Should regulators put limits on DERs?
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- Aug 23, 2019 3:00 am GMTAug 23, 2019 2:41 am GMT
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This item is part of the Special Issue - 2019-09 - Distributed Energy Resources, click here for more
In an unmistakable sign that change is underway, people in the power business have begun to ask new and different questions. Are DERs (Distributed Energy Resources) net positive for consumers and should grid administrators and regulators be dedicating resources to integrate them? More generally, considering all the other options on the table, to what extent should DERs be accommodated and encouraged in energy policy and planning? In one recent example, on July 18 the Ontario Energy Board released plans for a new consultation process on DERs, to consider possible changes to the regulatory framework that it expects will “have long-lasting impacts on Ontario’s energy sector”. Alberta's Distribution System Inquiry is looking at similar issues, from a broader perspective.
These questions start with a dramatic opening scene. In an industry characterized by cautious long term investments, an entire category of competitors is cropping up that doesn’t play by the old rules, and which seems poised to disrupt major parts of the system. Many analysts believe that modern societies are at the beginning of a historic “Energy Transition” moving to a future with much greater use of DERs. Should the rules enable the transition, try to limit it, or remain studiously neutral?
The brave new world
It is possible that in the not too distant future, ordinary customers will have digitally controlled demand management equipment behind the meter that effectively makes them real time suppliers on a second-by-second basis. This kind of equipment could reduce costs for the customer, and enable a wide range of efficiencies in grid operation. Those with access to a little more capital could add storage and generation to their own supply mix behind the meter, possibly financed through their home mortgage or leased from a utility-approved vendor like water tanks are now. Think about this for a second. It’s potentially ground-shaking. Customers could provide reliability-enhancing and cost-reducing services to their local grid, while reducing their own electricity bills. Grass roots entrepreneurs would be engaged in real time competition with wholesale grid assets. Who would want to stand in the way of innovations like that?
Regulators and policy makers have to respond when fundamental challenges emerge to how existing infrastructure is used. Regulatory or legal rules designed to limit customers’ abilities to make economic choices will not likely stand the test of time. Having customers contributing to load management and reliability is just too attractive and sensible. However, there are potential problems to grapple with. The adaptation costs may be significant, and will require attention in some cases. Although the precise costs can’t be determined in advance, regulators and consumers alike will have to provide for the possibility that these transitional costs will soon dwindle in comparison to the overall costs borne by the consumer. If so, transitional costs will not likely be an ongoing barrier to new DERs. The key is recognizing that there are significant dangers in overestimating these costs, just as there are dangers in underestimating them. Overestimating these costs is a risk primarily to the growth of a promising new market, while underestimating them is a risk primarily for the predictable recovery of costs for existing shared local grid assets.
Regulatory rules and legal limits will most likely be imposed in cases where customer based equipment creates sizable new costs that are effectively transferred to other customers. Situations where such cost transfers are significant will probably be unusual. However research is needed, to be sure. It will be important to define and recognize cases of cost transfer, to ensure that the energy transition is not seen as unfairly redistributing costs amongst consumers. Expect debates about cost sharing to rise in both importance and visibility.
How to manage a transition when the specifics are unknown
Managing the growth of DERs is more complex than a discussion about renewables or carbon reduction because DERs vary so widely. Some DERs may not reduce emissions at all and some DERs may actually increase net consumer costs, or could do so for a period of time. DERs should not escape responsibility for costs or emissions just because they are small. However, just as rules for small consumers are less detailed than those for large consumers, the regulatory tools for ensuring DERs are built and operated responsibly must be suited to their scale of operation.
One of the first orders of business will be to clarify and refine the principles governing which system upgrade costs are shared or should benefit from risk-sharing amongst a broad base of customers. Much of the electric power system is built on a rock solid assumption that has historically enabled large long term investment at favourable rates. The assumption is simple: Although market signals should drive most business decisions, certain essential electricity services require revenue streams above and beyond the market. The examples of firm non-market revenue streams are countless, usually dating to past policy decisions designed to encourage one type of investment or another.
Although DERs may challenge the expectation for non-market revenue streams in new ways, an appropriate response to DERs is typically built on at least two distinct parts:
First, when DERs crop up in the market, paid for without direct subsidies, under what conditions is it reasonable for the system to accommodate and integrate them through grid connection rules, installation of control equipment and local system planning? You might call this “accommodation of market-based DERs.”
Secondly, under what conditions, if any, is it reasonable for central procurement and public policy to proactively facilitate the deployment of DERs, on terms comparable to those used to facilitate deployment of other forms of power services? This second question is better characterized as “policy designed to encourage the most desirable kinds of DERs.”
Either way, government, regulators and the public will have to come to terms with what kind of non-market revenue streams are justifiable going forward.
To ensure that a consistent set of principles are applied, policy makers will likely need to answer two distinct questions. First, under what conditions should all customers be expected to pay for DER grid integration costs, and second, when should non-market revenue streams, comparable to other parts of the power system, be made available to DERs? These are early days for DER, but smart money will likely bet that the answer will often be yes to accommodation and integration, and a much more skeptical, case-by-case response to condoning non-market revenue streams. Such conclusions are defensible because they can be expected to produce the most competition and the best long term results from the consumer perspective.
What grid costs are shared
In the past, customers have often been obliged to pay for suppliers’ grid integration costs and various types of reliability payments, to varying degrees, in the interest of building a dependable power grid. (Broad sharing of many types of grid costs is widely accepted.) This was easy to justify when there were few suppliers and many customers. It’s harder to accept if there are thousands if not millions of suppliers.
Regulators in many jurisdictions have identified an important exception to the general policy of sharing grid costs. The cost of a generator’s physical connection to the grid is often paid for by the generator, not shared with other customers. (This is the case in Ontario and in many other jurisdictions.) For a number of reasons, including both efficiency and fairness, it makes sense that generators pay for their own connection costs but not for shared consumer-serving grid infrastructure. The core principle here is entirely rational: the entity that controls and directly benefits from each increment of capacity in discretionary capital infrastructure is in the best position to decide how much money to invest in that specific infrastructure. When suppliers pay their own connection costs, they naturally ensure that connection infrastructure is correctly sized. In this way, regulators have neatly ensured that the risk of overbuilding or underbuilding the connection is never offloaded to other customers. This relatively obscure principle will become much more relevant as the number of suppliers rises.
Can this kind of economic cost-sharing principle be extended into a future where many companies, possibly the majority of customers, are suppliers in one sense or another? The future path of the power system will be shaped by the answer to this question.
"Expect debates about cost sharing to rise in both importance and visibility."
As consumers and policy makers face an expanding range of choices, one over-arching principle will become apparent: Don’t let the small stuff obscure the larger opportunities. During any process of change, transition costs and adaptation costs loom large at the beginning, partly because of uncertainty. However such one-time costs are often overshadowed by historical changes. One of the key functions of regulators will be to work with the industry and policy makers to reduce the uncertainty surrounding transition costs.
Any attempt to design controls against overbuilding wires and transformers will have its own internal challenges. In addition to requiring extensive research, and implicitly a review by regulators, such controls have to weigh the risks of ill-effects caused by over building against the ill-effects of controls.
Research will be needed to test and qualify the general view that the cost of upgrading wires-related infrastructure to accommodate DERs will be small compared to the overall energy costs paid by customers. As long as there are no direct subsidies to DERs, this expectation should withstand scrutiny in the great majority of cases. However, it can’t be presumed in all cases. While it may be reasonably safe to assume that over time, the costs of wires upgrades as a whole will pale in comparison to the costs of the commodities flowing through the grid, accountability is needed for both wires costs and commodity costs.
Consumers installing their own DERs experience a natural ongoing form of commodity cost accountability by virtue of paying the commodity components of their energy bills. It will likely be necessary to institute analogous systems that avoid overspending on upgrading wires, transformers and switchgear, even if these wires-related expenditures generally enable energy cost savings many times larger upstream and downstream. In summary, even if there is general acceptance that the cost of upgrading wires-related infrastructure to accommodate DERs will be small compared to the overall energy costs paid by customers, it is necessary to have transparent research results available, to identify the qualifications and exceptions to the general principle.
All of these assessments are based on the expectation that DERs themselves will generally be built with private money, without subsidies. In many cases – perhaps most cases – policy makers will not be inclined to condone direct subsidies to DERs. As a result, DERs will likely be relatively market disciplined from the early stages, a quality that will add to their durability and strength. Services from DER will only make it onto the grid at times and places where they reduce costs. Real time price competition is in the nature of transactive energy.
A word of explanation: In this context, commodity costs are the charges for kilowatt-hours consumed, whereas grid costs are the costs for wires-related delivery and maintenance services, usually billed as demand charges or monthly fees. Historically, on most consumer bills, commodity costs have been much higher than grid costs.
Facing uncertainty and opportunity as a single package
While the specifics of the emerging DER industry are not yet known, a few aspects of the transition are foreseeable.
In the plannable future, it will probably be impossible to fully analyze the costs and benefits of each DER installation to assess precisely whether it’s net positive for the grid and for other customers.
It will be possible however, to identify categories and regions where benefits are most significant, and conversely, where the risk of DERs off-loading costs will be high. Regulators and system planners will very likely want to devise rigorous common systems for assessing the costs and benefits of DERs, and to disseminate signals about where to build, and where to avoid building DERs.
In parallel with all this analysis, DER is likely to grow significantly on the ground, delivering many benefits and probably a few headaches, even if it does not enjoy explicit policy or other types of support.
DER will grow more quickly in areas where regulation and policy encourage it to provide services to the grid, services traditionally provided by larger suppliers. Think for example of congested downtown cores having difficulty siting new transmission lines to supply growing load. Two prime examples of this would be Toronto and New York.
Mitigating the risk of stranded costs
The speed at which DER development proliferates will be determined largely by the readiness of electricity customers to invest their own money in additional infrastructure. This is a natural brake on overly rapid new investment, and reduces the likelihood of significant overbuilding or uneconomic investment. When so many market forces are in play, it’s possible that only very limited forms of regulatory oversight will be needed.
At the same time, regulators and policy makers will be concerned about minimizing the chance that inaccurate economic signals might be received by sizable groups of customers, causing inappropriate over-construction of DERs. There may be need for judicious, carefully-applied precautions of this nature, given the degree of uncertainty. However, such precautions may prove largely unnecessary over time, as long as information on where not to build is widely available, and all participants are held equally responsible for their share of grid costs.
There will be debate and consternation over the risk of stranded costs. However, as the Ontario Energy Board and other regulators have recognized, the worst of these risks can be avoided with a simple approach to managing existing costs: Decouple utility revenue from customer volume so that customers are not discouraged from innovating with their own money. Anyone who is connected to the grid must pay an equal share of the costs of that grid, proportionate to their maximum usage of the grid. With such a system, anyone can try new forms of supply and load management without being exposed to punitive costs, and the capital costs of shared infrastructure will be covered.
Considering all these elements together, viable options begin to take shape. Even at this early stage, solutions are readily available for transitioning to a reasonable framework for responding to DERS.
"As a general rule, any limits on DER development should flow naturally from market signals and consumer preferences, rather than being created artificially through public policy."
Regulators and policy makers will need to:
a) Accept that the transition will be a little chaotic and uneven in its benefits, and that a degree of uncertainty is part of the package when partaking of any new opportunity.
b) Devise common transparent methods for assessing the benefits of DERs.
c) Conduct research on the net costs of grid upgrades to accommodate DER, develop trusted durable methods for assessing the extent to which a DER project is likely to impose new costs on other customers, or whether it is likely to do so at all when considering the full suite of benefits, and consult comprehensively on any proposed remediation methodology rigorously before taking action.
d) Devise rigorous common systems for disseminating signals about where to build, and where to avoid building DERs, based on the systematic assessment of costs and benefits.
e) Continue to hold suppliers responsible for their connection costs while sharing the cost of broadly beneficial upstream grid enhancements widely.
f) With these principles as a baseline, allow the market to develop freely, and try to alleviate impediments to market-driven investment.
g) Develop new forms of planning that are comfortable relying more heavily on market driven resources.
The case for DERs
Although the core services required for grid stabilization will continue to be provided by central operators and bulk suppliers at the grid level, it appears there is no stopping the DER train. New technical capabilities at the grid edge will ensure that some of the services contributing to grid balancing and reliability will be delivered in a more distributed format. The current allocation of grid management responsibilities, developed before controls and intelligence were easily available at medium and small scales, will need to be updated. It will not mean total devolution to the grid edge, but it will likely mean significant reallocation of responsibilities.
The need to make the case for DERs is different from the need to make the case for other types of grid assets. Because most of the investment will be born privately by customers, most of the risk is entirely private. For regulators the primary challenge will be to assess the costs and benefits of new investments in shared infrastructure, and to do so in a way that inspires trust and confidence. This information will be used primarily to determine if the incremental changes in cost sharing resulting from a given type of proposed DER are significant. Although regulators have typically concluded that it’s best to share costs widely for most examples of new grid infrastructure, it’s even better to check first. There should be little reason for any consumer to worry about unfair advantages going to DERs.
"Accountability is needed for both wires costs and commodity costs."
In general DERs will be entering the market needing to recover all their costs, both capital and operating, whereas many existing assets will have an advantage in the same market, recovering parts of their capital investment through legacy non-market mechanisms. (In Ontario it’s the Global Adjustment, but there are parallels in many other jurisdictions.) DERs aren’t just a new source of supply – they are also a new approach to financing supply infrastructure, with more risk being accepted by the initial owners.
As a general rule, any limits on DER development should flow naturally from market signals and consumer preferences, rather than being created artificially through public policy.
As the discussion unfolds, two unmistakable conclusions are evident. First that change is coming and no one will be left unaffected. Second, it will be important in the short run for regulators and policy makers to undertake research to assess the risk that DER accommodation will unduly increase costs for consumers, and in particular to answer the key question: what rules and regulations would significantly decrease the risk that that the costs of a more complex integrated system will raise overall costs to consumers? Only after answering this broader question can rules be properly designed to control the proliferation of DERs, if such control is necessary at all. Much of this work will benefit from collaboration across jurisdictional and national boundaries. Although regulatory systems will vary by location, everyone will be dealing with similar questions on how to balance the desire to capitalize on new opportunities with the need to reduce the risk of disproportionate spending on grid upgrades.
In effect, the case for DERs will be made over and over again at the edge of the grid, as each customer decides what kind of equipment to buy and install, and as each grid operator looks for more efficient and effective ways to use distributed resources and smart technology to improve grid operation and development.
There will be innumerable opportunities to challenge the case for DERs as each installation undergoes its own cost tests with its owners, and regulators develop increasingly capable and transparent models for estimating costs and benefits.
That kind of exposure and testing could lead to a more rigorous review of infrastructure, and a more efficient and responsive system for all customers.
It is not a zero risk path. Unfortunately, a zero risk path does not exist. In fact, an evolving system that enables and cultivates well-informed real time customer choices may be the most risk-averse option of all.
— Jake Brooks
An earlier version of this editorial was published in IPPSO FACTO, the journal of the Association of Power Producers of Ontario.
For more information, readers may contact the author at
Note: This posting contains conjecture and opinion and should not be relied upon as definitive or used as a guide for any kind of investment decision. It contains the views of the author and may or may not reflect the views of APPrO or any APPrO members.
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