ERCOT CEO Bill Magness last week told the Board of Directors that the grid operator finished 2019 with a net positive variance of $35.4 million, boosting the pool of funds to implement real-time co-optimization (RTC).

Magness said during the board’s Feb. 11 meeting that a preliminary budget review indicated a 13.3% increase in revenues and a 3.4% decrease in expenditures. He credited a $19.2 million increase in interest income and a $6.5 million increase in system administrative fees for much of the positive variance.

Interest income was coming in over budget as a result of higher balances and rates, Magness told the board in April. The unexpected revenue has been set aside to fund an RTC development pool, now at $52.5 million. ERCOT has estimated it will cost at least $40 million to add RTC to the market.

Magness said the administrative fee variance benefited from warmer-than-normal weather from August into October. September provided $2.4 million and August $1.3 million in actual revenue above budget. October and November accounted for $800,000 and $700,000, respectively, in overages.

October “is kind of what you would expect,” Magness said. “September was the really unusual thing.”

ERCOT’s load continues to grow, with a 2% increase in annual energy usage between 2018 and 2019, after a 5% increase between 2017 and 2018. Over the past decade, energy use is up 20.4%, from 319,097 TWh to 384,040 TWh. The decade before, energy use was up 7.7%.

“[Growth] was as substantial as it felt like, and we continue to see growth,” Magness said.

Real-Time Co-optimization Team Finalizes Scope

ERCOT’s Matt Mereness thanked “all y’all” as he secured the board’s approval of the final batch of RTC key principles that will guide the grid operator’s addition of the market tool into its energy market.

RTC procures both energy and ancillary services every five minutes to find the most cost-effective solution for both requirements. (See “Committee Endorses Final Real-time Co-optimization Principles,” ERCOT Technical Advisory Committee Briefs: Jan. 29, 2020.)

Mereness chaired the Real-Time Co-optimization Task Force, which wrapped up nine months of work by producing a 44-page document that defines the principles, or boundaries, that staff and stakeholders are working toward.

“It’s been painful but focused,” Mereness said of the group’s 16 meetings. “Collaborative, not always perfectly unanimous, but working together to find solutions. One secret that made it work is we had a single forum. All the smart people were in the room working on it.”

Congratulated by board Chair Craven Crowell, Mereness responded, “It takes a village.”

Staff plan to file a set of Nodal Protocol revision requests (NPRRs) implementing RTC in March. The task force will serve as a clearinghouse to address language changes and comments, with a goal of submitting all NPRRs to the Protocol Revision Subcommittee for its consideration in November. If everything stays on schedule, the Technical Advisory Committee and the board will see the final NPRRs in November and December.

According to its schedule, RTC will be added to the market by mid-2024 before a planned update to ERCOT’s Energy Management System.

Helton, Lange Re-elected to TAC Leadership

The board approved staff’s determination that developing systems to enable economic dispatch over DC ties between the grid operator and other systems would be “prohibitively complicated and expensive” and is not “presently feasible.” Staff said existing systems and processes are sufficient enough to manage congestion caused by DC ties.

“A five-minute dispatch would be technically and jurisdictionally a challenge,” Mereness said.

ERCOT had been directed by Texas’ Public Utility Commission to study and determine whether some or all DC ties should be economically dispatched or whether implementing a congestion management plan or special protection scheme would more reliably and cost-effectively manage congestion caused by DC tie flows.

The directive was one of 14 related to Pattern Development’s Southern Cross Transmission, a proposed HVDC line in East Texas that would ship more than 2 GW of energy between the Texas grid and Southeastern markets (46304). (See “Members Debate Southern Cross’ Bid to be Merchant DC Tie Operator,” ERCOT Technical Advisory Committee Briefs: Feb. 22, 2018.)

Nick Fehrenbach, manager of regulatory affairs and utility franchising for the city of Dallas, pointed out the Southern Cross project is a “commercial venture for economic benefits” and raised concerns about the import and export of power outside economic dispatch.

“This troubles me,” Fehrenbach said. “I don’t know the next project of this nature, but this is something we need to resolve in the long run.”

Mereness said that ERCOT has changed its scheduling of DC ties. As their ramp comes in, it is offset by the grid operator’s economic dispatch.

Leadership Re-elected

In other action, the directors re-elected Crowell as chair, former PUC Commissioner Judy Walsh as vice chair and Magness as CEO, and ratified ERCOT’s officers.

The board’s consent agenda, which passed unanimously, included 16 NPRRs, single revisions to the Nodal Operating Guide (NOGRR) and Verifiable Cost Manual (VCMRR) and a system change request (SCR):

• NPRR826: creates a new process for determining the mitigated offer cap for reliability-must-run (RMR) resources.
• NPRR838: revises the RMR process by removing the requirements for units to submit operations and maintenance estimates and for RMR resources to submit quarterly O&M updates.
• NPRR955: defines a limited-impact RAS to accommodate NERC Reliability Standard PRC-012-2.
• NPRR963: allows an energy storage resource’s (ESR) components to be considered in aggregate for generation resource energy deployment performance scoring, controllable load resource energy deployment performance scoring and settlement of base point deviation charges.
• NPRR964: removes from the RMR process the term “synchronous condenser unit” and its related agreement.
• NPRR967: removes the 10-MW limit for limited-duration resources.
• NPRR970: clarifies the fuel-dispute process for reliability unit commitment (RUC) make-whole payments.
• NPRR971: updates the energy offer curve’s cost cap value.
• NPRR974: requires ERCOT to include additional data about the amount of projected capacity available in the short-term system adequacy report.
• NPRR977: requires ERCOT to post a report of canceled RUCs to the market information system.
• NPRR978: incorporates revisions to address recent changes on the PUC’s resource adequacy reporting rules.
• NPRR980: changes how forced outages longer than 180 days are treated in ERCOT’s Capacity, Demand and Reserves report.
• NPRR982: clarifies that a deployed block-load transfer will be appropriately compensated.
• NPRR985: modifies the time period used to compute the forward adjustment factor components of the total potential exposure calculation and clarifies that the three forward weeks commence on the applicable operating day, rather than following the operating day.
• NPRR986: gives ESRs more flexibility in updating real-time energy offer curves and bids.
• NPRR988: corrects NPRR929’s intended implementation by clarifying that conditions in its language are necessary for determining whether a point-to-point obligation with links to an option bid is eligible to be awarded.
• NOGRR183: aligns the Nodal Operating Guides with NERC’s remedial action scheme reliability standard.
• SCR806: adds resource-specific offer information to all individual disclosure reports on ERCOT’s website.
• VCMRR026: removes an appendix to align the manual with NPRR970’s proposed protocol language and NPRR617’s revisions.

— Tom Kleckner