A call for conservation, lower-than-expected temperatures and slightly higher-than-expected wind energy helped ERCOT avoid taking emergency actions during scarce conditions last week.
The National Weather Service had expected temperatures to reach triple digits in the state’s major metropolitan areas into the weekend. Temperatures ended up being 2 to 4 degrees lower in many of the cities, with rain in some parts of the state helping dampen demand.
Demand dropped as Sept. 6 conditions eased. | ERCOT
ERCOT’s system demand peaked at 68 GW and 68.8 GW on those two days. The latter set a new record for September, elbowing aside the 68.5-GW mark established Sept. 3.
“We are thankful to Texans for helping us conserve,” spokesperson Leslie Sopko said.
On Thursday, wind production was expected to be less than 1.5 GW during the early afternoon hours before coastal winds picked up. However, wind energy contributed an extra half-gigawatt when physical responsive capability was at its lowest.
“When the wind doesn’t blow, it gets interesting,” ERCOT COO Cheryl Mele said last week during the Infocast Texas Renewables Summit. “The driver to the day is how much wind do we have. On our peak days, we’ve definitely had a little less than we did on peak days last year. When [wind] gets down to 2 GW or less, it has an effect on price. We’re all sitting around hoping the wind really does show up.
“Anytime we’re seeing a forecast of less than 2 GW in the afternoon or at peak, it means we’re going to have an interesting day.”
Prices briefly hit triple digits on Thursday during the interval ending at 5 p.m., after settling at just over $5,000/MWh in the day-ahead market. On Friday, prices were in quadruple figures, topping out at about $1,778/MWh during the 2:35-4:45 p.m. time period. Day-ahead prices for Friday’s energy and ancillary services were both about $4,500/MWh for the day.
The Texas grid operator this summer has called two energy emergency alerts, its first in five years. (See “ERCOT CEO Briefs Commission on Summer Performance,” Texas PUC Briefs: Aug. 29, 2019.)
ERCOT began the summer with an 8.6% reserve margin. It set a new all-time peak of 74.7 GW on Aug. 12, and it has recorded 11 other demand marks above the record set a year ago. Last year, ERCOT broke its previous record 14 times.
Austin, home to ERCOT, exceeded 100 degrees Fahrenheit during 27 of August’s 31 days.
The New England Power Pool Markets Committee met last week to discuss ISO-NE’s proposed Energy Security Improvements (ESI), but the sense of urgency to act has lifted after FERC extended an October deadline by six months.
Todd Schatzki of Analysis Group was joined by ISO-NE economist Christopher Geissler to present an analysis of the impacts of ESI. Pressed by stakeholders on how the study would move forward with the deadline now pushed out to April, Schatzki said the effort will benefit from the additional time — but that his firm is not expecting any delay in its work.
Geissler said that although the energy security improvements team would no longer be “going at breakneck speed,” it was committed to getting out the best design as soon as possible.
The New England States Committee on Electricity (NESCOE) filed the motion for the delay, asserting that the complex market design effort in the region was being unduly rushed. (See FERC Extends ISO-NE Fuel Security Filing Deadline.)
Forward Market
Rebecca Hunter, Calpine senior analyst of government and regulatory affairs, presented again on the company’s proposed Forward Enhanced Reserves Market, expanding on its current position and suggesting modifications to ISO-NE’s proposal. She said Calpine will use the extension to spend more time on draft Tariff language.
“In terms of the need to run RAA [resource adequacy analysis], I do see it happening as often as you would award for EIR [energy imbalance reserves],” Hunter said. “If you think about it, with the ISO awarding resources for EIR, the operators are not going to have any information about those resources being awarded, so when they go to decide who they should commit under the RAA process, they’re going to be starting down from the bottom of the stack.
Calpine’s Forward Enhanced Reserves Market (FERM) is a market design intended to pay all fuel-secure resources equally. | Calpine
“There’s a chance that maybe they’re picking up that same EIR resource in the RAA process, and I do identify that as getting paid for the same thing, that has been awarded twice, or there’s also a chance that they’re running a completely separate resource,” she added.
Geissler led a discussion of the framework for developing a forward component to the ESI design.
“I don’t know how we’d get the linkage between the forward sale of fuel and the expected obligation in the [day-ahead] market, or how those settle,” Geissler said. “For example, if there is no linkage, there may be concerns about how resources can be compensated for fuel through a couple different mechanisms, but at the same time, without a spot market that looks a lot like this, it’s not necessarily clear to me how to link the two in a sensible way.”
Stakeholder Amendments
Christina Belew of the Massachusetts attorney general’s office presented three amendments to the ESI proposal, each to be voted on separately by the MC:
Restrict use of generation contingency reserves, replacement energy reserves (RER) and EIR to winter months; and require impact analysis and NEPOOL stakeholder process before implementing ESI year-round.
Limit use of 90-minute and 240-minute RER options year-round.
Add a sunset provision to the proposed energy security improvements to trigger review of program need and efficacy.
Belew said her office was no longer going to proceed with its forward stored energy reserve proposal — a seasonal auction format for stored energy options — because after modifications were made to address stakeholder concerns, it no longer met the attorney general’s original objectives of providing the most efficient solution at least cost to consumers, fairness to all resources and responsiveness to future changes in resource mix.
NESCOE Director of Analysis Jeffrey Bentz also presented four possible amendments, including restricting EIR and RER to the winter months, but said the group is “considering these as one set of potential amendments, not four separate amendments.”
Another amendment would implement a must-offer requirement for resources with capacity supply obligations, while another would increase by 25% the strike price for ISO-NE’s proposed hourly energy call options — and create two options.
“Even with these amendments, analysis suggests that ESI as amended would be unlikely to fully solve the emerging concerns around market power mitigation but would be a step in the right direction,” he said. “We may decide to separate, eliminate or modify these based on today’s discussion and those going forward.”
David Errichetti of Eversource Energy briefly presented an amendment to address the company’s concern that the RTO’s interim Inventoried Energy Program would overlap with energy security improvements for winter 2024/25.
ISO-NE has promised to develop netting rules to address paying for both programs but has presented nothing yet, so NEPOOL is being asked to approve these rule changes without knowing if the netting rules will avoid paying twice for winter 2024/25 operations reliability, Errichetti said.
Robert Laurita, on behalf of the Connecticut Public Utilities Regulatory Authority and the Department of Energy and Environmental Protection, presented their amendment to the Tariff language concerning quarterly certification of the competitiveness of the energy call option offers in the day-ahead market and the related clearing prices.
Pending consideration of an amendment from PSEG Long Island, the RTO on Wednesday postponed a vote on Tariff changes to clarify that a resource retained for fuel security will only be retained until the end of the fuel security need and no longer than the two-year period allowed by FERC. The MC will vote on the matter at its Sept. 18 meeting. (See “Time Limit on Fuel-security Resources,” NEPOOL Markets Committee Briefs: July 30, 2019.)
DTE Energy’s latest integrated resource plan before the Michigan Public Service Commission is attracting several detractors who say it is short-sighted and relies blindly on fossil fuels.
DTE filed the IRP in spring to cover 2020 through 2035. Last month, several environmental and renewable energy proponents called for the PSC to reject the plan when it rules on it in late January (U-20471).
Reaction to the plan is a now familiar salvo in the industry: Environmentalists and renewable advocates maintain the utility is not making enough progressive change and is snubbing alternative energy sources on a grid that they say will soon be brimming with new technology.
Or, as Robert Rafson put it in testimony on behalf of the Great Lakes Renewable Energy Association, DTE relies on “traditional, backward-thinking, business-as-usual practices compared to ideal forward-thinking planning.”
Rafson said DTE’s plan includes a “minimum level of adoption of new technology.”
DTE rendering of Blue Water Energy Center | DTE Energy
The company is currently constructing the $1 billion, 1,150-MW gas-fired Blue Water Energy Center to replace about 2,000 MW of retiring coal plants in southwestern Michigan. The utility will retire the 277-MW River Rouge plant next year, and the 1,260-MW St. Clair and 485-MW Trenton Channel plants by 2022.
The IRP also proposes multiple gas-fired plants rated at about 400 MW, 693 MW of wind generation, 11 MW of solar with on-site storage and 859 MW in demand response programs by 2024.
“It is disingenuous for DTE to pat themselves on the back for reducing their carbon emissions when most of that reduction is derived from inefficient coal generation to more efficient natural gas and energy efficiency which they don’t even pay for,” Rafson said.
Union of Concerned Scientists analyst James Gignac — representing UCS, Environmental Law & Policy Center, The Ecology Center and Vote Solar, among others — said the IRP is so “fundamentally flawed” that Michigan regulators should outright reject it and order an amended filing.
“Doing so will ensure that coal plants are not being operated longer than they should and that investments in clean energy options are being pursued sooner and at the lowest cost,” he testified. Gignac said DTE simply assumed that its Belle River and Monroe plants would operate until 2030 and 2040, respectively, without considering their operations and maintenance costs or possible hundreds of millions of dollars in environmental mitigation retrofits.
DTE has previously committed to end coal use by 2040 and has a 50% renewable energy goal by 2030.
“In several ways, the IRP modeling was effectively prevented from choosing other more cost-effective resources,” Gignac told the PSC. By “hardcoding” the coal plants into its plan, Gignac said DTE assumes that any added capacity provides zero value, even as the costs of wind and solar generation, battery storage and behind-the-meter resources rapidly decline.
“DTE forced its modeling to over-rely on existing, company-owned resources, which produced suboptimal results and portfolios with inflated present value of revenue requirement,” Gignac said.
DTE has told the PSC that its plan is the “most reasonable and prudent means” of meeting demand through 2035. The company said it’s now focused “on more clean energy and less coal,” and has also concluded it won’t have a “persistent capacity need” until 2030, when the mixed-fuel 1,395-MW Belle River Power Plant near the Canada border is expected to retire.
But consultant Robert Fagan — speaking on behalf of the Michigan Environmental Council, Natural Resources Defense Council and Sierra Club — said DTE is failing to account for ITC transmission upgrades in place by 2023 that will increase the Lower Peninsula’s capacity import limits and expand energy purchase options “from the broader MISO region.”
Fagan said MISO Zone 7 capacity import limits are set to increase anywhere from 1,000 to 2,000 MW above the current approximate 3,200-MW limit and called DTE’s decision to use the current limit in out-year planning “not credible.” The environmental groups urged DTE to pursue bilateral purchase alternatives and an earlier retirement of Belle River.
Following nearly a year of internal changes, PJM is now backing off previous indications that it would reconsider the nature of its periodically fraught relationship with its Independent Market Monitor.
In its request to dismiss a separate IMM complaint over fuel-cost policy in January, PJM argued that Order 719 established the Market Monitor as an “element of a jurisdictional RTO/ISO.” Thus, if the commission allowed the IMM to file complaints under Federal Power Act Section 206, a new governance structure was needed that provides “complete independence” for the Monitor and no longer mandates reporting to the Board of Managers (EL19-27).
The commission’s August ruling denying PJM a rehearing opened the door for the RTO to take action on the issue. But interim CEO Susan J. Riley has signaled a softening of PJM’s position, releasing a joint statement with Monitor Joe Bowring on Thursday that reaffirmed their “relationship of mutual respect.”
“We both have a commitment to fair and competitive markets, even though from time to time we have differences of opinion,” the statement reads. “PJM values the Market Monitor, and we are both committed to our contractual relationship. The FERC’s decision in no way changes that relationship.”
Long-simmering Debate Put to Rest — for Good?
Members said PJM’s perceived frustration with its Monitor dates back at least a decade, as their disagreements, few as they may be, became more public.
In September 2016, the Monitor complained that PJM’s plan for evaluating fuel-cost policies usurped its authority and contradicted the Tariff’s specification of their respective roles (ER16-372). PJM, in its defense, said the Monitor’s complaint crossed the line and muddied their contractual relationship, as overseen by the Board of Managers. In its request for rehearing, the RTO said that Attachment M of the Tariff permits the Monitor to file complaints against market sellers over fuel-cost policy violations, but not against the RTO itself. It also said that its board’s oversight of the Monitor’s budget creates a conflict of interest.
The tension came to a head when the Monitor filed a separate complaint in December 2018 over PJM’s decision not to assess a penalty against a market seller that did not follow its approved fuel-cost policy. The RTO responded the following month by suggesting FERC “revisit” Order 719 and “reform PJM’s governance structure so that PJM’s Market Monitor is no longer accountable to the PJM board and establish it as truly independent from PJM with clear standing to bring complaints.”
FERC has not issued a ruling on the 2018 complaint. But it rejected both the Monitor’s and PJM’s arguments in the earlier docket. It also found “unconvincing” PJM’s conflict-of-interest argument.
“There is no conflict,” Monitor Joe Bowring said during an interview with RTO Insider on Wednesday. “The board can’t tell us what to file. It’s not part of their authority over us.”
Bowring also noted that the board can’t sever ties with his firm, Monitoring Analytics, under the contract terms to which they both recently agreed.
“We can’t ‘cut off’ PJM board oversight of Monitoring Analytics — and nor would we want to, without a different and better governance construct in place,” Jeff Shields, PJM spokesperson, said in an email to RTO Insider on Thursday. “We believe there are better options, but this is a policy choice bound by legal considerations that FERC and the courts respectively would have to embrace.”
Still, PJM gave no indication it would pursue further legal action on the issue. “The board does not have substantive oversight over the positions of the Market Monitoring Unit,” Bowring said. “There is nothing in the FERC order that contradicts anything in the Market Monitoring Plan or in the contract between PJM and the Market Monitoring Unit.”
States Prioritize Stronger PJM/IMM Bond
Jackie Roberts, director of the West Virginia Public Service Commission’s Consumer Advocate Division, said the Monitor plays a crucial role through its independence and “ability to discharge its responsibilities to members.”
“If PJM is sincere about changing the culture, they need to see the Market Monitor as part of the solution, not part of the problem,” she told RTO Insider. “The Monitor needs to be brought into issues early on.”
Indeed, change has swept through PJM throughout the last year. Longtime CFO Suzanne Daugherty resigned in April, CEO Andy Ott retired in June and Nigeria Poole Bloczynski came aboard as the organization’s first chief risk officer in July. She will lead the credit and market reforms anticipated in the wake of the GreenHat Energy default. (See Report: ‘Naive’ PJM Underestimated GreenHat Risks.)
Other stakeholders echoed Roberts’ desire for a stronger partnership between PJM and the Monitor in FERC filings and letters to the head of PJM’s search committee for a new CEO.
“Just as PJM recognizes the rights of states to their policies, PJM must recognize the right of the IMM to be an independent body,” Kristin Munsch, president of Consumer Advocates of the PJM States, in a July letter to the committee. “Arguments parsing Tariff language distract from the larger questions of how to use competitive markets to provide affordable and reliable electricity service.”
“Fact of the matter is that PJM and the Market Monitor agree on far more issues than they disagree upon,” Roberts said. “I think we have to focus on that.”
Consumer advocates weren’t the only stakeholders to intervene in the proceeding. PJM Power Providers sided with the RTO in its dismissal request, saying previous commission guidance supports its interpretation of the Monitor’s ability to file complaints.
The Edison Electric Institute took no official position, but it urged FERC to consider a governance structure that excludes the Monitor from playing a primary role in drafting tariff revisions, manuals or other documents, or implementing rule changes “that they ultimately monitor.”
“When possible, Market Monitors should attempt to address perceived areas of concern associated with behaviors or practices of market participants through a fact-based transparent resolution process before taking formal steps of referrals to regulatory authorities or otherwise,” the EEI wrote. “As part of the process, prior to referrals to regulatory authorities, market participants should have the ability to challenge the Market Monitor’s findings pursuant to a dispute resolution process as outlined in the tariff.”
Taking a cue from PJM’s financial transmission rights market debacle, MISO will this month draft Tariff changes designed to further protect all of its markets from financial defaults — including a measure that could spell bans for defaulting parties.
MISO is proposing to increase collateral requirements in its FTR markets based on perceived risk and give itself discretion over banning a potential participant from joining or re-entering any of its markets in extreme cases.
The RTO is seeking to implement a 5-cent/MWh minimum collateral requirement for FTRs and a mark-to-auction mechanism that would estimate the market value changes of an FTR portfolio by calculating the difference between purchase prices and the most recent auction prices. (See MISO Proposes Protections for FTR Market.)
The plan also aims to prevent known “bad actors” from participating. The provision would extend to those with a material financial default or named in a case “involving malfeasance or manipulative behavior,” said Jordan Cole, of MISO’s credit and risk management team. The RTO would review public charging documents to decide whether to prevent an entity facing manipulation allegations in other markets from entering its market.
While MISO can already suspend trading privileges for those who default within its own market, it is also considering whether to increase collateral requirements and allow for a five-year ban for any company with default values at more than $1,000 in other markets. MISO would decide to take either action on a case-by-case basis.
“We think this $1,000 is a low enough bar that it isn’t prohibitively insurmountable,” Cole said during a conference call Wednesday. He and other staff stressed the RTO is open to stakeholder suggestions to refine the proposal.
The RTO is additionally proposing guidelines to allow market participants to re-enter the market without posting additional collateral if they cure a default within a week. Participants taking more than a week to remedy a default would also be permitted to re-enter but could face additional collateral requirements up to either twice the default value or their highest exposure over the last 12 months.
MISO is also proposing that parties submitting its Annual Certification Form must attest to past defaults, even if they occurred under a different company name or an affiliate. The RTO would also ask market participants to disclose any bankruptcies, mergers or acquisitions in the last five years.
“This will help MISO respond accordingly under a case-by-case basis,” Cole said.
MISO will also draft language to allow itself to act when any market participants exhibit “financial warning signs.” Cole said any course of action upon discovering red flags would be up to management’s discretion on a case-by-case basis.
Stakeholders on the call asked that MISO consider additional collateral requirements before it issues suspensions or bans.
When asked by stakeholders about the prospect for appealing suspensions or bans, MISO credit analyst Brian Brown said market participants are free to challenge RTO decisions at the FERC level. “We’re obviously not the last voice in this process. We’re an intermediate voice charged with protecting the market,” he said. “The reality is a financial default is a financial default.”
Brown added he doesn’t envision MISO ever utilizing market bans, but he noted it has not ruled out the possibility.
Executive Director of Strategy Shawn McFarlane said MISO had set out to re-examine its FTR market even before GreenHat Energy’s record default in PJM.
“Sometimes we are guilty of being reactionary. … This time we were looking at tightening this up even before GreenHat became public,” he said.
MISO staff have said the RTO will continue to examine its credit practices after the new rules take effect. The RTO plans to file the proposal with FERC by the end of the year.
“I don’t think the book will ever be closed on FTR improvements. At any given time, the market can change, and we will certainly re-evaluate and reopen this, if need be,” Brown told stakeholders at the Market Subcommittee meeting last month.
CAISO and BC Hydro officials recounted their first challenges as newly minted reliability coordinators, while ERCOT and SPP officials talked of surviving a difficult summer at the NERC Operating Subcommittee meeting Wednesday.
James E. Hartmann Jr., senior manager of system operations for ERCOT, said the Texas grid operator had a “difficult August,” which saw it set a new all-time peak of 74,531 MW on Aug. 12 and a new weekend peak of 71,864 MW. Level 1 energy emergency alerts were called on Aug. 13 and 15 because of increased forced outages and a reduction in wind production.
CAISO will provide RC services for about 80% of the Western Interconnection when it and SPP take over from Peak Reliability later this year. | WECC
ERCOT also set a new September peak on Tuesday, hitting 68,546 MW, almost 1,600 MW above the old mark. “Unless something changes, we’ll hit a new September peak probably at least a couple more times this week,” he added.
SPP also reported a challenging summer, starting with flooding along the Arkansas River in late May that resulted in generation outages and a switch to conservative operations on several occasions. An EEA 1 was called Aug. 6, resulting in the RTO calling back from ERCOT some switchable generation. The balancing area hit an all-time peak on Aug. 19, topping the previous record by 40 MW.
The RTO went into conservative operations seven times during the summer because of generation outages, higher loads and subpar wind production.
Tests for New WECC RCs
CAISO, which became the RC of record for California on July 1, was tested that month by an earthquake and wildfires that forced the de-energization of two of the three lines at the California-Oregon Intertie (COI).
Tim Beach, director of reliability coordination for CAISO and its RC West, said the July 4-5 earthquakes caused no apparent damage to the bulk electric system, although a couple of 115-kV lines tripped and reclosed. An inspection afterward, however, found that some 230-kV disconnects “were unseated; in other words, they weren’t at their full stop and closed,” Beach said.
The wildfire forced two shutdowns of Malin-Round Mountain lines 1 and 2 over two days at the end of July. The Captain Jack-Olinda line remained in service.
Beach said CAISO worked with Peak Reliability and the Bonneville Power Administration to reduce the flow on the COI below the threshold that would trigger the separation scheme if the third line had been lost.
“With the open loop in that position — all the power from Oregon having to go all the way around the eastern side of the loop and come all the way up into California to the load centers — it’s a long way to move the power, so we try to balance the power, especially in California,” he said. “So, we get that interface down to less than 600 MW, on an interface that has a limit of 4,800 MW. It’s quite an evolution of redispatch when we go into that mode.
“Once you get the flow down and you’re not worried about the facility tripping and triggering the RAS [remedial action scheme], we worry about the RAS being triggered accidentally, because it’s really not needed at that time. So, we worked to disable the RAS while the flows are that low.”
If the RAS had triggered, it would have broken the West into islands, with California separating from the Southwest, he said. “Hopefully the islands will survive, and if there’s one that’s not going to survive, [we hope] that it goes down by itself — it doesn’t take the whole loop with it,” he said. “It was a pretty interesting operating period, but it was gratifying to see that we were able to work through it as a new RC and coordinate with everybody.”
RC West started shadow operations for its expanded footprint on Wednesday.
The timeline for the transition from Peak Reliability | WECC
BC Hydro ‘Grateful’
Asher Sneed, manager of system operations for BC Hydro, said he was grateful for a “normal summer.”
“We’ve had three exceptionally dry summers [and] three years of exceptional wildfire activity. And after what was quite a warm and dry spring, it was nice just to have a … summer where we had pretty much normal precipitation levels,” he said.
BC Hydro did have one wildfire impact the BES shortly after beginning its RC shadow operations.
The fire in the Okanagan region of British Columbia caused the shutdown of one 500-kV and three 230-kV lines. “The system loads and temperatures were fairly moderate, so there was really no concern [over] a next contingency preparation. But it definitely was a good test for our RC in the shadow period,” Sneed said.
Other Regions
Other regions also provided updates.
Alberta started the year with forest fires in the northwest, but rains helped eliminate the threats. The province was considering a capacity market, but a new government decided to remain with its energy-only market.
Subcommittee Chair Chris Pilong, director of dispatch for PJM, said the RTO’s summer peak of 152,000 MW, set July 19, was about what was predicted in its 50/50 forecast and well below its all-time peak of more than 164,000 MW.
Lacy Skinner, assistant chief system operator for NYISO, reported an uneventful summer. Temperatures above 90 degrees Fahrenheit only lasted for two or three days at a time with no prolonged heat waves, he said. For the first time, the summertime peak — 30,400 MW — was on a Saturday.
The ISO is conducting parallel testing of its new ABB emergency management system, nearing the end of a three-year project. The switch is expected to be complete in mid-October.
Michael McMullen, MISO’s director of regional operations, reported a “relatively calm” summer with the yearly peak July 19 below its 50/50 forecast.
John Norden, ISO-NE’s director of operations, said the RTO experienced its hottest month on record in July. Temperatures approached 100 F throughout New England on July 20-21, when loads hit about 24,000 MW. The two days placed among the RTO’s top five weekend loads.
In Ontario, a cool spring extended into June resulting in power surpluses that forced the shutdown of a nuclear unit on some weekends until heat pushed up loads in July.
Francis Monette, manager of system scheduling and operations for winter-peaking Hydro-Québec, also reported a quiet summer. “Sometimes we have thermal constraints in the south region in summer due to outages. However, this year, the outages in the south weren’t that bad, and we have a new 735-kV circuit that was commissioned at the end of May, which gave us more transmission availability in the south,” he said.
The Carolinas were bracing for Hurricane Dorian following an uneventful summer. Duke Energy’s Brunswick nuclear plant was expected to have to come offline because of hurricane-force winds. South Carolina entered a moderate drought stage about a month ago.
Solar generation is continuing to accelerate, but onshore wind appears to be losing momentum outside ERCOT and Alberta, RTO officials told the NERC Operating Reliability Subcommittee on Wednesday.
Committee members discussed the growth of wind and solar generation following Committee Chair Chris Pilong’s observation that wind growth has plateaued in PJM while solar and batteries are “starting to ramp up.”
“There’s still wind coming online, maybe not at the velocity that it was in the previous few years, but there’s still some in the queue,” said Michael McMullen, MISO’s director of regional operations. “The solar is definitely picking up.”
Cumulative U.S. wind capacity | American Wind Energy Association
Lacy Skinner, assistant chief system operator for NYISO, said New York is seeing more behind-the-meter solar. “The last couple years, we [had] a rush [of wind]. We got about 1,700 MW of wind at one point in time. And then over the last couple years, we’ve only added another 150 [MW]. So, it has kind of slowed down.”
NYISO’s first battery project is in the testing stage. “I know there’s a bunch more in the bucket,” he said.
Alberta expects to add 600 MW of wind this year to its existing 1,400 MW with another 700 MW next year — nearly doubling its capacity. A 400-MW solar farm is expected for 2021, its largest installation yet.
ERCOT, with 22,000 MW of wind installed, is showing no signs of slowing down, said James E. Hartmann Jr., senior manager of system operations. “We still have a lot coming,” he said.
The Texas grid operator has about 2,000 MW of utility-scale solar, “and we have at least twice that much coming,” he said. ERCOT will be adding a five-minute solar forecast into its energy management system.
Solar power was responsible for half of the generating capacity added in the first quarter of 2019. | Solar Energy Industries Association
“One thing we’re seeing [with] these big utility-scale solar farms, whenever a big cloud will go over them, you’ll see almost an instant drop of the generation. Not as fast [as] a unit trip, but it ramps very fast.”
SPP did not report on its wind growth at the meeting. As of Jan. 1, wind nameplate capacity was almost 23% of the RTO’s total capacity. Wind produced almost a quarter of its electricity in 2018.
ISO-NE is adding about 50 MW of solar a month, said John Norden, the RTO’s director of operations. “Five years ago, there was no solar in New England. We’re over 3,000 MW now. Our average load is about 15,000 [MW], so it’s not insignificant for us. We definitely see the duck curve.”
Norden said the biggest change coming to the region’s generation mix will be offshore wind. The RTO is planning to send some of its engineers to the North Sea “to see how they did it” in preparation for its first large farm, the 800-MW Vineyard Wind project off Martha’s Vineyard and Nantucket.
Annual U.S. solar installations | Solar Energy Industries Association
He noted that the planned turbines will not be visible from land.
“If anybody followed the offshore programs in New England for the last couple decades, anything that could be seen from any landmass was killed. So, these are all over the horizon, and we suspect they will be built because they’re sponsored with state money.
“People are coming to us now [wanting] co-located batteries and solar farms and possibly wind farms included as a single asset. So, we’re trying to develop a product to dispatch those all together. And I think it will look like a battery when all is said and done.”
SACRAMENTO, Calif. — San Francisco offered $2.5 billion to buy PG&E Corp.’s grid facilities serving the city Friday as the company announced it was postponing a controversial effort to secure up to $20 billion in bonds to pay its wildfire debts.
The company’s announcement came as state lawmakers prepare to end their session Sept. 13 — and as PG&E gets ready to file a reorganization plan by Monday in U.S. Bankruptcy Court in San Francisco.
San Francisco Offer
The company indicated that the city’s offer — delivered in a letter from Mayor London Breed and City Attorney Dennis Herrera — was not part of its plans for exiting bankruptcy.
“PG&E has been a part of San Francisco since the company’s founding more than a century ago, and while we don’t believe municipalization is in the best interests of our customers and stakeholders, we are committed to working with the city and will remain open to communication on this issue,” PG&E spokesman Andy Castagnola said in a statement.
Breed and Herrera said in a statement that the city’s offer was the result of a “detailed financial analysis conducted by industry experts and encompassing an extensive examination into the company’s assets in San Francisco.”
“The offer we are putting forth is competitive, fair and equitable,” they said. “It will offer financial stability for PG&E, while helping the city expand upon our efforts to provide reliable, safe, clean and affordable electricity to the residents and businesses of San Francisco.”
The purchase would create California’s third-largest municipal utility, after the Los Angeles Department of Water and Power and the Sacramento Municipal Utility District. The city is not seeking to purchase any of PG&E’s gas assets.
The deal would have to clear the bankruptcy court and federal and state regulators, where a central issue is likely to be how the loss of San Francisco would impact the rest of PG&E’s system.
“What that will mean is that folks who live in suburban and rural parts of California are left behind in PG&E’s system, and it’s not clear that the system is economically viable,” Michael Wara, the director of Stanford University’s energy policy program, told the San Francisco Chronicle. “What is the impact of this on people who don’t live in San Francisco?”
IBEW Local 1245 — PG&E’s largest union with 12,000 PG&E employees — has opposed talk of municipalization, creating a website to make its case against a purchase it says would cost closer to $6 billion. “Should city government focus on fighting homelessness, reducing traffic gridlock and building more affordable housing — or should politicians spend $6 billion buying PG&E and running our local utility?” it asks.
Tom Dalzell, business manager for the local, toldThe Wall Street Journal the city’s offer “is off by a factor of four. They don’t have the workforce either — the underground workers, the engineers to run the system.”
The unions also may have an ally in Gov. Gavin Newsom, the former San Francisco mayor and supervisor, who helped defeat two initiatives to create a city-owned utility.
PG&E: Will Revisit Bond Plan
Steven Maviglio, a spokesman for major PG&E shareholders that backed the plan, said they would revisit it next year.
“The timing was simply not right to pass this legislation with just days left in the session,” Maviglio said in an emailed statement. “During the interim, we will continue to work to resolve the bankruptcy case and help PG&E fulfill its commitments. We will return in January with a renewed effort to getting this beneficial legislation the full and fair consideration it deserves.”
PG&E issued a statement Friday saying, “We firmly believe that Wildfire Victim Recovery Bonds are a critical element to the state’s path forward when it comes to addressing wildfire risk.”
California State Capitol
The company filed for bankruptcy in January after two years of devastating wildfires that are likely to cost the utility billions of dollars in damages. The fires included the November 2018 Camp Fire, the deadliest and most destructive in state history.
In recent weeks, PG&E and the hedge funds that control much of its stock have been lobbying lawmakers to draft and pass a measure that would have established a wildfire recovery bond program for the state’s investor-owned utilities. The proposal would have let the state borrow money, tax-free and at low interest rates, on behalf of the IOUs. (See PG&E Seeks $20B Wildfire Bonds Issuance.)
The vehicle for the bond measure was Assembly Bill 235, a wildfire-related measure that stalled in committee earlier this year. It was heavily amended Friday to include the bond provisions, just as PG&E said it would no longer pursue the effort.
The measure was meant to bolster PG&E’s position in bankruptcy and to head off an effort by its unsecured bondholders to take greater control of the company at a substantial discount. Those bondholders had put forward their own reorganization plan that included a $30 billion investment in the company in exchange for guaranteed payment of their notes, which could otherwise be dismissed in bankruptcy, and a big stake in PG&E. (See PG&E’s Bondholders Push $30 Billion Investment Plan.) They waged a lobbying and advertising battle against the PG&E bond proposal in recent weeks, launching a website titled “Stop the PG&E Bailout.”
In August, Judge Dennis Montali, who is overseeing PG&E’s Chapter 11 case, gave PG&E time to file its own reorganization plan without competing proposals, including the bondholders’ plan, but he could still consider alternatives going forward. (See Only PG&E Can File Bankruptcy Plan, Judge Says.)
PG&E has promised to file its own Chapter 11 reorganization plan by Monday, though the court had given it until later this month to do so. An outline of the plan released by PG&E earlier this summer said the utility will pay its debts and compensate fire victims by raising money through stock offerings.
In documents filed with the U.S. Securities and Exchange Commission, two major shareholders, Abrams Capital Management and Knighthead Capital Management, pledged to backstop PG&E’s plan with $15 billion in equity financing. Those firms also backed the legislative bond proposal.
FERC failed to adequately explain how it relied on natural gas exports in approving the Nexus Gas Transmission pipeline in Ohio and Michigan, the D.C. Circuit Court of Appeals ruled Friday (18-1248).
The court said it agreed with the city of Oberlin, Ohio, and the Coalition to Reroute Nexus, a landowners’ organization, that the “commission failed to adequately justify its determination that it is lawful to credit Nexus’ contracts with foreign shippers serving foreign customers as evidence of market demand for the interstate pipeline.”
The court, however, declined to vacate FERC’s approval of the 256-mile pipeline, saying, “We find it plausible that the commission will be able to supply the explanations required, and vacatur of the commission’s orders would be quite disruptive, as the Nexus pipeline is currently operational.”
At issue is the commission’s August 2017 order granting Nexus a certificate of public convenience and necessity under Section 7 of the Natural Gas Act and its July 2018 order rejecting rehearing (CP16-102, et. al.).
| Nexus Gas Transmission
The 36-inch pipeline runs from receipt points in eastern Ohio to pipeline connections in southeastern Michigan, allowing delivery to customers in northern Ohio, southeastern Michigan and the Dawn Hub in Ontario. Nexus Gas Transmission is a 50/50 partnership between DTE Energy and Enbridge.
FERC found that Nexus’ precedent agreements were “the best evidence” that the pipeline would serve unmet market demand. Although the precedent agreements represented only 59% of Nexus’ capacity, the commission concluded that existing pipelines could not absorb that amount of gas.
The petitioners claimed Nexus’ precedent agreements should be ignored because half of them are with affiliates. The court backed the commission’s explanation that it fully credited Nexus’ agreements with affiliates because it found no evidence of self-dealing.
But the court agreed with the petitioners’ claim that the precedent agreements are not strong evidence of market demand because two of the agreements, totaling of 260,000 dth/day, are intended for export to Canada. If the commission excluded the exports, Nexus would have precedent agreements for only 625,000 dth/day, about 42% of its 1.5 million dth/day capacity.
“The commission never explained why it is lawful to credit demand for export capacity in issuing a Section 7 certificate to an interstate pipeline,” the court said.
“Section 7 states that the commission may issue a certificate of public convenience and necessity for ‘the transportation in interstate commerce,’ and we have explicitly refused to interpret ‘interstate commerce’ within the context of the act so as to include foreign commerce.
“Accordingly, we remand to the commission for further explanation of why — under the act, the Takings Clause [of the Fifth Amendment], and the precedent of this court and the Supreme Court — it is lawful to credit precedent agreements with foreign shippers serving foreign customers toward a finding that an interstate pipeline is required by the public convenience and necessity under Section 7 of the act.”
The court rejected challenges to FERC’s approval of Nexus’ proposed 14% return on equity and its finding that the pipeline does not “represent a significant safety risk to the public.”
The case was decided by Judges Judith W. Rogers, Sri Srinivasan and Robert L. Wilkins, and the opinion filed by Wilkins.
One of the biggest blank spots on CAISO’s Western Energy Imbalance Market map could be partly filled if four Colorado utilities join the West’s expanding real-time trading market.
Xcel Energy, the state’s largest load-serving entity, and three partners — Black Hills Energy, Colorado Springs Utilities and Platte River Power Authority — announced Friday they were evaluating joining one of the markets with the help of a consulting firm. If that eventually happens, they’d be the first entities in Colorado to join an energy imbalance market.
“Working together, we have the potential to drive down fuel costs and provide customers with more energy from wind and solar resources,” Alice Jackson, president of Xcel Energy – Colorado, said in a news release. “We’re pleased to continue this regional collaboration and urge other power providers to consider joining us.”
The four utilities already share resources and balance peak demand through a joint agreement, but they see “value in joining a larger market to expand opportunities to exchange energy with neighboring utilities and be able to reliably integrate more clean energy into their systems,” Xcel said.
Motivating Factors
Political and financial factors likely influenced the decision.
Colorado Gov. Jared Polis signed a bill in May that reauthorized the Public Utilities Commission and implemented a host of new environmental requirements for it and utilities. SB19-236 requires utilities to submit greenhouse gas-reduction plans and instructs the PUC to investigate the potential benefits of joining a regional energy market.
“This exploration is in keeping with the passage of [the bill],” Xcel said.
A prior effort by Colorado utilities to join an RTO went south in April 2018, when Xcel upended a plan for the Mountain West Transmission Group to join SPP. Xcel, the group’s largest member, pulled out, saying it wasn’t in its best interests. (See Xcel Leaving Mountain West; SPP Integration at Risk.)
Xcel has also been engaged in a long-running turf battle with the city of Boulder over the city’s efforts to acquire the utility’s local assets and form a municipal utility intended to supply carbon-free energy by 2030. The city filed condemnation proceedings in June while simultaneously engaging in a separation proceeding with Xcel before the PUC, with both proceedings still playing out.
Boulder’s efforts were seen by some as spurring Xcel’s pledge in December to become the first major investor-owned utility to supply its customers with 100% carbon-free energy. The company said it would cut carbon emissions by 80% in 2030 and go all-green by 2050.
Polis, in his policy “roadmap” to achieving 100% renewable energy by 2040, has set similar goals for the state.
Reaction and Predictions
Xcel’s announcement was met with general praise from supporters of regional markets, including CAISO.
“The Western EIM has proven it can deliver as we enter a new era in the energy industry,” the ISO said in a statement sent to RTO Insider. “We support the efforts of these four Colorado utilities to join the Western EIM, which includes some of the largest electric utilities in the West. The current Western EIM participants have realized nearly three-quarters of a billion dollars in total benefits while reducing more than 400,000 metric tons of carbon emissions.”
CAISO’s latest figures show its continually expanding EIM saved its participants more than $736 million since it started in November 2014. Its current nine members include Arizona Public Service, PacifiCorp and NV Energy. Nine other entities scheduled to join include Arizona’s Salt River Project, in 2020, and the Los Angeles Department of Water and Power, in 2021.
The Bonneville Power Administration is well along the path to joining the EIM, filling in the second big gap in CAISO’s EIM map in the Pacific Northwest. (See Customers Probe BPA on EIM Impact.)
SPP said it, too, welcomed the interest.
“SPP has been working with several Colorado and regional utilities interested in participating in a wholesale electricity market,” a spokesman said in an email. “Having studied and observed the value of our energy imbalance and day-ahead markets over the last several years, we’re confident we can enhance the affordability and reliability of electricity in Colorado and across the west today and in the future. We stand ready to serve potential customers in the west if and when they determine the value of SPP’s services is right for them.”
Jennifer Gardner, senior attorney with Western Resource Advocates and chair of the committee that nominates leaders for the Western EIM, said Xcel and other Colorado utilities joining a regional market makes sense, especially to facilitate trade of Rocky Mountain wind energy with solar power from California and the Desert Southwest.
“We’ve seen a lot of market activity taking place in the last two to four years,” Gardner said. “These utilities realize there are more benefits to be gained with renewable energy integration … if they expand their footprint.”
Transmission connections to SPP or CAISO could be difficult with limited pathways, but a western connection may be more practical, she said.
Leaning Toward CAISO or SPP?
To perform the EIM study, Xcel and its partners selected the Brattle Group, a firm not usually associated with those intending to join that market. That led to some speculation that the Colorado utilities were leaning toward SPP.
An Xcel spokeswoman said in an email that wasn’t the case.
“At this time, we are waiting for the results of the study and are not leaning in any particular direction,” Michelle Aguayo said.
Gardner said it’s true that EIM entities have generally used another firm, E3, but she doubts the choice of Brattle signals a preference for SPP.
“The choice of who’s doing a study isn’t so important. This is just a personal preference” on the part of utilities, some of whom have used Brattle before, she said.
In energy conferences across the West in recent years, representatives of the intermountain states have expressed concern that California would dominate a regional market controlled by CAISO. They’ve been hesitant to go along with the ISO’s desire to form a Western RTO but have joined the EIM because its board is made up of members from other states and because participation is wholly voluntary.
Moreover, California’s huge population and demand for electricity is enticing.
Will financial calculations win out, or is a loathing of California and greater affinity for SPP more likely to control?
Carl Zichella, Western transmission director for the Natural Resources Defense Council and a strong supporter of regional markets, suggested that it could go either way but that CAISO might be the better choice because of its established track record and better connections.
“The power and efficiencies of wholesale energy markets are becoming increasingly clear to all load-serving entities in the West,” Zichella said in an email. “The CAISO’s Western EIM has surpassed $720 million in benefits for market participants and is continuing to grow. SPP’s Energy Imbalance Service has worked well for its members in the Eastern Interconnect.
“Colorado utilities must now decide whether their best deal is obtained by looking east — across the Eastern Interconnect’s limited DC ties — or West, toward the Western EIM.”
