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APPA, other groups urge House leaders to include energy innovation legislation in agenda

August 25, 2020

by Paul Ciampoli
APPA News Director
August 25, 2020

The American Public Power Association recently joined a coalition of 38 organizations, led by the U.S. Chamber of Commerce, in a letter to House Speaker Nancy Pelosi, D-Calif., and Minority Leader Kevin McCarthy, R-Calif., in support of including energy innovation legislation in the House’s fall legislative agenda.

“Our diverse organizations recognize and agree that climate change is an important national priority that demands Congressional attention,” APPA and the other organizations said in their Aug. 17 letter to Pelosi and McCarthy.

“While we may not agree on everything, we believe there is much common ground upon which all sides of the debate can come together to begin to address climate change, promote American technological leadership, and foster continued economic growth,” the groups said.

“There is a growing consensus that the development and commercialization of new technologies are an important factor that will determine how quickly and at what cost greenhouse gas emissions can be reduced,” the letter said.

The groups noted several bills that could be brought to the House floor this fall to address energy and climate technology and innovation, including:

APPA and the other organizations also highlighted H.R. 5428, the Grid Modernization Research and Development Act.

This bill would authorize several DOE research and development efforts, including a smart grid regional demonstration initiative, a program related to grid modeling, sensing, and advanced operation and controls, and a program on integrating electric vehicles onto the grid.

The bill also would create a grant and technical assistance program for which electric utilities, as well as state, local, and tribal governments, are eligible, to improve grid resiliency.

The groups note that the list of bills included in the letter is not comprehensive, but represents bipartisan efforts, that if signed into law, could accelerate technological breakthroughs and adoption of cleaner or more efficient energy technologies.

The letter is available here.

Impressive reliability track record for Clark Public Utilities reflects utility-wide focus

August 24, 2020

by Paul Ciampoli
APPA News Director
August 24, 2020

Washington state public power utility Clark Public Utilities has developed an impressive track record when it comes to reliability and keeping power outages to a minimum.

“I think there’s really a commitment from the top down within the whole utility to keep service interruptions at a minimum and, when they do happen, to get them fixed as quickly as possible,” said Ryan Kerr,  Manager of Systems Engineering and Planning at Clark Public Utilities, in an Aug. 14 interview with the American Public Power Association.

More specifically, Kerr noted that there is a “big commitment” from Clark Public Utilities when it comes to proactive vegetation management, which is done on a three-year cycle. In addition, the utility also utilizes tree wire in spots where tree trimming is difficult.

Kerr also highlighted the utility’s infrastructure monitoring and service crew protocols as substantial drivers behind the short response times. “I think the fact that we have a 24-hour dispatch center, and servicemen out there on patrol all the time who are ready at a moment’s notice when the dispatchers report an incident,” helps with power restoration efforts.

Dameon Pesanti, Media Specialist at Clark Public Utilities, emphasized the point that the utility has “built a culture of the customer’s interest above all else. We’re owned by them so we want to provide them the best service.”

Starting with the CEO of Clark Public Utilities, “down to our part-time employees,” the focus on reliability is front and center across the utility, Pesanti said. When power outages occur, “everybody jumps on it to get the lights back on and keep customers informed.”

Clark Public Utilities recognized by APPA

Earlier this year, Clark Public Utilities received a “Diamond” level designation from APPA under APPA’s Reliable Public Power Provider (RP3) program.  The Diamond level is the highest level of RP3 recognition.

The program recognizes utilities that demonstrate high proficiency in reliability, safety, workforce development, and system improvement. Utilities keep the RP3 designation for three years.

“Reliability and safety are the priority in all areas of operation in this utility,” Lena Wittler, CEO/General Manager of Clark Public Utilities, said in April. “The RP3 review thoroughly examines the practices and measures implemented across the organization to support those priorities. The fact that we’ve earned the highest level of recognition, with a rarely achieved perfect score, is a reflection of our ongoing commitment to delivering outstanding service, consistently and professionally.”

“I’m always excited to see exceptional reliability at public power utilities,” said Alex Hofmann, Vice President, Engineering Services, at APPA. “Keeping the lights on represents a huge value to the commercial, industrial, and residential customers serviced by Clark PUD.”

A recent article in the Battle Ground, Washington-based newspaper The Reflector notes that the average number of power outages a customer experienced in 2018 was 1.65. For Clark Public Utilities customers the average was 0.43, the newspaper reported.

In his interview with APPA, Kerr said that in 2016, the public power utility started to focus on Institute of Electrical and Electronics Engineers (IEEE) indices “and bringing those to the table.”

Clark Public Utilities for a long time has had an internal goal program with set metrics for reliability, cost-control and customer satisfaction. The reliability goal uses measures similar to the System Average Interruption Duration Index (SAIDI) with average time a utility customer is out of power during a specified timeframe, and employees watch the progress against the goal as a measure of success.

Kerr noted that one of the tools that Clark Public Utilities utilizes to minimize outages is remote device control. This helps in situations such that when there is an outage, “dispatch can participate in the switching order along with the servicemen out in the field, so it helps our restoration time and adds to the number of eyes on the system.”

Substations

Washington has the second-highest risk in the U.S. of large and damaging earthquakes because of its geologic setting, according to the Washington Geological Survey. Kerr noted that when it comes to substations, Clark Public Utilities takes a long-term approach in terms of things like seismic upgrades and “installing a lot of flexible connections between devices.” Clark Public Utilities has also taken steps to tie down its power transformers.

 “We think we’ll be able to get through our system in the next five years or so. We’re not trying to get so it’s going to be a hundred percent ride through, but anything we can do ahead of time to provide for a better restoration time following a seismic event is what the utility is aiming for,” Kerr said.

With respect to specific projects, he noted that Clark Public Utilities is working to replace its oldest substation near Washington’s border with Oregon along the Columbia River.

Along with the substation’s age (constructed in 1964), Kerr noted that another factor driving this project is a new $1.5 billion waterfront development project, so “we need a little extra capacity out of there.” The project is in downtown Vancouver, Washington.

The substation project, which is tied into two transmission lines, will help boost reliability by compensating for times when one of the lines experiences an outage. “In the past, it wasn’t really set up that way. We’ll have some duel redundancy” into the future for a large chunk of customers in the downtown Vancouver area, he said.

How PREPA brought earthquake-damaged plant online ahead of Isaias

August 24, 2020

by Peter Maloney
APPA News
August 24, 2020

In January, it looked like one of Puerto Rico’s biggest power plants would be out of commission for a year. Instead, one unit of the damaged plant was able to start generating power just days before Tropical Storm Isaias hit the island.

The speedy restoration of the Costa Sur plant is “by far the biggest success PREPA (Puerto Rico Electricity Power Authority) has ever had,” Todd Filsinger, senior managing director at Filsinger Energy and chief financial advisor to PREPA, said.

The two-unit, 820-megawatt (MW) Costa Sur plant, PREPA’s largest, was knocked out of service on Jan. 7 by a 6.4 magnitude earthquake that cracked foundations, ruptured pipes, split water tanks, and damaged a turbine and the plant’s control room.

Costa Sur provides about one quarter of PREPA electrical supplies and is one of the public power utility’s most efficient plants. Without it, PREPA was forced to use its more expensive diesel peaking plants and to rely more heavily on purchased power from third party generators such as EcoElectrica and a coal-fired plant owned by AES Corp.

Before actual repair work on Costa Sur could begin, however, a lot of negotiations and financial arrangements had to be made, all of which were complicated by Puerto Rico’s financial troubles – the island, and then PREPA, entered into a bankruptcy like process in 2017 – and in that same year was devastated by two hurricanes, Irma and Maria.

Soon after the earthquake in January, there were discussions with the Federal Emergency Management Agency (FEMA) for temporary generators, but that solution was thwarted by technicalities.

Meanwhile, plans to repair Costa Sur had to be approved by regulators, including the Puerto Rico Energy Bureau and the Financial Oversight and Management Board.

As part of the bankruptcy process, PREPA created a project management office (PMO) that reports directly to the head of the utility. The discipline, experience and focus of the PMO were key to the rapid restoration of Costa Sur, Filsinger said.

As the groundwork for the restoration efforts for Costa Sur began, it became apparent there were opportunities to negotiate a better deal in the form of lower prices and tighter schedules, Fernando Padilla, director of PREPA’s project management office, said.

When negotiations were completed and financing was in place – over 80% of the $40.2 million total cost is being covered by PREPA’s insurance – the actual physical work of restoration began in May.

The work was undertaken by a team of about 360 contractors and PREPA employees, many of them union workers, who worked in 24-hour shifts. PREPA was able to begin ramping up the 410-MW Unit #5 at Costa Sur within 24 hours of Isaias hitting Puerto Rico. Unit #5 is now fully operational, and Unit #6 is expected to be online by late October.

Among the key lessons learned from the restoration efforts, Padilla says, is to stay in close contact with the workers. He walked the power plant’s floor four times a day. “If you are not close to the people,” it is difficult for them to understand the scope and progress of their efforts. “It is hard to translate that from a piece of paper.”

“It is about having first eyes and hands on the problems to seek immediate solutions,” Padilla said. “Being there allows you to understand problems, employee needs, project risks, and to address contractors’ and employees’ problems and even creates opportunities to make work more efficient and quicker,” Padilla said. A daily management presence “also provides employees with the comfort that our executive team is fully committed” to bringing the plant back online quickly and motivates employees and signals urgency to contractors, he added.

The other lesson is the benefit of using a mix of contractors and public power union employees. “PREPA’s union expertise was indispensable due to their knowledge of the asset and its operation,” and union labor was lower cost compared with contractors of the same level of expertise, said Padilla.

Looking to the future, Padilla and his PMO team are working on other projects that will enable PREPA to be prepared for other disasters that befall Puerto Rico. Among them, vegetation management projects on 600 miles of the island’s electrical wires and a future that includes more decentralized power resources.

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?

Headshot of Brian Harrell

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?

CISA assistant director Brian Harrell meets with APPA staff
Brian Harrell (right), with Giacomo Wray (left) and Nathan Mitchell (center) from the American Public Power Association at a meeting in January 2019.

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.”