Friday, August 18, 2017

SPP Markets and Operations Policy Committee Briefs

AEP Project’s 41% Overrun Approved

LITTLE ROCK, Ark. — The SPP Markets and Operations Policy Committee endorsed a 41% increase in a delayed 345-kV project along the Red River in southeastern Oklahoma as reasonable and reset the project’s baseline.

American Electric Power was supposed to have upgraded a pair of substations and built 76 miles of transmission line between Valliant, Okla., and a substation outside Texarkana, located on the Texas-Arkansas border, for $131.7 million. That total has grown to $185.8 million following a two-year delay attributed mostly to weather. The project was supposed to be energized in October 2014, but that date has now slipped to December 2016.

AEP’s Brian Johnson said the company was late to notify SPP of the delay because of internal communication problems between project management and those reporting costs. He said the company didn’t realize how far the project was outside its bandwidth until July, calling the situation “embarrassing.”

The company attributed 51% of the cost overruns to extensive flooding along the 76-mile route. The project was also hampered by siting problems and a landowner group’s opposition. “It was a combination of everything,” Johnson said.

The Project Cost Working Group, which reviews projects when updated cost estimates fall outside a 20% bandwidth, passed the recommendation on to the MOPC with a no vote from Kansas City Power & Light and two abstentions.

SPP Regional Entity: Wind Farms not Meeting New Standards

SPP Regional Entity General Manager Ron Ciesiel said wind farms unfamiliar with new NERC standards for reactive power, voltage controls and frequency caused a spike in reported reliability violations during the third quarter.

SPP Markets and Operations Policy Committee Briefs

| SPP

There were 71 violations of the MOD-025-2 (Verification and Data Reporting of Generator Real and Reactive Power Capability and Synchronous Condenser Reactive Power Capability), PRC-019-2 (Coordination of Generating Unit or Plant Capabilities, Voltage Regulating Controls, and Protection) and PRC-024-2 (Generator Frequency and Voltage Protective Relay Settings) standards, most of them by individually registered wind farms.

“The only good news is they aren’t operating problems,” Ciesiel said. He said the violations resulted from wind generators’ lack of awareness with the new standards’ implementation plan and a shortage of third parties to conduct testing. Only 40% of the generation units covered by the new standards had their capability tested or settings verified by July 1, when the standards took effect, Ciesiel said.

The RE expects to report more than 200 violations this year, a number it hasn’t topped since 2011.

Ciesiel said 33 new or revised standards will take effect over the next 12 months.

Members Vote to Cancel 69-kV line in West Texas

The MOPC approved staff’s recommendation to withdraw a notice-to-construct (NTC) for the Hobart City-Roosevelt Tap-Snyder 69-kV line in West Texas, based on the availability of an AEP operating guide that can mitigate the congestion through pre-emptive redispatch.

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| © RTO Insider

The project was one of five withheld from the 2016 Integrated Transmission Plan (ITP) Near Term portfolio to determine whether they were needed to solve Scenario 5, which assumes renewable energy operating at 100% capacity.

Staff found while there have been 17 hours of congestion in the area since 2014, the 2017 ITP 10-year study indicated there were no congestion hours or future needs for the project, which had an estimated cost of $31 million.

Southwestern Public Service’s Bill Grant abstained from the vote, saying he did not want to live with operating guides forever.

The committee also endorsed staff’s recommendation to accelerate the NTC for an Oklahoma Gas & Electric 345-kV circuit upgrade project, but to leave a SPS 230-kV circuit upgrade in West Texas as is.

SPP staff said OG&E’s Amoco–Sundown project is necessary to meet additional congestion expected from more than 300 MW of wind energy added to the system this summer. With more wind energy on the way in Oklahoma, staff pushed the project’s in-service date to April 2018, a year earlier than originally planned.

SPP’s recent Wind Integration Study pegged both projects for further analysis. (See Study: 60% Wind Penetration Possible in SPP.)

MWG Clears 15 Change Requests

The Market Working Group brought five revision requests to the MOPC, which approved all over a small handful of no votes and abstentions. The committee unanimously approved 10 more changes as part of its consent agenda.

A revision request concerning the triggering of shortage pricing (MWG-MRR175) generated the most discussion among members — some concerned over sudden price spikes, others over a lack of scarcity events. The change incorporates language to comply with FERC Order 825 by using shortage pricing for any interval in which energy or operating reserves are short during the resources’ pricing. The change applies to any shortage, regardless of the duration or its cause. (See FERC Issues 1st RTO Price Formation Reforms.)

“Price spikes that occur over certain intervals can wipe out the entire day,” Nebraska Public Power District’s Paul Malone said. “There doesn’t seem to be any discussion about what can be done to mitigate this stuff. You can’t respond to a $500 price spike over five-minute intervals.”

SPP Markets and Operations Policy Committee Briefs

Carl Monroe, SPP (L) and MOPC Chairman Noman Williams, Golden Spread Electric Cooperative | © RTO Insider

The MWG recommendation was pushed for approval this month because it is a compliance matter. SPP staff and the group will both continue working to improve the process.

“We’re going to go back and see if we can make it better,” said Richard Dillon, SPP’s director of market design. “Scarcity pricing … is becoming more prevalent in the industry. We’d like to take a second look and see if we can do something better than the industry.”

“This will happen,” said AEP’s Richard Ross, chair of the MWG. “We are motivated to do something else, and staff is motivated to do something else.”

The motion passed with three no votes and two abstentions.

Golden Spread Electric Cooperative cited Order 825 in opposing a related change, (MWG-MRR173), which replaces the terms “head-room” and “floor-room” with “instantaneous load capacity.” Golden Spread said procuring rampable capacity for instantaneous load change, hourly load forecast or variable resource output through reliability unit commitment “masks shortage conditions in a manner inconsistent with the requirements of FERC’s shortage-pricing rule.”

Other rule changes approved by the committee were:

  • MWG-MRR183: Updates the violation relaxation limits (VRLs) operating constraint based on staff’s annual analysis, allowing additional redispatch to solve cases with fewer violations. Golden Spread abstained.
  • MWG-MRR188: Gives staff the option to include up to 100% of instantaneous load capacity (as opposed to the current 0% of capacity) in clearing the day-ahead market, an effort to minimize the gap between day-ahead and real-time energy prices. The motion received nine abstentions.
  • MWG-MRR193: Adds rules for solar resources to the market protocols and Tariff, including incorporating a solar forecast in SPP studies, increasing the solar forecast’s accuracy and including solar resources in dispatchable variable energy resource registration. Nebraska Public Power District cast an opposing vote, contending behind-the-meter generation would be required to register in the market should their loads change and they end up injecting power onto the system.
  • BPWG-RR123: Removes obsolete language and clarifies SPP’s current practices for short-term service requests and the system impact study process.
  • MWG-MRR178: Specifies that SPP’s Market Monitoring Unit will review the costs included in each mitigated resource offer, on an ex-post basis.
  • MWG-MRR179: Aligns the protocols with FERC-approved language (ER15-2265) ensuring long-term congestion rights are not affected by potential resource hub terminations, and that resource hubs used in bilateral contracts can’t be unilaterally terminated by the hub’s owner.
  • MWG-MRR181: Corrects outdated references in the Tariff and protocols related to the allocation of annual auction revenue rights, an oversight noted by FERC (ER16-13).
  • MWG-MRR182: Removes the term “control area,” which is no longer used by SPP, from the market protocols.
  • MWG-MRR184: Exempts resources from charges when they clear the day-ahead market with real-time meter readings of zero following either decommitment by SPP or dispatch to zero.
  • MWG-MRR185: Clarifies which document — SPP Planning Criteria or SPP Operating Criteria — is referenced when used in the market protocols and Tariff.
  • ORWG-RR168: Requires transmission owners to provide the highest available emergency ratings and specifies SPP’s interpretation of those ratings.
  • RTWG-RR176: Corrects and clarifies the responsibilities and requirements under the process that allows generation resources to be compensated for reactive support.
  • TWG-RR174: Revises Attachment AQ of the Tariff to no longer require transmission customers to submit a request for changes in delivery point facilities without a corresponding change in load.

Tom Kleckner

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