onto the system vs. service limited to on-site only,” the sector wrote.
The one-in-10 planning standard may become obsolete as the grid and new technology accommodate a variety of energy resources that deliver energy on different schedules, Brown said. He contended that the most challenging circumstances may become a certain time of day rather than the hottest week of the summer.
“Maybe we’ll no longer plan for that one hour of that one day in August,” Brown said.
Manitoba Hydro predicted increasingly severe weather disturbances impacting the grid as well as increasingly critical cyber threats. TOs also expect security issues to increase as smart devices connect to the grid.
The Environmental sector said MISO could monitor grid reliability by using dynamic and predictive transmission line ratings, where operators see real-time data on line ratings. The sector also asked MISO to consider “the diversity exchange that could be gained” by developing transmission that connects MISO Midwest to MISO South, which would allow “MISO South states to have enhanced opportunities for economic development of new generation resources.”
NIPSCO’s Kelly pointed to Amazon’s parade of products, with some enjoying success while others have flopped, suggesting that experimental grid investment could follow a similar boom-and-bust pattern.
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.
