Our linear ‘take-make-waste’ economy generates two billion tons of municipal solid waste per annum according to the World Bank. Not only do growing populations exacerbate the problem, but as economies get richer, they generate more waste per capita. The IPCC estimates that global waste management and landfills produced 64 million tons of methane per year between 2008 and 2017, with emissions steadily increasing.

Transitioning from our current system towards to a regenerative economy, in which materials are circulated in closed-loop production systems, will be essential to minimise resource consumption and associated emissions. The Circular Economy is an approach to organising production and consumption that touches every industry, in principle. In practice, the EU prioritises a select group of industries, such as electronics, batteries and vehicles, and plastics.

Circular Economy in Consumer Electronics

Studies estimate that the carbon footprint of the entire electronics industry — from laptops, smartphones to computers and servers — tripled to about 3.7% of global greenhouse emissions in the past decade. According to the UN, Europe generates 12 million tons of e-waste every year. Countries such as Norway and UK generate some 24 kg of waste per capita per year compared to a global average of 7 kg.

Consumers appear hungry for change, with movements such as the Right to Repair demanding the availability and affordability of spare parts. EU regulators have enshrined the principles of the circular economy in the European Green Deal by requiring manufacturers and retailers of consumer devices to recycle devices returned by customers.

Smartphones represent a major challenge, having become both ubiquitous and disposable, with an average lifetime of about two years. Manufacturing a new smartphone, including mining for critical materials, amounts to roughly 80% of the device’s total carbon footprint over its two-year lifespan. With each generation of increasingly feature-rich phones, carbon emissions rise further. The carbon footprint of the Apple 12 Pro Max is 86 kg, which is 51% more than for an iPhone 6.

Recycling rare earths and other materials inside consumer electronics devices are critical to the technologies powering the energy transition, such as electric vehicles and hydrogen electrolysers. Access to abundant, low-cost raw materials is necessary for these clean technologies to scale. With increasingly challenging and tight supply chains, recycling offers a sustainable way to ensure the energy transition stays on track. Although each smartphone contains only a few grams of rare earths, in aggregate they make up a meaningful volume of supply. Miniature gold mines live in our dusty desk drawers, waiting for good use.

Recycling obsolete products is not sufficient to retain and recover their entire value. Before recycling devices, we need to maximise the lifetime of electronic equipment by increasing repairability and re-use. According to a European Environmental Bureau study, extending the lifespan of smartphones by just one year would save as much as removing two million cars off the roads. Alternatively, renting a reconditioned device enables consumers to change phones without the CO2 emissions associated with manufacturing, which account for 80% of the total.

EIP’s Investment In Grover

EIP is excited to lead Grover’s $110m Series C round and to support the company as it seeks to radically reduce consumer electronics waste.

As a global leader in technology rentals, Energy Impact Partners’ latest portfolio addition offers consumers and enterprises the choice to subscribe for devices instead of purchasing them. As Grover’s products are repaired, refurbished, and recirculated up to eight times, users can benefit from all the devices in circulation — ultimately from drones to dishwashers — while minimising e-waste and landfill use. Grover has circulated over 500,000 tech products spanning the entire consumer electronics spectrum.

EIP looks forward to supporting Michael Cassau and the Grover management team as they scale across Europe and the all-important US market. Grover, is a fantastic example of EIP’s mission to produce strong market returns by backing entrepreneurs who are developing the most impactful carbon mitigating technologies and business models.

Gold Mines in Our Dusty Drawers was originally published in Energy Impact Partners on Medium, where people are continuing the conversation by highlighting and responding to this story.

by Andy Lubershane, SVP Strategy @ Energy Impact Partners

(but the opinions published herein are my own)

From Wikipedia (accessed 8/18/21):

“The 21st century hipster is a subculture that is defined by claims to authenticity and uniqueness yet, ironically, is notably lacking in authenticity and conforms to a collective style.”

I’ll return to this concept in a bit.

If natural gas is going to be a “bridge fuel”, the bridge needs to be short…and an actual bridge

In the past twenty years, natural gas has often been heralded as the ideal “bridge fuel”. Here’s why:

• Burning natural gas to produce energy releases about half as much carbon dioxide into the atmosphere as burning coal for energy.
• In many sectors — though not all — natural gas is a relatively straightforward substitute for coal.
• In North America, natural gas has become dirt cheap, thanks to the development of hydraulic fracturing (i.e. “fracking”) technology and associated infrastructure. It’s still about two times cheaper to burn North American natural gas to produce high temperature heat — which is what the majority of energy is used to do — than to produce heat from even the cheapest wind & solar power.
• Hence, substituting natural gas for coal appears to be an affordable way to reduce greenhouse gas emissions while renewables scale up to supply the majority of our energy — perhaps nearly all of our energy — over the next 2–3 decades. In this way, natural gas can serve as the “bridge” to a clean energy future.

This is the “bridge fuel” narrative. At first glance, it appears to be coming true:

So what’s the problem?

There are two big ones. Both are deal-breakers for natural gas if they’re not overcome, but neither is insurmountable.

First: The bridge we’re building might be too long: We’re in a climate emergency, and those who recognize that fact are rightfully concerned that new investment in natural gas infrastructure — from pipelines, to power plants, to home heating systems — will lock us financially into a much longer “bridge” than the climate will tolerate. The typical gas infrastructure investment has a 25–30 year financial lifespan. If those assets continue to emit carbon at a level anywhere near their full carbon-emitting capacity over that timeframe, then I won’t be able to look my kids in the eyes and tell them “You won’t get cooked”.

Second: The bridge we’re building isn’t really a bridge at all: It’s true that natural gas — when it’s burned — releases just a little more than half of the carbon dioxide as coal, when it’s burned. But, not all of the natural gas we unearth is burned. A well-regarded estimate from the Environmental Defense Fund pegs the total amount of “fugitive” natural gas leakage at about 2.4% of all the gas we pump out of the ground. Unfortunately, that measly 2.4% ruins natural gas’s carbon profile. That’s because natural gas — methane — is itself a greenhouse gas which is far more potent than the carbon dioxide emitted when it’s burned. Methane is especially potent in the first couple decades of its existence in the atmosphere.

Growing awareness of these two problems has shaken the foundation of the bridge fuel narrative. In its place, a “renewables only” narrative and an “electrify everything” narrative have taken hold of a growing share of the climate & energy community. These narratives are beginning to exert political power — leading to both subtle & not-so-subtle decisions that restrict new investment in natural gas infrastructure and consumption.

Narratives have a way of building on themselves. There’s a chance that natural gas infrastructure gets sucked into a kind of “death spiral” — the kind of negative feedback loop that was once prophesized for electric utilities due to the falling cost of rooftop solar. In fact, it’s turned out that cheap solar (mostly large-scale, not rooftop) has been an incredible boon for the electric infrastructure business, and has positioned electric utilities at the center of the energy transition. Actually, the “solar death spiral” has become a much more realistic threat to natural gas.

This, too, is just a narrative. The future of natural gas is no more set in stone than gas itself, which can be set loose from porous rock with the right application of pressure.

I repeat: we’re in a climate emergency. We can’t afford to be ‘climate hipsters’ who reject a cheap, abundant, rapidly scalable resource with robust, continent-spanning delivery networks in place…just because renewable electricity feels more authentically green.

Hence, the natural gas industry needs to face it’s glaring weaknesses head on, at least in order to shore up the bridge fuel narrative, and perhaps even more importantly: because natural gas might be more than a bridge. I’m convinced that it’s way to soon to give up on the optionality that natural-gas-centric approaches to decarbonization provide.

More on that in a bit, but first…

First, shoring up the bridge

In general: Beware articles that tout “one easy step” to fix anything.

In this particular case, though, there actually is one easy step that natural gas producers, pipeline operators, and consumers can take to fix the foundation of the bridge fuel narrative. This one easy step also happens to be extremely low-cost: Become a fugitive emissions hawk.

The 2.4% of gas that leaks along the way from wellheads to consumers is by no means impossible, or even all that expensive, to prevent from leaking. The industry simply hasn’t had enough incentive to prioritize doing so.

We have a pretty darn good idea which link in the natural gas supply chain is responsible for most of the leaks. A landmark EDF study estimates that three quarters of ‘fugitive’ emissions come from wellheads themselves or from local gathering & processing equipment — in other words: it’s the gas producers, ultimately, who’ll need to take action to stop the lion’s share of emissions.

We also know that producers vary tremendously in their self-reported emissions rates — and most producers report very low emissions. The top 50% of producers emit less than a tenth as much as the worst performers!

It’s possible that poorly performing producers might decide to shape up on their own. Hopefully they’ll realize that they’re at risk of getting caught in a death spiral, and they’ll elevate the hunt for fugitive emissions to the level of existential priority that it deserves.

For now, though, producers apparently still need a firm nudge in the right direction by their customers. Large natural gas buyers like electric utilities (who burn gas to run their turbines), gas distribution utilities, and other large industrial gas consumers need to appreciate that their social license to operate is also at risk. They, too, must contend with the threat of a death spiral.

Many electric utilities have now publicly committed to high levels of carbon reduction in the 2030–2050 timeframe. For most, natural gas remains an essential element of those plans. Large gas buyers are especially well positioned to demand that their gas suppliers clear a very high bar on fugitive emissions — and prove it. My firm, EIP, has invested in a company called Project Canary, which has developed a proprietary sensing & analytics suite — along with a certification system — to do just that. Project Canary estimates that a typical gas utility could purchase certified “responsible” gas for its customers for an average cost of about $1 per customer per year.

The most difficult challenge for utilities seeking to purchase certified “responsible” gas is unlikely to come from internal opposition. Instead, it’s likely to come from policymakers and regulators. In some states, regulators may feel their hands are tied from approving any increase in energy cost, no matter how negligible, in the name of climate change. In others, regulators may feel increasingly hamstrung by climate hipsters who perceive even responsible gas —despite being such an obvious win for the climate — as an impediment to their preferred decarbonization narrative.

I believe both ‘red’ and ‘blue’ objections to responsible natural gas can & should be overcome. In part, they can be overcome by the same argument:

Natural gas might be more than a bridge.

Really, natural gas might be more than a bridge!

If fugitive emissions are dealt with, then we can safely explore two credible technology pathways which would enable natural gas to play a significant role in a fully decarbonized energy system, well beyond 2050. Both, unsurprisingly, require a form of what’s called “carbon capture & storage”, or CCS.

The only difference between these pathways is that one relies on ‘post-combustion’ carbon capture, and the other on ‘pre-combustion’ capture.

Post-combustion capture is what most people think of as CCS. Essentially: burn the gas, then suck out as much of the CO2 as you can from the emissions flue — typically with a solvent or a sorbent-based chemical approach — then stick that CO2 in a pipeline and pipe it to a geological formation where it can be pumped underground for, effectively, the rest of time.

There’s no new technological wizardry needed to make this process work. All of the technology has been fairly well proven by large industrial incumbents, and geological storage capacity has been fairly well studied. But this pathway is still highly uncertain. The challenges are twofold:

1. The more of the carbon you want to capture from an industrial flue, the more expensive it becomes. Getting to absolute zero carbon is practically impossible.
2. In general, CO2 transport & storage infrastructure cannot be built up cost effectively on a facility-by-facility basis. To achieve economic viability, that infrastructure will need to be developed much like pipeline infrastructure today —to serve a regional or even national network of carbon capturers.

Pre-combustion capture is typically referred to by the nicknames for it’s output: “blue” or “turquoise” hydrogen. In both cases, methane is converted to hydrogen and a carbon byproduct. In conventional hydrogen production, a process called steam methane reformation, that byproduct is CO2. If the CO2 is captured and piped to a sequestration site just like in the scenario above, the resulting hydrogen is “blue”. If the carbon-based byproduct is instead solid carbon — ready to be either or landfilled or put to use as a feedstock for various products — the resulting hydrogen is called “turquoise”. (Most turquoise approaches can make use of some amount of ‘green’ electricity as a secondary energy input alongside natural gas — hence the blue/green color scheme.)

Whether capture is done pre or post-combustion, early indicators suggest that ‘clean natural gas’ could be very cost-effective. The most promising early-stage technology developers in each category believe that they can deliver dramatically lower-carbon energy and compete well economically against both “green” electricity & its derivative “green” hydrogen. There’s no doubt that these ‘pure green’ decarbonization pathways will have a big role to play in areas with superb wind & solar resources. But natural-gas-centric pathways are shaping up to be strong contenders in regions with more expensive renewable resources, like the densely populated east coast of the US.

That is, of course, if we deal with the fugitive emissions problem. If not, studies show that these pathways aren’t worth pursuing.

Getting to the other side of the bridge

I’ll repeat once more: We’re in a climate emergency. It’s too soon to rule out natural gas as a potential solution. Instead, the goal of climate activists, clean tech investors, and industry strategists alike should be to direct society towards the highest & best use of such a plentiful resource. If you agree, here are the steps forward I’d recommend:

I. For starters, an intense focus on fugitive gas emissions would reduce emissions right now! This is a must-do, because there’s no scenario in which we’re not pumping gas out of the ground, to at least some extent, for the next 30 years. Gas producers: If you ignore this risk, it’s your funeral. Gas buyers: It’s time to encourage your vendors to do the right thing. Next time you go to market for gas, demand at least a portion of it is certified by a trusted-third-party to be near-zero fugitive emissions.

II. To anyone in the gas infrastructure business: When you’re considering an investment in the next pipeline, power plant, or industrial furnace, make a plan to future proof it for decarbonization. Generally, speaking, that’s going to mean making it as “hydrogen-ready” as possible. It’s too soon to say whether that hydrogen will be green, blue, or some other color. My best guess is that the specific hue of hydrogen will vary from plant to plant depending on lots of site-specific variables. (In some plants, direct electrification will also be an attractive option…but that’s a tale for another day…)

Technology is on track to make the NG → H2 transition possible for a wide range of applications. For example, the three largest manufacturers of natural gas combustion turbines — GE, Siemens, and Mitsubishi — each offer modest hydrogen-cofiring options today, and plan to launch 100% hydrogen-ready turbine models by 2030. Utilities and independent power producers around the world are already beginning to realize the importance of the optionality that this technology offers.

Over time, natural gas assets will almost certainly burn less & less gas directly. Some will co-fire increasing levels of hydrogen. Others will simply run much less frequently, but provide outsized value to the energy system in the form of fuel diversity & resiliency. For example, the gas-based microgrids developed by Enchanted Rock (also an EIP portfolio company) are a quintessential case study in wringing the most resiliency value out of a relatively small amount of gas consumption. Over time, this type of distributed gas generation can also be transitioned to run on either hydrogen or renewable natural gas (a topic for another day).

To other interested readers: Don’t be a climate hipster. Be a fugitive emissions hawk! And please tell your politicians & regulators to do the same.

Stray notes:

• Apologies to hipsters (sorta). No really, some of my best friends were hipsters in college!
• Yes, my firm stands to profit from Project Canary’s success. I’d evangelize for them even if it cost me personally. I believe they’re doing some of the most important work in the energy industry today. Rarely in the clean tech world does one encounter such a slam-dunk value proposition.
• GHG emissions aren’t the only negative impact of natural gas production that need to be minimized. The industry still needs hawks watching out for conventional air & water pollution, too. However, it’s important to note that natural gas is not alone among energy sources in requiring careful management to avoid local environmental harm. Wind & solar power also come with serious land-use & environmental downsides that are much easier to dismiss today than they will be at net-zero scale.

How to keep worrying but still learn to love natural gas was originally published in Energy Impact Partners on Medium, where people are continuing the conversation by highlighting and responding to this story.

The sidewalks you walk on might seem pedestrian, but they could soon be an exciting frontier for climate action.

Concrete is both ubiquitous, as the most common man-made material on the planet, and incredibly carbon-intensive. Manufacturing its core ingredient, cement, produces about 8% of global greenhouse gas emissions annually — four times more than aviation. With the number of buildings worldwide expected to double by 2060 as construction accelerates in the industrializing world, it will be virtually impossible to meet climate goals without substantially decarbonizing concrete.

Fortunately, a slew of emerging technology solutions offer several pathways to significantly reduce the emissions impact of this building block of modern life — and perhaps even make concrete a climate solution, rather than a climate problem.

Pathway 1: Change the formula

The first step in making concrete is combining primary ingredients (mostly finely-ground limestone, clay, and iron ore) in a kiln to produce cement. The method of making Ordinary Portland Cement, the most commonly used variety, has remained largely unchanged for more than a century. Altering the formula could reduce emissions in several ways.

Solidia is pioneering an alternative cement formulation that significantly lowers the temperature needed in the kiln, which the company claims can achieve a 30–40% reduction in emissions through energy savings. Engineers at Purdue University recently discovered that adding nanoscale titanium dioxide to cement nearly doubles the amount of CO2 that concrete absorbs from the atmosphere as it hardens.

An electrochemical approach could separate out CO2 before the kiln. In 2019, MIT researchers announced they had demonstrated a breakthrough process using electrochemistry to separate carbon dioxide from limestone, producing a clean lime that can be combined with clay in a kiln. The process could be powered by clean electricity, and the separated CO2 would be pure and easily captured for use or storage. Leah Ellis, who was then a post-doc at MIT and the lead researcher on the process, has since spun out an early-stage startup called Sublime Systems to commercialize the technology.

Alternatively, the formulation of concrete could be changed to reduce or eliminate cement. Carbicrete has developed a process for producing pre-cast concrete that replaces cement with steel slag, a waste product from steelmaking. Because CO2 is absorbed through their process, Carbicrete’s concrete blocks are carbon-negative.

Pathway 2: Change the kiln

Cement kilns are typically coal-fired, and the ultra-high temperatures required (reaching 2,700 degrees Fahrenheit) make it challenging to switch to an alternative fuel. There are some small gains to be made in increasing energy efficiency and shifting to lower-carbon fuels like natural gas or biomass, but major carbon reductions require a more significant change.

Decarbonizing existing cement plants could be accomplished by capturing carbon dioxide directly from flue gas. Several point-source carbon capture startups have begun partnerships with some of the largest global cement manufacturers. Carbon Clean has announced a pilot project with CEMEX in California and Svante is working with LafargeHolcim at a plant in British Columbia, both focused on developing cost-competitive carbon capture.

Fossil fuels could be replaced by hydrogen or direct electrified heat to reach high temperatures without fuel emissions. However, neither approach has been significantly tested, and using a zero-carbon fuel would not address the 65–70 percent of emissions stemming directly from the chemical process of converting the calcium carbonate in limestone to lime (CaCO3 → CaO+ CO2). The European Union has partnered with a consortium of cement industry titans on a project called LEILAC to develop a new kiln design where process emissions, which are almost pure CO2, are kept separate from the fuel exhaust, making carbon capture of the process emissions much easier.

Pathway 3: Change the aggregate

Concrete is made by combining cement with aggregate material, typically a mixture of sand and gravel. Cement only accounts for approximately 10–15 percent of concrete by volume but is responsible for virtually all the emissions in the final product (thus, a current opportunity to somewhat lower emissions is to reduce the amount of cement in the final concrete mix). One breakthrough opportunity to reduce the climate impact of concrete is to use aggregate materials with ‘negative emissions’ by trapping CO2 in the rock. By reacting carbon dioxide with minerals such as calcium or magnesium oxide, carbon dioxide is mineralized and permanently locked into stable rocks. Because the material grows larger through carbonation, the process can produce more aggregate by volume.

German startup Neustark is recycling old concrete from demolition sites into fresh concrete by binding carbon dioxide to the recycled material, trapping CO2 and reducing the amount of cement needed. They claim that 10kg of CO2 is captured and 20kg of CO2 emissions are avoided in each cubic meter of their concrete. BluePlanet, a Silicon Valley startup backed by Leonardo DiCaprio, is creating aggregates of varying sizes with a synthetic limestone coating that consists of 44 percent CO2. Their method can use flue gas containing CO2 without requiring an additional step of purifying and separating the CO2, making it a direct carbon capture solution for industrial sites and power plants.

Pathway 4: Absorb CO2

In a somewhat ironic twist, the massive carbon impact of cement production is partially balanced after it is used in construction, as concrete naturally absorbs CO2. The hardening of concrete once mixed with water and air is a process called weathering carbonation, in which the concrete absorbs CO2 from the atmosphere. A large amount of CO2 is absorbed in the initial setting period, but concrete continues to absorb CO2 slowly for several decades, reaching nearly 45 percent of the emissions from cement production over the lifetime of concrete structures exposed to air.

To maximize this uptake, several startups are pursuing applications to set, or “cure,” concrete with CO2 instead of water. Nova Scotia-based startup CarbonCure has deployed their curing process, which not only permanently binds carbon dioxide but makes the concrete stronger and uses less cement, in more than 100 sites across North America. However, scaling up carbon curing at job sites will require developing a network of carbon sources and transport. CarbonBuilt offers a similar curing opportunity for precast concrete producers using diffuse CO2 from industrial flue gas sources near to the concrete plants. CarbonCure and Carbon Built recently won the high-profile Carbon XPRIZE, a five-year global competition for technologies that converted CO2 into valuable products.

Laying the foundation for a climate breakthrough

Major hurdles remain to changing a slow-moving industry. Incumbent cement and concrete companies have already invested massive amounts of capital into long-lived facilities. Meanwhile, the construction industry and its regulators are (understandably) risk-adverse when considering changes to key material formulations to support infrastructure and buildings.

But as demand for greater sustainability rises and regulators target high-emitting sectors, low to zero-carbon cement could be not only the climate choice but the economic choice. Startups pursuing alternative approaches could make their products even more profitable if they can sell at a ‘green premium.’ New technological developments for decarbonizing cement are poised to benefit from climate-focused policies incentivizing carbon capture and utilization, early-stage technology development, infrastructure built with low-carbon materials, and building decarbonization.

The wealth of emerging solutions to decarbonize cement present an opportunity for a rapid climate transition of a vital sector. Even if no solution proves to be the perfect “silver bullet” to zero out emissions, multiple decarbonization pathways along the concrete process could be employed simultaneously and we may ultimately see low or even negative-carbon concrete created using a “silver buckshot” combination of the pathways explored above.

Making Concrete a Climate Solution was originally published in Energy Impact Partners on Medium, where people are continuing the conversation by highlighting and responding to this story.

Written by Kevin C. Fitzgerald, Partner & Chief Utility Officer at Energy Impact Partners

The threat of cyberattacks on critical infrastructure has always been top of mind for the power industry. The most recent event– a cyber infiltration of a water utility to increase sodium hydroxide to dangerous levels — comes to us on the backdrop of the 2015 attack on the Ukraine power grid and other major incidents that have underscored the need for our country to focus more on defense against cyber threats.

The first step is to get better insight into what’s really happening on the power system. With that thesis in mind, EIP sought to identify a new technology to ensure critical infrastructure providers could get a clearer picture of the real threats and vulnerabilities on their OT systems. With our collaborative utility partnership model, EIP was uniquely positioned to work with our investors to identify the gaps in the ecosystem, and then scale a solution while sharing best practices across the industry.

In 2017, we led the Series A investment in Dragos, which was operating as a small startup out of Maryland — a long way from Silicon Valley! What the EIP team saw early in Dragos was an all-star team with deep industrial security and OT domain expertise who was dedicated to protecting the country from foreign and domestic cyber adversaries. Importantly, Dragos wanted to work with our utility partners to perfect the various products and services necessary to protect the critical and complex needs of power utilities, water, chemical and oil and gas pipelines.
Since that time, Dragos, the Department of Energy, Southern Company, and several other EIP partner utilities have been quietly contributing to the buildout of Dragos’s Neighborhood Keeper platform — which now stands ready for deployment across the country at this important moment for cybersecurity and critical infrastructure. It’s hard to overstate how important this collaborative approach has been.

What is Neighborhood Keeper? It’s a first-of-its-kind technology that enables critical infrastructure operators to anonymously share threat activity occurring in their industrial control systems in real time. It’s built on the back of the Dragos Platform — a software platform deployed as a series of high-fidelity network sensors within a utility’s OT networks, with deep packet inspection on OT protocols and analytics. The Dragos Platform roots out the threats, and Neighborhood Keeper anonymizes the data and shares it in a central location, identifying correlations across systems and enabling operators to query for more information.
The Neighborhood Keeper platform is built off the premise that through collective shared intelligence, utilities and industrial operators more broadly are stronger and more secure together than they ever could be going it alone. With real-time visibility into their own environments as well as environments of their peers, they can more quickly identify meaningful threats and vulnerabilities — and then rapidly respond in a targeted, coordinated way.

What’s been really special about Dragos, and what has made the Neighborhood Keeper product uniquely impactful, is the willingness to collaborate with DOE and utilities. This created an opportunity for the Dragos platform to meet the specific collective defense needs of our industry — rather than the typical startup company that develops a product to be marketed across as many verticals as possible with minimal customization.

Thus, for the first time we have this capability at an ICS/OT network layer to come together as a community to address these issues. Additionally, the technology ensures that all participant data is stored at the participant’s site and that identity is technologically irreversible. This means information sharing can happen without compromising data security or anonymity. The bottom line is that Dragos is laser-focused on providing the most efficient and effective solution for the industry, even if it means sharing that solution with the Federal government.

This technology is particularly apt in context of the recently announced Biden White House action plan. EIP and its LPs have long seen the necessity of OT/ICS specific cybersecurity, and it’s great to see government and industry come together to address this topic with a focus on threat detection and response, instead of just prevention.

It is time for the utility industry, and other critical infrastructure providers to further collaborate on Neighborhood Keeper and protect our nation from the increasing threats to our public safety.
For more information see this video of public power, and private power companies discussing the value of Dragos and the Neighborhood Keeper technology. (FMPA): https://www.fortnightly.com/videos/cybersecurity-it-takes-neighborhood and visit https://www.dragos.com/neighborhood-keeper/.

Collaborating to protect critical infrastructure — Neighborhood Keeper was originally published in Energy Impact Partners on Medium, where people are continuing the conversation by highlighting and responding to this story.

The story of the tragic 2021 blackouts in Texas isn’t about wind power versus natural gas. It’s not about ‘greedy utilities’ versus the people. It’s not even about the wonky details of how electricity markets are designed by the Texas power grid operator (the Electric Reliability Coordinating Council of Texas, or ERCOT).

The real story is about the value of electric reliability, and the difficulty of securing it in a changing energy system. Texas has shone a spotlight on the acute challenge of ensuring reliabity through a major energy transition, but not in the simplistic way that certain media outlets and politicians have implied. The solution is not to turn away from wind & solar energy; instead, the solution is to embrace the unique features of these energy sources, along with complementary technology like battery storage, to create an even more reliable grid alongside a cleaner one.

Reliability is getting more complicated, and simultaneously becoming even more critical. We need to rethink how we plan our energy system.

Two lessons from Texas for our net-zero-carbon future

I. Electric reliability is undervalued. In economics parlance, energy is one of the highest “consumer surplus” goods money can buy: its value exceeds its cost by leaps and bounds. The longer you go without electricity, the more you realize just how much extra you’d be willing to pay for a few watts of it. Moreover, as we’ve seen in Texas, there are externalities associated with large, regional power outages that exceed the cost to any individual consumer — for example, threats to public health, safety, and supply chains — which are difficult for a competitive market to fully ‘price in’.

The US electricity sector already scores incredibly well on reliability, all things considered. On average across the US, the lights turn on when you flip the switch more than 997 times out of 1,000. And yet, it’s not enough. Today, electricity delivers about 20% of the energy we consume in the United States (as in other industrialized countries). By 2050, most credible net-zero-carbon scenarios peg electricity’s share of the ‘final energy’ pie at 50% or higher.

We know how debilitating & dangerous blackouts can be for a 20% electric society; the recent tragedy in Texas is evidence enough. Sustained outages will become even more intolerable in a 50%+ electric society. Hence, the industry needs to do even better, and we need to do so in the face of two forces that are making the job harder…

II. Reliability is also getting more complicated.

The first force is climate change, which is already causing more extreme weather ‘events’ (including, most likely, the exceptionally frigid February temperatures we just saw in Texas). We’re already beginning to see the impact of more extreme weather play out in reliability data from US utilities.

This chart illustrates why 99.7% electric reliability isn’t good enough. Electric utilities have done a laudable job keeping the lights on during normal conditions. It’s abnormal conditions that are increasingly the driver of power outages. These are, for intuitive reasons, the most dangerous types of outages; they’re longer and more regionally concentrated. See: Texas, February 2021.

The second force making reliability more complicated is the rise of wind & solar power. Today, there is plenty of firm, on-demand power generation on the grid to manage the intermittency of renewables. Contrary to messaging from various politicians, the recent events in Texas had nothing to do with the natural variability of wind & solar energy resources. In fact, the Texas outages had much more to do with the failure of natural gas infrastructure, which Texans were counting on as a “firm” source of energy.

Yet, it’s important to note that neither wind power nor natural gas infrastructure in Texas was sufficiently prepared for extreme weather. A grid fully reliant on either resource, absent investment to prepare for such freezing temperatures, would have failed.

Many studies suggest we ought to be able to achieve very high levels of renewable energy on the grid—upwards of 80–90% of total annual power generation . During ‘normal’ conditions, we can rely on a combination of energy storage and gas-fired power plants to fill in the gaps left by the variability of wind & sun. However, there’s a few reasons to believe our power system planners are going to need to sharpen their pencils. As the situation in Texas highlights, we can’t just prepare for ‘normal’ conditions.

Obviously, we’ll need to install cold-weather gear on wind turbines and gas pipelines — but that’s just a start. Studies of high renewable energy penetration generally employ some approximation of ‘typical meteorological year’ weather data to model the hourly power generation of wind turbines & solar panels. These profiles don’t adequately account for extreme weather events — i.e. unusually extended periods of very low wind or sunshine. As we begin to rely more & more on weather-driven power generation, we need to make sure we’re prepared for really strange weather.

Second, most high-penetration renewable energy plans lean heavily on energy storage technology to balance out daily variations in wind & solar energy. But storage facilities — like big Lithium-ion battery plants, for example—are much more difficult to plan & operate effectively than conventional power plants.

Today, many electricity providers are already aiming to satisfy a portion of their peak demand needs with storage. Market operators & regulators are allowing them to do so with battery systems that have just four hours of ‘duration’ — meaning they can only provide their full power output for four hours without stopping to recharge. Four-hours has become a kind of ‘rule of thumb’ in the industry for the amount of storage one needs in order to serve as a form of ‘firm’ peaking capacity.

If we’re going to depend on storage for electric grid reliability, rules of thumb obviously aren’t going to cut it. We’ll need to know exactly what duration of energy storage the grid will need to make it through periods of low wind & sun. That will depend on a host of tough-to-pin-down variables, including: the precise shape of regional wind & solar generation curves (especially the very low-probability, but increasingly high-consequence tails); the extent to which electricity demand can be made more flexible; and the precision with which storage system operators can predict the optimal time to dispatch their storage plants.

We’ll need to add storage in longer-and-longer duration tranches, eventually using storage to balance all of the intra-day variability in renewable supply — and potentially even seasonal variability (with a much, much cheaper, multi-day storage technology):

In short: planning for a high renenewable energy and storage based system — with even better reliability than our current system — is going to require some new strategies.

Two complementary strategies

There’s no shortage of good ideas for eking out marginal gains in grid reliability while reducing the cost of the system to boot. Leading, next-generation solutions range from drone-based power line inspections to vegetation management employing satellite data. These types of solutions can make a big difference in the near-term, but we’ll also require a long-term game plan — a plan that focuses on two polar opposite, yet highly complementary strategies. One I’ll call “Big Transmission”; the other, “Distributed Resilience”.

Big Transmission

It is what it sounds like: a much bigger, more interconnected transmission system that essentially makes the entire country —perhaps the entire continent —behave like a single, tightly integrated grid. Big Transmission is most manifestly needed to access remote wind & solar resources many miles away from big cities; however, it also has a subtler role to play in blending the generation profiles of renewable resources across regions. As we hook up increasingly disparate wind & solar resources, we also ought to be weaving together regional transmission systems that have historically been only weakly interconnected.

Take Texas as an example. Texas is famous [infamous?] for refusing to interconnect the ERCOT grid outside of the state. But, take a look at the seasonal generation profiles for wind & solar resources along the Texas coast, where most of the energy demand is centered:

Relying solely on these renewable resources, Texas would pretty quickly encounter an overgeneration problem in the spring and summer months, and shortfalls in the winter. There are emerging solutions to this seasonality problem, ranging from ultra-long-duration storage to natural gas with carbon capture & sequestration. But, transmission is an even more tried & true answer.

Texas has even more abundant wind resources in the sparesly-populated Western half of the state than it does on the coast (especially the panhandle). Perhaps more importantly, the seasonal generation profile of panhandle wind is rather inverseley correlated with that of coastal wind:

If Texans were willing to set aside their aversion to inter-regional cooperation, they could do even better. For example, here’s a seasonal Iowa wind resource profile layered on top of Texas wind:

A Big Continental Transmission strategy wouldn’t solve all of our reliability challenges as we transition to net-zero-carbon. But studies show that it would be one of the lowest-cost mechanisms for balancing the grid in normal conditions, as well as guarding against extreme weather in any given region.

The challenge for a Big Transmission strategy in the United States is that it’s proven to be incredibly difficult to plan, site, permit, and build new long-distance, high-voltage transmission lines in the United States. Inter-regional transmission lines are especially tough, because they require coordination and approval from multiple regulatory bodies in every state they touch. So far, even highly promising transmission projects that have lined up willing renewable energy sellers on one end, and willing buyers on the other, have been stymied by objections from state gatekeepers in the middle.

Clearly, we need a stronger national transmission policy. But fortunately, technology can also help, even without a complete policy & planning overhaul. For example, the Brattle Group just released a study demonstrating how three specific “grid enhancing technologies” — advanced power flow control, dynamic line ratings, and topology optimization — can collectively double renewable energy integration capacity with no additional ‘poles & wires’ investments:

In addition to these ‘soft’ technology solutions, we’re also probably going to need to upgrade the wires themselves. The easiest way to add more transmission capacity is to use the corridors we already have, which are already sited and permitted. Each year for the next two decades, 4–6 thousand miles of transmission lines in the US will be turning 50–80 years old; those aged lines are ripe for replacement with conductors capable of carrying more energy — without expanding the size of the clearing or the towers (which would trigger a new environmental review). Eventually there ought to be a big market for new lighter-weight, higher-conductivity cables, or even superconducting cables.

Distributed Resilience

There’s no way we can cost-effectively prepare the macro-grid for every hypothetical threat, which range from extreme cold snaps, to weeks of low wind & sun, to cyberattacks.

What we can do is make our system more resilient so that we can make it through unforseen challenges. And the best place to do that is out at the edge of the grid, close to where people actually consume energy. In short: microgrids.

“Microgrids” are portions of the grid — or even simply individual buildings — which can ‘island’ themselves from the macro-grid for periods of time with their own power supply. Historically, this was done primarily with backup diesel generators, which are too inefficient and dirty to run except during emergency circumstances. The nice thing about renewables and storage is they can contribute to the macro-grid during normal conditions as well.

Today, these renewable microgrids work best when complemented by natural gas gensets, in order to provide as close to 100% reliability as money can buy. One of my firm’s portfolio companies, Enchanted Rock, is a specialist in low-cost, low-emissions natural gas systems, which performed valiantly during the recent crisis in Texas. Distributed natural gas systems are not, of course, zero-carbon today. But eventually they can be transitioned to run on zero-carbon fuels like hydrogen or RNG. Because of their critical contribution to reliability, they could very well be the last form of carbon-emitting generation pushed out of the system.

Microgrids that can provide both regular service to the energy system as well as backup power supply to homes & businesses require a unique blend of technology and business model innovation. Entrepreneurs are finally beginning to figure out the right recipes — taking slightly different approaches at the commercial building level, for individual homeowners, and for entire neighborhoods. Meanwhile, advanced system modeling & control software is making the dream of a ‘grid of microgrids’ feasible. (Disclosure: My firm is also an investor in Opus One Solutions, which makes some of that advanced software.)

Today, about 25% of households pay for some sort of security service focused on crime, but only about 5% of buildings have backup power. This is clearly a market with room to grow — and one that will need to grow as the grid faces greater threats of extended outages, and we become ever more dependent on electricity.

Getting to 100% clean…AND 100% reliable

We have the tools to begin preparing for both. With a combination of investment in Big Transmission and Distributed Resilience, our energy sector can deliver on the promise of zero-carbon energy, with even better reliability than we enjoy today, and without breaking the bank.

Lessons From Texas for the Grid of the Future was originally published in Energy Impact Partners on Medium, where people are continuing the conversation by highlighting and responding to this story.

The first act of the energy transition was powered mostly by incremental progress on decades-old technology.

The second act, which we’re entering now, will be a period of furious innovation to overcome three daunting obstacles to deep decarbonization that incrementalism can’t fix.

The third act will most likely begin in the early 2030s, as the winners emerging from Act II simultaneously begin to form alliances and draw battle lines — engaging in fierce “coopetition” (apologies for the business jargon)— to determine their places in the energy system of the future.

Iteration

First came triple-bladed, horizontal-axis wind turbines; then, polycrystalline-silicon solar panels; then, lithium-ion batteries. Each of these technology platforms already worked, albeit poorly and expensively, for decades before they became fixtures of the energy transition.

The winners of the energy transition so far have been those who seized upon these old ideas, iterated on them, and scaled up manufacturing & deployment until they worked much more efficiently and affordably. A few examples…

1. Suntech, Yingli, Trina, and other Chinese solar manufacturers: Government subsidies helped scale up the manufacturing of existing polycrystalline-silicon photovoltaic technology, driving down the cost by more than 80% from 2005–2015. (Germany’s feed-in-tariff policy also deserves a shout-out for giving Chinese manufacturers a price-insensitive market, which provided the government confidence to invest.)
2. Vestas, Siemens, GE, Gamesa, Nordex, etc.: Some of the first modern wind turbines were installed in the Tehachapi valley in California, in the early 1980s. These early machines were a few notches above old, medieval windmills, with a generator in place of a stone for grinding flour. Yet the basic design was ripe for incremental improvement by the likes of GE, which acquired some wind turbine IP from the ashes of Enron, in 2002. Vestas made a similar move in 2003; Siemens followed suit the very next year; and a few other small, European wind turbine manufacturers began to invest in scale (e.g. Gamesa and Nordex). They all began to iterate on the same basic design, and within a decade the industry was delivering turbines that generated twice as much power, at about half the cost per kilowatt-hour.
3. Sony, Panasonic, BYD, and other Lithium-ion battery manufacturers: Sony built on basic research on Lithium-ion batteries from the 70s and 80s, and commercialized the technology in 1991. (It’s important to note that Sony was pursuing better rechargeable batteries for the Walkman, not for storing solar energy). Ten years later, Li-ion became the go-to option for laptops and cell phones, and a scrappy Chinese company called BYD emerged as a major new player. Panasonic agreed to build a “Gigafactory” with Tesla, and a few other electronics manufacturing giants followed suit, investing in Gigawatt-hour scale production. Now, the technology appears integral to the next phase of the clean energy transition.
4. Tesla: Took a stack of Lithium-ion laptop batteries and asked the obvious-only-in-retrospect question: “Why don’t we put these in cars?” (Tesla is probably the closest to an exception to my ‘old-IP’ thesis, as the Roadster — though it was built mostly from existing building blocks — probably ought to be classified as something fundamentally new.)
5. NextEra, Iberdrola, Enel, Orsted, and other renewable independent power producers: Regional utilities who placed early bets on the ‘deployment & operations’ end of the clean power value chain — first by developing wind farms in Europe and North America; then by expanding both geographically and technologically, to solar and storage. These bets have paid off handsomely, as the market capitalization of each of these “clean energy supermajors” now equals or exceeds those of comparable oil majors.

The first phase of the energy transition is rife with these kinds of incremental innovation success stories: Phillips & the LED light bulb; Nest and ecobee & the ‘smart thermostat’; a whole bunch of solar inverter manufacturers... You get the gist.

Meanwhile, nearly every attempt to develop and commercialize fundamentally new clean energy technology — from wave power, to concentrated solar power— has been left in the dust by the relentless march of wind and solar PV down their respective cost curves. So far, in the battery storage field, Lithium-ion has crushed all pretenders to the throne; and fuel cells have been an expensive distraction.

And yet…

…it’s important that we don’t over-learn this particular lesson. There have also been a handful of bright spots towards the “deep tech” end of the clean energy pool over the past several decades. Offshore wind, for example, required a lot more fundamental innovation than simply bolting established onshore wind turbines to the ocean floor. There have also been a couple of modestly successful alternatives to standard polycrystalline silicon solar technology — First Solar’s thin film modules, and SunPower’s monocrystalline modules, for example — which have each managed to carve out a slice of the market.

Moreover, there’s no way that incrementalism alone will get us all the way to the zero-carbon finish line. The lesson for entrepreneurs can’t be to avoid deep tech…not if we want a habitable planet. Instead, I think the lesson is to avoid betting against the cost curve for more established technology that’s not yet manufactured at scale. If you set out to ‘build a better mousetrap’ on the premise that yours will be cheaper than the leading mousetraps today…be prepared for those other mousetrap manufacturers to build bigger factories before you can trap your first mouse!

Innovation

There are three interrelated reasons why simply continuing to iterate on established wind, solar, and battery technology alone won’t be sufficient for fully decarbonizing the energy system:

I. The last 20(ish)% of clean electricity generation will be exponentially harder to decarbonize: Wind & solar resources are limited — both temporally and geographically — and those limitations will become costlier to overcome as the penetration of wind & solar in the electricity mix rises. In any given region, the first renewable energy projects tend to occupy the best sites — the windiest or sunniest spots with flat ground, acquiescent neighbors, and nearby transmission. Moreover, the natural intermittency of power generation from those first few projects will be effectively washed out by the intermittency of power demand — which is already balanced out on the grid by small adjustments to the output from fossil fuel or hydro power plants.

However, as more wind & solar is added, it will tend to be added in locations with weaker resources or more difficult terrain. And the intermittency of these resources will quickly become the dominant source of variability & uncertainty in the system.

At first, wind & solar intermittency will cause occasional stress on the remaining fossil fuel generation fleet. Natural gas plants will need to ramp up and down somewhat more frequently, more rapidly, and with less notice, in order to keep the grid balanced. But small amounts of battery storage are already a fairly cost-effective solution for performing this balancing feat over the course of a few hours each day.

At some point, though, renewables will begin to cause wild daily swings in power generation; then, eventually, energy deficits that last days or weeks at a time; and lastly, in the home stretch to full decarbonization, enormous seasonal surpluses & shortfalls. At this point, the ‘supply curve’ for wind & solar energy will become so steep that the cost of extracting a marginal megawatt-hour of electricity from those sources will become socially & politically untenable. It’s hard to say exactly where along the supply curve this point will arrive, but the industry seems to have settled on an 80% ‘grid penetration’ threshold as a decent benchmark. Hence, the decarbonization agendas advanced by a growing number of legislatures and utility companies aim for 80% clean electricity within just 10–15 years; but allow for 20 more years after that to quash the last 20% of fossil fuel generation.

In reality, regions with more challenging renewable energy development environments might hit the steepest part of their supply curves much sooner. Hence the (ish) in 20(ish)%. That (ish) implies big error bars.

II. Clean electricity can currently only reach 80(ish)% of energy demand: Established wind & solar technology produces clean electricity…but in industrialized economies, only 20–30% of energy is currently delivered & consumed as electricity. The lion’s share of energy end-uses are fueled by the direct combustion of fossil fuels. Hence, in order to decarbonize the vast majority of transport, industry, and heating, we’ll need to either electrify all of those end-uses, or come up with an alternative clean energy ‘medium of exchange’ for them to consume.

III. Energy system inertia: It‘s incredibly unlikely that we’ll be able to replace existing fossil fuel energy sources with clean energy sources fast enough to hold ourselves to even the most permissive global carbon budgets. New fossil-fuel-consuming power plants and industrial facilities are still being built around the world today, as I write— for example, several gigawatts of new natural gas power plants in the US, and about 100 gigawatts of coal power capacity in China. In fact, thirty percent of global fossil fuel power capacity was installed in the past 10 years. Absent the addition of carbon capture technology, operation of these plants over the full course of their 30–50-year projected lives would make global carbon goals impossible to achieve.

In a series of articles published earlier this year, I dug into some of the specific places where truly game-changing innovation is probably necessary in order to overcome the challenges outlined above — including hydrogen production, batteries for electric vehicles, seasonal energy storage, and offshore wind. I still believe these are likely to be big pieces in the decarbonization puzzle.

Yet, oftentimes when solving a puzzle, it’s worthwhile to step back and survey all of the pieces arranged on a table…

For each of the puzzle pieces splayed out above, there’s now a wave of investment fueling innovators trying to find the right fit. (See: Gates, Bezos, Nadella, et al, and my own firm Energy Impact Partners, too.) At this point the key question for the industry has shifted from “If” there will be sufficient investment in deep tech to “When” the deep tech within each category will be ready for commercialization.

2025–2030 is shaping up to be a pretty good answer to that “When” question. Dozens of the most promising technology companies across the deep decarbonization landscape are targeting the second half of this decade to prove their mettle and commence full-scale deployments.

That brings me to the next phase of the energy transition…

Coopetition

Assume one or two companies working on each of the categories above are successful, meaning: by the late 2020s they’ve proven their technology works; they have line-of-sight to cutting costs by scaling up manufacturing; and they’ve shaken hands to cement some important commercial relationships.

They’ll soon begin to compete with each other, but only in some places; in others, they’ll form more cooperative relationships. Hence, the race to decarbonize in the 2030s and beyond will be defined by the admittedly business jargony, but in this context fully appropriate term coopetition.

So, let’s take a look at the coop-etitive landscape…

Decarbonizing the last 20(ish)% of power generation

(henceforth referred to as “20%”, for readability)

What do we know about the last 20% of power generation that will need to be decarbonized?

1. It will be seasonal, just like the ebb and flow of renewable energy. By the time we get to the last 20%, the majority of diurnal intermittency will already have been addressed with some variant on today’s Lithium-ion batteries.
2. If the last 20% comes from even more wind & solar resources, those resources will be extra far away from energy demand centers. The good sites for wind & solar close to cities or existing transmission lines will already be taken. The mediocre sites will be, too.
3. In most established electricity systems, the last 20% of fossil fuel power plants to be displaced will be made up of natural gas-fired peaking units — the most operationally flexible fossil-fuel generation sources, which will make them the last to go.

From here we can already see some of the biggest competitive fault lines, as well as the most important symbiotic relationships beginning to emerge…

1. Continuing to lean on wind & solar is an option, but it will require cooperation among at least three technologies beyond established wind turbines and photovoltaics. Two of those technologies are still mostly on the drawing board: floating offshore wind; and some form of ultra-cheap, ultra-long-duration storage technology. The third — high-power, long-distance transmission — is well-established technology, but has proven extremely difficult to deploy in the US, due in no small part to the social phenomenon known as “not-in-my-backyard-ism” (or NIMBY-ism).

Transmission & storage are classic ‘coopetitors’. In one sense, they‘re obviously competitive: transmission reduces the need for storage by blending wind & solar generation profiles across regions, which tends to decrease intermittency at an aggregate level; meanwhile, storage reduces the need for new transmission by increasing the utilization of existing lines. Yet, neither technology is a sufficient solution on its own; the combination will be necessary to allow us to continue tapping into more remote, intermittent renewables. Their relationship will be like a buddy comedy.

2. The aforementioned storage technology might be electrochemical (a battery), and it might be mechanical (e.g., pumped water, or compressed air), but hydrogen also remains a strong contender. Make it either “green” with electrolyzers powered by zero-carbon electricity; or make it “blue” by splintering a couple of H2's off of a methane molecule, then capturing & sequestering the resulting carbon. Next, store that hydrogen at very high pressure underground, or in enormous tanks. Then exchange it once again, on-demand, for electricity — using either a fuel cell or a gas turbine built to run on hydrogen.

One challenge for ‘green’ hydrogen as a storage medium is that converting electricity to hydrogen, and then back again to electricity, currently has an abysmal ‘round-trip’ efficiency of just 40–50%. (For sake of comparison, Lithium-ion batteries are ~90% round-trip efficient.) Another challenge for green hydrogen is capital utilization: to address the seasonal gaps inherent in the last 20%, green hydrogen entails two processes each working only part-time: electrolyzers running full-tilt for just a few months each year, and fuel cells or turbines operating for a few different months. In an excellent piece on hydrogen, Michael Liebreich from BNEF makes a compelling case that ‘blue’ hydrogen is better suited for the role of ‘seasonal grid balancer’ because “the capital-intensive stage, separating out and reinjecting the CO2, can be run at a very high capacity factor. The second stage, using the hydrogen, can then be intermittent.”

I don’t want to venture too far into the weeds of political economy; however, it’s important to note that blue hydrogen might also benefit from securing buy-in from key political interest groups — for example, the natural gas industry, and voters in politically crucial US states where natural gas is produced. (cough, cough Pennsylvania…) Blue hydrogen has its detractors too, on the ‘green’ (political) side of the sprectrum, but there’s no future for decarbonization without a little compromise.

3. Blue hydrogen is an inherently cooperative endeavor — a mashup of hydrogen & carbon capture, utilization, & sequestration (CCUS). Yet while blue hydrogen needs CCUS, CCUS doesn’t need hydrogen. It can instead be applied to the last 20% of power generation directly, either by retrofitting old natural gas plants, or building new ones, with mechanisms to capture the carbon in their exhaust — that’s the ‘CC’ step. The other two steps are distinct (and are not inherently baked into blue hydrogen production): carbon needs to be either bound into super-long-lived materials, like cement (‘U’), or pumped underground into permanent storage repositories (‘S’).

Capturing & sequestering carbon from natural gas power plants is already feasible with existing technology. If the cost were low enough, and the technology were sufficiently widely-applicable, CCS might just become the end-all, be-all of the clean energy transition. I personally might launch a lucrative new career as an instagram influencer.

Unfortunately, that’s not yet the case. Cost remains a major hurdle. Somewhat surprisingly, though, it’s not the CC step that’s the biggest sticking point. That’s already getting cheaper, and innovators appear to be making additional progress. Plus, there are a handful of high value ‘U’ companies which could indirectly propel CC further down the learning curve by driving additional demand for carbon.

The sticking point is another letter: ‘T’, for transportation. In fact, the implicit ‘T’ step between the ‘CC’ and ‘S’ is likely to be the most expensive step for many power plants, as laid out in a great piece by Jake Tauscher from G2PV. Take a look at the map below, which features geologic carbon storage potential in the US. Take note of the big swaths of the country — including most of the population centers along the East Coast — that would require a whole new transportation system to deliver captured carbon back from whence it came…

IV. Lastly, there are two more contenders for the final 20% of power generation: nuclear power, and geothermal power. Although these resources appear radically different at first, they’re functionally quite similar in many ways. Both resources can be tapped with established technology that’s already deployed at scale today. (As I write, tens of gigawatts of large nuclear reactors are currently under construction in China, Korea, and India.) But for both resources, conventional plants are difficult to site, permit, and build where we need them — in the case of nuclear, because of safety concerns; in the case of geothermal, because of geological constraints.

Fortunately, both resources are also being tackled by a handful of innovative companies aiming to push the envelope of where new plants can be cost-effectively built. Small, modular reactor proponents are envisioning a future of faster-to-deploy, more operationally-flexible, even more accident-proof nuclear plants. Meanwhile, “enhanced” drilling techniques could expand the range of geothermal development outside of places where heat rises naturally close to the earth’s surface.

If these companies are successful, their value proposition will be compelling: super power-dense sources of energy that can hypothetically be sited close to demand centers; and can be run 24/7. Hence, they’re technically capable of addressing wind & solar’s two critical weaknesses: remote space requirements & intermittency.

And yet, neither nuclear nor geothermal appear to be the ideal fit for the last 20%, due to a critical mismatch. Nuclear & geothermal plants are characterized by extremely high up-front capital costs, high fixed operational costs, and low variable costs. This cost profile means that maximizing utilization is crucial for delivering competitively priced energy. Such resources are best suited for a power system that needs a steady ‘baseload’ supply; but the last 20% is more likely to call for energy source that can deliver sporadic bursts of energy for only a few months each year. Hence, if either next-generation nuclear or enhanced geothermal technology take off, it will likely be hand-in-hand with some form of seasonal storage.

Decarbonizing the 80(ish)% of end uses that aren’t yet electrified

If I’ve convinced you to prepare for a period of intense coopetition in the electric power sector…well…you ain’t seen nothin’ yet.

In the power sector, it’s easy to imagine a symbiotic relationship among just a few technologies emerging as a dominant strategy. Perhaps an early partnership between ultra-long-duration storage and high-voltage transmission will head off major plans for investment in either hydrogen or carbon pipelines. On the other hand, a big early push for carbon infrastructure could give CCS the ability to satisfy most of the last 20% single-handedly.

On the demand-side of the energy market, it’s much harder to see this kind of winner-take-all scenario playing out. At first glance, there appear to be fewer coopetitors in the mix: just electrification, green hydrogen, blue hydrogen, and CCS. But the ways in which we use energy are simply too varied for a one-size-fits-all solution.

So, what generalities can we make about the 80%?

Delivery: Two of our options for the last 80%— electrification & green hydrogen — have big, obvious delivery problems. There’s no shortcut to massive investments in new infrastructure in order to get more electrons or hydrogen molecules to all of these new end-uses. Yet the other two options have a less obvious, reverse delivery problem. Blue hydrogen and direct CCS both aim to capture carbon from fuels that are already being delivered to end-users. But, as I described above, they’ll depend on infrastructure to carry that captured carbon to it’s final resting place, which will sometimes be very far away.

As far as I can ascertain today, there’s no universal winner among electric power lines, hydrogen pipelines, and carbon pipelines. The feasibility & cost of siting, building, and repurposing existing energy infrastructure depends on all kinds of project-specific factors, from the geographical to the political.

Transportation end uses: Point-source CCS is not an option for mobile end-uses, like cars, trucks, and airplanes (duh). Hence the competitive battle lines in this field will mostly be drawn between electricity and hydrogen. Hydrogen has some obvious advantages: It can be compressed to hold about four times as much energy in the same volume as a Lithium-ion battery, and can be pumped into vehicles at rates similar to gasoline or diesel. Meanwhile, both energy-density and charging speed have proven to be stubborn deficiencies for electric vehicles, as I outlined in a prior piece.

Yet sometimes the best solution is the first reasonably viable one, and today that’s electricity. Electricity is already the heir-apparent in the light duty vehicle segment, and it’s gaining ground in medium-duty vehicles too. Hydrogen appears unlikely to catch up. On the other hand, electricity is essentially a non-starter at the other end of the transport spectrum, in big container ships & intercontinental airplanes. In those segments, hydrogen or some derivative thereof is almost certainly the superior choice. In the middle of the transport spectrum — i.e. big trucks — we’re likely to see more hand-to-hand combat for market share, though perhaps we’ll also see some cooperation among batteries and hydrogen fuel cells.

There is one more option for transport. One more approach that might compete with both electricity & hydrogen for some of the big, long-haul use cases is CCS using “direct air capture”, or DAC. Rather than capturing carbon from an industrial flue in which carbon-dioxide is highly concentrated, DAC technology aims to siphon carbon out of ambient air, at about 410 parts per million (and rising). For airlines and shipping companies, the idea is that it might end up being cheaper to just keep burning jet fuel and bunker fuel, while paying a DAC provider to capture an equivalent amount of carbon somewhere else.

Do you have a yard? If you’ve ever tried to pick up handfuls of leaves in your yard before raking them into a big pile, you’ve already got an intuitive handle on the challenging economics of DAC. But, it’s worth keeping in mind regardless of its implications for air travel, because we’re probably going to need it when we inevitably overshoot our global carbon budget.

Space & water heating for buildings: Because of the magic of electric heat pumps, this is electricity’s sector to lose. That said, upgrading all of our electric infrastructure to accomodate a three-to-five-fold surge in demand during the coldest days of the year — when air-source heat pumps lose their magic touch— could prove extraodinarily expensive as a maximalist electrification strategy. Next-generation geothermal heat pumps could help in suburban & rural settings. Yet there may still be a path for hydrogen, especially in dense urban areas and in larger buildings that are harder to retrofit for fully electric heat. In these settings, we may find it cost-effective to add some large electrolyzers & hydrogen storage tanks — at either the building or district level —plus hydrogen boilers to serve as a form of distributed energy storage and backup heating source.

Industry: Here’s where coopetition will get especially chaotic. Most industrial plants already rely on a mix of energy inputs: fossil fuels for high-grade heat, electricity for specialized equipment, and so-called “feedstock energy”, which is needed first and foremost to supply molecules that end up in material products…but also simultaneously provides energy to catalyze various reactions.

In a decarbonized future, this potpouri approach is likely to persist. One plant might call for, say, hydrogen as a feedstock, electricity for robotic arms, and natural gas combustion with CCS to run a furnace. Some industries, like chemicals & cement — which can potentially serve as a sink for carbon-dioxide — might also become demand centers for carbon captured from other sources.

Quoting Michael Liebreich again: “What we’re going to see, therefore, is a fight, plant by plant”. The outcome of these mini-battles will be different for each individual facility, depending on site-specific energy & feedstock requirements, and site-specific costs for various types of electric power lines & pipelines. In most cases it’s going to be a scrum with multiple winners that end up leaning on each other to some degree after all…in other words, “coopetition”.

Iteration. Innovation. Coopetition.

Then Scrambling?

The 2010s will be remembered as a decade of super successful iteration for clean energy. The 2020s are shaping up to be a decade of tremendous innovation. Hopefully many of these innovations will be successfully commercialized, leading to a couple decades of intense coopetition in the 2030s and 2040s.

Beyond that? Probably several decades of what can only be described as “scrambling” — scrambling to close the gap that still exists between where our emissions are still heading, and where they need to go.

I didn’t talk much about the third big reason we still need more innovation for a successful energy transition, which is inertia. There aren’t many solutions to all of the fossil fuel plants under construction today, whose useful lives could stretch for many decades to come. What we don’t capture from these facilities on the front-end through point-source CCS retrofits, we’ll need to decarbonize on the back-end through much more expensive ‘direct air capture’, or mass reforestation, or perhaps geo-engineering. Like I said: scrambling.

So, here’s to more innovation today, to avoid scrambling tomorrow!

Iteration. Innovation. Coopetition. was originally published in Energy Impact Partners on Medium, where people are continuing the conversation by highlighting and responding to this story.

The upheavals of recent months — from the COVID-19 pandemic and Black Lives Matters protests, to the current wildfires out West — have put a renewed and intensive spotlight on corporate citizenship and responsibility for environmental, social and governance (ESG) action. Certainly, the need for ESG, and the related topic of impact investing, have been much discussed — but exactly what these terms mean and their role in private capital markets remain less well-defined for limited partners (LPs) and general partners (GPs). In particular, investors new to the world of ESG may feel besieged by all of the differing views they have to sift through, when what they’re searching for is a clear understanding of why they should care and how to take action.

When it comes to managing ESG signals in the world of private capital, most media coverage centers on a vague call to action while highlighting fund managers’ slow adoption and the barriers they face. Many of the articles out there do little to educate fund managers about fiduciary duty in the 21st century, or offer up strategies for how to institutionalize and capitalize on the benefits of a robust ESG program — regardless of whether your investment mandate targets market rate returns, or market rate returns +positive impact.

Energy Impact Partners (EIP) is at the vanguard of ESG program development and adoption, and its intersection with impact investing. We believe these topics warrant a deeper dive than a single blog entry, so we have parsed them into a four-part series intended to:

· Cut through the noise surrounding the role of ESG in private capital markets versus investment strategies focused on impact returns.

· Offer up some straight talk to fund managers and LPs who, like EIP at the start of our journey, are seeking education, instruction and best practices on ESG program adoption and integration.

· For impact investors, identify appropriate methods and metrics for environmental and social impact measurement and reporting.

Part 1 (below) explains what ESG means to the broader investment community and why ESG program adoption is not only critical to all modern analyses of investment risk and opportunity but has become a core responsibility for all fiduciaries.

Part 2 will address the unique value drivers and process efficiencies for launching internal and external ESG and impact initiatives. The key here is to re-envision traditional relationships between GPs and LPs as a collaborative forum for ESG policy development, investment due diligence, portfolio monitoring and impact measurement and reporting.

Part 3 will cover relevant policy frameworks, including the United Nations Principles for Responsible Investment (UN PRI) and guides for investment mapping to the Sustainable Development Goals (SDGs), which each can serve as scaffolding for performing ESG due diligence.

Part 4 will discuss best practices and strategies for impact measurement and reporting.

So onward with our first entry!

Part 1 — ESG is to Responsibility as Impact is to Strategy

Whether used as a noun, verb or adjective, ESG — environmental, social, and governance — represents evaluation factors that live outside the realm of legacy, traditional investment analysis. While no single process has been developed for how ESG themes and metrics should be integrated into modern investment analysis, the fact that they are essential criteria is no longer up for debate.

In our rising and fast-changing world, investors and their stakeholders understand that following sound ESG practices and management procedures provide vital risk and opportunity signals for what is simply responsible investing in the 21st century; not sustainable, not impact — just responsible.

I often like to think of ESG as a kind of chess game. The more you play and the better you understand strategies of risk and reward, the better equipped you are to protect your valuable pieces, while advancing on strategies for upside positioning. Conducting a legacy investment analysis that ignores ESG as a critical identifier of risk and opportunity is a bit like forgetting to think two steps ahead of your opponent. You could find yourself caught completely off guard when the inequality rook or the climate change bishop cuts across the board putting you in check. Of course, then your hand is forced to counter with a move that is reactive, rather than proactive, making it progressively harder to get back to an upside position, and before you know it — checkmate.

Consider a timely example: While many describe the economic, social and financial catastrophes stemming from the COVID-19 pandemic as a black swan event, some investors, researchers and politicians have been talking about pandemic risk for at least 15 years. Yet, governments continued to underfund research and development of vaccines and neglected to set in place comprehensive disaster recovery or emergency response plans, both decisions (or lack thereof) posing unfathomable material risks to society.

At the beginning of April, barely two months into the global pandemic, more than 3.9 billion people –over half of humanity — were confined to their homes; economies were shut down as business closures skyrocketed, and millions were, and still are, unemployed. At present, the Wall Street Journal reports that U.S. national debt is set to exceed the size of the economy next year for the first time since World War II.

We had so many warnings: Repeated close calls with bird flu, swine flu, SARS (severe acute respiratory syndrome) and MERS (Middle East respiratory syndrome) were seen largely as false alarms and pandemic risk, to the scale of threat we know today, was not perceived as imminent. This oversight sadly grew into a fast-spreading death sentence for millions, like a chess move where Black has a clear series of steps to force White first into check, and then check mate, but White neglects to make a move for downside protection.

While earned at a high social, economic and personal cost, the pandemic’s silver lining is that we have an opportunity to build back better. To me, this potential future is rooted in an enlightened, universal understanding of how the world works and cooperates with all living creatures and resources systems in it, coupled with an unwavering and all-encompassing appreciation of the risks and opportunities faced by governments, businesses, investors and citizens.

ESG — it’s not one size fits all

The evaluation of ESG risks and opportunities extends beyond the normal financial analysis investors have historically performed during due diligence screening. As alluded to above, ESG signals can result in very real, financially material, positive or negative outcomes that affect long-term value creation and risk-adjusted performance in an investment portfolio.

ESG integration and program development are often misinterpreted as undertakings that require organizations to adopt a set of one-size-fits-all principles and policies that must be implemented in a set order, effective immediately, and publicized for the world to see. First-time ESG adopters often fear that taking action prior to having a fully fleshed-out execution plan could expose them to shareholder scrutiny and greenwashing claims. Others see the media using the phrases “ESG,” “sustainable” and “impact” interchangeably, which adds to their confusion as to whether or not ESG is even a topic of relevance.

The reality is that implementing the high-quality, transparent, comprehensive, and accurate processes and procedures required for best-in-class ESG integration is a significant undertaking. It takes time — and the planning, staffing, enterprise-wide buy-in and go-to-market strategy all must be flexible to constantly change and adapt to emerging definitions of risk, opportunity, and materiality.

ESG should be thought of as a living, continually evolving governance platform, underpinned by a set of principles, procedures and policies, some standardized and others individualized, based on specific asset classes, geographies, target sectors and impact strategies. These principles are intended to serve as a framework for fiduciaries to ensure business is conducted in a responsible, accountable, and mindful manner, considering the full spectrum of existing, emerging and future material risks and opportunities related to ESG themes.

Impact, on the other hand, is not a responsibility shared by all investors. It is an elected investment strategy, largely focused on capturing opportunities related to environmental and social themes, through which investors seek double or sometimes triple mandates in capital allocation by targeting both positive impact and competitive financial returns.

A common misconception has emerged over the past five years with regards to impact investing, which is that these strategies implicitly accept concessionary returns in exchange for positive environmental or social outcomes. While this notion is certainly appropriate, and often expected, in philanthropic investing, today, concessionary return strategies among impact investors have become the exception, not the rule.

EIP is a great example of an investor seeking to maximize profitability and deliver risk-adjusted returns, while also being staunchly committed to ESG integration in due diligence, monitoring, and portfolio benchmarking in our exercise of ownership. Finally, as an impact investor, we have the added responsibility to report on both ESG performance, as well as the quantified, positive environmental outcomes enabled by our portfolio companies.

As traditional GP-LP environments tackle what’s next with ESG programs, our next blog entry will address how fund managers and limited partners can discover unique value drivers and process efficiencies in launching internal and external ESG/Impact initiatives. This can be accomplished by re-envisioning traditional GP/LP relationships as a collaborative platform for ESG policy development, investment due diligence, portfolio monitoring, and impact measurement and reporting.

What’s your next move?

ESG in Private Equity: What’s the End Game? was originally published in Energy Impact Partners on Medium, where people are continuing the conversation by highlighting and responding to this story.

Protection of critical infrastructure is at the heart of EIP’s mission to help innovators transform asset intensive industries. Over the last few years, infrastructure around the world — including power generation and transmission lines, communications networks, and the data centres that keep the essential services operating — have all experienced devastating cybersecurity attacks. Covid-19 has changed the type, but not the frequency of attacks.

We work closely with our partners to really understand these threats. And as we’ve spent more time with the executives responsible for the national infrastructure across North America, Europe and Asia, we’ve found there is a common concern about their ability to defend their organisation in the event of a breach.

They tell us that while they have plenty of ‘kit’ designed to keep them at the leading edge of cyber advancements, only ~25% of it is ever used in an organisation. Furthermore, no amount of kit can make up for operator error. Having the right tools is immensely important, but they are only as effective as the operators trained to use them.

That simple fact has brought us to the thesis behind our investment in RangeForce: The skill gap is the next frontier in cybersecurity. Every organisations’ resiliency is weakened because of the difficulty attracting leading talent and maintaining a current skill base for that talent.

The heart of any cybersecurity strategy — the security operations centre (SOC) — is expensive to operate, averaging $2.8 million annually. A third of this cost is employees. And, given that it can take a year to train a single SOC analyst and there are 1 to 1.5 million more open roles than there are eligible candidates, holding on to your key people is a necessity. Organizations simply cannot afford high rates of employee churn.

Keeping skills relevant and staff engaged is not easy. Traditional classroom-based courses can be overly theoretical, quickly outdated and expensive. In the Covid-era they are also no longer feasible, adding to the problem of how CISOs keep pace with the speed of change in the underlying technology and the increasing sophistication of hacker networks. The organisation learns the most during a real attack, but the costs can be devastating for them.

It was this problem that RangeForce, EIP’s latest investment, identified and set out to solve with realistic cyber-simulation tools that mimic a real attack.

From a learning standpoint, the next best thing to a real attack is a highly realistic, simulated environment. Active learning has been demonstrated time and again to better prepare the organisations when a real cyberattack happens. A hands-on, cyber range in the cloud that exposes the practitioner to the latest threats and vendor tools, while instilling muscle memory to mitigate them, enables a true human layer of security orchestration.

This is what RangeForce and its founder, Taavi Musk, have now achieved. I first met Taavi when he had just secured his seed financing from Paladin Capital. He had built his career developing complex cybersecurity simulation ranges for NATO in his native Estonia, the country with the population of 1.3 million inhabitants that has given us unicorns such as Skype, Transferwise and Bolt. And he was ready to conquer two continents with just 10 employees.

Until recently, cyber ranges were large, complex, bespoke environments used by those in critical industries such as the defence sector. With this in mind, Taavi developed his vision to bring the benefits of immersive, highly realistic simulations that mimic cyberattacks to the broader enterprise market.

When I joined EIP late last year, Taavi was one of the first people I contacted. Since our first meeting the company has experienced a 400% surge in demand and has won customers such as Barclays, Santander, Sodexho and Microsoft. At EIP, we believe in trying before buying. Taavi and his team presented to over one dozen CISOs from our investor base who collectively represent annual capex spending of $65bn+. We gained great insights through their interactions and, in that process, RangeForce won a few new customers.

RangeForce marks EIPs fifth investment in cybersecurity over the last three years.

The overlap between cybersecurity and e-learning remains an important investment theme which EIP will continue to mine. We’re really excited to be able to make this commitment to RangeForce and also to welcome Cisco as an investor and partner in RangeForce and Oliver Friedrichs, VP Products at Splunk to the Board.

Next Generation Cybersecurity Training: Why EIP Invested in RangeForce was originally published in Energy Impact Partners on Medium, where people are continuing the conversation by highlighting and responding to this story.

Why utilities? The energy transition is also a digital transition

For over a decade, the tech industry has been famous for its unofficial motto: “Move fast and break things” (This was actually the official motto of Facebook, in the early days).

The utility industry also has an unofficial motto, in truth — a mandate — which it has maintained for over a century: “Safe, reliable, and affordable.” In other words: “Move slowly, and don’t break anything.”

It’s time for these historically disparate industries to cross-pollinate worldviews. We will not linger on the tech industry’s issues in this article; suffice to say that tech might benefit from breaking… fewer things. Instead, we want to focus on how utilities can “move faster” — how they can borrow the best of what tech has to offer in order to become more agile, creative enterprises.

Utilities need to “move faster” in order to confront three critical challenges:

1) Our global civilization has about three decades to dramatically cut greenhouse gas emissions, but a lot of the heavy lifting must be done in the next ten years for there to be any hope. Utilities are the cornerstones of that effort.

2) Utilities run the electrical grid on which we are already highly dependent, and on which we’re set to become even more dependent as we address Challenge #1. The safe, reliable, affordable functioning of that grid is already facing an escalating array of threats — in both physical and cyber form — and utilities need to be sufficiently agile to take on those threats as they arise.

3) As a century-old industry that never gets any down-time to turn the lights off and retool, utilities are burdened by an especially high level of technical debt.

That third challenge is where we at Energy Impact Partners see an opportunity. Utilities have not historically been the top choice for tech startups looking to break into a new market vertical (maybe something about that “move slowly” motto…). But the urgency of the first two challenges means that utilities are on the cusp of becoming exactly the right vertical for new tech adoption. Our company would not exist if this major industry wasn’t ready to move faster, and when they do move, our partners alone represent over $65 billion in annual spend in North America and Europe.

The past decade(s) of utility technology strategy

Utilities face many of the same decisions as other enterprises when it comes to technology adoption. At a high-level, these decisions fall along three axes:

1) Suite or best-in-class? A “suite” approach to technology adoption means procuring as many related product functions as possible from the same vendor (or building them all in-house), as part of a cohesive solution set. At the other end of the spectrum, enterprises can pursue the absolute best possible product for each discrete bit of functionality, and somehow piece those products together into an integrated solution.

2) Horizontal or vertical tools? Horizontal solutions are designed to be agnostic to industry-specific systems, workflows, and use cases; they ought to work just as well out of the box for a bank as for a utility. Vertical solutions, on the other hand, are narrowly tailored to addressing industry-specific problems.

3) Build or buy? This one’s obvious. But there is one important note: Typically, enterprises won’t build horizontal solutions in-house. After all, if you’re going to build something yourself, you might as well build it exactly to spec!

Historically, utilities have leaned towards a suite procurement approach. When your mandate is “safe, reliable, and affordable,” buying an integrated suite of products from established vendors like Oracle, SAP, and GE tends to be the presumptive choice. Large, cohesive technology suites have historically been easier to set up and maintain than assemblages of point solutions, and they’re often perceived as the choice of least operational risk.

Moreover, the utility regulatory construct also tends to favor the suite procurement approach. For the most part, utilities are able to earn a rate of return on capital investment, but not on O&M expenditures; hence, the utility business model inherently favors paying up-front for a comprehensive suite, rather than paying the salaries of large teams of developers to continuously tighten the bolts on pieced-together or home-brewed systems.

On the question of horizontal versus vertical solutions, utilities have tended to lean vertical. When it comes to operational technology (OT) for monitoring and controlling electric power equipment, that’s often been the only option. For example, tools for identifying outages in the electric distribution system generally need to be built for purpose.

Build or buy? Utilities aren’t manufacturers. They don’t produce their own power generation equipment or transmission towers. Instead, utilities have long understood their role to be smart buyers, integrators, and operators of this type of equipment. As digital systems have increasingly come to underly physical energy infrastructure, utilities have mostly stuck to their “smart buyer/integrator/operator” core competency.

Emerging opportunities for enterprise software

As utilities have begun to transition from “move slowly and don’t break anything” to “move quickly and… we still can’t afford to break anything,” they’re being pulled in new strategic directions. From our perch at the intersection of the utility and tech markets, we see three emerging changes in utility tech roadmaps that presage new opportunities for enterprise software vendors.

First, utilities are experimenting with building some of their own digital point solutions. The impetus for these experiments was the rapid evolution and diffusion of machine learning techniques — and, to be frank — the extraordinary hype around artificial intelligence. For a time in the middle of the last decade, high-priced consultants and think-pieces alike espoused the view that “data was the new oil,” and that all enterprises needed to “become AI companies” in order to thrive.

For a time, it seemed as though any enterprise — utilities included — could become “manufacturers” of their own best-in-class machine-learning-based solutions. Unlike physical equipment, which patently requires huge economies of scale to produce cost-effectively, machine learning seemed like the sort of thing almost any mid-sized enterprise could produce on its own: just hire a few data scientists and coders, and start sniffing around the enterprise for use cases.

We’ve since learned that there are limits to the “build it in-house” approach to ML. It turns out that there are actually economies of scale in building ML solutions — specifically, in training algorithms on enormous datasets, incorporating expert feedback, and of course, integrating ML-based solutions into a plethora of established systems and workflows. Oftentimes, for use cases that are common across an industry, third-party vendors can assemble the highest quality solutions and, in effect, spread the cost of developing those solutions across scores of customers. That said, there are always going to be edge cases in which enterprises encounter problems so singular and specific to their own operations that those problems are better solved through in-house development.

Even for in-house analytics, though, there’s often still a need for third-party solutions to support in-house data scientists and business analysts. For example, data science “workbenches” or “platforms” are enterprise tools that take much of the hard-core coding out of the process, thereby putting the latest and greatest ML algorithms in the hands of subject matter experts — who probably have the statistical chops to interpret those models, but not to build them from scratch.

These tools bring us to the second new direction in which utilities are expanding their digital footprint: infrastructure. As utilities rethink their digital strategies, many are finding that their infrastructure needs are not so different from most other mid-sized enterprises. Next-generation solutions in analytics, storage, networking, security, and other “horizontal” enterprise software categories that have worked well in other verticals can be powerful force-multipliers for energy providers with a less well-established digital heritage. That said, we also occasionally encounter more vertical-specific infrastructure solutions — for example, integration platforms purpose-built to connect existing OT systems and applications.

One category that will be especially vital for energy infrastructure is security. Threats to industrial controls systems, networks, endpoints, cloud infrastructure, and IoT devices all represent opportunities for the startup ecosystem to address growing threats to our critical energy delivery systems. EIP’s unique position within this ecosystem allows us to build the connective tissue between innovative security companies and our limited partners.

Third, and perhaps most importantly, utilities are increasingly moving away from the suite approach to procurement. As discussed above, there are clear benefits to single-source procurement. But when it comes to specific applications — especially those rooted in ML — utilities are finding that point-solution vendors are able to build superior solutions, faster, while competing on cost with entrenched incumbents. The aforementioned economies of scale in building ML-based products appear to be captured much more easily by highly-focused vendors than those trying to manage increasingly unwieldy and far-ranging suites. Also, investment in digital infrastructure ought to enable utilities to add new point solutions with fewer integration headaches.

Adding “Clean” and “Agile” to “Safe, Reliable, and Affordable”

“Safe, reliable, and affordable” has worked well for over a century (we certainly don’t recommend replacing that with “move fast and break things”). But we know that energy infrastructure providers will be increasingly required to add “clean” and “agile” to their mantras. As they do, we believe that EIP represents a unique platform for bridging the gap between those strategic mandates — balancing the risk of innovation with the rewards of efficiency, productivity, and cost. Bridging that gap isn’t theoretical for us; it means doing the legwork of bringing together the most promising innovators across the technology landscape with the key decision makers who are building the tech foundation for the utility of the future. We’ve proven this model, investing in best-in-class point solutions for our industry, and we believe the time is right to do the same for enterprise infrastructure.

The Energy Transition Is Also a Digital Transition was originally published in Energy Impact Partners on Medium, where people are continuing the conversation by highlighting and responding to this story.

“Historically, we have forecast demand for power, and dispatched supply. In the future, those roles will reverse.”

I overheard this quote last summer at the market symposium for the Midcontinent Independent System Operator. It perfectly captures what I believe to be the most realistic vision for a decarbonized power system: lots of large-scale solar and wind generation, balanced by a mix of large-scale storage and myriad flexible, distributed energy resources (or ‘DERs’). After roughly a decade of technology evolution, large-scale wind and solar have now proven themselves ready to play their part in this vision. (I won’t go into detail about how cheap these renewable energy sources have become — for more on that topic see here, here, and here.) But the dispatchable demand side of the equation turns out to be a more complicated story.

Here’s the outline of that story:

· The pool of flexible DER capacity is growing fast, driven mostly by consumer choices.

· This capacity represents both an opportunity and a challenge. If managed well, the burgeoning fleet of DERs could be harnessed to serve as a critical pillar of support for grid stability — smoothing the pathway for very high levels of renewable energy. If managed poorly, however, certain DERs could instigate a surge in infrastructure costs, and potentially threaten reliability.

· Price signals are at the core of the DER management problem. The existing framework for consumer electricity pricing (called “retail” pricing) tends to under-incentivize the most flexible DERs, and threatens to create serious challenges for utility cost recovery and ratepayer fairness. Hence, getting retail prices right is essential.

· However, managing DERs with retail price signals alone turns out to be a very difficult task, given a variety of technical, administrative, regulatory, and business model hurdles.

· Therefore, utilities need to simultaneously begin restructuring their retail prices while investing in systems to monitor, optimize, and dispatch DERs directly. Just as importantly, they need to be able to explain what they’re doing to consumers, who will continue to be the critical decision-makers for the lion’s share of DERs.

My colleague Shayle recently wrote about the future from the perspective of my soon-to-arrive daughter. (She’s here now, and “Bug” is doing great!) In order to understand the nuances of each of the points outlined above, I’ll ask you to inhabit the perspective of a much older, more mature entity: the electric utility.

DERs from the utility perspective

Put yourself in the shoes of an electric utility serving a fast-growing metropolitan area. Housing developments are popping up seemingly overnight across your service territory. Business is churning; you’ve got an apparently endless stream of craft breweries setting up shop in previously lonely industrial parks. For the first time in more than a decade, you anticipate aggregate load surpassing your reserve margin target; according to your latest forecast, you have about three years before supply gets extremely tight. On a number of your distribution feeders, demand is threatening to exceed thermal limits even sooner. For example, in a more up-scale neighborhood in your service territory, one of your service crews reported seeing not one, not two, but three driveways exhibiting brand new electric vehicles. One of them was a Tesla!

Ten years ago, you would have known exactly how to respond to this surge in demand: either build or procure a new gas-fired power plant. You’d crunch the numbers to determine whether a CT or a CCGT was the better fit for your load profile. And you’d upgrade whatever distribution equipment needed upgrading to accommodate feeder-level demand spikes. Your regulators would have little reason to push back against adding all of this investment to your rate base.

But today, your regulator is pushing back. The staff of the public utilities commission have argued that you should evaluate alternatives to conventional generation and network upgrades — specifically, they say that you should consider a variety of “non-wires alternatives”, by which they mean DERs. In fact, they claim, many of these DERs are already sitting in your customers’ garages and living rooms, and they are just waiting to be tapped to support the grid.

In addition to this regulatory nudge, you also recognize the potential strategic value of adding more flexible DERs to your system. In particular, you’re keeping in mind your long-term resource plan, which includes a lot more large-scale renewables. ‘Utility-scale wind and solar’ is among the biggest categories of capex you anticipate in the next decade or two. But without more flexible resources to contain the cost of managing wind and solar intermittency, that vision may not materialize.

So…what should you do? How can you address the imminent constraints on your system while attending to your regulator’s guidance on DERs? How can you incentivize the most flexible resources to bolster the prospects for your renewable energy investment plans? What changes do you need to make to the way you plan & operate the grid? And what new technology will you need in order to keep the system working through those changes? (At Energy Impact Partners, we’re especially interested in the answer to that last question.) First, you need to answer a more basic question: What’s the state of DERs in your territory today?

The state of DERs

Market data suggests that about 15% of your customers have purchased smart thermostats from companies like ecobee (one of EIP’s portfolio companies) or Nest. In fact, you recently started granting customers a $100 rebate for both of those products. The rebate is part of an energy efficiency program, and does not require customers to set their thermostats any particular way, or give your system operators any direct control; but the results of several pilot studies have suggested that they will reduce aggregate consumption.

You know where about half of the thermostats in your territory are installed, because their purchase was tied to a rebate. But the rest could be anywhere.

In addition to thermostats, a tiny group of customers are starting to purchase home battery systems, which are often installed alongside rooftop solar panels. For example, that house with the Tesla has one. You can see the very beginning of this trend in interconnection requests, which spike a few months after every storm-related outage. However, you’re pretty sure that you’re not catching all of the residential battery additions, as customers sometimes neglect to file the proper paperwork. (Unlike solar panels, which are easy to see…)

A couple of large office buildings are also adding batteries; they’ve filed interconnection requests for 500 kW systems, which they plan to use to clip their peak demand, and provide near-instantaneous backup power to critical systems. You’ve done a little analysis: peak demand for these particular buildings is driven by the morning influx of office workers, which prompts elevators and HVAC units to ramp up simultaneously. Unfortunately, these building-specific peaks do not coincide with peak load on your overall system, which occurs in the mid-afternoon.

There’s a problem here, your engineers say. These building owners are expecting to save a significant amount of money on peak demand charges, but you aren’t anticipating a proportionate reduction in your own peak capacity needs. Intriguingly, though, the battery system project developer has reached out to you to discuss how their batteries could provide more value to the grid…and whether they could be paid more for doing so. One of our portfolio companies at EIP, Advanced Microgrid Solutions (or ‘AMS’), is a pioneer of this type of business model.

You still don’t see a lot of rooftop solar systems in your territory, but you are required by law to offer net energy metering. Somewhat ominously, a major national solar installer just opened up a distribution center in a wealthy suburb. I say “ominously”, because you’ve seen how the household solar story has played out in California.

You know that once the cost of rooftop solar dips significantly below the volumetric portion of the retail price, customer adoption will accelerate. Your residential customers pay a volumetric retail price of about 10 cents per kWh. Your average marginal cost of mid-day power generation (the cost that solar energy effectively displaces) is about 5 cents per kWh. If solar starts to grow, the 5 cent gap between these rates presents a clear problem for cost recovery and ratepayer fairness. In California, once the rooftop solar industry started to grow, it became very difficult (politically) to address this dilemma.

If you count demand response as a DER (which you should), then you already have a contractual relationship with a couple hundred megawatts of DERs today. Your operators have the ability to call on load reductions from a variety of commercial & industrial customers. “Call on” is a literal description of the process, as the way your operators dispatch these resources is by picking up the phone and calling or texting a building manager. But, to be honest, nobody has actually been called on in about five years. Remember, until recently you’ve had essentially no load growth, so you’ve had no reason to test your biggest customers’ patience.

If the preceding paragraphs describe your situation, you’re more or less a typical US utility. The chart below shows the history of DER growth in the country so far this decade. (For the purposes of the chart, I’m defining DERs as anything that produces power, or is a potentially flexible source of load, connected to the lower voltage distribution system — either behind or in front of customer meters.)

C&I demand response has hovered in the 20 GW range since the beginning of the decade. Smart thermostats, mostly deployed at the residential level, have quickly caught up — and now represent about the same amount of potentially flexible load. (“Potentially” is a key word here, as many smart thermostats are not currently configured to respond to utility signals, or even time-variant prices.)

Distributed solar has also grown to about 20 GW, but of course, solar is not a very flexible resource. It can only be made flexible in the downward direction (i.e. curtailed).

Household EV chargers are starting to be deployed in parallel with EV adoption. To be clear, the vast majority of EV charging is not at all flexible today, but it certainly qualifies as another potential source of flexibility. Non-household EV charging can also be made grid-responsive. (Our portfolio company Greenlots can make it so.) But that flexibility tends to be more difficult to realize, and it still barely registers on the above chart. Also negligible today are behind the meter storage and small-scale gas generators. (Backup diesel generators are not represented here, because they are typically restricted from operating outside of outage periods by emissions criteria and extremely high operating costs.)

Here’s a snapshot of all those flexbile DERs today, in 2018. I’ve removed solar (because of its limited flexibility), and added controllable electric hot water heaters.

Now the kicker: the reason that you, as a utility, should care about all of this stuff. Here’s a snapshot of how DER capacity could evolve over the next 5-ish years, given reasonable assumptions — some might even say conservative assumptions — about future adoption trends. Note that none of these trends are especially dependent on additional utility intervention; they’re mostly driven by various consumer whims and preferences.

For context, all of those DERs adds up to a flexible capacity bank of about 237 GW, or roughly a third of non-coincident peak US load. Now, to be clear, not all of that 237 GW is guaranteed to be grid-responsive, and it’s not all peak-coincident. But nonetheless, the magnitude of the resource potential is tremendous. It gets us about a third of the way towards realizing the vision of “dispatching load” that I laid out at the beginning of this article — that is, if it can be harnessed. If it can’t, some of these new loads also represent a significant liability.

Take EV charging. It’s safe to assume that residential EV charging load will be relatively concentrated — at least initially — in neighborhoods with certain demographics. So, the penetration of EVs on particular distribution feeders is expected to be several times higher than the penetration of EVs in society at large. Adding a single Level 2 household charging station (~10 kW) — if left unmanaged — is like adding 2–5 more houses-worth of peak evening load! The first piece of infrastructure to feel the impact will be older pole-mounted transformers serving a handful of homes. Just a few neighboring households all buying EVs could be enough to exceed the ratings of 25–50 kVA transformers. Those aren’t too expensive to replace, but because of the lack of visibility utilities have at that level on the grid, equipment could easily be overloaded before problem areas can be identified. Over the longer-term, you can foresee much bigger challenges once EV load begins to have a material impact at the feeder and substation level.

And then, of course, there is the combination of rooftop solar and household batteries. Given a typical residential rooftop, the duo can satisfy somewhere between 50–80% of a home’s energy needs without ever having to export energy back onto the grid. It’s technically feasible to achieve 100% grid independence and truly ‘cut the cord’ to the utility, but doing so would require a much larger solar array — bigger than most rooftops can hold — and a battery that’s sized for the darkest, cloudiest weeks of the year.

Set that kind of completist ‘grid defection’ aside; it’s a fairly unlikely scenario. Moreover, customers don’t need to go that far in order for ‘solar + storage’ to become problematic; surely an average annual load reduction of 50–80% would be more than enough to completely undermine your ability to recover the fixed costs of the grid. If a 50–80% solar + storage setup can be installed and financed for less than the volumetric retail price of electricity, then all of the ongoing battles over net energy metering will be rendered moot. At that point, the only way to prevent a downward spiral for utility cost recovery will be to fundamentally restructure retail electric pricing to more accurately reflect the true mix of fixed and variable costs.

“You could argue that our only job is to set the right prices, and then step out of the way”

This quote comes from a DER strategist from one of EIP’s utility partners. The argument is a natural response to the scenario described above, and it’s alluring because it acknowledges two core truths:

1. The utility’s existing rate structure is sending inefficient price signals for both the deployment and dispatch of DERs, especially at the residential level.

2. For the most part, utilities aren’t in control of DER adoption; consumers are. DERs are supported by a growing ecosystem of independent retailers, installers, DER aggregators, and other ‘intermediaries’ (now including Amazon, in partnership with EIP’s portfolio company Arcadia Power). Hence, you need to be prepared for a growing pool of DER capacity that won’t be under your direct control, or even necessarily visible to your operators.

The “right prices” argument stirs everyone’s inner economist. In theory, if you provide consumers, energy retailers, DER aggregators, and other intermediaries with exactly the right price signals — reflecting the true cost of service at every point on the grid, at every point in time — then the market should arrive at the best outcome. But in practice, a purely price-based approach to DER management runs into four fundamental challenges.

Challenge 1: Technical & administrative. Consider “the true cost of service at every point on the grid, at every point in time”. This seemingly innocuous phrase opens the door to a vortex of technical questions. For starters, it’s a mouthful — and the acronym TTCOSAEPOTGAEPIT is a bit much — so the industry has come up with a shorthand of sorts: LMP+D. Technically, LMP stands for “locational marginal price”, which in a wholesale market context is the marginal cost of generation required to serve load at any given transmission node. But in this context, the term is often used as a stand-in for all of the transmission-level, wholesale components of the cost of service — including generation capacity and ancillary services. In ISO regions, the market operator already calculates all of these cost components using security-constrained economic dispatch.

For a small number of your largest customers, LMP is not a new concept. Most utility tariffs for big commercial and industrial consumers simply pass through wholesale energy costs. Why not do the same for all of your customers? Exposing much smaller consumers (even households) to the real-time, marginal cost of generation and truly system-peak-coincident capacity charges will take a lot of technical work, but it’s certainly feasible. However, doing so will entail a significant investment in customer-facing data portals, customer usage analytics, and billing systems — new costs that will need to be justified to regulators.

Moreover, there are legitimate economic disagreements about the most efficient way to translate the cost of grid infrastructure into consumer-facing prices. Here’s just one example: Most of the cost of the grid is, in economics jargon, a “sunk cost”. It’s already bought and paid for. One could argue that the ‘sunk’ nature of these costs should be reflected in consumer prices, and therefore, they should be embedded in an entirely fixed fee that every customer pays, simply for a grid connection. But, that approach would not send consumers any kind of forward-looking price signal that reflects the cost of future investments in T&D capacity.

And that’s just the ‘LMP’ part of the equation. The ‘D’ component is an order of magnitude more complex from a technical standpoint. The graphic below highlights just a small sample of the questions that swirl around ‘D’.

Many of these questions require sophisticated technical and economic analysis in order to answer. There is no consensus on methodology. Hence, the administrative and implementation costs involved may be simply too high to justify the potential savings. Ultimately, this is probably the strongest objection to adding a location-based pricing component to every node on the distribution system.

Fortunately, we at EIP believe that software tools can make the process of identifying ‘D’ more feasible at a lower cost. A leader in this space is our portfolio company Opus One Solutions, which can enable feeder-level distribution system modeling and DER-oriented scenario analysis. Opus One can help you make progress towards accounting for ‘D’ in various ways — for example, through competitive RFPs in the highest-value locations, or DER-specific tariffs — even if you deem it too costly to implement distinct distribution-level prices for every feeder.

Opus One is also at the forefront of taking the LMP+D approach to its logical extreme: a distribution-level marketplace. As a utility operating such a marketplace, you might consider yourself a “distribution system operator” (or ‘DSO’), and the marketplace you facilitate could be labeled a platform for “transactive energy”. Underlying these nebulous concepts, the core idea is that loads and DERs can be more than just price takers for LMP or D. They can be active market participants, bidding just like large generators. This concept certainly benefits from a purity of form — it’s the hypothetical end-state for the “set the right price” theory of DER management — but it is still very much in the demonstration stage of implementation. And hoo-boy, does it struggle with technical and administrative challenges.

Challenge 2: Regulatory pushback. Public utility commissions are staffed by economists, so you might imagine that an entirely price-based system would be attractive to regulators — especially those with an ideological bent towards market-based solutions. However, it turns out that making just about any change to retail pricing is politically…fraught. And anything that is politically fraught, is also fraught for public utility commissioners. Here is just the short-list of groups with political power that might publicly oppose a move towards LMP+D:

1. Distributed solar installers, who prefer a fully bundled, volumetric price. (Fortunately, many of the same companies installing distributed solar are now also installing other DERs, which can benefit from more time-variant pricing; so, objections from this group are becoming more nuanced.)

2. Energy efficiency advocates, who also tend to prefer a fully bundled volumetric price.

3. Consumer advocates, who tend to oppose any change that might confuse consumers or increase bills.

4. Low-income consumer advocates, who oppose changes such as fixed charges that disproportionately impact low-usage customers.

5. Rural customers at the end of long distribution lines, for whom a location-based price component is likely to be relatively high.

6. Inner-city customers in T&D constrained areas, for whom a location-based price component is also likely to be relatively high.

These last two constituencies pose a serious philosophical challenge for regulators. Adding a ‘D’ component to prices would contradict one of the original social purposes of the “public utility”: socializing the costs of an essential service among all consumers. “Socialism” may be a dirty word in political debates across much of the country, but utility commissioners in every state continue to employ the rate base as a tool to socialize the costs of the grid evenly among all consumers, even those who cost a lot more to serve.

Challenge 3: How do you make money? Insomuch as DERs reduce the need for conventional grid infrastructure, they will be viewed by a large segment of utility leaders as an affront to the way that utilities have always, historically, made money. For decades, utilities have been compelled by varying degrees to seek competitive offers for power generation. But T&D has been a relative safe haven for capital investment. Every distribution system need that is deferred or avoided because of DERs represents a utility investment opportunity that might slip away.

At the extreme end of the “set the right prices” spectrum — the DSO model — it’s even less clear how to make a profit. After all, the closest parallel — the ISOs — are non-profit entities! In New York, the Public Service Commission has embarked on a proceeding called “Reforming the Energy Vision”, or REV, that is trying to identify a solution to this problem. But the REV initiative faces more than it’s fair share of healthy skepticism from every corner of the industry.

Challenge 4: The customer response. Let’s say that you were approved by regulators today to charge customers the real-time LMP for the energy portion of their bill. You come up with a reasonable methodology for baking in capacity and ancillary service costs. Maybe you even add a ‘D’ component. You figure out how to make this data available to consumers, and build an API so that any DER intermediary they choose can access the price in near-real time.

Could you really count on this strategy to induce a reaction from your residential customers…or even your mid-sized commercial customers? Will the fast food franchise manager check his or her phone, see that the price of electricity has reached $10/kWh, recognize what that means, and turn off the fryolators? (“Sorry patrons, no more French fries today…the price of electricity is too high!”)

If you were to open up the demand side of a capacity auction to actual bidding — a true mirror of the supply side of the auction — how many of your customers would have any idea what to bid to reserve varying levels of capacity? And, in a pinch, how many could limit themselves to the capacity they’d reserved? If they overshot their allocation, would you cut off their power? (Could you cut off just their power, alone?) Or would you charge them a steep penalty fee?

Taking a step back: Do your customers actually want more sophisticated, time-and-location-variant energy pricing? At this point, it’s essentially dogma in the utility industry that customers avoid spending more than a few minutes a year thinking about energy. Anecdotally, one of EIP’s utility partners has attracted about a quarter of its customers onto an “all you can eat” energy plan with a completely flat monthly bill — exactly the opposite of high-resolution LMP+D!

I’m confident that these objections can gradually, eventually be overcome. Given a few years of more sophisticated pricing, the market for price-responsive DERs and third-party intermediaries will blossom and bear fruit. Customers won’t need to ponder and respond on their own to hourly energy prices, because an energy service provider and/or a building full of smart devices will respond on their behalf. For example, our portfolio company ecobee has developed algorithms to optimize HVAC utilization based on customer comfort settings and an hourly price series.

Yet, even as the demand side of the market develops, utilities may still face a dilemma: In real time, they are required to guarantee reliable service for every customer. When reliability is on the line, betting on prices to elicit a response from customers will be perceived as a risk — especially by control room operators who are accustomed to exercising direct dispatch over critical resources. Sure, you can set an extremely high price during peak hours, cross your fingers, and hope that enough customers will be enticed to reduce their load. But even as thousands of additional smart devices and energy managers enter the market, a subset of longtime utility operators will balk at yielding control in favor of a purely price-based approach.

Thinking beyond “setting the right price”

None of the challenges described above are insurmountable, but they all point to a fundamental truth: in the near-term, you aren’t going to be able to be able to manage DERs simply by “setting the right price”. Accelerating the transition to more cost-reflective prices is a necessary step, but it’s not a sufficient one.

Fortunately, a gradual shift to truly cost-reflective pricing can be elegantly paired with a more direct approach to DER management. After all, if you need to dramatically change the way you price your product, what better way to ease the transition for customers than by helping them adopt and utilize DERs to react to the new pricing regime?

Imagine rolling out a new tariff with a much more time-variant, peak-oriented price structure. Perhaps you could even include a location-specific demand charge for customers in especially distribution-constrained areas.

This sounds like exactly the sort of pricing that would raise consumer hackles and prompt Challenge #2 from regulators. But, imagine if you paired this new tariff with another offering: a managed service for 10–20 common DERs — thermostats, batteries, EV chargers, hot water controls, etc. — whatever your customers choose. You’ll provide customers with a simple process to connect their DERs to a utility management platform, and an interface to set their preferences for comfort and convenience versus cost savings (dramatically simplified, of course: think High, Medium, and Low savings settings).

You’ll also provide customers with a range of estimates for their total average annual bill depending on which settings they choose. Many customers will find that they can save money with even a modest level of DER management and practically negligible impact on comfort.

Even more importantly for utility shareholders: There are a variety of ways to make money from this type of DER management model. (Of course, the options available to you will be highly dependent on your regulatory regime.)

1. Rate-base the DERMS software. At this point, we think utilities ought to consider this to be table-stakes. There is a strong case to be made to regulators that DERMS should be treated just like your other grid management systems, such as DMS or EMS, that support reliability and reduce total system cost.

2. Sell the DERs. Rather than waiting for your customers to buy DERs from other suppliers, why not capture some of that value yourself? You can either try to sell DERs directly and earn a margin, or refer customers to third-party retailers & installers, and earn a referral fee.

3. Finance DERs on the customer bill. If your regulator will allow it, you can offer customers some type of no-money-down financing, paid for via a line item on their electricity bill. Customers may be attracted to this option if you can show that the energy cost savings from DER participation are likely to exceed the new line on their bill. This approach has been described as the “Million Rate Base Model” by the firm Twenty-First Century Utilities.

4. Offer customers a flat bill, then use DERs to lower the cost to serve. This is a completely different approach, in which cost-reflective pricing is used to assess the cost to serve a customer, but not used to send price signals to that customer. Instead, the customer pays you a flat monthly bill equal to their baseline cost of service (based on historical load data). Simultaneously, you offer the customer a number of managed DER packages with which you can lower their cost of service moving forward.

The difference between the baseline and actual cost to serve becomes value that’s available to be captured. Surely, some of that value will need to be shared with the customer, but there is a strong argument to be made to regulators that you should be allowed to keep some value for yourself. Regulators know that a utility — properly incentivized — will seek out opportunities to reduce costs much better than most customers will do for themselves; as customers are notoriously bad at making cost-effective investments in energy optimization.

This model does face several significant challenges; notably, it’s not totally clear how to set the baseline bill, or how often the baseline should be re-set. Also, this model is likely to encounter resistance from energy efficiency advocates and third-party DER aggregators. In fact, one strong argument against approving this model is that third-parties should be able to compete to offer customers the same service; and they can only do so as long as customers are directly exposed to truly cost-reflective prices.

5. Engage in some regulatory entrepreneurship. New DERs mean new ways to achieve energy efficiency and other demand-side flexibility goals for politicians and regulators. Hence, the proliferation of DERs presents a new opportunity to engage with regulators about various forms of performance-based regulation. That topic is much too big for this article to explore in detail. Suffice to say, it’s potentially compatible with many of the strategies outlined above.

From theory to practice: EIP’s investments

What technology do you need to make this vision a reality? EIP has been investing in a number of building blocks at every link in the DER management value chain. The way I see it, that chain looks like this:

1. Price setting & billing: You need an engine to determine the cost of service, and translate that cost into retail prices. You’ll need to do this at least for the wholesale (LMP) portion of your cost structure, and potentially for the ‘D’ portion as well. And of course, you’ll need a back-office billing system capable of handling much more complicated, time and location variant rates.

2. Customer analytics: The best price structure in the world will be meaningless absent high-resolution visibility of customer load. This is clearly necessary for billing purposes, but it’s also needed for analyzing how each customer’s individual bill would be affected by the deployment and optimization of various DERs.

3. Customer communication (and marketing): It’s a rare customer who is going to pay close attention to the nuances of electricity pricing, or spend much time thinking about how to reduce their energy costs. For the bulk of consumers to adopt DERs and enable them to be managed effectively, a significant amount of translation and simplification will be required.

4. DER-level optimization: Once the right prices are in place, DERs can get to work. Many DERs will have built-in optimization software that is designed to satisfy customer preferences at the lowest cost. Others will be optimized by aggregators across a fleet. In any case, DERs will need two interfaces, one for users to input their preferences, and one to receive price and dispatch signals from the utility. In this way, many DERs themselves will probably play a key role in customer communication (the prior link in the value chain), in addition to optimization.

5. Utility DERMS: In order for utilities to move beyond pricing and adopt any of the business models described above, they will need software and communications solutions that connect with DERs, monitor their statuses, translate their individual capabilities into a common language (kW, kWh, VAR, etc.), aggregate them into relevant groups for grid management functions, and then dispatch them optimally on behalf of customers.

Here’s that value chain visualized, overlaid with the investments EIP has made.

Returning to the quote I highlighted at the beginning of this article, we are still in the early days of “dispatching demand” for power. But I’m confident that the time is now for utilities to begin preparing for a DER-rich future. We think we’re making the right investments to help the industry do just that.

What To Do About DERs was originally published in Energy Impact Partners on Medium, where people are continuing the conversation by highlighting and responding to this story.