NERC will begin testing the newest version of its situational awareness tool in mid-November, which will add the ability to integrate transmission feeds with other sources such as real-time weather station data and radar.
Situational Awareness for FERC, NERC and the Regional Entities (SAFNR v.3) was piloted in 2017 during GridEx IV. It is being developed by ResilientGrid, an Austin, Texas, firm headed by Michael Legatt, who holds doctorates in both energy systems engineering and clinical health psychology/neuropsychology.
That unusual pairing of disciplines helps explain the idea behind SAFNR v.3, he told NERC’s Operating Reliability Subcommittee on Sept. 4.
“At a high level, the philosophy that drives the work we do and the tools we build are that the most important components on the grid are now — and will always be — human beings in the control room and the field,” he said.
Image from ResilientGrid Operating System showing Hurricane Michael in 2018 | ResilientGrid
“Under high-stress situations, when people collaborate — especially from adjacent infrastructures or different control rooms — if they’re looking at different pictures, the likelihood of human error goes up pretty significantly, especially under the times of the most profound stress. So, this tool is part of a larger platform and our vision to support shared situational awareness and collaboration throughout the industry.
“Situational awareness requires two things that the human brain cannot do at the same time: scanning and focusing. Often you have loss of situational awareness when people are focused on one thing and tend to … miss either a threat or opportunity” while attempting to also scan, Legatt said.
“Things that you’ll often find in control rooms — from the NERC and [Information Sharing and Analysis Center] level to the [reliability coordinators] down to the [transmission operators] and [distribution service providers] — all of these entities tend to have lots of different screens and monitors, and operators will look back and forth. But when you integrate [the sources] together, you start to see the impacts of these relationships. … By building a common integrated view, we’re able to significantly increase the effectiveness and speed of collaboration and reduce some risks of human error.”
The system was piloted with FERC, NERC and the Electricity Information Sharing and Analysis Center (E-ISAC) and used by E-ISAC and NERC Bulk Power System Awareness operators to track the progress of GridEx IV in 2017.
Exercising what he called “continuous improvement,” Legatt said his company plans to upgrade the system regularly. “The most important thing we build is really the relationship with the industry,” he said.
For example, he said GridEx led NERC and the E-ISAC to streamline their data entry for electric emergency incident and disturbance reports (Form OE-417) and EOP-004 event reporting forms.
James Merlo, NERC’s director of reliability risk management, said SAFNR v.2 replaced the original “rudimentary” tool in 2010. “It’s nine- or 10-year-old technology. It’s time to be re-platformed,” he said.
Merlo said the system will be based on raw Inter-Control Center Communications Protocol power flow data from RCs. That data can be overlaid with other data sources such as fires and weather.
“You can actually look at forest fires, transpose that with which way the wind is blowing and then … be a little more predictive to say: that fire is threatening that transmission line. It allows us to see all that without having to call individual entities.
“All of that data was available. You could turn this map on, and you could turn [that] map on, so you had to look at them all individually. This is now a holistic platform that allows you to create those layers so you can clutter or declutter as necessary to create situational awareness.”
VALLEY FORGE, Pa. — The Market Implementation Committee endorsed a PJMproposal on Wednesday to make demand response performance testing more realistic, resisting calls from load interests to stay close to the status quo.
Nearly 75% of stakeholders preferred PJM’s plan to replicate the “surprise element” of demand response events by revising how and when the RTO makes resources aware of upcoming tests. The current rules, developed when DR availability was limited to just six hours a day over the summer, give resources a two-day warning — down to the exact hour — and provides unlimited retesting.
Pete Langbein, PJM’s manager of demand response operations, said the RTO’s proposal — just one of five developed in the Demand Response Subcommittee and up for a vote at the MIC — would better align testing with actual event conditions and the evolution of its capacity performance construct over the last five years. Since implementing CP, DR resources must now be available 15 hours a day year-round.
High level overview of five proposals for demand response testing requirements. | PJM
“The status quo is less like an event,” Langbein said. “People schedule it far in advance and it’s only during summer. When we need these resources, they aren’t going to know a month in advance. They probably won’t even know the night before.”
In its proposal, PJM wants to perform three-hour tests in different zones once a year. The three-tiered notification system would give all zones a heads-up of who will be tested on the 21st of the month before. PJM will then give a second notification to the zone the day before the test and a third on the morning of — an attempt to balance the expensive penalties that could come from springing tests upon unprepared participants with the RTO’s desire for more realistic “surprise” conditions.
Load interests, however, believe DR is far more predictable than PJM’s proposed testing requirements suggest, noting 13 of the last 14 events since 2007 occurred during a hot weather alert.
“Test performance has always exceeded commitments and is in fact improving,” said Bruce Campbell, director of regulatory affairs for CPower. “That suggests to me a higher bar for testing isn’t going to get better event performance and there isn’t an obvious reliability issue here.”
The PJM Industrial Customer Coalition (ICC) and CPower sponsored another plan, called CSP1, that would expand testing to include winter and summer seasons but give resources notice of the test before the CP delivery year begins. They said limiting retests, as PJM suggests, skews the program’s balance and may discourage participation. In a poll distributed to the DR Subcommittee in July, 92% of participants favored this plan.
“We are supportive of CSP1 because it maintains the risk/reward profile and continues to make this a viable program for participants,” said Dave Mabry of the ICC. “If I have one bad day, I won’t lose 120% of my capacity revenue.”
Except, argues the Market Monitoring Unit (MMU), current test requirements could allow DR resources to exaggerate their capacity performance and hide reliability issues behind unlimited retests.
“If it takes you unlimited times, I don’t know if that’s a reliable resource,” said Skyler Marzewski, market analyst for the MMU. “It needs to be there when its being dispatched, otherwise it’s not reliable.”
The MMU’s proposal, which only garnered 25% of stakeholders’ votes, would have subjected resources to two tests a year and provided just two advanced warnings — the day before and the morning of — and allow just one retest. Of the five proposals, PJM’s Langbein described this plan as the closest to simulating DR conditions.
“We cannot really look at giving a resource days or weeks to prepare when an event may just give them 30 minutes,” Marzewski said.
Enel X stepped in with a fourth plan, called CSP2, as a compromise between PJM and CSP1, that would give participants one-week notice of an upcoming test. Some 53% of MIC stakeholders supported the proposal, compared to just 33% who voted for CPS1.
A second PJM plan that would have only given participants notification on the day before and the morning of earned just 15% support.
Since votes for PJM’s first plan and CSP2 exceeded the 50% threshold, both proposals will advance to the Markets and Reliability Committee later this month. In a non-binding poll conducted after the votes, 67% of stakeholders indicated they preferred PJM’s proposal over the status quo.
VALLEY FORGE, Pa. — PJM anticipates filing a GreenHat Energy settlement on Oct. 9 that staff says will avoid costly legal proceedings, signaling a possible end to months of uncertainty and confusion for stakeholders in the wake of the company’s massive default on 890 million MWh of financial transmission rights.
Jen Tribulski, PJM’s associate general counsel, told the Market Implementation Committee on Wednesday a meeting is planned for mid-October for stakeholders unable to participate in negotiations to have a chance to discuss the settlement terms before filing comments with FERC. (See FERC Denies Shell, ODEC Seat at GreenHat Settlement Table.)
“Based on all the feedback we’ve gotten so far, we think the settlement will be unopposed by all parties,” she said. “We think the settlement will help avoid litigation and the unintended costs and uncertainties that would extend from litigation.”
In June, FERC gave PJM stakeholders just 90 days to settle all disputes about how to best liquidate FTRs left over from the default before kicking off a paper hearing on the RTO’s request to clarify a previous ruling related to the debacle (ER18-2068). (See FERC: PJM Settle Disputes Before GreenHat Hearing.) On Monday, PJM confirmed a settlement in principle had been reached but declined to give further details.
It’s unclear how much the agreement will cost members, though PJM spokesperson Susan Buehler previously told RTO Insider that estimates had now dropped below $200 million — a far cry from the anticipated $430 million expense stakeholders would have faced if forced to unwind five months of GreenHat settlements as initially ordered in FERC’s waiver denial in January. (See FERC Orders PJMto Unwind GreenHat Settlements.)
Grid operators and generators need more granular, real-time data to respond to grid oscillation events, engineers on a NERC panel said last week.
Tim Fritch, Tennessee Valley Authority manager of reliability analysis, last week gave the Operating Reliability Subcommittee (ORS) new details on the Jan. 11 oscillation event, when a “misbehaving” steam unit in Florida sent the Eastern Interconnection rocking like an unbalanced washing machine for 18 minutes. The presentation was an update of one that Fritch, vice chair of the Synchronized Measurements Subcommittee (SMS), gave to the ORS in the spring. (See Panel: Action Needed in Response to Oscillation Event.)
It was at least the sixth such event since 1996, according to a NERC reliability assessment published in July.
SCADA data show the flow on a 500-kV tie line with Southern Co. fluctuating by 200 MW during the Jan. 11 oscillation event, which was caused by a malfunctioning generator in Florida. | NERC
In the January event, Fritch said, the plant operators knew their unit was malfunctioning but “didn’t know they were moving the grid.”
One of the voltage signals used for the power load imbalance controller was compromised and 30% below what it should have been, Fritch said. “So, the controller was opening and closing the inverter valve on the unit. And this was causing a local area oscillation at about 0.25 Hz. This excited a natural mode that we had identified in previous studies that was around 0.23 to 0.24 Hz. So, since the unit was oscillating at 0.25, it was exciting this natural mode that was in turn causing this resonance phenomenon.”
The resonance was felt from Florida to the Midwest and New England, with power swings of 200 MW around Florida and 50 MW around ISO-NE.
Fritch said the event highlighted the need for better diagnostic tools and training in what not to do in such events.
“If you take some units offline for these types of events, we know it could get worse,” Fritch said. “Units act as a shock absorber on the system to absorb some of the energy from these big grid oscillations. So, taking some units down could make it worse.”
Fortunately, the only unit taken offline was the Florida unit that caused it. But other utilities considered taking their units down or shutting off automatic generation control (AGC), Fritch said.
Need for Better Tools
Fritch said TVA and other utilities with oscillation detection tools can only see their own footprint. “This happened for a lot of utilities on the Jan. 11 event: We knew it was big because all of our oscillation tools went into alarm. It showed our PMUs [phasor measurement units] were seeing this oscillation. But we couldn’t see outside of our footprint,” he said.
“We’re pretty good at identifying when we have a local oscillation based off our oscillation tools. But when you have these big grid oscillations where you excite these natural modes, you need more visibility.”
TVA was one of the two utilities that took its generators off AGC. “We thought our units were misbehaving. It’s hard to tell sometimes whether you’re the leader or the follower of these events.”
Of 11 utilities that responded to a NERC survey about the event, seven agreed there is a need to develop both a PMU data-sharing requirement for reliability coordinators and a real-time regional oscillation and source detection tool. The same number agreed the SMS should identify and address gaps in existing reliability standards on RC-to-RC coordination.
Fritch noted Professor Yilu Liu, of the University of Tennessee at Knoxville, helped create a video visualizing the oscillation using FNET/GridEye, a GPS-synchronized, wide-area power system frequency measurement network that uses data from more than 200 frequency disturbance recorders — essentially PMUs — around the world.
The University of Tennessee at Knoxville operates 180 frequency disturbance recorders in the U.S. through its FNET/GridEye network. | University of Tennessee at Knoxville
“Maybe there’s an opportunity to make that a real-time application instead of a post-op,” Fritch said, adding the industry may need to increase the number of recorders. “In my mind, there’s not enough to give you great granularity down to the unit,” he said.
“That’s why the industry, with like the [Department of Energy’s] ESAMS [Eastern Interconnection Situational Awareness Monitoring System] program, has been looking at bringing all of the PMU data into some type of tool because it has much greater coverage than the frequency disturbance recorders that FNET uses.”
Thousands of PMUs were installed across North America in the last decade. ESAMS is using their data “and looking for these types of events to see how [they’re] affecting the grid and help identify the cause of the forced oscillation that’s exciting these natural modes.”
Training Needs
Chris Wakefield, of reliability coordinator Southern Company Services, said some plant operators in his company’s footprint thought their control systems were malfunctioning during the oscillation. “They were [ready to take] action — taking their units off AGC or doing something more drastic, like a nuclear plant may go into some type of protective mode,” he said. “How do you communicate to generator operators that that’s not probably what you want them to do?”
Fritch said there’s no “cookie cutter answer” but training would help.
“Maybe it’s coming up with better communication between generation owners and RCs for these types of events,” he said. “That’s something we need help with from the ORS and from the industry.”
Next Steps
NERC will hold a webinar 2-3:30 p.m. ET on Friday to discuss the Jan. 11 event and the recently published Interconnection Oscillation Analysis report on the oscillatory behavior of the Western, Texas and Eastern Interconnections.
“I feel like we’re headed in the right direction. It seems like … the consensus is that NERC believes there needs to be some type of tool or application and guidance on how to handle these in the future,” Fritch said. “I know what we experienced was bad, but it could have been worse if those forced oscillations, instead of being 0.25, were around 0.23 or 0.24, or the unit was bigger. This was a 25-MVA unit. What if it were a 1,000-MVA nuke plant that was doing this?”
Members of the Operating Reliability Subcommittee (ORS) last week appeared to reach consensus on the need for an emergency conference call procedure for reliability coordinators to supplement the existing NERC hotline.
John Norden, director of operations for ISO-NE, shared a draft of the procedure with the committee before the meeting.
“This is something independent of the NERC hotline procedure. It’s for those situations like what we had in the January [oscillation] event where it might not be appropriate for the operators to get on a NERC hotline call and have a discussion because either they’re too busy taking a tactical response to what’s going on [or] we need a more strategic discussion that might involve management staff at the [reliability coordinator] level.”
Norden said the procedure would include a roster of primary and alternate contacts for the RCs and could be triggered by an RC or NERC. The call would be led by NERC’s director of situational awareness, currently James Merlo, vice president of reliability risk management. Testing of the system would be conducted about twice a year.
There is a list of potential “triggers” for the emergency call, along with a catch-all: “any other threats to the” bulk electric system, Norden said.
ORS Chair Chris Pilong, of PJM, said it would have been good to have had such a procedure in place during the 2014 polar vortex, when as much as 22% of his RTO’s generation was out of service.
“I personally see value in having something like this,” said Pilong, the RTO’s director of dispatch. “We have similar procedures internal to PJM to be able to set up conference calls with our members — or even just internally with support staff — to get the right people from the right departments in place. Having it there ready and tested — to me it’s a great thing to have.”
Norden noted the GridEx drills have included “these fake management calls where there’s no protocol, no procedure, no way for us to get together if it was real life. … This could potentially do that.”
Pilong said the ORS members will discuss the draft proposal with their companies and may recommend the plan to the Operating Committee at the next ORS meeting in November.
SPP RC Update
SPP’s Bryan Wood told the committee that a 21-member certification team visited the RTO and conducted interviews and viewed demonstrations in August as part of its bid to expand its RC function to the Western Interconnection. The team was led by the Western Electricity Coordinating Council and included staff from FERC, NERC and the Midwest Reliability Organization.
“We came out of that with some things that needed to get done, most of which were already on the project plan,” he said. A smaller group from the certification team is planning a half-day follow-up visit on Oct. 9.
SPP is scheduled to begin shadow operations with outgoing RC Peak Reliability on Oct. 7 and begin live services on Dec. 3.
Dynamic Transfer Reference Document Endorsed
The committee endorsed the Dynamic Transfer Reference Document, which provides guidance on the procedures for parties involved in dynamic transfers.
Unlike pseudo-ties, which are accounted for by all parties as actual interchange, dynamic schedules are accounted for as scheduled interchange.
The document describes the factors to be considered when determining which type of dynamic transfer should be used and includes a table comparing balancing authority obligations for different situations under dynamic schedules versus pseudo-ties.
Numerical example of supplemental regulation service as pseudo-tie | NERC
The Operating Committee, meeting in Minneapolis, also approved the document this week.
PG&E Corp. on Monday filed a reorganization plan in U.S. Bankruptcy Court that includes $16.9 billion to pay for wildfire claims, the first step in what is expected to be a protracted battle between wildfire victims and other creditors over the utility’s future.
The San Francisco-based company said the Chapter 11 reorganization plan is designed to enable its debtors to “fairly and expeditiously” treat wildfire claims made before the filing “in full compliance” with recently passed legislation (AB 1054). The law creates a $21 billion insurance-like fund to pay for wildfire damages and is bankrolled by California’s three big investor-owned utilities and ratepayers. (See Calif. Wildfire Relief Bill Signed After Quick Passage.)
The plan would create two trust funds, one capped at $8.4 billion to wildfire victims who were unable to cover all their losses and a second capped at $8.5 billion to reimburse insurance companies for their payouts.
The plan also would cover $1 billion previously announced to fully settle the wildfire claims of public entities.
CEO Bill Johnson said in a statement that the plan “will meet our commitment to fairly compensate wildfire victims and we will emerge from Chapter 11 financially sound.”
“I am confident that we can, and will, provide better service to our customers and communities, and our plan of reorganization is another step in this process,” Johnson said. He said the company will remain focused on reducing the risk of wildfires and continue supporting the state’s clean-energy goals.
PG&E said the plan will achieve a rate-neutral solution for customers and meet AB 1054’s June 30, 2020, timeline to become eligible to participate in an insurance fund for future wildfire claims. The company also said it will honor all pensions and collective bargaining agreements.
Under the plan, PG&E would also assume, or remain responsible, for all power purchase agreements and community choice aggregation servicing agreements. Court documents indicate the utility holds almost 400 PPAs with more than 350 companies, worth about $42 billion.
It remains to be seen whether the wildfire victims will accept PG&E’s offer. In addition, a group of hedge funds seeking to recoup billions of dollars from PG&E are attempting a hostile takeover of the company.
Meanwhile the city of San Francisco made an offer Friday to buy the utility’s city electric operations for $2.5 billion. (See related story, PG&E Ends Bond Bid as SF Makes Wires Offer.)
PG&E said it intends to work with financial institutions over the next several weeks to obtain up to $14 billion in equity financing commitments. Those proceeds will be used to pay wildfire victims and help fund PG&E’s contributions to the state wildfire fund.
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.
The U.S. Bankruptcy Court in San Francisco, where PG&E made the filing, canceled a hearing scheduled for Tuesday.
The Western Area Power Administration, Basin Electric Power Cooperative, and Tri-State Generation and Transmission Association announced Monday they will join SPP’s Western Energy Imbalance Service (WEIS) market, giving the new market a foothold in more than a dozen states. SPP plans to launch the WEIS in February 2021.
As the market administrator, SPP will centrally dispatch energy from the participants every five minutes using the most cost-effective generation to reduce wholesale electricity costs for participants. The market will provide price transparency and allow parties to trade bilaterally and hedge against transmission congestion.
SPP is accepting commitments from additional customers to be included in the market’s initial go-live through Oct. 25.
The footprints of the three members include portions of Arizona, Colorado, Iowa, Kansas, Minnesota, Missouri, Montana, Nebraska, New Mexico, North Dakota, South Dakota, Utah and Wyoming. Arizona, Colorado, and Utah are not part of the RTO’s 14-state footprint.
Basin Electric CEO Paul Sukut cited SPP’s “proven track record in operating energy imbalance and full day-two markets,” its “independent board of directors, a proven stakeholder process and a governance structure that specifically includes commissioners from state regulatory commissions.”
Tri-State CEO Duane Highley said the WEIS will provide “a cost-effective solution that quickly increases market efficiencies, reduces expenses for our members and electric consumers, and supports Tri-State’s rapid transition to cleaner energy.”
Joining from WAPA will be the loads and resources of Pick-Sloan Missouri Basin Program – Eastern Division, the Loveland Area Projects and the Salt Lake City Area Integrated Projects, located in the Upper Great Plains Western Area Balancing Authority (WAUW) and Western Area Colorado Missouri Balancing Authority (WACM).
WAPA Administrator and CEO Mark Gabriel said the agency needed to examine markets because of the increasing pace of change in the electric industry, with new generation options “and pressing needs regarding balancing area operations.”
“We are committed to seeking mutually beneficial partnerships consistent with sound business principles,” he said.
The RTO said it plans to operate WEIS under a “Western Joint Dispatch Agreement,” which it said “guarantees participants a say in the market’s ongoing evolution.” Utilities do not have to be a member of the RTO to participate.
“We’re a stakeholder-driven organization that believes in the power of partnership,” SPP CEO Nick Brown said. “We want to do more than just launch a wholesale electricity market in the West. We want to work with utilities to understand the challenges they face and develop smart solutions that benefit the whole region. That’s how we operate as an RTO, and it’s how we plan to administer this and other contract services in the West.”
SPP also is scheduled to begin providing reliability coordination services for more than a dozen utilities in the Western Interconnection in December. It also intends to offer planning coordination to help utilities study and plan transmission upgrades.
Last week, Xcel Energy, Colorado’s largest load-serving entity, and three partners — Black Hills Energy, Colorado Springs Utilities and Platte River Power Authority — announced they were evaluating both the WEIS and CAISO’s Western Energy Imbalance Market. (See related story, Colorado Utilities Examine Market Membership.)
Basin Electric, headquartered in Bismarck, N.D., generates and transmits power to 141 rural electric systems and 3 million customers in nine states: Colorado, Iowa, Minnesota, Montana, Nebraska, New Mexico, North Dakota, South Dakota and Wyoming.
Tri-State is a not-for-profit generation and transmission cooperative with 43 distribution cooperatives and public power districts that serve 1.3 million people in Colorado, Nebraska, New Mexico and Wyoming.
ERCOT said Monday that it has sufficient installed capacity to meet system demand this fall and winter.
The final fall seasonal assessment of resource adequacy (SARA) indicates the Texas grid operator will have nearly 84 GW of capacity to meet a projected peak demand of 61 GW during October and November. The preliminary SARA for the winter season (December-February) anticipates a peak demand of 62.3 GW.
ERCOT’s fall outlook | ERCOT
The fall SARA — based on normal weather conditions during peak demands from 2003 through 2017 — adds almost 2 GW of planned additional capacity: 296 MW of gas-fired generation, 732 MW of wind and 170 MW of solar resources. It also includes 13,833 MW of forecasted unit outages, based on historical averages for the past three years.
“Our studies show we have sufficient generation for the fall season,” Manager of Resource Adequacy Pete Warnken said in a statement.
An additional 1,179 MW of planned winter-rated capacity is expected to be added between now and December. The final winter SARA will be released in early November.
ERCOT began the summer with 78.9 GW of available capacity and an 8.6% reserve margin.
The SARA report assesses generation availability and expected peak demand conditions at the time it is prepared. The assessment takes into account expected generation outages for routine maintenance and a range of outage scenarios and weather conditions that could affect seasonal demand.
AUSTIN, Texas — Infocast’s Texas Renewable Energy Summit last week brought developers, corporate off-takers, cities, municipalities, cooperatives, the financing community and other key stakeholders to sort out where ERCOT’s market is headed, stay abreast of the latest trends shaping the Texas renewables market, and glean the latest insights into the market.
Meeting in the midst of 100-degree-plus heat along the banks of Lady Bird Lake in downtown Austin with ERCOT facing tight grid conditions, much of the conversation centered on the market’s performance this summer.
John Hall, Texas-based director of regulatory and legislative affairs for the Environmental Defense Fund, complimented ERCOT’s staff on meeting record customer demand despite an 8.6% reserve margin. The grid operator has been forced to call two energy emergency alerts, the first in five years, but avoided taking more extreme measures.
Referring to the “ERCOT movie, which I find the most interesting movie this summer,” Hall asked the panel he was moderating for their opinion.
Jacob Steubing, director of origination and structuring for solar developer Recurrent Energy, agreed with Hall but said, “I’m still holding out for ‘Joker’ with Joaquin Phoenix. It’s getting good press.”
Turning serious, Steubing said, “I’m a solar guy, so going by the book, we think the market design as it stands is ideal. Solar has performed at least as well as expected, and I think the data backs that up. We’re continuing to see more sophisticated buyers seeking that solar shape. Your exposure in Texas is when it’s hot and sunny, and solar is a pretty good hedge for that.”
Karl Dahlstrom, senior vice president of commercial execution for renewable developer Seventus, said ERCOT’s market is unique, given its 2% “consistent load growth every year.”
“The impressive number of renewable buildup is placing pressure on fossil plants,” he said. “We do think the market is working. We’re happy to see the $9,000[/MWh scarcity] prices happen. The purpose of the $9,000 price was to encourage new generation. It will be some time over the next two years to see if that’s changed investors’ expectations.”
“This summer’s been really good. It’s helped improve the market confidence in EROCT and [the Public Utility Commission’s] management of the market,” said Resmi Surendran, senior director of regulatory policy for Shell Energy. “ERCOT is only taking market actions at the last moment. It’s a good example to show market impact on prices. That has shown the importance of having the right market design.”
“You will get your returns in the energy-only market, but be careful what you wish for, because here we are,” PowerFin Partners CEO Tuan Pham said. “This market is designed as a trader’s market. Traders love volatility, and they’re killing it right now. Grandma’s not going to be paying the $9,000 prices, so who pays? The retailers are supposed to, and they will, but prices will eventually get socialized to all the ratepayers. It’s going to take some time to work through the system to socialize Grandma’s bills, but it’s going to happen.”
Pham said if ERCOT operated a capacity market or more defined market, no longer would “traders make a whole lot of money and walk off with their bonuses and never invest in the transmission grid.”
A capacity market is anathema to many of ERCOT’s participants. “As a solar developer, we’re against that,” Steubing said, echoing similar comments from others on his panel.
Bob Helton, ENGIE’s senior director of regulatory affairs, recoiled when a fellow panelist mentioned a capacity market.
“There are three words you can’t say in Texas: blackouts, capacity market and the wall,” he said in jest. “It’s involuntary load shed, load obligation and life-form barrier.”
On a more serious note, Helton said transmission is the biggest issue in the market, saying renewable energy’s “basis risk” — the spread between futures and physical prices — is “horrendous across Texas.”
“That will be the main barrier,” he said. “It’s hard to find projects. We’ll have to look at things completely out of the box.”
Panel: Not All Proposed Projects Will be Built
A panel discussing the generation buildout and connecting the resources to the system cast doubt on the more than 100 interconnection requests by renewable developers. ERCOT’s August generator interconnection status report lists 62.4 GW of planned solar projects and nearly 36 GW of wind projects among the nearly 112 GW of study requests.
“We’re just simply not going to build out 40 GW of solar in the state,” Pham said. He said it’s “apparent” ERCOT’s interconnection processes, bogged down with too many specious applications, need to change. “It’s also important to think about distinguishing between solar and wind. You have investors still stuck in this paradigm of imposing wind expectations on solar energy. Wind is off peak; solar is on peak.”
Sunil Nair, managing director for Transmission Analytics Consulting, called the amount of solar projects in the queue “ridiculous” and said the “basis differential risk is real, and it’s growing.”
“The large amount in the queue … is going to cause issues,” he said. “How much is built or where. Unfortunately, I don’t think anyone has a crystal ball.
“There are growing levels of basis differential risk and congestion risk,” Nair said. “We’ve heard a lot of talk about scarcity pricing … but people are building out in areas where they are competing with other wind and solar projects for transmission access. But you may not see that $9,000 pricing. If located behind a constraint with wind or solar on the margin, you may be sitting at zero or negative pricing, while everyone else is getting $9,000.”
Kip Fox, president of Electric Transmission Texas, a joint venture between subsidiaries of American Electric Power and Berkshire Hathaway Energy, said the end result is a system that does not have enough transmission.
“We’ve had half a billion in congestion costs so far this year. Half a billion solves a lot of adequacy problems,” he said. “When I hear an appeal for conservation from ERCOT, I see a transmission system that is going to be in trouble. We’re going into a period where there is more risk due to increased load and congestion.”
While energy storage facilities are increasingly being added to the interconnection queue, ERCOT insiders are also seeing growing interest from server farms and Bitcoin mining operations seeking reliable transmission service.
“We’ve had a lot of requests from Bitcoin server farms,” Fox said. “Bitcoin is tired of being in Mongolia or the Siberian peninsula. These facilities take anywhere from 10 to 20 MW of power and would love to be hooked up to a reliable grid.”
“You won’t see 40 GW of server farms [in West Texas]. You have prairie dogs out there,” Pham said, offering a dissenting viewpoint. “People who operate those things would rather live in Austin or Silicon Valley.”
Wind Industry Expects Continued Growth
The summit’s speakers continue to see strong growth in the Texas wind industry. The rush to begin construction on approved projects before the production tax credit falls off after 2020 is a key driver, but so could be the groundwork laid back in the 1990s by former Texas Gov. George W. Bush, which has led to acceptance of the industry’s facilities.
Texas opened its electricity market to competition in 1999, which led to a wave of wind development and the need for additional transmission infrastructure. The Competitive Renewable Energy Zones (CREZ) project was the answer, resulting in the construction of 2,400 miles of high-voltage lines, capable of carrying 18.5 GW of West Texas wind to ERCOT’s major load centers.
“You could almost say George W. Bush was the godfather of Texas transmission lines,” Pattern Energy Group Vice President George Hardie said. “The CREZ lines enabled an extraordinary amount of new wind to be developed. Because Texas wind has done extraordinary things for Texas communities, there’s been very little blowback of visual aesthetics. You’re seeing wind projects going increasingly closer to load centers.”
“This has all the fundamentals of being a great place for wind development,” said Susan Williams Sloan, vice president of state affairs for the American Wind Energy Association. “There’s high load, so there are a lot of customers. There are ample wind resources and market rules that allow the developers or generation owners to connect to the grid and get their power to the market. With a low-cost, competitive market … there’s a whole lot of political support for building and hosting wind farms. We’re seeing a lot more interest in hosting more [renewable resources] because it’s been so good for rural economic development.”
Vanessa Tutos, EDP Renewables’ director of government affairs, said there’s no political will for a CREZ II, saying “it’s so much more expensive to build large-scale transmission to serve that cheap generation than it is to use distributed generation.”
“Looking at the economic development that is lost to rural America, renewable energy can be there and help some of the economies,” she said. “The only way to do that is enable access to those markets so we can get these projects developed where they’re needed.”
“You can argue wind has been so successful in Texas, it’s creating some adversities that need to be shaken out,” Hardie said. “We need more transmission, but how conducive is ERCOT to building a new transmission line just to accommodate a 100-MW wind farm in West Texas when there’s already so much wind coming out of there? The CREZ lines have become, in an amazingly short time, all full up. Careful siting and location of wind projects, and where the power is needed, will be the key for the ongoing success of wind.”
Sloan said that while the wind industry may soon be the only form of generation not receiving some form of federal tax subsidy, and without a price on carbon, her stakeholders always find a way to beat expectations.
“If there’s only one technology left competing against other technologies with their incentives and subsidies, and despite the cost of wind coming down 69% over the last nine years, being able to compete against others is going to be tough,” she said. “Since I’ve been in this industry, we’ve beat expectations every way. A technology-neutral tax incentive is something you will see us advocating for.”
Permian Basin Drives ERCOT’s Load Growth
Shannon Caraway, vice president of business development for Solar Prime and a 30-year veteran of the ERCOT market, said that while the grid operator’s 2% annual load growth may be setting the standard, it’s nothing compared to the growth in West Texas’ oil-rich Permian Basin.
“The amount of sheer load growth is just staggering. In my entire career, I can’t remember an area that has grown that fast and worn out a forecast,” he said, noting that peak load in ERCOT’s Far West zone has grown 47% since summer 2017 (2,920 MW to 4,280 MW), accounting for about 27% of ERCOT’s peak load growth.
The growth is fueled by oil and gas production. The Permian Basin is currently producing more than 4.2 million barrels per day, though the rate of growth has slowed in recent months. If the trend continues, it would only mean the load growth slows somewhat.
“As long as oil prices stay above $50 a barrel, production could reach up to six million barrels a day,” said Brian Bartholomew, a U.S. power analyst with BloombergNEF.
The petroleum companies are betting on renewables to help manage their price risk. Exxon Mobil recently procured 250 MW of solar energy in the Permian and 250 MW of wind. Shell is also said to seeking renewable generation. ERCOT’s most recent adequacy report indicated nearly 1,9500 MW of solar energy is already operating in its footprint, with 1,500 MW in West Texas.
“A vast majority of all that West Texas solar sits in the Permian Basin,” Caraway said. “When we came out to the Permian area six years ago, most of the solar development was much farther west, west of Fort Stockton. It had great solar irradiance but almost no transmission. Since then, we’ve seen solar in the Fort Stockton area experience severe congestion.”
American Electric Power on Tuesday said it is revising its 2030 targets for reducing carbon dioxide emissions, increasing them to 70% from 60% over 2000 levels.
AEP also said it believes it can cut CO2 emissions by more than 80% by 2050 from its 2000 levels. The company already has cut its emissions by 59% since 2000, a pace it said was faster than expected.
“We’ve made significant progress in reducing carbon dioxide emissions from our power generation fleet and expect our emissions to continue to decline,” AEP CEO Nick Akins said in a press release, adding that the company’s aspirational goal is zero emissions by 2050.
AEP has achieved many of the reductions so far by shutting down inefficient, out-of-market coal plants. Coal-fired generation accounts for 45% of its capacity today, down from 70% in 2005. Natural gas capacity has increased from 19% to 28% and renewable capacity from 4% to 17% during that time.
“Technological advances, including energy storage, will determine how quickly we can achieve zero emissions while continuing to provide reliable, affordable power for customers,” he said.
The Columbus, Ohio-based company, which has operations in 11 states, said it will invest in renewable generation and transmission and distribution technologies that increase efficiency and expand demand-response and energy-efficiency programs to increase CO2 reductions.
AEP’s resource plans include adding more than 8.6 GW of new wind and solar generation to serve the company’s regulated utility customers by 2030. The company is currently seeking regulatory approval to add 1.5 GW of new wind generation to serve customers in Arkansas, Louisiana, Oklahoma and Texas.
AEP Ohio has a case pending before the state’s public utility commission to have customers finance the building of a 400-MW solar farm, the largest in the state, in southeast Ohio.
The company could also benefit from provisions in the state’s House Bill 6, which will raise and distribute $20 million annually from 2021 through 2027 to help finance six utility-scale solar farms previously approved by the Ohio Power Siting Board.
Akins said last October that the company would focus on smaller renewable projects after Texas regulators rejected its proposed $4.5 billion Wind Catcher project. Wind Catcher would have included a 2-GW wind farm in the Oklahoma Panhandle that would have supplied customers in Oklahoma, Louisiana, Arkansas and Texas. (See AEP to Focus on Smaller Renewable Projects.)
AEP intends to shut down its coal-fired Oklaunion plant in Texas by October 2020. | AEP
The company plans to invest another $2.2 billion in contracted renewables and renewables integrated with energy storage in competitive markets between 2019 and 2023. AEP has added 1,302 MW of contracted renewable energy to its portfolio this year.
Over the long term, AEP plans to invest approximately $25 billion over the next five years to improve efficiency and resilience in its transmission and distribution systems.
AEP said it has factored future carbon regulations into the company’s evaluation of generation resource options and will continue to do so.
