CAISO is seeking stakeholder input on how to respond to a solar eclipse that will significantly curtail output from California’s growing solar generation portfolio next August.
“It will not be a total eclipse [in California], but it will affect what solar production we have in California,” Jim Blatchford, an ISO senior advisor for short-term forecasting, said during a Oct. 20 call to discuss the issue.
The state will begin experiencing the effects of the Aug. 21, 2017, eclipse at about 9 a.m. PT, just as solar output is ramping up to its mid-day peak.
CAISO expects output to drop at an average rate of 46 MW/minute, from 6,603 MW to 2,828 MW at 10:22 a.m., when the eclipse reaches its totality.
During next summer’s eclipse, solar output in CAISO’s balancing area is expected to decline from 6,603 MW to 2,828 MW in fewer than 90 minutes, followed by an even sharper upward ramp as sunshine reemerges. | CAISO
“This is just for large-scale utility solar — not behind-the-meter,” Amber Motley, manager of short-term forecasting at the ISO, pointed out.
By that time, the sun will be completely obscured south of Portland, Ore., while California’s San Juaquin and Coachella valleys — both key solar producing regions — will see coverage of around 76% and 62%, respectively. Utility-scale solar output is forecast to be about 5,050 MW below what it would otherwise be without the eclipse.
The loss of output will require steady ramping from other generation sources to cover the 3,775-MW difference between the 9 a.m. peak and the 10:22 a.m. trough.
As the eclipse begins to pass, solar output is projected to increase at a rate of 56 MW/minute until noon — nearly four times the norm for that time of day. That will require a sharp downward ramp of other resources.
Motley noted that the ISO has not calculated the eclipse’s effect on California’s rooftop solar — currently estimated to be at about 5,000 MW — but expects that variable will be factored into the load rather than generation forecast.
CAISO must also focus on the impact of the eclipse on the Western Energy Imbalance Market. Arizona Public Service, NV Energy and PacifiCorp have a combined 3,270 MW in utility-scale solar and 816 MW in rooftop installations.
Arizona and Nevada will not be as affected as PacifiCorp’s sprawling territory, Blatchford noted. Utah alone will experience a 70% reduction in radiance.
The ISO is looking for advice from European electricity planners, who experienced a similar event last year. The planners increased reserves, made strategic use of pumped storage, limited planned outages and reduced DC line capacities between different regions. Germany procured twice its normal level of regulation reserves, while Italy curtailed PV production ahead of the eclipse.
“They were going to lose 90 GW, so they had a lot riding on this,” Blatchford said. “They did a very good job there, I thought.”
In light of Europe’s success, CAISO is hoping to develop a plan that encompasses the West at large. The effort would take up several possible mitigation measures, including cooperation with the Western Electricity Coordinating Council, gas-electric coordination, use of flexible ramping and hydroelectric resources, EIM transfer capability, reserve procurement and development of special operating procedures for the event.
“I think we have a lot of market products that we can use … and help with the coordination of this event,” Motley said.
Stakeholders are asked to provide feedback on potential measures by Nov. 3. The ISO expects to develop an eclipse mitigation procedure early next year, with publication of a final plan targeted for March.
“This is a unique event that we don’t get to deal with on a day-to-day basis,” Motley said.
A Wisconsin wildlife hospital and refuge lost its case against American Transmission Co., as a judge decided that the company has the right to remove trees from the sanctuary’s property.
Walworth County Judge Daniel Johnson ruled against Fellow Mortals Wildlife Hospital in Lake Geneva, Wis., following a four-day trial. Johnson ruled that ATC had the right to cut any trees in the 50-foot easement that in the company’s “reasonable opinion” could pose a threat to its 138-kV line in the future.
“So if the tree can grow tall enough that it reaches the lines even 50 years from now, it could come down,” said attorney Robert Kennedy, who represented the hospital.
Kennedy said this likely means the end for the sanctuary’s “Grandfather Spruce,” an estimated 100-year-old Norway spruce, that had only been periodically trimmed since the easement was granted. (See Wildlife Refuge Preps for Trial Against ATC Clear-Cut.)
But ATC spokeswoman Jackie Olson said the company has not yet formulated a tree-cutting plan for Fellow Mortals. “We respect the care and commitment that Fellow Mortals has for rehabilitating wildlife. Our team is working to plan our next steps,” she said.
No Precedent
At issue was a 1970 easement between the hospital’s previous property owner and ATC’s predecessor, Wisconsin Power and Light. Until recently, the transmission company had allowed periodic trimming of Grandfather Spruce and other trees.
The hospital filed suit after receiving notice that ATC planned to clear-cut the 50-foot easement, which Fellow Mortals said would remove screening that protects its animals from a nearby roadway.
Johnson said he regretted there would be an impact on the sanctuary, but he concluded that the issue was one of “cold, hard real estate,” Kennedy recounted.
Kennedy, however, said Johnson’s ruling would not set a precedent unless the case reached the appellate level.
“It’s possible that other courts at a trial level might rule differently,” he said, noting that many older aging easements bear language similar to the one currently held on Fellow Mortals. “It appears that ATC recognized back in the early 2000s that the easement language was ambiguous and they stopped using that wording. All of the newer easement language is refined,” Kennedy said.
“Easements like this literally allow power companies to destroy large swaths of natural forest,” Kennedy added. “When you consider how many thousand miles of line ATC has and the acreage it covers, that’s a vast amount of natural timber that’s going down. Legislators should have looked at that and done something to protect the natural growth.”
Hospital Prepares for Cutting
In response to the Oct. 13 ruling, Fellow Mortals founders Yvonne Wallace Blane and Steven Blane are working with their staff to move as many animals into the hospital as they can to shield them from the tree-cutting. “We have an order of priorities. I assume they’re able to start cutting at any time,” Yvonne Blane said.
Blane said Johnson visited the habitat and praised the hospital’s work.
“I think the judge didn’t have a choice,” Blane said. “What was worked out [in the 1970 easement] is ambiguous. No one is arguing that line areas [don’t] need to be safe and maintained. But after 46 years of trimming, it’s a change in policy that this company is making.”
Blane said the animal relocation includes capturing 39 birds that are permanent residents of the hospital’s sanctuary area, including a 36-year-old great horned owl that serves as a foster parent to other orphaned owls. She also said her staff is working to release any treated animals that are ready to re-enter the wild. But she said there’s not much she can do for four elderly deer that have been affected by chronic wasting disease and are permanent residents of the hospital; they will have to weather the cutting in a half-acre pen.
Blane said she was proud that the case did not provoke animosity. “ATC attorneys and staff were very respectful. Our issue is not with the people; it’s with the policy,” Blane said.
She said she does not rule out the possibility that the company might return to the occasional trimming schedules, leaving the trees standing. “Perhaps knowing that they can do whatever they want, someone with the ability to be harsh would be kind. They might not care about public opinion, but boy, that would make so many people happy.”
Hospital’s Work Continues
Blane said Fellow Mortals spent $40,000 in donations on the case and was not looking to appeal the decision. She said moving the hospital is impractical because it would cost millions. So the Blanes and their staff plan to continue their work from the current location.
“We have to adjust; we have to move on. We’re not going to let us make this bitter; we’re not going to stamp our feet here. We’re going to show some dignity. One defeat doesn’t ruin everything.”
On Oct. 12, after the third day of the trial, the hospital was called to rescue an immature red-tailed hawk that had gotten caught on an Alliant Energy power line. The bird, which was suffering from hypothermia and shock, had exposed leg muscle from struggling against the pole. Blane said the bird will be in the hospital’s care while the leg heals, perhaps over the winter.
The Sacramento Municipal Utility District (SMUD) announced on Friday it will begin negotiations with CAISO to join the Western Energy Imbalance Market, and other members of the Balancing Authority of Northern California (BANC) may follow.
BANC said a cost-benefit analysis with the Western Area Power Administration’s Sierra-Nevada Region (WAPA-SNR) determined that some of its six members would benefit from joining the EIM.
“We also view the EIM as a tool to help us integrate increasing penetrations of variable renewable energy resources in the future,” Jim Shetler, BANC’s general manager, said in a statement.
Completed in 2012, the Sacramento Municipal Utility District’s Solano Wind Farm has 230 MW of capacity. | Sacramento Municipal Utility District
The joint powers agency said it will seek an arrangement allowing it to phase in members who want to join the EIM. Any agreement must recognize “the unique situation faced by the BANC members as public power entities and their existing arrangements,” the agency said.
SMUD would be the first BANC member to participate. The utility expects $2.8 million in yearly net benefits from transacting in the market — a figure that nets out the estimated $6.7 million in implementation fees and $2.6 million in annual operations costs.
In a presentation to its board of directors last week, SMUD management said EIM participation will improve the region’s renewable integration, potentially reduce reliance on gas-fired generation and provide “many of the benefits of regionalization while preserving [local] control over resources.”
“We view this is an extension of our existing market engagement with the CAISO,” said SMUD CEO Arlen Orchard. “SMUD also believes this further demonstrates our commitment to collaboratively work with California entities to help achieve the state’s energy and environmental goals.”
SMUD operates under an agreement that enables the utility to bid power into CAISO through a single hub in which one proxy price is selected to represent all connection points between the two areas. The ISO entered into a similar agreement with WAPA last year.
“We are extremely pleased to see a major regional public power utility like SMUD step forward to engage in the EIM,” CAISO CEO Steve Berberich said.
In addition to SMUD, BANC’s members are the Modesto Irrigation District, the cities of Redding, Roseville and Shasta Lake, and the Trinity Public Utility District.
The joint powers agency’s footprint extends from Modesto, Calif., to the Oregon border and includes a portion WAPA’s transmission grid and the U.S. Bureau of Reclamation’s hydroelectric resources in California. The agency’s members also control capacity on the California-Oregon Intertie, one of two high-voltage transmission lines linking California with the Pacific Northwest.
The footprint of the Balancing Authority of Northern California extends north to south from the Oregon border to Modesto, and east to west from Sacramento to the Sierra Nevada range. | Balancing Authority of Northern California
Founded 70 years ago, SMUD serves 1.4 million people, making it the sixth largest municipally owned utility in the country and the second largest in California, behind the Los Angeles Department of Water and Power.
BANC, which began operations in 2011, is the third largest balancing area in California and the 16th largest of the 38 balancing areas in the Western Electricity Coordination Council. Created as an alternative to CAISO, BANC is responsible for balancing load among its members, as well as coordinating system operations with neighboring balancing areas. BANC contracts with SMUD to perform day-to-day balancing functions.
BANC’s announcement came three days after Mexico’s grid operator said it will explore EIM participation for Baja California Norte, a region already interconnected with CAISO. (See Mexico Grid Operator to Explore Participation in EIM.)
The current EIM members are Arizona Public Service, NV Energy, PacifiCorp and Puget Sound Energy. (See Arizona Public Service, Puget Sound Energy Begin Trading in EIM.) Portland General Electric is slated to join the market in October 2017, followed by Idaho Power in April 2018.
CAISO’s latest draft of governing principles for a Western RTO is an improvement, but more changes are needed to win approval from regulators in the states in which PacifiCorp operates, speakers at a California Energy Commission (CEC) governance workshop said Monday.
Edmonds | Linkedin
“Our states are very sensitive to the perception that California can swing a veto,” PacifiCorp Transmission general counsel Sara Edmonds said.
Edmonds was referring to a provision that would institute load-weighted voting on the proposed Western States Committee (WSC) — the body comprising representatives from states considering participating in a future RTO. (See Latest Proposal Fills Out Western RTO Governance Plan.)
Veto Rights
As currently conceived, the voting rule — which requires any initiative be approved by 75% of voting members representing 75% of load — would not only prevent California from ramming through favored policies, but also permit that state to singlehandedly block any measures with which it disagrees.
“Ultimately, why we came to this [voting model] is that it gives some power to the weight of load, but gives all parties the ability to block a vote,” said Stacey Crowley, vice president of regional and federal affairs at CAISO. “It really does drive consensus.”
“I also understand that [weighted voting] is very important to California,” Edmonds said, noting that her company will seek to obtain feedback from state utility commissions on the issue.
Gardner | Western Resource Advocates
“I can tell you that a weighted voting model that gives California veto power will be problematic,” said Jennifer Gardner, an attorney for Western Resource Advocates (WRA), a Colorado-based environmental group that supports the ISO’s bid to regionalize the Western grid. (See Q&A: Western Resource Advocates Sees Benefits from Western RTO.)
In an alternative voting proposal submitted to the CEC last month, WRA pointed out that California would represent 76% of the load in an expanded ISO in which PacifiCorp was the only service area outside the current footprint. Including Arizona Public Service and NV Energy would still leave California with a 61% share, which would fall to a slim majority of 52% with the addition of Portland General Electric, Puget Sound Energy and Idaho Power.
Tiered Voting
WRA’s proposal: a tiered voting process in which every state would hold one vote under most circumstances and the WSC would attempt to work toward consensus. For issues where consensus voting might be difficult, other rules would apply, such as majority voting for day-to-day decisions and two-thirds majority voting for amending bylaws.
Load-weighted voting could apply for decisions related to the WSC’s areas of “primary authority” — tariff revisions that currently fall under the remit of state regulators. The weighting would be simplified so that any state with more than a 50% of the RTO’s load would wield two votes, while all others would get one. Gardner noted that the New England States Committee on Electricity follows a similar practice.
“What’s really important with that group is that they achieve all of their decisions based on consensus,” Gardner said. “If not, they revert to voting based on load.”
Florio | Linkedin
The California Public Utilities Commission’s Mike Florio said he was “taken aback” by the WSC’s limited role in the initial development of the resource adequacy and transmission access charge rules for an RTO.
“I think the counting rules [for resource adequacy] should be uniform for all the states,” Florio said. “That’s why it’s something that should fall to the Western States Committee.”
The ISO has played its strongest role with local resource adequacy, but the process is still in play for flexible capacity, Florio said.
“There is a significant role for the states there that hasn’t been outlined to date,” he added. “I’d think the states would want to have some kind of backstop role.”
Clarity on Roles
“I think we need to get much more clear on the very specific roles between the ISO board and the WSC — and versus the WSC,” said Dede Hapner, vice president of FERC and ISO relations with Pacific Gas and Electric.
Hapner | University of Michigan
Hapner said the most recent governance proposal provided a larger role for the WSC than the previous version and that industry participants must think about areas where the committee could trump the board.
“How much will be acceptable to the FERC?” she asked.
Hapner also advocated for the creation of a “transitional” WSC to begin quickly addressing issues of concern to participating states.
Concurring with that view was Rachel Gold of the Large-Scale Solar Association.
“Seating the WSC earlier — even in informal fashion — will be important to getting to ‘yes’ here,” she said.
Gendron | BPA
Other Western states would likely want to weigh in on rules around resource adequacy and greenhouse gas accounting, Gold noted.
Mark Gendron, vice president of power services at the Bonneville Power Administration, had a similar take. While his agency was pleased with the proposal’s attention to complex technical issues such as resource adequacy, it thinks it will take time to work through those matters.
“We’re concerned that some of the decisions on some of these technical issues could be made prior to the [seating of the] new board and Western States Committee,” Gendron said.
Potential Shortcoming
Cromwell | Linkedin
Robert Cromwell, director of power contracts and resource acquisition at Seattle City Light, pointed out a potential shortcoming in the ISO’s decision to make the WSC a body of general state representatives rather than regulators: Utility commissions might still have to weigh in on whether they could fulfill a WSC decision based on their own state laws.
The panelists found some positives in the latest proposal as well.
“We have repeatedly requested that consumer and environmental advocates be separated [in the Transitional Committee guiding development of the RTO],” Gardner said. “We appreciate CAISO taking our concerns.”
PacifiCorp’s Edmonds supported the proposal’s creation of a Nominating Committee and Approval Committee to select members of the final RTO board — the latter of which would comprise WSC members.
“The current revised proposal appears to shift more responsibilities to states, and I know our states are looking at this,” Edmonds said.
Edmonds also noted that the fleshed-out proposal deferred fewer governance design details to the Transitional Committee, calling that a “good thing.”
Florio and Gendron both complimented the proposal for emphasizing that the WSC should be a collaborative body.
Weisenmiller | CPUC
“I think the emphasis on a collaborative, consensus-based process is appropriate,” Florio said.
Hapner supported the proposal’s shorter transition to seating a final board and agreed with the redistribution of sector representation on the Transitional Committee, which folded generators and marketers into the independent power producers sector and created an exclusive grouping for end-use consumer advocates.
“The consensus seems to be that we’re making progress, but there’s still a lot of work to be done,” concluded CEC Chair Robert Weisenmiller.
Despite its best efforts to avoid litigation, the New York Public Service Commission saw its Clean Energy Standard challenged in federal court Wednesday by a group of energy companies and trade groups calling the rule’s subsidies to several nuclear power plants unconstitutional.
The suit, filed in U.S. District Court for the Southern District of New York in Manhattan, claims the zero-emission credits (ZECs) intrude on FERC’s jurisdiction over interstate electricity transactions, asking the court to find them invalid and order the PSC to withdraw them from the CES.
The ZECs are “purely protectionist in nature, enacted for political reasons to save jobs at the subsidized generators and the property tax revenues there from,” said the plaintiffs, which include Dynegy, Eastern Generation, NRG Energy and the Electric Power Supply Association.
The CES, adopted by the PSC in August, mandated that New York obtain 50% of its power from renewable resources by 2030. The ZECs were seen as a way to keep the state’s nuclear plants operating while utility-scale renewables are built. The 12-year subsidies would help keep open Exelon’s R.E. Ginna and Nine Mile Point and Entergy’s James A. FitzPatrick plant, the sale of which to Exelon is pending regulatory approval.
Nine Mile Point | Constellation Energy Nuclear Group
When it issued its order, the PSC said it had revised it in a way that it believed would avoid legal issues that caused the U.S. Supreme Court to void a contract between Maryland and Competitive Power Ventures in Hughes v. Talen. (See NY Attempts to Thread Legal Needle with Clean Energy Standards, Nuke Incentives.) The court found the contract unconstitutional, as it was tied to prices in PJM’s capacity market, over which FERC has jurisdiction. The PSC instead tied the price of its ZECs to EPA’s social cost of carbon and the price of carbon allowances in the Regional Greenhouse Gas Initiative.
The plaintiffs, however, said the ZECs were still tethered to FERC-regulated wholesale energy prices and thus unconstitutional.
“Apparently recognizing that its original proposal was plainly unconstitutional under Hughes, the PSC staff hastily revised its recommendation in July 2016 and changed the formula for determining the amount of ZEC subsidies,” they said. “Although the new formula was ostensibly based upon a federal interagency working group’s ‘social cost of carbon,’ this was window dressing, changing the name but not the intent to replace the FERC-determined energy price with a state-determined energy price.”
The plaintiffs argued that the subsidies disadvantage out-of-state generators who participate in NYISO’s markets.
“The ZEC order is directly discriminatory, as only specified New York nuclear facilities are eligible to receive ZECs,” they said. “Although states have the right to regulate the retail sale of electricity within their own borders, the wholesale sale of electricity involves interstate commerce, which the state may not regulate. NYISO’s wholesale marketers are interstate and international in nature, as they involve the sale and transmission of energy and capacity from generators located in other states and in Canada, and the purchase of such commodities by customers in other states.”
They also claimed that the ZECs could inhibit competition because they “would cause more efficient interstate generators to leave the market and discourage the entry of new competitors.”
Proponents of the CES were quick to denounce the suit.
“This lawsuit, filed by gas, oil and coal generators, is blatantly putting specific business interests ahead of what is best for New York,” said Gary Toth, vice chair of the County of Oswego Industrial Development Agency.
“Today’s lawsuit … is wholly inconsistent with the values of the countless New Yorkers who want to achieve a clean energy future,” said Ted Skerpon, chairman of the IBEW Utility Labor Council of New York.
“The bottom line here is that eliminating the nuclear provision from the CES will cause electricity prices to spike and will put thousands of New Yorkers out of work,” said Gregory Lancette, president of the Central-Northern New York Building and Construction Trades Council.
“Ultimately, if upstate nuclear plants close, it is the generation facilities that burn coal, oil, and gas that will benefit from the electricity price spikes that would result,” said Dave Young, president of the Rochester Building & Construction Trades Council.
Downstate Legislators Blast ZECs Again
On Monday, a group of New York City-area legislators again blasted the ZECs in a second letter sent to the PSC.
The legislators, now numbering seven, also said the PSC’s response to their first letter mischaracterized their opposition. (See New York Legislators Question Nuclear Subsidy.) They said they support the standard’s renewables goal but contend that the $965 million ratepayers will spend on the subsidies over the first two years of the program will be disproportionately borne by downstate ratepayers. They again called for the cost review of the power plants’ operating costs to be made public.
“The commission has kept the cost review concealed from the public, presumably on the grounds that the costs of the nuclear plants are trade secrets, but the commission in its order acknowledged there was little competition involved,” the letter states. “Upon sale of the FitzPatrick plant, Exelon/Constellation will become nearly the exclusive owner. Accordingly, there is no justification for withholding this information on the basis that the costs are protected trade secrets.”
The PSC responded to the first letter by saying the benefits of low emissions are shared statewide. It also has said the move toward a low-carbon energy portfolio would suffer if the nuclear plants retired prematurely.
COLUMBUS, Ohio – PJM officials said Wednesday they will seek FERC approval of the RTO’s seasonal capacity proposal despite a lack of stakeholder consensus.
The proposal, which would relax the current prohibition on seasonal resources aggregating across locational deliverability areas, received less than one-third support in a Seasonal Capacity Resources Senior Task Force poll last month. (See No Consensus Among PJM Stakeholders on Seasonal Resources.)
Adam Keech, executive director of PJM market operations, told the annual meeting of the Organization of PJM States Inc. that the PJM Board of Managers had approved making a FERC filing in November.
In addition to what Keech called PJM’s “facilitated aggregation” proposal — which is intended to improve the ability of intermittent resources and demand response to participate in the capacity auction — the RTO also will consider changes in load forecasting and incorporating summer DR’s curtailment capabilities after the auction, Keech said.
“We’re looking for other ways to value seasonal resources” in addition to changes in capacity rules, Keech said. “We recognize there’s more work to be done in this area.”
Keech said PJM’s proposal is a response to complaints that the aggregation options offered to seasonal resources under Capacity Performance rules are unworkable because of the difficulty summer and winter resources had in “finding one another” and reaching commercial agreements.
Under the proposal, PJM would match summer and winter resources, eliminating the need for commercial ties between them. Summer and winter resources would have separate six-month obligations and would not be liable for another resource’s nonperformance.
The RTO’s proposal also would allow resources to aggregate beyond LDA borders, with unmatched resources moving up to the next LDA level until a match is found. For example, an offer containing individual resources located in the EMAAC LDA and SWMAAC LDA would be modeled in the MAAC LDA. An offer with resources in COMED and EMAAC would be modeled in the “Rest of RTO.” Performance penalties would be distributed evenly between the resources, no matter which failed to perform.
Keech said PJM also will propose a change in how it measures winter DR, returning to the former firm service level (FSL) calculation “that is more conducive for demand response capability for industrial resources.”
PJM also plans to propose that wind be able to obtain higher winter capacity injection rights, in recognition that wind farms, which are rated at a 13% capacity factor in the summer, can produce 40% of their nameplate capacity in the winter. Hydro resources “potentially” could receive higher winter injection rights as well, Keech said.
Another initiative will seek ways to better incorporate DR into load forecasts, which would reduce costs by reducing the amount of capacity procured. PJM’s current method requires load reductions to be repeated for 15 years before they are reflected in the load forecast, Keech said. “There’s probably some room to improve in that area,” he said.
In addition, PJM is considering registering summer load curtailment capabilities after the capacity auction, which he said will borrow from its former interruptible load for reliability (ILR) program and “operational attributes” concept.
“We realize the operational flexibility value to that,” Keech said, adding “the details remain to be ironed out.”
Mixed Reception
The announcement of PJM’s plans got a mixed reception from other speakers at the OPSI meeting.
John Farber, an analyst with the Delaware Public Service Commission, called PJM’s choice “disappointing.”
Susan Bruce, counsel for the PJM Industrial Customer Coalition, said the group supports PJM’s filing. “We think it will help with the next auction,” she said. “It’s not a silver bullet though.”
Katie Guerry, of DR aggregator EnerNOC, made a pitch for her company’s proposal, which combined PJM’s plan with a “balancing ratio” that changes how DR is valued. It won support from one-third of the task force. Keech said PJM is discussing whether to apply the balancing ratio — currently used only for generation — to other resources.
James Wilson, a consultant for state consumer advocates, said PJM’s proposal falls short of his winter performance equivalents plan, which would auction “WIPES” credits that allow capacity resources to not perform in the winter. Opposed by PJM, Wilson’s proposal was supported by less than a quarter of task force members.
Wilson said the 2014 polar vortex was “a real wake-up call on the value of winter capacity” and said the CP rules properly created much stronger incentives for performance.
But he said CP went in the “wrong direction” in not recognizing the seasonal nature of both capacity resources and PJM’s peak loads. PJM’s projected 2020 summer peak load is 20,000 MW greater than its winter peak in a 50/50 forecast — with the difference rising to 26,000 MW in a 90/10 forecast.
“PJM’s reliability studies have always suggested that all of the outage risk is really in the summer, not in the winter,” he said.
Wilson said his “simple simulation” found that a “full seasonal” approach would save ratepayers about $1 billion annually by procuring 20,000 MW less in winter and accommodating more participation by seasonal resources — solar, wind and DR.
He said separate summer and winter price signals “would be potentially very helpful” for both renewable developers and gas-fired generators weighing the cost of obtaining firm gas supplies in winter.
Wilson praised PJM’s efforts to revise its load forecasts to recognize increasing energy efficiency. The changes reduced the forecast peak for the 2019/20 Base Residual Auction by 5,660 MW (-3.5%). (See Changes to PJM Load Forecast Cuts Benchmark Peaks.)
“But it’s too soon to … conclude that we’ve solved the over-forecasting problem,” Wilson said.
No Consensus in Task Force
The task force polled members last month on five proposed rule changes, with the most popular proposal — retaining the base capacity product for an additional year, delivery year 2020/21 — claiming 43% support. Only 48% of members who voted favored any change, while 52% chose the status quo.
Bruce Campbell of energy management company CPower said “a handful of large entities” can skew the voting in lower committees not subject to sector-weighted voting because they have multiple business units represented with stakeholder votes. “It’s my opinion that that probably has happened in this case,” he said.
The U.S. Commodity Futures Trading Commission on Tuesday unanimously issued a final order granting SPP’s request to exempt certain energy transactions in the RTO from the Commodity Exchange Act (CEA) and commission regulations.
The order is similar to the commission’s March 2013 ruling that provided six other grid operators with the same exemption, according to CFTC. But it also exempts those transactions from private rights of action, judicially inferred rights to relief that could have left the RTOs and their market participants as potential targets for lawsuits outside the FERC process.
The commission simultaneously amended its 2013 order to expressly exempt the six other grid operators from private actions, it said. SPP was not a party to the original order because its day-ahead market was not in operation, but it filed a “me-too” exemption in 2013 when it became apparent the market would soon be live. In response, the commission said in May that it never intended to protect the RTOs from private actions.
The ruling was expected after CFTC Chairman Timothy Massad said in a September letter to Sen. John Boozman (R-Ark.) that he would recommend the commission provide the exemption, reversing his previous position after receiving substantial industry feedback. (See CFTC Chair Flips on Private Rights of Action in RTO Markets.)
Boozman (L) and Massad
Commissioners J. Christopher Giancarlo and Sharon Y. Bowen joined Massad in a seriatim process, in which the commissioners vote in sequence and in private, rather than at an open meeting. Massad and Giancarlo have both issued statements supporting their votes.
Mike Ross, SPP’s senior vice president of government affairs and public relations and a former six-term Arkansas congressman, guided the effort that provided 38 comments against the proposed rule to allow private actions. There were only five comments in favor.
“We’re pleased with the commission’s decision to keep existing exemptions in place,” Ross said in response to the ruling.
An isolated area of Mexico’s grid already interconnected with California could become the first non-U.S. participant in the Western Energy Imbalance Market.
El Centro Nacional de Control de Energía (CENACE) — Mexico’s grid operator — and CAISO today announced an agreement to explore the benefits of having the Baja California Norte region join the West’s only real-time energy market.
While the region has no transmission connections with Baja California Sur or Mexico’s mainland grid, it boasts two 230-kV links with California through the Imperial Valley and Otay Mesa substations. Those lines, known as Path 45, provide about 800 MW of transfer capacity.
The isolated Baja California Norte region’s only transmission interconnections are to the north – with California. | Mexico Ministry of Energy
“CENACE’s Baja California Norte participation in the Western EIM will enable it to benefit from the savings that a large geographic region can offer,” CAISO CEO Steve Berberich said in a statement.
Baja already hosts natural gas-fired generation built in part to serve California’s market, including Sempra Energy’s 625-MW Termoelèctrica de Mexicali and Intergen’s 1,100-MW La Rosita. Deliveries into Imperial Valley can serve San Diego County via the 500-kV Sunrise Powerlink, which was energized in 2014.
The region also has promising potential for wind energy, which is increasingly valuable to California as the state seeks to balance its solar-heavy portfolio in pursuit of a 50% renewable standard. Sempra’s Energía Sierra Juárez, a 155-MW wind farm completed near the U.S. border last year, operates under a 20-year power purchase agreement with San Diego Gas and Electric.
“Mexico has had a long, productive relationship with the ISO as we coordinate the management of our interconnected electricity grids,” CENACE General Director Eduardo Meraz said. “It is only logical for CENACE to carefully consider Baja California Norte’s participation in the Western EIM, with its promises of lower-cost electricity and increased renewable integration.”
Mexico’s energy policy requires the country to generate 30% of its electricity from hydro and other renewable sources by 2021, a mandate that increases to 35% in 2024.
Legislation enacted in 2014 named CENACE the nationwide grid operator and partially deregulated Mexico’s power sector, allowing for expanded private sector participation. The agency, which manages the nation’s wholesale electricity market, operates more than 33,000 miles of high-voltage transmission.
PJM’s Independent Market Monitor asked FERC on Friday to reconsider its “flawed” ruling on PJM’s financial transmission rights market, saying it “contradicts the fundamental purpose of returning congestion revenues to load” (EL16-6-001, ER16-121).
“A consistent theme of the Sept. 15th order is the unsupported view that load must provide guaranteed and risk-free funding of FTRs as a hedge against day-ahead congestion, and that this is somehow in the interest of load,” the Monitor wrote in its rehearing request. “This approach, favored by the financial participants who own most FTRs, is not consistent with the reason that FTRs exist and has no basis in market logic.”
The commission’s order rejected PJM’s proposal to reduce Stage 1A infeasible auction revenue rights by increasing its zonal load forecast growth rate, saying the change would result in unnecessary transmission projects because it would rely on outdated source and sink points. The commission also rebuffed PJM on its plan to eliminate the netting of negative ARRs in a portfolio against positive ones.
An FTR entitles its holder to credits based on locational price differences in the day-ahead energy market when the transmission grid is congested. FTRs can be purchased or converted from ARRs, which are allocated to network and firm point-to-point customers.
| PJM
The Monitor’s request argues that FERC departed from precedent and contradicted earlier orders in striking balancing congestion from the FTR definition.
“Elimination of the total congestion revenues rule means that load-serving entities will be forced to pay to make up the difference when congestion revenues paid to FTR holders are in excess of the total congestion revenues collected,” the Monitor said. “This requires load to pay total congestion, including day-ahead and balancing, and then pay balancing again when it is negative. This is not consistent with the objective of the FTR/ARR design, which is to return congestion revenues to load.”
The Monitor described FERC’s ruling on portfolio netting as “unexplained” and said it “fails to address extensive arguments and examples that show the portfolio netting rule does result in cross subsidies.” The netting rule should be eliminated, the Monitor argued, because it “provides unjustified subsidies to participants holding FTRs with negative target allocations.”
It also challenged the commission’s determination that the Stage 1A allocation rule is necessary, saying it “avoids addressing the actual problem: the complete disconnect between the allocation of ARRs and actual system usage.” The Monitor said “the entire concept of generation to load paths is archaic, reflecting the contract path approach to physical transmission rights prior to the introduction of market.”
A new research report indicates that the belly of CAISO’s “duck curve” is deepening more quickly than originally expected, with its effects increasingly spread across the year — and not just on the typical spring day depicted by the graph.
The report from consulting firm ScottMadden also suggests that distributed energy resources such as rooftop solar are contributing only modestly to the decline in net load and ramping rates associated with the widespread adoption of solar energy in California.
The ScottMadden report contends that growth in distributed energy resources is keeping a lid on total load growth, but has little impact on system load —and, therefore, the deepening of the duck curve. | Scott Madden
“The duck curve is driven by utility-scale solar in California, not distributed resources,” the report says.
The report’s authors contend that understanding the root causes and impact of the curve is necessary for responding appropriately to its effect on grid operations.
“If we are to effectively address renewable integration challenges, it is imperative that we understand and address the actual issues that exist,” the report says. “Solutions for a seasonal, weekend, utility-scale solar issue may well be different than solutions for an everyday, distributed resource issue.”
California’s duck curve first appeared in 2013, the product of CAISO’s effort to forecast the long-term impact of increased renewable penetration on its daily operations.
That forecast demonstrated how the adoption of solar and other renewable resources would steadily undercut the ISO’s “net load,” which represents the portion of load that must be served by dispatchable resources such as gas-fired generation and imports. The net load calculation looks at total load for a given interval and subtracts energy generated by variable renewable resources.
Load Declines not Limited to Spring
The duck-shaped curve illustrates how daytime solar output crowds out the need for dispatchable resources during much of the day. That, in turn, creates the need for the sharp ramping of dispatchable resources as the sun begins to set. Over the long term, that ramp is expected to grow steeper as more solar resources come online and further depress net load as the state seeks to meet a 50% renewable energy mandate.
While CAISO’s original duck curve forecast predicted that minimum net load would fall to about 15,000 MW in 2016, this past spring already saw that figure — represented by the curve’s trough — sink to a low of 13,894 MW, a 31% decline from 2011. (See Solar is the Generation of Choice in California.)
Since 2011, ScottMadden said, CAISO’s daytime minimum net loads have been declining throughout the year, not just during the spring periods characterized by low residential loads coupled with relatively high solar generation. Furthermore, steep ramps are becoming more frequent, with the late-day three-hour ramp exceeding 5,000 MW on 58% of days in 2015, compared with 6% in 2011. Last year’s steepest ramp was 10,091 MW, a 62% increase from four years earlier, the report shows.
And the most significant ramps are occurring in fall and winter, when California’s net loads are at their lowest. In 2015, the 20 steepest ramps occurred in December (10), November (eight) and January (two).
The firm’s analysts also determined that the sharpest ramps consistently occur on weekends, the low point for weekly loads. Weekend ramps average 10% higher than those occurring on weekdays.
Weekends More Prone to Impacts
“These results suggest that weekends are more prone to experience the impacts of the duck curve because of their lower system loads,” the report says. “Conversely, higher system loads on weekdays mitigate the midday decline in net load and the impact of the duck curve.”
Perhaps most important from a system planning perspective, the report attempts to dispel the notion that DER is contributing significantly to the shape of the duck curve.
The authors explain that, while behind-the-meter distributed resources and energy efficiency appear to be offsetting growth in California’s total load, together they have little impact on the shape of the daily curve of system load — or load that must be supplied by system resources.
The authors back this claim by comparing CAISO — where distributed resources are just 3% of utility-scale capacity and do not participate in the wholesale market — with Hawaii, where residential solar represents 9% of generation managed by the state’s largest utility. In California, daytime system load has changed little since 2011, while Hawaii has seen a sharp decline over the same period.
Based on those findings, grid solutions need not “be totally dependent on complex DER management,” the report contends.
“Instead, the operational challenges associated with utility-scale solar present the potential for more targeted utility-scale solutions,” the report says.
