ERCOT’s Technical Advisory Committee voted last week to dissolve its Distributed Resource Energy Ancillaries Market (DREAM) task force, agreeing the group had brought issues to the forefront that could now be taken up in the ISO’s stakeholder process.

The DREAM team was created last May to investigate the regulatory and market framework for distributed energy resource (DER) participation in ERCOT’s wholesale markets.

Shell Energy’s Greg Thurnher, the DREAM team’s chair, said the goal was to establish a marketplace where price-taking and price-responsive distributed generation (DG) resources can efficiently coexist.

Expanding the scope of price-responsive loads and resources in security-constrained economic dispatch, he said, more accurately reflects the price elasticity of demand.

“In the eyes of TAC, I think we’ve achieved our charter,” said Thurnher, who represents the Independent Power Marketer segment.

TAC Chair Randa Stephenson, with the Lower Colorado River Authority, agreed and thanked the team for its work. “We’re now at a point where we can vet specific and technical issues through the stakeholder process,” she said, before casting the only abstention in an otherwise unanimous vote.

Thurnher said Shell will sponsor a nodal protocol revision request (NPRR) following up on the DREAM team’s recommendations. He has proposed five market rule changes for price-responsive DG, among them a proposal to exclude the resources from participating in ERCOT’s congestion revenue rights markets.

He would also exclude DG from participating in regulation until distributed storage becomes larger and more cost competitive. DG “is a low-cost hedge, it’s out there and it’s growing. These assets are right-sized and can solve many of the smaller constraints we have on our system,” Thurnher said. “When you have resources with no load responding to the system, they should be given the opportunity to bid into the market and contribute to price formation.”

Kenan Ögelman, ERCOT’s vice president of commercial operations, responded with a spreadsheet listing 15 short- and long-term issues identified by the ISO as needing revision requests or new market rules. “The idea was to put down ERCOT’s perspective on what our needs are,” he said.

Ögelman said staff looked initially at accounting for larger resources and then tried to capture smaller resources. He said the focus was on “what’s in the market, instead of getting these resources participating in the market.”

“Some of these things are what Greg was talking about,” Ögelman said. “We understand your priorities might be slightly different, and we’re happy to work with you and move them up. This is not written in stone.”

Ögelman said he would like to combine Thurnher’s proposals with ERCOT’s spreadsheet and hand the effort over to a working group. He said he would be “looking for input and timing from the market as to when these should come into play.”

Several stakeholders expressed concern smaller market participants might lack the resources to ensure their voices are heard in stakeholder proceedings. Others cautioned about moving too quickly to allow stakeholders to provide input.

Stephenson said she will work with ERCOT “to ensure the right people,” including distribution utilities, are involved in the discussions.

TAC Approves Addition of Responsive Reserves

The TAC approved staff’s recommendation to add 200 MW of responsive reserve service (RRS) during the afternoon hours in July and August. The vote came after the TAC asked ERCOT to include in its 2017 ancillary service methodology review an analysis of how the elimination of the reserve discount factor (RDF) would affect operations.

The ISO’s current minimum RRS requirement is 2,300 MW under normal conditions. The additional 200 MW will come into play during those four-hour blocks when average temperatures are most likely to exceed 95 degrees Fahrenheit. Effective this year, RDFs are reviewed and adjusted based on the generator’s performance during an unannounced test.

“If the temperatures are over 95, we need to move this market away from the old zonal market rules and control area rules,” Calpine’s Randy Jones said. “You should not be doing testing around peaks.”

Austin Energy’s Barksdale English agreed with Jones, saying the RDF should be based on actual performance, not unannounced testing.

The recommendation has already been endorsed by the Wholesale Market and Reliability and Operations subcommittees. It will go to ERCOT’s Board of Directors in June for final approval.

NOGGR Tabled, Other Revision Requests Approved

The TAC unanimously approved a previously tabled revision request and several other change requests brought forward by its subcommittees. It also tabled a nodal operating guide revision request (NOGRR) that recommended a 25-MW annual-peak threshold to exempt distribution service providers from procuring designated transmission operator services from a third-party provider.

NOGRR 149 was developed last year to settle the noncompliant status of seven municipally owned utilities (MOUs), ranging in size from 9 to 21 MW. It was rejected by ROS and tabled by TAC, but the revision request’s proponents appealed.

GDF Suez’s Bob Helton, representing the Independent Generators segment, recommended tabling the NOGRR to allow ERCOT staff to answer several other questions. TAC Vice Chair Adrianne Brandt, of CPS Energy, asked that transmission service providers meet with the MOUs to further discuss the issue.

The committee approved:

• NOGRR 151, aligning operating guides with changes made in NPRR 748 and providing consistency, transparency and clarification related to communication protocols;
• NOGRR 153, creating a new process to maintain alignment of the energy emergency alert language between the protocols and nodal operating guides;
• Nodal protocol revision request (NPRR) 752, clarifying the revision-request process protocol language to reflect current ERCOT practices; and
• System change request (SCR) 788, updating the resource-limit calculator formula used to determine the generation-to-be-dispatched value.

Ögelman updated the TAC on NPRR 667, which he called an “odyssey” more than two years in the making. The revision request is designed to improve regulation-up and regulation-down service and replace RRS and non-spinning reserves with a combination of four new ancillary services.

ERCOT is hoping the Protocol Revisions Subcommittee (PRS) will endorse the NPRR in May, before bringing it back to the TAC.

“We believe 667 meets a lot of board objectives and market-design objectives,” Ögelman said, “but ERCOT is willing to wait on TAC’s final input on the issue.”

In March the PRS withdrew a similar revision request (NPRR 756) that would redesign the ancillary services market. Staff said at the time NPRR 667 was the better option.

Data Workshop Scheduled

The committee discussed ERCOT’s upcoming workshop on data reports, tentatively scheduled for May 20. The workshop is a result of a discussion at the March TAC meeting about how the ISO and its market participants exchange data and handle changes to reports. (See “TAC to Schedule Data-Exchange Workshop,” ERCOT Technical Advisory Committee Briefs.)

Ögelman said the workshop would focus first on changes to reports and how they impact market participants, and then the internal need for “some type of controls around [the reports] that give people comfort.”

“We want to explore more stable, different ways to interact without scraping data,” he said.

“I think this is an important step for us to take,” Citigroup Energy’s Eric Goff said. “It’s so critical to ensure everyone has reliable and robust access to all ERCOT data. Over the long run, I think it will be a significant improvement to the transparency of data.”

ERCOT staff said it is also working on an NPRR to improve the accuracy of its wind forecasts by synching them with the current operating plan for intermittent resources.

Stephenson noted market participants have seen “big swings” of about 175 MW during March and April, creating volatility in the market. She assigned the NPRR’s work to the Wholesale Market Subcommittee.

The WMS, Retail Market and Commercial Operations subcommittees all delivered their normal monthly status reports.

– Tom Kleckner