Monopolies in Competition

March 29, 2016
T&D World's IdeaXchange experts discuss how utilities should respond to the competitive threats embedded in some DER technologies and take advantage of the customer engagement opportunities also present there.

In a pivotal scene from the epic World War II movie “Saving Private Ryan,” Captain Miller (played by Tom Hanks) takes Sergeant Horvath aside to discuss an unexpected turn of events. Private Ryan (played by Matt Damon), the young solider who Miller has been ordered to find and bring home, has just refused to go home, saying he wants to stay with his own unit, which has been ordered to defend a bridge at all cost.

In commenting on the dilemma that has arisen between his orders and Ryan’s loyalty and sense of duty, Miller says, “Sergeant, we have crossed some strange boundary here. The world has taken a turn for the surreal.”

When I contemplate the current state of electric utility regulation in the U.S., that world appears to have taken a turn for the surreal. The original regulatory compact was established to provide society a valuable public service while protecting customers from possible monopoly excess and still assuring utilities would receive a return large enough to attract capital investment. That was then, but now, the same utilities that received protection from competition in exchange for regulation are seeing increasing competition — often from their customers.

In some ways, the situation is very familiar. Today new technologies and changes in customer preferences that allow new entrants to grab market share from well-entrenched incumbents seems to be the norm in multiple industries. Yet in the case of regulated utilities, the well-entrenched incumbents (the utilities) are well entrenched by design and are often prohibited from engaging in competitive activities. Where things really take a surreal turn is when one remembers that these particular incumbents are often compelled by their regulators to fund the very technologies that result in the erosion of their market share.

In the electric utility industry, this threat is largely embodied in the growth of distributed energy resources (DERs). Many of the technologies in the broad DER category represent direct competitive threats for utilities and how DERs are handled varies from one regulatory jurisdiction to another.

New York's Reforming the Energy Vision (REV) appears to be one of the most aggressive efforts. In that jurisdiction, the aim is to create a viable DER marketplace with distribution utilities serving as market-enabling platforms. Yet, in other places, utilities are becoming direct providers of various customer-sided DER products/services. In that last group, CPS Energy in San Antonio is clearly a leader.

Here’s how Raiford Smith, vice president of corporate development and planning, described CPS Energy’s DER approach:

With the rise of distributed energy resources, utilities are faced with a critical question, how to respond? The solution is not always self-evident as it is rooted in simultaneously solving issues in three different areas: the business/regulatory model, customer engagement around new products and services, and enhancing utility assets and operations to accommodate DERs.

At CPS Energy, we’re tackling the problem with a three-part strategy.

First, install a digital, densely-sensored infrastructure to generate the data and control needed for new capabilities. This includes investments in synchrophasors, advanced metering infrastructure, weather sensors and distribution automation.

Second, make data easy to use and systems interoperable at the network’s edge so analytics can go anywhere and new capabilities can be added easily. At our company, this includes pilot deployments of the OpenFMB technology to federate data using a common semantic and protocol using a publish-and-subscribe message bus, linking a wide variety of field assets together logically.

Finally, using our new data, systems, and capabilities to deploy advanced analytics, launch new products, and enable better customer engagement. At CPS Energy, our SolarHost and Roofless Solar programs are at the forefront of these capabilities. Similarly, we’ve invested in new, stochastic and geospatial planning tools to better understand the value and distribution impacts from DER’s. We’re also investing in a DERM’s tool to manage a host of DERs, including demand response and smart inverters. Together, we believe this strategy will position CPS Energy to better understand and optimize these assets as customers adopt DERs in greater numbers.

Some may agree that the DER environment has a surreal element to it but I am sure most would agree that utilities are entering far more complex territory.

So intrepid Xperts, here is your question:

How should utilities respond to the competitive threats embedded in some DER technologies and take advantage of the customer engagement opportunities also present there?


See the threats as opportunities (easy for me to state). I have made a number of posts on this subject, so let me cite some relevant points without repeating the details.

DERs are here to stay and will grow significantly. It would be wise for utilities to explore options within their state regulatory paradigms (and follow those states that may be more progressive on the subject). Once the boundaries are known, utilities should explore opportunities within those boundaries (or seek regulatory or legislative changes to those boundaries if desired).

Customers who wish to choose DERs may be encouraged by offerings that help them reduce the initial cash outlay and O&M complexity in favor of (set it and forget it) lease payments or rents with the benefits of energy savings on the bill.

Large building owners, including those who are not thinking about DERs, may be encouraged by offerings to rent their rooftops or other space for a utility (or third party) with a creative business model to install DERs.

Utilities (or third parties) may benefit from aggregating DERs (perhaps combined with demand levers) in a grid marketplace to take advantage of ancillary services to improve the economics of the possible business models. Aggregation in a robust grid marketplace requires robust transmission to reach the DER assets.

DERs with an energy storage component enhance significantly business model options and the economics. This point is a game changer.

Utilities can benefit operationally in aggregate and at the distribution feeder level with real-time data (and perhaps control) at all DER interconnection points.

Admittedly, this is a complex subject that cannot be dismissed to a few bullet points, but it would be wise for utilities to see DERs as opportunity rather than threat. The least they should do is follow the activity, paying particular attention to states leading in this area, such as New York and California.


I agree with your “bullet points”; however, even more important than a list of responses is the need for a complete change of attitude in our industry regarding the “threat” of DER “competition.” Do that and many more bullet points will appear.

First of all, who/what is being threatened? For IOUs, the investors may lose some low-risk returns on utility capital investment. That could impact the ability of IOUs to raise capital and require regulators to restructure the rate-making process so that utility bonds and stocks remain attractive. But that’s what regulators do quite well. For municipal utilities, DERs are a godsend of opportunities to offer diverse services and increase revenue. Just witness what you (Baker) did at Austin!

And for utility employees, DERs offer a new sandbox of technologies to apply and customize. Only the most intransigent engineers would resist the opportunity to contribute. Also, I don’t see any layoffs coming. If anything, we’ll be short on manpower as about half of the existing workforce retires this decade, leaving room to bring in disciplines needed to support DER integration (and maybe installation and service).

The only threat to the customer may be the perceived overcharges for utility standby services for residential solar. If we don't deal with that, we'll eventually have a wave of customers going off-grid. 

Competition? I’m not sure how that applies in a protected monopoly. Are we competing for sales? Other? Or just protecting a century-old paradigm?

When automobiles began appearing in the late 1800s, some carriage body manufacturers refused to change their business model and went broke; others began adapting their carriage design to accommodate an engine and steering. Those companies, for the most part, thrived.

For over 100 years, our industry has been a natural monopoly, protected by regulation. Other industries have taken business advantage and adapted and adopted new technologies and innovation.

Now it’s our turn. We have regulatory and customer environments that are accommodating and encouraging us to join (not compete) with the DER movement. Let's do it.


First, DER is only a threat to the generation portion of the business. In 2015, DER represented a US$2 billion reduction on purchased energy by utilities, according to EIA. Not a small decline, but not earthshaking either. Distribution and transmission operators today have an opportunity to shape the future of their grids, if they consider DER as an asset and the regulatory environment allows them to do so.

DER is made up of several components: distributed generation (DG), demand-side management (DSM) and distributed storage (DS). DSM can be broken down further into energy efficiency (EE) and demand response (DR). Most people use DER today to talk only about DG and specifically photovoltaics (solar).

Most people forget the other pieces. DS mostly because today it is rare and based on Telsa’s announcements probably will remain rare for a while with Tesla dropping the lower cost of its two Powerwalls for economic reasons.

EE has long been supported by the regulatory environment in most locations, and utilities have programs that support EE — it has and will remain a friend of the industry. It should be focused and pushed a lot harder; light bulb programs are easy, but hardly scratch the surface of what can and should be done, especially in low-income housing.

DR tends to be air-conditioning interrupters, again, because it is easy, not the comprehensive types of programs Florida Power & Light has struggled and succeeded to develop over the last 30 years. Again, there is a lot more that can be done with utility-managed DR programs. Transactive Energy programs run by independent aggregators will fill this gap if the utility industry does not. The aggregators will be able to bid directly into the ISO/wholesale market; the California ISO has already taken the first steps with filings and new products.

Now let’s talk about solar, the part that everyone wants to focus on for DER. First, the regulations are unjust and discriminatory! Yes, let me say that again so the regulatory staff and commissions don’t miss this point: Solar programs in most states are unjust and discriminatory. They are probably the most socially backward of any regulations that commissions have created.

Solar currently, almost everywhere, is subject to first come, first served, meaning people who can afford to install solar or have the financial scores to lease solar. This is the crux of the discrimination. If you don’t own a home (or property), and you don’t have cash or great credit scores, you are locked out of the solar programs. This is a huge problem for utilities, because it goes directly against the engineering problems that planners have to deal with — phase imbalance, local voltage problems and much lower hosting capacity — than if solar was designed in carefully and truly distributed. Today we put in solar the same way a French cook in Paris made biscuits and gravy. They cut the sausage into 2-inch pieces and dropped it into gravy, there were four pieces in my gravy, not the Southern style of small pieces of sausage in the gravy. We do the same with solar, larger arrays, mostly on single phases, instead of uniformly installed. This has a HUGE impact on hosting capacity.

With the current regulations and the random way solar is being installed, the limit (without engineering strategies) is about 8% of the lowest load on a circuit annually during daylight hours. Take 8% and triple it (assume all the solar ends up on one phase), and you are potentially out of the dead band (24% imbalance 8% times 3 because all 3 phases worth of that 8% ends up on one phase). This is way below the engineering hosting capacity of most circuits.

First come, first served also locks out late movers, renters, low-income residents and commercial customers who lease office and factory space, making the area less attractive to new residents and lowering property values for those locations that don’t have solar.

Utilities need to work with regulators to limit the size of a residential array so that more solar can be installed. They need regulations that allow them to lease roof space in under-served locations where the demographics do not support solar leasing programs. They need to work with regulators on fair tariffs that do not add to the cost of electricity for the people who do not have and can’t get solar.

Overall, the regulators need to wake up to the fact that the current regulations actually reduce the total amount of solar that can and will be installed, instead of encouraging it. Yes, solar leasing companies will scream, and they are well-organized and well-funded lobby, as the lawsuit that TASC filed in Nevada shows.

We as an industry can either work to make ALL of DER work for all of our customers, or watch as we have to deal with the high-income homeowners and well-funded businesses leave the grid, and the people who can’t afford to, see electricity prices rise because of the cost to maintain the grid.

Ideally, for the 130 million residences in the U.S., there will be 1 kW of solar on every roof someday, enough to lower bills significantly and to add greatly to the overall use of solar. OBTW, if we do it this way, we add 130 GW of residential rooftop solar capacity — far more than we have today and far more than the current regulations will allow from an engineering hosting capacity of distribution. Similar programs could be adopted for commercial and industrial customers. In 2015, the industry, including utility-scale solar, installed just over 7GW.


There’s a story of a private road in the western North Dakota badlands. The landowner has the ability to say who uses the road, when and under what terms, i.e. pay to access. Accessing this road can save well over 40 miles when traversing the Badlands — if the landowner allows it. The same situation holds true of many rural roads in Wyoming; they cross private land and therefore access is controlled by the landowner, even when those roads lead to public lands. Traveling these roads can be readily done as the roads are engineered and will accommodate most any vehicle. Gaining access to these roads involves a business aspect.

When considering the DER movement, and how utilities should respond to it, there are really two aspects that should be considered separate from one another: the technical (engineering) aspects and the business aspects.

Engineers by virtue of their intrinsic interest in exciting new technology, will likely be quite interested in the DER technology being developed for harnessing renewable energy and converting it to electric power. Integrating that same energy into an electric network grid will create new opportunities for design, ingenuity and success. While some may argue that harnessing renewable power is far from a ‘new adventure’ (albeit there are many remnants of these systems from past generations - Aermotor water windmills, Jacobs Wind Generators, et. al.), the improvements in today’s DER technology surely have engineers excited.

The electric utility that I’m employed by found this excitement well over 30 years ago when they integrated standby diesel engine generators into its electric load management program, far ahead of the DSM technology curve at the time by any measure. With the ability to shed over 50% of our system peak demand in less than 20 minutes during peak load times, the integration of other generation sources into the mix was an eclectic and exciting adventure by any measure from the engineering perspective. Today, our utility has almost 100 MW of member-owned diesel standby generation successfully and safely interconnected to our grid operation. It worked then and still does today — remarkably well!

This program also saved our member-owners hundreds of thousands of dollars, with the return on their investment in the diesel standby systems often being realized in less than three years for most projects, through a time-of-use rate program.

Therein lies the business aspect. Engineering these systems into the electric grid wasn’t contingent on whether or not the system was economical to install or operate. The engineering aspect was based on safety and operability so as to insure that grid integrity and safe operation wasn’t compromised under any circumstances.

Today’s DER movement consistently talks about the economics of the technology, with virtually every program stating the systems are only feasible under certain conditions, which usually include large tax incentives on the financial investment and lucrative energy purchase buy-backs, i.e., net metering. Without those financial fortunes, the industry flails and flounders (i.e., California vs. Nevada). And repeatedly, the movement looks to the electric utility industry to provide some/all of the financial incentives they so need in order to survive, let alone flourish.

The question remains: Is it the responsibility of the electric utility industry to insure the financial feasibility of these systems so as to assure their livelihood? The question to this panel is valid: How should the electric utility industry view the DER movement? The answer probably depends on which aspect is being considered, technical or financial? It really involves both, but with separate consideration to both.

Going back to the road analogy, without access to the grid, the value of these systems diminishes from two aspects: their inability to store excess energy on-site and their inability to transfer excess energy to points elsewhere. This equity argument of toll-free access to the grid, or toll-free use of the grid as a storage battery falls on deaf ears within the movement; it’s simply not their concern as the ‘grid is always there.’ Another argument that’s often used is the consumers have already paid for the grid, thus the utility should not be able to charge for its use by others.

Many state regulators are now coming to realize the Pandora’s box that was opened by allowing the initial entry of net metering by the DER movement. A recent news report cited 24 of 40 states now reconsidering the net metering issue. The DER movements clearly states without net metering (i.e., free energy storage), their efforts are all but in vain. The utilities have made the case that free access, or free storage, is simply not sustainable. The DER movement occasionally states that renewable generation will sustain or improve utility operations, not hamper them, by providing needed capacity that will alleviate the need for costly system upgrades. Thus the interconnection should be welcomed, as in possibly quid-pro-quo fashion, or better yet, paying a retail rate for wholesale energy.

DER may well provide many benefits to a utility system as demonstrated by the experiences of my employer. But those benefits need to be quantified and documented so as to be properly reflected into a rate base, which may be based on capacity, energy, or both. The famed phrase ‘time-of-use’ suddenly becomes part of the equation, a term seldom welcomed by many residential consumers or consumer groups, let alone DER operators who often depend on utility resources most during peak utility load times; our system often peaks in early evening when solar is waning or ‘done for the day.’

Utilities deal with the engineering and business aspect of their operations every day, and sometimes they do get entwined when investments and alternatives are considered. Just as the utility must evaluate the business case of their investments, so too should a DER operator using the market pricing and cost to enter the market. Forcing or expecting the electric utility industry to simply accept the DER movement into the grid with enthusiasm and elation, not to mention without any question of the business aspect, is simply dumbfounding by any measure.

The business case of the DER movement can be quantified through simple economics using the results of system engineering and planning. This is the exciting challenge of incorporating the movement into the present-day grid operation, utilizing the resources so as to enhance the grid performance and integrity and determining the value of that integration. It should and must be done in an orderly manner with attention to detail. Forcing integration without consideration for the business and engineering aspect would be foolhardy and jeopardize an engineering marvel that has served our nation arguably quite well throughout history.


I can only give a European perspective. First, define “utility”; this has different meanings depending on geographic location. In Europe, generation, transmission, distribution and retail is supposed to be offered by separated entities on the basis of encouraging something called "competition" in the generation area and at the retail level. To some extent, this has succeeded, although there are great variations between different EU member states. Moving to networks disputes center around cajoling TSOs/DNOs to give network access to DER.

 I don't need to say much about the large generation/retail utilities, they are slowly dying due to a combination of incompetence/institutionalized ways of thinking. I was listening to one of their chief economists yesterday. It was quite funny given that he whined on about having enough money to invest in new generation, whilst not mentioning the fact that his company was hit with a $40 million fine in 2015 by one of the Euro regulators because they could not bill their customers in a timely fashion. Nope, I ain't making this up. By the way, EdF has exactly the same problem (mostly to do with customer data cleaning). If you sense I have a certain disdain with respect to utilities, well, they seem to be the ones making the bullets (apologies for mixed metaphors).

 Back to the TSOs/DNOs. The nature of DER disputes is a function of the effectiveness (or lack) of the regulatory regime. In most cases, TSOs and DNOs are remunerated on their asset base, which tends to result in them having more than a passing resemblance to junkies on crack cocaine (except they tend to be infrastructure build out junkies). Just like junkies, they talk about not building out more copper (I'm going to give it up) but they still do it.

I speak from experience. A UK DNO (owned by U.S. private equity as it happens) wants one of my clients to fund a 66-kV sub, which the DNO/crack junkie will then own. This is because the client wants to install in his factory 600 kW of CHP — he will internally consume almost all (= 95%) of the electricity produced. I'm not making this up, neither have I massaged the facts.

A variation on a theme is Euro DNOs trying turn themselves into DSOs, and thus opening up possibilities to control both DER and demand response assets (owned by somebody else). This opens up revenue possibilities whilst closing them to new players such as aggregators (DNOs have very sharp elbows). This is not an assertion, but being played out in real time on some projects I'm working on in Europe.

Most "utilities" in Europe (and as far as I can see in the USA as well) claim to be capitalists and in favor of competition (certainly the Euro ones do). They also rumble on about providing "service" to customers. Well, perhaps they do. But what they want more than anything is corporate socialism, i.e. managed competition, which keeps them on top in the style to which they have grown accustomed. They claim to support "new developments" but only at their pace and only provided they stay on top. The question to be answered is: Can they control the pace of change which DER brings? The problem with this is the fact that DER evolution is being driven by technology developments (generation and storage) over which "utilities" have zero control.

The title of this piece is revealing of a utility mind-set, which sees DER as a threat and treats it as such. Quoting one of your own singer-song writers, "the times they are a changing." I have always thought the USA was a "land of opportunity" and thus change (opportunity implies change). Clearly. I'm mistaken at least in the case of U.S. utilities.

Wrapping up: From a Euro perspective, the traditional generator utilities are on the Titanic, they are rearranging the deck chairs, and they are going to sink/change. The network operators, TSO and DNOs need some attitude adjustment/fine tuning of their regulatory/factory settings and perhaps some cold turkey with respect to remuneration based on assets. I'm optimistic that the old generators will sink, less so that the regulators have either the appetite (due to regulatory capture) or technical understanding (they tend not to employ engineers) to do anything. We shall see.


Setting the Context – Defining competitive threats embedded in DER technologies

DERs encompass a broad set of technologies that bring new sources and forms of supply into the grid. By their very definition, these are distributed in various parts of the grid, primarily at distribution level voltages.

The list of DERs (from NY REV) include solar (PV, CSP), fuel cell, wind, thermal, hydro, biogas, cogeneration and combustion generators. They also include various forms of storage and demand response. As we look at this list, it is easy to see that may of the items in the list are not new at all. Cogeneration, combustion generators and a few others have been around for a while now.

What is changing, however, is that these technologies and others are coming down in price, and as a result, more of them are showing up in the distribution grid where, historically, the electric system has been planned only for one-way flow of electricity. In addition to price reductions, regulatory mandates and state-level subsidies have also led to increased deployment. The presence of these resources in the distribution system are changing the dynamics of the relationship between the utility and their customer in new and interesting ways. Let’s analyze some of them.

  • Individual customers: Individual customers (both residential and some commercial/industrial) are able to take advantage of these mandates and subsidies and deploy behind the meter one or more of the options listed above.

  • Microgrids: Taking advantage of DERs and the availability of new technologies to manage and control them is allowing campuses (universities, industrial and commercial) to install local sources of generation and manage much of their own supply needs internally.

  • Aggregators: Taking advantage of these technologies and control mechanisms, newer business models are coming up in which aggregators learning from the sharing economy successes of companies such as Uber and Airbnb are trying to bring those ideas into the electric grid. The examples of plans and ideas are vast and varied as can be expected from something as nascent as this.

  • And there are more.

To recap, the competitive threat of DERs is not coming just from their existence but from the result of their existence, which is resulting in decreased purchase of electricity from the utility and has increased the complexity of distribution system planning and managing reliability to historical levels.

Why is this important or detrimental to the utility?

Utilities are basically asset management companies. They install large and expensive assets and expect to get a rate of return on them. Because they invest in the assets, the state PUC guarantees them a rate of return on their assets. This is the rate of return that their investors/stakeholders expect and deserve as a part of their investment. The assets cover a broad spectrum ranging from generators, circuit breakers, transmission/distribution lines, substations, transformers and so on.

In return for this investment and as the service to its customers, the utility operates the assets to deliver power reliably to their customers and here again, the state PUC steps in by monitoring the quality and reliability of the power delivered to the customers.

While, for the most part, the delivery cost of the power is a pass through component, the utility recoups the return on its asset investment by bundling it into the cents/ kWH that it charges the customer. Utilities can often incur penalties for not meeting certain distribution reliability metrics.

So, with the examples provided above, if the customer takes a reduced amount of energy, the utility gets a reduced return on its investment and possibly incurs penalties for reduced distribution reliability.

This is a problem.

What are the options?

There are several options that can be pursued and are either being considered or have already been implemented by utilities across North America. Let us look at some of them:

  • Unbundling: In this option, the utility separates out the cost of the energy delivered from the cost of the infrastructure being provided. This way, the customer only pays for the true cost of the energy being delivered to their premise but pays for the privilege of being connected to the grid.

  • Of course, the customer is always free to completely disconnect from the grid upon which they will not pay either the energy charge or the connection charge.

  • New services: The advent of DERs has provided utilities with opportunities to partner with their customers who have DERs installed in their premises. These services could take on a plethora of options ranging from managing and maintaining the DERs to taking on the extra energy fed into the grid and others. Each of these options has the potential to bring new revenues into the utility.

  • Installing DERs on customer’s premise: The utility could use ratepayer (and PUC approved) funds to install DERs on customer’s premise and use the excess energy to assist in delaying or avoiding grid-upgrades, thereby saving money for the ratepayer and supporting/encouraging an environmentally beneficial generation mix.

For any of these to work, the utility needs to work closely with the regulatory compact at their state and work out the details because they will all need regulatory approval. In some states, utilities cannot own generation, and in some states, these rules also include storage. There is a level of complexity that needs to be resolved before forward steps can be made.

So what?

Competition is not new to the utility industry. Starting with PURPA of 1978, EPA of 1992 and FERC orders 888/889 which drove wholesale deregulation, to retail in states such as Texas and now from DERs, the utility industry is no stranger to competition. PURPA did not drive the generation entities to ruin, FERC orders 888/889 and Texas deregulation did not bring ruin to transmission companies. Similarly, DERs will not bring ruin to distribution companies.

The key to any competition is to create a level playing field for all players — including utilities.

The playing field cannot be one-sided. For example, if you look at Demand Response, one cannot expect any self-respecting industry to agree to ask its customers to consume less of its product but also expect the same level of reliability. One cannot expect utilities to be asked to continue to provide reliability services, ancillary services (voltage support, frequency support), connection to the grid and so on, for no extra charge and all for a decreasing amount of product sales. They are linked inextricably and must remain so.

This means that these new sources of competition need to be supported by new regulations and for that to happen, the regulators also need to be enlightened with the ability to look at both sides of the equation, ensuring the reliability of the system is maintained, free riders aren’t allowed and that environmental mandates are achieved.

As a power system engineer, I am positive that utilities will weather this competition and all parties will win.


Mani, I could not agree more with your piece. This is a pretty key point here I would suggest:

"One cannot expect utilities to be asked to continue to provide reliability services, ancillary services (voltage support, frequency support), connection to the grid and so on, for no extra charge and all for a decreasing amount of product sales. They are linked inextricably and must remain so."

This raises the issue of bundled vs. unbundled rate designs as it relates to this DER topic and integrated investor-owned utility rate design. Breaking out delivery charges — or in the case of solar applying distribution interconnection charges — in integrated/IOU utility environments is obviously a very contested issue at present. Witness the SolarCity suit in Nevada.

Regulators mostly dislike this idea of breaking out distribution charges in the vast majority of integrated/IOU situations today because of the view that it shifts a burden of overall cost to lower-consuming, often lower-income, customers as opposed to coupled/volumetric rate designs that naturally (and most would argue fairly) allocate costs to those who use more. However, regulators must grapple with the reality that this same consumer advocate backlash scenario could unfold if new rate designs allow for solar customers on the system to lower volumetric consumption and also in turn shift the share of systemwide distribution reliability and delivery capacity costs to lower-income consumers. So do regulators face a bit of a catch 22 on this topic right now? I’d say yes, in some regards they do.

One answer to these challenges that many utilities are exploring is the deployment of DERs in community solar projects. These spread the benefit of DERs across the customer base without unfairly shifting costs, thereby allowing all customers to participate with the added benefit of utility coordination of PV placement to maximize system-wide value against location constraints. PSEG speaks of its solar on a stick program in this regard, and Georgia Power likewise grounds its rapidly growing distributed solar capacity here in Georgia to this same general approach and philosophy.

If IOU regulators deploy flat delivery charges, many consumer advocates will balk. Yet, if they leave volumetric/coupled rate designs in place absent any fees for solar/DER interconnection and net metering or absent fixed delivery charges, the overall costs will have to be spread across fewer customers as those not reducing their volumetric consumption will see their  kWh rates rise to cover the base costs and the base revenue requirement as more people dump grid power for premise-based solar and solar/storage.

As it relates to DERs and the emerging energy "prosumer" movement, distribution rate designs need a careful review and, depending on circumstances, an overhaul. The lawyers and power system economists are going to make a lot of money on the battles yet to come!

What utility engineers and those responsible for reliability must do is start monitoring and quantifying the hidden system buried costs of DERs that may or may not be measured and broken out today (i.e., loss tariffs and possible thermal effects, the costs of added protection, etc. ). This opens a bit of a can of worms for the regulatory staff at many utilities, or as an earlier comment in this stream noted, it opens "Pandora’s box."

I'd suggest though that the energy prosumer movement is here, Pandora’s box is wide open, so the industry must evolve both its systems, strategies and regulation to keep pace and keep things safe, fair, economical and equitable for all customers while promoting free markets.

These, after all, are the key charge of regulators.

Prosumers You Ask? Read more here:Smart Grid Research Indicates That Utility Perceptions on “Prosumers” Evolved Rapidly 2010-2012


Historically in the U.S. (and to a large extent Canada), the decision to use volume as a placeholder for demand was based on the limitation of the meter to measure and report demand. With the advent of digital meters, measuring demand is trivial. Italy has had demand-based charges for infrastructure since World War II that it enforced with breakers in the meters. The whole ENEL metering project was done to support remote setting of those demand breakers.

A simple study of demand charges shows that if one puts 1 kW or so of solar on the roof of a home, that the demand charge would drop for most residential customers, since their peak demand tends to be on summer days. If one instead installs a net-zero amount of solar, the demand charges go up significantly (since in many places you need between four and eight times the amount of solar that your average demand is to get to net-zero). In Michigan (see my article in last month's IEEE Smart Grid Newsletter), the average home draws just over 1 kW across the year and demand peaks at just about 2 kW on the hottest days of summer, during daylight. At 1 kW of solar, the system exports 5 kWh of power over the course of the year for an average home and reduces peak demand by 0.6 kW for an average home in 2015. To get to net-zero in Michigan on that same home (annually generation from solar = annual consumption), you need just over 7.5 kW, and your maximum demand is 7.4 kW in late April. At net-zero, the utility (or somebody) needs to hold energy from late March through to August for the customer (they over-generate in March, April, May and early June and then under-generate significantly in late June, July, August and early September).

On the other, using demand-based infrastructure tariffs (with typical ROR caps), and at roughly 10% of the energy generated in the state coming from rooftop solar installed in a net zero fashion, the non-solar customer would see a slight reduction in their electric bill as the maintenance of infrastructure would shift slightly to the solar net-zero customer.

In short, renters, low- and fixed-income homeowners would be protected to some extent from the additional costs that distributed solar would place on the grid.

There are many ways to create and manage demand charges, for this exercise, the high demand during the year set the rates for the customer, obviously you could do it with a monthly reset of some other fashion.

Demand charges are probably the closest to fair and prudent of any of the choices of integration of solar. Fixed monthly charges, and other artificial fees, do not adequately take into account the customer's use of energy and decision on devices to buy and own; for instance, high-income net-zero homeowners may choose to put in a rack of Powerwalls in their garage to reduce the demand they place on the grid. Not only would demand charges probably impact the first-come, first-served mentality of the renewable installation today, but would also jumpstart residential storage and the move to direct DC in the home.

I am also a fan of using solar for heating and hot water, but then I live in Michigan and today was a reminder of how bad winter can be.


Dear Don,

As you can expect, I completely agree with you and the thoughts you have portrayed in the email.

So far, most of the discussion has focused on the needs of one side of the equation —we can call them a lot of things, “prosumers” is a good one to start with. This same argument has made the utilities look like "the party of NO."

While utilities have indeed acted as obstructionists. they do not deserve all the blame. I think the utilities have not advocated their position well. I am hoping that my article will get that discussion going in the right direction.


As I write this piece, I am sitting in my in-laws’ house in Gurgaon, India. Gurgaon is outside of New Delhi, near the Delhi Airport. It has grown in the last 15 years from farms and pastures to a huge hub for business. Many corporate headquarters, including that of the national transmission system operator, relocated here to avoid the congestion in New Delhi. Sounds familiar? I am not trying to impress the reader with my global travels, rather I am setting some context. Being in India for the last one-and-a-half weeks has given me a great appreciation for the pros and cons of DER. As I wrote this piece, the power went out for the third and fourth times today. Yesterday the power was out five times for anywhere from 20 minutes to 3 hours, on a day when the temperature reached between 96° to 100°F. Moreover, the power has gone off at least once per day, every day, the entire time I have been here.

I am able to continue working offline because my in-laws have invested in battery backup for the house. The backup is sufficient to cover some lights in most of the house and a ceiling fan in each of the rooms, but not enough power for the AC units or the TV, so sitting down to write seemed like a good idea. My in-laws have one part of a DER, the battery backup. A few minutes ago, I could smell that the neighbors and the apartment complex about a quarter mile away also have their DER (diesel generators) running.

So make no mistake, I am a fan of DER, not just today, and especially today.

As I have discussed before in this forum, our industry emerged from DER. In the early days, that was all that we had. As needs grew and people began to understand the economics of energy production, electricity distribution via wire grew rapidly. The rising demand and economies of scale gave rise to higher voltage lines and larger production resources. It is clear that the growth and strength of the U.S. economy in the 20th century was driven by the availability of low-cost reliable energy, primarily in the form of electricity.

We are now seeing a situation where the economics, social pressures and government/regulatory policy appear to be moving us back in the direction of distributed energy resources. Again, I am a fan of DER, especially this week. I am also a pragmatist and am always looking for more efficient and effective ways of meeting needs, or solving problems. I believe that as we move toward greater integration of DER, something that is not only inevitable, but is pragmatic, we should look at the long view and take steps to make sure that we get it right.

The consequences for not getting it right are dire. If we suffer from degradation in reliability, grid security or overall energy costs we will have hampered our economy and weakened our country.

So, what are the main drivers for DER? Based on what I hear and read, the most significant factors that are cited are:

  • The cost of electricity continues to rise in many markets to the point where it is more cost effective to install DER for individual or community energy supply. This applies to both business and residential customers. This tends to be more prevalent in the developed markets and the undeveloped markets (those with no infrastructure) and less the case in emerging markets

  • The cost of DER technologies continues to fall and the technologies continue to improve. This appears to be the case for prime movers, including solar, wind, and other sources as well as for storage. This appears to be the case across all markets. DERs are even more cost-effective when they are deployed in ways that support constraints or difficult reliability areas. In my career, we have deployed DERs in many places where they were the most cost-effective solution by orders of magnitude. The downward cost trend suggests those opportunities will continue to grow.

  • Reliability can be enhanced through the application of DER. Businesses that have ultra-high reliability requirements can ensure that their processes run unimpeded by the application of DER. Other customers gain an added measure of reliability from having DER in parallel with the utility connection. This is more the case in the undeveloped and developing markets, and is still a factor in many of the developed markets.

  • Reduced impacts on the environment through the application of renewable-based DER with or without storage. This is particularly true in cases where the conventional energy supply is from sources with high GHG output, regardless of markets, though there is stronger pressure on this factor coming from the developed markets and while important in developing and undeveloped markets, it is often traded off against the need for electricity.

All of these make sense and are rational explanations for why we should move toward integration of DER. There are other drivers such as anti-big utility movements, and I believe that these are largely secondary to those listed above and, on their own, are not sufficient or pragmatic reasons to consider DER.

Sticking with the pragmatic, I believe that we should look at what it will take to ensure that we get this right. We need to integrate DER and we need to do it well. From my perspective, there are several things that we need to consider to ensure that we get it right.

Key factors for consideration:

  • Cost – What is the real cost of DER integration? Clearly there is the upfront capital cost of the DER system and the interconnection (if interconnected) with the utility. Having designed and installed DERs over my career, I have seen that we often underestimate the costs of operations and maintenance, including periodic overhauls. We also need to look at the cost of reliability or redundancy for the DER systems. Answering the question of how will energy be supplied during maintenance outages and overhauls will be important. It will either need to be supplied from the grid, or supplied by oversizing the DER system to ensure that there is sufficient redundancy. If the backup is supplied from the grid, what is the real cost of that supply? I don’t wish to debate that question here, as it is the topic of numerous ongoing debates. It is sufficient to say that the cost of back up is not zero and it is more than merely the cost of the energy that is delivered. There is some cost that is incurred to ensure that there is sufficient capacity to back up the DER.

We need to get this right to ensure the costs are appropriate. We have examples, such as California, where we have not always gotten it right. I have heard proponents of social justice refer to the early California policies on renewables and the NEM rates as the largest shift of wealth from “have nots” to “haves” in the history of California. While I can’t vouch for the accuracy of that assertion, it is something that California and other jurisdictions have woken up to. Artificially lowering the costs of integration of DER, even for good reasons such as stimulating renewables, creates the risk of shifting the costs from those who can afford DER to those that cannot.

The other factor that needs to be considered in looking at the costs, is what is the true cost of electricity supplied by the utility? In California, the investor-owned utility rates are high, in part because of the programs that have been put in place through policy or regulation. Regulators and policy makers need to recognize that rolling these programs into electricity rates has helped to create the drive for DER as a means of lowering the overall bill. As more customers opt for DER, there will be fewer customers remaining to pay for the programs and for the fixed costs of the utility, driving rates up further, thus stimulating a vicious cycle made up in large part due to policy and regulation.

  • Reliability, Security and Integration are all highly interrelated and interdependent. I believe most people accept the linkage between cost-effective reliable electricity and economic security. For me this gives rise to several questions:

  • If we become reliant on net exports from DER, how do we ensure that we consider the impact on the economy for loss of supply from the DER? Granted, the loss of one DER unit may be inconsequential. Where do we draw that line and under what standards do they operate? At what point does the loss of a DER resource represent a reliability risk, either locally or regionally? Who is responsible for scheduling and managing that risk?

  • If we believe the growth of DER will continue to increase, and I do, how do we address the potential impact on grid security? Again, a single DER unit is not likely to have an impact on grid security. At what point, though, is their sufficient critical mass of DER systems that they become part of the critical infrastructure? Given the number of cyber-attacks on power and energy related facilities globally, it is not a stretch to think that malevolent forces would seek to hack the control systems for large numbers of DERs and undertake a coordinated attack. When do DERs fall into the realm of CI and CIP standards? This is likely to be a contentious issue as the costs of maintaining CIP compliance are high and the work intensive. If our reliance on DERs continues to grow, then, at some point, they will become part of the critical infrastructure of the economy and our security.

  • When I speak with system operators in utilities and within RTOs, there is growing concern about the loss of rotating mass. Many proponents of DER dismiss this; however, based on my discussions with experts in the field, including leaders in the development of power electronics, it is clear that we will need to find ways to replace this capacity. The rotating mass supports our ability to ride through faults and maintain a synchronized system. Most DERs do not have the equivalent amount of energy behind them to replace the loss of this mass. As with all problems, this is solvable, though we will not solve it if we fail to recognize it or if we continue to dismiss it as “obstructionist tactics.”

  • The other concern that emerges from discussions with system operators is the DER will have an impact on the ability to operate and maintain the Bulk Electricity System (BES) or Integrated Transmission/Generation System. Some DER proponents suggest that we no longer need a BES. I don’t agree with that view. Many of the renewables that we currently rely on are remote from the load and I believe that this will continue to be the case for some time. The concerns about DER with respect to operations surfaces when we see DER providing net export or ancillary services to the grid. Many forms of DER are used for ancillary services as their deployment can be modular, targeted and many of them are fast acting, highly responsive. The difficulty stems from the fact that many of the DER are installed on the distribution systems. BES operators generally have no visibility to what is happening at the distribution level. Moreover, visibility to operations at the distribution level is inconsistent among utilities and they fall under different regulatory jurisdictions. This makes the job of those accountable for the reliability of the BES extremely difficult. How can they rely on sources that they can’t see? As the level of dependence on DER grows, I believe that this will be a growing issue. It really begs the question of who is ultimately responsible for reliability. We need to have a holistic approach to integrating DER so that we can ensure reliability rather than ensuring finger pointing.

  • Social Equity was discussed above and so I won’t belabor the point. I believe that if we want to see DER deployed in the most efficient, expedient and sustainable ways, then we need to ensure that the costs are transparent and equitable and that the standards applied to all sources of supply are comparable and reasonable.

  • One of the biggest questions for me is the Regulatory Impacts from a growing dependence on DER. We are already seeing moves by entities like the CAISO to pave the way for rooftop solar to be aggregated and bid into the market. Clearly this creates more opportunities for solar and other forms of DER to take advantage of a wider range of economic opportunities. Does this mean that as DER grows and begins to participate in the organized markets, that they will then fall under FERC jurisdiction rather than State regulation? The recent Supreme Court ruling certainly suggests that is at least a possibility. Would the potential for this shift in jurisdiction change the way State Regulators view DER and enact regulation? What would this uncertainty do to the DER market?

With all of those considerations, how do we move forward and what is the role for the utilities? To ensure customers, the economy and our society all benefit from the advances that enable DER, I believe we need to ensure the following:

  • Utilities, DER proponents, policy makers and regulators all take a holistic view of the benefits and the costs. We should use DER anywhere and everywhere that they make economic sense (including reliability), and this should also consider the true costs of energy supply without the burden of regulatory-mandated programs.

  • The policies that are put forward and turned into regulation should level the playing field. Utilities should have the opportunity to invest in and deploy DER. Utilities should not have the ability to block the effective and efficient deployment of DER by third parties or by customers.

  • We need to ensure that our policies and regulations recognize the value to the economic security of the country from a stable electricity supply. This means that we need to think about when and how we integrate DER into the critical infrastructure. If the proponents are correct about how quickly we could move to a DER centric model, then DER are very rapidly nearing the point of being part of our critical infrastructure.

Utilities need to embrace DER and see their role as supplying energy to their customers in whatever way makes sense. There is a great example from a mid-tier utility in eastern Canada. A developer announced it was going to build a very large mixed-use development and it intended to have it be a zero net energy microgrid. Rather than opposing the developer’s rights to build such a development (under provincial regulation the utility could have opposed it and prevailed), the utility chose to approach the developer and offer to help in the design of the infrastructure. After agreeing to take the utility’s help, the developer asked if the utility also would  be willing to take on a contract to operate and maintain the facilities. The developer recognized that this was not its core skill set. The utility recognized not only could it help the developer and the developers’ customers, it could do so in a way that recognized the overall system needs and could make proposals that were value adding for the developer and the for existing utility customers.

For me, this highlights the value utilities can bring. The utilities have some of the best knowledge of how to design and operate complex energy systems. It is a natural place for utilities to step into and a great way for them to add value to the DER customer and maintain their ability to help plan and develop reliable systems. If the utilities view DER as a powerful tool they can deploy in the planning and operations of the system, I believe everyone will benefit. This will take work and collaboration with DER proponents, regulators and policy makers. I believe it is the work we should be doing as an industry and as a society.

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