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FERC, NERC to open joint inquiry into recent cold weather grid operations

February 16, 2021

by Paul Ciampoli
APPA News Director
February 16, 2021

The Federal Energy Regulatory Commission (FERC) and the North American Electric Reliability Corporation (NERC) announced on Feb. 16 that they will open a joint inquiry into the operations of the bulk-power system during the extreme winter weather conditions currently being experienced by the Midwest and South Central states.

The severe cold weather over the weekend, and continuing into this week, has contributed to power outages affecting millions of electricity customers throughout the region.

“For now, the emphasis must remain on restoring power to customers and securing the reliability of the bulk-power system,” FERC and NERC said.

“In the days ahead, FERC and NERC will formally begin the inquiry, which will work with other federal agencies, states, regional entities and utilities to identify problems with the performance of the bulk-power system and, where appropriate, solutions for addressing those issues.”

Grid operators, utilities continue to grapple with freezing temperatures

Grid operators and electric utilities on Feb. 16 continued to grapple with bitter cold temperatures and address strains on the power grid that resulted in rotating outages starting on Feb. 15.

SPP

SPP early on the morning of Feb. 16 said it was declaring an Energy Emergency Alert (EEA) Level 3 effective immediately for its entire 14-state balancing authority area. SPP said that systemwide generating capacity had dropped below our current load of approximately 42 gigawatts (GW) due to extremely low temperatures and inadequate supplies of natural gas.

“We’ll be working with our member utilities to implement controlled interruptions of electric service throughout our region,” SPP said. “This is done as a last resort to preserve the reliability of the electric system as a whole. Individuals in the SPP service territory should take steps to conserve energy use and follow their local utilities’ instructions regarding conservation, local conditions and the potential for outages to their homes and businesses.”

SPP said that it was forecasting a morning peak of above 44.6 GW around 9:00 a.m. Central time.

Nebraska public power utility Lincoln Electric System (LES) on Feb. 16 said it had been instructed to shed load by SPP, the balancing authority for LES.

Rotating outages, also known as rolling blackouts, are controlled, temporary interruptions of electricity that reduce demand on the system. Outages are typically limited to 30 to 60 minutes, but may last longer, before being rotated to another location, LES noted.

Customers may experience multiple outages, LES said Feb. 16. Locations of controlled outages are determined by load shed requirements from SPP, which happens in minutes.

Nebraska Public Power District (NPPD) on Feb. 16 said in a Facebook post that in order to maintain system reliability, “we have just been informed by SPP that we need to do emergency coordinated interruptions of service. These 30-minute interruptions of service occur in real-time, so we have very little, if any, notice as to where these interruptions will take place. This is done to prevent longer, uncontrolled outages. If you experience a controlled outage, it should only last approximately 30 minutes.”

Another Nebraska public power utility, Omaha Public Power District (OPPD), on the morning of Feb. 16 reported that it had rotated another 12,222 customers back online as controlled outages continued Tuesday morning.  Customers in Sarpy County and parts of west and central Omaha had been brought back online after undertaking approximately one-hour outages.

SPP “has directed all its member utilities, from North Dakota to Texas, to have controlled outages to help the power grid stay balanced. Record setting cold temperatures have settled in over the Central Plains region over the last few days and some snow and ice storms in the southern regions have also impacted the situation,” OPPD noted.

All utilities in the SPP footprint have been taking part in these controlled outages. For the OPPD area, those outages have been about one hour on a rotating basis. “While inconvenient for our customers and businesses impacted, the impacts of these outages have been minimal compared to winter snow and ice storms which can cause outages for days at a time.”

As of 10:05 a.m. CT, there were about 130 customers impacted by the rotating outages, OPPD said.

Missouri River Energy Services (MRES) noted that it was notified that SPP declared an EEA Level 3 starting on Feb. 16 at 6:15 a.m. “MRES had hoped to provide advance notice to its members but SPP was unable to notify us in time,” MRES said.

MRES is a joint-action agency made up of 61 member municipalities in the states of Iowa, Minnesota, North Dakota, and South Dakota. MRES provides its members with wholesale electricity along with a host of energy-related services.

MRES noted that the Western Area Power Administration (WAPA) and MRES are both transmission owners in SPP and both serve the power supply needs of MRES members, adding that MRES members located in the SPP footprint may be affected by this event.

Upon instructions by the reliability coordinator of SPP, WAPA began to curtail power to substations within the MRES membership, causing power outages in those communities. MRES was notified at about 10:50 a.m. that WAPA was in the process of restoring curtailed load. “MRES has no control over, and does not make any decisions regarding when and if these rolling blackouts are required,” it pointed out.

All MRES-operated generation resources have been operating to the fullest extent during this extreme weather event and are performing well, it said. Those include Laramie River Station in Wheatland, Wyoming, the Exira Station near Atlantic, Iowa, and the Watertown Power Plant in Watertown, South Dakota. Many MRES members with local generating units in their communities are also running those units to support power supply in the region.

MRES noted that it was asking its member municipal utilities to do whatever they can to reduce power usage in their communities, such as requesting that customers voluntarily reduce electric usage by delaying running the dishwasher and clothes washer, turning down the heat, and shutting off lights.

SPP subsequently declared a move from EEA Level 3 to EEA Level 2 at 11:30 a.m. Central time. “SPP’s forecasts anticipate that due to high load and persistent cold weather, it is likely its system will fluctuate between EEA levels over the next 48 hours,” it said in a tweet.

SPP as of 12:31 p.m. CT downgraded the EEA to level 1. This is declared when all available resources have been committed to meet obligations, and SPP is at risk of not meeting required operating reserves.

ERCOT

On Feb. 15, ERCOT reported that it had started to restore some of the power lost due to the winter weather event in Texas. As of 4 p.m. on Feb. 15, approximately 2,500 MW of load was in the process of being restored – enough power to serve 500,000 households. Earlier in the day, ERCOT entered emergency conditions and initiated rotating outages.

“The number of controlled outages we have to do remains high. We are optimistic that we will be able to reduce the number throughout the day.” Dan Woodfin, Senior Director of System Operations, said on the morning of Feb. 16.

ERCOT said in a Facebook post that it should be able to restore some customers the afternoon of Feb. 16 due to additional wind and solar output and additional thermal generation “that has told us they expect to become available. But, the amount we restore will depend on how much generation is actually able to come online.”

Texas Gov. Greg Abbott on Feb. 16 declared reform of ERCOT an emergency item this legislative session. “In declaring this item an emergency, the governor is calling on the legislature to investigate ERCOT and ensure Texans never again experience power outages on the scale they have seen over the past several days,” a news release from the governor’s office said.

Texas public power utilities

Texas public power utility CPS Energy on Feb. 16 said that extreme cold temperatures and high energy usage “are continuing to force multiple power outages across our community and our state. If you are currently experiencing an outage, it is possible that the outage will continue for longer periods,” it said on its Facebook page. “If you have power, it is also possible you may experience a power outage and you should plan accordingly. Please seek shelter if you are in need of assistance.”

San Antonio, Texas, public power utility CPS Energy on Feb. 16 said that after exhausting all other options, these additional controlled service interruptions are a last resort, “and a step we take only when necessary to safeguard continued reliability of the statewide” ERCOT grid.

CPS Energy officials on Feb. 16 held a media briefing via Facebook Live to provide the latest update on outages caused by the extreme cold temperatures.

CPS Energy officials participating in the briefing included Paula Gold-Williams, President and CEO, and Rudy Garza, Interim Chief Customer Engagement Officer.

Meanwhile, Texas public power utility Austin Energy on Feb. 16 reported that as electric providers all wait for the ERCOT grid to stabilize, customers who have sustained outages should expect those outages to continue until the situation improves.

“All of our crews are ready to restore power to those affected as soon as we are authorized to do so by ERCOT,” Austin Energy said.

“We recognize the hardships and understand why customers are frustrated,” it noted.

Austin Energy General Manager Jackie Sargent was joined by city and county officials on Feb. 16 in a virtual press conference to address the unprecedented severe weather that has impacted residents. The replay of the press conference is available here.

MISO

The Midcontinent Independent System Operator (MISO) and its members managed multiple interdependent issues this week including transmission constraints and generation outages, MISO said on Feb. 16. MISO is also supporting its members’ restoration efforts in the South Region which remains under emergency declarations due to high demand and frigid temperatures.

MISO on Feb. 16 noted in a tweet that in light of uncertain operating conditions, it had declared additional emergency actions including instructing South Region members to issue a Public Appeal to conserve electricity (https://www.misoenergy.org/mcsnotification/?id=1121).

MISO has issued several emergency declarations since last week, some of which resulted in temporary power interruptions in parts of Southeast Texas, Southwest/South-Central Louisiana and South-Central Illinois. Most of those outages have been restored. Load demand is being driven by the freezing temperatures expected through the rest of this week, the grid operator said.

MISO said it continues to actively monitor developments related to the Arctic Outbreak, including information and guidance from our members and weather experts.

NREL reports examine effects of solar penetration on grid stability

February 16, 2021

by Peter Maloney
APPA News
February 16, 2021

Rising contributions from variable generation sources, particularly photovoltaic (PV) solar, present challenges but, overall, the Western Interconnection has enough inherent flexibility and ramping ability to manage fluctuations in net load, a new report from the National Renewable Energy Laboratory (NREL) found.

The report’s authors also noted, however, that flexibility in the Western Interconnection is “heavily dependent” on transmission between regions and the dominant sources of ramping vary by region, and each region’s flexibility is dependent on one another’s ramping capability.

System flexibility can be provided from conventional generation, from less conventional generation – such as storage, demand response, concentrating solar power with thermal energy storage – as well as from imports and exports between neighboring regions, the report said.

The report, Power System Flexibility Requirements and Supply, is one in a series that examines the challenges related to planning power systems with higher solar photovoltaic penetrations.

The report, along with several others, was commissioned by the Western Interstate Energy Board (WIEB) as part of the Enhanced Distributed Solar Photovoltaic Deployment via Barrier Mitigation or Removal in the Western Interconnection project funded by the Department of Energy in collaboration with Lawrence Berkeley National Laboratory.

For its power system flexibility report, NREL created an open-source tool to analyze the flexibility of the results of a specific commercial unit commitment and economic dispatch tool (PLEXOS). The tool assesses the demand of a system through a net load analysis. The constraints and limitations of each generator are then considered to determine the available supply. Supply and demand are then compared to paint a more complete picture of potential flexibility concerns.

NREL’s reports for the project focused on four broad categories: bulk dispatch, system planning, dynamic stability, and the distribution grid.

NREL’s Resource Adequacy Considerations report examined the availability of resources to meet requirements during periods of peak load. The report found the Western Interconnection is overbuilt in general, with “extremely high levels of capacity adequacy,” and that the future buildouts computed by NREL’s models appear to have sufficient resources to serve peak net load with PV penetrations of up to 33%.

The authors said that planning reserve constraints used in resource planning may be conservative and could lead to higher-than-necessary investments in capacity resources. They cautioned, however, that a more accurate representation of the grid’s planning reserve needs could be achieved through studies that test NREL’s results under a wider range of system operating conditions and use more detailed representations of transmission and energy-limited resources.

Another NREL report, Simulating Distributed Energy Resource Responses to Transmission System-Level Faults Considering IEEE 1547 Performance Categories on Three Major WECC Transmission Paths, studied transmission issues related to wider solar power penetration. The report found that distributed energy resources could ride through transmission-level faults associated with prolonged voltage events, thereby limiting the impact of faults on power reliability by keeping more distributed generation online both during and after a disturbance.

NREL’s report on Behind-the-Meter Solar Accounting in Renewable Portfolio Standards, found that a common accounting practice among states has the potential to decrease the total amount of renewable generation in a state.

If a renewable portfolio standard (RPS) is designed so that behind-the-meter solar renewable energy credits (RECs) can be used for compliance and the load served by behind-the-meter solar generation is not covered by the RPS, the presence of behind-the-meter solar resources and the transfer of those RECs for compliance can decrease the total amount of renewable generation in a state, compared with a situation in which there is no behind-the-meter solar power, NREL said.

On the other hand, if load served by behind-the-meter solar generation counts toward the RPS load and behind-the-meter solar RECs cannot be used for compliance, the presence of behind-the-meter resources does not change the amount of RECs a utility is required to retire, but additional RECs will be retired by the behind-the-meter solar resource owner, increasing the total amount of renewable generation on a one-to-one basis as behind-the-meter solar generation rises.

Finally, NREL’s report on how power inverters used by distributed energy resources can influence grid stability. The report, Stability and Control of Power Systems with High Penetrations of Inverter-Based Resources: An Accessible Review of Current Knowledge and Open Questions, reviewed literature describing what may be required to transition from spinning inertia associated with traditional generation, to mostly inverter-based power systems and serves as a reference for grid operators and planners.

Iowa city extends contract with Heartland Consumers Power District

February 16, 2021

by Paul Ciampoli
APPA News Director
February 16, 2021

The city council of Stanhope, Iowa, recently voted to extend the city’s power supply contract with Heartland Consumers Power District through the year 2030.

Heartland began supplying the city with wholesale power and energy in 2014, expanding their customer base in the state of Iowa. Stanhope’s original contract was set to expire at the end of 2023.

Heartland approached the city about extending to continue taking advantage of stable pricing. The extension would also make Stanhope a long-term customer, giving them access to customer programs.

Along with stable, affordable electricity, Heartland noted that it also offers a suite of customer service programs to assist with economic development, energy efficiency and cybersecurity.

The new contract provides savings over their existing contract, as well as consistent pricing for the next 10 years, Heartland noted. The city council approved the new contract at a January 12 meeting.

Heartland’s energy efficiency program provides rebates for making energy efficient purchases. Upgrading lighting, water heaters and heating and cooling systems may qualify for incentives.

Heartland’s economic development program assists new and expanding businesses within customer communities. Growth incentives and utility rebates are available to qualifying businesses.

Heartland also offers programs to assist the city with infrastructure upgrades related to development, make energy efficient improvements at city facilities and protect valuable data from cyber thieves.

Stanhope is situated within the Midcontinent Independent System Operator (MISO) market and is connected to the ITC transmission system. Heartland will provide full-requirement power supply to the city.

Stanhope is home to just over 400 people.

Texas grid operator initiates rotating power outages in wake of freezing temperatures

February 15, 2021

by Paul Ciampoli
APPA News Director
February 15, 2021

In the wake of record-setting freezing temperatures, the Electric Reliability Council of Texas (ERCOT) entered emergency conditions and initiated rotating outages at 1:25 a.m. on Monday, Feb. 15.

Two other grid operators — the Southwest Power Pool (SPP) and the Midcontinent Independent System Operator (MISO) — were also taking steps in response to bitterly cold temperatures. SPP instituted rotating outages on Feb. 15.

“We continue to have communication with our members about this evolving situation and look forward to continuing to work with them to help address this serious situation,” said Joy Ditto, President and CEO of the American Public Power Association.

“A sprawling winter storm continued to sweep across the country on Monday, knocking out power for millions of people as it dumped snow and ice in places where such perilously frigid conditions tend to arrive just once in a generation,” the New York Times reported on Feb. 15.

ERCOT

About 10,500 megawatts of customer load was shed at the highest point, ERCOT said on Feb. 15.

“The entire state was below freezing on Monday, with temperature ranging from 25 degrees in Brownsville in the south to 15 degrees below zero in the Panhandle,” CNN reported in a story posted on its website.

Extreme weather conditions caused many generating units across fuel types to trip offline and become unavailable, ERCOT said, noting that there was over 30,000 MW of generation forced off the system as of the early morning hours of Feb. 15.

“Every grid operator and every electric company is fighting to restore power right now,” said ERCOT President and CEO Bill Magness, in a statement.

Rotating outages will likely last throughout the morning and could be initiated until this weather emergency ends, ERCOT said on Feb. 15.

On Sunday, Feb. 14, ERCOT asked consumers and businesses to reduce their electricity use as much as possible through Tuesday, Feb. 16.

“We are experiencing record-breaking electric demand due to the extreme cold temperatures that have gripped Texas,” said Magness. “At the same time, we are dealing with higher-than-normal generation outages due to frozen wind turbines and limited natural gas supplies available to generating units. We are asking Texans to take some simple, safe steps to lower their energy use during this time.”

ERCOT starts to restore power

Later in the day, ERCOT reported that it was beginning to restore some of the power lost due to the winter weather event in Texas.

As of 4 p.m., approximately 2,500 MW of load was in the process of being restored.

“ERCOT and Texas electric companies have been able to restore service to hundreds of thousands of households today, but we know there are many people who are still waiting,” said Magness. “It’s also important to remember that severe weather, mainly frigid temperatures, is expected to continue, so we’re not out of the woods.”

At the time, the grid operator said it was instructing transmission owners to shed approximately 14,000 MW of load, down from 16,500 MW earlier in the day.

Controlled outages will likely last throughout the evening and into Tuesday, Feb. 16 as ERCOT works to restore the electric system to normal operations.

White House issues emergency declaration

Texas Gov. Greg Abbott on Feb. 14 announced that the White House had issued a Federal Emergency Declaration for Texas in response to the severe winter weather throughout the state. The governor submitted a request for this declaration on Saturday to assist the state in response efforts related to the storm.  

The Federal Emergency Declaration authorizes the Federal Emergency Management Agency to provide emergency protective measures for mass care and sheltering and Direct Federal Assistance for all 254 counties in Texas.

Abbott on Feb. 12 declared a state of disaster in all 254 Texas counties due to severe weather posing an “imminent threat of widespread and severe property damage, injury, and loss of life due to prolonged freezing temperatures, heavy snow, and freezing rain statewide.”

Also on Feb. 12, the Railroad Commission of Texas issued an Emergency Order pursuant to Texas Utilities Code affecting the gas utility systems in the state. The order specified increasing the priority of gas supplies to ERCOT generators.

Public power utilities in Texas

Public power utilities in the state were affected by the outages and took a number of steps to keep their customers up to date with the latest news and ways that they can help conserve electricity.

In the early morning hours of Feb. 15, San Antonio-based CPS Energy noted that as part of its participation in ERCOT and the critical nature of this stage, “we are required to participate in coordinated rotating outages in an effort to prevent larger and more extreme impacts on the Texas grid. CPS Energy is also asking natural gas customers to reduce energy use as well.”

“Rotating outages are necessary to help preserve the integrity of the Texas electric grid,” said Rudy Garza, Chief Customer Engagement Officer for CPS Energy.  “It is crucial that we, along with other Texas utilities, implement rotating outages as directed by ERCOT. The mandatory request for load shed can be subsidized by residential and commercial customers doing what they can to reduce energy use.”

Meanwhile, Texas public power utility Austin Energy on the morning of Feb. 15 said that due to the severity of weather and the condition of the electric grid, rotating outages in the Austin Energy area were lasting longer than the expected duration. “To serve critical loads and protect the overall reliability of the grid, customers experiencing an ERCOT-directed outage will remain out until conditions improve,” it said.
 
“The situation continues to worsen across Texas and here in Austin,” said Austin Energy General Manager Jackie Sargent. “Austin Energy implemented required outages early Monday morning, doing our part to help stabilize the ERCOT grid. The required outages are more extensive than anyone expected and do not allow us to bring affected customers back online at this time. We will continue working with ERCOT and working through our contingency plans to get power back on to customers as soon as the grid allows.”
 
Conservation is still needed by those who have power. Customers are urged to keep electric use to only what is essential for heating and safety, Austin Energy said.

The utility noted that ERCOT declared an Energy Emergency Alert Level 3, calling for rotating outages across the state.  Rotating outages are controlled, temporary interruptions of electrical service implemented by utilities when it is necessary for ERCOT to reduce demand on the system. This type of demand reduction is only used as a last resort to preserve the reliability of the electric system as a whole.

When power is restored, circuits can become overloaded because of lights, electronics and thermostats left on prior to the outage. This is called cold load pickup and can cause a second outage.

Austin Energy said that customers currently without power can help the utility avoid cold load pickup by turning off their thermostats, turning off or unplugging any fixtures or appliances and only leaving on one light to indicate when the power is back on.

A number of other public power communities also proactively kept their customers up to date on the rotating outages.

In a Feb. 15 Facebook post, the City Hall of Denton, Texas, noted that the duration and frequency of outages depends on the severity of the event and the directions provided by ERCOT.

“Due to the severity of the statewide electric supply shortfall, our originally expected 30 min. outage time has been significantly extended,” the post said. “In addition, we are responding to separate outages caused by the record-breaking weather. We are doing everything possible to respond to this event and keep power on for as long as statewide electric supply will allow.”

The City of Denton is served by public power utility Denton Municipal Electric.

Texas public power utility Greeneville Electric Utility System (GEUS) issued a news release on Feb. 15 in which it noted that ERCOT is encouraging all consumers to reduce their electricity usage to the lowest possible. “Your conserving electricity now can improve ERCOT’s grid reliability and possibly avoid prolonged rotating outages and/or blackouts should conditions worsen,” GEUS said.

New Braunfels Utilities also issued a news release noting ERCOT’s declaration of an Energy Emergency Alert Level 3 and detailing steps that customers can take to help reduce electricity usage and manage their utility bills.

“It is very important that all utilities participate in helping reduce strain on the electric grid, and at this time ERCOT has determined that this can only be accomplished by shedding load from the system,” said Gary Miller, General Manager of Texas public power utility Bryan Texas Utilities.

“BTU’s primary concern is the safety and well-being of our customers, and while these outages are certainly not ideal, they are in the best interest of our service territory and the integrity of the Texas electric system as a whole.”

During this period of rolling blackouts, customers are urged to reduce their electric load to the smallest amount possible, by turning off all unnecessary lighting, appliances, and electronic equipment, BTU said. Additionally, businesses should avoid starting equipment that utilizes a large amount of electricity, and postpone any non-essential production processes, it said in a news release.

“ERCOT is doing everything in its power to keep the electric system from going critical. Consumers are asked to lower thermostats & turn off unneeded appliances/lights,” the public power city of College Station, Texas, said in a tweet.

Other Texas public power utilities and communities that issued news releases or leveraged their social media channels to provide updates on the rotating outages included the City of Georgetown, Kerrville Public Utility Board, Floresville Electric Light and Power System and Brownsville Public Utilities Board.

U.S. Department of Energy issues emergency order

On Feb. 14, the U.S. Department of Energy (DOE) issued an emergency order under section 202(c) of the Federal Power Act relaxing environmental restrictions on certain units in ERCOT through Feb. 19. The order was issued by David Huizenga, Acting Secretary of Energy.

“ERCOT is in the beginning stages of an unprecedented cold weather event brought on by a rare, southward excursion of the jet stream into the South Central United States,” the order states. Temperatures for Sunday and Monday in many parts of Texas are forecasted to drop well below the lowest temperatures experienced in several decades, and abnormally low temperatures are expected to persist for several more days. This weather event is expected to result in record winter electricity demand that will exceed even ERCOT’s most extreme seasonal load forecasts.”

ERCOT had asked the DOE to immediately issue an order, effective February 14, 2021 through February 19, 2021, authorizing “the provision of additional energy from all generation units subject to emissions or other permit limits” in the ERCOT region.

“Given the emergency nature of the expected load stress, the responsibility of ERCOT to ensure maximum reliability on its system, and the ability of ERCOT to identify and dispatch generation necessary to meet the additional load, I have determined that additional dispatch of the specified resources is necessary to best meet the emergency and serve the public interest for purposes of FPA section 202(c),” wrote Huizenga.

“Because the additional generation may result in a conflict with environmental standards and requirements, I am authorizing only the necessary additional generation, with reporting requirements” detailed in the order.

Southwest Power Pool

Meanwhile, due to an unprecedented energy demand during record low temperatures, SPP, Lincoln Electric System’s (LES) regional reliability coordinator, had notified utilities within its regional footprint that energy curtailments are required, LES, a Nebraska-based public power utility, said on Feb. 15.

SPP declared an Energy Emergency Alert Level 3, which means utilities across the SPP region have been instructed to begin rotating planned outages because there is not enough power available to keep up with customer demand, LES noted.

SPP reported late in the afternoon that after directing member utilities to implement controlled interruptions of service shortly after noon on Feb. 15, SPP had restored load to its 14-state region as of 2:00 p.m. Central time. “The grid operator now has enough generation available to meet demand throughout its service territory and to fully meet its minimum reserve requirements,” it said.

The SPP system reached a peak electricity usage of 43,661 MW on Feb. 15 and is required to carry additional operating reserves in excess of load, it noted. After committing all of its reserves and exhausting other avenues such as importing power from other regions, available generation in SPP fell about 641 MW short of demand for a period beginning just after noon. In response, SPP directed its member utilities to implement planned interruptions of service to curtail electricity use by that amount.

Effective at 2:00 p.m., SPP cancelled the Energy Emergency Alert Level 3 it had declared at 10:08 a.m. when its reserves were exhausted and re-entered an EEA Level 2. SPP’s forecasts anticipate that due to high load and persistent cold weather, it is likely its system will fluctuate between EEA Levels 2 and 3 over the next 48 hours and may have to direct further interruptions of service if available generation is inadequate to meet high demand.

At 10:08 a.m.  Central time on Feb. 15, SPP declared an Energy Emergency Alert Level 3 in response to conditions created by persistent and extreme cold across its service territory. An EEA3 signals that SPP’s operating reserves are below the required minimum. SPP has also directed its member utilities to be prepared to implement controlled interruptions of service if necessary to mitigate the risk of more widespread and longer-lasting outages.

LES had asked customers to continue to voluntarily and safely implement one or more energy-saving measures listed on LES.com.

LES later reported that it had stopped controlled outages after only going through two cycles. “While LES hasn’t received additional requests from the Southwest Power Pool to curtail, we ask customers to remain prepared for rotating outages over the next 36 hours,” LES said.

Another public power utility, Omaha Public Power District (OPPD) on Feb. 15 posted a tweet stating that OPPD and other utilities were asking customers to conserve energy now, “as the bitter cold continues in our region.” OPPD president and CEO Tim Burke addressed the polar vortex event in a YouTube video.

“We are asking customers to conserve energy,” Nebraska Public Power District (NPPD) said in a Feb. 15 Facebook post. “The record cold forecast is putting a high demand on the electrical system.”

In Missouri, City Utilities of Springfield reported that it had been told to reduce its electric load within the SPP. This is a combined group of power generating utilities throughout 14 states and all utilities are under similar reduction requirements. “This process has started at this time,” CU noted in a news release.

CU “will begin what is commonly known as a rolling blackout in sections of Springfield. These will last from 30 to 60 minutes in duration and will be executed in different areas of the city. All areas of the City Utilities electric service territory may potentially be impacted.”

The Kansas City Board of Public Utilities (BPU) on Feb. 15 reported that it was asking customers to conserve electricity use as much as possible through Wednesday, Feb. 17, at the request of SPP.

The SPP “advises that the region’s coldest weather in decades is creating high demand for electricity. At the same time, the extreme weather is driving high demand for natural gas used to heat homes and businesses, straining the gas supply available to generate electricity, and icy conditions have made availability of wind generation uncertain,” Kansas-based BPU said.

“Everybody must do their part to save electricity the next few days and this in turn will help us make sure the power supply continues to best serve the region’s needs,” said David Mehlhaff, BPU Chief Communications Officer.

Later in the day, BPU reported that beginning on February 15 at 12:10 p.m., BPU began to turn off electricity to blocks of customers for approximately 40 minutes. Once the period concluded, power was restored to the impacted area. The emergency outages will then rotate to another portion of BPU’s service area and power may cycle off and on periodically until the reduction is no longer required by the SPP, BPU said.

MISO also takes action in response to weather

Meanwhile, MISO on Feb. 15 said that sustained frigid temperatures and winter weather impacting the MISO South Region contributed to the loss of generation and transmission. This led to emergency actions in the region’s western portion to avoid a larger power outage on the bulk electric system.  Periodic power outages began early Monday morning for some customers in Southeast Texas.

“We fully committed every available operating asset before the event to lessen the impact on our system, but conditions eventually deteriorated to a point where demand exceeded supply,” said Renuka Chatterjee, executive director – System Operations at MISO. “The accelerated change in conditions led us to our last resort in order to maintain grid reliability and we are in direct communication with our members to support their restoration efforts in the affected areas.”

MISO and its members worked together to identify the worst-case scenarios to limit the effects of temporary power supply interruptions to those areas that will provide the most relief, it said. That plan focused on the forecasted load demand and expert weather forecast as well as the risks associated with generation availability and transmission capacity across the region.

“This was truly a coordinated effort with all of our members to avoid a potentially larger grid outage,” said Daryl Brown, executive director – South Region at MISO.  “We are in direct communication with our members in the affected area to support their restoration efforts.”

Periodic power outages are always the last stage of several emergency procedures and steps taken to maintain grid reliability, MISO said.

Later in the day, MISO declared a Maximum Generation Event – Emergency Event Step 2c in its South Region due to the extreme cold and weather conditions causing high demand on the bulk electric system.

The declaration was effective February 15 at 6 p.m. until 10 p.m. ET. As part of its emergency procedures, MISO directed South Region members to make a public appeal of conservation to their customers to avoid a larger power outage.

“The frigid temperatures have increased the number of uncertainties and conditions are changing to a point where demand could exceed supply,” said Chatterjee. “We’re moving into uncertain territory which is why we are asking the public for assistance.”

MISO said that this is a highly unusual situation with current power demand nearly exceeding what current generation and transmission can supply because of the extreme weather. The situation has been taking a toll on parts of the bulk electric system limiting MISO’s ability to import electricity from neighbors that are in a similar situation, it said.

“Our members regularly provide customers advice on how to conserve regardless of weather conditions,” said Brown. “However, we are specifically asking those customers in the South Region to heed that advice and limit electricity usage to only the most essential functions so we can avoid a larger grid outage.”

The Maximum Generation Event – Emergency Event Step 2c notification includes instructions for Local Balancing Authorities to issue a public appeal to reduce demand. MISO Operating Conditions FAQs provide details on the necessary steps to manage system demand and ensure grid reliability during tight situations. MISO said it woud continue closely monitoring conditions in the South Region for the duration of the winter weather event.

FERC closely monitoring weather conditions

The Federal Energy Regulatory Commission “is closely monitoring the extreme weather conditions occurring in much of the country and the impact they are having on electric reliability,” said FERC Chairman Richard Glick.

“The Commission is in contact with ERCOT, SPP and MISO — as the regions served by these grid operators have been particularly hard hit by record cold and wintry precipitation.  Safeguarding the reliability of the bulk power system is paramount and I have directed FERC staff to coordinate closely with the RTOs/ISOs, utilities, NERC, and regional reliability entities to do what we can to help,” he said. 

“In the days ahead, we will be examining the root causes of these reliability events, but, for now, the focus must remain on restoring power as quickly as possible and keeping people safe during this incredibly challenging situation.”

New report affirms that TVA, public power work best for serving region

February 12, 2021

by Paul Ciampoli
APPA News Director
February 12, 2021

The Tennessee Valley Authority’s business structure and the public power model continue to provide the greatest value to the ten million people in TVA’s seven-state service area, according to an independent assessment presented to the TVA Board of Directors at its quarterly business meeting.

Building on an earlier strategic review in 2014, the board commissioned Lazard to reassess TVA’s business performance through 2020 and determine if its current business model is a reasonable approach to fulfilling TVA’s mission in the future.

Lazard’s new report notes that TVA’s financial performance has been notably strong against both its own plan and the performance of other utilities, including reducing operating and maintenance budgets by $800 million and reducing debt below the $21.8 billion target three years ahead of plan, TVA said.

In addition, TVA’s improved business performance has enabled a reduction in effective wholesale power rates from those 10 years ago, a higher level of renewable energy production than its southeastern U.S. peers and stronger partnerships with local power companies that allowed for a rapid community response to the COVID-19 pandemic.

“Just as it did in 2014, Lazard’s assessment concluded that the public power model works and continues to provide the best value to the communities and customers we are privileged to serve,” said Jeff Lyash, TVA’s president and CEO, in a statement. “This independent report validates the effort and focus of the entire TVA team, as well as public power partners across the region.”

Lazard believes that its previous conclusions in the 2014 strategic assessment with respect to the benefits and considerations of alternative business models versus the public power model are still valid today.

“Under the investor-owned utility model, TVA would likely charge higher rates as equity investors would require a return on investment,” the report said. “It would also be unclear how TVA’s non-power mission and activities would logically fit within such a structure — any reductions in the scope of the non-power mission and activities could have a negative impact on TVA’s service area,” Lazard said.

TVA also said that the effectiveness of its business model was supported as part of an independent review of CEO compensation discussed at the Feb. 11 meeting. 

The review by the FW Cook firm concluded that the board’s compensation process is best practice and, with expanding inclusion of government agencies and non-profit entities, uses the most relevant market data to be consistent with requirements of the TVA Act.

Reviewing Lyash’s performance and leadership during the challenges encountered in Fiscal Year (FY) 2020, the board approved the FY21 CEO total direct compensation granted resulting in an increase from 37% to 28% below the market median of CEO compensation.

Nearly two-thirds of the CEO’s total direct compensation is performance-based and at risk, which is an increase from 65% in FY20 to 66% in FY21.

TVA said that its first-quarter base revenue and net income remained favorable to budget even as revenues were lower than a year ago, in part due to the TVA pandemic relief credit that began in October and returns 2.5% of the base wholesale rate each month to local power companies, their large commercial and industrial customers and TVA directly-served customers. Nearly $49 million was returned in the first quarter, and the credit will continue through the end of FY21.

On Feb. 12, TVA reported $2.3 billion in total operating revenues on 36.7 billion kilowatt-hours of electricity sales for the three months ending Dec. 31, 2020.  

Sales of electricity to local power companies were not significantly impacted by the ongoing COVID-19 pandemic but were slightly lower compared to the same period of the prior year due to milder weather. Sales to directly served industries and others increased.

Total operating revenues decreased about 11% over the same period of the prior year, driven primarily by lower demand volume, lower effective base rates, and lower fuel cost recovery revenues. 

Hydropower grew faster in the last 10 years than other forms of storage

February 12, 2021

by Peter Maloney
APPA News
February 12, 2021

Over the past decade, pumped hydropower storage (PHS) capacity grew by almost as much as all other forms of energy storage in the United States combined, which were mostly battery storage installations, according to a recently released Department of Energy (DOE) report.

Pumped hydropower storage capacity increased by 1,400 megawatts (MW) from 2010 to 2019, the report noted. Almost all of the growth came from upgrades to six existing PHS plants: Castaic in California, Northfield Mountain in Massachusetts, Muddy Run in Pennsylvania, and Bad Creek, Fairfield, and Jocassee in South Carolina.

Since 2010 a total of $7.8 billion has been invested in pumped hydropower storage refurbishments and upgrade with almost $2 billion of the total investment for projects initiated between 2017 and 2019.

All other utility-scale energy storage projects deployed by the end of 2019, mostly battery storage projects, had a combined power capacity of 1.6 GW and energy storage capacity of 1.75 GWh.

In all, there are 43 pumped hydropower storage plants in the U.S. with total power capacity of 21.9 gigawatts (GW) and estimated energy storage capacity of 553 gigawatt hours (GWh), which accounted for 93% of utility-scale storage power capacity (GW) and more than 99% of electrical energy storage (GWh), according to the DOE report.

Looking forward, pumped hydropower storage appears poised to continue its upward trajectory. The pumped hydropower storage project development pipeline doubled in the past five years, according to the report. At the end of 2019, there were 67 pumped hydropower storage projects, representing 52 GW, under development, ranging in size from 5 MW to 4,000 MW. Geographic interest in pumped hydropower storage has expanded with new projects being explored in New York, Ohio, Oklahoma, Pennsylvania, Virginia, and Wyoming.

Overall, hydropower capacity saw a net growth of 431 MW between 2017 and 2019, mostly from capacity increases at existing facilities, new hydropower in conduits and canals, and by powering non-powered dams. At the end of 2019, U.S. hydropower totaled 80.25 GW, accounting for 6.7% of the country’s installed generation capacity.

In 2019, hydropower generated 274 terawatt hours (TWh), representing 6.6% of U.S. electricity generation and 38% of electricity from renewables.

The most recent U.S. Hydropower Market Report is the third edition and covers the years 2017 through 2019. The previous editions were published in 2015 and 2018. The report combines data from public and commercial sources, as well as research findings from other Department of Energy research and development projects.

Members of Southeast energy exchange market file for approval at FERC

February 12, 2021

by Paul Ciampoli
APPA News Director
February 12, 2021

Members of the Southeast Energy Exchange Market (SEEM) on Feb. 12 filed with the Federal Energy Regulatory Commission (FERC) for the approval of an automated, intra-hour energy exchange.

The FERC filing and approval process will provide an opportunity for the members of SEEM to demonstrate the benefits of the proposed market design and for interested parties to provide feedback and comments for FERC to consider, according to a news release related to the filing.

Founding members of SEEM are expected to include:

Participation in SEEM is open to other entities that meet the appropriate requirements. Some utilities will make decisions about whether to commit following FERC approval. 

The new SEEM platform will facilitate sub-hourly, bilateral trading, allowing participants to buy and sell power close to the time the energy is consumed, utilizing available unreserved transmission.  The platform is an extension of the existing bilateral market.

The result will be cost savings and improved integration of all energy resources, including renewables, which are expanding rapidly in the Southeast, the news release said.

NREL outlines four-phase framework for energy storage development

February 11, 2021

by Ethan Howland
APPA News
February 11, 2021

With energy storage deployments growing, Department of Energy researchers have developed a four-phase framework to help utilities and others understand the technology’s possible evolution on the grid.

The National Renewable Energy Laboratory researchers expect their report — The Four Phases of Storage Deployment: A Framework for the Expanding Role of Storage in the U.S. Power System — will help utilities, regulators and other stakeholders evaluate different pathways for storage and other sources of grid flexibility.

The report released late last month is the first publication to come out of NREL’s multi-year Storage Futures Study, which will explore energy storage technologies across a range of potential future cost and performance scenarios through 2050.

There are about 24,000 megawatts of energy storage on the U.S. grid, mainly in the form of pumped hydroelectric facilities that pump water from a lower reservoir to an upper reservoir when electric demand is low and then run the water through turbines back to the lower reservoir when power is needed.

Looking ahead, the NREL researches expect energy storage to develop in four phases, with the storage’s duration increasing in length in each successive phase.

The boundaries between the phases will be indistinct and the transition between phases will vary between regions, driven partly by how much wind and solar are added in each region, according to the researchers.

The first phase started around 2011 and is characterized by energy storage with no more than one-hour duration that can provide operating reserves, according to the report.

The potential deployment of short-duration storage is limited by the overall need for operating reserves, which is less than 30,000 MW in the United States, the researchers said.

The second phase, which has started in some areas, centers on storage with two to six hours of discharge duration to provide peaking capacity, according to the NREL framework.

Energy storage in the second phase gets most of its value from replacing traditional peaking resources, mainly natural gas-fired combustion turbines, the researchers said.

The opportunities for storage in the second phase are tied to the local or regional length of the peak demand period, the NREL researchers said, noting the phase could support at least 40,000 MW of storage.

The second phase is characterized in part by the positive feedback between solar photovoltaics increasing the value of storage by boosting its ability to provide capacity and storage increasing the value of solar by augmenting its energy value by shifting its output to periods of greater demand, the researchers said.

“Thus, greater deployment of solar PV could extend the storage potential of Phase 2 to more than 100 GW in the United States in scenarios where 25% of the nation’s electricity is derived from solar,” the researchers said.

The third phase of the storage framework is characterized by lower costs and technology improvements that enable storage to be cost-competitive while serving longer-duration peaks that last four to 12 hours, according to the report.

“Deployment in Phase 3 could include a variety of new technologies and could also see a reemergence of pumped storage, taking advantage of new technologies that reduce costs and siting constraints while exploiting the 8+ hour durations typical of many pumped storage facilities,” the NREL researchers said.

Technology options for the third phase include next-generation compressed air and various thermal or mechanical-based storage technologies, according to the report.

The researchers said storage in the third phase might provide additional sources of value, such as transmission deferral and additional time-shifting of solar and wind generation to address diurnal mismatches of supply and demand.

There is at least 100,000 MW of new storage opportunities in the third phase, according to the report.

The final phase is the most uncertain and is characterized by storage with durations lasting from days to months that could help achieve very high levels of renewable energy in the power sector, or as part of multi-sector decarbonization, the researchers said.

Potential phase-four technologies include production of liquid and gas fuels that can be stored in underground formations for a long time with very low loss rates, according to the report. There could be roughly 250,000 MW of storage in the fourth phase.

Upcoming reports from the Storage Futures Study will cover the economic potential of diurnal storage, the implications of widespread storage deployment and other topics.

TVA to help develop statewide electric vehicle fast charging network in Tennessee

February 10, 2021

by Paul Ciampoli
APPA News Director
February 10, 2021

The Tennessee Valley Authority (TVA) and the Tennessee Department of Environment and Conservation (TDEC) on Feb. 3 announced that they are partnering to develop a statewide electric vehicle fast charging network to spur the growth of EVs across Tennessee and reduce barriers to transportation electrification.

TDEC and TVA signed an agreement to collaborate and fund a network of fast charging stations every 50 miles along Tennessee’s interstates and major highways.

The initiative would add approximately 50 new charging locations, tripling the existing fast charging network.

There are only 24 fast charging locations currently operating in Tennessee that are open to all consumers and support both charging standards common to EVs, TVA noted in a news release.

TVA said that a network of public fast charging stations will promote EV growth by giving drivers more confidence that they will have easy access to refueling while they are away from home, eliminating so-called “range anxiety” that keeps many consumers from considering EVs a viable option.

EV adoption will spur jobs and economic investment in the region, keep refueling dollars in the local economy, reduce the region’s largest source of carbon emissions, and save drivers and fleets money, TVA said.

TDEC and TVA will leverage various funding sources to support the development of the fast charging network with an anticipated project cost of $20 million.

TDEC has committed 15 percent, the maximum allowable, of the state’s Volkswagen Diesel Settlement Environmental Mitigation allocation to fund light-duty EV charging infrastructure. Approximately $5 million from this fund is expected to be allocated to fast charging infrastructure along corridors.

The remainder of the project will be funded by TVA, other program partners, and program participant cost share.

The agreement reflects recommendations outlined in the Tennessee Statewide EV Charging Infrastructure Needs Assessment, conducted in 2019 by Drive Electric Tennessee, a consortium that includes TDEC, TVA and the Tennessee Department of Transportation.

The agreement will support Drive Electric Tennessee’s goal of 200,000 light-duty EVs in Tennessee by 2028. As of December 2020, 11,034 light-duty EVs were registered in Tennessee.

TVA is working with a group of local power companies to design a charging station experience convenient for drivers, located close to major highways, and featuring access to amenities that drivers expect, it said.

To learn more about this partnership, the memorandum of agreement, and Tennessee’s Volkswagen Diesel Settlement Environmental Mitigation Trust Beneficiary Mitigation Plan, visit www.tva.com/ev and www.tn.gov/EVFastCharge.

The American Public Power Association offers a Public Power EV Activities Tracker that summarizes key efforts undertaken by members — including incentives, electric vehicle deployment, charging infrastructure investments, rate design, pilot programs, and more.

NERC sees growing role for battery storage, calls for further studies

February 10, 2021

by Peter Maloney
APPA News
February 10, 2021

Battery energy storage can provide essential services to ensure the reliability of the bulk power system, but system planners need to conduct more analysis in order integrate higher levels of storage into the grid, according to a report released by the North American Electric Reliability Corporation (NERC) this week.

Battery energy storage can contribute to the reliable operation of the bulk power system “in a similar fashion as synchronous resources that provide those same necessary characteristics to the grid,” the report said.

“North America currently has less than 2 GW [gigawatts] of battery storage, but that capacity is projected to increase 100 percent to 4 GW by 2023,” Thomas Coleman, NERC’s chief technical advisor of engineering and standards, said in a statement. “It is abundantly clear that battery energy storage systems have a key role” in the “rapid transformation of the transmission grid” to meet goals for the reduction of carbon dioxide emissions while maintaining reliability, security and resilience, he added.

NERC cited Department of Energy projections that by 2050, 35 percent of the United States’ energy will come from wind power (404 GW) and 27 percent will come from solar photovoltaic power (632 GW).

As the amount of renewable generation on the grid has grown, battery energy storage has also expanded. In 2014, utility-scale battery storage capacity in North America was approximately 214 megawatts (MW). By 2019, battery storage increased to 899 MW. “This growth is expected to continue with utility scale storage levels reaching 3,500 MW by 2023,” the NERC report said.

Battery energy storage can play several roles in the transformation of the grid, NERC said, identifying functions such as supplying peaking capacity; minimizing the need for new generation and transmission infrastructure, and providing reliability services such as frequency response, ramping and voltage support.

To keep pace with this transformation, however, NERC said electric system planners “should conduct further analysis to model a system with significant battery storage and hybrid power plants.”

And while existing NERC reliability standards adequately cover existing battery storage installations, the report recommended “NERC should conduct a thorough assessment of existing standards and guidelines to ensure that they adequately consider the projected large increase in battery energy storage systems.”

In addition, the report said that data on battery storage “lacks consistency across reporting entities, necessitating a need for better reporting mechanisms for this type of data.” NERC recommended that entities that compile battery data information enhance both their data and their reporting methods.

NERC also said that the value of battery storage as a complement to variable energy resources, such as wind and solar, should be fully understood by system planners and operators. “System planners must conduct adequate studies to determine the dynamic stability impacts of battery storage interconnection, the capability to provide capacity to meet long-term and contingency reserve margin requirements and the ability to provide essential reliability services.”

The report also recommended that NERC’s Reliability and Security Technical Committee form a task force to study the implications of battery energy storage systems and their overall effects on bulk power system reliability and resilience.

“As we continue to assess the implications created by the integration of cutting-edge technologies to the electrical grid and the increasing amount of projected battery storage in the future, industry and regulators must pay more attention to bulk power system-connected battery energy storage systems,” Coleman said.