Over their 140-year history, electric utilities have figured out how to deal with all sorts of calamities: floods, hurricanes, monsoons, earthquakes, ice storms, wildfires, even active shooters. But the last time they experienced something comparable to the COVID-19 pandemic, it was 1918, and only a third of U.S. homes had electricity.
In the COVID-19 crisis, most of the utilities’ existing disaster responses were of little use. The pandemic was both geographically boundless and also long-lasting, and yet it didn’t pose any immediate threat of physical damage. Rather, the risk was something new: Grid operators worried that if huge numbers of essential workers fell ill, key pieces of infrastructure—generating plants, substations, transmission and distribution lines—could become damaged or inoperable. This was at a time when the importance of uninterrupted electrical service was paramount, because hospitals’ response to COVID-19 depended strongly on suites of medical tools. Those included ultrasound and computed tomography for diagnosis and, in the most serious cases, ventilators for treatment.
Now, as utilities that endured the first wave of outbreaks begin returning to normal operations, they are taking stock of their responses to the pandemic. Meanwhile, as new hot spots emerge, utilities that escaped the first wave are bracing for their own first encounters.
The New York Power Authority (NYPA), the state’s public utility, was one of the organizations buffeted by the first wave in the United States. In mid-March, with COVID-19 cases beginning to soar in parts of the state, NYPA found itself grappling with how to deal with the anticipated onslaught. “We were trying to find strategic ways to make sure we could isolate key staff,” recalls Joseph Keesler, chief operating officer. “One of the things that we considered was our capacity. Should the virus go into our key staff, do we have enough backups?”
Projections suggested that NYPA did, but it hoped to avoid having to find out for sure. Office workers, such as those in management, payroll, and billing, were asked to work from home. But the specialists who run NYPA’s 16 electrical generation facilities and troubleshoot the equipment could not work remotely.
So the utility began bringing beds into their plants, and even towed some dormitory-type trailers to work sites, so key workers could comfortably remain on-site around the clock. After several weeks, NYPA rotated them out and replaced them with a second shift. “Sequestering is one method of social distancing that was helpful for us in terms of making sure our essential personnel were safe,” Keesler says. He himself directed operations from a makeshift office in his home.
The measures managed to keep critical personnel free of infection. As of the end of May, the utility was winding down the sequestration plan, but it remains vigilant and ready to return to that plan, or take new steps should cases of the virus begin to spike again.
In devising their responses to the pandemic, NYPA and other U.S. utilities called upon their experiences during two previous outbreaks, the bird flu of 2005 and the swine flu of 2009, according to Keesler. But COVID-19 spread further and faster than either of those, and it had unique attributes, such as a much higher degree of spread by infected but asymptomatic people. That meant the electricity sector had to adapt existing guidelines to account for the realities of the specific disease, not just for its own sake but for the sake of the countless medical workers and patients depending on a fully functional electricity grid. “Frontline hospital workers and ventilators and first responders don’t work without electricity,” notes Scott Aaronson, vice president for security and preparedness at the Edison Electric Institute, the association representing U.S. investor-owned utility companies.
The industry is now compiling its experiences on how to deal with COVID-19, Aaronson adds. “We are literally writing a book,” he says. “We have crowdsourced from hundreds of experts all across the sector.” He’s referring to a resource guide for dealing with COVID-19 from the Electricity Subsector Coordinating Council, a group made up of utility executives. “It started as a 6-page document, sort of a pamphlet,” Aaronson adds. “It’s 112 pages today.”
The guide contains recommendations for pandemic-related issues faced by utilities, such as how to identify which personnel are critical, how to practice social distancing in the tight confines of a control facility, how to clean and disinfect control rooms, and how to prepare for difficulties in getting critical equipment.
Another concern is how to handle situations that require mutual aid. Utilities often help each other out during emergencies—for instance, sending repair crews to help with downed power lines after a storm. But that presents challenges when people from different regions are not supposed to be mingling. So the industry developed COVID-19 protocols for mutual aid, which include limiting the times when two people are in a bucket at the top of a pole and restricting personnel to one person per vehicle or per hotel room. Utilities put those protocols into practice in early April, when tornadoes from eastern Texas to the mid-Atlantic region left 1.5 million people without power, and they worked well, Aaronson says. “Some of these protocols are going to be used even after the pandemic,” he says.
Keesler says utilities have also agreed to expand the concept of mutual aid to include the sharing of control-room personnel, if the virus renders key members of one company’s workforce unable to work.
NYPA has also been benefiting from efforts, dating back to 2013, to digitize more of its operations. Under the initiative, the utility built up its information-technology infrastructure, installed remote sensors throughout its generating plants, and provided more handheld instruments to employees. The organization also benefited from prior experimentation with a couple of other technologies. “Drone operation for routine inspections or 3D modeling and 3D printing are things that were novelties but became essentials during this crisis,” Keesler says. He explains that NYPA used 3D modeling to examine its infrastructure and 3D printing to test potential replacement parts, which the utility would then machine with more standard tools.
In the future, NYPA may manufacture those parts with 3D printers, Keesler says. During the pandemic, it even used 3D printing to create plastic face shields for its workers and others. “I think going forward, we’re actually going to double down on all of our digital strategy to make sure that we can respond to the next crisis,” he adds.
Power companies were also forced to confront supply-chain problems during the pandemic. Utilities generally carry what is known as “storm stock”—extra poles, conductors, transformers, and other equipment that might need to be rapidly available. But the surplus stock tends to be somewhat meager, Aaronson says. The industry already has equipment-sharing programs in case one area runs short, and it’s pushing suppliers to ramp up production where possible, although many of those suppliers are also struggling to cope with the pandemic.
Some equipment, such as transformers, turbine wheels, and circuit breakers, is manufactured overseas, and utilities began experiencing disruptions back in January, when factories in China’s Hubei province, where the novel coronavirus is believed to have originated, shut down. On 1 May, U.S. president Donald Trump issued an executive order banning the purchase of electrical-grid equipment that comes from a country designated as a foreign adversary or that might pose a risk of sabotage. The threat identified in the executive order “is nothing new, but it’s shining a flashlight on an issue that has existed over time,” says Massoud Amin, a professor of electrical and computer engineering at the University of Minnesota and a leader in the field of electric-utility security.
Aaronson plays down that threat, however, noting that while potential attackers might see a spiraling crisis as an opportunity to wreak mayhem, the same emergency puts utilities on heightened alert. “During things like a pandemic, our workforce, in particular our cybersecurity workforce, is hypervigilant,” he says.
Even as states continue to grapple with new coronavirus cases and try to figure how to safely resume activity, epidemiologists are warning about a second wave later this year, which could coincide with a new flu season and also with peak hurricane season in North America. Even as they brace for what’s to come, utilities are looking further ahead. Once the pandemic has passed, experts say, the lessons learned may help the industry not only prepare better for the next emergency but also improve its operations in good times. Some of the changes made to cope with the crisis, such as more remote work and a greater reliance on digital technology, could become permanent. “I don’t think we’re ever going to get back to what we considered normal before,” Keesler says.
About the Author
Neil Savage is a freelance science and technology writer based in Lowell, Mass., and a frequent contributor to IEEE Spectrum. His topics of interest include photonics, physics, computing, materials science, and semiconductors. His most recent article, “Tiny Satellites Could Distribute Quantum Keys,” describes an experiment in which cryptographic keys were distributed from satellites released from the International Space Station. He serves on the steering committee of New England Science Writers.
On 1 May, Donald Trump signed an executive order aimed at securing the U.S. bulk-power system, the backbone of our national electricity infrastructure. Bulk power comprises high-voltage transmission lines and generators delivering energy to large consumption centers. The order spotlights an important issue, but neither the order nor the issue has received the attention it deserves, due in part to the COVID-19 outbreak. The order highlights the U.S. power system’s extreme vulnerability to attacks by hackers, terrorists, state actors, and other malefactors, and it’s a bold and timely attempt to recognize and appropriately deal with these threats.
We know that terrorists and state-sponsored actors already have the capabilities to disrupt a country’s power supply. In 2015, a Russian group launched cyberattacks against the Ukrainian power system, causing temporary blackouts and leaving more than 200,000 people without electricity on a winter day for up to six hours. Similarly, Russians were suspected of cyberattacks on Estonia’s power system in 2019. There is little doubt that many other countries also have this capability, though nobody else has applied it—yet.
As a means of protecting the U.S. bulk-power system, the new executive order bans the purchase of equipment manufactured outside of the United States. The supply chain for the power infrastructure is multinational, and many components intended for transformers, circuit breakers, and substation equipment are produced outside of the United States. The imported hardware as well as software could potentially include back doors that would provide critical access to this equipment. If these back doors are triggered remotely, they could disrupt or even lead to the collapse of our national power system.
But the executive order doesn’t account for some major details. The bulk-power system, defined in the order as 69 kilovolts and above, already enjoys tight federal regulation, close oversight, and continuous monitoring. Local power-distribution systems, much of whose energy delivery is below 69 kilovolts, are another story.
This portion of the grid, which may be thought of as the “last mile” to millions of end users, delivers electricity to countless systems, appliances, and devices—including anything you might plug into a standard 110-volt outlet. Because these distribution networks are regulated locally by states and municipalities, and not by the federal government, they fly under the radar of the new executive order. But they are still just as vulnerable to attack.
This vulnerability is particularly pernicious because it allows for a cyberattack that could propagate from a local network to the bulk-power system. Such a hack could target a local power utility or end-user systems, including large numbers of high-wattage devices like dishwashers, HVAC systems, or electric vehicles (EVs). Research at New York University by Samrat Acharya, Ramesh Karri, and me has shown, for example, that large numbers of EVs can be compromised remotely over the Internet and then manipulated to overload power system equipment. Because this type of attack begins with end users, it may remain invisible to operators of bulk-power systems until equipment failure or major abnormalities occur.
The very real danger here is that these sub rosa attacks, while local, can affect the national bulk-power system in the same way that damming a number of tributaries can damage the major river into which the tributaries flow.
Even if an attack doesn’t propagate to the bulk-power system, local end-user attacks in major metropolitan areas could directly and immediately affect vast numbers of people. Consolidated Edison, the electric power utility in New York City, operates 69 distribution system substations supplying 60 billion kilowatt-hours of electricity yearly to more than 3.4 million customers of all socio-demographic groups. A local attack that brought down even part of ConEd’s distribution system could disrupt service to hundreds of thousands of people.
The human costs of power-supply disruptions can go far beyond inconvenience. People on dialysis machines or ventilators or those with heat-sensitive pre-existing conditions are considered “electricity-dependent,” because the consequences for them of even a brief power outage could be dire. The number of electricity-dependent individuals in the United States who reside at home was estimated to be about 685,000 in 2012. Roughly one-fifth of that population could be harmed by even a short three- or four-hour power outage. The executive order needs to look at the many ways local and particularly metropolitan power systems are still at risk.
Another limitation of the executive order is its emphasis on hardware—that word appears in nearly every paragraph—without a corollary focus on software, another attractive port of entry for attackers. Despite sophisticated protection, power system software can be compromised in multifarious ways that are more difficult to identify than are hardware backdoors. And this risk exists in both the bulk- and local-power systems. Software is generally tested against known vulnerabilities, and so a valuable modification to the current order would be protocols for software improvements or analysis to discover new vulnerabilities.
Finally, the executive order focuses explicitly on protecting the power grid against foreign threats. But the danger comes from not only state actors, but also non-state actors and even, unfortunately, U.S. citizens. Consider the sniper attack of 2013 at a PG&E transmission facility near San Jose, Calif., in which a group of gunmen fired on transformers at a substation. While not a cyberattack or even technologically sophisticated, the incident nonetheless inflicted millions of dollars in damage and caused a local blackout—a prime example of a domestic attack by non-state actors. And because cyberattacks on the U.S. power system could be launched remotely, they could be carried out by domestic actors residing overseas.
Overall, the executive order is a big step in the right direction. It is bringing attention to a huge problem and could lead to good ideas and solutions. Still, it would be even stronger if it took a more comprehensive view of both the vulnerabilities in our power systems and the sources of potential threats.
About the Author
Yury Dvorkin is an assistant professor of electrical and computer engineering and a faculty member of the Center for Urban Science and Progress (CUSP) at New York University’s Tandon School of Engineering.
When Hurricane Maria razed Puerto Rico in September 2017, the storm laid bare the serious flaws and pervasive neglect of the island’s electricity system. Nearly all 3.4 million residents lost power for weeks, months, or longer—a disaster unto itself that affected hospitals and schools and shut down businesses and factories.
The following January, then-Gov. Ricardo Rosselló signaled plans to sell off parts of the Puerto Rico Electric Power Authority (PREPA), leaving private companies to do what the state-run utility had failed to accomplish. Rosselló, who resigned last year, said it would take about 18 months to complete the transition.
“Our objective is simple: provide better service, one that’s more efficient and that allows us to jump into new energy models,” he said that June, after signing a law to start the process.
Yet privatization to date has been slow, piecemeal, and mired in controversy. Recent efforts seem unlikely to move the U.S. territory toward a cleaner, more resilient system, power experts say.
As the region braces for an “unusually active” 2020 hurricane season, the aging grid remains vulnerable to disruption, despite US $3.2 billion in post-Maria repairs.
Puerto Rico relies primarily on large fossil fuel power plants and long transmission lines to carry electricity into mountains, coastlines, and urban centers. When storms mow down key power lines, or earthquakes destroy generating units—as was the case in January—outages cascade across the island. Lately, frequent brownouts caused by faulty infrastructure have complicated efforts to confront the COVID-19 outbreak.
He and many others have called for building smaller regional grids that can operate independently if other parts fail. Giant oil- and gas-fired power plants should similarly give way to renewable energy projects distributed near or within neighborhoods. Last year, Puerto Rico adopted a mandate to get to 100 percent renewable energy by 2050. (Solar, wind, and hydropower supply just 2.3 percent of today’s total generation.)
So far, however, PREPA’s contracts to private companies have mainly focused on retooling existing infrastructure—not reimagining the monolithic system. The companies are also tied to the U.S. natural gas industry, which has targeted Puerto Rico as a place to offload mainland supplies.
In June, Luma Energy signed a 15-year contract to operate and maintain PREPA’s transmission and distribution system. Luma is a newly formed joint venture between infrastructure company Quanta Services and Canadian Utilities Limited. The contract is valued between $70 million and $105 million per year, plus up to $20 million in annual “incentive fees.”
Wayne Stensby, president and CEO of Luma, said his vision for Puerto Rico includes wind, solar, and natural gas and is “somewhere down the middle” between a centralized and decentralized grid, Greentech Media reported. “It makes no sense to abandon the existing grid,” he told the news site in June, adding that Luma’s role is to “effectively optimize that reinvestment.”
Orama Exclusa says he has “mixed feelings” about the contract.
If the private consortium can effectively use federal disaster funding to fix crumbling poles and power lines, that could significantly improve the system’s reliability, he says. But the arrangement still doesn’t address the “fundamental” problem of centralization.
He also is also concerned that the Luma deal lacks transparency. Former utility leaders and consumer watchdogs have noted that regulators did not include public stakeholders in the 18-month selection process. They say they’re wary Puerto Rico may be repeating missteps made in the wake of Hurricane Maria.
As millions of Puerto Ricans recovered in the dark, PREPA quietly inked a no-bid, one-year contract for $300 million with Whitefish Energy Holdings, a two-person Montana firm with ties to then-U.S. Interior Secretary Ryan Zinke. Cobra Acquisitions, a fracking company subsidiary, secured $1.8 billion in federal contracts to repair the battered grid. Last September, U.S. prosecutors charged Cobra’s president and two officials in the Federal Emergency Management Agency with bribery and fraud.
A more recent deal with another private U.S. firm is drawing further scrutiny.
In March 2019, New Fortress Energy won a five-year, $1.5 billion contract to supply natural gas to PREPA and convert two units (totaling 440 megawatts) at the utility’s San Juan power plant from diesel to gas. The company, founded by billionaire CEO Wes Edens, completed the project this May, nearly a year behind schedule. It also finished construction of a liquefied natural gas (LNG) import terminal in the capital city’s harbor.
“This is another step forward in our energy transformation,” Gov. Wanda Vázquez Garced said in May during a tour of the new facilities. Converting the San Juan units “will allow for a cheaper and cleaner fuel” and reduce monthly utility costs for PREPA customers, she said.
Critics have called for canceling the project, which originated after New Fortress submitted an unsolicited proposal to PREPA in late 2017. The ensuing deal gave New Fortress an “unfair advantage,” was full of irregularities, and didn’t undergo sufficient legal review or financial oversight, according to a June report by CAMBIO, a Puerto Rico-based environmental nonprofit, and the Institute for Energy Economics and Financial Analysis.
The U.S. Federal Regulatory Commission, which oversees the transmission and wholesale sale of electricity and natural gas, also raised questions about the LNG import terminal.
On 18 June, the agency issued a rare show-cause order demanding that New Fortress explain why it didn’t seek prior approval before building the infrastructure at the Port of San Juan. New Fortress has 30 days to explain its failure to seek the agency’s authorization.
Concerns over contracts are among the many challenges to revitalizing Puerto Rico’s grid. The island has been mired in a recession since 2006, amid a series of budget shortfalls, financial crises, and mismanagement—which contributed to PREPA filing for bankruptcy in 2017, just months before Maria struck. The COVID-19 pandemic is further eroding the economy, with Puerto Ricans facing widespread unemployment and rising poverty.
The coming months—typically those with the most extreme weather—will show if recent efforts to privatize the grid will alleviate, or exacerbate, Puerto Rico’s electricity problems.
Predictably, the inquiries will be framed as they were after the bungled government response to Hurricane Katrina in 2005, which focused on the question, “How could this have happened in America, and what must our government do to make sure to the best of our ability that nothing like this national nightmare ever happens again?” The foregone conclusion will be the same, i.e., “All levels of government failed in their obligations.” The inquiries will fail—again—to probe and answer the more fundamental set of questions that need asking if we are to mitigate future crises: What are the government’s, and the American people’s, respective roles and responsibilities in the face of disaster?
Indeed, so predictable is this turn of events that—with some substitutions to match the current crisis—that what follows below is substantially an identical argument to the one I made in April 2006 for IEEE Spectrum following Katrina, and which warned of future events like pandemics.
For example, what is the obligation of government—local, state, and federal—to manage its citizens’ risk? Can the government protect its citizens from all their risks, and even if it can, should it? What are U.S. citizens’ expectations regarding personal choice in management of their risk? What is the nation’s risk appetite and risk tolerance? How much risk management is enough? What are the responsibilities of corporations as well as individuals to make preparations? Without addressing these and similar questions, we are likely to end up with more poorly conceived, contradictory and costly strategies that will only increase risk.
A particularly contentious issue has been the lack of intensive care unit (ICU) ventilators available for hospitals. Governors, mayors and other locally elected officials have criticized the Federal government for not having enough ventilators in the Strategic National Stockpile to support the COVID-19 patients in their states’ hospital ICUs. However, the potential lack of ventilators in the event of a national pandemic was fully understood by state health preparedness officials prior to the pandemic.
For instance, in November 2015, New York State Commissioner of Health released its updated ventilator allocation guidelines (PDF) originally released in 2007 which “develop guidance on how to ethically allocate limited resources (i.e., ventilators) during a severe influenza pandemic while saving the most lives.” The guidelines explicitly make it clear that in a severe pandemic, “many more patients will require the use of ventilators than can be accommodated with current supplies.” The guidelines further state that even if New York were to purchase the “vast number” of ventilators needed, a “sufficient number of trained staff would not be available to operate them.”
In the introduction to the guidelines, the Commissioner with obvious pride notes, “The first Guidelines were widely cited and followed by other states. We expect these revised Guidelines to have a similar effect.” Other states who don’t use New York’s guidelines have similar ones of their own.
Given this widespread acknowledgement and acceptance that ICU ventilators and trained personnel would be in short supply in a severe pandemic, state politicians’ feigned surprise and anger over shortages are mere deflections for their own failure to have a robust public discussion about their government’s role, and capability, to manage their state’s citizens’ risk in a pandemic before it occurred. If New York State residents knew, for example, that its public officials were not going to purchase adequate number of ventilators in case of a pandemic, would they have objected and insisted that they should be? Unfortunately, they never were asked.
Similarly, what is the responsibility of the American people to manage their own risks? The Centers for Disease Control and Prevention (CDC) has repeatedly published and widely advertised preparedness guidelines [PDF] for the American people to follow in the case of a severe pandemic. The guidelines recommend that households buy and store two-weeks’ supplies of food, water, medicine, face masks and other essentials. Yet, how many families followed these recommendations? (A related question regards how much thought was given to households without the resources or space to accumulate such a cache, particularly in pandemic-prone high-density cities like New York, where housing costs are burdensome and apartments small.)
In both cases, the risk and resources needed to prepare for a pandemic was traded-off against other competing risks, both short-term and long term. While many American households may not have the means to prepare for a pandemic as the CDC recommended, the paucity of ventilators in event of a pandemic was a risk accepted by state government officials with eyes wide-open.
There has been a growing expectation among the American people, as well as state and local governments, that the Federal government be the risk manager of first resort in every crisis. However, there are limits to what any government can realistically accomplish, given the sheer number of disasters possible. Can the government protect all citizens from the effects of pandemics, floods, fires, hurricanes, tornadoes and earthquakes, as well as human follies like oil spills or financial mismanagement?
If the American people desire the Federal government to be their risk manager of first resort, then there must be an open and honest discussion to decide what its risk management priorities should be. Then allocate tax dollars to mitigate those risks as opposed to others. The government must draw a bright line demarcating which risks it will try to anticipate and act to prevent, and which risks it can only react to. For these latter cases, the government must forcefully convey what it can and cannot reasonably do, and just as forcefully formulate what it expects its citizens to do. Then no one will be under the illusion that the government can control risks that it cannot, nor guarantee a risk-free life where it will make every person “whole” after disasters occur.
A friend of mine who was recovering from his second heart attack remarked to me that his first heart attack got his attention, while the second kept it. Perhaps, after suffering yet another government risk mismanagement heart attack, we can finally have a national debate on the roles, responsibilities, and expectations of government and its citizens in terms of managing risk—and decide which risks and responsibilities are whose. If we don’t, the next heart attack may be the one that kills us.
Abstract: This book includes a select set of examples curated to show how researchers and industrial partners are changing the way we produce and consume energy. See what is possible when leveraging the NI platform.
As South Sudan emerges from the wreckage of civil war, its leaders are beginning to build the nation’s electric sector from the ground up. With only a handful of oil-fired power plants and crumbling poles and wires in place, the country is striving for a system that runs primarily on renewable energy and reaches more homes and businesses.
Today, only about 1 percent of South Sudan’s 12.5 million people can access the electric grid, according to the state-run utility. Many people use rooftop solar arrays or noisy, polluting diesel generators to keep the lights on; still many more are left in the dark. Those who can access the grid must pay some of the highest electricity rates in the world for a spotty and unreliable service.
The generations-old trend toward lower electricity prices now appears to have ended. In many affluent countries, prices tilted upward at the turn of the century, and they continue to rise, even after adjusting for inflation.
Even so, the price we pay for electricity is an extraordinary bargain, and that’s why this form of power has become ubiquitous in the modern world. When expressed in constant 2019 dollars, the average price of electricity in the United States fell from $4.79 per kilowatt-hour in 1902 (the first year for which the national mean is available) to 32 cents in 1950. The price had dropped to 10 cents by 2000, and in late 2019 it was just marginally higher, at about 11 cents per kilowatt-hour. This represents a relative decline of more than 97 percent. A dollar now buys nearly 44 times as much electricity as it did in 1902.
Because average inflation-adjusted manufacturing wages have quadrupled since 1902, blue-collar households now find electricity about 175 times as affordable as it was nearly 120 years ago. And it gets better: We buy electricity in order to convert it into light, kinetic energy, or heat, and the improved efficiency of such conversions have made the end uses of electricity an even greater bargain.
Lighting offers the most impressive gain: In 1902, a lightbulb with a tantalum filament produced 7 lumens per watt; in 2019 a dimmable LED light delivered 89 lm/W (see “Luminous Efficacy,” IEEE Spectrum, April 2019). That means a lumen of electric light is now three orders of magnitude (approximately 2,220 times) more affordable for a working-class household than it was in the early 20th century. Lower but still impressive reductions in end-use costs apply in the case of electric motors that run kitchen appliances and force hot air into the ducts to heat houses using natural-gas furnaces.
An international perspective shows some surprising differences. The United States has cheaper residential electricity than other affluent nations, with the exception of Canada and Norway, which derive high shares of their power from hydroelectric generation (60 percent and 95 percent, respectively).
When using prevailing exchange rates, the U.S. residential price is about 45 percent of the European Union’s mean, about half the Japanese average, and about a third of the German rate. Electricity prices in India, Mexico, Turkey, and South Africa are lower than in the United States in terms of the official exchange rates, but they are considerably higher in terms of purchasing power parity—more than twice the U.S. level in India and nearly three times as much in Turkey.
A naive observer, reading the reports of falling prices for photovoltaic cells and wind turbines, might conclude that the rising shares of solar and wind power will bring a new era of falling electricity prices. Just the opposite has been true.
Before the year 2000, when Germany embarked on its large-scale and expensive Energiewende (energy transition), that country’s residential electricity prices were low and declining, bottoming at less than €0.14/kWh ($.13/kWh, using the prevailing exchange rate) in 2000.
By 2015, Germany’s combined solar and wind capacity of nearly 84 gigawatts had surpassed the total installed in fossil-fueled plants, and by March 2019 more than 20 percent of all electricity came from the new renewables. However, over an 18-year period (2000 to 2018) electricity prices more than doubled, to €0.31/ kWh. The E.U.’s largest economy thus has the continent’s highest electricity prices, followed by heavily wind-dependent Denmark, at €0.3/kWh.
A similar contrast can be seen in the United States. In California, where the new renewables have taken an increasing share, electricity prices have been rising five times as fast as the national mean and are now nearly 60 percent higher than the countrywide average.
This article appears in the February 2020 print issue as “Electricity Prices: A Changing Bargain.”
Another devastating hurricane season winds down in the Caribbean. As in previous years, we are left with haunting images of entire neighborhoods flattened, flooded streets, and ruined communities. This time it was the Bahamas, where damage was estimated at US $7 billion and at least 50 people were confirmed dead, with the possibility of many more fatalities yet to be discovered.
A little over two years ago, even greater devastation was wreaked upon Puerto Rico. The back-to-back calamity of Hurricanes Irma and Maria killed nearly 3,000 people and triggered the longest blackout in U.S. history. All 1.5 million customers of the Puerto Rico Electric Power Authority lost power. Thanks to heroic efforts by emergency utility crews, about 95 percent of customers had their service restored after about 6 months. But the remaining 5 percent—representing some 250,000 people—had to wait nearly a year.
After the hurricanes, many observers were stunned by the ravages to Puerto Rico’s centralized power grid: Twenty-five percent of the island’s electric transmission towers were severely damaged, as were 40 percent of the 334 substations. Power lines all over the island were downed, including the critical north-south transmission lines that cross the island’s mountainous interior and move electricity generated by large power plants on Puerto Rico’s south shore to the more populated north.
In the weeks and months following the hurricane, many of the 3.3 million inhabitants of Puerto Rico, who are all U.S. citizens, were forced to rely on noisy, noxious diesel- or gasoline-fired generators. The generators were expensive to operate, and people had to wait in long lines just to get enough fuel to last a few hours. Government emergency services were slow to reach people, and many residents found assistance instead from within their own communities, from family and friends.
The two of us weren’t surprised that the hurricane caused such intense and long-lasting havoc. For more than 20 years, our group at the University of Puerto Rico Mayagüez has studied Puerto Rico’s vulnerable electricity network and considered alternatives that would better serve the island’s communities.
Hurricanes are a fact of life in the Caribbean. Preparing for natural disaster is what any responsible government should do. And yet, even before the storm, we had become increasingly concerned at how the Puerto Rico Electric Power Authority, or PREPA, had bowed to partisan politics and allowed the island’s electrical infrastructure to fall into disrepair. Worse, PREPA, a once well-regarded public power company, chose not to invest in new technology and organizational innovations that would have made the grid more durable, efficient, and sustainable.
In our research, we’ve tried to answer such questions as these: What would it take to make the island’s electricity network more resilient in the face of a natural disaster? Would a more decentralized system provide better service than the single central grid and large fossil-fuel power plants that Puerto Rico now relies on? Hurricane Maria turned our academic questions into a huge, open-air experiment that included millions of unwilling subjects—ourselves included. [For more on our experiences during the storm, see “For Two Power Grid Experts, Hurricane Maria Became a Huge Experiment.”]
As Puerto Rico rebuilds, there is an extraordinary opportunity to rethink the island’s power grid and move toward a flexible, robust system capable of withstanding punishing storms. Based on our years of study and analysis, we have devised a comprehensive plan for such a grid, one that would be much better suited to the conditions and risks faced by island populations. This grid would rely heavily on microgrids, distributed solar photovoltaics, and battery storage to give utilities and residents much greater resilience than could ever be achieved with a conventional grid. We are confident our ideas could benefit island communities in any part of the world marked by powerful storms and other unpredictable threats.
As is typical throughout the world,Puerto Rico designed its electricity infrastructure around large power plants that feed into an interconnected network of high-voltage transmission lines and lower-voltage distribution lines. When this system was built, large-scale energy storage was very limited. So then, as now, the grid’s control systems had to constantly match generation with demand at all times while maintaining a desired voltage and frequency across the network. About 70 percent of Puerto Rico’s fossil-fuel generation is located along the island’s south coast, while 70 percent of the demand is concentrated in the north, which necessitated building transmission lines across the tropical mountainous interior.
The hurricane vividly exposed the system’s vulnerability. Officials finally acknowledged that it made no sense for a heavily populated island sitting squarely in the Caribbean’s hurricane zone to rely on a centralized infrastructure that was developed for continent-wide systems, and based on technology, assumptions, and economics from the last century. After Maria, many electricity experts called for Puerto Rico to move toward a more decentralized grid.
It was a bittersweet moment for us, because we’d been saying the same thing for more than a decade. Back in 2008, for instance, our group at the university assessed the potential for renewable energy [PDF] on the island. We looked at biomass, microhydropower, ocean, photovoltaics (PV), solar thermal, wind, and fuel cells. Of these, rooftop PV stood out. We estimated that equipping about two-thirds of residential roofs with photovoltaics would be enough to meet the total daytime peak demand—about 3 gigawatts—for the entire island.
To be sure, interconnecting so much distributed energy generation to the power grid would be an enormous challenge, as we stated in the report. However, in the 11 years since that study, PV technology—as well as energy storage, PV inverters, and control software—has gotten much better and less costly. Now, more than ever, distributed-solar PV is the way to go for Puerto Rico.
Sadly, though, renewable energy did not take off in Puerto Rico. Right before Maria, renewable sources were supplying just 2.4 percent of the island’s electricity, from a combination of rooftop PV, several onshore wind and solar-power farms, and a few small outdated hydropower plants.
Progress has been hamstrung by PREPA. The utility was founded as a government corporation in 1941 to interconnect the existing isolated electric systems and achieve islandwide electrification at a reasonable cost. By the early 1970s, it had succeeded.
Meanwhile, generous tax incentives had induced many large companies to locate their factories and other facilities in Puerto Rico. The utility relied heavily on those large customers, which paid on time and helped finance PREPA’s infrastructure improvements. But in the late 1990s, a change in U.S. tax code led to the departure of nearly 60 percent of PREPA’s industrial clients. To close the gap between its revenues and operating costs, PREPA periodically issued new municipal bonds. It wasn’t enough. The utility’s operating and management practices failed to adapt to the new reality of more environmental controls, the rise of renewable energy, and demands for better customer service. Having accumulated $9 billion in debt, PREPA filed for bankruptcy in July 2017.
Then the hurricane struck. After the debris was cleared came the recognition—finally—that the technological options for supplying electricity have multiplied. For starters, distributed energy resources like rooftop PV and battery storage are now economically competitive with grid power in Puerto Rico. Over the last 10 years, the residential retail price of electricity has fluctuated between 20 and 27 U.S. cents per kilowatt-hour; for comparison, the average price in the rest of the United States is about 13 cents per kWh. When you factor in the additional rate increases that will be needed to service PREPA’s debt, the price will eventually exceed 30 cents per kWh. That’s more than the levelized cost of electricity (LCOE) from a rooftop PV system plus battery storage, at 24 to 29 cents per kWh, depending on financing and battery type. And if these solar-plus-storage systems were purchased in bulk, the LCOE would be even less.
Also, the technology now exists to match supply and demand locally, by using energy storage and by selectively lowering demand through improved efficiency, conservation, and demand-response actions. We have new control and communications systems that allow these distributed energy resources to be interconnected into a community network capable of meeting the electricity needs of a village or neighborhood.
Such a system is called a community microgrid. It is basically a small electrical network that connects electricity consumers—for example, dozens or hundreds of homes—with one or more sources of electricity, such as solar panels, along with inverters, control electronics, and some energy storage. In the event of an outage, disconnect switches enable this small grid to be quickly isolated from the larger grid that surrounds it or from neighboring microgrids, as the case may be.
Here’s how Puerto Rico’s grid could be refashioned from the bottom up. In each community microgrid, users would collectively install enough solar panels to satisfy local demand. These distributed resources and the related loads would be connected to one another and also tied to the main grid.
Over time, community microgrids could interconnect to form a regional grid. Eventually, Puerto Rico’s single centralized power grid could even be replaced by interconnecting regional grids and community microgrids. If a storm or some other calamity threatens one or more microgrids, neighboring ones could disconnect and operate independently. Studies of how grids are affected by storms have repeatedly shown that a large percentage of power outages are caused by relatively tiny areas of grid damage. So the ability to quickly isolate the areas of damage, as a system of microgrids is able to do, can be enormously beneficial in coping with storms. The upshot is that an interconnection of microgrids would be far more resilient and reliable than Puerto Rico’s current grid and also more sustainable and economical.
Could such a model actually work in Puerto Rico? It certainly could. Starting in 2009, our research group developed a model for a microgrid that would serve a typical community in Puerto Rico. In the latest version, the overall microgrid serves 700 houses, divided into 70 groups of 10 houses. Each of these groups is connected to its own distribution transformer, which serves as the connection point to the rest of the community microgrid. All of the transformers are connected by 4.16-kilovolt lines in a radial network. [See diagram, “A Grid of Microgrids.”]
Each group within the community microgrid would be equipped with solar panels, inverters, batteries, control and communications systems, and protective devices. For the 10 homes in each group, there would be an aggregate PV supply of 10 to 20 kW, or 1 to 2 kW per house. The aggregate battery storage per group is 128 kWh, which is enough to get the homes through most nights without requiring power from the larger grid. (The amounts of storage and supply in our model are based on measurements of energy demand and variations in solar irradiance in an actual Puerto Rican town; obviously, they could be scaled up or down, according to local needs.)
In our tests, we assume that each community microgrid remains connected to the central grid (or rather, a new and improved version of Puerto Rico’s central grid) under normal conditions but also manages its own energy resources. We also assume that individual households and businesses have taken significant steps to improve their energy conservation and efficiency—through the use of higher-efficiency appliances, for instance. Electricity demand must still be balanced with generation, but that balancing is made easier due to the presence of battery storage.
That capability means the microgrids in our model can make use of demand response, a technique that enables customers to cut their electricity consumption by a predefined amount during times of peak usage or crisis. In exchange for cutting demand, the customer receives preferential rates, and the central grid benefits by limiting its peak demand. Many utilities around the world now use some form of demand response to reduce their reliance on fast-starting generating facilities, typically fired by natural gas, that provide additional capacity at times of peak demand. PREPA’s antiquated grid, however, isn’t yet set up for demand response.
During any disruption that knocks out all or part of the central grid, our model’s community microgrids would disconnect from the main grid. In this “islanded” mode, the local community would continue to receive electricity from the batteries and solar panels for essential loads, such as refrigeration. Like demand response, this capability would be built into and managed by the communications and control systems. Such technology exists, but not yet in Puerto Rico.
Besides the modeling and simulation, our research group has been working with several communities in Puerto Rico that are interested in developing local microgrids and distributed-energy resources. We have helped one community secure funding to install ten 2-kW rooftop PV systems, which they eventually hope to connect into a community microgrid based on our design.
Other communities in central Puerto Rico have installed similar systems since the hurricane. The largest of these consists of 28 small PV systems in Toro Negro, a town in the municipality of Ciales. Most are rooftop PV systems serving a single household, but a few serve two or three houses, which share the resources.
Another project at the University of Puerto Rico Mayagüez built five stand-alone PV kiosks, which were deployed in rural locations that had no electricity for months after Maria. University staff, students, and faculty all contributed to this effort. The kiosks address the simple fact that rural and otherwise isolated communities are usually the last to be reconnected to the power grid after blackouts caused by natural disasters.
Taking this idea one step further, a member of our group, Marcel J. Castro-Sitiriche, recently proposed that the 200,000 households that were the last to be reconnected to the grid following the hurricane should receive rooftop PV and battery storage systems, to be paid for out of grid-reconstruction funds. If those households had had such systems and thus been able to weather the storm with no interruption in service, the blackout would have lasted for 6 months instead of a year. The cost of materials and installation for a 2-kW PV system with 10 kWh of batteries comes to about $7,000, assuming $3 per watt for the PV systems and $100/kWh for lead-acid batteries. Many households and small businesses spent nearly that much on diesel fuel to power generators during the months they had no grid connection.
To outfit all 200,000 of those households would come to $1.4 billion, a sizable sum. But it’s just a fraction of what the Puerto Rico government has proposed spending on an enhanced central grid. Rather than merely rebuilding PREPA’s grid, Castro-Sitiriche argues, the government should focus its attention on protecting those most vulnerable to any future natural disaster.
As engineers, we’re of course interested in the details of distributed-energy resources and microgrid technology. But our fieldwork has taught us the importance of considering the social implications and the end users.
One big advantage of the distributed-microgrid approach is that it’s centered on Puerto Rico’s most reliable social structures: families, friends, and local community. When all else failed after Hurricane Maria, those were the networks that rose to the many challenges Puerto Ricans faced. We think it makes sense to build a resilient electricity grid around this key resource. With proper training, local residents and businesspeople could learn to operate and maintain their community microgrid.
A move toward community microgrids would be more than a technical solution—it would be a socioeconomic development strategy. That’s because a greater reliance on distributed energy would favor small and medium-size businesses, which tend to invest in their communities, pay taxes locally, and generate jobs.
There is a precedent for this model: Over 200 communities in Puerto Rico extract and treat their own potable water, through arrangements known as acueductos comunitarios, or community aqueducts. A key component to this arrangement is having a solid governance agreement among community members. Our social-science colleagues at the university have studied how community aqueducts are managed, and from them we have learned some best practices that have influenced the design of our community microgrid concept. Perhaps most important is that the community agrees to manage electricity demand in a flexible way. This can help minimize the amount of battery storage needed and therefore the overall cost of the microgrid.
During outages and emergencies, for instance, when the microgrid is running in islanded mode, users would be expected to be conservative and flexible about their electricity usage. They might have to agree to run their washing machines only on sunny days. For less conscientious users, sensors monitoring their energy usage could trigger a signal to their cellphones, reminding them to curtail their consumption. That strategy has already been successfully implemented as part of demand-response programs elsewhere in the world.
Readers living in the mainland United States or Western Europe, accustomed to reliable, round-the-clock electricity, might consider such measures highly inconvenient. But the residents of Puerto Rico, we believe, would be more accepting. Overnight, we went from being a fully electrified, modern society to having no electricity at all. The memory is still raw. A community microgrid that compels people to occasionally cut their electricity consumption and to take greater responsibility over the local electricity infrastructure would be far more preferable.
This model is applicable beyond Puerto Rico—it could benefit other islands in the tropics and subtropics, as well as polar regions and other areas that have weak or no grid connections. For those locales, it no longer makes sense to invest millions or billions of dollars to extend and maintain a centralized electric system. Thanks to the advance of solar, power electronics, control, and energy-storage technologies, community-based, distributed-energy initiatives are already challenging the dominant centralized energy model in many parts of the world. More than two years after Hurricane Maria, it’s finally time for Puerto Rico to see the light.
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