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Bristol, United Kingdom

Anderson W.,Center for Sustainable Energy | White V.,Center for Sustainable Energy | Finney A.,University of Bristol
Energy Policy | Year: 2012

This paper presents findings from a study of low-income households in Great Britain which explored households' strategies for coping both with limited financial resources in the winter months, when demand for domestic energy increases, and, in some cases, with cold homes. The study combined a national survey of 699 households with an income below 60 per cent of national median income with in-depth interviews with a subsample of 50 households. The primary strategy adopted by low-income households to cope with financial constraint was to reduce spending, including spending on essentials such as food and fuel, and thereby keep up with core financial commitments. While spending on food was usually reduced by cutting the range and quality of food purchased, spending on energy was usually reduced by cutting consumption. Sixty-three per cent of low-income households had cut their energy consumption in the previous winter and 47 per cent had experienced cold homes. Improvements to the thermal performance of homes reduced but did not eliminate the risk of going cold as any heating cost could be a burden to households on the lowest incomes. Householders' attitudes were central to their coping strategies, with most expressing a determination to 'get by' come what may. © 2012 Elsevier Ltd. Source

News Article
Site: http://www.greentechmedia.com/articles/category/solar

California’s next four years of net metering policy have fallen into place, and for the solar industry, it’s a major victory -- with a big dose of uncertainty, and a considerable amount of last-minute conflict. On Thursday, the California Public Utilities Commission voted 3-to-2 to enact its net energy metering (NEM) successor tariff, also known as NEM 2.0. For the past decade, this policy has assured net-metered customers that they’ll earn retail-rate payments for their surplus solar energy, which has helped push the state to lead the country in rooftop solar deployments. As expected, Thursday’s decision upholds those retail rates, handing solar companies an important win, compared to recent net-metering losses in states like Hawaii and Nevada. Much of the public battle between solar advocates and California’s big investor-owned utilities has been about these rates -- utilities had asked to cut them, saying they unfairly shifted costs to non-solar customers. But the new regime also imposes an  “aggressive” move to time-of-use rates for net-metered customers, Commission President Michael Picker noted. Starting as soon as the successor tariff is implemented, net-metered solar customers will be required to move to TOU rates that charge different prices during different times of the day, to better match real-time costs of generating and transmitting energy across the grid at large. Solar groups have given tentative support to this concept, but have worried that its implementation, still being worked out in CPUC proceedings and upcoming pilot projects, might make it difficult to predict the economics of net-metered solar systems in years to come. "We support a movement towards time-of-use rates, as better aligning grid needs with economic signals," Adam Browning, executive director of the Vote Solar advocacy group, said after Thursday's vote, but added, "we would have preferred to see a more gradual phase-in." The 124-page decision, which included some changes posted only a day before Thursday’s vote, also reduced some of the “non-bypassable” charges that new net-metered customers will be required to pay. Specifically, they won’t pay transmission charges as part of that mix. That will reduce the average non-bypassable costs of a typical residential rooftop solar system from about 4 to 5 cents to about 2 to 3 cents per kilowatt-hour, Browning said. But Commissioners Catherine Sandoval and Mike Florio, who voted no, said it was this last-minute exclusion of transmission charges that forced their decisions. Both said it was going too far in a decision that already favors solar compensation over fairly sharing grid and energy costs across all classes of utility customers. “If anything, it would have made sense to me to reduce the solar compensation to reflect and share the benefit of the Investment Tax Credit extension,” Florio said in Thursday’s meeting. “But these last changes have taken a decision already hailed by the solar industry, and made it even richer. And I don’t think these benefits are going to accrue to solar customers -- they’re going to accrue to solar vendors.” But Commissioners Liane Randolph and Carla Peterman joined Commission President Michael Picker in voting yes for the decision and putting it into effect. Each noted that the decision wasn’t perfect. They also highlighted that Thursday’s decision sets a 2019 deadline to reconsider its net metering policies and to adjust their value equations in light of other regulatory proceedings underway in the state. “This has been a very contentious, very complicated process,” Picker said. But “it’s a big step toward giving California consumers more choice, more responsibility, and more control over their energy usage.” Here’s our previous coverage that lays out the scope of Thursday’s decision and how it fits into California's broader moves to incorporate rooftop solar, energy storage, demand response and other grid-edge technologies into its energy regulatory regime. This Thursday, the California Public Utilities Commission is expected to vote on a final plan for what the state’s next phase of net energy metering (NEM) policies will look like -- at least for the next four years. And if the final decision looks anything like last month’s proposed decision -- and according to observers, it probably will -- it will be a major victory for the solar industry. So far, we’ve seen little sign that commissioners are going to reconsider the key solar-friendly points of last month’s proposed decision -- to retain retail rates, and reject additional fees, for net-metered solar systems. That’s more or less what solar advocates had asked for, and it’s a pretty good deal, compared to other net-metering policies coming out of states like Hawaii or, more recently, Nevada. The proposal hasn’t sat well with investor-owned utilities Pacific Gas & Electric, Southern California Edison and San Diego Gas & Electric, however. Earlier this month, they filed an unusual joint alternative proposal, seeking a last-minute compromise -- an export compensation rate of 15 cents per kilowatt-hour until installed systems reach 7 percent of a utility’s customer peak demand, and 13 cents per kilowatt-hour thereafter. That’s more than the rates utilities had originally proposed, but significantly less than the average retail rates paid by residential customers. Meanwhile, the unexpected decision by Congress to extend the federal Investment Tax Credit for solar has added a new variable to consider in the net metering debate -- namely, how it might alter the equation for solar costs over the coming years. Last Wednesday, CPUC Commissioner Michael Florio held a meeting for utilities, solar companies and other parties to discuss how the ITC extension might require alterations to this week’s final NEM 2.0 decision. Solar advocates had worried that this meeting might serve as a forum for the commission to introduce the new utility ideas into an alternative proposal. But Wednesday’s meeting passed without mention of any significant changes to what’s already been proposed. “The news, really, was in what didn’t happen -- no alternative was proposed” Bernadette Del Chiaro, executive director of the California Solar Energy Industries Association (CalSEIA), said in an email this week. With only a day now left before Thursday’s vote, it’s unlikely that an alternative proposal will emerge, given that the CPUC is already several weeks past its statutory deadline to set the new program in motion, she noted. That doesn't rule out some minor tweaks that could alter the economic equation for net-metered solar, however. According to a Monday investors note from Credit Suisse analysts, “Parties also discussed reducing the grandfather guarantee to 10 years from 20 years (which we believe is unlikely), mandatory TOU plans, and how the costs and benefits of solar should be calculated.” The issue of 10-year versus 20-year guarantees is potentially problematic for solar economics. Today, existing net-metering customers are guaranteed to keep their net metering rates for 20 years under a “grandfathering” structure, and last month’s proposed decision applied the same logic to the successor program. Cutting that period to 20 years could undermine the business case for power-purchase agreements, leases and other structures that have driven the third-party solar models that now dominate new rooftop PV growth. But according to Stephanie Wang, senior policy attorney at the Center for Sustainable Energy, last week’s discussion about 10-year versus 20-year guarantees wasn’t focused on changing current grandfathering policies. Instead, it came up during a conversation about system financing, which indicates that “the CPUC was trying to get a sense of whether [the proposed] interim tariff proposal hit the right balance between maintaining steady solar growth during this interim period and being cautious with ratepayer funds.” From NEM 2.0 to NEM 3.0: The bigger changes coming to California’s grid That brings up an important point, however, she said -- the fact that net metering 2.0, as the CPUC’s successor program is called, is meant as an interim solution. Specifically, the CPUC highlighted that it intends to revisit net-metering policies in 2019. By then, it expects to have a whole new set of regulatory structures in place that will put a new spin on the question of finding the right value for rooftop solar and other distributed energy resources (DERs). These new policies include time-of-use rates, which will charge different prices at different times of the day to better tie the cost of retail power to wholesale energy costs. These are part of a broader set of residential rate changes set in place by the CPUC last year, including flattening the state's longstanding tiered monthly charges, adding minimum monthly bills, and switching all residential customers to time-of-use rates by the end of the decade. Under the CPUC’s proposed NEM decision, these TOU rates are set to be applied first to solar customers, ahead of a broad switchover for most residential customers starting in 2019. Beyond that, however, the CPUC is looking forward to the need to merge net-metering policies with two big distributed energy proceedings it has underway. The first, its distribution resources plan (DRP), is meant to include the value of rooftop solar, energy storage, demand response and other DERs in the multibillion-dollar grid investment plans of the state’s big three utilities. The second, known as integration of distributed energy resources (IDER), is meant to put these values into play as real-world economic incentives, rate structures and utility tariffs. As the CPUC explained in last month’s proposed decision, reviewing net metering in 2019 is an attempt to create a near-term policy that will sustain solar growth, while leaving the door open to a more sophisticated approach once these new policies are ready to be put into practice: Given the choice between making a large change from existing NEM now and waiting for what promises to be much better tools for grounding that choice, we choose to base the successor tariff on current NEM, with changes that will better align the responsibilities of NEM customers with those of other customers in their class, looking toward the time when a more comprehensive reform of residential rates is completed and information from the DRP and IDER proceedings is available. This is a common challenge for many different CPUC proceedings, from its energy storage mandate to its new approaches to demand response and energy efficiency, Wang noted in a recent blog post. But its specific mention in last month’s NEM proposal is “the first time the CPUC has made this point” explicitly, she said in an interview this week. “The fact that the [proposed decision] calls out the revisit of NEM 2.0 in 2019 after they figure out rates and IDER/DRP means that the other next big issues are first, the timing and design of integrated DER sourcing mechanisms that will be developed through the IDER proceeding, and second, the quantifiable and monetizable locational value of DERs,” she said. “All the solar folks who’ve been focused on NEM 2.0 will likely find that they need to engage on market designs and new business models for integrated 'prosumer' solutions going forward.”

Parag Y.,The Interdisciplinary Center | Hamilton J.,University of Oxford | White V.,Center for Sustainable Energy | Hogan B.,University of Oxford
Energy Policy | Year: 2013

One of the many barriers to the incorporation of local and community actors in emerging energy governance structures and policy delivery mechanisms is the lack of thorough understanding of how they work in practice, and how best to support and develop effective local energy governance. Taking a meso-level perspective and a network approach to governance, this paper sheds some new light on this issue, by focusing on the relation, channels of communication and interactions between low carbon community groups (LCCGs) and other actors. Based on data gathered from LCCGs in Oxfordshire, UK, via network survey and interviews the research maps the relations in terms of the exchanges of information and financial support, and presents a relation-based structure of local energy governance. Analysis reveals the intensity of energy related information exchanges that is taking place at the county level and highlights the centrality of intermediary organization in facilitating information flow. The analysis also identifies actors that are not very dominant in their amount of exchanges, but fill 'weak-tie' functions between otherwise disconnected LCCGs or other actors in the network. As an analytical tool the analysis could be useful for various state and non-state actors that want to better understand and support - financially and otherwise - actors that enable energy related local action. © 2013 Elsevier Ltd. Source

News Article
Site: http://www.greentechmedia.com/articles/category/grid

California is rethinking how to incentivize consumers to manage their energy use. In September, the California Public Utilities Commission (CPUC) said it would seek to create an integration framework to make choosing and integrating distributed energy resources easier for consumers. The CPUC found that “harmonization” of consumer benefits and “system” (grid and societal) benefits is necessary for integrating more distributed energy resources (DERs). How can we harmonize these benefits with simple, scalable solutions that work for consumers and communities? Let's start with a fundamental question on the definition of harmonization. Does that mean equalization of benefits -- ensuring that benefits to consumers and the system are roughly equal? Equalizing benefits can serve two purposes: prevent ratepayers from paying more than the net value of DERs, and level the playing field for DERs to compete with distant power plants by compensating consumers for the additional locational system value. Or does harmonization mean alignment -- adjusting consumer benefits to incentivize actions that are beneficial to the system? The answer, of course, is both. But when to apply one approach over another is a matter of contention. Take the example of net metering policy, which is meant to do both things at once. Harmonization requires the application of the equalization principle, in the broader mandate to both ensure that ratepayers at large pay no more than the net value of DERs. But harmonization also requires attention to maintaining steady DER growth under state renewables and greenhouse-gas reduction mandates, which means aligning customer choices via incentives for rooftop solar. A key question is whether it’s currently possible to calculate the net value of DERs. Continuing the net metering example, California utilities and stakeholders are still working on quantifying the benefits of DERs, including location-specific and general carbon-reduction values. California could apply an alignment approach to harmonization during this bridge period where it is not possible to quantify a substantial portion of the benefits of DERs, and transition to an equalization approach once more DER benefits can be quantified. To encourage individual consumers to make DER choices that collectively benefit the grid, we can design financial signals in two ways. One option is to ensure that each separate solution-specific DER incentive is designed to encourage adoption of other complementary DERs so the consumer’s combined system presents an optimized or flexible resource to the grid. However, this top-down, solution-specific approach to regulation is likely too time consuming and complex for regulators to implement or stakeholders to navigate. There are already separate, specific incentives, including tariffs or rebates for distributed generation, energy storage, energy efficiency and demand response. Adjusting each incentive to reflect the grid optimization of every possible combination of DERs, as well as adjusting for market penetration over time and other factors, is a nearly impossible task. To illustrate this concept, let’s return to the example of net metering policy for distributed solar PV. Standalone net-metered solar is likely less valuable to the grid than a system enhanced by combining other DERs, including various energy efficiency measures, different types of demand response, managed electric-vehicle charging, different amounts and types of energy storage, and optional advanced inverter settings. With each combination, the net-metered value of the solar generation would have to be adjusted up or down, as would any incentives for the other technologies, to reflect the appropriate value of the combined DERs for both the consumer and the system. This adjustment would be difficult in any case, but is complicated by the many overlapping regulatory proceedings, attribution methodologies and cost-effectiveness calculations. The simpler option is to incentivize consumers based on the capabilities and performance of any type or combination of beneficial DERs. Start with the premise that every consumer can better manage their energy use by adopting a range of clean DERs. Then, seek optimization of the suite of services they ultimately purchase by sending the right price and incentive signals for the capabilities and performance desired by the system. This would greatly reduce the complexity of harmonizing consumer and grid-wide system benefits. For example, the CPUC could develop technology-neutral use cases for DER operations to meet specific needs, such as load reduction, load shifting, voltage regulation and frequency response.  Rather than separately approving and designing incentives for each new technology or new combination of DER solutions, regulators could approve a process for relying on aggregated consumer performance. The CPUC has required regulated utilities to consider quantifiable societal benefits of DERs in distribution resource planning. To harmonize consumer and societal benefits, we will need new methods for quantifying societal benefits and sharing these benefits with consumers. Regulated utilities know how to include compliance costs in cost-benefit calculations. However, many societal benefits do not fit neatly into this category. Good examples of local government initiatives that are not incorporated into regulated utilities’ plans include: increasing resilience; implementing zero net energy codes and standards; reducing greenhouse emissions beyond state goals; setting local clean energy and energy management goals; and increasing local economic benefits of clean energy and energy management. Local efforts are critical to meeting state climate and clean energy goals. However, there’s no consensus among stakeholders about which local efforts should be supported with utility ratepayer dollars versus other local or state funds. One approach is to determine which local plans support statewide targets, such as climate goals, and which local targets primarily provide local benefits, such as local jobs requirements. In addition to determining how much ratepayers should pay for statewide societal benefits of DERs, regulators must also decide how to harmonize consumer and local societal benefits. For example, consumers within a local jurisdiction could be given the option to pay more to meet local goals that primarily provide local benefits. Local governments, consumer choice aggregators and DER solutions providers have been tackling these issues, and it’s time to connect these efforts with utility grid planning and resource planning. We recommend that regulators support demonstration projects to show how local entities can quantify and share societal benefits with community members. Over time, grid and resource planners across the country will no longer view DERs as disruptive resources. Rather, they'll be seen as ways to help consumers manage their energy use. Rather than restricting how and where DERs provide system value, planners can focus on sending the right signals to consumers and DER providers to deliver innovative solutions across the grid. Similarly, planners can both leverage and support local efforts to meet the state’s climate and clean energy goals and tap societal benefits. Stephanie Wang is a senior policy attorney at the Center for Sustainable Energy.

News Article | December 7, 2015
Site: http://cleantechnica.com

By Betsy Glynn, Northeast Regional Manager for Center for Sustainable Energy There’s no big surprise in Massachusetts earning the top spot for a fifth consecutive year in the State Energy Efficiency Scorecard issued by the American Council for an Energy-Efficient Economy (ACEEE). With a focus on capturing all cost-effective energy efficiency through utility ratepayer-funded programs, combined with strong state programs, buildings codes and deployment of combined heat and power (CHP) technology, the commonwealth’s electricity load has leveled off, and is even decreasing, as the economy continues to grow. However, with other states learning from the best practices of those with strong efficiency policies and programs and potentially leapfrogging ahead, the state may be on the path to a major upset in 2016. ACEEE’s Energy Efficiency Scorecard serves as a platform for national discussions about how to achieve energy and carbon reduction goals simultaneously, with annual and lifetime benefits far exceeding costs. Massachusetts earned 44 points in the 50-point ACEEE scorecard, compared to California’s 43.5. Third-place Vermont achieved 39.5 points whereas when the scoring began in 2006, it tied with Connecticut and California for the most energy efficient state title. While ACEEE reports Massachusetts’ electricity savings achievement level is at 2.5 percent, that figure represents only the savings goal set in its energy efficiency plan. In fact, in 2014, Massachusetts achieved electricity savings of 2.7 percent of sales by offering a variety of incentives and financing programs to encourage investments. Further, Massachusetts’ 2014 annual gas consumption was reduced by 1.33 percent of sales, compared to the goal of 1.15 percent. However, second-place California’s scoring is inching closer to Massachusetts, and this year the Golden State also received a “most improved” designation. Comparing California to Massachusetts can be difficult, given the inherent differences. For example, California’s population is nearly six times that of Massachusetts. From my house in Boston I can get to New York State in about two hours. I understand that it takes anywhere from 12 to 16 hours to drive from San Diego to the Oregon border (not accounting for traffic). If we begin to compare the two states in the ACEEE ranking, we can see some striking differences. Thanks largely to the Massachusetts Green Communities Act, it won all possible points in the utilities category, which encompasses policies and programs operated by or in partnership with utility program administrators. California, meanwhile, achieved 14 of 20 points in this category. In contrast, California won perfect scores in nearly all of the other categories: transportation, building codes, CHP, state-led initiatives and appliance standards. In these categories, Massachusetts achieved varied success in capturing points, with a low of zero for appliance standards. The two states are neck and neck on the total scoring, but are achieving those points in completely different ways. What would happen if Massachusetts adopts California’s stronger tailpipe emissions and appliance standards? And what if California begins to achieve stronger utility ratepayer-funded efficiency goals closer to the Massachusetts model? Of course, in this scenario, we’re not talking about the other 49 contenders (including Washington, D.C.) – any of whom could catapult past these two top-tier states. Another variable in the race to the top is the scoring system. ACEEE is constantly evolving the scoring to accommodate new technologies and practices, to capture the full possibility of opportunities to achieve savings. Will there ever be a perfect score? If there is, then how will we know the extent that future perfect-score states could be improving? In my professional circle, I regularly hear speculation about how the next scorecard ranking will pan out. When we have this simple platform, we can see how to learn from each other to achieve even greater savings moving forward. The differences between states’ energy efficiency performance levels represents a huge opportunity to fill the gap in performance so that we can all enjoy the benefits of a lower overall cost of energy, less reliance on carbon-emitting fossil fuels, improved energy reliability and increased local job growth. Recently, in Minneapolis during a discussion among national energy efficiency experts talking about the scorecard, one colleague from another state jokingly shook his fist in my direction while exclaiming, “We’ll get you, Massachusetts!” Reprinted with permission.    Get CleanTechnica’s 1st (completely free) electric car report → “Electric Cars: What Early Adopters & First Followers Want.”   Come attend CleanTechnica’s 1st “Cleantech Revolution Tour” event → in Berlin, Germany, April 9–10.   Keep up to date with all the hottest cleantech news by subscribing to our (free) cleantech newsletter, or keep an eye on sector-specific news by getting our (also free) solar energy newsletter, electric vehicle newsletter, or wind energy newsletter.  

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