Public power utilities prepare for Tropical Storm Marco, possible hurricane
August 24, 2020
by Paul Ciampoli
APPA News Director
August 24, 2020
Public power utilities across several states were preparing for Tropical Storm Marco to make landfall on Aug. 24 and a second tropical storm that was set to enter the Gulf of Mexico by early Tuesday and potentially strengthen into a significant hurricane.
Tropical Storm Marco on Monday, Aug. 24, was “weakening but will track near the northern Gulf Coast into Tuesday, where it will bring locally heavy rainfall and gusty winds to parts of Louisiana, Mississippi, Alabama and the Florida Panhandle,” the Weather Channel reported.
In advance of Marco, the City of Tallahassee, Fla., sent crews to Louisiana to be on hand to help public power utility Lafayette Utilities System (LUS).
LUS noted that Tallahassee was sending four overhead crews ahead of Marco and Laura as part of mutual aid to help LUS “with unprecedented back-to-back storms.”
Through its social media channels, LUS thanked Tallahassee and the Florida Municipal Electric Association (FMEA) for the assistance.
LUS also utilized its social media channels to remind customers that they could download the public power utility’s hurricane handbook to prepare for Marco and Laura.
Meanwhile, public power utilities in Texas, Alabama, Georgia and Mississippi were also preparing for any impacts from Marco and Laura.
Second tropical storm could become major hurricane
Tropical Storm Laura on Aug. 24 was generating heavy rainfall in Cuba and the Cayman Islands and was set to enter the Gulf of Mexico by early Tuesday, the Weather Channel reported.
Over the weekend, the storm caused some impacts to Puerto Rico and scattered outages to the US Virgin Islands. As of Monday morning, there were approximately 20,000 customers out in Puerto Rico, down from a peak of approximately 190,000.
Tropical Storm Laura “could strengthen quickly into a major hurricane in the Gulf of Mexico with a dangerous threat of storm surge along parts of the Louisiana and Texas coasts, and threats of flooding rain and strong winds extending well inland later in the week,” the Weather Channel said.
Protecting criticial energy infrastructure: Q&A with CISA’s Harrell
August 21, 2020
by Paul Ciampoli
APPA News Director
August 21, 2020
A Q&A with Brian Harrell, Assistant Director for Infrastructure Security at the Cybersecurity and Infrastructure Security Agency, Department of Homeland Security. Harrell submitted these responses in August 2020. On August 20, 2020, he announced that he will be resigning from CISA.
How can the Cybersecurity and Infrastructure Security Agency help public power utilities on the cybersecurity front? What resources are available to public power utilities?
CISA is in a unique position because we are able to work with our critical infrastructure partners by bringing together an array of solutions across every sector, whether we are adopting new technology ourselves, helping our stakeholders securely adopt new technology, or in some cases looking at how our adversaries are adopting and utilizing new technological developments. Our goal is to help those that own and operate our Nation’s infrastructure understand and manage the risks they face. In these efforts, CISA works hand in hand with the critical infrastructure community by offering a number of voluntary programs, services and products, including: cybersecurity risk management and resilience services and tools; technical assistance upon request; and expanded information sharing capabilities to improve situational awareness of threats, vulnerabilities, incidents, mitigation, and recovery actions.
CISA also provides a number of partnership engagement opportunities that are free to all critical infrastructure owners and operators. For example, the Industrial Control Systems Joint Working Group (ICSJWG), which is led by CISA, supports information sharing and risk reduction to the Nation’s industrial control systems (ICS) through enhanced collaboration between the Federal Government and private owners and operators of industrial control systems across all critical infrastructure sectors. Many energy sector representatives have been longstanding members of the ICSJWG and we continue to find ways to innovate and strengthen the community.
For additional information on the various resources CISA provides to our critical infrastructure partners, including the electric sector, we encourage you to visit our website – CISA.gov.
Do you have any real-world examples of how CISA has successfully worked with a public power utility?
There has been a longstanding and strong relationship of collaboration and cooperation between CISA and the electricity sector, and our important partnership has continued to evolve over the years. For example, in 2018 we saw a multi-stage intrusion campaign led by Russian government cyber actors who targeted multiple critical infrastructure sectors, including the energy sector. Through an extensive collaboration effort across industry and government, we were able to release an alert providing critical infrastructure owners and operators information on observed tactics, techniques and procedures related to the threat. The alert also provided actionable mitigation techniques. Following the alert, CISA hosted a series of webinars for our partners, providing additional information on how to further reduce their exposure.
To give you just one more example on CISA’s collaboration with the electricity sector, on December 23, 2015, a campaign led by Russian government cyber actors caused power outages to three Ukrainian power companies, leaving nearly a quarter-million customers without power. CISA and the federal government partnered with the Electricity Information Sharing and Analysis Center (E-ISAC) and sent a team to Ukraine to help the impacted entities recover from the attack and implement mitigation techniques.
Together, we’ve also established effective partnership mechanisms, including the Tri-Sector Executive Working Group and the E-ISAC. The Tri-Sector Executive Working Group was chartered under the Critical Infrastructure Partnership Advisory Council (CIPAC) in 2018, with representatives with the financial services, electricity subsector and communication sectors. The working group is designed to facilitate and integrate a collaborative approach to risk management and address sector-specific capability gaps, cross-sector strategic challenges, and resilience during significant events affecting critical infrastructure. The long-term goal of the working group is to serve as a model for strategic coordination and establish a framework for operational collaboration that can be expanded to other critical infrastructure sectors. As I mentioned, the E-ISAC is a great example of how utility companies are working to secure their infrastructure across the sector. Two-way sharing of information on cyber threats and vulnerabilities between the private and public sector will enable us to continually take the advantage to the defender and apply costs to our adversaries.
How would you characterize the power sector’s response to the pandemic since March?
The COVID-19 pandemic has shown that when strong relationships and information-sharing capabilities are already in place by the time a crisis begins, services to the American people can continue unabated. Throughout the pandemic, utilities have shown their readiness and ability to respond to the challenge and they should be commended for their work to keep our nation’s electricity reliable during these unprecedented times.
When COVID-19 began to spread across our country, CISA quickly stepped up to help our critical infrastructure partners decrease impacts and the degrading of their services by leveraging our agency’s analytic capabilities and partnership mechanisms to develop risk management guidance for essential infrastructure workers. While earlier versions of CISA’s guidance were primarily intended to help officials and organizations identify essential work functions in order to allow them access to their workplaces during times of community restrictions, Version 4.0, which we just recently released, identifies those essential workers that require specialized risk management strategies to ensure that they can work safely. As we look ahead, and as the virus continues to take hold across the international community, it is imperative that we continue to work together across sectors to improve the security and resilience of our vital systems and functions. Through our collective defense measures, I believe that we will come out more secure and resilient than we were before the onset of this virus.
How would you characterize the current cybersecurity threat environment facing the electric utility industry? What are the key positive steps that the power sector has taken to boost cybersecurity, and are there any additional steps the industry can take?
Securing our nation’s critical infrastructure is a vast and complex endeavor. The convergence of information technology (IT) and operational technology (OT), and the expansion of internet-connected people, places and things creates an expanded attack surface. OT is an attractive target for those who wish us harm because critical infrastructure functionality, reliability, security, and safety depends so heavily on OT. Together, these factors make securing these digital networks increasingly difficult. In addition, cyber threat actors — including nation states — continue to demonstrate their willingness to conduct malicious cyber activity against critical infrastructure by exploiting internet-accessible OT assets. To combat against this threat, CISA and our partners at the National Security Agency recently issued an advisory to provide network defenders with recently observed tactics and recommendations for reducing cyber risk exposure across OT systems.
While these risks are significant, companies have risen to the occasion and have taken several positive steps to manage these risks. For example, through established information sharing mechanisms, companies are detecting compromises sooner. Companies are also adopting more rigorous cybersecurity standards for their OT and IT environments. In addition to these important steps, we’ve seen organizations place a greater emphasis on the adoption of sound software development, acquisition processes and practices.
The energy sector has also been involved in a full spectrum of cyber exercise planning workshops and seminars designed to assist organizations at all levels in the development and testing of cybersecurity prevention, protection, mitigation, and response capabilities. For example, the North American Electric Reliability Corporation (NERC) hosts a Grid Security Exercise (GridEx) every two years, and it is an outstanding example of the public-private partnership. Through our agency’s participation in GridEx we’ve witnessed utility companies demonstrate how they would respond to and recover from cyber and physical security threats and incidents, strengthen their crisis communications relationships, and provide input for lessons learned. Only by continuing to proactively test our plans and processes and following up on these lessons learned will we strengthen the country’s critical infrastructure security and resilience.
In addition to these cyber exercises, through the Energy Sector Pathfinder program, CISA, along with our interagency partners, is working collaboratively to strengthen the U.S. government’s ability to identify cyber threats to the energy sector and respond effectively. As the nation’s risk advisor, CISA will leverage the lessons learned within the program to improve public-private collaboration across all critical infrastructure sectors and functions. CISA also intends to utilize the Pathfinder program to continue to improve incident response procedures and protocols with our government and industry partners.
How will CISA’s recently released strategy to strengthen and unify industrial control systems cybersecurity affect the power sector? Will electric utilities need to take actions in response to the strategy?
CISA has collaborated extensively with our interagency and industry partners to create an ICS initiative that will unify various stovepipe efforts, move to a more proactive approach, and ultimately strengthen cybersecurity. The ICS Strategy, which was released in July, describes where we want to go in ICS security. It also stresses that we cannot get there alone.
Through the strategy, we define a path forward that will integrate previously segmented cybersecurity capabilities, move CISA and the ICS community toward a more proactive risk posture, and ultimately strengthen the nation’s cybersecurity capabilities.
Through the implementation of the strategy, CISA aims to form deeper partnerships with the energy sector and the electricity subsector. We are specifically concerned with the energy sector because the electric grid remains a critical lifeline sector and the backbone of our country’s infrastructure. With such pervasive critical infrastructure dependencies on electricity, the cascading effects of a successful cyber-attack remains of deep concern. Due to this reality, we are calling on greater contributions from the ICS community, while ensuring CISA delivers more value in return. The ICS community can radically amplify ICS risk-management capabilities and shape joint security investments that shift the cybersecurity paradigm by combining their collective security resources and expertise. Through the development of these shared capabilities, asset owners and operators can better defend themselves. CISA remains committed to continuing to provide and improve our current ICS security products and services, and we will prioritize development of ICS community-driven solutions.
To find out more information on how the strategy aims to help the ICS community achieve collective security, I encourage you to visit CISA.gov/ics
Is there anything else you would like to add?
When it comes to making an organization cyber resilient, in today’s environment the stakes are increasing, and the decisions are challenging. In addition, a cyber-attack on any organization can often result in substantial financial and reputation loss for a business. Due to this reality, CISA is calling on greater input from C-suite executives. It is imperative for CEOs and senior-level managers to be engaged in the cybersecurity decisions being made across their company. Without the support of an organization’s leadership, it is impossible for cybersecurity leaders to effectively plan for and defend against these threats. I can’t stress enough that cybersecurity is no longer just an IT issue. It’s an enterprise risk management issue. C-suite level executives must work hand in hand with technical network defenders.
TVA’s flexibility program enables local utilities to embrace distributed energy
August 19, 2020
by Peter Maloney
APPA News
August 19, 2020
In June, the Tennessee Valley Authority began allowing local power companies the flexibility to generate up to 5% of their average electric needs from distributed resources.
That equates to about 800 megawatts of new distributed generation, or 2,000 MW if all the generation is solar power, TVA said.
The program, approved by TVA’s board in February, allows any of the 141 local power companies that have entered into 20-year Long-Term Partnership Agreements with TVA to reduce the amount of energy they buy, potentially cutting their overall energy costs. TVA serves 154 local power companies.
TVA anticipates that much of the generation that will be built under the program will be solar power because the cost of the technology has fallen rapidly in recent years.
Since the June 22, 2020, launch, 47 local power companies have signed on to the program, citing a desire to provide customers with more renewable energy, a chance to lower costs for customers, and the economic development benefits of being able to offer renewable energy.
The flexible partnership agreement, which launched August 2019, committed to developing a flexibility solution by October 2021, but that schedule was moved forward by about 15 months to accommodate the immediate needs of customers of some of TVA’s local power companies.
It is “impressive to watch the diverse and creative solutions that are now beginning to sprout up all around the Tennessee Valley,” Dan Pratt, TVA’s vice president for customer delivery, said in a statement.
“We found ourselves in a non-competitive state when we were faced with some of the options being offered to us when school systems, universities, industries would come to us asking for renewable power and asked, ‘Can you do this for us?’” Jeff Dykes, president and CEO of BrightRidge, which provides electric and broadband services to Johnson City, Tenn., said during a Webex meeting to discuss the flexibility program. “It was always disheartening to tell them, ‘No. We agree that this is an option we should look at, but our current contract does not allow that.’”
So, the flexibility program is an opportunity to help meet customers’ needs in terms of solar power, as well as electric vehicle charging stations, Dykes said. “I think all 150-plus utilities in the valley will be able to use flexibility to their advantage,” as an economic development advantage, he added.
Dykes said BrightRidge already has “a lot of things in the hopper.” The goal is to get a large-scale solar plant in place in 2021 and some smaller solar projects that could be brought on at a quicker pace, Dykes said.
Greg Williams, executive vice president and general manager of Appalachian Electric Cooperative, also welcomed the flexibility program. “It will allow us to bring a solution to the table for a university customer” that otherwise the co-op could not do, he said during the meeting.
Appalachian Electric Cooperative has been exploring options for a number of months that will likely include solar power in combination with energy storage, as well as demand response options that would “help us lower our overall costs” by reducing demand charges, Williams said. The cooperative is in the process of preparing to issue a preliminary solicitation and is looking at potential providers, Williams said.
“We are certainly excited about the possibility [of the flexibility program] and what this truly means for public power,” said David Wade, president and CEO of EPB, the public power utility serving the Chattanooga, Tenn. area, during the online meeting. “It is really about ‘how do we serve our community in the best possible fashion?’”
One of the uses Wade sees for the program would be as a means of increasing reliability in outlying neighborhoods where adding generation would provide the redundancy to re-route power around damage when it occurs. Wade said the utility has $10 million in generation and storage projects in its budget this year.
“We do not have anything in the hopper right now, but we are certainly open to it,” Chris Davis, the general manager of Cumberland Electric Membership Corp. said during the meeting. “We see this as a marketing tool going forward.”
The new flexibility program could have a “huge impact” in the community and throughout the Tennessee Valley, Dykes at BrightRidge said.
The utility executives at the meeting said they are happy to have the reliability afforded them by a long-term supply agreement with TVA. “Right now, we need the baseload generation and support for increased renewables,” Wade at EPB said. “As the world changes, we’ll continue to change.”
Agreeing with Wade about the need for baseload power, Dykes added that the 5% mark is “just a start. It could become 20% at some point.”
SRP to provide expanded customer group with 100MW of solar energy
August 19, 2020
by Paul Ciampoli
APPA News Director
August 19, 2020
Salt River Project recently announced 21 commercial, municipal and school district customers have signed agreements to get a portion of their energy from solar power. A total of 100 megawatts of solar energy will soon be helping to power operations at these organizations.
This is the second phase of SRP’s Sustainable Energy Offering, which is part of the public power utility’s ongoing commitment to provide commercial customers with the option to obtain clean, emission-free energy at an affordable price.
The first phase, announced in 2018, included 12 companies and municipalities from across different industries.
With the addition of the 21 companies during this second phase, a total of 33 companies have signed up to receive approximately 300 MW of solar energy. The energy will be provided from facilities to be developed in Arizona.
The offering allows SRP to share the benefits of large-scale renewable resources with its diverse customer base. The companies range from school districts/higher education and technology to agriculture and governmental agencies and from data centers to grocery, defense contracting, telecom and hospitals.
The offering will also help customers achieve their sustainability goals, reduce carbon emissions and invest in renewable energy while sharing the economic benefits of a utility-scale, renewable energy resource.
The solar resources contribute to SRP’s 2035 Sustainability Goals to reduce carbon intensity by more than 60% in 2035 and by 90% in 2050 from 2005 levels. SRP is also on track to complete the goal of adding 1,000 MW of new utility-scale, solar energy to its system by the end of fiscal year 2025.
The solar energy for the phase two group of customers will be generated by Central Line Solar, a 100-MW, solar plant to be built in Eloy, Ariz. by sPower and scheduled to achieve commercial operation in December 2021.
Participating phase 2 customers include, among others, Apple Inc., PepsiCo, Boeing, Chandler Unified School District, Target Corporation, City of Tempe, Wells Fargo Bank and Verizon Communications.
More generation came from natural gas in first half of 2020 versus a year ago
August 18, 2020
by Peter Maloney
APPA News
August 18, 2020
Driven by low prices, the rapid growth of natural gas as a fuel for power generation continued through the first half of the year.
Natural gas-fired generation in the lower 48 states increased nearly 55,000 gigawatt hours (GWh), or 9%, in the first half of 2020 compared with the first half of 2019, the Energy Information Administration recently reported.
The gains by natural gas came even as total electricity generation declined by 5% because of reduced business activity as a result of COVID-19 mitigation efforts.
Coal-fired generation absorbed most of the decrease in electrical load in the first half of 2020, registering a 138,000 GWh (30%) decline in output. Because of historically low natural gas prices so far in 2020, coal-fired generation this year has been uneconomical in most regions compared with natural gas-fired generation, leading to price-driven coal-to-natural gas fuel switching, EIA pointed out.
In the first half of 2020, natural gas prices at the U.S. Henry Hub benchmark reached record lows. The average monthly Henry Hub spot price in the first six months of the year was $1.81 per million British thermal units (MMBtu) compared with an average of $2.74/MMBtu in the first half of 2019. And monthly prices reached a low of $1.63/MMBtu in June, the lowest monthly inflation-adjusted price since at least 1989, EIA noted.
Coal prices, on the other hand, were relatively stable in the first half of 2020. The average delivered cost of coal was $1.91/MMBtu this year through May compared with an average delivered cost of $2.07/MMBtu at the same time last year.
Low gas prices relative to coal prices often results in fuel switching in competitive wholesale power markets where cheaper fuel often determines which power plant is dispatched.
Coal-to-natural gas switching was most prominent in the PJM Interconnection and the Midcontinent Independent System Operator (MISO), which together account for about 35% of the total electric power generation in the Lower 48 states, EIA said.
At the end of June, local spot gas prices at hubs in PJM and MISO were at $1.58/MMBtu and $1.66/MMBtu, respectively, down nearly 50¢/MMBtu each from last year, EIA said.
Gas-fired generation increased by about 17,000 GWh in PJM and by 15,000 GWh in MISO in the first half of 2020, while coal-fired generation declined about 34,000 GWh in PJM and 40,000 GWh in MISO.
The Electric Reliability Council of Texas (ERCOT) region was the exception to that trend. Coal-fired generation in ERCOT declined 8,650 GWh in the first half of 2020 compared with the first half of 2019, but gas-fired generation also declined slightly. Most of the decline in coal-fired generation in ERCOT was offset by increases in wind and solar generation, which together increased about 8,400 GWh in the first half of 2020, EIA noted.
Coal-fired generation remains reasonably competitive in ERCOT, EIA said, because power plants there have access to low-cost subbituminous coal from Wyoming’s Powder River Basin and to lignite produced at mines near several plants.
Natural gas has also become the favored fuel for new power plants. About 18,000 MW of combined-cycle natural gas turbine plants have entered service since 2018, according to the EIA’s Electric Power Monthly. During the same 30-month period – January 2018 through June 2020 – about 31,000 MW of coal-fired capacity retired along with about 2,400 MW of nuclear power capacity.
Many coal-fired plants are also being repurposed to burn other types of fuels. A total of 121 coal plants were repurposed between 2011 and 2019, most of them to burn natural gas, the EIA reported earlier this month.
The EIA also noted, however, that gas-fired generation is facing increased competition from solar and wind capacity. Since 2018, about 23,200 MW of new net solar and wind capacity has been added. Renewable energy, consisting of wind, solar, and hydroelectric generation, has increased by about 5% and has been the only other fuel source other than natural gas to grow in the first half of 2020, the EIA said.
Calif. grid operator initiates rotating power outages with extreme heat, high power demand
August 17, 2020
by Paul Ciampoli
APPA News Director
August 17, 2020
Against the backdrop of scorching temperatures and a spike in demand for power, California’s grid operator on Aug. 14 and Aug. 15 initiated rotating power outages throughout the state.
The California Independent System Operator (CAISO) on Aug. 14 declared a Stage 3 electrical emergency due to high heat and increased electricity demand. The emergency initiated rotating outages throughout the state.
A Stage 3 emergency is declared when demand outpaces available supply. “Rotating power interruptions have been initiated to maintain stability of the electric grid,” CAISO said.
The Stage 3 emergency declaration was called after extreme heat drove up electricity demand across California, causing the ISO to dip into its operating reserves for supply to cover demand.
The grid operator went into Stage 3 Emergency at 6:36 p.m. PDT. By 7:51 p.m., the grid had stabilized, and utilities began restoring 1,000 megawatts of electricity that had been taken out of service.
CAISO terminated its Stage 3 Emergency declaration at 8:54 p.m. on Aug. 14.
“The power crisis was caused in part by coronavirus restrictions, which have closed movie theaters, malls and other locations where people would typically gather to beat the heat. Concerns about outbreaks have kept many inside their homes with the air conditioning on,” the Los Angeles Times reported on Aug. 15.
Investor-owned Pacific Gas & Electric (PG&E) on Aug. 16 said that the COVID-19 pandemic “has made the heat-outage forecast more uncertain due to shifts in electric loads because more people are staying home all day.”
Investor-owned utilities
PG&E on Aug. 14 reported that it was directed by CAISO to turn off power to approximately 200,000 to 250,000 customers at a time in rotating power outages. PG&E noted that rotating outages are not Public Safety Power Shutoffs, which are conducted during specific high fire threat conditions.
The utility subsequently said that Power has been restored to essentially all of the approximately 220,000 impacted customers.
Meanwhile, CAISO also directed SDG&E to initiate rotating outages throughout its service territory in San Diego and southern Orange counties.
“A total of about 58,700 customers were impacted in SDG&E’s territory by service interruptions. All impacted customers had their power restored as of 8:03 p.m. – about an hour and 20 minutes after the rotating outages began,” the Times of San Diego reported.
Approximately 132,000 of Southern California Edison’s five million customers lost power Friday night for about an hour, the Los Angeles Times reported, citing spokesman Robert Villegas. All of those customers had their power restored by 8 p.m., he told the newspaper.
LADWP
The Los Angeles Department of Water and Power (LADWP) on Aug. 13 said that in addition to asking residential customers to save energy, LADWP was also implementing a Demand Response event with its commercial customers in response to a CAISO Flex Alert. The alert asked all power customers to save energy from 3:00 p.m. to 10:00 p.m. on Friday, August 14.
LADWP’s Demand Response is an incentive-based, voluntary program designed for businesses that helps reduce their utility bills during periods of peak power demand and helps to ensure the continued reliability of power service for Los Angeles.
LADWP said in an Aug. 15 tweet that the rolling blackouts implemented by CAISO on Aug. 14 did not affect residents of Los Angeles.
The public power utility noted that it owns its plants and transmission lines and had enough supply to meet demand and required reserves.
LADWP, “which has never had to implement rolling blackouts due to excess demand, was able to sell 225 megawatts to California ISO between 5 and 9 p.m., spokesman Joe Ramallo said,” the Los Angeles Times reported.
On Aug. 16, LADWP said that while it has adequate supply to meet its customer demand and emergency reserves “at this time, we join CAISO in urging customers to conserve energy to help the state grid and reduce the strain on neighborhood distribution systems. Extreme heat conditions, including very high nighttime temps that provide little relief to strained equipment, can cause equipment to fail, leading to power outages.”
LADWP also said on Aug. 16 that its crews had been working around the clock to restore small localized power outages caused by extreme heat and electricity demand. “Crews are working as quickly and safely as possible, and will work around the clock responding to outages.” As of 5 p.m., approximately 4,800 customers out of 1.5 million total were without power.
SMUD
The Sacramento Municipal Utility District (SMUD) on Aug. 16 said it was asking customers to limit their use of electricity during this week’s high temperatures, which are expected to continue into next weekend.
“With the heavy use of air conditioners, customers are using electricity at record levels, requiring the use of all SMUD power sources. With help from customers, SMUD expects to be able to avoid any power shortfalls,” it said in a news release.
SMUD noted it is a member of the Balancing Authority of Northern California (BANC), an independent balancing authority within the western electricity power grid. As a member of BANC, SMUD is not required to participate in rotating outages ordered by the California Independent System Operator (CAISO).
SMUD said it continues to support the statewide electricity grid in the event of a true electrical emergency.
During the heatwave, SMUD is all hands on deck with extra personnel available to restore power outages as safely and quickly as possible, it said.
CAISO requested power outages on evening of Aug. 15
CAISO declared a Stage 3 Electrical Emergency at 6:28 p.m. on Saturday, Aug. 15, due to increased electricity demand, the unexpected loss of a 470-MW power plant the and loss of nearly 1,000 MW of wind power.
IOUs in the state were directed to initiate rotating outages.
The load was ordered back online 20 minutes later at 6:48 p.m., as wind resources increased.
CAISO issues flex alert
On Sunday, Aug. 16, CAISO issued a statewide flex alert, a call for voluntary electricity conservation, through Wednesday, Aug. 19. The Flex Alerts are in effect from 3 p.m. to 10 p.m. each day.
“A persistent, record-breaking heat wave in California and the western states is causing a strain on supplies, and consumers should be prepared for likely rolling outages during the late afternoons and early evenings through Wednesday. There is not a sufficient amount of energy to meet the high amounts of demand during the heatwave,” the grid operator said.
“However, consumers can actively help by shifting energy use to morning and nighttime hours and conserving as much energy as possible during the late afternoon and evening hours,” CAISO said. “Consumer conservation can help lower demand and avoid further actions including outages, and lessen the duration of an outage.”
Consumers were urged to lower energy use during the most critical time of the day, 3 p.m. to 10 p.m., when temperatures remain high and solar production is falling due to the sun setting.
Extended periods of heat also can cause generator equipment failures that can lead to more serious unplanned losses of power, the grid operator noted.
Lightning strike to Alameda Municipal Power substation knocks out power to customers
Meanwhile, Alameda Municipal Power reported on Aug. 16 that lightning struck one of its substations causing a power outage to 10,000 customers.
Alameda Municipal Power subsequently reported that it had restored power to all but 50 customers on Aug. 16.
CAISO president and CEO offers thoughts on grid reliability, extension of day-ahead market
August 13, 2020
by Paul Ciampoli
APPA News Director
August 13, 2020
Steve Berberich, who will soon retire as president and CEO of the California Independent System Operator, recently offered his thoughts on what he sees as the greatest challenges to grid reliability in the next ten years, CAISO’s stakeholder and governance process and the extension of the day-ahead market into CAISO’s Western Energy Imbalance Market (EIM).
Berberich, who made his remarks in a July 29 interview with the American Public Power Association’s Public Power Daily newsletter, has served 14 years with the CAISO, the last nine as CEO.
On Aug. 6, CAISO announced the appointment of Elliot Mainzer as its new president and CEO. Mainzer, who has served as administrator and CEO of the Bonneville Power Administration for the past seven years, will succeed the retiring Berberich on September 30.
Challenges to grid reliability
In the interview, Berberich was asked to detail what he sees as the greatest challenges to grid reliability in the next 10 years and what steps CAISO should take to address those challenges.
“I think by far the biggest challenge is moving from a thermal-based fleet to a renewable-based fleet,” he said. “I think that’ll be the biggest challenge — to make sure that you can get essential grid resources or services if you will from the renewable fleet, which we’ve shown that you can.”
But this means marrying up “the regulatory, contractual, dispatchability all across because mostly the renewable contracts” reward the producer “on how much they can pump out, not whether they can hold back and provide voltage support or reactive power or ancillary services of all kinds, things like that. But it is technically possible to do that.” Energy storage is “going to play a critically important role,” he added.
“But I think we just have to do that very thoughtfully to make sure we maintain reliability. If you have any reliability issues, that’s going to be a major issue with this transition.”
As for CAISO’s role, “we have to be very clear about what the grid needs to respond to the load profiles and things like that.” But CAISO’s markets “have to adapt to compensate more for services and less from an energy perspective. I think energy’s going to continue to play a big role in the markets, but I do think critical services are going to become a more predominant part of the market mix.”
CAISO’s stakeholder and governance process
Meanhwhile, Berberich was asked to detail how well he thinks the stakeholder and governance process in CAISO is working and whether he sees any benefits to this process as compared to other RTOs.
“We have a unique governance model and it’s become more unique with the energy imbalance market. No other ISO has an appointed board and I’m obviously on record as saying I think a regional grid is really, really important for integrating high levels of renewables. I think you necessarily have to have a regional board of some type.”
He said that “I’m just a big advocate of a regional grid, so you’ve got to have a regional, representative board.”
Nonetheless, with the delegation of responsibilities to the energy imbalance market governing body, and with potential expanded delegation for a day-ahead market, “I think that you can achieve what you need to achieve and I’m confident that we can find a way to balance representation on the governing body board with what the region requires to have a fully functioning real-time and day-ahead market.”
With respect to the stakeholder process, “I have some major philosophical thoughts on this in as much as I think that there is a major evolution of stakeholders over time and I think that has accelerated and when you set up a standing stakeholder committee I think you necessarily create stakeholders that are sort of more important than others and I think we have to be very cautious of that,” he said.
With respect to public power, “it’s easy for the IOUs to overpower the munis because of the resources that they bring to bear and I think it’s a good example of you’ve got to make sure you protect and allow participation of all the stakeholders.”
Some of the ISOs “have standing stakeholder committees and they basically decide on something before it ever comes to the board. I’m not in favor of that because I think it segregates stakeholders and I think that’s unfair to certain stakeholders,” Berberich said.
“The other thing I think about and the analogy I use is the United Nations Security Council. You have the five permanent members on there and it’s really, really hard to get another one on there” and you have that same problem with a stakeholder committee once it’s established.
“Who would have thought the wind association would want to be part of the stakeholder community ten years ago or storage five years ago, or microgrids for that matter? And I think that’s all evolving and changing and I wouldn’t want to be in a place where they were on the outside looking in,” Berberich said.
“I think we have an open, participatory stakeholder process, so my perspective is I wouldn’t change what we’re doing in favor of what some of the eastern ISOs are doing.”
Western EIM and extension of the day-ahead ahead market into the EIM
CAISO in late July reported that the Western EIM surpassed $1 billion in economic benefits.
The Western EIM allows participants to buy and sell power close to the time electricity is consumed and gives system operators real-time visibility across neighboring grids.
Berberich was asked whether he sees any challenges for the future of the Western EIM and if he views the extension of the day-ahead market into the EIM as necessary for its continued success.
“The day-ahead market has vastly more energy traded in it than the real time market so it should have comparably higher value and billions of dollars — and potentially a billion every year — that you could unlock and I think we owe that to the energy customers across the west.”
He also thinks it will help integrate renewables and trade energy.
“We have about 50 percent more curtailment this year than we had last year and you would think that you could just export that negatively priced or very low-priced energy. You have people that…do the resource commitment day ahead and unless you have a coordinated day-ahead market, people can’t take it because they’ve already committed resources. So I think that will be really important from a benefit perspective but also from a renewable integration perspective.”
He added, “there’s a lot of people in the west that seem to like this model better than a full RTO where they turn over transmission control and things like that, so I’m comfortable with the direction we’re headed.”
What are the obstacles? There are “some critical market design things that need to be taken care of. As an example, you’ll have to do some sort of transmission compensation. You’ve got to do some sort of resource adequacy methodology and things like that. Those are going to be hard to do, but I don’t think they’re insurmountable and they’re already handled as part of our bucket one, if you will, of design features for the day-ahead market.”
He is “confident that we can solve the governance issues, which is going to mean some expanded responsibility for the governing body, but also the market design things and once you’ve done that you’ve added a whole lot of value.”
Berberich added, “I also know that, to the extent we can leverage our platform, it’s a hell of a lot cheaper than standing up a new RTO.”
Transmission
Turning to the topic of transmission, Berberich was asked whether he sees a need for new transmission in the state and, if so, what the greatest driver of that need is.
There is a lot of transfer capability that already exists, he said. Moreover, there will be transfer capability that will be freed up “as you retire coal plants and other thermal facilities and I think it’s critically important that we locate new resources,” such as renewables and battery storage – “using those same transmission corridors and in that way I think we can limit the build that we may have to do,” Berberich said.
“I think we’ll have to do some build, particularly to bring renewables to market and to share them, but I think you can limit it if the policymakers are thoughtful about where they put renewables and where they’re procured,” Berberich said in the interview.
“You can do it really, really badly and build a whole lot of transmission or I think you can do it really smart and limit the transmission that has to be built,” he went on to say.
“A lot of people kind of get to the, well, if you move to microgrids and other things will you need new transmission? I don’t know that we’ll need new [transmission] for that, but I do think we’ll have to continue to use the existing transmission system even as you move to a more distributed system.”
He also addressed the question of what steps the grid operator has taken to mitigate rising transmission costs while ensuring that needed infrastructure investments are taking place.
“We have been very, very loud about talking to the public utility commission and other policymakers – not just here in California but throughout the region – that it’s critical that you re-use what you have so you don’t have to force a bunch of new build and I think that’s the best thing we can do,” Berberich said.
“We need to do what we can to re-use what we have” when it comes to transmission “because there’s going to be more pressure” to do things like undergrounding power lines, “which is going to be just hugely expensive.”
Berberich to remain with CAISO into October
Berberich will remain with CAISO into October to ensure a smooth leadership transition to Mainzer.
Mainzer has “demonstrated success leading a large, complex power and transmission organization will serve CAISO, our customers and stakeholders well,” the CAISO Board of Governors said in a statement. “We are happy to have a leader so knowledgeable about integrating renewables and passionate about building on CAISO’s organizational strengths and momentum toward low-carbon electricity.”
In his current position, Mainzer is responsible for managing the non-profit federal agency that markets 23,000 megawatts of carbon-free power and operates much of the high-voltage power grid across the Pacific Northwest, including major interconnections with California.
“I am grateful to have the opportunity to lead the creative and innovative team at CAISO and to enable California to reliably and safely achieve its ambitious clean energy and climate goals,” said Mainzer. “I also look forward to working closely with our colleagues across the West to build on the success of the Western Energy Imbalance Market and further strengthen regional coordination and technology innovation.”
Mainzer brings “exceptional leadership experience, wide-ranging contacts and inclusive strategic thinking to the CEO position,” the Western EIM Governing Body said in a statement. “We look forward to working with Elliot as we continue to enhance and expand the financial, environmental and reliability benefits of the WEIM.”
NWPP taps Southwest Power Pool to design its resource adequacy program
August 11, 2020
by Peter Maloney
APPA News
August 12, 2020
Northwest Power Pool (NWPP) has hired Southwest Power Pool (SPP) to develop a resource adequacy program for a set of 18 member utilities.
Public power participants in the RA program are the Bonneville Power Administration, the Balancing Area of Northern California (with its member, the Sacramento Municipal Utility District),
Chelan Public Utility District (PUD), Douglas PUD, Eugene Water and Electric Board, Grant PUD, Seattle City Light, Snohomish PUD, Tacoma Power and Turlock Irrigation District.
“Over the last few years, there have been several forecasts indicating shortfalls in resources relative to peak load in the 2020-2025 timeframe,” Frank Afranji, NWPP president, said via email. “These forecasts have created a strong incentive for utilities to work together to identify the regional resource adequacy needs.”
Over 5,000 megawatts of gas-fired generation were built in the Northwest between 2001 and 2010, but that pace has slowed recently. Only four gas plants, totaling 1,100 MW, have come online since 2011, according to an October 2019 NWPP report.
In recent years, many utilities in the region switched from building new generating resources to purchasing power through the wholesale market, and renewable development has been increasing. As of 2019, the Northwest had 450 MW of grid-scale solar power resources and 9,400 MW of wind power. Meanwhile, nearly 2,000 MW of coal-fired generating capacity in the Northwest is expected to retire by 2023 with another 1,500 MW expected to retire by 2029, according to the report.
Coal retirements combined with load growth could lead to capacity shortages as soon as this year and, by the mid-2020s, the region could face a capacity deficit of thousands of megawatts, leading to the risk of “extraordinary price volatility” and “unacceptable loss-of-load,” the report says.
The scope of SPP’s work for NWPP is expected to last through 2020 and will span the design phase of resource adequacy program development.
SPP will work with the NWPP and its participating member utilities to expand and refine the preliminary program design into a comprehensive resource adequacy program.
When the resource adequacy program is fully designed, NWPP members plan to conduct a competitive solicitation for a program administrator to implement and run the resource adequacy program.
“Southwest Power Pool has direct experience developing and running a resource adequacy program across multiple states and the skill set to help us determine key program design features to achieve the reliability objectives of the RA program,” Afranji said in a statement. “The program we are developing will be available to participants with different needs and interests across a wide swath of the West and we believe SPP’s multi-state RA program experience will help us develop a program that provides benefits for all participants as well as the region.”
The resource adequacy program would be voluntary to join, but once an entity has joined, they are obligated to fulfill the commitments under the program, Afranji said.
“Enforcement under the program is a design element that has not yet been defined,” he added.
Ditto emphasizes important of managing customer expectations during pandemic
August 11, 2020
by Paul Ciampoli
APPA News Director
August 12, 2020
In recent remarks at a Florida Municipal Electric Association (FMEA) virtual conference, Joy Ditto, President and CEO of the American Public Power Association, underscored the importance of managing customer expectations to ensure that public power utilities can continue to operate safely during the COVID-19 pandemic.
It is vital that customers “understand that what we’re doing is for them. That we’re essential workers, but we have protocols in place to maintain our safety” and that public power has a culture of safety, Ditto said on Aug. 3 in comments during FMEA’s “Powering On” virtual conference.
At the same time, there needs to be a recognition that “we do still need to operate our systems and that comes with a cost. We want to maintain affordable electricity, but we also still need to operate our systems.”
That ongoing communication with customers is key and while it is challenging in a virtual environment, there are ways it can be accomplished through social media and other channels, Ditto said.
Amy Zubaly, Executive Director of FMEA, moderated the session, “The Future of Public Power: How Lessons Learned From COVID-19 Can Help Us Better Serve Our Customers.”
Financial impact of pandemic
As for the financial impact of the pandemic on the power sector, Ditto pointed out that rating agencies continue to maintain stable outlooks on public power utilities.
However, depending on the severity of the economic downturn, there could be an impact on the ability of public power utilities to continue to maintain their systems optimally or access capital, she said.
At the same time, public power’s ability to show that it can make decisions locally “and that we are committed to high levels of reliability, but also affordability, is going to situate us well.”
But some public power communities are being hit harder than others in terms of the economic downturn “and that’s the other piece. That uneven impact is really something that’s going to be challenging, particularly for associations like mine, like FMEA, for joint action agencies to try to help bridge some of that downturn that is more specific to individual communities.”
APPA recently urged its members to reach out to their senators and members of Congress to express support for the inclusion of language in a COVID package that was being negotiated by the White House and House and Senate leadership last week.
Senate Energy and Natural Resources Committee staff for Chairman Lisa Murkowski, R-Alaska, and Ranking Member Joe Manchin, D-W.Va., developed language with APPA and the National Rural Electric Cooperative Association to create a forgivable loan program for public power and rural electric cooperatives impacted by customer non-payments due to the COVID-19 pandemic.
Mutual aid
With respect to mutual aid, Zubaly “does an incredible job” when it comes to managing mutual aid and works in “strong coordination” with APPA’s mutual aid team, Ditto said.
In a Q&A with APPA earlier this year, Zubaly detailed how FMEA was taking a number of steps to ensure that planning for this year’s hurricane season was not disrupted by the COVID-19 pandemic.
Ditto also highlighted the fact that public power utilities have maintained high levels of performance this year during mutual aid events while also making sure that their frontline workers have effective protections against COVID during power restoration activities.
In April, Tennessee public power utility EPB noted that several steps had been taken to minimize the threat of COVID-19 exposure during power restoration work including providing mutual aid crews with gloves and masks.
And public power utility Jonesboro City Water and Light (CWL) took a number of steps to minimize the threat of exposure to COVID-19 for utility crews during a mutual aid effort to restore power to customers in the wake of a tornado that hit Jonesboro, Arkansas, in March.
CWL took several steps to minimize the potential exposure to COVID-19 for workers helping with restoration efforts, which were detailed in a “lessons learned” document that it prepared.
That focus on safety has continued in more recent mutual aid events.
Florida public power utility JEA this month sent crews to New York to help investor-owned utility Con Edison with power restoration efforts in the wake of Tropical Storm Isaias.
Ricky Erixton, JEA interim general manager for electric systems, noted that this was the first time JEA has participated in mutual aid during a pandemic. “We’re sending our guys with sanitizer, masks, all these types of things that help prevent the spread of COVID,” he said in a video posted on JEA’s Twitter feed.
Pandemic may lead to influx of workers
Among the longer-term effects that the COVID-19 pandemic may have on public power is that residents of large cities could decide that smaller towns and communities are more appealing, which in turn could lead to a more highly qualified and diverse workforce, Ditto said.
“This is total speculation on my part and it may not come to fruition, but I just think about how larger cities have been hit” hard by COVID-19 and whether that means city dwellers may find it more attractive to move to smaller towns and communities.
If one of the lasting results of the pandemic is for residents of larger cities to move to smaller towns and communities that could be a benefit to public power in terms of attracting a highly qualified workforce, “which has been a challenge for us sometimes, especially in our smaller communities,” Ditto said.
Also, in the context of public power’s enhanced focus on diversity and inclusion, such a shift could lead to greater diversity in smaller communities, she said.
In June, Ditto issued a statement on justice and equal opportunity in which she said that the electric utility industry must redouble its commitment to diversity at every level. “We’ve seen time and time again that this diversity and inclusion pays dividends, yielding teams that are rich with different backgrounds and ideas,” she said in the statement.
Kansas Municipal Energy Agency buys engineering firm to offer more services
August 11, 2020
by Peter Maloney
APPA News
August 11, 2020
The Kansas Municipal Energy Agency (KMEA) has acquired Mid-States Energy Works, a small engineering company based in Salina, Kansas.
Mid-States provides engineering, testing, troubleshooting, fabrication and installation of electrical equipment and controls.
KMEA, a joint action agency serving public power utilities in Kansas, has 81 members. Mid-States currently works for about half of those members, as well as other public power utilities in Kansas.
“Members had been asking us to get into the service arena,” Paul Mahlberg, KMEA’s general manager, said. The Mid-States acquisition allows for us to provides these types of services now rather than trying to build them up from scratch.”
“The fact that we both have the same vision of helping out the Kansas municipal utilities to be the best they can be… it became a win/win/win situation for Mid-States, KMEA and most importantly for the cities,” Mike Schmaderer, president of Mid-States, said in a statement.
The acquisition grew out of requests that KMEA’s members had been making for years. A couple years ago, KMEA did a strategic plan. As part of that plan, KMEA surveyed its members in 2019. The top response, according to Mahlberg, was for KMEA to expand the services it offers members. At the top of that list was line maintenance, followed by engineering, project management, substation maintenance and construction and power plant troubleshooting.
Around the same time, KMEA had embarked on a separate venture with one of its members, the City of Dighton. For 20 years, the city had contracted for line maintenance with the local rural electric cooperative, but it was now ready for a change.
KMEA hired a couple of linemen and signed a two-year agreement with the city to provide the labor for the operation and maintenance of the city’s distribution system, including preventative maintenance, repair, equipment testing and repair, connection and disconnection services, tree trimming, and streetlight maintenance. The “partnership with KMEA will provide us more control and involvement in maintenance and health of our electric system,” Dighton Mayor Doyle Capra said in a statement.
The Dighton partnership turned out to be a “parallel path” for KMEA, a path that “blended together” with the Mid-States acquisition, Mahlberg said. Dighton was its first member to receive KMEA’s new services, and now with a journeyman lineman and apprentice on board, the crew, along with the Mid-States staff, will be available to assist other KMEA members, Mahlberg said.
The relatively small size of many of KMEA’s members – the agency’s average member has 1,500 meters and some have as few as 100 – means that it is difficult for many of those utilities to be able to afford a full-time electrical maintenance staff.
In addition to having a dedicated maintenance staff it can share with its members, Mahlberg says KMEA will be able to offer services to its members at close to cost. In the near term, KMEA plans to amortize the purchase price into its rates, but over the longer term the agency plans to lower its fees and expand its services, Mahlberg said.
“We are doing more strategic thinking about how to grow the business.”
Among the services KMEA is looking at are preventive plans for substation maintenance, and it is also starting to look at a mobile substation that could be used anywhere throughout the state, Mahlberg said.