Small Public Power Group’s Appeal Again Meets Defeat
ERCOT’s Board of Directors last week rejected an appeal by small public power distributors seeking a proposed change to the ISO’s Nodal Operating Guide regarding the definition of transmission owners.
The revision request (NOGRR149) exempts municipal distribution service providers without transmission or generation facilities from having to procure designated transmission owner (DTO) services from a third-party provider if their annual peak load is less than 25 MW. ERCOT’s Technical Advisory Committee in February unanimously rebuffed an appeal of an early subcommittee’s rejection of the NOGGR after it had been tabled for more than a year. (See “Members Reject Appeal from Small Municipalities,” ERCOT Technical Advisory Committee Briefs: Feb. 22, 2018.)
The proposal was developed in 2015 to settle the noncompliant status of six municipally owned utilities with loads of 9 to 21 MW as the Texas Public Utility Commission’s staff began to look into the issue. However, the NOGGR has never received a positive vote as it moved through the stakeholder process, being rejected three times and tabled nine times.
“Typically, by the time TAC considers a proposal, it has enough consensus to move the initiative forward,” said the Office of Public Utility Counsel’s Diana Coleman, advocating the TAC’s position during the April 10 board meeting. “All 30 TAC members were there, and it didn’t receive one positive vote.”
Pointing to the unanimous vote against the NOGRR at the TAC, board Chair Craven Crowell said, “This particular appeal doesn’t have any legs under it.”
ERCOT CEO Bill Magness told the board that accepting the appeal would be granting an “overly broad” exemption to as many as 53 eligible systems, which represent about 600 MW of the grid’s load.
“If we get into a load shed situation in the ERCOT system, we’re going to ask for the load shed that we need to solve a reliability problem,” Magness said. “It’s going to be distributed out to the participants in the markets to make it happen. We’re going to solve the reliability problem. … Being a part of the [ERCOT] system has its benefits and obligations, and one of those obligations is to participate in load shed.”
Tom Anson, legal counsel to the municipalities under the Small Public Power Group (SPPG), said his members have not been able to reach an agreement with transmission service providers to be their DTOs. He said the SPPG members faces “hundreds of thousands of dollars” to self-designate as DTOs.
“I know ERCOT is reluctant to grant exemptions, but it’s the cleanest thing to do,” Anson said. “It would conform the ERCOT rules to the reality that these small systems just don’t have enough load or other resources to justify the expenditure of the kinds of money to build the substations or other parts of interconnections — all of which, if done, would not increase ERCOT reliability. They would be spending lots of money, but getting no reliability benefits.”
Anson said he was offering a clean solution to the problem, because SPPG members and the larger transmission providers wouldn’t have to continue looking for market solutions.
“Despite lots of hard work, and some progress, we still don’t have permanent solutions in place for all of them. That’s because there is no instant infrastructure, and ERCOT doesn’t control action of third parties. It’s a clean solution because if we want to pursue other rule revisions, time and effort would be avoided.”
The board denied the appeal by a 12-1 vote, with two members abstaining. Carolyn Shellman, who represents the municipal market segment and serves as CPS Energy’s general counsel, was the lone member to vote in favor of the appeal.
Noting the importance of compliance with operating guides and the rule of law, Shellman struggled to balance that with carving out exemptions for “very small groups of entities … that are doing everything necessary to comply if they can.”
“The small power group has some unusual circumstances that may warrant looking at them differently,” she said. “I’m not in favor of a 25-MW exemption … but we do have a solution that works in the market and recognizes the importance of rules. I hate to reject the appeal and send it to the commission that is obligated to enforce the rules we have. I’d hate for them to be in a position to impose penalties that could be devastating on very small systems.”
The SPPG has 35 days to appeal the board’s action, or it can start an appeal process within the TAC by providing different alternatives or language to resolve the issue.
“These small systems are caught between a rock and a hard place,” Anson said. “We’re open to all creative ideas, and we welcome anyone’s thoughts.”
“TAC is willing and looks forward to working with the SPPG,” Coleman said. “It has indicated some of its alternatives would require additional revision requests. We look forward to getting those resolved.”
Tight Summer Conditions Subject of Conversation
Magness said the ISO sees “tight conditions” this summer, not surprising given the surge of coal-fired plant retirements last year that halved ERCOT’s planning reserve margin to 9.3%, 4 percentage points below its 13.75% target. (See ERCOT: Tight Summer Margins No Cause for Alarm.)
“We see sufficient generation [this summer], based on normal conditions,” Magness said. “We could be tested in abnormal situations, based on the tightness of the system.”
Staff have said they have numerous tools at their disposal to help meet what is expected to be a record summer demand of almost 73 GW, including ancillary services, demand response and generators capable of switching between neighboring grids. ERCOT is also working to remove reliability unit commitment (RUC) capacity from its operating reserve demand curve (ORDC), a move that is expected to result in more accurate scarcity pricing (see below).
Texas PUC Chair DeAnn Walker thanked Magness and staff for moving quickly to revise the ORDC, but she added a word of caution.
“I want to raise awareness that when we have changes like this, sometimes we see changes in market behavior,” she said. “I’m relying on ERCOT, and in particular Beth [Garza, the ERCOT Independent Market Monitor’s director], to be keeping their eyes on market behavior like this, to be sure it stays in line with our expectations.”
Garza, for her part, declined to project what will happen this summer. “We would like to share comparisons and contrasts for the last few years, and let you make your own determinations,” she said during her regular update to the board.
She highlighted recent developments in DC tie activity between ERCOT and its neighbors SPP and Mexico. She noted exports across the ties to Mexico have grown in recent years, while imports from SPP have fallen. The five ties have 1.2 GW of capacity but contribute only 389 MW to ERCOT’s capacity in nonemergency situations.
“That could be good news for the summer,” Garza said.
She said lower prices — and the narrowing price spread between ERCOT and SPP — have contributed to decreased imports to the Texas grid.
ERCOT has received more good news in recent weeks, with three previously mothballed generators notifying that they are returning to operational status:
- Talen Energy’s gas-fired Barney Davis 1, effective May 7. Talen had said last year it would retire the unit, which has a summer seasonal rating of 300 MW.
- The City of Garland’s Gibbons Creek facility, effective May 17. The 454-MW coal-fired unit was approved for seasonal status last year by the ISO.
- Garland’s Spencer Units 4 and 5, effective June 1. The two gas units have a total of 118 MW of capacity.
The plants will add almost 900 MW to the ISO’s summer capacity.
ERCOT Projecting $7.2M Favorable Variance in Net Revenues
Magness told the board that ERCOT is projecting a $7.2 million favorable variance in year-end net revenues, driven by winter weather that pushed up load. Net revenues are $4.3 million over budget through February, thanks to the higher administration fees and a $2.1 million favorable variance in expenditures due to timing differences.
ERCOT also saw above-normal revenue neutrality (RENA) uplift charges and market uplift charges in January, Magness said, stressing that the market is functioning as designed.
RENA charges were $16.57 million, up from $7.18 million in December and $10.46 million in January 2017. Magness said congestion in the real-time market was the main driver, with high prices at one end of the constraint and limits on low prices at the other end pushing up RENA.
Market-based uplift to load in January saw charges totaling $71.78 million, compared to a $9.19 million charge in December and a $33.71 million charge in January 2017. High ancillary service costs for non-spin on Jan. 17 contributed to the increase.
Magness also noted two projects continue to track poorly and will be re-planned within months.
The congestion revenue rights system upgrade has been hampered by significant vendor defects. Magness said the vendor has committed to improving its deliverables, and a new go-live date will be set once the defects are resolved.
Integrating the IT change and configuration management system with the content management system will require more time than originally planned, and the scope was expanded to ensure controls maintain data accuracy. A re-plan is expected to be completed in May.
Consent Agenda Removes RUC Capacity from ORDC
The board unanimously passed its consent agenda, which included an other binding document revision request (OBDRR) that removes RUC capacity from the grid operator’s ORDC.
The change meets the PUC’s directive to remove RUC capacity from the ORDC as part of its project assessing the Texas market’s price formation rules (No. 47199). (See “Commission Directs ERCOT to Revise ORDC,” Marquez to Depart Texas PUC.) Magness said the OBDRR is expected to be implanted by June.
The ORDC creates a real-time price adder to reflect the value of available reserves and is meant to incentivize resources to produce more energy and reserves. PUC staff recommended removing both RUC and reliability-must-run capacity from the ORDC, saying it would ensure that scarcity pricing is accurate and reflective of market dynamics.
ERCOT staff said it would take two or three months and $30,000 to $40,000 to make the software changes, an increase from the $15,000 to $25,000 initial estimate. The affected systems include Market Management Systems, data and information products, and analytic data.
The consent agenda included six nodal protocol revision requests (NPRRs), a change to the retail market guide (RMGRR), two changes to the Resource Registration Glossary (RRGRRs) and two system change requests (SCRs):
- NPRR854: Allows non-opt-in entity (NOIE) transmission and distribution service providers to submit meter data for NOIE points of delivery, rather than incurring the expense of installing, testing and maintaining an ERCOT-polled settlement meter, resulting in decreased expenses for both the NOIE and ERCOT.
- NPRR858: Requires ERCOT to publish all current operating plan (COP) data submitted by generators after confidentiality has expired, a change from the limited subset currently available. The change provides transparency into all intra-hour updates to COP data, as generators can update them at any time and change aggregate information available to the market.
- NPRR860: Clarifies certain day-ahead market practices and cleans up protocol language to better match the current implementation, including clarifying 1) the language for offering in three-part supply and ancillary service offers for offline non-spinning reserve in the same hour for day-ahead consideration; 2) the self-commitment treatment of resources with only an ancillary service offer submitted for the day-ahead; and 3) ancillary service offer resubmission rules. Also removes the reference to CRRs being co-optimized in the day-ahead.
- NPRR864: Modifies the RUC engine to scale down commitment costs of fast-start resources with less than one-hour starts. Following the change, the RUC engine will recommend slow-start resource commitments only if re-dispatching online resources and market-based self-commitments of fast-start resources will not resolve the reliability issue. With the change in the generation portfolio, market-based commitment decisions could be made much closer to real-time than in the past, allowing more self-commitments to materialize in real time than is reflected in COPs many hours earlier.
- NPRR865: Requires ERCOT to publish shift factors for hubs, load zones and DC ties for the real-time market, mimicking the day-ahead market’s current practice and providing more information on the inputs used to calculate pricing aggregations.
- NPRR868: Modifies the hub bus and load zone definitions and price calculations to account for the current usage of power flow buses — as opposed to electrical buses — in the day-ahead market and congestion revenue rights auction systems. The rewritten formulas will clarify the scenario when buses are de-energized in contingency analyses and align the protocols with ERCOT systems. (A power flow bus — a collection of points on the system that are electrically connected and have zero impedance between them — is identified dynamically based on the status of transmission equipment. Electrical buses — physical transmission elements that use breakers and switches to connect loads, lines, transformers, generators and related infrastructure — are defined statically.)
- RMGRR0150: Clarifies the content and format of the competitive retailer safety net spreadsheet within the market guide and removes Section 9, Appendix A1: Competitive Retailer Safety Net Request, which eliminates conflicts between the appendix and language found in Sections 7.4 (Safety Nets) and 7.10 (Emergency Operating Procedures for Extended Unplanned System Outages).
- RRGRR015: Clarifies glossary definitions and detailed descriptions of data fields to help market participants successfully submit their resource asset registration forms (RARFs). The change does not add or delete any data requirements, does not require a revision of the existing RARF form and does not require resubmission of previously submitted data already accepted by ERCOT.
- RRGRR016: Provides amplifying direction to RARF users for completion of certain solar data and narrows the data in order to provide solar forecasters with more precise data.
- SCR793: Gives transmission service providers access to the same ERCOT-generated status telemetry as the ISO’s operators in monitoring line outages with calculated subsynchronous resonance condition monitoring points.
- SCR795: Updates the resource limit calculator’s formula for calculating dispatched generation by including the addition of a predicted five-minute wind ramp (PWRR). The PWRR will be calculated from the intra-hour wind forecast and a configurable factor to capture the forecasted five-minute wind ramp, relieving regulation service’s burden to cover the five-minute gain or loss of generation from variations in wind, and instead dispatch this energy economically.
— Tom Kleckner