CAISO is nailing down its final preparations for the Aug. 21 solar eclipse, which is expected to take about 5,600 MW of utility-scale and rooftop solar generation off the California grid during morning hours when those resources would typically be ramping up output.
Still, the grid operator expressed confidence in its ability to avoid service outages stemming from the event, despite having to support an upward ramp of about 70 MW/minute heading into the eclipse and a downward ramp of 90 to 100 MW/minute coming out.
“We will ramp up generation to compensate for lost solar production, and there is plenty of capacity to meet need,” the ISO said in a FAQ published on its website. “It is not unusual for the ISO grid operators to manage ramps this large on certain days.”
CAISO currently has about 10,000 MW of utility-scale solar interconnected into its system, and its typical morning ramps average about 29 MW/minute.
The extra capacity will mostly come from traditional generating resources. (See CAISO Solar Eclipse Prep Relies on Conventional Mix.) With California’s water levels still relatively high after a wet winter, CAISO expects to have access to about 6,000 MW of flexible hydroelectric capacity in mid-August. The ISO has also been working with gas pipeline companies, utilities and generators to procure additional reserve and regulation capacity, both of which will be needed to grapple with the potential for oversupply and frequency regulation issues after the eclipse, as solar rapidly ramps up its output.
Tasks Completed
Begun last year, CAISO’s preparations for the eclipse have been extensive.
The ISO said it has consulted with the forecasting team that helped grid operators in Europe prepare for a 2015 eclipse, which especially affected Germany’s 40 GW of installed solar capacity. The ISO has developed its own event-day forecast using Aug. 22, 2016 — also a Monday — as the basis for projecting expected demand the morning of the eclipse. The ISO’s model assumes full sun, no “extraordinary” conservation measures and higher obscuration rates (representing the proportion of the sun obscured by the moon) in Northern California, along with a corresponding loss with rooftop solar output there.
The eclipse will have its greatest impact on solar generation in Northern California, where “obscuration” rates will be above 75%. | CAISO
The ISO has also completed a market simulation for the day of the eclipse and conducted “tabletop exercises” and training for real-time grid operators. It has also refined its renewable forecasts — in part by comparing them with third-party forecasts — and coordinated with natural gas companies to plan for increased output from gas-fired power plants.
The grid operator is also working with Western Energy Imbalance Market (EIM) participants to “incorporate eclipse impacts in their power schedules, maintain full operational energy transfers, and collaborate on forecasting.” CAISO expects the eclipse to have some impact on 1,700 to 2,000 MW of solar generation in neighboring EIM areas.
Still to Come
A week ahead of the eclipse, CAISO plans to “refine” its resource and load forecasts and update market participants about any changes to its reserve needs. Two days before the event, it will hold a conference call with market participants “to facilitate coordination and transparency,” the FAQ said.
Finally, on the morning of the eclipse, the ISO will ensure that its real-time forecasts are transferred into the ISO system in order to prepare generation and optimize the transmission network.
And while the ISO is not expecting the need for conservation measures, it did encourage electricity consumers to keep those measures in mind on the day of the eclipse.
“The ISO predicts the typical consumer will not notice the grid management challenges and balancing strategies,” CAISO said. “However, energy efficiency is always helpful to curb spikes in need for power and to lower consumer electricity bills during times of high demand.”
Data centers and residential customer growth are driving increased electric demand for Dominion Energy in Virginia, with weather normalized sales up about 2% for the first half of the year.
New customer connections in the first six months jumped 7% over 2016, and the company connected five new data centers between April and June, company officials said in their second-quarter earnings call Wednesday.
CEO Thomas Farrell said an anticipated increase in federal defense spending under the Trump administration would “provide strong support for the Virginia economy, which is the largest recipient of defense dollars in the nation.”
“All of these factors support our expectation that annual electric sales growth of at least 1% will continue,” Farrell added.
The company reported second-quarter earnings of $390 million ($0.62/share), a drop from last year’s $452 million ($0.73/share). Operating earnings for the quarter were $421 million ($0.67/share) versus $441 million ($0.71/share) for 2016. The main difference between reported and operating earnings were costs related to Dominion’s acquisition of Questar.
Operating revenue was $2.81 billion, up 8% from almost $2.6 billion a year earlier. The company is predicting earnings growth of at least 10% in 2018.
Transmission spending will contribute to that growth. Dominion added $327 million in transmission assets in the first half of the year, and the company plans to invest $800 million in transmission annually for at least the next decade.
Extensions for Va. Nukes, Subsidy for Millstone Sought
Cove Point Liquefaction Project | Dominion Energy
Farrell said company officials are “working very hard” to win financial support from Connecticut lawmakers for its Millstone nuclear plant. He did not respond to an analyst’s question on whether the company would share Millstone’s financials to rebut criticism that the plant is already profitable and doesn’t need assistance.
However, he said the company will participate in the study ordered by Gov. Dannel Malloy last month. The state’s Department of Energy and Environment and Public Utilities Regulatory Authority are to report to the legislature on the plant’s financials in January 2018. (See CT Gov Orders Financial Analysis of Millstone Plant.)
Paul D. Koonce, CEO of Dominion’s Power Generation Group, said that the timing of legislative action depends on the resolution of the Connecticut budget, which he hopes lawmakers will complete by Labor Day.
Meanwhile, the company has begun the process for winning license extensions for its North Anna and Surry nuclear plants in Virginia. Officials said state legislation will allow the company to recover through a rate rider the costs of extending the plants’ lives, which could be as much as $4 billion.
Company officials also provided updates on several projects:
Farrell reiterated the company’s plans to add as much as 2,000 MW of offshore wind if two test offshore wind turbines planned for 26 miles off Virginia Beach “demonstrate that they work well in these waters and produce the kind of capacity that we expect.” (See Dominion Plans 12-MW Offshore Wind Project, 2nd in US.)
The Cove Point Liquefaction Project is 95% complete, on target for the beginning of commercial service later this year.
Construction of the Atlantic Coast Pipeline project should begin in November, assuming FERC restores its quorum by the end of September. “There’s certainly some vocal opposition in some isolated localities, but overall, folks in Virginia support the pipeline as they do in West Virginia [and] North Carolina, and we expect to get all the necessary permits later this fall,” Farrell said. Dominion won’t discuss potential expansion of the pipeline until it has the FERC permit in hand, he said.
The 1,588-MW Greensville County combined cycle plant is almost half complete and is on time and on budget with commercial operations expected late 2018.
The company said it expects to select sites later this year for one or more pumped-storage facilities in Southwest Virginia. The General Assembly approved recovery of the facilities’ costs through a rider.
Greensville County combined cycle plant construction | Dominion Energy
Solar
The company said data centers, military installations and the state government are driving demand for renewables. Three facilities totaling 119 MW went into commercial operation in the second quarter. In total, the company expects to add 438 MW of solar this year and another 200 MW by the end of 2018, bringing its total to 1,800 MW. The company’s integrated resource plan calls for up to 5,000 MW of solar by 2032.
“Solar uses a lot of land, and that’s beginning to become obvious to people as maybe not quite as obvious to folks in the West, where vacant land is abundant,” Farrell said. “So we’re exploring all of our options to meet our customers’ demands for decades to come. That’s part of why we’re looking at the relicensing of North Anna and Surry as well, and pump storage in the Virginia mountains.”
On Thursday, the company announced it has acquired two 5-MW solar facilities and plans to purchase two other solar farms totaling 10 MW later in the third quarter from Strata Solar, of Chapel Hill, N.C.
[Editor’s note: Quotes from the earnings call are according to a transcript by Seeking Alpha.]
With its merchant nuclear power plants all but part of history, Entergy reported second-quarter earnings Wednesday that almost doubled investor expectations.
The New Orleans-based company said second-quarter profits were $409.9 million ($2.27/share), compared with $567.3 million ($3.11/share) a year ago. A Zacks Investment Research survey of Wall Street analysts had forecasted earnings of $1.20/share.
At the same time, the company has received final regulatory approval to build a pair of nearly identical 990-MW combined cycle gas-fired plants in Louisiana and Texas. The Lake Charles Power Station in Westlake, La., is expected to go online in 2020, while the Montgomery County Power Station near Houston should begin operations in 2021.
Entergy’s Vermont Yankee nuclear plant, closed in 2014.
“These projects will contribute to our portfolio transformation efforts to replace older, less efficient plants with new generation,” Entergy CEO Leo Denault told analysts during a Wednesday earnings call, pointing to state-of-the art emission controls that capture and use waste heat to boost generation. “They are an important part of our strategy to meet our voluntary commitment to develop an electric system that is well-positioned to operate in a carbon-constrained economy.”
Denault said the two plants are expected to provide Entergy’s Louisiana and Texas customers at least $3 billion in combined net benefits and lower production costs. The plants are also expected to provide thousands of jobs during construction and generate more than $2 billion in economic activity for their local communities, he said.
Entergy has also amended its application for the proposed New Orleans Power Station, which has encountered opposition from the City Council. Denault said the company has renewed its request for the original 226-MW combustion turbine but also proposed a 128-MW unit as an alternative.
Exelon officials said Wednesday they will press PJM to enact rule changes boosting off-peak prices and are confident nuclear subsidies in New York and Illinois will survive court challenges.
The comments came as Exelon reported second-quarter earnings of $80 million ($0.09/share), a drop from $267 million ($0.29/share) a year earlier, as its generation division saw a $250 million loss.
Adjusted operating earnings for the quarter were $509 million ($0.54/share), down from $604 million ($0.65/share) in 2016, reflecting the end of the reliability support services agreement for its R.E. Ginna nuclear plant in New York, increased nuclear outage days and lower realized energy prices. Those negatives were partially offset by rate increases that boosted utility earnings and zero-emission credit revenue ($0.05/share) for the Ginna, Nine Mile Point and James A. FitzPatrick nuclear plants beginning April 1.
Joe Dominguez, executive vice president of governmental and regulatory affairs and public policy, said federal district court rulings rejecting challenges to the New York and Illinois ZEC cases suggested opponents will have a difficult time prevailing on appeal.
“The district court decided these cases at a very preliminary stage, whereas a legal matter the courts had to assume all the facts that the plaintiffs pled were accurate. Those facts were not accurate, but even under the plaintiffs’ versions of the case, the courts found that they had no legal claim whatsoever,” Dominguez said. “In both decisions, the district courts rejected the entire waterfront of the plaintiffs’ claims beyond the … procedural issues. That speaks to how high a hill they will need to climb on appeal to reverse those decisions.”
David Gaier, spokesman for plaintiff NRG Energy disagreed. “We don’t think we’re down for the count at all,” he said.
Initial briefs are due Aug. 28 in the plaintiffs’ appeal of the ruling on the Illinois ZECs, pending before the 7th U.S. Circuit Court of Appeals. The plaintiffs plan to ask the 2nd Circuit Court to review the New York ruling.
Lobbying Position Improved
Dominguez said the court rulings have helped Exelon’s lobbying posture in other states considering ZEC-type programs. He said opposing lobbyists have cited the legal questions as risks for policymakers, saying “‘Why would you take a tough vote on this only to have it overturned in the courts?’ These decisions resolve that issue.”
Dominguez said, however, that pricing carbon emissions in the wholesale markets would be preferable to ZECs. “It’s more clear to us now than ever that federal wholesale markets need to evolve to fully incorporate attributes like resiliency, fuel diversity and the environmental qualities of the generation resources. If the markets don’t evolve, then the markets are going to have a diminished role in energy policy going forward. We are committed [to markets] but the markets should be well-functioning. Our commitment to markets only extends so far as it provides the best outcomes for our customers.”
Dominguez said the company was heartened by PJM’s plan for energy market changes that would allow baseload generators such as nuclear plants to set clearing prices in off-peak hours. The RTO has said it will file the changes with FERC by the first quarter of 2018, with implementation targeted by summer 2018. “We are going to push very hard to make sure that happens,” promised Dominguez, who said the changes should increase off-peak energy prices and reduce capacity prices. (See RTOs to Congress: Don’t Lose Faith in Markets.)
Not Considering GenCo Spin-off
Crane said that although Exelon believes it is undervalued by Wall Street, it is not considering spinning off its generating unit into a separate company. He cited the “synergies” between its generation fleet and its distribution utilities. Exelon noted that all its utilities scored in the top quartile of the Customer Average Interruption Duration Index and that Baltimore Gas and Electric and Commonwealth Edison achieved their best-ever System Average Interruption Frequency Index scores.
“We are differentiating ourselves from any other merchant generator in the business. [We have] strong balance sheets, a different class of assets, very well run and fairly matched to our load books. So, we like where we’re at and wouldn’t speculate on anything else,” he said. We “really can see the value creation and want the market to recognize it as we do execute on what we say.”
CFO Jack Thayer told analysts Exelon believes future power prices will be higher than suggested by forward curves, whose liquidity has declined over the past year. Trades for 2020 and beyond represent only 6% of the futures volume at the PJM West hub on the ICE and NASDAQ exchanges, he said.
Exelon
“We would note that our fundamentals group has a more constructive view on power markets than these illiquid forward curves suggest, but we appreciate that there is perceived safety in using the forwards,” he told the stock analysts on the call. “However, when running your numbers, we would just encourage you all to appreciate what is underpinning those forward prices.”
CAISO hauled in the largest share of the $39.52 million in benefits produced by the Western Energy Imbalance Market (EIM) during the second quarter, the grid operator said in a report released Monday.
The ISO was also the market’s dominant exporter of energy over the period as California coped with combined surpluses of solar and hydroelectric output on its system after a wet winter.
CAISO took in $15.49 million in benefits, compared to $8.81 million for PacifiCorp, $8.13 million for Arizona Public Service and $2.47 million for Puget Sound Energy. NV Energy’s estimated $4.62 million in benefits did not include data for June, which is still pending verification.
| CAISO
The EIM’s total benefits increased by $8.52 million — or 27% — over the first quarter. (See CAISO EIM Exports Rise With Spring, Report Shows.) That spread will increase with the addition of NVE’s June figures.
The gross benefits represent either cost savings for serving load or increased profits from merchant operations within the EIM’s participating balancing authority areas (BAAs). The market’s ability to reduce curtailments also enables participants to collect renewable energy credits that would not otherwise be issued.
The benefits calculation nets out inter-BAA transfers that were scheduled ahead of the EIM’s 15- and five-minute market runs to avoid attributing contracted flows to the market.
CAISO exported more than 1.11 million MWh of electricity in the EIM’s five-minute market during the quarter, the report shows. Most of that energy was transmitted into NVE’s territory to be wheeled into the PacifiCorp-East area, but APS also absorbed a significant portion. The inclusion of APS and PSE last October greatly increased the transfer capability within the EIM, improving California’s ability to move its solar surpluses into other areas of the West.
Last year’s addition of Arizona Public Service and Puget Sound Energy to the EIM has significantly increased the market’s transfer capacity, facilitating exports from CAISO | CAISO
That export capability enabled CAISO to avoid curtailing 67,055 MWh of renewable output from April to June, displacing 28,700 metric tons of CO2 emissions , the report said. The ISO estimates that, since 2015, avoided curtailments from EIM operations have reduced carbon emissions by 204,941 metric tons, the equivalent of removing more than 43,000 passenger cars off the road for a year.
CAISO’s exports are likely to decline sharply this summer as California absorbs more of its own renewable output in the face of increased summer loads, a pattern seen last year. (See PacifiCorp Increases Share of EIM Benefit in Q3.)
The report also noted the EIM’s impact on the procurement of flexible ramping capacity, which represents resources capable of responding to the variable output of renewable generators.
Because variability can decrease in one BAA at the same time that it’s increasing in another, the EIM enables participants to share flexible resources — allowing each BAA to procure fewer resources than would have been necessary on a standalone basis. These “flexible ramping procurement savings” during the second quarter represented about 39% of what would have been the total requirement of the participating BAAs absent the EIM, the report showed.
The EIM has yielded $213.24 million in gross benefits since commencing operation in November 2014 with PacifiCorp as its first member.
Negative day-ahead prices surged in CAISO during the first quarter as combined surpluses of solar and hydroelectric output frequently left the market upside-down.
Prices went negative during 51 hours in the day-ahead market over the three-month period, compared with just three hours in all of last year, the ISO’s Department of Market Monitoring said.
“This is something we first just started seeing in this quarter,” Senior Analyst Gabe Murtaugh said during a July 31 call to discuss the department’s first-quarter report.
Negative prices indicate that the cost to procure wholesale power was at or below $0/MWh, which happens when there is an oversupply of solar power and other renewables while demand is relatively low.
Negative prices occurred in the day-ahead market during about 10% of the hours in the 11 a.m. to 3 p.m. time frame during the first quarter. They also happened more frequently during weekends when electricity loads were lower.
| CAISO
Real-time prices also dipped frequently into negative territory during the quarter, occurring at about 10% of intervals in the 15-minute market and 13% of intervals in the five-minute market.
The negative pricing has become central to the debate around renewables in California, with some arguing that it is the result of a rush to integrate renewables without completely accounting for or understanding their impact on reliability and markets.
CAISO average energy prices decreased sharply in the first quarter, from about $35/MWh in December 2016 to about $23/MWh in March. This coincided with increased renewable output and low loads, the Monitor said. Prices in the 15-minute market are consistently lower than day-ahead prices and moved in about the same direction and magnitude each month.
“On average, five-minute market prices in March were notably low at about $17/MWh. This was the lowest average monthly five-minute market price during the past several years,” the Monitor said in the report.
CAISO also curtailed more renewable generation in the quarter, rising to a high in March of nearly 6%, compared with peak curtailment less than 3% a year earlier. Renewable curtailment rose above 80,000 MWh in both February and March, compared with less than 60,000 MWh in March 2016, according to ISO data.
During nearly all first-quarter intervals when prices were negative, the market economically dispatched generation down and CAISO did not have to curtail self-scheduled generation.
Rooftop solar and other renewables pushed up negative prices in CAISO in the first quarter
Prices at times surged above $750/MWh at certain times because of generator ramping limitations when solar resources rolled off the system at sunset.
“During these intervals, steep increases in net load exceeded flexible ramping capacity procured through the flexible ramping product and required the power balance constraint to be relaxed because of insufficient available incremental energy,” the Monitor said.
Congestion in the Western Energy Imbalance Market (EIM) continued to isolate PacifiCorp-West (PACW) from CAISO and PacifiCorp-East (PACE), the Monitor said. This drove down prices in PACW and Puget Sound Energy compared with the ISO and the rest of the EIM.
Arizona Public Service and PSE joined the EIM in October 2016, adding new transfer capacity. This reduced congestion between APS, CAISO and PACE, the Monitor said. EIM market prices in the APS area were close to those in NV Energy, PACE and CAISO.
The Monitor earlier this month said that bid limits placed on PacifiCorp, NVE and APS are no longer needed because of increased transfer capacity in the EIM. (See CAISO Monitor Says EIM Bid Limits No Longer Needed.)
The report reiterated the Monitor’s recommendation that the ISO’s congestion revenue rights auction be eliminated and replaced with a market or locational price swaps based on bids for CRRs. (See CAISO Monitor Proposes End to Revenue Rights Auction.) CAISO is in the midst of an initiative to investigate the efficiency of the auction.
Public Service Enterprise Group CEO Ralph Izzo said last week that the company has received “just about universal support for the continued operation” of its nuclear plants.
Speaking during the company’s second-quarter earnings call on Friday, Izzo also revealed that PSEG’s Public Service Electric and Gas plans to ask the New Jersey Board of Public Utilities to decouple its distribution revenue from its sales volume to enable it to support large-scale investments in energy efficiency.
PSEG — which owns the Hope Creek Generating Station and 57% of the adjacent Salem Nuclear Generating Station in New Jersey, and 50% of the Peach Bottom Atomic Power Station in Pennsylvania — wants financial compensation for its emissions-free generation, which it says is at risk from low power prices.
Salem & Hope Creek Nuclear Reactors on Artificial Island
Izzo said it’s good that the Department of Energy recognizes a challenge “with baseload generation and fuel diversity,” which will be the subject of a report the department plans to release soon. He called “the recent PJM proposals on how to deal with inflexible units … potentially quite helpful.” (See New York ZEC Suit Dismissed.)
Izzo | PSEG
Still, Izzo said, “the problem, according to the forward price curve, is at New Jersey’s doorstep, and there’s no denying it.” As a result, he said, PSEG will “continue to educate stakeholders at the state level about the need to preserve the diversity and resiliency of our electric generating mix.”
PSE&G will make the decoupling request in a rate case it plans to file no later than Nov. 1. A growing number of utilities are seeking to decouple their revenue from their sales. The move enables them to get the money they say they need to maintain their infrastructure even if their sales are flat or declining. In California, for example, utilities receive incentives to encourage their customers to use renewables and conserve electricity.
PSEG earned $109 million ($0.22/share) in the quarter, down from $187 million ($0.37/share) in the second quarter of 2016. The company said its most recent figures were affected by accelerated depreciation associated with the June 1 retirement of its last two coal-fired generating stations. PSEG’s revenue in the most recent quarter was $2.13 billion, up from $1.91 billion a year ago.
A Central Texas heat wave is leading to surging demand for electricity, helping ERCOT continue its streak of breaking demand records.
The Texas grid operator’s latest record came Friday when it reported 69,525 MW of demand between 4 and 5 p.m., the fifth time in July it exceeded last year’s mark of 67,469 MW.
Temperatures in Austin, where ERCOT is headquartered, hit 105 F on Sunday, breaking a 60-year-old record for the date and marking the 13th straight day of triple-digit heat. Nearby San Antonio broke heat records Saturday and Sunday with temperature readings of 105 and 104 F, respectively. The previous records were set in 1950 and 1946, respectively.
On Saturday, ERCOT broke the weekend peak demand record by nearly 1,500 MW when it recorded a preliminary total of 68,413 MW between 4 and 5 p.m. — after hitting 67,728 MW in the previous hour.
And the ISO has set new monthly demand records for nine of the past 12 months, including the last four.
“The system has performed well so far this summer,” said ERCOT spokesperson Robbie Searcy. Unable to resist the use of a pun, she said, “We have kept up with monthly record demand in June and July, and blazed past the previous weekend record without any reliability concerns.”
ERCOT’s final resource adequacy seasonal assessment projected demand to peak this summer at 72.9 GW in August, above the all-time high of 71.1 GW set in August 2016.
Area heat indices have been as high as 109 F, but temperatures are expected to drop into the high 90s for much of this week.
AUSTIN, Texas — The Public Utility Commission of Texas agreed Friday that Southwestern Public Service does not have the exclusive right to build transmission facilities in its service territory, signaling a final order will be considered at its next meeting.
The PUC’s decision was not the answer SPS was looking for when it filed a request asking the commission to determine whether Texas law includes a right of first refusal that overrides FERC Order 1000. (See Texas PUC Agrees to Take up SPP, SPS Request on ROFR.)
Wes Reeves, spokesman for SPS parent Xcel Energy, said the company “is disappointed with this ruling and will seek rehearing and appeal.” The PUC’s next meeting is scheduled Aug. 17 (Docket No. 46901).
SPS contends that the state’s Public Utility Regulatory Act (PURA) allows it, as the incumbent utility operating outside ERCOT, the ROFR to build in the service area prescribed by the PUC. That would prevent a potential competitive project under Order 1000.
The commission disagreed, sticking to its staff position that “an incumbent utility’s expertise in providing service within its certificated service area does not confer an exclusive legal right to construct transmission facilities within the utility’s certificated service area.”
Commissioner Ken Anderson offered little of his own reasoning but noted ERCOT’s Competitive Renewable Energy Zone (CREZ) project backed his position.
“The fact is, whether it’s CREZ lines or non-CREZ lines, we have transmission lines owned by different service providers inside and outside ERCOT that crisscross each other’s distribution service territory,” he said.
SPS filed a lawsuit in state district court in January, seeking approval to build the project and an injunction prohibiting SPP from issuing a notification-to-construct. The two parties agreed to suspend the proceeding to give the PUC an opportunity to decide how to interpret PURA.
Parties to See LP&L Contested Case After Aug. Meeting
All parties involved in Lubbock Power & Light’s planned migration of its load from SPP to ERCOT agreed they are ready to move on to a contested case, but not until after the PUC’s Aug. 17 meeting (Project No. 45633).
Commissioner Brandy Marty Marquez said the delay would give her and PUC staff more time to study data compiled by ERCOT and SPP in a joint study on the potential move’s financial and reliability impacts.
“Everybody’s ready to go but me,” said Marquez, requesting a hearing schedule be set at the commission’s next open meeting.
Anderson agreed, saying he hasn’t yet “completely digested” the studies.
“There’s a lot of good data in the SPP and ERCOT report,” he said. “It’s not brought together in [a] bottom line, but you can derive it with little work.”
The study indicated SPP would see small production cost decreases in all of its transmission zones except for SPS, which serves LP&L’s 430 MW of load in a contract that has been extended into 2021. ERCOT would see production cost increases but hopes to balance that out by unlocking wind energy in the Texas Panhandle. (See Lubbock Load Could Boost ERCOT Production Costs by $66M.)
LP&L has said it intends to complete a study similar in scope and scale to the grid operators’. It wants to begin the contested case in May 2018, allowing it to successfully integrate with ERCOT before its “bridge agreement” with SPS expires.
AUSTIN, Texas — ERCOT stakeholders last week tabled a proposal to eliminate the reduction of congestion revenue rights (CRR) payments — “deration,” in the ERCOT vernacular — after the measure failed to pass the Technical Advisory Committee.
The nodal protocol revision request (NPRR821) would reverse the deration-settlement mechanism, which was introduced to deter market manipulation but has resulted in large financial losses to generators.
Lower Colorado River Authority’s Randa Stephenson recalled when her company lost $2 million over three months because of a forced outage at one of its power plants. She said generators face downside risk because CRRs are settled in the day-ahead market, which sometimes doesn’t align with real-time outcomes.
“All the generators are trying to do here is the right thing,” said Stephenson, a former TAC chair. “We’re trying to hedge our congestion risk in the real-time, and we don’t feel like we can do that right now.”
The deration price for a CRR path is determined at the constraint level and applied to the CRR payout. CRR payments can be derated if transmission elements are oversold, the target payment is a positive value, or the CRR source or sink is a resource node.
Stakeholders willing to eliminate CRR deration have expressed concern that NPRR821 unfairly changes allocations so that load will bear 100% of the risk associated with deration. Other participants countered that the shortfall is borne by CRR holders when a balancing account is exhausted and said the shortfall risk is not exclusive to load.
“We think the deration process that’s in place now is appropriate,” said Amanda Frazier of Luminant, the only generator to vote against eliminating CRR deration. “It’s a risk that can be managed. It allows for appropriate values of CRR on paths where we have unexpected outages that cause those paths to be oversold.”
TAC’s consumer and independent retail electric provider (REP) segments voted unanimously with Luminant against the measure, providing 10 of the 12 “no” votes. The 15 favorable votes were not enough to meet the required two-thirds threshold to approve the measure.
“The real issue is the risk itself is not changing … and you’re transferring the risk to load, instead of the market participants that are participating in the CRR auction,” said one REP representative, Read Comstock of Source Power & Gas. “I have sympathy for LCRA’s issue, but I’m assuming the price they offered considered that risk that existed. This same risk is going to be transferred to load with this NPRR change.”
“This NPRR is just like insurance. You overpay for insurance, and I think we’re going to wind up overpaying for the CRRs,” said Morgan Stanley’s Clayton Greer, who voted to eliminate deration. “Right now, we have hedges that don’t work when you need them. It’s like buying flood insurance that has an exemption for when it rains. Whenever the outages are taken, that’s when the congestion hits — and that’s when we actually need the coverage.”
Asked by stakeholders to weigh in, Beth Garza, the Independent Market Monitor, said she would leave the “very hard discussion” on money and value assessments to the TAC to decide.
“One of the aspects brought up in discussion that hasn’t been brought up today in the deration process is a way to manage potential manipulation,” Garza said. “I would argue it’s a very heavy-handed way to do that, and an unnecessary way to monitor for manipulative intervention in the CRR market. We don’t see a need for the current deration process.”
“This is very unique when it happens. It’s just the generators that get the derates and take the hit,” Stephenson said. “We’re trying to have a tool here that makes sense for us when we have these unique situations. It’s very hard to predict behavior if we’re going to have price blowouts on the upside, or CRRs get more expensive and give the load more money.”
Comstock urged stakeholders to remain engaged in the auction process. If not, he said, “we’re going to see CRR market participants push for more capacity to be sold at longer terms, because they’re not concerned about risk that exists if they are oversold.”
Stephenson, who was sitting in for John Dumas, the LCRA’s normal TAC representative, said she would bring back additional comments and math samples of the “unique situations” to provide a “deeper discussion” on the proposed change.
The motion to table passed by a 23-6 margin. Further discussions will take place at the Wholesale Market Subcommittee (WMS), and possibly the Qualified Scheduling Entity Managers Working Group, before returning to TAC.
“821 is getting rid of the entire deration process in order to fix a relatively small problem,” Frazier said. “There are very directed ways to address the LCRA issue. That’s an issue we are interested in trying to resolve as well.”
EEA Price Adder Change Tabled
The TAC also tabled for another meeting the only revision request that required significant discussion.
The Texas Industrial Energy Consumers has opposed NPRR768 throughout the stakeholder process. The NPRR would revise the categories of ERCOT-initiated actions, such as energy emergency alerts (EEAs), that trigger a real-time deployment adder so that prices reflect current system conditions.
“What ERCOT is really doing [when it calls DC tie imports] is replicating what a good market outcome would be,” said the TIEC’s legal counsel, Katie Coleman. “I know EEAs don’t happen often, but when they do, this could keep prices at the cap for significantly longer than they would be otherwise, and this is real money for my members.”
Referencing ERCOT’s systemwide offer cap of $9,000/MWh, Coleman said, “When you have an EEA in ERCOT and prices are at $9,000, everybody has every incentive to sell power into the ERCOT market.”
In her opening statement, Coleman also said the TIEC is concerned NPRR768 would apply to the Southern Cross Project, a proposed HVDC transmission project that would transport more than 2 GW of electricity from Texas to Southeast markets.
“When you’re talking about making a price adjustment for up to 2,000 MW of import, that starts to be real money,” she said.
In delaying action on the proposal in the past, stakeholders have noted the Southern Cross proposal was part of a recent docket before the Public Utility Commission of Texas (45624). In a resulting compliance docket (46304), the commission directed ERCOT to determine the project’s “appropriate” market participation classification, necessary transmission upgrades and cost allocations, and whether any price adjustments are necessary. (See “Southern Cross HVDC Project,” ERCOT Technical Advisory Committee Briefs.)
Coleman said that the commission did not direct ERCOT to take specific action on NPRR768 or similar proposals, and that the ISO’s decision to file the NPRR, rather than leave the issue to stakeholders, was concerning.
“It’s not necessarily an appropriate role for ERCOT to be filing things that increase prices for customers,” she said.
Frazier said Luminant, a participant in the Southern Cross litigation before the PUC, asserted a price correction would be needed if ERCOT curtailed DC ties for reliability reasons. As the Southern Cross DC tie would be a merchant tie, she said, there was little reason to be concerned about replicating market actions.
“[Southern Cross] will have those incentives to operate, so this is more of a backup position,” Frazer said. “Where if ERCOT is taking command and control over someone’s assets that would otherwise be doing something else — and they’re doing that to preserve the reliability of the ERCOT system — then there should be a price correction for that action, which is how we treat other reliability actions.”
“The problem is, the Southern Cross facility [is] not being built to facilitate market transactions in and out of ERCOT,” Coleman countered. “It’s being built to facilitate moving wind from SPP and Texas to regulated utilities in the Eastern Interconnection so they can fulfill renewable requirements.
“We’re concerned the incentives won’t be appropriate for people to sell into ERCOT, even when prices are $9,000.”
The WMS will be given the opportunity to weigh in before the discussion is scheduled to resume during August’s meeting.
TAC Approves 5 Revision Requests
The TAC approved two additional NPRRs, revisions to the load profiling guide (LPGRR) and the retail market guide, and a system change request (SCR):
NPRR822: Establishes the procedure for identifying resource nodes as an “other binding document” instead of a “business practice manual,” and adjusts the process for handling a retired resource’s nodes by allowing ERCOT to convert CRRs at that node to a different, nearby settlement point.
NPRR833: Adjusts NPRR827’s language to account for the steady state when ERCOT implements the long-term, automated change affecting point-to-point (PTP) obligation bid clearing. The NPRR updates the day-ahead market optimization engine to address situations where a contingency disconnects a resource node. The engine will pick up the PTP megawatts and distribute them to other nodes, instead of ignoring them in a contingency analysis if that PTP sources or sinks at the disconnected point.
LPGRR063: Clarifies the wording referring to the competitive retailer (CR) of record for certain profile type requests, and specifies only the CR of record may request certain profile assignments.
RMGRR149: Clarifies certain communications processes for electric service identifiers (ESI IDs) without a REP.
SCR792: Allows ERCOT to send the consecutive clock-minute average exceedances of Balancing Authority ACE Limit (BAAL) to the appropriate entities, and creates a situational awareness display in the information system’s public area that displays consecutive clock-minute average exceedances of BAAL.
