AUSTIN, Texas — With Hurricane Harvey rapidly gaining strength in the Gulf of Mexico and threatening the Lone Star State, ERCOT’s Technical Advisory Committee on Thursday focused on three tabled revision requests and appeals before quickly scattering to their homes and work.
“Be safe,” urged TAC Co-Chair Bob Helton, of Dynegy, as he adjourned the meeting.
Committee members did approve one of the three tabled issues, passing a nodal protocol revision request (NPRR768) after staff filed comments most could agree to. The NPRR was the subject of vigorous debate during the July TAC meeting but was passed this time with only Shell Energy and Sharyland Utilities abstaining. (See “EEA Price Adder Change Tabled,” ERCOT Technical Advisory Committee Briefs: July 27, 2017.)
The revision request adds real-time DC tie imports and exports through registered block load transfers to the list of ERCOT-initiated actions that trigger a price adder to ensure that prices reflect scarcity conditions.
Staff revised the language to cap the total adjustment for DC tie imports at 1,250 MW, the current capacity of all DC ties.
That was enough to placate the Texas Industrial Energy Consumers group, which has opposed the measure throughout the stakeholder process.
“We have a philosophical disagreement about whether this is appropriate,” said Katie Coleman, legal counsel for TIEC. “Rather than continue fighting about that, we got comfortable about moving this forward with a megawatt limit on it.”
Shell’s Greg Thurnher called the revised language a “nice compromise” and a “step in the right direction” to support scarcity pricing signals, but said he wasn’t sure “every adder is a good adder.”
“This one has a lot of fine print,” Thurnher said. “We’ve had some growth in traditional [DC ] ties that could be excluded for the circumstances it’s trying to prevent. We’ve arrived at the solution, but I’m not sure it’s a good one.”
NPRR768 does not address the Southern Cross Project, a proposed HVDC transmission project that would transport more than 2 GW of electricity from Texas to Southeastern markets. Several stakeholders agreed that is a discussion for a later date.
“When we wrote this, we tried to recognize what exists today,” said Kenan Ögelman, ERCOT’s vice president of commercial operations. “We don’t believe it’s biased toward anything. Our process allows the accommodation of whatever the future is going to be. This was our effort to put something forward to get to a compromise and recognize some of the concerns.”
Shell filed comments to ERCOT’s revisions, suggesting modifying the NPRR to restrict price correction to imports ordered on DC ties classified as transmission facilities. Cratylus Advisors’ Mark Bruce, speaking for Southern Cross, disagreed with the change.
“It seems pretty clear to us that once the Southern Cross project is interconnected to the ERCOT network, it will be a transmission element by definition, which means the definition of a transmission facility has to be amended to include it,” Bruce said. “Shell’s comments don’t really change anything. It actually opens it up and includes Southern Cross when it goes live.
“The ERCOT approach, on its face, is sort of less discriminatory. It doesn’t really start distinguishing between transmission facilities based on regulatory classification or ownership structure of the facility, which in our view isn’t a permissible way to go about this. In our view, this is either a good policy, [and] you put the megawatts in the calculation, or it’s not good policy, and you don’t.”
“Our intent was to impose a limit,” Thurnher responded. “The protocols get tricky when they define things. I think of Southern Cross as a load sometimes and a generator sometimes, neither of which are transmission assets. If Southern Cross gets built, then this needs to be revisited.”
Said Coleman, “We are intentionally leaving that for future discussion.”
CRR Deration Remanded Back to Subcommittee
The TAC unanimously remanded back to the Protocol Revision Subcommittee NPRR821, which failed to pass the committee in July after substantial discussion, to reconcile “three very different” modifications proposed by stakeholders.
The revision request would eliminate the reduction of congestion revenue rights (CRR) payments, or deration, by reversing the day-ahead market’s deration-settlement mechanism. The mechanism, which was introduced to deter market manipulation, has resulted in large financial losses to generators.
The deration price for a CRR path is determined at the constraint level and applied to the CRR payout. Payments can be derated if transmission elements are oversold, the target payment is a positive value, or the CRR source or sink is a resource node.
The Lower Colorado River Authority filed two proposed adjustments to NPRR821 following a $1.9 million loss in 2016 that it called “unusual and unique.” LCRA said it worked with ERCOT and others in attempting to find a balance between low impact and low implementation cost.
The company’s preferred solution was linking the CRR’s holder and the point-to-point (PTP) obligation of the qualified scheduling entity on the same path. It suggested linking the PTP price to the corresponding CRR value if a PTP obligation bid is awarded to a QSE with a CRR. If the CRR is derated, the PTP bid’s settlement price is matched to the CRR’s derated value.
The second option would cap the PTP’s value at the derated CRR’s value on the same path.
“It’s clear a lot of folks still have a learning curve with how this process works and the way the money flows,” said LCRA’s Randa Stephenson. “If it’s TAC’s will to send this back, please be ready to vote on this. This is going to be an issue that comes back to us.”
ERCOT staff agreed and volunteered to put together a presentation detailing all the proposed modifications.
“I just want to make sure everything’s clear,” Ögelman said, noting that LCRA’s proposal considers PTPs, not CRRs. “People need to look at all of these things to understand all of the mechanisms.”
DC Energy’s suggestion to add a “circuit-breaker” lowering the capacity offered in the CRR monthly auctions when the balancing account reaches zero at the end of any month drew positive feedback from several stakeholders.
“It’s a little bit more protection for our customers,” said Austin Energy’s Barksdale English.
Under DC Energy’s proposal, the CRR balancing account would be allowed to rebuild its value before reverting to the 90% capacity offering status quo.
Morgan Stanley offered the third proposal, which it said would “level the playing field” for all CRR participants by making short pays equivalent, regardless of the source or sink of the owned CRRs. Eliminating the current process — which covers hub and load zone CRRs and provides hedge value for those instruments involving resource nodes (well over half of these shortfalls) — would eliminate the expense created for load, the company said.
“There was a request to try and narrow the NPRR, and this narrows the application as far as you can get it,” said Morgan Stanley’s Clayton Greer, whose first preference was either the original NPRR or DC Energy’s proposal. “It actually eliminates all short-pay recoveries and hedge payments entirely. The retail segment argued that derate support was being done on the backs of load. If that’s the case, then all derate coverage would be on the backs of load.”
The Protocol Revision Subcommittee (PRS) plans to return with new language for NPRR821 in September.
Small Municipalities’ Appeal Tabled Again
The committee once again tabled the Small Public Power Group of Texas’ (SPPG) appeal of a rejected revision to the Nodal Operating Guide (NOGRR149) regarding the definition of transmission owners. In granting a six-month extension until February, the TAC agreed to take up the “substance of the appeal” at that time.
The revision would exempt distribution service providers without transmission or generation facilities from having to procure designated transmission operator services from a third-party provider if their annual peak load is less than 25 MW. The proposal was developed in 2015 to settle the noncompliant status of six municipally owned utilities with loads from 9 to 21 MW.
The SPPG has been filing monthly updates since the appeal was last tabled in January. In its most recent, the group said, “significant progress has been made” in reaching permanent market solutions for its members’ designated TO service, but they have not yet been achieved.
“All of these have been proceeding as hard and as fast as they can,” said Tom Anson, legal counsel for SPPG. “These things take more time than you think. We want another six months to keep working hard at it.”
The appeal has now been tabled eight times since it was first brought to the TAC in March 2016, shortly after it failed to pass the Reliability and Operations Subcommittee.
PRS Adds Resource Definition Task Force
The PRS brought forward two unopposed NPRRs and announced the formation of the Resource Definition Task Force. The task force, chaired by Vistra Energy’s David Ricketts and ERCOT’s Jay Teixeira, will work to synch up the ISO and Public Utility Commission of Texas’ definitions.
The TAC tabled NPRR829, one of two unopposed revision requests, to allow ERCOT time to refresh its initial impact statement. Staff said it believes the second impact statement, which should be complete for the next PRS meeting, will come in above the current $120,000 to $160,000 estimate to implement.
NPRR829 requires the use of telemetered data from non-modeled generation in the day-ahead market to more accurately calculate QSE collateral requirements. The change will increase day-ahead liquidity through the increased participation of non-modeled generation, and potentially allows ERCOT to gain near real-time transparency into the generation.
The committee unanimously approved NPRR836, which incorporates the following “other binding documents” into the protocols as a new Section 23 (Forms): Congestion Revenue Right Account Holder Application Form, Load Serving Entities Application Form, Managed Capacity Declaration Form, Market Participant Agency Agreement Form, Notice of Change of Information, QSE Agency Agreement Form, QSE Application Form, Qualified Scheduling Entity Acknowledgement, Resource Entity Registration Form, Transmission/Distribution Service Provider Registration Form and WAN Agreement.
Changes to these Section 23 forms will be made using the NPRR process.
— Tom Kleckner
