The ERCOT Board of Directors approved extending a reliability-must-run contract with NRG Energy for its Greens Bayou Unit 5 plant in the Houston area. The RMR, ERCOT’s first in five years, will run through June 30, 2018, at which time additional generation and transmission infrastructure is expected to be in service.

The 371-MW natural gas-fired generator was originally scheduled to be mothballed June 27, but ERCOT’s RMR contract June 3 made the unit available to the market through September. (See ERCOT to Keep NRG’s Greens Bayou Plant Running for Summer.)

Staff analysis indicates Greens Bayou Unit 5 is needed to maintain or support reliability in the region over the short term.

“Having that unit available will reduce the likelihood of having to engage a constraint-management plan, which would likely mean load shed,” said Warren Lasher, ERCOT’s director of system planning.

Under the RMR agreement’s terms, ERCOT will make a standby payment to NRG of $3,185/hour during on-peak hours, whether or not the unit runs.

Directors Carolyn Shellman, of CPS Energy, and Read Comstock, of Direct Energy, both encouraged additional discussion on the ISO’s RMR practices at the next board meeting. “I think we should encourage a holistic review of the RMR protocols,” Comstock said.

Lasher said staff will begin evaluating must-run alternatives, which it will bring to the board in August. The Technical Advisory Committee is also creating a task force to focus on the issue.

“I would like to see the market solve these situations, so we don’t have to,” Director Judy Walsh said.

Staff said the region’s reliability concerns will subside before the summer peak of 2018, when the $590 million Houston Import transmission project — “the ultimate [RMR] exit strategy,” Lasher called it — is expected to be completed. New generation is also on the way, with NRG’s 390-MW PH Robinson peaking facility expected to come online later this summer and Exelon’s 1,148-MW Colorado Bend combined cycle plant to follow in July 2017.

ERCOT also added 75 MW of power last week when NRG converted a gas turbine at its Houston-area W.A. Parish facility into a cogeneration unit. The unit was originally built to produce steam and electricity as part of the Petra Nova post-carbon capture and sequestration joint venture with JX Nippon Oil & Gas Exploration. The unit went into mothballs May 19 during its conversion process.

Magness: Mild Weather Cuts into Admin Revenue

CEO Bill Magness said ERCOT’s year-to-date revenues are $2.3 million over budget, despite a $2.2 million shortfall in the administrative fee that is attributed primarily to mild weather this year. He said the ISO is on track to finish $3.1 million above budget, thanks to positive variances in resource management, hardware and software, and employee benefit costs.

“It looks like we can create a favorable variance, but we don’t know what the weather’s going to be like,” Magness said.

ERCOT’s senior meteorologist, Chris Coleman, said this summer will “likely” not be as warm as last summer — the 17th hottest in Texas over the past 121 summers — or 2011, when sustained heat led to several peak-demand records and seven emergency alert notifications.

“This summer is one of the more difficult forecasts I’ve put together,” Coleman said. “Most indicators suggest a milder summer. I can guarantee you we will not see a repeat of 2011.”

Coleman said ocean temperatures, the primary influence on weather patterns, have been above normal in both the Pacific and Atlantic Oceans. He also said the transition from the second-strongest El Niño on record to what he expects to be a neutral or weak La Niña could lead to above-normal temperatures in the late summer.

The meteorologist said he does see “more potential for hurricane activity in the Gulf of Mexico” than his first four years with ERCOT. Coleman predicted five hurricanes, of which one or two could be in the Gulf, and the potential for two storms to make landfall in Texas.

“It doesn’t mean Texas will be hit by a tropical storm or hurricane,” he said, “but if there are three to five in the Gulf, the potential is greater.”

Dan Woodfin, ERCOT’s director of system planning, said it would take “really, really extreme” weather conditions to affect the grid’s operations. The ISO said last month it has more than enough natural gas and renewable energy capacity to meet its projected summer peak this year. (See ERCOT Briefs: Ample Capacity; Outage Procedures.)

“We’re not expecting a 2011 summer,” Woodfin said. “We have procedures in place should something out of the ordinary happen.”

The Rio Grande Valley, long a trouble spot for congestion, “looks better this summer than it has in quite a few years,” Woodfin said. He said a 345-kV line was completed last month and a cross-valley project went into service two weeks ago, easing some concerns.

LP&L Integration Could Unlock More Panhandle Wind Energy

Lasher shared staff’s report on how to integrate Lubbock Power & Light into ERCOT, which recommends a plan that would allow for further export of the Texas Panhandle’s ample wind energy supplies.

Lasher said staff’s “option 40W” will cost $364 million and result in 141 miles of new 345-kV rights of way, but it could also help export 4,246 MW of wind energy elsewhere on the grid.

“It’s not the low-cost option,” he said, “but it’s preferred specifically because it’s consistent with the longer-term needs ERCOT has identified for the region.”

LP&L announced last September it planned to disconnect from SPP and join ERCOT by 2019. Xcel Energy, whose Southwestern Public Service subsidiary serves LP&L’s load, asked FERC in May for an $88.7 million interconnection switching fee should the municipal utility proceed with its plan. (See Xcel Asks for $88.7M Fee for Lubbock Switch to ERCOT.)

Staff combined studies supplied by LP&L and Sharyland Utilities, which has transmission assets in the Panhandle, and folded them into its own analysis. The final report will be filed in the Public Utility Commission of Texas’ LP&L docket (# 45633).

Changes to Calculation of Market’s Physical Responsive Capability

ERCOT’s methodology for determining ancillary service requirements will change July 1 when it adjusts the reserve discount factor (RDF) in the market’s physical responsive capability (PRC) calculation on quick-response online generation.

The board unanimously approved staff’s recommendation on the adjustment, pleasing PUC Commissioner Ken Anderson, who has raised concerns over an event last August when the ISO’s scarcity pricing adder, the operating reserve demand curve (ORDC), did not appropriately reflect a reduction in the PRC.

“In defense of ERCOT, these changes are looking to solve the problem we saw last August … the disconnect between the ORDC and PRC,” he said.

On Aug. 13, operators deployed non-spinning reserve service as the PRC dropped to 2,371 MW. However, ERCOT’s real-time online reserve capacity was 3,629 MW, which was reflected in wholesale prices.

ERCOT buys responsive reserve service to ensure sufficient PRC is available. The measure approved by the board aligns the ISO’s systemwide discount factor, lowering it from 2% last year to 1%. It also makes operational adjustments to the RDF.

Board Approves 13 Revision Requests

The board pulled one nodal protocol revision request (NPRR) from the consent agenda but gave it its unanimous approval following a brief discussion.

NPRR758 is designed to provide improved transparency to market participants when transmission outages that could create congestion are submitted with less than 90 days’ notice. It would identify outages that have historically resulted in high congestion costs, as adjusted through stakeholder review to account for upgrades and other changes.

“I’m concerned we don’t have a clear-cut requirement to how we came up with the list and published it,” said Nick Fehrenbach, manager of regulatory affairs and utility franchising for the City of Dallas, before offering up the motion for approval. “We need clear requirements and how we can change them, or we’re leaving ourselves in a quandary.”

TAC Chair Randa Stephenson, of the Lower Colorado River Authority, said the subcommittee and ERCOT staff will “work to ensure a list of high-impact outages is available to public knowledge.”

The board’s consent agenda resulted in the approval of nine more NPRRs, two system change requests (SCRs) and a nodal operating guide revision request (NOGRR).

• NPRR709: Modifies the alternative-dispute resolution procedure and clarifies parts of the settlement and billing dispute process.
• NPRR752: Clarifies revision request protocol language to reflect current ERCOT practices.
• NPRR754: Revises the posting frequency of the load-forecast distribution factors report. Posting is required only when the factors are changed.
• NPRR761: Clarifies that a resource will not be eligible for make-whole payment startup-cost compensation in the day-ahead market when the market considers the resource as not having a startup cost.
• NPRR762: Removes references to the provision of responsive reserves across the DC ties.
• NPRR763: Corrects the formula for calculating qualified scheduling entities’ monthly block load transfer amount to reflect a charge, rather than a payment.
• NPRR764: Changes calculations for charges to entities short their capacity obligations in reliability unit commitment. Calculations for wind and solar resources will be based on their production potential.
• NPRR765: Eliminates publisher names for various fuel price indexes and provides additional clarifying language regarding the use of a substitute source for daily fuel prices.
• NPRR766: Aligns the description of the systemwide discount factor with the proposed operational adjustment to the RDF in the physical responsive capability calculation; also aligns the posting for RDFs applicable to both generation and load resources.
• SCR788: Updates the formula used to calculate the “generation to be dispatched” (GTBD) value and help minimize GTBD oscillations from one security-constrained economic dispatch interval to the next.
• SCR790: Adds an additional level of geographical granularity — the Panhandle/North area — to reports on wind power production and forecasts.
• NOGRR050: Removes ERCOT’s requirement to produce outage-scheduling reports until systems can be changed to include only transmission service providers’ outages.

– Tom Kleckner