In Chapter 14, we looked at some of the parties interested in adopting energy storage systems, and the reasons they are replacing legacy-generating facilities with solar, wind, and supplemental battery storage. In this chapter, we'll look at the specific effects that battery storage systems will have on future power plant construction. The effect of cheap storage combined with local generation (solar and wind) will keep a lot of power plants from ever being built. Let's look at some of the specific reasons energy storage is becoming such a game-changer in the energy space. Some of this material can get very technical, but I have done my best to clarify and simplify the concepts for you.

BLINK AND YOU'LL MISS IT

Remember that the electricity in non-storage, electrical-grid networks is used as soon as it is generated. All power generated worldwide is alternating current (AC) power. Here in the United States, the nominal frequency is 60 hertz (Hz). Most of Europe, Asia, and Africa generate 50 Hz power. Most networks have excess generating capacity that is available to add to the grid as demand increases. When an electric generating plant trips offline suddenly and unexpectedly, there is an immediate dearth of energy on the grid. This causes a drop in frequency on the grid. If the frequency falls too far, other generators may not be able to supply enough energy to the system fast enough to keep the grid stable. If that happens, those other stations could also trip off the grid. Eventually, a blackout would ensue as the electrical load becomes too big for remaining generators to handle. And all of that would occur within the first half-second after the original generator trips off. That's about the time it takes us to blink.

This problem has only gotten bigger as higher levels of renewables continue to be deployed on global electrical grids. As their levels increase, grid stability becomes progressively more at risk. The inertial response that a turbine-driven spinning generator provides to the network is what keeps networks stable. But as they are replaced by renewables, new ways of maintaining grid stability (in that blink-of-an-eye example above) are crucial.

THE CHALLENGE: MATCHING SUPPLY AND DEMAND

In order to keep the grid stable, the amount of power being supplied and the demand being drawn from customers must be closely matched all the time. When a power grid is in balance, the frequency is stable (60 Hz here and 50 Hz across most of the rest of the world, as noted above). But when an unexpected fault occurs and a generating plant trips off the grid, the frequency starts to drop. In order to avoid a catastrophic networks failure, the drop must be quickly stopped and reversed.

As depicted in the waveform shown in Figure 15.1, there are two areas of concern after a fault occurs.

The first area is the ROCOF, the Rate of Change of Frequency. That's simply how quickly the frequency changes. If the ROCOF is greater than 1 Hz per second, other power stations on the grid could trip offline or, even worse, sustain damage.

The second area is the Nadir. That's the minimum frequency to which the grid drops after a fault occurs. Below 59 Hz (in a grid with a nominal frequency of 60 Hz), the potential for additional power stations to trip off the grid goes up rapidly.

Actively managing ROCOF is the easiest way to reduce the Nadir to a level that keeps other power stations online. However, it's becoming a growing challenge to manage ROCOF as the system nonsynchronous penetration (SNSP) has increased. There are three ways to manage ROCOF at high SNSP levels.

1. The first way is to increase the tolerance of existing generators to higher levels of ROCOF. This is something implemented in grid control software that will improve overall grid resilience to frequency faults.
2. The second is to reduce the level at which the thermal synchronous generator operates, or add additional types of synchronous inertia. If combined-cycle gas turbine generators can run at lower load levels, operation will accommodate higher levels of SNSP. Potential sources of synchronous inertia include pumped hydro storage, synchronous compensators, compressed air energy storage, and rotational stabilizers.
3. The third way, and the most relative to our discussion of energy storage, is to increase the synthetic or emulated inertia on the grid. The level of SNSP on grids with significant wind and/or solar penetration is often 75 percent or higher. Synthetic inertia can keep ROCOF within manageable and reasonable levels, even with a 75 percent SNSP level. Battery storage systems with sophisticated control software are capable of achieving low ROCOF, even at high SNSP levels.

SYNCHRONOUS GENERATORS VERSUS BATTERY STORAGE

Let's compare the frequency fault response of synchronous generators and batteries on a typical grid. When the frequency drops suddenly on a grid with nothing but additional backup synchronous generators, those generators automatically respond immediately by slowing down. This adds additional energy that is stored in these massive rotating masses (the generator armature assembly); it is called the synchronous inertial response (SIR). The average generator can provide an increase in grid power of 7 to 14 percent of its total rated capacity. The average SIR response time for a large fault is 0.05 seconds.¹ But here's the catch: In order to respond, a synchronous generator must already be running to create analog inertia. And each additional unit can only provide a small amount of the total required power, as noted above. In order to protect a grid, a large amount of reserve synchronous generators have to be running. This defeats the whole purpose of creating an efficient grid. It also eliminates the need for additional renewables, slowing the transition to a sustainable energy grid.

A battery energy storage system, on the other hand, has no moving parts. With sophisticated control software, this system begins to respond as soon as the frequency fault can be measured. Reaction times of current systems are in the range of 0.1 seconds. Note that the response of battery systems is slightly slower than standby synchronous generators. But once a grid fault is detected by grid control software, a battery system can ramp to full power in less than 0.2 seconds. And unlike synchronous generators, which require a lot of fuel (coal, natural gas, oil) to keep running in standby mode, a battery energy storage system just sits there, fully charged, waiting to respond.

In a real world example, the island country of Ireland installed a 10-MW energy storage array. It began operations on January 5, 2016. The Kilroot Advancion Energy Storage Array is owned by AES Corporation and is the first grid-scale battery storage system in the United Kingdom. It helps keep the island's energy supply and demand in balance. The array assists system operators in efficiently managing existing generation assets. More importantly, it greatly facilitates the integration of renewable power sources into Ireland's power grid.

The initial 10-MW storage array works so well AES is planning to install a 100-MW energy storage array on the grounds of the Kilroot Power Station. That would be the largest energy storage array in all of Europe, and would be the equivalent of 200 MW of flexible generating resources. That array, once installed, is expected to provide $11.3 million in savings annually. In addition, it will avoid 123,000 tons of CO₂ emissions annually.²

Batteries have much higher ramp rates when compared to standby synchronous generators. Once batteries reach full power, the battery system can maintain that level for minutes or hours, as dictated by the size of the battery system. Installing battery storage systems allows grid operators to automatically respond to grid faults much faster than conventional standby generators. It therefore allows renewable generation to replace more conventional synchronous generation and reduce or eliminate standby synchronous generators. More importantly, all those dirty, polluting, and greenhouse gas-emitting fossil fuels that power those generators are no longer necessary.

SOLAR AND WIND, PAIRED WITH STORAGE, ARE DISRUPTING ELECTRIC POWER GENERATION

The year 2017 saw a dramatic drop in both wind and solar energy prices. This reverberation was felt around the world across the global electricity generation sector. In 2017, wind and solar installations nearly reached 155 GW. That's more than all of the power capacity currently installed in the United Kingdom. Renewables are far outpacing coal and nuclear plant development. It's good news for electric customers as well. Prices for solar energy generation dropped 50 percent from levels reached in 2014 and 2015.³

The rapid drop in solar is creating a rapid shift away from fossil fuels. Examples of large utilities shedding fossil fuel generators are NTPC of India, NextEra in the United States, and ENGIE in France. In Italy, ENEL has only had its green power division in existence since 2008. Remarkably, half of its generating capacity now comes from its 39.4 GW of renewable generating assets around the world.⁴

As the amount of renewables deployed goes up, economies of manufacturing scale kick in, and prices go down, a situation compounded by advances in technology, government renewable targets, and inexpensive financing. It's Fessler's first and second laws of technology in action. As a result, solar power purchase agreement (PPA) price records were broken not one but four times in 2017. This technology-driven change is happening all over the world. During 2017, 75 GW of solar PV capacity was turned on by the top three thermal power generating countries: China (53 GW), the United States (12 GW), and India (10 GW). In total, that's more power capacity than all of Indonesia or Australia.⁵

NextEra Energy is one of the world's leading clean energy providers. Based in Juno Beach, Florida, NextEra has 46.79 GW of net generating capacity online; it is the largest producer of wind energy in North America, with 16 percent of all US wind energy capacity. It has almost tripled the amount of wind energy it's deployed over the past decade. It currently has 14 GW of wind energy online, with plans to add an additional 2.4 to 4.1 GW by the end of 2018. Its wind energy projects are located in 20 states and four Canadian provinces.

NextEra is also the world's largest producer of solar energy, having pioneered utility-scale solar nearly 30 years ago. In 2016 alone, NextEra tripled its solar energy plants and now has 2.262 GW of solar energy online. It expects to nearly double that number over the next seven years, including one plant in 2018 that will contain 2.5 million solar panels when complete. Its solar deployments are in 10 US states and Canada. NextEra believes that by 2025, renewable power in the United States will be less expensive than either coal or natural gas–fired power plants. In addition to solar plants that it owns, NextEra Energy designs, builds, finances, and operates solar energy plants for third-party owners. These are located on commercial building rooftops, vacant land, and parking structures. In 2018, it had 20 solar plants in development or under construction in eight states, representing an investment of over $300 million.⁶

NextEra Energy has continued to lead its peers with additional planned deployments of both solar and wind. But it's also the leader in energy storage here in the United States, with over 100 MW of battery energy storage in operation on its grids. Its Babcock Ranch Solar Energy Center is a 74.5-MW solar power plant combined with a 10-MW battery storage system. It's currently the biggest combined solar-plus-storage system in the United States.⁷

In Arizona, the company has a 20-MW, solar PV generating system with 258,000 solar panels. Located on 257 acres of land in Casa Grande, the Pinal Central Solar Energy Center has 10 MW of lithium-ion battery energy storage. The batteries can provide 10 MW of power for a four-hour period. The system cost $60 million to design and install. The owner is the Salt River Project, one of Arizona's largest utilities. The battery system is one of three that the Salt River Project expects to install on its power grid.⁸

A decade ago, the cost of renewables was still in the pre-commercial stage. The only countries that were spending large amounts of capital on them were the United Kingdom, Germany, and Denmark. Now, we've reached the renewable energy tipping point. Today, renewables aren't just commercially viable. They are the cheapest game in town when it comes to energy generation, especially when paired with battery storage. As a result, we see South Korea, France, Japan, the United States, India, and Taiwan all with plans for a rapid ramp-up of renewable energy generation. India could reach fossil-fuel parity by 2020.

Renewables are no longer classified as “other” when compared to coal, natural gas, and nuclear. Their rapid deployment has given rise to a rampant deflationary trend in new power generation costs. This has not gone unnoticed by many governments that are making the shift from fossil fuels to sustainable energy sources. Renewables aren't plagued with the kind of stranded asset issues thermal power plants wrestle with. In addition to countries mentioned above, the UAE, Mexico, Australia, Chile, Canada, and Argentina are all favoring renewable-energy generation. I believe that by the end of this decade, renewables – when paired with storage – will be the least cost generating option everywhere.

RENEWABLES REPLACING NEED FOR MORE NATURAL GAS CAPACITY

In January 2018, much of the United States, including New England was subject to an extended period of cold weather. Unfortunately, New England is underserved in available natural gas transmission line capacity. As a result, spot prices for natural gas hit $35.35 per thousand cubic feet (Mcf) at the Algonquin Citygate, New England's main trading hub for natural gas. But just 250 miles away, in the vast Marcellus shale region of Pennsylvania where the gas comes from, that same gas was priced at between $1 and $2 per Mcf. During that weather pattern, New Englanders paid the highest recorded price for natural gas anywhere in the world. It was 13 times higher than the main US natural gas pricing location, the Henry Hub in Louisiana.

While New England homeowners paid hundreds of dollars more than their counterparts in Ohio and Pennsylvania, they aren't New England's biggest customers for natural gas. Those are the utilities that own natural gas–fired power plants in the region. Natural gas turbines turn generators that produce 50 to 60 percent of New England's daily power requirements.⁹

Looking at New England's problem based simply on natural gas demand, one might conclude that it's absolutely essential that New England have more natural gas pipeline capacity. Without it, especially during winter cold snaps, the reliability of New England's entire power grid could be at risk. And that was exactly the conclusion that ISO-New England, the region's power grid operator, stated in a report it published in January 2018. The report, titled “Operational Fuel Security Analysis,” claimed that if nothing was done to alleviate the natural gas pipeline bottleneck to the region, by the mid-2020s, New England could be subject to rolling blackouts during periods of severe winter cold.¹⁰

The New England Power Pool is the region's group of electricity stakeholders. When this type of analysis is done, they are usually included in the process. But ISO-New England neglected to include them. It didn't include the owners of New England's two LNG import facilities. ISO also made a few assumptions that were way off the mark. It assumed that natural gas demand for use by utility customers would see huge increases. It was an overestimation that resulted in an erroneous conclusion that New England would see complete depletion of natural gas during cold snaps. ISO's other misstep in its report was to completely underestimate the positive effects energy efficiency would bring to the table over the next decade.

It was clear that ISO-New England's study was sending a message to readers that only more natural gas can solve New England's future energy supply issues. But in reality, more natural gas capacity into New England just prolongs that region's move toward a sustainable energy model and creates even more dependence on natural gas. One of the other factors that ISO-New England failed to take into account was the Energy and Diversity Act of 2016 passed by the Massachusetts state legislature. It requires Massachusetts to import clean hydro energy from Canada and contract for 1.6 GW of offshore wind by 2027. Roughly one-third of that wind capacity should be online by 2023. Had ISO-New England taken this information into account when it did its study, its determination would not have been as dire.

In fact, it would have shown that a diversified energy mix, including renewables and storage, improves the reliability of any energy grid. And ISO-New England's conclusions fly in the face of another study commissioned by the attorney general of Massachusetts back in November 2015. It concluded that, “there's no reliability problem though 2030 so long as we continue to pursue our national leading energy efficiency and renewable programs.”¹¹

The bottom line is New England doesn't need more natural gas capacity and the pipelines it would need to get it. What it really needs is a focused program to increase the amount of renewables and battery storage on its grid. Adding more natural gas makes it even more difficult to meet climate change goals. And it would create even more stranded assets that ISO-New England's customers would eventually end up paying for. Its grid reliability goes up as the amount of renewables goes up and reliance on natural gas goes down. Renewables plus storage just seems like a no-brainer when you take the pair at face value. They provide grid resilience and stability, which completely flies in the face of what some legacy-loving individuals are advocating. But we are at a renewable tipping point, and their inclusion into twenty-first-century grid planning and development is unstoppable. In fact, having them as part of any modern electrical grid architecture is a basic requirement.

HUGE EXPENDITURES ON TRANSMISSION AND DISTRIBUTION INFRASTRUCTURE ARE OVER

For the last hundred years or so, utilities expanded generation, transmission, and distribution infrastructures in anticipation of future load expansion. And it was a plan that worked. The annual 2 to 3 percent load growth that the average US electric grid saw was directly correlated to the growth in US gross domestic product (GDP). That's no longer the case. And it's almost entirely due to the rapid growth in rooftop solar as well as energy efficiency measures like LED bulbs and more efficient appliances, all of which are driving the demand for electricity down. But at the same time, electric vehicle charging is starting to drive it up.

This is a real problem for grid planning engineers. They have to make investment decisions on assets that are designed to last 50 years. And the information they have to base their decisions on is extremely fluid. For the first time since electric grids were first designed and built, engineers must deal with the very real possibility that new thermal generation, transmission, and distribution infrastructure added to keep the grid “stable” might not be needed.

COAL-FIRED ELECTRIC GENERATION IS HISTORY … IS NUCLEAR NEXT?

The collapse of coal-fired power generation has had devastating effects on America's coalmines. But cheap renewable and natural gas–fired generation is also weighing heavily on America's remaining nuclear power plants. Nuclear power was once hailed as the world's “cleanest” source of energy. But now, there is a nuclear renaissance in reverse in the United States. And it's being fueled by renewables and natural gas. It's another no-brainer. And once again, it's pure economics.

Back in the heyday of nuclear power, it was hailed as “too cheap to meter.” Fast-forward to 2018 and nuclear is anything but too cheap to meter. In an electricity market dominated by cheap energy from solar, wind, and natural gas, nuclear power is rapidly failing. Let's look at the newest nuclear power generators under construction in the United States. They are Vogtle Units 3 and 4.

This massive boondoggle is being sold to Southern Company's Georgia Power customers. They will be paying for this project for generations to come. The original construction estimate for Vogtle was $14 billion. Units 3 and 4 were scheduled to be online in April 2016. After cost overruns totaling billions, the new price tag has soared to $29 billion. But don't expect these units to be producing power anytime soon.¹²

Southern Company estimates Vogtle will cost an additional $3.9 billion to complete by 2022. But existing current and future debt service is straining Southern Company's balance sheet. Not too surprising, Moody's has a negative outlook on the company's stock, which is rated Baa2. That's only a level or two above junk status.

At the end of 2017, Southern Company had long-term debt of $44.46 billion.¹³ Just imagine if Southern Company had bet on solar and natural gas instead of Vogtle. It would already be producing plenty of clean energy. What's more, its customers wouldn't be on the hook for tens of billions of dollars. It's an expensive lesson for Southern Company. It's too soon to tell if Vogtle will ever be completed. Let's look at why other nuclear plants are closing here in the United States.

NUCLEAR PLANTS ARE DROPPING LIKE DOMINOS

At last count, there are 99 nuclear power plants licensed to operate here in the United States.¹⁴ Sixteen have scheduled closing dates of 2025 or sooner.¹⁵ That means over the next seven years, 25 percent of America's nuclear power fleet will be gone. It's just too expensive to keep these giant maintenance nightmares running. In January 2018, California officials voted to close the last operating nuclear plant in the state. By 2025, the Diablo Canyon Power Plant will be closed.¹⁶

In April 2018, FirstEnergy Corporation (NYSE: FE) announced it is closing three nuclear power plants in Ohio and Pennsylvania.¹⁷ The reason? They cost too much money to run. So much for “too cheap to meter.” Utility executives at FirstEnergy and at other utilities are appealing to lawmakers for money. Their nuclear plants just can't operate profitably.

The latest announcement came in August 2018. NextEra, the owner of the Duane Arnold nuclear plant in Iowa, says it's closing the plant early. NextEra claims that closing the plant now will save Iowans $42 annually in electricity costs starting in 2021. If all of the planned nuclear plant closings move forward, the U.S. nuclear plant fleet will drop from its current level of 99 plants to 89 by 2025.¹⁸

And state public utility commissions aren't willing to have customers shoulder the costs. But nearly all state and federal lawmakers are turning a blind eye toward the utilities' nuclear woes. In January 2018, the Federal Energy Regulatory Commission (FERC) sidelined a Trump administration plan to prop up coal and nuclear power plants. Energy Secretary Rick Perry suggested coal and nuclear plants should have a 90-day fuel supply on hand. He also suggested US taxpayers should pay for it. FERC disagreed, and voted the measure down.

In October 2018, a Trump nominated Bernard McNamee to FERC. He replaces outgoing commissioner Ron Powelson. McNamee is a big champion of Trump's coal and nuclear bailout. Trump is still hopeful FERC will pass his plan, which has been regularly denounced by former FERC commissioners, various consumer groups, and the solar, wind, natural gas, and energy efficiency sectors.¹⁹

The oldest operating nuclear plant belongs to Exelon Corporation (NYSE: EXC). It's the Oyster Creek plant located in Lacey Township, New Jersey. The plant originally went online on December 1, 1969. The plant's biggest problem is lack of storage for cooling water. The company is closing the plant in October 2018,²⁰ over a year ahead of schedule. Exelon cites excessive maintenance costs and cheap power from natural gas and renewables as the reason.

Another very real example of unnecessary generation expansion occurred in South Carolina. As I mentioned earlier, in 2008, nuclear industry executives predicted a “nuclear renaissance.”²¹ Never mind that no utility had started a new reactor project since the 1970s. Fast-forward a decade. In August 2017, two South Carolina utilities announced they were abandoning the V.C. Summer nuclear project. The project was to have two reactors when completed sometime in 2018. Today, the reactors are each about 40 percent complete. Cost to date? About $9 billion. The original cost estimate was $11.5 billion. The estimate to complete them now is $25 billion.

The SCANA Corporation and Santee Cooper, South Carolina's state-owned electric and water utility, jointly own the V.C. Summer project. The two new reactors were under construction next to an existing nuclear reactor. In order to keep the project afloat, the two utilities appealed to “high White House officials,” according to SCANA's CEO Kevin Marsh. This included Energy Secretary Rick Perry. His answer? No response. It appears even Washington isn't interested in reviving American nuclear power.²²

What's wrong with America's nuclear industry? The engineering expertise and the robust supply chains needed to build these plants no longer exist. They've been atrophying for the past 30 years. That's one issue facing today's nuclear projects. Another is the reactor supplier. The Westinghouse Electric Company had been building nuclear reactors for decades. But on March 29, 2017, Westinghouse filed for bankruptcy protection. That was a big nail in the coffin of the V.C. Summer project.

But the biggest nail of all is the overall cost of nuclear power generating plants. They take one or two decades to permit and construct. Even the most ambitious solar and wind projects are permitted and constructed in a year or two. And for tens of billions of dollars less. But the bottom line is the final cost of the energy they produce. Nuclear power, when the costs of the plant, storing the toxic waste it produces, and the operating costs are all taken into account, is the most expensive power source on the planet. There's no question nuclear power served America well for more than half a century.

The disruption of nuclear power is one that utilities didn't see coming. In the case of nuclear (and coal) the disruption is an economic one. Many existing plants are eligible for 20-year extensions from the Nuclear Regulatory Commission. But economics trump license extensions. I wouldn't be a bit surprised if most of our nuclear power plants closed over the next several decades. Expensive nuclear has no place in today's world of cheap, renewable energy. The twenty-first century is going to be one of energy disruption: The “nuclear sunset” and the “rise of renewables” are all part of it.

PJM Interconnection is one of the regional transmission organizations (RTOs). It overlooks the transmission grid that covers most of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia, and the District of Columbia. PJM is responsible for coordinating the movement of electricity (at the wholesale level) between major markets and the generators tied to the grid serving those markets, and it acts as a referee in a price-competitive market. Ultimately, it's responsible for grid reliability for over 65 million Americans.

As part of its duties, PJM has to estimate the growth of electrical loads within the aforementioned areas. That has never been an easy task. And for the last decade, PJM has consistently overestimated its summer peak load. Its projections specified that in 2017 load growth was going to increase. But it never materialized. That's a real problem for customers. They're the ones footing the bill me personally, because I live in PJM's coverage area.

Today we see progressive organizations taking a much more cautious view toward any transmission and distribution upgrades. In 2017, Arizona Public Service (APS) had a big little problem. The small village of Punkin Center, 90 miles northeast of Phoenix, needed more power. Only 600 people live in this tiny hamlet. APS could upgrade 20 miles of a 21-KV transmission line that serviced the village. The line would have to traverse very mountainous terrain. Constructing it would be very expensive.

So APS looked into a battery storage system. It found the cost to be far less than the transmission line. It installed two MW-worth of storage on land it owned in Punkin Center. Now, on the 20 to 30 days during the year when Punkin Center's load would have overloaded the existing transmission line, APS can source additional power from the battery system. The overall cost ended up being less than half of the transmission line upgrade.²³ It's a great example of not having to install a thumbtack with a sledgehammer. The project is one of several APS has installed in its territory, and the utility now considers storage as part of any new transmission and distribution upgrade discussion.

Another advantage of battery storage, often overlooked by its detractors, is its flexibility. An upgraded transmission or distribution system can only provide relief to one place. And transmission and distribution lines can take years to permit and install. A battery storage system can be permitted and installed in six months, whereas a battery storage system can source power onto a grid that can then be directed anywhere. What's more, if storage is no longer needed in one place, it can be dismantled and moved to another. Storage can solve headaches for utilities and soothe the wallets of utility ratepayers. Everybody wins.

A NATURAL GAS CRISIS WITH AN ENERGY STORAGE SOLUTION

The Aliso Canyon Oil Field and Natural Gas Storage Facility is an underground oil reservoir containing both oil and natural gas. It's located in the Santa Susana Mountains, north of Los Angeles. It was initially discovered in 1938 and underwent rapid development. Oil production from Aliso Canyon peaked in the 1950s. After the depletion of its oil and gas resources, the Southern California Gas Company (SoCalGas), a subsidiary of Sempra Energy, converted it to an underground natural gas storage reservoir in 1973. The reservoir has a capacity of more than 86 billion cubic feet of natural gas.²⁴ That makes it the second-largest underground natural gas storage facility in the United States.

SoCalGas used Aliso Canyon to store natural gas for future use during winter peak heating periods. It also withdrew natural gas during peak summer months as air conditioners created more demand for electricity. Gas is accessed via one of 115 injection wells on the property. There are 38 miles of interconnecting pipelines from the wells to distribution and transmission pipelines. The average thickness of the reservoir is 160 feet, and it's located roughly 9,000 feet below the surface.²⁵

On October 23, 2015, SoCalGas employees found a huge natural gas leak at Aliso Canyon. Natural gas was leaking from a well on the property. It was not until February 11, 2016, that SoCalGas brought the leak under control. A week later on February 18, California state officials announced that a permanent plug had successfully been installed in the leaking well.²⁶ The duration of the leak resulted in a massive natural gas release. At its peak, the well was leaking 4.5 metric tons of ethane. But its 60 metric tons of methane leaking every hour was twice the methane emissions rate of the entire greater Los Angeles area. Altogether, 97,100 metric tons of methane were released as a result of the leak, making the Aliso Canyon leak the largest natural gas atmospheric spill in US history.²⁷

As a result, San Diego Gas & Electric (SDG&E), the electric utility for Southern California, now had a big problem. It relied on natural gas from the Aliso Canyon Storage Facility to power its peak natural gas–fired turbine generators during peak summer periods of electricity demand. It needed a solution it could quickly deploy. Gas peaker plants were out of the question. Traditional solar and wind were also off the table due to their intermittent nature. The solution had to be compact, since it would be servicing densely populated areas around San Diego and Los Angeles.

At the time, grid-scale battery storage was still very new. The California Public Utilities Commission (CPUC) was fearful of blackouts. It mandated several measures in order to find a quick solution to the problem, one of which was quick approval of an energy storage solution. The CPUC told SDG&E and Southern California Edison to find a battery storage system supplier that could deliver and put a system into operation in a few months.

SDG&E decided to make this a major test case for its service area. So in August 2016, SDG&E chose AES Energy Storage to build the two energy storage projects. Together, they are 37.5 MW, and can store a total of 150 MWh of electricity. They are located at several sites, one of which is a substation in Escondido, a northern suburb of San Diego. The Escondido system contains 24 containers that house numerous racks of lithium-ion battery packs.

Because of the tight schedule as dictated by the CPUC, AES was at an advantage. It was and is the world's largest energy storage system installer. AES's contract with SDG&E stipulates that AES must maintain the nameplate capacity of the system (37.5 MW for four hours) for 10 years. After that, maintenance is the responsibility of SDG&E. In order to meet capacity for the full 10-year timeframe, AES oversized the project upfront.²⁸ The system is used to meet peak loads, and therefore is discharged and charged almost completely on a daily basis. This is a strain on lithium-ion cells, hence the oversizing of the project.

Even prior to the Aliso Canyon disaster, SDG&E was taking a serious look at energy storage. James Avery, the chief development officer for the utility, raised some eyebrows at the 2015 Energy Storage North America conference when he dreamed out loud to the audience, “I see a future where there will be no more gas turbines. Two years ago, we were only looking at gas turbines.” Avery believes that we are living through the energy storage tipping point. Soon he thinks it will be commonplace to use energy storage in place of gas peaker plants and even baseload plants.²⁹

It's clear that energy storage is going to be a benefit to electric utilities, especially as their grids have more and more solar and wind energy generation systems tied to them. The combination of renewables and energy storage is going to eventually replace most other conventional forms of power generation. In the next chapter, we are going to look at the effects that electric vehicles (EVs) are going to have on the world's power grids, and how someday, they may turn into sources of grid power when not being driven.