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A Song in the Key of E: Emissions, Efficiency, Equity, and Electrification

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A lot of folks out there (including we at RAP) have, for the last four decades, been devising ways to make utilities more economically efficient, their customers more energy-efficient, and the power system cleaner, sustainable, more equitable, and non-emitting. But now they have a problem: the world has changed, and suddenly we need more of that thing that they for so long tried to constrain. Now that the time has finally come to make the leap that has to be made if our climate crisis is to be solved, we’re like the proverbial deer in the headlights — if only for a moment. The prospect of wild load growth in electric demand is a bit hard to swallow at first. It’s both frightening and, well, electrifying.

Efficiency has been the central theme of electric sector reform for nearly a half century. It is the recognition that meeting a society’s energy needs is not simply a matter of “more is better” but rather of “no more than is necessary (and it’d better be as environmentally benign as possible).” This insight meant that we should not use energy when it was cheaper and more valuable to save it. And it meant that the traditional business model of the monopoly electric utility had to change—that profitability could no longer be linked to growth in commodity sales but to the least-cost provision of energy service and achievement of express public policy objectives.

So what’s the problem?

Well, it turns out that we need more, lots more, of a particular kind of energy — electricity from non-emitting resources — if we’re going to decarbonize as much of the economy as we possibly can. We need clean electricity for transportation, heating and cooling, agriculture, and industry. Are the regulatory reforms that we’ve advanced in the past thirty-odd years — in particular, integrated resource planning, revenue decoupling, and systems of performance-based rewards and penalties — appropriate to a vision that calls for a great expansion in our use of electricity and therefore a sea change in how we produce and deliver it?

The answer is yes, and it shouldn’t surprise us. It follows directly from an approach to economic analysis and policy — aimed at maximizing the net societal benefits of energy use — that we’ve relied on for decades. Thirty years ago, given the costs, expectations, and constraints we faced, the analyses pointed us in certain directions. Today, given different costs, expanded expectations, and more urgent constraints, they point us in new directions. In both cases, they told us how to minimize the costs — that is, maximize the benefits — of our desired path.

At a conceptual level, the problem isn’t daunting. It’s time to truly look at the energy system in its entirety, not just the electric system. How do we minimize the total costs of energy production and use, while meeting our climate, economic, and social goals?

It’s simple. The least-cost path is characterized by massive fuel-switching — from fossil fuels to clean, emissions-free sources, primarily electricity. But it’s not that simple. It doesn’t relieve us of the duty to make sure those new loads are as efficient as possible and are managed as efficiently as possible — indeed, it insists upon it, since any waste only increases costs. It isn’t right simply to say “Electrify!” How we electrify matters.

The good news is that our planning tools and regulatory methods are up to the task. We know how to think about the problem, consider alternatives, test uncertain futures. We know how to change course when circumstances dictate. And we know that utilities and market actors respond to the forces that act upon them, which means that we should still care deeply about whether their private financial incentives align with the public interest. We want these players to be successful by doing the right things.

So what does this mean for the utility business model? For the “wires” sides of the business — transmission and distribution — in both vertically integrated and competitively restructured markets, there’s still every reason to remove the “throughput incentive.” Whether load is growing or not, a utility whose revenues and profits are a direct function of kilowatt-hour sales (that is, of kWh deliveries) has a very powerful incentive to encourage usage, even if that usage is inefficient. We shouldn’t think that, simply because the electricity is clean, we have license to be profligate. The recent decision of the Massachusetts Department of Public Utilities to scrap Eversource’s decoupling regime, on the grounds that good ol’ fashioned price-only regulation will encourage the company to promote electrification. Probably it will, but, alas, it won’t give the utility much, if any, reason to care whether the electrification is in the best interests of society.

Revenue decoupling remains a critical element of a regulatory regime that aims for least-cost investment in, and operation of, the grid. It keeps the regulated monopoly focused on efficient operations. But, by itself, it doesn’t guarantee utility enthusiasm for preferred outcomes. Legal and regulatory obligations go a long way to solving that problem, but there’s a place for carrots and sticks too. Performance measures, with achievement rewards and penalties, overlaid on a decoupling mechanism, are powerful drivers of policy objectives.

What about the commodity side of the business? Again, in both vertically integrated and restructured markets, investment has been and will continue to be propelled in significant measure by policy requirements, such as renewable portfolio standards and emissions reductions requirements (e.g., cap-and-invest programs). These have been effective in transforming our resource portfolios and, moreover, have helped drive deep cost reductions in clean energy technologies, so that now the relative costs begin to favor the preferred investments. Important wholesale market reforms are still needed, but the outlook is good.

In those places where utilities remain vertically integrated, the question of how power costs should be recovered is of acute interest, especially where price risk has been shifted to consumers by means of fuel adjustment clauses and power-cost pass-throughs. How these mechanisms, intended to insulate shareholders from the volatility of global energy prices, distort management imperatives to manage power costs and investment for the long-term good of both consumers and shareholders has been well understood for decades. It’s time to revisit these tools, to consider whether and how they can be reformed to better align private incentives with the public good. Utilities and other load-serving entities possess the comparative advantage for bearing price, climate, and other market risks. Some simple fixes to power-cost recovery mechanisms will go a long way to reordering those risks and creating the environment in which clean, reliable electricity flourishes.

By all means, let’s let utilities and other market actors make money providing the energy and energy services we want. And that includes where increased load is societally most efficient—which is to say, the least-cost means of meeting demand for reliable, equitable service and, among other things, our climate goals.

Stay tuned for more blogs in this series. We’ll dig into some of the knottier regulatory challenges that large growth in load raises and try to answer the question: “Just what does a regulatory scheme look like that promises to achieve these ends?”

Building a Next-Generation Mix of Energy Resources: Practical Perspectives

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Earlier this fall, we explored next-generation approaches to competitive utility procurement in a webinar based on recent work by RAP and RMI — laying out recommendations for processes that consider all available resources, are aligned with policy objectives, and result in “least-regrets” outcomes. In a follow-up roundtable session moderated by Lauren Shwisberg of RMI and Carl Linvill of RAP, we heard more about this fast-changing landscape from a panel of practitioners:

  • Jim Baak, distributed energy resources manager, MCE
  • Kristin Munsch, director for regulatory and customer strategy, National Grid
  • Pat O’Connell, senior clean energy policy analyst, Western Resource Advocates (formerly of the Public Service Company of New Mexico)

Our panelists offered varying perspectives, working with the contexts of a vertically integrated utility, a restructured distribution utility and a community choice aggregator. They discussed what demand- and supply-side resource portfolio procurement looks like for each of them, challenges and opportunities, and what regulators can do to accelerate progress.

Advancing Storage: Progress in Markets and Regulation

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In a presentation for the National Association of State Energy Officials, Richard Sedano discussed the key role of regulation in assuring the successful deployment of storage technology as a flexible and cost-effective grid resource.

A Next-Generation Approach to Energy Resource Procurement

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Three trends in the power sector are converging to drive rapid and unprecedented change. State and utility climate goals are driving significant investment in clean energy. Fossil-fueled generation is aging and retiring at the same time that renewable energy and storage are increasing in efficiency and declining in cost. And increased electrification of end uses, including transportation and space and water heating, is allowing for demand-side flexibility that enables supply- and demand-side resources to complement each other.

Vertically integrated utilities are poised to spend at least $350 billion on power plants between now and 2030. But legacy procurement practices in most states are not poised to harness the three trends described above to take full advantage of next-generation electric systems and technologies. Such legacy practices are likely to result in suboptimal procurement outcomes. Flexible, clean and reliable energy optimization requires a next-generation approach to procurement, and a new report co-authored by RMI and RAP seeks to help regulators and utilities implement next-generation procurement practices.

Traditionally, procurement practices were designed to accommodate the limited needs and capabilities of legacy electric systems: Utilities delivered electricity from large, remote and inflexible power plants to passive households and businesses. This type of static generation will no longer meet the needs of utilities, customers, and states seeking to meet policy goals at least cost. Instead, states need an electric system where demand- and supply-side resources can be optimized on a flexible platform. Optimizing resources in this manner is feasible, but it will not happen without next-generation procurement, which allows these resources to be acquired in a way that enables their coordinated operation.

Legacy procurement practices are fundamentally flawed for several reasons. First, they often limit bids to a subset of available resources. For example, a utility request for proposals (RFP) might seek bids for only gas peaker plants, thus disallowing bids for Clean Energy Portfolios (combinations of solar, storage, and distributed energy resources), which can offer the electric services provided by a gas peaker plant while providing additional energy and non-energy benefits.

Second, legacy practices seldom specify the electric system need transparently, with the locational and temporal granularity required to attract optimized solutions. By failing to specify the actual need, utility procurement practices often favor inflexible fossil resources that may not optimally meet the specific need, while at the same time discouraging optimized portfolios of resource solutions. When utilities communicate the system need transparently with specifics of time and location, bidders can use the more diverse and flexible resource mix of today to offer targeted solutions to meet that need.

Finally, legacy procurement practices reward solutions to immediate system needs that often fail to identify “least-regrets” resource solutions that co-optimize system and environmental goals over a longer planning horizon. For example, investment in an inflexible, capital-intensive fossil project may meet near-term energy needs effectively, but may become obsolete before the end of the project’s physical life. A portfolio of resources may meet the near-term need while at the same time providing value to the end of its expected life. In such a situation, the latter resource is clearly preferable, and thus best-practice procurement evaluation should consider both near-term needs and longer-term needs in evaluating competing resource proposals.

A next-generation approach offers fixes for each of the flaws described above and offers principles and best practices as illustrated in the figure below. The report explains all of the principles and best practices in detail and with examples where best practices have emerged. In this blog, we want to focus on what regulators can do most immediately to usher in a next-generation procurement paradigm — one that enables energy optimization to meet reliability and environmental goals at least cost over the planning horizon.

To enable next-generation procurement, regulators can jump -start their progress with four actions:

  1. Order utilities to transparently define and validate the system need;
  2. Implement a resource planning process that engages stakeholders, which can ensure that the system need is specific and placed in the context of system planning;
  3. Make modeling assumptions and tools as transparent as reasonably possible to all stakeholders to allow the system need to be further vetted and tested within the stakeholder process; and
  4. Align procurement RFP specifications with vetted resource planning outcomes.

Regulators can promote a beneficial competitive outcome by requiring bidding processes that are open to all who meet reasonable qualification requirements. Next-generation procurement initiates an RFP process that is transparent and fair to all bidders, where regulators allow all bidders to both design solutions to meet needs and to compete on a level playing field. Regulators should further ensure that the process allows bidders to offer all the capabilities their resources and resource portfolios possess. Finally, regulators should ensure that codes of conduct are established to ensure fair competition if the incumbent utility or an affiliate of the same holding company is allowed to bid on the solicitation.

Regulators should structure a next-generation procurement process so that the grid and societal values of resources are clear and transparent and can be applied to the evaluation of bids to select optimal solutions. Evaluation criteria should be transparent and clearly communicated to bidders well ahead of bid deadlines. Regulators may also want to require a third-party, independent evaluator to supervise utility bid evaluation to ensure that it is done in line with the established evaluation criteria.

Finally, next-generation procurement requires utilities to bring the best portfolios to a utility commission for consideration. At this point, regulators can exercise their discretion to consider trade-offs among bids, and if necessary, require additional modeling to determine the optimal portfolio to meet power-system and regulatory goals.

Regulators can navigate the difficult waters of emerging technologies and evolving business models by aligning procurement practices with their regulatory goals using next-generation procurement practices. The practical guide demonstrates to regulators that achieving this alignment will point the way to optimized system solutions, which are:

  • All-source, to effectively utilize available resource options;
  • Objective-aligned, to enable investments to address specific utility needs or state policy goals; and
  • Least-regrets, to limit investment in suboptimal long-term solutions.

Why Rate Design in New England Needs a Refresh

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Looking ahead to 2030 and then beyond to 2050, the majority of New England states have set ambitious clean energy goals. The growing adoption of new technology empowers energy customers to play a direct role in making these goals happen and to make their own energy choices in ways not available 10 years ago. But one piece of this puzzle is still largely missing: The design of electricity rates by utilities serving the region simply has not kept up with customers’ changing needs.

We set out to examine this mismatch between modern needs and outdated rate design recently in a four-part series of policy briefs. What we found shows that there is substantial room for improvement in residential pricing. The New England large utilities’ rates do not work to realize customers’ current-day needs, nor do they accurately reflect the time-varying aspect of grid costs, from electricity supply to transmission and distribution to regional capacity and charges.

We’re revisiting RAP’s series to highlight the opportunity at hand for utilities and regulators: Updating rate designs can empower consumers control over their energy choices, including low- and moderate-income ratepayers. Modern rates must be affordable rates for all ratepayers, and in turn these rates can help states meet their policy goals for clean energy and affordability. A few leading examples of promising rate design already on offer suggest that this challenge can be met.

A Rate Design Disconnect

The first brief, New England’s Rate Design Disconnect: Analyzing the Region’s Wide Variation in Electricity Bills, tackles one of the most puzzling aspects of rate design by New England utilities: Rates are all over the place, varying among the different states to a degree that is greater than that seen within any other U.S. region. Moreover, when we tried to figure out why that is the case, there was no substantial good reason. This hints at a lack of good information flowing between and among regulators and utilities. That lack of information suggests an opportunity for New England states to set benchmarks and collect data on utility costs and performance for use in better standardizing cost data, analysis and rates.

The Affordability Challenge

The benchmarking process alluded to above could particularly benefit low- and moderate-income customers, who face a significant energy burden, and our second brief, Making Basic Service More Affordable: Electricity Rates for Low- and Moderate-Income Ratepayers, focuses on rate designs for low- and moderate-income customers and how they can be improved. We review and compare tariff discounts from utilities in four New England states, and highlight the example of New Hampshire’s Electric Assistance Program, whose sliding-scale design targets greater relief to those ratepayers who need it most. New Hampshire also provides LMI rate uniformity in design and cost allocations across all the state’s utilities.

Designs that Work for Customers: Time-Varying Rates Give Options

The last two briefs in our series, published in 2020, focused on the modern imperative for rates around the region to shift more to time-varying options and models, in which energy and its delivery is valued in part according to when it is used.

Time-varying rates (TVRs) work well for particularly modern needs such as electric vehicle charging and home storage batteries. This is the focus of our third brief, Rate Designs That Work for a Modern, Customer-Oriented Grid. The brief examines the examples of a few utilities, such as Green Mountain Power (GMP) in Vermont and Liberty Utilities in New Hampshire, that are putting specific EV or battery storage rates in place. Since we published this brief, GMP has begun offering a time-of-use rate for EV charging that features a peak period of 1 p.m. to 9 p.m. on weekdays. (That may be slightly longer than ideal for shaping customer behavior, an idea we explored in the last brief in our series.) GMP separately offers EV customers a chance to avoid “peak event” pricing by having the utility give advance notice that it wishes to switch off their chargers during such an event. Customers can opt out of any given critical peak event notification but will then pay a critical peak rate of 68 cents per kWh to charge during that time; that rate is high enough to be a definite price signal to avoid critical peaks, and that’s the tradeoff for discounted off-peak rates.

A number of the existing time-varying rate designs offered by New England utilities have little uptake from consumers. In the final brief, Time-Varying Rates in New England: Opportunities for Reform, we look at a set of these and concluded that in general, these rates have overly long peak periods and that the differences between peak and off-peak pricing are not large enough to drive customer behavior (i.e., shifting usage to when it is cheaper for the grid to serve it). New rates in New Hampshire are a promising example of a design that fixes these problems, with a peak period of no longer than five hours and a critical-peak-to-off-peak price ratio of more than 3:1. And recently released data from beyond the region, in Maryland —more on that in a moment — shows robust results for well-designed time-varying rates.

What does all this mean for regulators and utility rate designers in New England?

  • First, discounts for low- and moderate-income customers can be provided on a sliding scale and can be consistent across utilities, following New Hampshire’s model.
  • Second, time-varying pricing is the most tested and leading rate design model to meet modern needs of customers and the grid.
  • Third, utilities and regulators can design time-varying rates that send customers a clear signal to shift their usage to lower-priced and lesser polluting hours.
  • Fourth, time-varying rates empower customers to take more control of their energy consumption and make use of affordable technology (smart thermostats, smart appliances and EV chargers) that can more easily time when they use energy. This helps customers reduce their bills while also reducing grid costs and pollution.
  • Finally, recent data on time-varying rate pilots from Maryland — a state with a restructured electricity market like most of New England — offer encouraging evidence that good rate design can pay off for consumers and the power system alike. The results from pilots by Baltimore Gas & Electric, Pepco, and Delmarva Power & Light found that time-varying rates reduced peak-time usage across all customers enrolled in the pilots by 10-15%, and low- and moderate-income customers were able to save 5-10% on their bills, with other customers saving even more.

Antiquated rate structures are one of the reasons that New England’s energy burden is relatively high compared to the U.S. average. And there are growing questions about whether the management of the region’s power market is designed to meet the needs of the future. To enable the grid flexibility New England will need to decarbonize, customers will need to be empowered to target their energy usage to times that are cheapest for them — and optimal for the operation of the grid. Modernized rate design is an essential ingredient of this modern grid recipe.

Energy communities with grid benefits: A quest for a blueprint

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Throughout Europe, energy communities are becoming more abundant as the continent moves towards a cleaner, greener future. It’s easy to see why many people find them appealing — these communities allow organised groups of energy consumers more of a say in their energy choices, while saving money. Member States are discovering that enabling individuals to become more proactive in the energy world helps increase energy democracy, alleviate energy poverty through broader access to money-saving projects, and facilitates the deployment of decentralised renewable energy. Perhaps most importantly, energy communities can drive positive social cohesion and innovation.

As energy communities gain traction, questions pop up: Do energy communities deliver real‑world benefits to the operation of the electricity grid? How do these cooperative efforts differ from commercial aggregators that offer similar services?

Bram Claeys gathered insights from community energy business models and pilot projects to elucidate the elements that provide tangible grid and system benefits and help create a blueprint for energy communities to support the power system. By first laying the groundwork and positioning energy communities in the European energy framework, Claeys builds the case for the system benefits of energy communities and business models within those communities.

Offshore wind should be seen as a joint European resource

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Offshore wind is a special resource. The fact that there is little legacy infrastructure, coupled with the impressive European ambition of expanding the current capacity of 12 GW to 300 GW by 2050, raises an important question: How can we develop only the minimum infrastructure needed, at lowest cost, and operate it to the maximum benefit of European consumers?

The answer lies in utilising this resource collectively.

To have any chance of exponentially increasing offshore wind capacity in time for the 2050 net-zero decarbonisation goal, we need to move beyond approaching offshore energy as a coastal state resource, beyond even approaching it as a regional resource at sea-basin level.

Simple arithmetic tells you that 300 GW clearly exceeds the needs and wants of the coastal states themselves, individually or collectively. It is therefore at best doubtful that they would develop the necessary offshore infrastructure in a sufficiently timely or coordinated fashion.

We should consider offshore wind as a joint European resource and opt for joint governance every step of the way.

The cost of the technology has decreased to the point that private money is willing to build wind parks without direct public financial support.

The prospect of exploiting wind over the seas at this scale, however, presumes one major prerequisite — developing the offshore grid that would gather offshore energy production and deliver it to where it is needed. This is the crux of the offshore wind success story.

The current practice of coastal states linking wind parks to their onshore power system one by one is not nearly as effective as more cooperative solutions. The European Commission acknowledges this in its recent offshore renewable energy strategy (“the strategy”), which calls for the collaboration of all parties concerned.

So, how cooperative would we need be to have 300 GWs by 2050? We should consider offshore wind as a joint European resource and opt for joint governance every step of the way.

Joint planning

Each element of the offshore grid needs to be built with a masterplan of a fully developed, meshed grid in mind. The strategy refers to the need for anticipatory investment and envisions setting offshore wind capacity targets for each seabed and cooperating to define suitable locations for industrial marine energy development.

No framework for incentivising anticipatory investment would work as efficiently as a jointly developed masterplan that optimises the value of each component towards developing the overall resource whilst considering environmental and other use limitations.

Joint development and financing

The default case for transmission development is that it be planned and built by a single incumbent transmission system operator (TSO) or two neighbouring TSOs. This approach is problematic for three reasons.

First, it runs the risk of coordination problems because the value of investment in new offshore grid elements is dependent upon the timely completion of other elements developed by other TSOs.

Second, the entire grid can be built quicker and cheaper if its components are awarded competitively in packages of discrete grid elements.

Third, putting together the puzzle of nationally financed grid elements is likely to create an offshore grid where various otherwise similar joint-use elements have different development costs, depending on the national TSOs’ remuneration schemes, regulatory context, ownership and costs of capital.

Additionally, this would constrain and delay development by making it reliant on the financing capacity of individual TSOs in each of the individual coastal states.

The strategy shines a light on these problems. It refers to the UK’s offshore transmission operator regime as a potential alternative to TSO-led grid development.

This is not the time for gradualism.

Wind farm developers have the option of designing and constructing offshore connections or enlisting an offshore transmission operator to do so. Regardless of who builds the assets, the offshore transmission operator will be responsible for the ongoing ownership and operation of the connections.

The strategy also recognises the financing gap and suggests the use of various EU funds for enhancing both offshore and connected onshore network development.

More importantly, it suggests the use of the EU renewable energy financing mechanism for additional funding.

This mechanism allows Member States to finance renewable projects anywhere in Europe — in addition to domestic and bilateral cooperation projects — with the primary intention being to fill the gap in ambition between individual countries’ contributions and the 2030 EU renewable target.

Member States pay voluntary financial contributions into the scheme, which will be used to tender support for new renewable energy projects in all Member States willing to host such projects.

The strategy, however, fails to take the final step of bringing the construction and the financing of the offshore grid under the joint governance framework that would be required to tackle these barriers.

It is one thing to say that any Member State can finance one or more offshore wind parks, but it is quite another to consider the complex undertaking involved in creating the offshore grid that would make best use of the wind parks possible in the first place.

A joint framework would mean that any Member State could contribute to the financing of offshore renewable energy grids (and procure generation) through EU auctions, e.g., the EU renewable energy financing mechanism, and receive renewable credits to be counted against the country’s contribution towards the joint 2030 EU renewable energy target.

Joint operation

Disjointed operation of an integrated offshore wind energy grid will never deliver the full value of such a massive undertaking. Siloed operation also fails to provide adequate investment signals for wind farms.

Regional Coordination Centres were introduced in 2019 as the newly created entities for enhanced regional coordination of system operations. The strategy envisions this as the mid-term operating regime and only mentions establishing joint operational control by regional independent system operators as a long‑term possibility.

We should rather use the unique characteristics and challenges of the offshore energy resources as an ideal opportunity to implement the regional independent system operator model now, in anticipation of possible application elsewhere in Europe.

This is not the time for gradualism. Failing to scale up offshore wind with onshore wind and solar on the stated timeline would mean either the need for other, even more challenging undertakings, or the failure to reach agreed EU climate targets altogether.

The strategy sets a clear path but concedes too much to politically driven gradualism. We should instead acknowledge and embrace the leap that will be required to achieve Europe’s ambitions for offshore wind.

We should seize the opportunity to plan, finance and operate the offshore grid as a truly European resource and as a pilot for European power system operation.

We should seize the opportunity to throw a stone into the sea and find out how far the ripples spread.

A version of this article originally appeared in Euractiv.

Vehicle-to-Grid: Right At Your Doorstep

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​In a webinar presentation, Jeffrey Taft of the Pacific Northwest National Laboratory, Chris King of Siemens, and Willett Kempton and Sara Parkison of the University of Delaware discussed strategies for moving forward on the adoption of vehicle-to-grid technology, including grid architecture needs, interoperability and regulatory improvements. David Farnsworth moderated the discussion.