By Shaina Cole | Contributing Writer, Rocky Mountain Voice
On April 1, Colorado Springs Utilities and Platte River Power Authority, two of the utilities that initiated SPP’s western expansion effort, joined other Colorado utilities in the Southwest Power Pool, a regional grid operator headquartered in Little Rock, Arkansas. Neither utility was legally required to join. Both chose to.
Jason Frisbie, Platte River’s general manager and CEO, said the move would help his utility “maintain the reliability and affordability that our communities and their customers expect.”
One hundred and ten days later, Frisbie was asking those same communities to hold off on running their dishwashers.
“We are monitoring conditions and working closely with SPP regarding this emergency alert,” Frisbie said in a July 20 notice to customers in Fort Collins, Loveland, Longmont, and Estes Park, “and we are asking customers to reduce their demand for electricity.”
Colorado Springs Utilities issued its own conservation appeal the same day.
Danielle Nieves, Senior Public Affairs Specialist for the utility, told RMV that CSU “anticipated a high demand for local power on Monday, July 20, due to load forecasts and continued high temperatures” and “issued an appeal to customers to conserve energy earlier in the day through media outreach.”
From April 1 through August 5, SPP had some form of grid notice in effect for its western region on at least 56 of 127 days, by RMV’s count of SPP’s posted notices. Most were advisories that SPP classifies as normal or stable conditions.
The period also included five posted emergency alerts, including one at SPP’s highest level.
What happened on July 20
SPP operates a tiered alert system. It classifies resource advisories as normal conditions and conservative operations advisories as stable conditions. Energy emergency alerts indicate increasingly serious risks to the balance between available power and demand.
On July 20 at 4:38 p.m. Central Time, SPP declared an Energy Emergency Alert Level 1 for its western region, meaning all available generation had been committed and operating reserves were at risk.
Twenty-nine minutes later, at 5:07 p.m., SPP escalated to Level 3, its highest alert and the level at which controlled service interruptions may be directed. It held that level for 53 minutes before conditions improved.
SPP directed no controlled power cuts. SPP’s own grid-conditions page confirmed at the time that “no controlled service interruptions (load shed) have been directed.” Meghan Sever, a spokesperson for SPP, told RMV that “these emergency protocols operated as anticipated” and that “service was not interrupted.”
The federal government responded the same day.
The Department of Energy issued an emergency order authorizing SPP to dispatch specified generating units as needed for reliability, with emissions and operating hours incurred under the order not counted toward applicable rolling-average limits.
A second order followed six days later, and a third was requested by SPP itself, extending the emergency authority through August 10. SPP ended its conservative operations advisory on August 4, citing improved conditions.
The plants authorized for emergency dispatch included resources connected to the Colorado utilities that had asked customers to conserve.
Craig Station, a coal plant in Moffat County, had all three units named on the federal dispatch list.
Platte River is one of five co-owners of Craig Units 1 and 2. Tri-State owns Unit 3 outright.
Platte River’s own Rawhide Unit 1, a 280-megawatt coal plant near Fort Collins, was also on the list, along with eight Colorado Springs Utilities natural-gas units and two 570-megawatt coal units at Wyoming’s Laramie River Station, where Tri-State is a minority owner.
The orders and the dispatch list do not show which of those units were available or actually called on during the July 20 emergency.
Who has oversight
Two days after the July 20 event, Colorado Public Utilities Commission Chairman Eric Blank raised it at the Commission’s weekly meeting. He asked PUC staff what had happened.
Erin O’Neill, the PUC’s deputy director of fixed utilities, said she believed the Commission knew little about the system conditions that led to the alert.
She offered to report back after staff had more time to investigate. That was the extent of the Commission’s discussion at the July 22 meeting. RMV found no follow-up item concerning the event in the Commission’s publicly posted weekly meeting agendas through August 5.
Megan Castle, the PUC’s communications director, told RMV that the Commission does not have regulatory authority over SPP’s western operations. “SPP’s operation of its West Balancing Authority Area is subject to the Federal Energy Regulatory Commission (FERC), not state jurisdiction,” Castle said. The Colorado PUC’s role is indirect: it appoints one commissioner to SPP’s Regional States Committee, which has certain regulatory and comment authority at FERC.
Platte River’s own answer to whether it drew on Craig Station’s capacity during the emergency reflected what changed on April 1. “Now that we’re in the RTO, SPP dispatches resources to meet regional demand, including Platte River’s service territory,” Kendal Perez, a spokesperson for the utility, told RMV.
Under RTO membership, dispatch decisions are coordinated regionally through SPP.
Xcel Energy, which is not a member of SPP’s western region, confirmed to RMV that it exported ‘a small amount of electric power’ to SPP on July 20 during the emergency.
Michelle Aguayo, a senior media relations representative for Xcel said “We only allow such transfers when energy is available and will not impact reliability of service to Colorado customers.”
What the utilities say now
SPP and the Colorado utilities that joined it say the system performed as designed.
Sever, the SPP spokesperson, told RMV that the western region spent “about 7.5 hours outside normal and/or stable grid conditions” in its first 122 days, “less than one percent of the total time since expansion.”
She said SPP issued a total of 16 advisories and alerts for the western region in that period, compared to three resource advisories for SPP’s eastern region. “In the short term, the same challenges that existed in the West prior to expansion are likely to require SPP to continue using tools like resource advisories, conservative operations advisories and energy emergency alerts to reduce reliability risks,” she said.
Colorado Springs Utilities told RMV its preliminary estimated savings from SPP membership were $7 million between April 1 and July 25. “We remain confident in the importance of membership in SPP to maintain reliability and cost-effective power for our community,” Nieves said.
Platte River said “the advisories issued by SPP during this time worked as designed” and that “there were no service interruptions within our owner communities or the broader region.” Perez noted that several Colorado utilities, including Platte River, set new record peak loads during the period.
Where things stand
The conservative operations advisory that took effect July 20 ended August 4, replaced by a resource advisory. SPP placed the western region under a new conservative operations advisory beginning August 6.
Federal emergency authority first applied July 20 and 21, then resumed July 26 and continued through August 10.
No follow-up concerning the event appeared on the Commission’s weekly meeting agendas through August 5. SPP directed no controlled service interruptions, and the emergency ended without an SPP-related blackout.
The event prompted conservation appeals from two Colorado utilities and a small power transfer from a third.
The broader period of constrained conditions brought three federal emergency orders. Colorado’s utility regulators do not have jurisdiction over the regional operator that now dispatches part of the grid.