LP&L Study: Production Costs Increase
AUSTIN, Texas — Jeff Billo, ERCOT’s senior manager of transmission planning, told the Board of Directors last week that further analysis indicates Lubbock Power & Light’s potential transition from SPP could result in as much as $77 million in increased production costs — an $11 million jump from the preliminary results presented in May to the Technical Advisory Committee. (See Lubbock Load Could Boost ERCOT Production Costs by $66M.)
The increase did not go unnoticed by Director Carolyn Shellman, of San Antonio’s CPS Energy.
“So, you caught me on that,” Billo joked, when questioned about the difference. He explained the increase was caused by the addition of a third synchronous condenser to a previously approved project, designed to reduce wind energy congestion in the Texas Panhandle.
“Once we added a third [condenser], we didn’t see quite as much [economic] benefit from a wind-congestion relief perspective,” Billo said.
Staff’s evaluation indicates an increase of $77 million in fuel costs to serve the additional load in 2020 and $74 million in 2025. The preliminary numbers were $66 million and $60 million, respectively.
Should LP&L’s load be integrated into ERCOT, it will be placed in either the ISO’s West zone or its own zone. Analysis indicates non-LP&L consumers would see an increase of 3 to 5 cents/MWh in the years 2020 and 2025 to pay for serving Lubbock’s load.
Billo reminded the board that the increased production costs will be offset by additional wind energy flowing into the ERCOT market through the LP&L interconnection.
“The Lubbock Power & Light facilities create a new transfer path for wind energy out of Panhandle,” he said. “[The facilities] connect to wind resources where we’re seeing a lot of congestion.”
LP&L announced in 2015 it planned to disconnect 430 MW of its load from SPP and join ERCOT in June 2019. The Public Utility Commission of Texas last summer asked the grid operators to conduct coordinated studies on the move, focused on a cost-benefit analysis for ratepayers. (See PUCT Asks ERCOT, SPP to Coordinate on Lubbock P&L Move.)
ERCOT plans to file its study with the PUC by the end of June (Docket 45633). SPP has said it intends to file its study results with the commission in late June.
‘Healthy Margins’ Headed into Summer Months
ERCOT CEO Bill Magness said “healthy” reserve margins “well above our targets” have the grid in good shape to meet increased demand this summer. The ISO’s latest Capacity, Demand and Reserves report indicated reserve margins of 16.8 to 18.9% in the next five years. (See ERCOT Sees Enough Generation Through 2022, 73-GW Peak for Summer.)
ERCOT set demand records in both April and May, recording 59.2 GW on May 26 for its latest monthly high. The ISO has set new demand highs for seven of the 12 calendar months during 2016-17.
“Continuing growth on the system is pretty much evidenced by that fact,” Magness said.
Dan Woodfin, ERCOT’s senior director of system operations, said the ISO has sufficient resources (81.9 GW) available and doesn’t expect the Houston and Rio Grande Valley areas to be the “significant issues” they have been in recent years. He said transmission limitations may create congestion for exports from the Panhandle and imports into Houston.
Chris Coleman, the ISO’s meteorologist, said he doesn’t expect above-average temperatures in Texas this summer, despite the warmest winter on record. He shared data with the board that showed little correlation between warm winters and warm summers, and said it’s “highly unlikely” temperatures will reach the record-breaking levels of 2011.
“The main reason I won’t forecast a repeat of 2011 is because it’s wetter. Quite a bit wetter,” Coleman said, pointing to drought-breaking rains over the last few years that have raised reservoir capacity from 75.5% full to 87.2% in the last year. “We have 1.2 trillion gallons of water more than we did in the reservoirs in 2011.”
But Coleman told directors that Texas is long overdue for a hurricane’s landfall. The last storm to hit the state was Hurricane Ike, which devastated Southeast Texas in 2008. Another year without a hurricane’s landfall would equal the longest such span since 1900.
“We’re way overdue,” he said. “Statistically, we average one storm every 2.5 years.”
Coleman is forecasting 14 named storms and seven hurricanes, including four major storms. He is projecting three or four named storms in the Gulf of Mexico, where water temperatures never dropped below 73 degrees this winter.
“There’s a very strong correlation between a warmer-than-normal Gulf of Mexico and extreme weather,” Coleman said. He said there is a disturbance in the gulf over the Yucatan Peninsula and Bay of Campeche that could develop into a named storm (Bret) later this week, a forecast backed up by the National Hurricane Center.
Coleman has also been developing medium-range (eight to 14 days) and long-range wind forecasts (one to three months), work that’s still in progress. He said above-normal temperatures lead to windy conditions, and he expects a “windy” summer.
Board Vice Chair Judy Walsh asked Coleman whether he would begin to do wind forecasts that could provide meaningful data.
“That’s my plan,” Coleman said. “I just wrapped up this study, and I’ll try to apply it for the rest of the summer.”
Magness Unfazed by Lagging Admin Fees
Despite a $2.3 million negative variance in budgeted system administration fees, ERCOT still has favorable net revenues of $1.3 million — and little reason to worry, Magness said.
“Thinking about revenues in ERCOT in the springtime is sort of like Joaquin Andujar,” he said, referencing the late Major League Baseball pitcher. “Joaquin Andujar once said, ‘I can sum up the game of baseball in one word: you never know.’”
Magness noted that a year ago, revenues were down $2.2 million, yet the ISO ended up with a favorable variance. ERCOT is on track to finish 2017 with a $2.6 million favorable variance in net revenues.
“It’s all about managing to what we have,” he said. “We think we will come much closer to the forecast.”
Directors Approve 2018-19 Budgets, Keep Admin Fee Flat
The board unanimously approved ERCOT’s 2018-19 biennial budget, which includes $222.3 million and $228.0 million for operating expenses, projects and debt-service obligations for 2018 and 2019, respectively. The ISO is currently operating under a $223.1 million budget.
The 2018-19 budget keeps the system administration fee flat at 55.5 cents/MWh. It was raised from 46.5 cents/MWh with the current budget, approved in 2015.
Walsh, who chairs the Finance and Audit Committee, said projections through 2023 show load growing at almost 2% and labor costs escalating at 4% annually. She said committee members asked ERCOT staff to come back in August with analysis on how to keep from raising the admin fee.
“As we look out further in time … and if these assumptions prove true, we’re going to have to balance the levers we have,” Walsh said, referencing FTR revenues, credit revolvers and the admin fee. “We want to explore how each of those moving parts work, so we’re fully apprised of what our choices will be, should we continue to have higher growth in expenses than load,” she said.
After 4 Years, NPRR Gets Unanimous Approval
Nodal protocol revision request (NPRR) 562, four years in the making, was among 10 changes unanimously approved by the board.
“This was a very challenging issue,” Magness said. “You notice the NPRR started with a five. Everything else [on the agenda] started with an eight.”
NPRR562 creates new requirements for identifying and protecting against subsynchronous resonance (SSR) and clarifies responsibilities for affected entities. The ERCOT system has become more vulnerable to SSR with the introduction of series capacitors for voltage support. Without proper mitigation, SSR can quickly destroy resonating elements and resources, and lead to cascading outages.
“We built a grid that delivers power at 60 Hz,” said Woody Rickerson, ERCOT’s vice president of grid planning and operations. “That’s the synchronous heartbeat of the grid.”
Rickerson said series capacitors increase the risk of energy being exchanged at a frequency of less than 60 Hz.
The board also approved related changes to the Planning Guide, PGRR056, which accounts for potential SSR vulnerability in the transmission planning process, providing references and citations to the appropriate protocol sections related to SSR, and removing its definition from the guides.
Magness brought Fred Huang, manager of dynamic studies, before the board for special recognition, calling him instrumental in guiding NPRR562 through the PUC’s rulemaking process.
“[Huang] always ends up in the middle of something really hard and thorny we have to solve,” Magness said.
NPRR831, the only revision request to receive a separate vote, relates to private-use networks (PUNs) — networks connected to the ERCOT grid that contain load typically netted with internal generation and not directly metered by the ISO. The change updates market systems to calculate a net load value for each PUN that will be included in the load zone price for all markets, when the load is a net consumer from the grid.
Source Power & Gas’ John Werner encouraged ERCOT to find a short-term solution before NPRR831 goes into effect in October, saying revenue neutrality allocation has reached $50 million this year, five times the amount for the same period last year. The increase is a result of largely PUN loads creating point-to-point obligation payments without offsetting energy imbalance charges.
The consent agenda included five other NPRRs and two additional PGRRs:
- NPRR796: An administrative revision specifying that character set validations are available within each Texas standard electronic transaction implementation guide.
- NPRR820: Aligns the definition of an aggregate generation resource (AGR) with the Protocols, which allow a resource entity to register several generators as an AGR. Intermittent resources are not included.
- NPRR824: Aligns Protocol language with NERC reliability standards for energy emergency alerts and real power balancing control performance.
- NPRR827: Bars ERCOT from awarding point-to-point obligations in the day-ahead market when the corresponding clearing price is greater than the bid price for the PTP obligation by 25 cents/MWh or more. ERCOT said the change will prevent harm to market participants over “modeling issues that need to be resolved and any resolution will take many months to implement.” The ISO said the language change will not need to be reversed once the modeling issue is addressed because “any resolution of this issue must honor the fact the PTP obligation bid price reflects the maximum willingness to pay by the bidder.”
- NPRR830: Revises the basis of ERCOT’s calculation of the four-coincident peak calculation (4-CP) to be consistent with NERC’s net-energy-for-load methodology. The proposed methodology uses metered net DC tie flows.
- PGRR057: Aligns the Planning Guides with NERC Standard TPL-007-1 (Transmission System Planned Performance for Geomagnetic Disturbance Events) by identifying responsibilities for performing geomagnetic disturbance vulnerability assessments.
- PGRR058: Clarifies specific generation to be included in the Planning Guide and the applicability requirements for proposed generation that must submit generation interconnection or change requests.
– Tom Kleckner