What To Do About DERs
By Andy Lubershane, Senior Director of Research, Energy Impact Partners
“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.
