PART II Collocation and Franchise Rights: Infrastructure on the Modern Electric Grid

James McGinniss
Jun 19, 2018 · 23 min read

It is said that towards the end of his life, Nikola Tesla was attempting to use the acoustic frequencies of the earth in order to transmit electricity wirelessly. While this may sound like a crazy idea and it is still not in use today, it seems that Tesla was on to the inherent problem of the AC electricity he invented: wires. With our current grid infrastructure, 40% of electricity costs are attributed to transmission and distribution. That is, 40% of our energy bills simply pay for the wires to carry electrons from generation to load. Sometimes more. No matter how cheap new technology can make the generation process, the cost of transmission and distribution will not go away. In fact, it is widely believed that we are not spending enough on transmission and distribution infrastructure, and that those costs will go up. This problem is a direct result of how the grid was built in the past.

Economies of scale in generation made for natural monopolies in distribution. Coal plants, for example, became dramatically more cost effective and efficient the larger they became over time. Building large, centralized plants has allowed energy generation to become very cheap, and has kept the average person’s bills manageable. This choice in the building of the grid, driven by real technological constraints, created the monopolistic nature of utilities that has been gradually dismantled since the 1970’s. Utilities and regulators made a bargain to let utilities vertically integrate in exchange for being heavily regulated. While wholesale markets have been liberalized, distribution electric poles and wires are still believed to be a natural monopoly.

The centralized model today, however, is creating a problem: peak demand on the grid and overall energy usage are diverging (demand is going up, overall usage is going down). The advent of distributed technologies such as solar, wind, storage, fuel cells, and, perhaps most importantly, combined heat and power (CHP) offer a solution to this problem in the form of generation and load collocation.

It is important to understand how monumental of an idea collocation is: by feeding loads from onsite generation, we can potentially change the fact that 40% of our energy bills comes from transmission. While, for example, rooftop solar LCOE is more expensive per kwh than utility scale, it is not drastically less efficient and does not need to be transmitted long distances. Collocation eliminates wires, and therefore cost, in the way Tesla originally dreamed was possible. Thus, with the newfound ability to collocate supply and demand, it is apparent that electric infrastructure is not a natural monopoly. As such, franchise rights have become a barrier to the proliferation of distributed generation assets and the efficiency with which they can be deployed.

A Brief, Reductionist History of the Grid*

One could argue that we are at the dawn of the (roughly) fourth epoch of the U.S. electric grid. The eras can be defined as follows:

  • Edison and other’s private, local systems in the early days (grid beginnings)
  • The Grow and Build Era
  • Wholesale Markets
  • Retail Markets

Edison’s systems were installed in backyards or on city blocks because DC current could not travel long distances efficiently. Starting with wealthy houses having electric lights, eventually industries and trolley companies had their own private power. This era was fractured, with little to no consolidation and standardization. However, an inflection point was reached with Tesla/Westinghouse’s AC hydro plant in Buffalo. This was the first time we began moving towards a centralized grid architecture because AC power could travel long distances. A large AC power plant could achieve economies of scale to generate cheap hydro power, and then we just needed to build the infrastructure to get this cheap power to loads. But how to build it?

In Chicago at the turn of the century, Samuel Insull helped pioneer the idea of the modern electric utility by selling power from the same generating asset to multiple parties from different industries with Time of Use rates (power cost different rates at different times of day). Instead of building a power plant for each building, he realized that by combining retail customers with industrial customers, he could keep his generators running for longer and, in effect, increase his capital utilization rate. In essence, he understood the importance of capacity factor. More up time meant cheaper electricity rates and more customers. Furthermore, he won exclusive (franchise) rights from the city to build electric grid infrastructure.

This helped usher in the second era of the grid: the grow and build period. During this time, we decided as a nation that it was essential to get electricity to as many U.S. citizens as possible. With ever increasing demand, we could build infrastructure and grow the user base. Economies of scale established the most efficient way to do this was by building large, centralized generating plants and shipping that cheap power out to loads with shared infrastructure. This required consolidation, central planning, and vertical integration. The Insull model went mainstream.

As the 70’s approached, most of the U.S. had been electrified, in effect ending the “grow and build” model for utilities. At the same time, power plants weren’t getting anymore efficient by getting bigger. We started reaching the limits of thermodynamics, and aside from Natural Gas Combined Cycle (NGCC) generators, we aren’t doing much better now than we were then. Lastly, one of the most monumental orders in the history of the electric grid, PURPA, was handed down in 1978. PURPA, which broke the vertically-integrated utilities’ monopoly by allowing for the first time non-utility generators to sell power on the utility-owned grid, opened the utilities up to competition and began the third era: a march towards wholesale markets.

Ever since, the grid has been on a steady trend of deregulation, democratization, and decentralization. This trend of deregulation culminated with the full liberalization of wholesale electricity markets in many states around the new millenium. Furthermore, in many areas of the country, utilities must compete regionally for customers on distribution wires they don’t own. Poles and wires, payment settlement or power procurement, and generation are largely being segmented.

Which bring us to present day, the beginning of the fourth act: the liberalization of the distribution grid. The idea is that, due to distributed generation, markets will be needed to coordinate information (energy) being transacted between potentially millions of connected assets. Yet with all the excited talk about prosumers and distributed generation, currently the only real market mechanism on the distribution grid is NEM, a blunt instrument that does not transfer any valuable information whatsoever. Programs such as NYREV, are beginning to push us towards full retail markets.

In a sense, each era can be defined by the problem it had to deal with.

  1. The Edison Era (1880’s-1920’s) was defined by the fact that DC could not transmit power long distances efficiently. Solved by Tesla’s AC power and later Insull’s utility model, we could begin to build efficient, standardized distribution channels.
  2. The Grow and Build Era’s (1920's-1978) problem was getting electricity to every American. Quite simply, with the solutions of Insull and Tesla, we could grow the customer base by building infrastructure. Important legislation includes FDR’s Rural Electrification Act of 1936, which provided federal loans to build distribution networks, and the Public Utility Holding Company Act of 1934, which declared electric utilities as public goods.
  3. The Wholesale Markets Era (1978–2005) addressed the market problem created by the vertical utilities at the wholesale level. The solution was to make generating assets competitive, and was enabled via PURPA in 1978. The Energy Policy Act of 1992 forced transmission line owners to open their networks to all generators, but because our technological constraints still only allowed for large power plants, the distribution network remained in the grips of utility monopolies.
  4. The present era is defined not only by climate change (we want more renewables on the grid) but also the following technical problem: peak demand is growing, while overall energy consumption is remaining constant or dropping. Furthermore, this is driven by some of the very energy efficiency and renewable projects we want to be more widespread. Put differently, we face again a capital utilization problem that, if managed poorly, renewables will exacerbate. Every kwh of renewables put onto the grid displaces a kwh of legacy generation, and thus peak demand issues and renewables integration are analogous. We can solve this by liberalizing the distribution grid and repealing the last legacy of the utility monopoly: franchise rights. The Energy Policy Act of 2005 began incentive programs for decarbonization — call this a PURPA analog — but we await an act analogous to the Energy Policy Act of 1992 to liberalize distribution networks.

Peak Demand Rates: How we Really Pay For Infrastructure

The centralized model comes with inefficiencies in the building of infrastructure. In most markets, with an absence of public funding, infrastructure cost is passed onto the consumer in the form of peak demand rates. Peak demand rates are the market signal that point to the need for distributed assets like CHP, solar + storage, fuel cells, Demand Response capable loads. While much has been said about storage’s frequency regulation, voltage support, arbitrage, and etc capabilities (all still good things — we will discuss variability later), it is the idea of demand reduction that fundamentally makes distributed generation superior to current generation mechanisms and overall grid architecture. Distributed generation can thus be looked at as a means to defer infrastructure costs, both directly and indirectly, by collocating generation (supply) and loads (demand).

On average nationally, 10–15% of our grid is built to handle loads 1–2% of the time, and has an overall capital utilization rate of under 50%. Furthermore, markets like ERCOT state they like having 12–17% generation reserve margin, meaning we often have 10–20% more generation capacity than even our record peaks. In English: we overbuild our grid like crazy, for reliability’s sake.

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The load duration curve of ERCOT. Demonstrating the trend of rising peak demand and limited utilization of all grid resources, from transmission lines to generators. With a peak demand of close to 70GW and an average usage of around 35GW, much of the grid is not used for most of the time. As overall consumption is not growing, renewables and the infrastructure built to deliver them, simply displace other assets leading to even lower capital utilization rates.

With new technology, this no longer has to be so. Generation resources are increasingly being added to distribution (rather than transmission) feeders behind commercial and residential meters. So let us explore the most obvious market to discuss these issues: ERCOT (Texas). Given that it is the smallest interconnection (there are three grids in the US: the East, the West, and Texas) by land size, it is also an energy (as opposed to capacity) market and has a simple means to calculate demand rates.

Capacity in Texas generally fluctuates between 35 GW in the winter and 55 GW in the summer, with a record peak occurring in August 2015 of 69.8 GW. That means the grid has to be ready to handle a wide range of loads in order to avoid blackouts. This leads to much of the grid infrastructure sitting idle for much of the time. In Texas, the consumer pays for this, and infrastructure in general, in the form of 4CP pricing.

All transmission expenditures are rolled into “4CP rates”. 4CP stands for “Four Coincident Peaks”. During the 15-minute interval of greatest demand grid-wide on ERCOT in the months of May, June, July, and August, ERCOT measures everyone’s demand, and then uses their demand to assign a monthly rate in $/kw used for the entire following year. Consumers using greater than 700kw in competitive retail spaces receive the charge directly on their bill, whereas municipalities, like Austin Energy, can pass through their 4CP charges to customers however they like. These charges are significant. For example, to get West Texas wind and solar to high load centers in East Texas, the CREZ lines were built for $7 billion to transmit that energy. In addition, TDSP’s have to spend yearly to maintain transmission lines.

What a fascinating market signal peak demand rates are, then: the more grid infrastructure we build on the whole, the more the user is incentivized to use it less. Collocated batteries or generators triggered properly during a 4CP event (15-minute period) reduces a user’s 4CP bill significantly, dumping more of the costs on other users. The battery in this case is technically redundant capital being deployed on the grid — at least at this point in time — but does reduce overall peak demand. While certain upgrades to integrate more renewables are inevitable, like CREZ, we must avoid haphazard infrastructure spending. We must think deeply about how best to not only integrate renewables, but leverage their benefits into existing infrastructure.

There are many out there who believe more transmission lines like CREZ, or even long-range High Voltage DC (HVDC) superhighways, are the best way to integrate renewables, but I remain skeptical. As is seen via the CREZ lines, any argument for HVDC and transmission upgrades must come with the discussion of how the costs are passed onto the consumer and the incentive structures they create. There are three main options of how these projects can be funded: public money (no direct cost to consumers), private money (the wind/solar developers and their off-takers fund the transmission), or market mechanisms such as 4CP (the most likely scenario, and one in which the consumer pays directly).

While I’m not unilaterally opposed to these projects, I do question how elegant and simple centralized infrastructure projects would actually be, as proponents would lead us to believe. I’m more enthusiastic about the idea of moving high loads, like industries, to high renewable resource areas, which makes far more sense from a market perspective. Those willing could benefit off of cheap power. For example, it’s possible we see a massive industrial boom in West Texas, where they have the trifecta of cheap wind, cheap solar, and cheap natural gas. This is an entirely different discussion, but is an important aside in discussing the implications of peak demand pricing. Simply put, centralized renewable projects could make the matter worse, not better. Distributed Generation, on the other hand, offers a solution to rising peak demand prices in Texas, and across the country.

This is because peak demand pricing is itself a market signal indicating the benefits of distributed generation, and rates are becoming high enough in order to make the raw financials work. 4CP is how the rate is assigned in ERCOT, but there are plenty of other markets with peak demand rates; PJM, NYISO, and NEISO are markets with even higher rates. For example, it is estimated that the cost is $35,000/MW (and rising) drawn from the grid during a 4CP event per year in Texas, and anywhere from $75,000-$150,000/MW per year (also rising) in NEISO. Each market then has further revenue potential in ancillary services markets; in PJM, frequency regulation is very lucrative, while in ERCOT Emergency Response Services (ERS) ad Demand Response (DR) are. By stacking functions, batteries are becoming economical or close to it in many areas.

CHP, another technology, handidly beats utility market rates in dense urban areas due to its ability to not only couple load to generation, but also generation to water supply. CHP uses the waste heat from generating electricity with natural gas to supply hot (or cold, with an absorption chiller) water to a building. Because of this, CHP plants can be 90% efficient. NGCC plants can only achieve 60% efficiency, due to their inability to supply low grade heat to domestic water supply. That will never change. So here we now have 100kW systems crushing 1GW coal and NGCC plants from an efficiency standpoint (although not necessarily LCOE, discounting the cost of distribution).

With the low cost of natural gas and amazing efficiencies, CHP can generate power in NYC, for example, at $0.06/kwh, where the utility rate is $0.22-$0.28/kwh (thanks, in part, to demand charge reduction). For those worried about climate change, consider for a moment that CHP can beat coal plants (via efficiency gains and lower emissions) by up to 75% from an emissions standpoint, and often times replaces heating oil still used in many NYC buildings. Furthermore, in dense urban areas, CHP and battery storage are our best options; solar can be put on all available roofspace, but still will not meaningfully offset total load.

The simple fact of the matter is that, with peak demand savings as the base, these distributed systems are starting to save a wide variety of customers across the nation real dollars. Thus, demand rates are an important indicator of how distributed generation will lower peak demand, and thus indirectly defer infrastructure spending over time. That is, as more and more dynamic generation — generation where time of use can be controlled — is built behind the meter, the need for expanding transmission and distribution lines to handle increasing demand will diminish because ISO’s will see lower demand grid-wide.

Distributed generation is also being used to directly defer infrastructure spending through the idea of No-Wires-Alternatives. The idea of NWA’s is that with central grid planning, one can install distributed assets in targeted locations in order to relieve pressure on congested areas, and avoid paying for grid infrastructure updates. In NY, regulators are incentivizing utilities to do this by offering a percentage of the savings compared to a normal distribution infrastructure upgrade.

But only in certain cases will grid planners be effective at utilizing DG to defer transmission. For example, instead of building a $1.2 billion substation to deliver power to a problematic area in Brooklyn, ConEdison let private companies put in proposals for an alternative. What they came up with was a 1.1 MW, 1.2 MWh mix of distributed fuel cells, solar, and storage for $200 million that solved the same problem. Projects like this should be welcomed — and are an excellent example of grid planners and the market working together — but should not be expected to change the fabric of the grid at large.

Not all areas of the grid have problems so clearly identifiable. It certainly, however, shows distributed generation’s potential. In areas where the problems are less directly (centrally) observable, it is crucial to have price signals with the proper incentives behind them for our desired outcome (of a cheaper, cleaner, more reliable grid).

Thus, it will be peak demand and demand response market signals that leads to behind-the-meter DG deployment at scale. These peak demand rates are a direct result of how we have chosen to build our grid as a centralized model, and point at the inherent inefficiencies of doing so. The aforementioned low capital utilization on the gird, or low capacity factor, is a direct result from the need to overbuild our grid to handle peak demand times.

But, a properly designed market that incentivizes solar + storage to shift solar usage to the times we need it most and rewards demand reduction accurately, integrating renewables could help actually improve peak demand issues via collocation. Currently, integrating solar into current markets, because of blunt mechanisms like NEM, actual make our peak demand problems worse (quack quack). And most of the time, peak demand is covered by fossil fuel generators, which works against our aims. There is a good way and a bad way to do this.

A Decentralized Grid

Before tackling the implications of franchise rights on this problem, it may be helpful to look at areas where the grid is being started from scratch. Remarkably, developing countries may create decentralized grids before developed countries, much in the way mobile phones leapfrogged landlines. This, however, comes from necessity — a lack of centrally organizing parties and infrastructure.

In many countries in Africa and Latin America, microgrids are the only option. In Africa, a solar panel and a battery can power a few lightbulbs and a TV. The logical progression for these systems, due to counterparty risk, is interconnection. When a person in a village doesn’t have the money to power their TV, why wouldn’t they sell it to a neighbor who might? As more of these systems go in house to house, eventually some degree of consolidation, via a distribution network, will be more efficient than individual units. That is, by spending a little extra on wires to connect homes (financed via transaction fees), the developer may reduce risk of default. A robust transmission network, however, is less likely.

As a thought experiment: What can we learn from these places, where the grid will be built from the bottom up?

For introducing chaotic, variable elements to the grid in the form of wind and solar leads to a requirement that we consider what a ground up grid looks like in the U.S. Variable resources, even with better storage solutions, will be incompatible with the fully centralized architecture of old. You know how bad the weatherman is at predicting the weather? Increasingly, as we accomplish deeper renewables penetration, that will translate to our grid operators. And for a system in which reliability is predicated upon good forecasting, that is a troubling thought. That is, instead of the static grid planning of old, we will need a dynamically responding grid instead.

Maybe a centralized grid is not the best structure; our grid is vulnerable to Black Swan events as it is, whether through natural disaster or the possibility of malicious attackers. Think for a moment that we only have three grids in the U.S: The Eastern and Western Interconnections, and ERCOT (Texas). While the level of reliability and cost currently delivered to the consumer is one of the most impressive feats of engineering in the history of humanity, we can always do better. When a couple of curious squirrels, in the wrong place at the wrong time, can cause a rolling blackout from Ohio to NY, this becomes apparent. Maybe regional grids should be isolated. Maybe we should have 20 interconnections instead of 3.

So ask yourself the questions: would locally owned and controlled distribution feeders lead to a more antifragile grid? Is the risk of over (or under) voltage on distribution feeders due to high (or low) transaction volume a decent trade-off for stopping rolling blackouts? How do you even centrally dispatch what could become millions of interconnected assets, all on different feeders with different capabilities? It may be that a decentralized grid, while having more frequent local outages, can avoid catastrophic rolling outages completely.

Thus, can we consider a grid in the U.S. where central planners take a backseat? Maybe locally owned and transacting grids, still interconnected into the bulk grid, will make more sense in a future with high degrees of uncertainty and variability on the grid. Whereas rolling blackouts can have a marked net negative impact on yearly US GDP in a single event. Is that really better than more frequent, but shorter and less catastrophic, outages?

The point is that grid outages in the way that we experience them are a direct result of the way we’ve chosen to build our grid. They are baked into the DNA of a centralized grid. And yet, wholesale markets and bulk grids are a wonderful thing, so we should certainly leverage existing infrastructure in a distributed grid. There are certain thinkers out there who believe grid defection would be a good thing, but I could not disagree more. This is all to say simply that not only do we need a decentralized grid in order to integrate renewables, but it may even be better than the grid we currently have (cleaner, yes, but cheaper and more reliable too).

But there is one policy still standing in the way of this possibility. Much like the Energy Policy Act of 1992 opened transmission lines to all generators and paved the way for wholesale markets, we need a policy to do the same to distribution grids. Not only should prosumers be given access to selling on Distribution Service Providers’ wires, but utilities should unilaterally lose their exclusive rights to build distribution infrastructure.

Franchise Rights

Franchise rights give utilities exclusive rights to build electric infrastructure on public rights of way. This means that if a private developer would like to build electric wires across (or under) a public road or other right of way, the utility can step in and prevent it. It does not matter how much sense the project makes, or if it would lower the participating parties electric bills. The utility has full control by divine right. When the electric grid was thought to be a natural monopoly, this may have made sense in order to establish order via consolidation.

It gets worse, though. Even when electric infrastructure does not cross public grounds, the utility can step in if a certain number of distinct tenants are receiving service. This varies state to state. For example, in NY and California, it is two or three tenants. How does this possibly make sense, even from a reliability standpoint? In our current system, with the potential of DG or onsite generation assets, the “natural monopoly” is broken, and thus the reasoning for franchise rights is too.

The logical alternative is having a non-market participating government entity accept applications for developers that want to build infrastructure, and approve the plans or not, like any other type of construction. Or rather, like wholesale markets and the transmission network. In wholesale market functions, infrastructure is not controlled by a central, financially participating actor. Rather, projects are proposed, go out for bid to private developers, and are approved by non-financially participating actors (regulators). With collocation, there is now no reason why this shouldn’t occur at the distribution level too.

This is indeed already happening today, albeit on a small scale. Possibly the most interesting “microgrid” project in existence today is Hudson Yards in Manhattan. Hudson Yards is a massive re-development project on the West side of the Island, with a mix of retail, commercial, and residential spaces that will truly change the face of the city. What’s most interesting, however, is that a large majority of the power will be delivered by a 13.2 MW CHP system. The plant is centralized, distributing thermal energy to the different buildings through water loops snaking through the development (this is called District Energy). Not only does this lower tenants bills significantly, but it also lowers carbon emissions and protects them from grid blackouts like those experienced during Hurricane Sandy.

Most encouraging is the fact that ConEdison worked with the developers on this project. Hudson Yards will pay monthly fees (standby tariffs) for the infrastructure built by ConEd to still interconnect them to the grid. This means that at times, Hudson Yards will be able to buy power from ConEd when necessary. I do not believe they will be selling into the grid, but if it made sense to do so, they should be able to.

Hudson Yards is, by all measures, a win-win-win. The developers make more money by controlling their own utility. The tenants pay less by getting access to cheaper energy. The utility avoids expensive capital expenditures to deliver power to a massive new load and thus avoids peak demand issues. Hell, even the environment wins. Why doesn’t every development in the city do this? Well, they’re starting to. And it’s not just limited to NYC; In Texas, UT-Austin runs on it’s own District Energy CHP plant, and pays on average $0.06/kwh compared to the $0.11/kwh the surrounding city pays Austin Energy. So let us take this further.

In a scenario like Hudson Yards, or UT-Austin, what is the line where franchise rights can be enacted? If it made sense economically, and could be done reliably, what is stopping a developer from building infrastructure to an adjoining building or development to sell them power? What is physically so different about a college campus, or private development, from a city block? Could a city block be run on District Energy? Luckily, the goal of NYREV is to allow retail markets to happen, and yet without mentioning franchise rights, what will this process look like at scale? If it weren’t for NYREV and NY state’s forward thinking policy on energy, would even Hudson Yards have happened?

The answer is decidedly no. In California, for example, a state with probably the largest amount of distributed generation, there exists something called “Departing Load Charges” or DLC’s. That is, on top of the same standby tariffs that ConEd can charge Hudson Yards, California utilities can charge users of CHP the lost revenue from the kwh they’re NOT selling them. Standby tariffs make sense, to cover the idle infrastructure built for them. DLC’s, on the other hand, are a preposterously predatory practice by a monopoly. In fact, in the industry, it’s called baldly “the anti-CHP tax”. And CHP is indeed going no where in California currently, despite how much it would benefit all parties (aside from the utility) involved. But it is not just predatory tariffs that are the issue.

Rather, it is having a participating actor, the utility, acting as the arbiter for what infrastructure can and cannot be built, instead of a benevolent market overseer, like at the wholesale level. While the PUC still has to approve proposed infrastructure projects by the utility, private developers don’t even have the luxury of putting in a bid. Let us thus imagine the following scenario: the retail rate, set by the NYREV DSP, for selling into the grid is $0.12/kwh and the buying rate for the costumer (prosumer) from the utility is around $0.24/kwh. The prosumer can generate at $0.06/kwh with their CHP system. Instead of their being able to build infrastructure to an adjoining building and selling them power for, say, $0.20/kwh, with NYREV they will be forced to sell to ConEd, who then sells it back to their neighbor at a premium ($0.24/kwh).

Thus, franchise rights put an artificial constraint on market prices from distributed generation resources, and keeps them from developing properly. That is, the ability to collocate energy to supply, with very short distances between generators and loads, means that this artificial constraint on building such local infrastructure will actually have an effect on market prices themselves. This point is absolutely crucial. It should be self-evident that there is no central planner, or group of them, in existence who can understand the intricacies of every different city block on a distribution grid, and how those parties could find ways to trade surplus collocated energy among themselves. Whether or not you agree with that, or whether you think it’s even important, this much is clear: we will never know the efficiencies in distribution that we could gain if we don’t remove franchise rights. They put an arbitrary limitation on the ability of local nodes to self-organize.

In a distributed era, especially with variable generating sources, the central planner can only do so much. Thus, we must allow the distribution grid to be built from the ground up to a certain degree. And it’s not even like this means laissez-faire distribution grids! The PUC will oversee all of it. It just means letting more parties participate, which is, if you think about it, an entirely underwhelming request.

This is why we can take notes from developing countries. Certain areas of the grid should be built from the ground up, for it will result in the most efficient deployment of DG and distribution infrastructure. That doesn’t mean the bulk grid goes away; this will first start happening at the grid edge. In time, it should lead to a network of interconnected generating nodes, each leaning on at first only the wholesale grid, but then also each other, in times of scarcity. This will indeed create a far more robust grid; if one local grid loses power, the macrogrid doesn’t flinch. A grid built as such would be far less susceptible to rolling blackouts.

Thus there are two concerns for DG from a distribution grid standpoint: the liberalization of energy markets and of infrastructure. First, regulators must create a market where these self-organizing nodes are compensated properly for selling power on distribution grids and lowering demand. Second, the utilities must cooperate in building a bi-directional grid. We must outlaw franchise rights, because if Hudson Yards and college campuses are any indication of what is possible with local generation sources, we should make sure that there is no practice that prevents this happening in a more public, scaleable manner. We need more Hudson Yards and fewer anti-CHP taxes.

Projects like Hudson Yards and UT-Austin are the most obvious argument for why the electric grid is not a natural monopoly. If one can build a microgrid for cheaper than what the utility can provide, then one doesn’t need their infrastructure. Interconnecting with them, though, is preferable in that it is an insurance policy for when the microgrid experiences issues, and microgrids can in return offer ancillary services to the bulk grid. Thus, while interconnection is not necessary in some cases, we should strive for regulations that encourage it.


In brief, the problem of franchise rights is the following: collocation helps solve peak demand issues, and franchise rights stand in the way of collocation efforts. When attempting to set up a retail market, if the infrastructure upon which the commodity is traded is controlled by a single entity, by divine right and not market logic, then it opens users up to the possibility of predatory practices. Especially when that entity is also selling power (but, again, more on that here). It may be that NYREV will be effective in protecting the user from such practices, but that doesn’t address the idea of self-organizing nodes.

Of course these changes will take years, but if we take NYREV to be ground zero for the future grid, we best get it right. And we can hopefully now see how infrastructure is an integral part of this new market’s incentive structure. Building a distributed grid will be far trickier than the centralized structure of old. It requires different rules and a different approach. That approach should be some combination of Edison’s and Tesla’s original vision. Here’s a heuristic to guide us: private, local power when possible, and wholesale, long-range power when necessary.

From this standpoint we can see CHP as a new form of baseload. Local grids may have CHP at its core, then trade solar and even wind among each other using batteries. Surpluses will be procured from the bulk grid, (HVDC solar and offshore wind may have a part to play yet) but distribution channels will also be used for local transactions. Such a complexly layered system will not be best planned centrally, but rather local nodes will be built from the ground up. No grid defection is necessary, but the only way in which this can happen is through a liberalization of not just retail energy markets, but the infrastructure upon which they’re trading.

Thus we’ll end with an anecdote. I approached Richard Kaufman, the so-called “Energy Czar” basically running the NYREV overhaul, and asked him about franchise rights. His response? “You know I can’t talk about that.” Despite how such a comment makes me vulnerable to backroom deal, tinfoil hat conspiracy theories, I’ll just say this instead: franchise rights are something we really should be talking about. From an infrastructure standpoint, will the benevolent despot utility act in our best interest? Consider me a skeptical citizen.

*Much of this history has been lifted and re-purposed from Gretchen Bakke’s The Grid

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