The three California organizations that oversee electricity responded to a request by Gov. Gavin Newsom to explain why the state had two days of rolling blackouts on Aug. 14 and 15 and would have had more if not for statewide conservation efforts.
“We agree that the power outages experienced by Californians this week are unacceptable and unbefitting of our state and the people we serve,” CAISO, the Public Utilities Commission and the Energy Commission told Newsom in a joint letter last week. “We understand the critical importance of providing reliable energy to Californians at all times, but especially now, as the state faces a prolonged heat wave and continues to deal with impacts from the COVID-19 pandemic.”
The organizations operate independently but coordinate efforts to supply the state with electricity. CAISO operates the transmission grid. The CPUC regulates investor-owned utilities and orders procurement. The CEC forecasts demand, among other functions.
“We are working closely as joint energy organizations to understand exactly why these events occurred,” they said.
The tone of shared responsibility differed from CAISO initially blaming the CPUC for failing to procure sufficient energy despite warnings of capacity shortfalls starting this summer. (See CAISO Blames Blackouts on Inadequate Resources, CPUC.)
Disconnecting Navy ships from shore power helped CAISO avoid more blackouts. | U.S. Navy
Leaders of the three organizations said their staffs would need more time to fully analyze the causes of the blackouts, but they provided Newsom with their initial findings. The letter was signed by CAISO CEO Steve Berberich, CPUC President Marybel Batjer and CEC Chair David Hochschild.
Demand on Aug. 14-15 was high, peaking at approximately 47 GW and 45 GW respectively, they said, “but not above similar hot days in prior years. Given this, our organizations will need to conduct a deep dive into how we ensure sufficient electric supply and will make modifications to our reliability rules to make sure reliability resources can be available to address unexpected grid conditions.” (See CAISO: Blackouts May Continue, Calls Emergency Meetings.)
The state’s “heavy reliance” on imports was one obvious factor in the blackouts, the leaders told Newsom.
The heat wave that engulfed the West in triple-digit temperatures dried up imports that weren’t secured by long-term contracts, CAISO said. It struggled to meet peak demand during the late afternoon and evening hours and would have ordered additional days of rolling blackouts if conservation efforts hadn’t cut demand by 2,000 to 3,000 MW and the state hadn’t secured more megawatts. (See ‘Last Challenging Night’ for CAISO, Governor Hopes.)
Conservation, More MWs
The organizations provided additional details on those efforts in the letter to Newsom.
The CEC coordinated with data centers in Silicon Valley to move approximately 100 MW of load to on-site backup generation, the letter said. It worked with the U.S. Navy and Marine Corps to “disconnect 22 ships from shore power, move a submarine base to backup generators and activate several microgrid facilities resulting in approximately 23.5 MW of load reduction.”
The state Department of Water Resources and the Metropolitan Water District of Southern California shifted 80 MW of hydroelectric generation to peak demand times. The department and the U.S. Bureau of Reclamation made changes in pumping schedules that secured another 72 MW. And San Francisco maximized output at its Hetch Hetchy hydroelectric facilities to generate an additional 150 MW during peak demand periods.
CAISO and the CPUC have both warned of more severe shortfalls going forward as fossil fuel plants and the state’s last nuclear power generating station retire. The state’s switch to solar and wind resources isn’t to blame for the shortfall, but far greater storage is needed to meet “net-peak” demand after the sun sets, CAISO and the CPUC said recently. (See CAISO, CPUC Warn of ‘Reliability Emergency’.)
To avoid shortfalls in the coming summers, “forecasts and planning reserves need to better account for the fact that climate change will mean more heat storms and more volatile imports, and that our changing electricity system may need larger reserves,” the organizations wrote.
The CEC is holding sessions Wednesday to help forecast demand through 2030, with the recent shortfalls part of that discussion.
Renewable energy’s proliferation has played a key role in helping ERCOT meet demand, but it is also beginning to cause transmission constraints that are likely to increase during the next five years.
Staff are previewing what they say are necessary future conversations. They say that while planning studies have not shown that transmission constraints will hamper resource adequacy in the near term, they will pose an increasing challenge requiring more training, detailed models and more powerful software.
The problem is that new resources are being sited farther away from urban load centers, taking advantage of Texas’ ample wind and solar potential. This shift from traditional, large fossil-fired plants near load centers to smaller renewable resources on the farthest reaches of the ERCOT system has led to the stability challenges.
ERCOT’s transmission-constrained areas | ERCOT
“Every year, we’re seeing generation getting a little further from load. That’s our underlying issue,” said Woody Rickerson, ERCOT’s vice president of grid planning and operations. “It’s inherently harder to serve load on the edge of the system, where it’s not networked deeply into the system.”
Rickerson told ERCOT’s Board of Directors during its Aug. 11 meeting that most new generation projects are inverter-based resources. These resources are added to the planning models six months to two years ahead of their commercial operation date, but transmission upgrades resolving congestion can take up to six years to complete.
Planning studies beyond 2022 don’t include wind or solar projects, Rickerson said, “because the development time frame puts them inside the 2023 timeline.”
“The planning process will result in some lag and congestion,” he said.
Jeff Billo, ERCOT’s senior manager of transmission planning, said the grid operator’s “generator-friendly” interconnection process has also played a role. Beginning with the Competitive Renewable Energy Zone (CREZ) initiative — which resulted in 3,500 miles of transmission facilities in 2013, freeing up 18.5 GW of West Texas wind energy — the grid operator’s stakeholders have set up processes designed to quickly add generation to the grid.
“Most developers I talk to prefer the ERCOT way, with the firm transmission rights and being able to get interconnected in less than two years, versus other [regions], where I hear anecdotally it can take six to seven years,” Billo said. “We really needed to build some amount of transmission that was appropriate for new generation.”
Not surprisingly, ERCOT has identified its West Texas zone, home to most of the state’s wind resources, as one of five geographical areas where it expects emerging reliability and/or economic issues. Reliability issues are driven by load growth, and economic issues are typically driven by generation growth.
Rickerson said 28 GW of renewable generation is expected to be connected in West Texas, far beyond CREZ’s plans. Stability limitations are expected to lead to high levels of congestion on West Texas exports, he said, but ERCOT is studying the region’s congestion solutions in its 2020 Regional Transmission Plan.
Far West Texas is also home to the oil-rich Permian Basin’s Delaware Basin, the fastest growing load in Texas. The region’s annual peak load has grown by more than 10% since 2010, compared to the ERCOT’s systemwide growth rate of about 1.5% during the same time frame.
ERCOT’s new generation resources are mostly in West Texas, while demand is in the east and south. | ERCOT
Staff analyzed the Delaware Basin and has identified a five-stage roadmap of transmission upgrades to continue meeting the oil and gas load.
“If you are moving power across a longer distance, you’ll have more marginal losses and reactive losses. With the inverter controls, you’re pushing a lot of power on your circuit … and getting stability challenges,” Billo said. “Going forward, stability is going to be more limiting than thermal issues. That’s just the way our generation fleet is evolving.
“Because we have that generation-friendly environment, we can wait until the last minute [for developers] to turn in their data or make a commitment,” he said. “We don’t have a lot of lead time to know where the generation constraints are through this process. We’ve seen the system is evolving to where we see more and more stability constraints on the system, but the stability studies take time.”
The Delaware Basin’s peak demand has been steadily increasing. | ERCOT
Interconnecting resources are increasingly requesting remedial action schemes (RASes) as a protection scheme. These hardwired relay systems detect predetermined system conditions and automatically take corrective actions, which can include transmission reconfiguration and load sheds or generation trips that allow resources to produce beyond local transmission constraints.
“When [an RAS] sees a condition, it doesn’t call the operator. It acts,” Rickerson said. “A lot of study goes into them from a reliability standpoint. It’s something you really have to pay attention to.”
ERCOT has drafted a change to the Nodal Operating Guide (NOGRR215) that is currently winding its way through the stakeholder process. The change proposes boundaries for new RASes that limit reliability risks associated with their potential widespread use.
The schemes were a major topic of conversation last week during a workshop on transmission issues related to generation constraints. EDF Renewables, SolarPrime and other renewable interests submitted presentations advocating for RASes and the need to meet economic criteria.
The grid operator also relies on generic transmission constraints (GTCs), predefined collections of transmission elements, to maintain grid reliability to subject the aggregate power flow to a defined limit in real time. This is necessary because economic dispatch, reliability unit commitment and other existing market tools are not capable of calculating other operating limits.
ERCOT held a GTC-themed workshop in February and has drafted a GTC white paper to educate and inform stakeholders.
Five of the grid operator’s 12 GTCs can be found in South Texas, which faces both import (reliability) and export (economic) stability constraints. LNG facilities in the Rio Grande Valley could require up to $1.2 billion in transmission improvements and additional generation development in the region could lead to further stability constraints.
ERCOT’s other staff-flagged transmission-constrained areas include:
The Northwest Dallas-Fort Worth Import: One of the highest congested areas in recent planning studies, generation development northwest of the DFW area and load growth within the metroplex is expected to exceed the region’s transmission capacity. Rickerson said staff are actively analyzing project options to relieve these constraints.
Houston-Freeport Import: The Houston Import went into service in 2018 and the Freeport Import will be completed in 2021. (See ERCOT Stakeholders OK $246.7M in Freeport Reliability Projects.) However, the 2014 Houston Import Project study indicated additional upgrades would be needed by 2027 to continue meeting reliability criteria. Recent planning studies indicate congestion will increase in coming years as power is imported into the Houston and Freeport areas.
Oregon regulators are grappling with how to modernize the state’s customer-choice electricity program to accommodate a rapidly changing energy landscape that’s being reshaped by decarbonization policies across the West.
The Oregon Public Utility Commission last year opened an investigation (UM 2024) into the state’s 20-year-old long-term direct-access programs, which give large energy consumers the ability to obtain electricity service outside the regulated cost-of-service regime. The commission is now seeking how to shape the inquiry.
The state legislature authorized the PUC to implement direct access as part of a raft of provisions in SB 978, a 1998 law intended to equip the commission with authority to implement programs that could address investor-owned utility greenhouse gas emissions, encourage the development of a regional electricity market and create retail choice options for nonresidential customers.
Oregon’s two main IOUs, Portland General Electric (PGE) and PacifiCorp, function as gatekeepers for the programs, providing larger consumers with a yearly process for applying to opt out of regulated service in order to enroll in either a utility-run, market-based program, or contract with a third-party direct-access electricity service supplier (ESS). Similar to the process in other Western states, opting in to direct access carries certain “transition” costs for customers that ensure utilities reduce their exposure to stranded costs for providing regulated service, including meeting resource adequacy requirements. Those costs ultimately fall to the larger pool of cost-of-service customers.
Evolutionary Need
UM 2024 comes in response to a June 2019 petition from the Alliance of Western Energy Consumers (AWEC), whose membership represents companies with 160 facilities (that employ 170,000 workers) comprising both direct-access and cost-of-service customers, according to the organization.
Oregon PUC Commissioner Letha Tawney | Oregon PUC
In seeking the investigation, AWEC’s petition cited “significant disputes” over the programs in recent years, including those related to whether the state should further expand or restrict the programs and whether the programs have benefited or harmed cost-of-service customers. AWEC also noted that PGE’s direct-access program — what it called the only one “that has successfully contributed to the development of a competitive market in Oregon” — is nearing its 300-MW cap, making it soon unavailable for customers.
“My goal, when I think about this docket, is to sort of see how and where this customer-choice option needs to adapt to the current and likely future of the system — the policy, the regulation, the markets and technology that are all evolving alongside a customer-choice program that we set and have tinkered around the edges with but not fundamentally grappled with for two decades,” Commissioner Letha Tawney said during a Thursday workshop on the issue.
The PUC is proposing that its line of investigation address four sets of questions:
Does the direct-access law currently raise concerns about unwarranted cost-shifting “or other relevant harms to the public interest?” Would expansion of the programs in size and reach create additional “concerns related to unwarranted cost-shifting or other relevant harms to the public interest?”
Can program design mitigate unwarranted cost-shifting or other relevant harms? “What mechanisms should be used; how should such mechanisms be structured; and what are the legal or practical barriers to implementing them?”
“With such mechanisms in place, are unwarranted cost-shifting or other relevant harms to the public interest mitigated to the degree that the commission should expand access to direct-access programs?”
What evidence has been presented or could be presented in the docket (or a future one) to show that existence of cost-shifting and whether it would occur under an expansion of the program, and whether mitigation would be effective at preventing cost-shifting?
“I think our task here is in no small measure updating direct access and this particular kind of customer choice to where the world is today and the realities that are unfolding before us. … We talk a lot about existing cost-shifting, but I worry about the future,” Tawney said.
From Cost-shifting to Risk-shifting
In comments filed ahead of the workshop, PGE asked the commission to consider the future potential for future “risk-shifting” in addition to historical concerns around cost-shifting.
Nidhi Thakar, PGE | Oregon PUC
Elaborating in the workshop, PGE Director of Strategy Nidhi Thakar offered an example of risk-shifting: the fact that IOUs must serve as “de facto” energy providers of last resort in cases when an ESS fails financially, foisting its customers back on the utilities.
“We just want to call out again that we really see a distinction between the terms ‘cost-shifting’ and ‘risk-shifting,’” Thakar said during the workshop. “There are … going to be risks that are quantifiable. We really do believe that there are risks that are going to be harder to quantify, which to the extent that they can be quantified, those numbers could continually be changing.
“The markets are constantly evolving and changing at a rapid pace in the West, and I think it’s important that there is some breathing room from the regulatory standpoint to readjust what some of these pricing mechanisms may look like that may potentially come out of this discussion.”
Etta Lockey, PacifiCorp | Oregon PUC
Etta Lockey, PacifiCorp vice president of regulation, seconded PGE’s take: “We don’t want to get hung up on not being able to take action now because a particular risk can’t be fully quantifiable or there’s not full evidence of an unintended consequence that is likely to happen in the future.”
Speaking for the Northwest & Intermountain Power Producers Coalition, which represents ESSes, attorney Carl Fink rebuffed the notion that the PUC’s proceeding should examine potential future risks for the IOUs.
“I don’t really believe that’s within the scope of what we can be doing here, nor do I think it’s appropriate to really be looking at some of the opportunity costs that may or may not occur to the extent that utilities lose market share,” Fink said.
Oregon PUC Chair Megan Decker | Oregon PUC
PUC Chair Megan Decker clarified her own thoughts about how to address potential opportunity costs for IOUs that could lose market share while still needing to maintain resource adequacy in their service territories.
“When I’m talking about that opportunity cost around meeting a flexible load in the grid, I’m very open to how that load comes to the table and participates. I think there’s a need, and I have an interest in how the ESSes might participate in that flexible future,” Decker said.
Fink also advocated for further expansion of direct access.
Carl Fink, Blue Planet Energy Law | Oregon PUC
“We do want to stress that, to the extent the commission is looking back at how we should be doing direct access, we always need to start with the statute, as we say in every one of our pleadings,” Fink said. “The statute puts requirements on the commission. It doesn’t ask the commission to decide whether direct access is supposed to be OK; it says you shall ensure direct access. And it says it needs to be direct access for all customers.”
Tawney expressed concerned that, under the current structure, “a sort of wall comes down” after an electricity customer converts to direct access, cutting it off from the mechanisms in the regulated sector, “even though these customers have some of the most flexible and most interesting — and most capable — on-site resources that might help us through our transition to a clean-energy, high-renewables-based grid.”
“There is a lot to be said for policy stability, but that means we need to set out boundaries or structures that will be resilient for how this future unfolds in the next decade, and that really requires thinking about the unexpected and setting up policies and structures that will manage those changes effectively,” Tawney said.
Tyler Pepple, Davison Van Cleve | Oregon PUC
Tyler Pepple, the attorney who filed the petition on AWEC’s behalf, asked whether the PUC would proceed under the presumption that direct access is in fact in the public interest.
Oregon PUC Commissioner Mark Thompson | Oregon PUC
“Is that the intention there, that we’re sort of assuming that direct access is in the public interest because it’s required by statute, or do you think that it’s important for the parties to present evidence on the benefits of direct access and whether that would be helpful?” Pepple asked.
Commissioner Mark Thompson said he didn’t think the PUC is being asked to consider whether direct access is in the public interest because state law has already established the program.
“I guess where I think the public interest question enters into it for us is with respect to how do we implement the statute’s guidance that we’re supposed to protect against unwarranted cost-shifting; and I do think the statute clearly contemplates us having a role there to put potential limits or guidelines on how that program is implemented,” Thompson said.
SPP staff are working feverishly to address FERC and Market Monitoring Unit concerns that threaten the launch of its Western Energy Imbalance Service (WEIS) market.
FERC last month rejected the RTO’s proposed Tariff for the market, saying it failed to respect nonparticipants’ transmission rights and could improperly burden reliability coordinators. The commission also cited shortcomings on supply adequacy, market power protections and line-loss calculations (ER20-1059, ER20-1060). (See FERC Rejects SPP’s WEIS Tariff.)
On Aug. 3, SPP’s MMU posted a report on a WEIS market study that found “high potential” for structural market power. The Monitor concluded that the WEIS presents “significant structural market power concerns” for energy and imbalance energy that should be addressed before its implementation.
SPP’s regulatory and legal departments are working to revise the Tariff for another filing in early September. Staff have met with the region’s nonparticipants to understand and address their concerns and then fold them into the next filing. They plan to meet with FERC staff in September to lay out a plan for moving forward.
The WEIS working group and executive committee last week passed four revision requests (WRRs) responding to the FERC and MMU issues. Those groups have scheduled two joint meetings this week to hammer out additional WRRs needed to finalize the filing.
Market Design Manager Gary Cate said he is still confident SPP can meet a Feb. 1 deadline for launching the market.
“I think we’ve put together a really good package and minimized changes to everyone’s system involved, and I think we’ve hit directly at what the FERC’s recommendations are. I don’t see why we can’t move forward,” Cate told the Western Markets Executive Committee during its meeting Friday.
David Kelley, SPP’s director of seams and market design, noted that the commission provided specific guidance to help staff respond to the filing’s deficiencies.
“This order was really a good order for us,” he said. “When you read through it, it was very complimentary of our efforts and recognized the benefits of markets being developed in the West. I got the sense the commission was encouraging us to continue developing the WEIS market and address the issues they noted in the order.
“We will know where we stand after meeting with FERC in September,” Kelley said.
The WMEC and Western Market Working Group’s approved revision requests last week included WRR5, a response to FERC’s assertion that there was a lack of justification for automatic increases to market mitigation thresholds and the MMU’s concerns over market power.
SPP based its proposal on its Integrated Marketplace market power mitigation provisions, where it automatically applies mitigation measures to resource offers if the offer exceeds applicable thresholds and fails the market impact test.
The change expands the local market power test to include an assessment of structural market power at the system level. It also “appropriately” mitigates the energy offers when a resource has system-level structural market power and an energy offer curve that exceeds the conduct test threshold, when an impact test has failed for that market interval.
MMU Executive Director Keith Collins said the Monitor “fully supports” WRR5, which borrows from a similar ISO-NE mechanism.
MMU Director Keith Collins shares his thoughts on the WEIS market power study. | SPP
“We think it’s a good alternative,” he said.
The Western markets governance groups also approved three other WRRs:
WRR2: updates the WEIS protocols to be consistent with SPP’s system change process and modifies the emergency change language to clarify that the RTO will notify stakeholders of the change as soon as practicable.
WRR3: aligns the WEIS protocols to the Tariff, and documents the changes for the WRR process.
WRR4: corrects a calculation of the lower operating tolerance for underground residential distribution (URD) and clarifies language expanding URD tolerance during contingency reserve events.
The WEIS currently includes eight members and covers the Western Area Power Administration’s Western Area Colorado Missouri and Western Area Upper Great Plains West balancing authority areas. Several other Western utilities are interested in participating as well, SPP has said.
Market participants are currently undergoing structured testing of SPP’s upstream systems. They are testing data inputs in certain scenarios to ensure they act as expected.
Utilities in seven Southeastern states could cut their electric rates by more than a quarter and reduce greenhouse gas emissions by almost half by joining an organized wholesale market, according to a study by a clean energy think tank.
The study by Energy Innovation Policy & Technology compared the use of utility-specific integrated resource plans (IRPs) with an RTO Scenario, which chose the most economical resources, optimized dispatch to minimize cost, and co-optimized transmission and distribution planning and regionwide reserve sharing. The results were based on a combined production-cost and capacity-expansion model of the electric power system in Alabama, Florida, Georgia, North Carolina, South Carolina, Tennessee and the non-MISO portion of Mississippi.
It projected cumulative economic savings of about $384 billion for the RTO Scenario compared to the IRP Scenario. By 2040, researchers say, retail rates would average 2.5 cents/kWh, or 29% less than current costs (adjusted for inflation).
The researchers also project a 37% reduction in carbon emissions compared with 2018 levels, and a 46% reduction compared to the IRP Scenario. They said the RTO Scenario would create 285,000 more jobs than the IRP Scenario, thanks to the construction of 62 GW of solar, 41 GW of onshore wind and 46 GW of battery storage.
The study projects cumulative savings of about $384 billion for the RTO Scenario compared to the IRP Scenario. By 2040, researchers say, retail rates would average 2.5 cents/kWh (29%) less than current costs (adjusted for inflation). | Energy Innovation Policy & Technology
Energy Innovation’s online data explorer allows readers to review the impact of a Southeast RTO on the region’s fuel mix, emissions, jobs and costs by region and state.
The study is the latest of several recent initiatives looking at the Southeast’s alternatives to the current vertically integrated model. Legislators in the Carolinas have proposed studies on creating an RTO and about 20 utilities and cooperatives in the region — including Duke Energy, Southern Co. and Tennessee Valley Authority — are discussing a voluntary 15-minute energy market, the Southeast Energy Exchange Market (SEEM). (See Southeast Utilities Talking Regional Market.)
Last September, Santee Cooper’s largest customer joined PJM in the wake of the South Carolina-owned utility’s abandoned plans to build a new unit at the V.C. Summer nuclear plant. (See South Carolina Power Cooperative Joins PJM.)
“Despite the fact that new renewable energy and battery storage resources are the least-cost forms of generating electricity, the Southeast region is largely beholden to monopoly utilities that rely on existing coal fleets and new gas-fired power plants to meet consumer electricity needs,” Energy Innovation said. “Policymakers considering a regional market or state-level competitive procurement should be encouraged by this analysis to keep pressing in legislative and regulatory forums. State stakeholders where utilities block competitive reforms now have new quantitative findings to challenge the assumption that the way utilities have traditionally done business is in the public’s best interest.”
Asked to respond to the findings, Duke spokeswoman Erin Culbert said Monday that the utility has “been advancing a clean energy transition for more than a decade” and doesn’t “need to wait for an RTO.”
“Duke Energy customers already enjoy many of the benefits RTOs claim to bring because of our large geographic size and generation diversity,” she added. “The energy market we’re considering would enhance that and better integrate renewables at a much lower cost than an RTO.”
TVA spokesman Scott Fiedler said, “It would be inappropriate to comment on a study that we did not participate in, nor had the opportunity to review the underlying data used to develop the conclusions.”
Officials of Southern Co. did not immediately respond to requests for comment.
Region Resistant to Renewables
Energy Innovation describes itself as a nonprofit energy and environmental policy firm funded by foundations and philanthropic donors that support decarbonization and climate policy. For the study, Energy Innovation used a model from Vibrant Clean Energy, which was supported by funding from the Hewlett Foundation.
The firm says ratepayers in the Southeast are missing out on the economies of a regional market because their monopoly utilities plan their grids and generation needs independently from their neighbors — including subsidiaries of the same holding companies — and discourage competition by imposing wheeling charges on imports. “Largely insulated from meaningful forms of competition, Southeastern utilities have been among the slowest to embrace clean electricity resources, even as resource costs have fallen precipitously in recent years,” it said.
About 92% of the region’s coal capacity was uneconomic compared to local wind or solar as of 2018, the researchers said. “By 2025, that number grows to 100%.”
About 92% of the Southeast’s coal capacity was uneconomic compared to local wind or solar as of 2018, according to Energy Innovation Policy & Technology. By 2025, all coal will be uneconomic, the group says. | Energy Innovation Policy & Technology
The study did not include any carbon constraints and also did not imply a market design. “This is not PJM’s RTO. This is not MISO’s RTO. It is a technical optimization of costs based on one single regional grid,” coauthor Michael O’Boyle, Energy Innovation’s electricity policy director, said during a press briefing Friday.
The RTO model used a single planning reserve margin for the region, eliminating the inefficiencies of serving loads on a state-by-state basis in the IRP Scenario. It did not optimize transmission and dispatch with neighboring PJM and MISO, however.
Energy Innovation said its model represented the maximum benefits of competition, noting that some markets allow vertically integrated monopolies to continue recovering costs of generation from captive customers. “RTOs today also face structural and political barriers to transmission development and fair cost allocation, distribution optimization, and clean or distributed energy resource participation,” the researchers noted.
The researchers also acknowledged that the IRP Scenario is likely to differ from utilities’ ultimate 2040 mix because the 10- to 15-year IRPs are updated periodically. “Hopefully, as utilities and their regulators catch up to the reality that clean electricity is less expensive than the status quo, it is reasonable to assume the inefficiencies won’t be quite as stark as the modeling implies,” they said. “Nevertheless, we model the current IRPs to demonstrate how current utility plans … open up customers to financial risk from potential stranded assets.”
A Southeastern RTO would add increasing amounts of renewable generation, replacing coal and natural gas selected under utility integrated resource plans, according to Energy Innovation Policy & Technology. | Energy Innovation Policy & Technology
Additional Scenarios
The study also looked at two additional possibilities, including the Economic IRP Scenario, which includes a cost-optimal resource mix — reflecting competitive procurement within existing monopoly service territories — but without the co-optimized transmission and reliability planning in the RTO Scenario. It would save $298 billion through 2040 compared to the IRP Scenario — about three-quarters of the savings of the RTO Scenario.
“This recognizes the reality that full regionalization may be politically infeasible in the near to medium term but shows that a majority of the cost savings can still be achieved by subjecting utility procurement plans and existing generators to market competition,” Energy Innovation said.
The study looked at four scenarios. | Energy Innovation Policy & Technology
The RTO with Nuclear Scenario adds to the RTO Scenario the assumption that all existing nuclear plants extend their licenses and remain operational through 2040, regardless of cost-competitiveness — essentially assuming they would be kept in service through subsidies such as those enacted in Illinois, New Jersey and New York.
It would save about $375 billion through 2040, $9 billion less than the RTO Scenario but with a 41% cut in emissions below 2018 levels compared to a 37% drop in the RTO Scenario.
Reduced Reserve Margins
The RTO Scenario rationalizes transmission planning to reduce congestion and allow load pockets access to cheaper generation. It realizes about 10% of cumulative savings ($38 billion) from co-optimized distribution system planning that uses behind-the-meter generation and storage when it reduces total system costs.
The IRP Scenario would result in a reserve margin over 40% by 2040, according to the study, far above the 16% margin for the RTO Scenario. | Energy Innovation Policy & Technology
“This co-optimization of bulk and small-scale resources helps reduce peak load in the RTO Scenario 11.8% below the IRP Scenario, creating savings from generation all the way down to distribution,” the study says. “Realizing these savings goes beyond reforming the market structure for the bulk power system and likely requires regulatory incentives at the distribution level to coordinate with a central RTO.”
The researchers say the IRP Scenario would result in a reserve margin over 40%, resulting in more jobs in unnecessary coal and gas plants. “Utility IRPs in aggregate are redundant and excessive on their own, but when taking a regional view where significant efficiencies could be obtained by sharing reserves, the waste becomes more apparent,” the researchers said. “Utilities are rushing to build new gas generation that increases their earnings while planning to hold onto uneconomic coal generation for decades longer than economics would dictate.”
The RTO Scenario assumes a 16% reserve margin in 2040. Nevertheless, Energy Innovation says, “By 2040, the RTO Scenario leads to an additional 408,000 jobs in the sector, compared to just 122,000 new jobs in the IRP Scenario, a net of 285,000 jobs.”
Emissions
The study notes that Duke and Southern Co., which represent 45% of retail sales in the Southeast, have pledged net-zero company emissions by 2050. But it says, “a competitive market with no carbon policy does a better job of reducing emissions than Duke and Southern’s efforts.”
“Vertically integrated utilities’ incentives to maintain and earn on existing infrastructure conflicts with both customer wellbeing and environmental goals. … Regional transmission and operational approaches are more effective at integrating high shares of renewable electricity, and Duke and Southern hamper their own efforts to decarbonize at least cost by resisting regionalization efforts,” the researchers said.
The IRP Scenario adds little renewable generation or battery storage, while the RTO Scenario adds large amounts of wind and solar PV, including distributed PV, and utility-scale and distributed storage, with most gas peakers retiring by 2040.
Most generation would remain fossil fuel by 2040 under the IRP Scenario. “In the IRP Scenario, there is almost no wind generation, and solar PV provides just 4% of annual generation. In contrast, wind and solar provide 22% of generation in the RTO Scenario; when aggregated with nuclear (20%), geothermal/bioenergy (5%) and hydropower (4%), 51% of the Southeast fleet is zero-carbon by 2040.”
Other pollutants, including NOX, SO2 and PM2.5, also would be reduced by the elimination of coal-fired generation, the researchers say.
Endorsement
During the press briefing Friday, the Renewable Energy Buyers Alliance, which represents more than 120 major corporate purchasers, endorsed the call for regionalization and suggested the region’s competitiveness is at stake.
Bryn Baker, Renewable Energy Buyers Alliance | REBA
“More and more businesses are setting [clean energy] goals. They’re making decisions about siting and expanding facilities based on access to renewable energy,” said Bryn Baker, REBA’s director of policy innovation. “Right now, many parts of the country, including the Southeast, their only option is often a green tariff through the existing utility, which can often be limited.”
Baker said full regionalization offers savings “10-fold higher than anything that’s being contemplated now” in the region, including SEEM.
Michael O’Boyle, Energy Innovation | Energy Innovation Policy & Technology
“There are so many details that need to be filled out that it is a little bit premature to say, ‘the SEEM is x.’ We just don’t know exactly what it’s going to be,” O’Boyle said. “There doesn’t appear to be an agreement to use transmission without those wheeling charges, so … unless there’s an open transmission agreement, there’s still going to be unnecessary costs and a lack of optimization across the region.”
Duke’s Culbert said the SEEM would be much cheaper and faster to create than an RTO, “meaning energy customers in the Southeast would see real benefits much sooner.”
“Participating in that would not prevent any of the companies from participating in an RTO in the future. From our perspective, we don’t see RTOs as the right solution for Duke Energy customers in the Carolinas at this time. We’re currently in the phase of engaging with stakeholders on SEEM and are working through their questions and feedback as we continue to formulate the concept.”
Many utilities in the Western Interconnection continue to use outdated models for their solar and wind generation resources, or none at all, despite warnings about their reliability, according to a joint report issued this week by NERC and WECC.
The report, “WECC Base Case Review: Inverter-Based Resources,” is based on a review of steady-state power flow data posted to the regional entity’s website in May. NERC and WECC undertook the review as part of their ongoing efforts to address shortcomings in inverter-based resource modeling discovered following the Blue Cut Fire of 2016 and the Canyon 2 Fire of 2017, both in California.
The 2016 incident led to about 1,200 MW of solar photovoltaic resources tripping offline or momentarily ceasing output, while Canyon 2 resulted in about 900 MW of solar output tripping or momentarily ceasing. NERC issued alerts following both disturbances seeking information from registered entities on solar generation in their footprints and how they plan for the loss of resources. (See NERC Chief: Inverter, Fuel Assurance Standards Needed.)
Helicopters fighting the Blue Cut Fire in 2016. | San Bernardino County Sheriff’s Department
Information from the alerts — particularly the Canyon 2 alert, which focused on modeling issues — was used by NERC’s Inverter-based Resource Performance Task Force (IRPTF) in a technical report earlier this year to describe the challenges that utilities and inverter manufacturers face with “ensuring the models used to represent [inverter-based] resources … sufficiently represent [their] actual behavior.”
The new report aims to highlight some of those resources in greater detail, focusing on the Western Interconnection because of the “large concentration” of bulk power system-connected solar and wind generators in the region. The two accounted for 17% of overall generation capacity in May, with instantaneous penetration of such resources rising over 50% in CAISO’s footprint.
In addition, the study is intended to help the WECC Solar Modeling Advisory Group, which was formed last year to help transmission planners and planning coordinators in the Western Interconnection improve their modeling activities but has made little progress, citing a lack of reliable data.
Outdated, Inaccurate Models Persist
In their analysis, NERC and WECC found that a significant amount of inverter-based resources used improper or insufficient models. The issues were particularly widespread among wind resources, with only 27% of wind plants modeled using regc_a, the most up-to-date renewable energy model; 36% use the outdated wtXg models; 17% use the genrou model intended for synchronous generators; and 12% have no model in place at all. The remaining 8% use other models.
The situation is better on the solar side, where about 66% of generators — representing 82% of overall solar generation capacity — use the regc_a model and only three out of 414 generators use genrou. However, 8% of all solar plants still use the wt4g model, and 20% have no models. Other models account for the remaining 5% of solar plants.
In addition, use of the latest model is no guarantee of accurate results. NERC and WECC’s solar study revealed that 95% of facilities that use the regc_a model are using the reec_b electrical controls model, which was previously recommended by WECC but was replaced by the reec_a model last year. The organizations said that using the appropriate electrical controls model in conjunction with regc_a is “critical for accurately modeling solar PV resources.”
Dynamic models used for wind (left) and solar (right) generators in the WECC base case | NERC
Similarly, many of the wind generators that use the latest model may still have issues arising from incorrect parameterization. NERC and WECC found a number of units — including several of those using the regc_a and the “vast majority” of those using outdated models — in which parameters are still set to the default values indicated in the user manual. Additional units have matching parameters, though not those from the manual. The widespread use of matching parameters indicates that the units were programmed with generic values rather than being individually calibrated.
In response to the issues uncovered in the analysis, NERC and WECC said utilities’ highest priority should be updating their dynamic models to the latest version, in order to ensure the highest quality data is provided. In addition, transmission planners and planning coordinators should verify that parameters “match the as-built controls, settings and configuration of the equipment installed in the field” prior to providing the models to WECC for inclusion in its database.
Portland General Electric said Monday that it suffered $127 million in losses from wholesale electricity trades because of recent volatility in the California energy market — a figure that is almost certain to rise.
PGE estimates the losses could undercut its 2020 earnings by as much as 48%.
“Certain PGE personnel entered into a number of energy trades during 2020, with increasing volume accumulating late in the second quarter and into the third quarter, resulting in significant exposure to the company,” CEO Maria Pope said in an email to employees included in a filing with the U.S. Securities and Exchange Commission. “Simply put, these trades were ill conceived.”
“As a result of the convergence of these conditions, the company’s energy portfolio, as of Aug. 24, 2020, has experienced realized losses of $104 million and unrealized, mark-to-market losses of $23 million,” PGE said. “Total third-quarter losses in the portfolio are estimated to be up to $155 million subject to market conditions — although the ultimate amount of losses could exceed that amount.”
PGE on Monday moved quickly to contain potential political damage from the incident, saying it had placed two unnamed staff members on administrative leave pending further review. It also assured customers that it would not seek to recover the losses through increased rates.
PGE wind farm in Eastern Oregon | Sherman County Government
The utility also announced the formation of a special committee consisting of five independent board members to examine the events leading to the losses and review existing procedures and controls. The company has additionally engaged external consultants “to perform a full operational review of our energy supply risk management policies, procedures and personnel,” Pope said.
She also said the company would not be adjusting its 2020 and 2021 capital and operational budgets and assured employees that “we do not anticipate any layoffs as a result of this situation.”
“This situation is not reflective of who we are at our core, and we will learn from the situation and make the necessary changes to ensure this will never happen again,” Pope said.
Black Swan?
While PGE has not disclosed the exact cause of the losses, their sheer size — and the utility’s response — suggests the trading activity leading to the losses fell outside expected norms.
“The way Pope worded it — ‘ill-conceived’ — makes me think it’s something nonstandard,” said a compliance analyst with another Northwest utility who asked not to be named.
The analyst also questioned how traders could build up such exposure under a standard protocol of daily trading and position limits.
“I know we have significant risk controls. But I don’t really know what kind of trading led to the losses,” the analyst said.
Portland-based energy economist Robert McCullough pointed to the potential impact of CAISO’s convergence bidding market on PGE’s trading woes.
“The nature of a relatively unregulated pure derivative — like the convergence market in California — has an enormously asymmetric risk profile. In English, this means that a prudent trade, on rare occasions, can lose 50 times the expected profit,” McCullough said.
He said CAISO’s suspension of convergence bidding during the heat wave — right after the declaration of a Stage 3 emergency — indicates that market losses were high at the time and that manipulation was a possible explanation.
“PGE is hardly a high-risk trading operation,” McCullough said. “A regional utility with substantial assets, they traditionally ‘trade around assets.’ I would suspect that the natural asymmetry of a black swan caught them off guard.”
Even CAISO officials seem aware of the potential for convergence bidding to produce a “black swan” trading event.
During a CAISO stakeholder call Aug. 21 to discuss the recent blackouts, ISO Director of Market Analysis and Forecasting Guillermo Bautista Alderete said convergence bidding can add confusion to the market in times of short supply because convergence bids and physical supply are cleared on the same basis.
When there’s sufficient capacity and supply, “the positions taken in the day-ahead market can be supported. However, when the system is constrained … the position parties can take can result in chaos,” he said.
New York officials on Monday discussed recently proposed statewide greenhouse gas limits of 60% and 15% of 1990 emissions for 2030 and 2050, respectively.
The new methodology for estimating the emissions in 1990, as set out by the Climate Leadership and Community Protection Act, include upstream emissions in the calculation, meaning the baseline increased by 70%, Jared Snyder, deputy commissioner of the Department of Environmental Conservation (DEC), told the New York State Climate Action Council (CAC).
“It increases the starting point for calculating those 40% and 85% emission reductions,” Snyder said. Statewide GHG emissions in 1990 totaled 401.38 MMT of carbon dioxide equivalent, which under the proposed rule translates into 240.83 MMT allowed a decade from now, and 60.21 MMT at midcentury.
Total NY greenhouse gas emissions in 1990 by sector and gas, in MMT CO2e, as estimated by the New York DEC | NY DEC
The CLCPA directs the DEC to set greenhouse gases on a common scale using the CO2e metric and the 20-year global warming potential of each gas, as derived from the U.N.’s Intergovernmental Panel on Climate Change. In calculating the proposed limits, the DEC interpreted the statute as focusing on gross emissions, Snyder said.
Administrative Law Judge Molly T. McBride will conduct two public comment hearing webinars for the proposed rule on Oct. 20, and public comments will be accepted by the DEC until Oct. 27.
CAC’s Role
CAC member Robert Howarth, Cornell University professor of ecology and environmental biology, brought up the question of the council’s role in drafting the proposed emissions limits.
The NY State Climate Action Council met via webinar Aug. 24. | NY DPS
“My reading of the CLCPA says that the DEC and the New York State Energy Research and Development Authority, in consultation with the Climate Action Council, will develop these guidelines,” Howarth said. “I appreciate that I as an individual have been able to talk to you [Snyder] and staff, and I will certainly give written comment in the hearing, but so far I haven’t seen any real role for the CAC here other than the fact that we are getting these briefings.”
On the quantification of methane emissions, Howarth said he had just recently published a peer-reviewed paper on the topic. He said he believed the DEC team did a better job in some parts, but that he did better on others, and that there should be a way to reconcile those differences.
“Specifically, I very strongly believe that we should use a top-down approach when we can … for the 1990 baseline,” Howarth said. “What is the role for the council here? What does it mean for these numbers to be developed in consultation with the council?”
Paul Shepson, Stony Brook University | NYDPS
Snyder replied that the DEC consults with council members and considers their input, but that any rulemaking decision has to be based on the record. He encouraged anyone interested to submit written comments.
“Our understanding of the actual emissions, particularly for methane, is a rapidly developing field in the scientific community, and my concern is whether we are effectively carving in stone the emissions limits at the end of October … so the opportunity for input is relatively urgent,” said Paul Shepson, dean of the College of Marine and Atmospheric Sciences at Stony Brook University.
He asked, for example, how the DEC would respond if at some point in the future the scientific community’s understanding of 1990 emissions changes dramatically.
“The limits we establish now are not necessarily written in stone forever,” Snyder said. “If there are further developments that cause us to question the accuracy of those emission limits, there is nothing to prevent us from undertaking another rulemaking to amend them.”
Just Representation
Meeting for the second time this summer, the CAC also approved member rosters for a Just Transition Working Group and six advisory panels that will collectively prepare a scoping plan by next fall for the council’s mission to help the state achieve its clean energy and climate agenda. (See NY Climate Action Council Looks at Deep Decarbonization.)
Anne Reynolds, ACE NY | NYDPS
The panels include representatives from public, private, academic, environmental and community groups and cover six different economic sectors: agriculture and forestry; energy-intensive and trade-exposed industries; housing and energy efficiency; land use and local government; power generation; and transportation.
“Two of the most controversial and important issues with renewables are connected with agriculture and community acceptance and support of renewables,” said Anne Reynolds, executive director of the Alliance for Clean Energy New York. “I would just plant the seed that if it’s decided that the agriculture and forestry panel is going to tackle the issue of solar interacting with ag-land, then there should be a representative of the solar industry in that group, and the same with land use and local government.”
Gavin Donohue, president and CEO of the Independent Power Producers of New York, said he was surprised and disappointed that the power generation panel had no utility representatives, as the statute says the panel should include regulated industries.
“You can’t generate electricity and not have a utility deliver it to its customers,” Donohue said. “And while I see someone from National Grid on the energy-intensive and trade-exposed industries panel … it’s an oversight that the generators are not on that panel.”
Several members of the 22-member CAC emphasized the importance to all its proceedings of public comment, especially from environmental justice communities.
Peter Iwanowicz, executive director of Environmental Advocates of New York, said he was pleased to see representatives of the environmental justice community included on panels. “They fought pretty hard to make sure that the offset program is fairly constrained in [power generation], and I think they’re going to have valuable input.”
Doreen Harris, NYSERDA | NYDPS
Council co-Chair Doreen Harris, acting CEO of NYSERDA, agreed, saying that environmental justice representation throughout the panels is not only important, but significant.
“We want to make sure that the advisory panels’ primary work is to identify recommendations for our consideration through the spring of next year, and then we as a council will integrate the input and consider it as part of the statewide strategy we will be advancing,” Harris said.
Basil Seggos, NY DEC | NYDPS
Clean energy advocate Raya Salter lauded the representation of environmental justice groups but questioned the lack of local elected officials on a proposed working group to estimate waste management emissions.
“I’m concerned because solid waste management seems a key area for direct stakeholder representation,” Salter said.
Co-Chair and DEC Commissioner Basil Seggos said that the council “would certainly entertain” proposals to structure the working group to ensure full public input.
Memphis Light, Gas and Water took another step away from the Tennessee Valley Authority last week as staff recommended the utility issue its first ever request for proposals for new energy sources.
MLGW staff made the recommendation to its Board of Commissioners at a Wednesday meeting after conducting a yearlong review of resource alternatives to TVA.
The utility could begin the RFP process in October, with approval from its board and the Memphis City Council. The MLGW board and the city council meet every two weeks. Neither entity has announced an intention to hold a vote on the matter.
MLGW President J.T. Young announced that the utility will hire a consultant to help manage the bidding process. Young was also clear during the meeting that MLGW had not yet decided whether it would depart TVA.
Earlier this year, the city-owned utility said it was eyeing MISO membership or joining another wholesale supplier as a more economic alternative to TVA, its electricity provider for 81 years. (See Memphis Muni Mulls Move to MISO.)
MLGW currently accounts for about 10% of TVA load and pays about $1 billion a year for power. To split with the federally owned corporation, Memphis would likely procure some of its own resources and look to a new wholesaler for the rest. MLGW doesn’t currently generate any of its own electricity.
Memphis riverfront | TVA
“This historic decision sets up MLGW to provide more value to customers in Memphis and be a national leader on clean energy,” Southern Alliance for Clean Energy (SACE) Executive Director and MLGW adviser Stephen Smith said in an emailed statement. “By seeking bids on alternative power supplies, the people of Memphis … will lock in lower-cost and cleaner, more efficient energy, giving Memphis more control of its own future. This also serves as a significant ‘shot across the bow’ to TVA that MLGW is setting the stage to break loose from TVA’s dictatorial long-term contract arrangements.”
An MLGW-commissioned Siemens study found that certain combinations of self-supply and MISO wholesale market offerings could save Memphis about $150 million per year from 2025 to 2039, while cutting carbon emissions by as much as 50% by 2030.
TVA said it “respects and supports” the utility’s decision to explore an RFP from alternative suppliers, though it touted itself as the better option over self-supply and the markets across the Mississippi River.
“We are excited about the opportunity to engage in the RFP process — to put the facts on the table — and prove that TVA in partnership with MLGW is the best option for the people of Memphis and Shelby County,” TVA said in a statement. “When it comes to energy costs, Memphis starts from a position of strength. In partnership with TVA, MLGW today provides the third-lowest energy costs in the nation among its peers. TVA’s commitment is to keep energy costs stable over the next decade.”
MLGW said its electricity rates are competitive when compared to other major U.S. cities.
Citizens have said a parting with TVA would bring desperately needed affordable energy to Memphis, where about a third of its residents live at or below the poverty line.
“In the past, and especially now during the COVID-19 pandemic, I see parents being forced to decide between paying to keep the lights on or buying medicine or shoes for their kids. That’s not how it should be in the future, when Memphis buys or produces its own power and takes control of its own power supply,” Pearl Eva Walker, an organizer with grassroots social justice group Memphis has the Power, said in a press release.
SACE has recommended that MLGW issue two RFPs: one for a large-scale energy-efficiency program on a five-year horizon, creating savings as the municipality navigates leaving TVA, and another for clean resources and supporting infrastructure beyond a five-year horizon.
MISO’s Advisory Committee is on a tight schedule to redesign the RTO’s sector setup.
The committee met virtually Wednesday to discuss possible design elements, a month after FERC said MISO’s creation of the Affiliate sector as a repository for new difficult-to-define members was fair only on a temporary basis.
FERC approved the sector late last month but gave MISO until March 2021 to work out a more permanent member-sorting process and representation model that affords full participation to all members. The commission said the RTO should be swift in forming a long-term equitable solution and said it would investigate the arrangement if left unrevised, a warning that had Commissioner Richard Glick crying foul. (See New MISO Sector Gets FERC OK — with a Catch.)
The Affiliate sector currently contains North Dakota coal-lobbying group Lignite Energy Council, coal trade organization America’s Power, and several chambers of commerce and mining organizations. It also contains conservative lobbying group Center of the American Experiment and sustainability and conservation trade association Minnesota Forest Industries.
The AC is now asking whether the new sector should be allowed to vote on recommendations to the MISO Board of Directors. The sector cannot vote for the time being, but it can offer opinions during discussions with the board during the committee’s quarterly meetings.
The Union of Concerned Scientists’ Sam Gomberg said he would be concerned if MISO discussions took a more political turn. He said the RTO has historically been very good about minimizing politics in its guided policy conversations.
Lignite Energy Council headquarters in Bismarck, N.D. | LEC
Some AC members argued that the Affiliate sector’s miscellaneous status means that members would not reach enough of a consensus to cast votes. Others said all MISO sectors should have a vote.
“Voting is more de minimis and often a rarity. We do a lot of things by consent,” AC Chair Audrey Penner said. “When we do vote, we’re voting on pretty important issues.”
AC votes are nonbinding and advisory in nature to the board and MISO staff.
The committee has already decided the board will have the final say in creating new sectors and MISO will be the final arbiter when a disagreement occurs over whether an organization is a good fit for a certain sector. Sectors must also establish their membership criteria and post them on the public MISO website. (See MISO Members Make 1st Rules on Sectors.)
The AC is now asking if it should consolidate some of its 10 other existing sectors. With 11 sectors, MISO has more than any other RTO or ISO. The committee is asking how many is too many.
Independent Power Producers and Exempt Wholesale Generators sector representative Travis Stewart said the sheer number of people participating can make the AC’s quarterly “hot topic” discussions before the board chaotic. He said a more structured discussion with fewer representatives per sector could yield more streamlined discussions.
Some members said sectors don’t need to be thinned or merged; instead, they need more face time with the board. A few proposed that sector representatives form a liaison committee to the board in order to get more access to and interaction with it.
“MISO does have a very different access to the Board of Directors. And this is my personal view: It’s much more controlled,” said Beth Soholt, representative of the Environmental and Other Stakeholder Groups sector. “Other RTOs have unfettered access to their boards.”
