Category Archive: Blog

Utilities Want to Provide EV Fleet “Advisory Services.” Should Regulators Approve?

As the electrification of vehicle fleets goes mainstream, fleet owners are facing a gauntlet of challenges, starting with engaging their electric service provider. The utility response of providing “advisory services” is both creative and presents new challenges for utility and air regulators.

Advisory services, whether offered by utilities or third parties, are designed to educate and enable fleet managers. The goal is to fill the gap between what fleet managers already know about transportation and what they need to know about electric transportation.

RAP recently facilitated a conversation on this topic, inviting a representative of a school district, a utility company, and several third-party transportation service providers to discuss their perspectives and better understand the challenges.

In our webinar, “So, How Does This Work Again? The Role of Advisory Services in Fleet Electrification,” Timothy Shannon, transportation director at the Twin Rivers, Calif., Unified School District; Matt Stanberry, managing director at Highland Electric Fleets; Ann Xu, founder and CEO of ElectroTempo; and Jason Peuquet, strategy and policy manager of clean transportation with Xcel Energy, shared their perspectives with RAP’s Camille Kadoch.

From my perspective as a former utility commissioner, I was asked to serve as the “respondent” and identify the pertinent regulatory issues.

Reviewing Advisory Services Proposals

At first glance, the expansion by utilities from offering a commodity to offering professional services may seem unprecedented. But actually, advisory services are a more visible form of what utilities used to refer to as “marketing key accounts,” a focus that utilities regularly had that helped them stay in touch with sizable commercial and industrial customer segments, and for which they were allowed to recover reasonable expenses.

The point here for regulators is not that this is different, but instead that this is more overt, and coming at regulators in a more robust and comprehensive manner. Advisory services also have a component of market development, a similar quality found in demand-side management programs. Note that third-party support to help utilities better serve fleets is not so different than the energy auditing support that contractors provide energy efficiency programs.

So what have we learned from those experiences, and how do we apply what we’ve learned in this context? This history can help regulators understand how to proceed when a utility says it wants to engage in these ways, that it will incur costs for which it wants recovery, and possibly even that it seeks earnings on those costs.

What is the right regulatory construct to apply here and what needs to change? The slide below provided by Xcel’s Jason Peuquet, does a good job of illustrating the range of comfort to discomfort of the regulatory process in this context. On the right-hand side, regulators are comfortable with rate design. We’ve had a 100-year history with that. Advisory services the new phenomenon over on the left about which we are less certain. The pieces in the middle come with a different levels of comfort.

Meeting Fleet Customers' EV Needs

Source: Xcel

Costs and Benefits

Electrification means that a utility is creating new load. But the regulator still has a key role to determine the answers to two questions: Is the utility proposal creating the kind of load that is appropriate? And is the load being managed effectively from a system benefit perspective? The regulator needs to ask:

  • What is the utility aspiring to do or become?
  • How does this new service change the utility’s current role as a public service?
  • Does investment in advisory services align with existing regulatory principles — i.e., are these investments just and reasonable? And are they least cost?
  • How should costs be allocated — i.e., who pays for them, and why?
  • Do today’s costs deliver future societal benefits, however difficult they may be to quantify?

A narrow interpretation would focus on who is the cost causer and what they should pay. That would put all the burden back on the fleet services. That is fine, and internally consistent in a narrow framework.

But recognizing that we are working in a broader arena, we acknowledge that we are not just making investment to help fleets. We are doing “demand creation.” This puts the regulator in a position to look at today’s costs that are known and knowable, and at future benefits that are speculative and uncertain — although we know they are out there. How do we get comfortable matching today’s costs with future benefits? Those benefits range from consumer savings, to lower-cost grid management, to the many societal benefits like reduced air emissions and improved health outcomes.

21st Century Load Forecasting

At the same time regulators need to recognize that doing this work — letting utilities build load through advisory services — ushers in a new aspect of load forecasting. Fundamentally, the regulator-utility relationship will need to further evolve. Effective regulatory oversight of load forecasting requires greater engagement of the utility, with lines of inquiry such as:

  • Will advisory services requests be strategic and narrow, seeking only to develop certain types of load?
  • What kind(s) of load do you want?
  • Do you just want maximum growth, no matter where it comes from?
  • Where on your system do you want it?
  • At what time of day do you want it?

Requests for approval of advisory services will bring with them a new complexity about understanding load. So, this is not only an inquiry into costs and benefits (both short- and long-term); it is also a challenge into understanding how the utility is changing its relationship with certain customers — from the traditional provision of a commodity, a blended commodity and service-based relationship. The regulator is confronted with understanding that this service-based customer engagement is interwoven into utility decisions concerning capital asset investments in infrastructure. For it is through effective advisory services that these capital assets become viable and reasonable assets.

Finally, in this world where the utility has the onus to make and justify these proposals, it is the regulator’s role to ensure that the utility is clear in what it aspires to become. And this will require even more questions for regulators to raise:

  • How does this service fit in the utility’s portfolio?
  • What is the utility’s longer-term sense of itself as a commodity and service provider?
  • Is the regulatory called to assist them and nudge them on their way? Or on the contrary, is your task to “keep them in their lane?”
  • How am I going to manage the commission’s relationship with that utility into the future?

One way or another, transportation electrification represents a new set of evolutionary forces upon the utility-regulator relationship. Awareness and preparation will make the ride more enjoyable.

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

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?”

Surf’s Up: Catching the IIJA Wave

I’m learning how to surf. For my birthday, my kids got together and bought me a surfboard. One day last summer I spent about three hours in the waves off of Popham Beach in Maine trying to figure things out. After about 60 attempts — no kidding — trying to catch a wave, I finally caught one. But I had help. I got tips from my kids, and from other surfers about things, like when to paddle hard and where to place myself on the board. When I finally caught that wave, all that paddling and the soreness in my neck and shoulders faded away. I was lifted and carried forward at easily three times the speed while the others alongside me and I were effortlessly propelled forward toward the shore by the energy of that wave.

I was recently reminded of my first day surfing as I read an order from the North Carolina Utility Commission (NCUC) in which it recognized that it too could use a little help better understanding the implications of the wave of federal funding — $1.2 trillion over eight years) — that is about to reach the states.

The Infrastructure Investment and Jobs Act of 2021 (IIJA) makes available billions of dollars for investment in utility infrastructure, including support for electric vehicle charging, smart distribution grid improvements, energy storage, and water system resilience and security. Referring to the IIJA, the NCUC opened its order with a “preliminary conclusion”:

It is in the public interest for the public utilities of this State to fully and carefully consider taking advantage of these available federal grants and loans, in order to promote adequate, reliable, and economical utility service to the citizens and residents of the State.

The order poses basic questions like:

  • Which federal programs could assist utilities in meeting their obligations?
  • What actions does the NCUC need to take to facilitate access to the funds?
  • What other organizations will utilities need to coordinate with?
  • What actions are other state agencies taking or considering?

More than a dozen utilities and others provided comments to the NCUC in this docket. The order not only brought together these parties, encouraging their insights and testing their ideas, but it also created a larger public conversation about the best ways to spend federal dollars for utilities in North Carolina.  It is the Commission’s role to ensure that the power sector develops in a manner that promotes the public good, and the NCUC recognizes that responses to the questions posed in the three-page order will enhance its expertise to best promote that public good.

Other states should consider taking a page from the NCUC’s playbook. It will create the opportunity to be more informed and better positioned to make decisions you very likely will need to make. Why wait until you are constrained by limitations associated with having to review a filing in a contested case? After all, who would be better situated to render a decision: a commission that has reviewed diverse comments and participated in discussions regarding the best ways to use federal dollars for the benefit of its state prior to having to review an actual proposal, or a commission that hasn’t?

Riding a wave requires help. Adopting the North Carolina approach will better position your utility commission to ride the oncoming wave of federal funding for the benefit of your utility sector and state economy.






高管们匆匆离去。此后五年左右的时间里,东北地区电力系统进行了深度改革。这是“紧密型电力库”(tight power pools)时代的开始——新英格兰、纽约、宾夕法尼亚-新泽西-马里兰(PJM)——其特点是电力公司共享发电和输电资产,由中央系统运行商管理,负责确保系统安全(实时可靠性)和资源充足(长期投资的充足性)。通过让可靠性成为一种共同的责任,即通过扩大需要管理的发电和输电资源组合,分散风险,这样总成本降低了,系统范围停电的可能性也大大降低了。


这就是诀窍所在。服务于RTO的输电系统资产可能由不止一个公司拥有——事实上是许多公司——但它们被视为属于一个所有者,并由一个所有者运行。每个人为使用大电网支付相应的价格;但是他们支付多少取决于他们在电网总负荷中所占份额(通常以同时峰值负荷需求的兆瓦数来衡量,但在某些情况下,也以兆瓦时来衡量)。这被称为一个地区的负荷分担比率,通常由负荷服务实体(例如,电力购买者)支付。对于满足低于一定电压阈值需求(例如345 kV)的电网资产,通常全部由其所在地区的负荷服务实体支付,除非有人认为这些资产对整个系统的可靠性起着必要作用。











From laggard to leader: How Poland became Europe’s fastest-growing heat pump market

With the war in Ukraine compelling everyone to rethink their energy strategies and focus on getting rid of Russian fossil fuel imports, while maintaining what is left from the affordability of energy supply, the go-to tactics are achieving several energy policy goals at the same time. The Polish heat pump sector seems to be doing just that.

It is showing the fastest growth rate for heat pumps in Europe in 2021 with an expansion of the market by 66% overall—more than 90,000 units installed reaching a total of more than 330,000 units. Per capita, more heat pumps were installed last year than in other key emerging heat pump markets, such as Germany and the United Kingdom.

But this has not always been the case. For years Poland prided itself on being one of the most energy independent countries in Europe. Its coal mining sector and coal-fueled power plants provided carbon-intensive, but domestic, energy—both for heating and electricity.

Coal Dependent

Even now, with the recent growth of renewables making quite a dent in Polish coal reliance, the share of coal in electricity production and district heating is around 70%. In individual home heating, it is around 48%. Poles consume as much as 87% of the coal burned by all EU households in their homes for heating. The heating sector is responsible for nearly a quarter of CO2 emissions in Poland.

This reliance, however, has been proving less and less sustainable for a number of reasons — especially in the individual heating sector. First of all, the energy independence narrative no longer holds. Polish coal mines are notoriously labour-inefficient, but a bigger problem is that they become less and less economical to run for sheer geological reasons. The average depth of extraction is now close to 800 metres below ground, which brings immense cost—both economical and human.

Time has seen a steady decline in coal mining output, especially for the coal sorts used by individual boilers are in shorter supply. This has been replaced by imported coal mainly from Russia. Poland is currently buying €0.5-1 billion worth of Russian coal each year to heat its houses.

Even if we put aside the acute air quality problems that burning coal in old individual coal furnaces brings—which we should not as the list of 20 most polluted cities in Europe constantly features at least 10 Polish cities—this should be enough in the current circumstances to warrant a huge public policy shift directed at eliminating coal from individual heating altogether.

The preferable way of doing so would be a massive deployment of heat pumps and energy efficiency programmes whilst continuing to utilise more renewables for electricity generation at the same time. This would check the boxes for so many policy objectives, including increasing energy security, reducing carbon emissions and lowering long-term heating costs.

Long-Term Planning

Given Poland’s reliance on coal for heating, how did the Polish heat pump market achieve such remarkable growth? All signs point towards government policy. Through the ten-year Clean Air Programme that started in 2018, Poland will provide close to €25 billion for replacing old coal heating systems with cleaner alternatives and improve energy efficiency.

In addition to providing subsidies, many regions in Poland have begun to phase out the coal heating systems through regulation. Prior to those bans, heat pump installations rates were modest with limited growth over the years. This shows that policy can make a big difference in steering the market towards clean heating away from polluting fossil fuel heating systems.

Trust Building

The recent success is also a showcase of efficient market development by the heat pump industry association, PORT PC. Building customer and installer trust by developing and introducing industry guidelines, quality standards and certification, as well as conducting extensive training programmes, is now bearing fruit.

Further growth in the heat pump sector in Poland is expected and will need to take place in order to further replace coal heating. This can be achieved by implementing changes to the Clean Air Programme and other similar programmes designed to improve the efficiency of homes and heating systems, like the current tax breaks for investment in buildings insulation as well as the STOP SMOG programme designed to help local governments give targeted support to the poorest households.

Also, the recently announced new programme “My Heat” financed from the sale of EU ETS allowances through the Modernisation Fund and fully directed towards heat pumps, will provide additional sources of funding and hopefully build even more awareness among consumers.

Whilst the Clean Air Programme has so far promoted mostly gas boilers (over 40% of the total), the war in Ukraine has shown that natural gas will be a scarce and costly resource and should be used wisely. Heat electrification, rather than gasification, is surely the way to go.

Challenges Remain

Three challenges remain to be tackled for continued success. Firstly, for heat pumps to be most beneficial in terms of climate protection, electricity generation should continue on the pathway towards (quicker) decarbonisation.

Secondly, heat pumps should be an element of system flexibility, rather than a strain on the peak demand. For this, dynamic tariffs and smart solutions are fairly easy fixes but require regulatory intervention as well as consumer awareness and industry willingness to go the extra mile.

Thirdly, proactive measures should be taken to avoid potential supply chain disruptions and to secure enough of a skilled workforce. Poland is very well positioned in both areas, now being a highly industrialised country with excellent technical education.

Poland’s energy transition is picking up speed, and the growing heat pump market is a prime example of a policy push working with supply pull to deliver excellent results. The prospects are encouraging and there have never been more incentives to continue on this pathway.

This article previously appeared in Foresight.

Indian power sector has opportunities to create value for the discoms and their consumers by mainstreaming behind-the-meter resources

The electricity sector in India has experienced an evolution of sorts throughout the years. Since the early the 1990s, the sector has grown from a vertically integrated monopoly with generation, transmission, and distribution all under one roof, to the current structure in accord with the Electricity Act of 2003 where the three have been unbundled and now operate separately. The Bureau of Energy Efficiency (BEE) has made substantial progress towards promoting end-use efficiency with more than 15% savings demonstrated in the appliance-level energy use with its labelling and standards plans. The Indian power sector has created a conducive environment for renewable energy generators: as of 31 January 2022, renewables constituted 26.8% of the nation’s total installed capacity of 370 GW. The politics of subsidised or free electricity to a certain category of consumers, a legacy practice followed by the distribution companies (discoms), puts undue pressure on the entire power sector’s financial health.

The four charts below show Average Billing Rate (ABR),* Aggregated Revenue Requirement (ARR),** revenue gap (difference between the average cost of supply (ACS) and ARR, and Aggregated Technical and Commercial (AT&C) losses for discoms in major states.*** 

The distribution sector in India is also struggling. As of March 2021, the sector owes over INR 85,000 Crores (approx. U.S. $12 billion) to the generation companies. Discoms depend on the commercial and industrial (C&I) consumer base to subsidise the agriculture and the low-volume domestic customer classes, as seen in the difference between energy sales and revenues in the figure below.

Source: PFC, 2019

The C&I consumers will continue to provide the lion’s share of discom revenues, even if they take advantage of “open access” (the freedom to buy power from sources other than the incumbent discoms), because they are nevertheless required to pay high cross-subsidy surcharges and wheeling charges (power distribution charges). It’s important to retain such consumers within the incumbent discoms with key objectives of promoting higher renewable energy shares in the power mix, as well as reducing the electricity use with a deeper portfolio of energy efficient end-use practices. The discoms’ heavy dependence on C&I consumers to generate sufficient revenues creates significant barriers to decarbonisation investment opportunities among these consumers.

C&I consumers have an intrinsic need to reduce their power costs. Open access is a powerful opportunity for these consumers. So too are on-site efficiency and distributed resources, but such behind-the-meter investments are not encouraged by the discoms, given the threat of reduced revenues that they pose. Along those same lines, behind-the-meter generation (rooftop photovoltaic) within the consumer base is not easy to implement without on-site storage options or net metering/renewable energy export opportunities provided by the discoms. In several states, net metering policies do not favour the consumers creating large capacities to be exported to the grid beyond their diurnal requirements. It’s also opportune to deepen the behind-the-meter renewable energy and energy efficiency portfolio, combined with the storage solutions, at the consumer categories that are heavily subsidised.

One key opportunity to be explored in creating a substantive renewable energy, efficiency and storage portfolio on both sides of the meters is the possibility of discoms doubling up to become new energy service providers as much as legally possible. We hypothesise the possibility of developing a stronger efficiency, renewables, demand-responsive, end-use consumption, with adequate thermal and battery storage solutions at the consumer-side of the meter amongst all the customer categories.

Our team is currently exploring the efficacy and benefit-costs of discoms and consumers co-investing in behind-the-meter efficiency, dispersed solar, storage and demand-responsive end-use consumption patterns. We’re also researching in detail the regulatory regime that allows such investments, the benefit-costs of making investments in the behind-the-meter efficiency and renewables assets, and existing enhanced power sales opportunities through the possibility of selling saved energy for newer uses, such as electric vehicles. Other key benefits of enhanced renewable energy assets on the customer side of meter is the possibility of exporting renewable energy sources to other regions through an aggregated sale on the exchanges. More to come.

*ABR is calculated as ABR = Revenue expected from all categories million Rs /Approved sales in MU. The data has been obtained from the latest ARR of the respective utilities.

**This is the approved ARR for the upcoming year for the respective utilities. 

***Discom key:

  • Maharashtra: MSEDCL
  • Punjab: PSCPL
  • Karnataka: BESCOM
  • Tamil Nadu: TANGEDCO

Energiewende im Krisenmodus braucht sozialen Zusammenhalt

Der Krieg und das Leid der Menschen in der Ukraine halten uns alle in Atem, bringen uns aber auch als Gesellschaft näher zusammen. Die große Hilfsbereitschaft in den Grenzregionen und auch in Deutschland macht uns zusammen stark. Wie Bundespräsident Steinmeier in Litauen sagte: „Die Einigkeit und die Geschlossenheit (der Nato und der Europäischen Union) sind der Schlüssel zu unserer Stärke.“

Krisen und Kriege sind schmerzhaft und teuer. Um diese Zeit zu überstehen, braucht es den Zusammenhalt, der den Menschen die Grundbedürfnisse sichert, für die geflüchteten und die verletzlichen Verbraucher:innen innerhalb unserer Gesellschaft. Da dieses Leid eben auch unsere Energieversorgung betrifft, müssen wir hier zusammenstehen, mehr als in der Vergangenheit.

Denn in diesen Tagen wird es deutlich, dass fossile Energien teuer sind und wohl teuer bleiben werden. Der Abschied von diesen teuren und schmutzigen Ressourcen kostet allerdings ebenfalls Geld und Zeit. Für den einzelnen geht jede Umstellung auf eine Wärmepumpe und höhere Energieeffizienz mit hohen Investitionskosten einher, welche wir uns trotzdem leisten können müssen. Denn die zusätzliche Rechnung, die Deutschland durch die gestiegenen Gaspreise stemmen muss, wird sich wohl auf einen hohen zweistelligen Milliardenbetrag im Jahr belaufen.

Für einzelne Verbraucher:innen mit Gasheizung bedeutet das etliche hundert Euro im Jahr zusätzlich, bei schlechten Gebäuden und damit hohen Verbräuchen können es auch leicht mehr als 1000 Euro werden. Die Mehrwertsteuer erhöht die Kosten noch weiter. Im Vergleich dazu führt die beschlossene Senkung beziehungsweise Überführung der EEG-Umlage in den Bundeshaushalt zu einer Entlastung des durchschnittlichen Haushalts um gut 200 Euro im Jahr.

Durch die gleichzeitig stark steigenden Strompreise werden die Stromrechnungen der Verbraucher:innen wohl trotzdem nicht sinken. Sowohl für den Gas- als auch der Stromsektor sind das Mittelfristbetrachtungen, das heißt, sobald die hohen Großhandelspreise vollständig in die Endkundentarife eingepreist sind.

System und Regulierung sind unsozial geprägt

Diese Kostensteigerungen lassen sich mittelfristig nur durch mehr erneuerbare Energien und eine größere energetische Unabhängigkeit bekämpfen, mit Freiheitsenergien, wie Herr Lindner sagte. Dazu gehört die schnellere Verbrauchsminderung durch Effizienzmaßnahmen und eine beschleunigte Elektrifizierung, insbesondere im Wärmesektor durch Wärmepumpen und Wärmenetze. Ein fortgesetzter Einbau von Gasheizungen in Neubauten und ein weiterer nachfrageorientierter Gasverteilnetzausbau passen dazu nicht. Hier bedarf es einer sofortigen Richtungsänderung, die die Verringerung unserer Import-Abhängigkeit einleitet als auch die langfristigen Energiewendekosten begrenzt. Kosten, die am Ende sonst alle Verbraucher tragen, im Verhältnis die vulnerablen Verbrauchergruppen aber stärker betreffen.

Unser Energiesystem und dessen Regulierung kann jedoch kaum mit sozialen Absicherungen oder Hilfen aufwarten, eher ist das Gegenteil der Fall. Beispiele sind:

Auf der anderen Seite fördern wir mit Milliarden Euro Kaufprämien für E-Pkw, Pendlerpauschalen und Wallboxen wie auch energetische Sanierungen in Eigenheimen, während die bedürftigsten Verbraucher:innen in den energetisch schlechtesten Gebäuden wohnen (müssen), auf deren Energiestandard oder Energieträger sie keinen Einfluss haben. Unser Sozialsystem versucht, die Mehrkosten der Bedürftigsten mittels Arbeitslosengeld II und durch Einmalzahlungen zu kompensieren. Damit bleiben jedoch die Wohnsituationen wie auch Hilfen für die unteren Einkommensgruppen insgesamt außen vor.

Die Folgen der hohen Gaspreise werden noch unterschätzt

Es ist richtig, den Umstieg auf nachhaltige und saubere Lösungen zu fördern, jedoch im Sinne einer gemeinsamen Stärke, wo es nötig ist. Dazu gehören neben den Anreizen auch Besteuerungen und das Ordnungsrecht. In der Krise wird sich deutlicher denn je zeigen, wie weit wir das Ordnungsrecht über den Artikel 14 des Grundgesetzes bemühen und Eigentum über Gebote und Verbote verpflichten. Abweichend davon spielt im selbstgenutzten Eigentum die Sichtbarkeit der mittel- bis langfristigen Kosten die wichtigste Rolle.

Wenn es sich jedoch um vermieteten Wohnraum handelt, greift dieser Ansatz zu kurz. Die Energiekosten werden für fast jeden Mieter stark steigen. Die bisher diskutierten Größenordnungen von Pro-Kopf-Rückzahlungen oder Vorhaben für eine CO2-Kostenteilung mit dem Vermieter werden daran nur wenig ändern. Trotzdem diskutiert Deutschland maßgeblich die Spritpreise. Sowohl die Opposition als auch die FDP wollen die Preise durch Steuernachlässe auf breiter Basis senken, obwohl aus volkswirtschaftlicher und geopolitischer Sicht ein schnellerer Abschied geboten ist.

Wie wenig ausgewogen diese Forderungen sind, zeigt sich im Vergleich. Die Rohölpreise haben sich „nur“ verdreifacht, während es beim Großhandelspreis Gas aktuell fast eine Verzehnfachung innerhalb eines Jahres ist. Die Auswirkungen in den Gas-Tarifen sehen wir erst in einigen Monaten, jedoch mit viel weiterreichenden sozialen Folgen.

Auch ein reiches Land wie Deutschland wird sich ohne anderweitige, massive Steuererhöhungen kaum eine Kostenübernahme für fossile Energien in der Breite leisten und gleichzeitig die Förderung von Einsparungen und erneuerbaren Energien erhöhen können. Angedachte Entlastungen müssen sich daher stärker an den sozialen Auswirkungen und den Langfristzielen orientieren. Preissignale zu mindern, stellt jedoch das Gegenteil dar. Wenn unsere Gemeinschaft die gemeinsame Stärke besitzt, die unser Bundespräsident bekundet hat, schaffen wir es, die Krise als Chance zu nutzen.

Es ist dringlicher denn je, die Verteilung der Kosten und die Ausgestaltung der Unterstützungen in der begonnenen Transformation fair und sozial zu gestalten. Nutzen wir diese Chance. Jetzt.

Eine Version dieses Artikels erschien in Tagesspiegel Background.

How Europe can rapidly reduce its gas dependency

“We cannot solve our problems with the same thinking we used when we created them,” Albert Einstein famously said. Yet this is exactly what the European Commission appears to be doing in its forthcoming strategy for more affordable, secure and sustainable energy, a leak of which emerged a few days ago.

The Commission rightly identifies the energy price crisis as rooted in the EU’s exposure to global and volatile gas prices. It also points to energy efficiency and renewable energy investments as the ‘best answer for the future.’ But the strategy then proceeds to more of the same cure: Fossil gas imports, this time from different third countries such as Azerbaijan, Qatar and Turkey. This approach is at odds with the Commission’s own projections showing that by 2030 fossil gas use must decline by 30% compared to 2015.  To bet on short-term gas contracts in a global commodity market is a risky undertaking, as the current geopolitical situation painfully demonstrates.

History repeating

What are the problems? The leaked strategy mentions ‘low-carbon gases’ and significant EU funding for such gases to lower dependence on fossil gas. Low-carbon gases include blue hydrogen, which is made from fossil gas and would actually increase Europe’s dependence because of the inefficiencies involved in the production of blue hydrogen. The International Renewable Energy Agency clearly states in its recent report on the geopolitics of hydrogen: ‘Blue hydrogen would follow the patterns of gas markets, resulting in import dependencies and market volatilities’. In short, investing more in gas as a strategy to move away from gas would worsen, not improve the situation.

Then, there is the issue with biogas. The EU’s quota for food-based biofuels was capped when indirect land-use effects became evident. Yet the Commission rushes unnecessarily into setting a biogas target for 2030 without checking consistency with other elements of the Green Deal – namely competition for land use, methane reduction commitments, air pollution and soil protection. This means a doubling of biogas use within the next eight years – implied by the 35bcm target – which would put more pressure on our soils and potentially result in harmful agricultural practices. Any renewable methane pathway also carries the risk of undermining its climate benefits through methane leakage, as the gas is a strong climate forcer. Finally, a biogas target seems to come prematurely given that an independent review of the sustainable biogas potential in Europe reflecting the new LULUCF (Land Use, Land-Use Change and Forestry) targets of the Fit for 55 package has not been undertaken.

The only biogas that provides a climate benefit by not straining land resources is produced from wastes and residues, which are limited in availability and will be needed to decarbonise aviation and shipping. Claims that biogas could remotely replace current fossil gas use at the level needed and across all uses are therefore unconvincing. Biogas will instead need to become a niche fuel, alongside hydrogen, reserved for replacing fossil fuels in applications where electrification is not an option.

A positive path forward

Luckily there is another way forward. The EU’s fossil import bill increased by 70% between December 2020 and December 2021, currently reaching around 380 bn euros. This amount happens to be as high as the additional clean energy investment needs estimated by the European Commission in its Impact Assessment underpinning the higher 2030 targets. In one case, it would go to investments on energy efficiency, renewables and electrification and the jobs that come with them, in the other case, money is lost on buying fossil fuels. This comparison reveals that the current crisis is as much a fossil gas demand crisis as it is a supply crisis.

Therefore, let’s move beyond the current strategy of replacing gas with more gas and instead start from the demand side. Most of Europe’s gas is used for low-temperature heating, which can be replaced with existing technologies. The Commission’s Energy System Integration Strategy of 2021 rightly identifies energy use reduction and electrification of home heating as key levers, findings backed up by recent reports from the International Energy Agency and McKinsey. This building heating transition is expected to reduce gas consumption in buildings by more than 40% compared to 2015 levels and contribute nearly two-thirds of the overall reduction in gas consumption over the same period.

Towards an EU framework for electrification

Decarbonising heating in Europe still relies heavily on biomass, not all of which comes from sustainable sources. This is because, unlike in the transport sector, there is no multiplier in the Renewable Energy Directive that would incentivise the use of ambient heat extracted by heat pumps.  The proposed directives on renewables and gas should be used to both push for the electrification of heating and to direct gaseous fuels to areas where they cannot be. The European Parliament and the Council can now introduce the necessary amendments to change the incentives accordingly.

The old recipes cannot make supply more secure, more affordable or cleaner.  Let Europe’s response to the current crisis be ramping up support to ensure the exponential growth of solar and wind and the use of green electricity to replace fossil gas.

Michaela Holl is a senior associate at Agora Energiewende.

A version of this article originally appeared on Euractiv.

How heat pump sales are starting to take off around the world

Experts see heat pumps as one of the main solutions for tackling the carbon emissions associated with keeping buildings warm, both in the UK and internationally. Yet sales of the technology, often likened to a fridge running in reverse, have remained stubbornly low in many countries.

The latest figures, collated in this article for Carbon Brief, show the tides beginning to turn, with sales in 2021 seeing double-digit growth in countries ranging from Austria to China.

While rapid growth in the market seems assured, heat pumps might still fall short of the levels required for a global pathway to net-zero by 2050, without further government action.

Highly efficient

Heat pumps are a low-carbon heating technology with the potential to deliver large-scale reductions in carbon emissions from building heat.

They use electricity to move heat from ambient outside air, water or soil to a building’s interior and to heat water. This process is highly efficient, with heat pumps delivering three to four units of heat for each unit of electricity needed to run them.

When the electricity used to drive a heat pump is produced from low-carbon sources, all this heat is also low carbon. It is this simple capacity to deliver heat very efficiently and cleanly that makes heat pumps a key technology in most pathways to net-zero.

The International Energy Agency’s (IEA) pathway to net-zero by 2050, for example, includes 1.8bn heat pumps in buildings in 2050 providing 55% of energy demand for heating globally. This compares with just 180m units installed today, providing 7% of heating.

Similarly in the UK, the most cost-effective Climate Change Committee (CCC) “balanced” pathway to net-zero sees the majority of homes being heated with heat pumps by 2050.

Until recently, however, the heat pump market has been growing far more slowly than required in the IEA or CCC scenarios. This is evident from the IEA’s global heat pump stock figures in the chart below, which shows that, at current trends, only 253m heat pumps would be installed globally by 2030, compared with the 600m units needed by that year in the IEA’s net-zero scenario – a shortfall of 58%.

Globally, just 177m heat pumps had been installed by 2020, according to the IEA’s data. Most of these heat pumps were in China (33%), followed by North America (23%) and Europe (12%).

Interestingly, the highest penetration of heat pumps can be found in the coldest climates, as the chart below shows. In Europe, the four countries with the largest share of heat pumps are Norway (60% of households), Sweden (43% of households), Finland (41% of households) and Estonia (34% of households). These four countries also face the coldest winters in Europe.

Expanding market for heat pumps in 2021

The IEA data shows the global heat pump market grew by just 3% in 2020. Before that, the market had been growing by around 10% per year. The IEA’s net-zero pathway requires market growth at a global level of around 13%, year on year to 2030.

Following the slowdown in 2020, initial data suggests the heat pump market saw a strong recovery in 2021, with double-digit growth in some of the countries where figures are available.

Across Europe, for example, the European Heat Pump Association (EHPA) expects market growth to have exceeded 25% in 2021, hitting 2m units sold per year for the first time.

The Polish heat pump association Port PC reported an increase of 60% for heat pumps in 2021, mainly driven by regulations phasing out coal heating for single-family homes in the country.

In Germany, the heat pump market grew by 28% in 2021, with 154,000 units sold – mainly because of the expansion of air source heat pump sales. The adoption of a carbon tax on heating fuels in 2021 partly explains the growth observed.

These figures are shown in the chart below, along with data for several other countries where data is available through to 2021.

The U.S., another global leader for air source heat pumps, gained 15% in 2021, capping a run of consistent yearly growth above 5% since 2015.

Finland showed similar growth to Germany in 2021, with an increase of 25% to 130,000 heat pumps installed, according to the Finnish Heat Pump Association. Given the small size of the country in terms of population, this is remarkable, with almost 5% of all homes installing a heat pump in 2021.

The majority of heat pumps installed in Finland were air-to-air heat pumps, which can also be used for cooling. However, the Finnish Heat Pump Association estimates that air-to-air heat pumps used for cooling account for only 10%-15% of the respective market.

What is notable about Finland is that the heat pump market only started to expand in the mid-2000s, with cumulative installations now exceeding 1m units.

Overall, the French heat pump market grew by 3% in 2021, but the air-to-water segment rose by 53%. The French heat pump market is the largest in Europe, with more than 1m units in 2021. By far the most important type of heat pump in France are air-to-air heat pumps.

Switzerland, another mature and long-established market for heat pumps, showed market growth of 20% in 2021, mostly air-to-water systems. More remarkable is the fact that 54% of all heating systems sold in Switzerland last year were heat pumps, making it the dominant heating technology not only in new buildings but in existing buildings too.

In China, initial estimates of residential air-source heat pump sales in 2021 saw market growth of 10% to more than 1 million units, for the first time, with hints of even larger growth in non-residential sales.

In Norway, a total of 125,000 heat pumps were sold in 2021, a similar amount to Finland. This represents growth of 36% compared to 2020. Also similar to Finland is that the majority of heat pumps sold in Norway are air-to-air heat pumps.

graph showing annual heat pump installations in norway, 2012-2021

Outlook for heat pumps

Although further rapid growth now looks likely, the pace of adoption – and how that measures up against pathways to net-zero – will depend strongly on government policies and energy price trends.

The recent increase in European and Asian gas prices makes heat pumps financially more attractive than gas boilers, as previous analysis shows. But that could change, which is why policy remains key and initiatives are underway to provide more support for heat pumps.

In the EU, for example, the European Green Deal and the associated push for decarbonising heating through a variety of directives means the market for heat pumps will double to 4m installations per year, according to the EHPA.

Drivers include a European Commission proposal to extend the EU Emissions Trading System to heating fuels, which would improve heat pump economics relative to oil-and-gas heating.

There is also new regulation in various European countries banning or limiting fossil-fuel heating, not only in new buildings but also increasingly in existing buildings.

For example, the new German government has announced that from 2026 all new heating systems must run on at least 65% renewable energy. Others such as Norway, Sweden, Denmark and Finland have announced explicit or implicit bans of new fossil oil-based heating systems in all buildings.

The Netherlands no longer allows new homes to connect to the gas grid, while Ireland, Flanders (Belgium) and Austria have announced bans on oil boilers for new buildings.

Ireland recently unveiled a €8bn scheme that nearly doubles the value of grants for heat pumps as the country looks to ship 400,000 heat pumps into homes by 2030.

In the UK, the government is consulting on requiring manufacturers of heating systems to sell an increasing number of heat pumps and has announced an “ambition” to phase out gas boilers by 2035. It will also launch a new heat pump grant scheme in April.

China has a track record of using clean heat solutions to reduce air pollution from coal boilers. Its southern provinces have high market potential for heat pumps, with areas such as Beijing already offering incentives.

Despite these local incentives and programmes, however, heat pumps lack support at the national level in China . For example, they are not classified as renewable by the national government, meaning they do not benefit from a clean heat subsidy available in the northern provinces.

In the U.S., a drive to electrify homes – and, in some areas, ban fossil fuel heating – is expected to further boost the prospects for heat pumps. The stalled Build Back Better plan included a 10-year $3.5bn rebate program for electric homes with up to $4,000 for heat pumps, among other incentives.

The Biden administration has also launched a National Building Performance Standards Coalition, a task force comprising 33 state and municipal governments, that aims to “unlock energy efficiency and electrification across the buildings sector.”

Double-digit growth in major heat pump markets during 2021 shows powerful momentum. But without the continued expansion of policies to support their rollout, heat pump deployment will fall short of the level needed to reach net-zero by 2050 – and to limit warming to 1.5C.

Duncan Gibb is the lead analyst on heating and buildings at REN21.

This article originally appeared in Carbon Brief. Graphics by Joe Goodman for Carbon Brief.

Environmental Regulations and the “No Regrets” Approach: A Refresher for Utility Generators

Many of us have a hard time keeping track of where our federal government stands on environmental issues, especially when viewed through a political lens or from the perspective of the popular press. For example, in 2016 we signed on to the Paris Climate Accord. We withdrew in 2020, then rejoined in 2021. The Obama administration put in place numerous environmental regulatory programs. Subsequently, the Trump administration undermined them in court and dismantled them administratively. Then, rather than supporting the Obama administration’s Clean Power Plan, which was replaced by the Trump administration’s Affordable Clean Energy rule, the Biden administration took a different tack through a series of executive orders.

Despite being confusing at times, policy changes should not be an impediment to utility companies. The reason: Electric utilities across the country have always been masters of long-term planning. They know that major infrastructure projects take a long time — up to a decade or more — to conceive, plan and execute. More than half of all states require utilities to develop long-term integrated resource plans, a full range of feasible options on the supply side (utility-scale generation), demand side (customer-sited solutions) and distribution side (customer and community resources), and to assess them against a common set of planning objectives and criteria to meet expected customer service requirements into the future at least cost.

The truth is that utilities routinely make and execute resource plans, whether mandated or not. As illustrated in a blog one of us wrote in 2015, a careful assessment of risk factors will reveal that, in addition to what is immediately before you, utilities face “a host of other rules, initiatives, and market trends that are forcing other changes.”

So, instead of getting caught up in the latest pronouncements, utilities should make sure that they consider a wide range of regulatory scenarios, then develop plans to help them acquire a portfolio of resources capable of serving customers well, given existing trends and the law. In other words, “no regrets” approaches today can dictate what reasonably appear to be a company’s most equitable and economical choices.

What follows are some examples to illustrate that new environmental requirements could arise from federal laws already on the books. Utilities, working with their state regulators and stakeholders, should recognize and make long-term plans for these likely requirements.

Ambient Air Quality Standards (standards reviewed every five years)

The Clean Air Act requires the U.S. Environmental Protection Agency (EPA) to review the National Ambient Air Quality Standards every five years. This requirement includes primary and secondary standards for six of the most common air pollutants, known as criteria pollutants: carbon monoxide, lead, ground-level ozone, particulate matter, nitrogen dioxide, and sulfur dioxide. The purpose of the review is to ensure that these standards reflect the best, current scientific information to ensure the protection of public health and the environment.

These reviews depend on the development and evaluation of scientific information by the EPA, and, in turn, advice from the agency’s independent Clean Air Scientific Advisory Committee. Today’s utility planners should note the ongoing review of the air quality standards for fine particulate matter, for example. A 2021 Advisory Committee report indicates that the current standards may not be adequate to protect public health and welfare, as required. Particulate matter is emitted whenever fossil fuels are burned, so a tighter standard could result in more restrictions on processes and equipment (including power plants) that burn fossil fuels.

Section 110(a)(1) of the Clean Air Act requires states to submit State Implementation Plans to the EPA within three years after the initial development or revision of a national primary ambient air quality standard. State plans provide for the implementation, maintenance and enforcement of these standards.  These plans provide an excellent opportunity for utility regulators, utilities and community groups to help states design appropriate plans, consistent with other utility planning efforts.

Interstate Air Pollution (allowable emissions in 12 states are due to decrease through 2024)

In 2011, EPA finalized the Cross-State Air Pollution Rule (CSAPR) to address the emissions of criteria air pollutants that are transported across state lines and affect air quality in downwind states.

Because the interstate transport of emissions affects air quality and public health locally, regionally, and in states hundreds of miles downwind, this rule requires certain states in the eastern half of the United States to regulate and reduce power plant emissions to improve air quality. If a downwind state can demonstrate that upwind emitting sources in neighboring states are affecting its ability to comply with national standards, the “good neighbor” provisions of Section 126 of the Clean Air Act require the upwind source to either cease operation or comply with emissions limitations established by the EPA.

If the EPA determines that states are taking too long to implement changes to their state plans, the agency has the authority to issue a Federal Implementation Plan. In 2021, it issued new or amended plans for these 12 states, revising their emission budgets until air quality projections demonstrate resolution of the link between emissions in these states, allowing downwind states to meet air quality standards.

New Source Performance Standards for GHG Emissions (standards could be revisited any time)

In 2015, using authority from Section 111(b) of the Clean Air Act, the EPA set New Source Performance Standards for greenhouse gas (GHG) emissions from new, modified, and reconstructed fossil fuel-fired power plants. As required, the agency established these emissions standards based on its evaluation of the “best system of emission reduction” for affected sources. For example, the best system for baseload natural gas-fired turbines was determined to be the use of efficient natural gas combined cycle technology. For peaking turbines, however, the EPA determined that using “clean fuels” was the best system of emissions reduction. In neither case did the agency require new gas-fired turbines to match the performance of the lowest-emitting commercially available turbines.

In December 2018, EPA proposed revisions to the new source performance standards for coal-fired electric power plants relaxing the requirements. The primary reason given by the agency, “high costs and limited geographic availability of [carbon capture and storage] CCS.” Using the same authority, the EPA could likewise propose to tighten the standards for baseload and peaking gas plants. If it were to consider current resource information, the agency could revisit its best system of emissions reduction determination for a gas “peaker” and determine, for example, that new plants should not emit more than the very lowest emitting units on the market today.

Hazardous Pollutants (standard reviewed every eight years)

In 2012, the EPA developed the Mercury and Air Toxics Standard (MATS) pursuant to Section 112 of the Clean Air Act. That section gives the agency the authority to regulate hazardous air pollutants from stationary sources like electric generating units. Section 112 also requires periodic review and potential revision “taking into account developments in practices, processes, and control technologies.”

In fact, fossil-fueled electric power plants emit toxic air pollutants and could become subject to further restrictions given the EPA’s recent announcement about the need to enforce the mercury requirements, reversing another decision made during the Trump administration. The agency is taking comments on whether the mercury emissions limits should be made more stringent.

Utilities have the capability and the responsibility to factor all these contingencies and scenarios into their long-term plans and investment decisions. In the foreword to its 2011 publication Preparing for EPA Regulations:  Working to Ensure Reliable and Affordable Environmental Compliance, RAP quoted Moody’s Investor Service:

 …credit risk factors associated with energy and climate legislation have existed for decades and managing these risks are considered a core competency for all utility operators, whether they are regulated or un-regulated, public, or privately-owned.

This applies as much today as it did 10 years ago when Moody’s made the pronouncement. Staying abreast of changes to environmental and public health laws and their potential effects on the utility sector continues to be an important responsibility of utility owners, operators, and regulators.