NewEnergyNews: 12/01/2021 - 01/01/2022

NewEnergyNews

Gleanings from the web and the world, condensed for convenience, illustrated for enlightenment, arranged for impact...

The challenge now: To make every day Earth Day.

YESTERDAY

  • FRIDAY WORLD HEADLINE-Global Leaders Name Climate Crisis World’s Biggest Risk
  • FRIDAY WORLD HEADLINE-New Energy’s New Storage Options
  • THE DAY BEFORE

  • Electricity Rates That Offer Equity
  • THE DAY BEFORE THE DAY BEFORE

  • Electricity Rates That Offer Equity
  • THE DAY BEFORE THAT

  • Weekend Video: Comparing Zero Carbon Energies
  • Weekend Video: Winterizing Texas Wind
  • Weekend Video: Misinformation/Disinformation Against Solar
  • THE LAST DAY UP HERE

  • FRIDAY WORLD HEADLINE-From 2021 To 2022 With The Climate Crisis
  • FRIDAY WORLD HEADLINE-Four New Energy Focuses For 2022
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    Founding Editor Herman K. Trabish

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    Some details about NewEnergyNews and the man behind the curtain: Herman K. Trabish, Agua Dulce, CA., Doctor with my hands, Writer with my head, Student of New Energy and Human Experience with my heart

    email: herman@NewEnergyNews.net

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      A tip of the NewEnergyNews cap to Phillip Garcia for crucial assistance in the design implementation of this site. Thanks, Phillip.

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    Pay a visit to the HARRY BOYKOFF page at Basketball Reference, sponsored by NewEnergyNews and Oil In Their Blood.

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  • FRIDAY WORLD, January 14:
  • Global Leaders Name Climate Crisis World’s Biggest Risk
  • New Energy’s New Storage Options

    Friday, December 31, 2021

    2021’s Climate Crisis Top Ten

    From floods and wildfires to inaction and urgency: These are the top climate and weather stories of 2021

    Rachel Ramirez, Brandon Miller and Bill Weir, December 22, 2021 (CNN)

    “…The climate crisis took a catastrophic toll across the globe in 2021. From the Arctic to Louisiana and to China's Henan province, signs that climate change is already altering our weather were everywhere…As climate disasters mounted, the world aligned around combating the crisis: Scientists published a landmark report that concluded humans are unequivocally to blame; US President Joe Biden reentered the Paris Agreement in the early days of his administration; world leaders met at the UN climate summit in Glasgow, Scotland, to negotiate solutions.

    But promises were not met with action in 2021, and humans are pumping more planet-warming emissions into the atmosphere than ever. Experts now warn that the Earth is currently on track for 2.4 degrees Celsius of warming above pre-industrial levels -- far beyond the critical 1.5-degree threshold that scientists say we should stay under…These are the top 10 climate crisis stories of 2021…

    10. Historic rain at Greenland's summit…In August, precipitation at the typically snowy summit of Greenland fell as rain for the first time…It was the heaviest rainfall on the ice sheet since record keeping began in 1950, according to the National Snow and Ice Data Center. And scientists say it will occur more often…

    9. Texas deep freeze…February brought a historic deep freeze to Texas, which was also felt across much of the Central Plains and into the Southeast, and showed how the climate crisis can produce both hot and cold extremes…

    8. Fatal floods across three continents…In the span of a few weeks, destructive and fatal flash flooding ravaged parts of Western Europe, China's Henan province and the state of Tennessee…World Weather Attribution, a group of scientists that establishes the link between climate change and weather, found the record rainfall was up to nine times more likely due to human-caused climate change…

    7. US rejoins the Paris Agreement…Within hours of being sworn in, Biden signed an executive order in January to rejoin the global climate pact…In April, Biden pledged to cut US greenhouse gas emissions in half by 2030…However, the United Nations says there is still a huge gap between what's been promised and what scientists say is needed to curb emissions.

    6. UN report: A 'code red'…[The United Nations' Intergovernmental Panel on Climate Change report found it] is "unequivocal" that humans have caused the climate crisis and that "widespread and rapid changes" have already occurred, some of them irreversibly…

    5. A critical summit in Glasgow…And after nearly two weeks of negotiations on how to limit global warming, nearly 200 countries signed the Glasgow Climate Pact, which included the first-ever acknowledgment of the role burning fossil fuels have played in perpetuating the climate crisis…[but] negotiations around climate financing -- funding from wealthy nations to help low-income countries deal with the crisis -- broke down.

    4. Hurricane Ida…In late August, Category 4 Hurricane Ida destroyed homes, uprooted trees and cut off power to more than 1 million customers in Mississippi and the already storm-ravaged state of Louisiana…Ida checked all the boxes of how climate change is making hurricanes more dangerous…

    3. December tornado outbreak…The last month of the year is typically the quietest for tornadoes, but warm temperatures brought a historic twist…Though it's not completely clear what role climate change played in December's outbreak, scientists say the fingerprints of global warming can be found on every extreme weather event…

    2. Pacific Northwest heat wave…All-time record temperatures were set across the region, and scientists say the heat wave would have been "virtually impossible" without human-caused climate change… Officials later called the heat wave a mass casualty event…

    1. Drought, wildfires and water shortages…The megadrought also primed the landscape for perilous wildfires. The three largest fires of 2021 -- the Bootleg, Dixie and Caldor Fires -- have burned roughly 1.6 million acres, an area half the size of Connecticut…Scientists say this summer is only a preview of what's to come…” click here for more

    Thursday, December 30, 2021

    ORIGINAL REPORTING: A New Approach To Rooftop Solar Support

    SMUD on the Verge of Net Metering Breakthrough

    Herman K. Trabish, September 7, 2021 (California Current)

    Editor’s note: The SMUD Board approved this plan and it is being held up as the direction state regulators need to take in providing a successor tariff for solar statewide.

    The Sacramento Municipal Utilities District is considering a multi-faceted rate design that reduces the retail compensation to solar owners but adds features to drive the growth of solar plus storage. The proposal by staff includes a critical peak pricing rate that will give customers a very high per-kWh price for supplying generation stored in batteries at critical periods of demand when solar generation is reduced, like after sunset.

    It also includes an upfront rebate that will help customers cover the high cost of adding a storage system, and programs to low-income customers for offsite local solar system investments.

    “Retail rate NEM transformed the market and brought solar into the mainstream, but it is not good for the industry to argue that there hasn’t been a cost shift at SMUD,” solar advocate Vote Solar Senior Director for Grid Integration and former SMUD board member Ed Smeloff told Current. SMUD’s “new outside the box NEM design couples a reduced rate with incentives for storage to create more value.”

    Under SMUD’s current $0.12/kWh retail NEM credit, solar owners may be paid $0.05/kWh to $0.09/kWh more for their electricity than its value to SMUD, according to a disputed Energy and Environmental Economics (E3) Value of Solar study. That now adds up to $45/month for the average non-solar owning residential customer and could cost them $90/month in 2030.

    “We’re encouraged that the proposal seeks to engage solar and storage customers to meet SMUD’s ambitious climate goals,” Tesla Managing Policy Advisor Damon Franz said at a public SMUD meeting. He praised SMUD’s critical peak pricing, virtual power plants, and other incentives for storage. The new NEM proposal appears to align with Tesla’s business model focused entirely on solar plus storage systems.

    In addition to Tesla, public endorsements have come from leading battery provider STEM, the California Energy Storage Association, the Natural Resources Defense Council and the Environmental Defense Fund. Some solar plus storage proponents have concerns about Sacramento’s net energy metering proposal because it could contract the overall solar market… click here for more

    A Reliable, Pure New Energy Power System

    U.S. can get to 100% clean energy with wind, water, solar and zero nuclear, Stanford professor says

    Catherine Clifford, December 21, 2021 (CNBC)

    “…Transitioning to a clean-energy grid should happen by 2035, [according to Mark Jacobson, a Stanford professor of civil and environmental engineering and the director of its Atmosphere/Energy Program]…with at least 80% of that adjustment completed by 2030…[His newest work includes] granular data for how much heat will be needed in buildings in every state for the coming two years in 30-second increments…[It also makes use of] battery-storage technology to compensate for the inherent intermittency of solar and wind power generation…

    The Achilles’ heel of a completely renewable grid, many argue, is that it is not stable enough to be reliable. Blackouts have become a particular concern, notably in Texas this year and during the summer of 2020 in California…[Jacobson argues four-hour batteries are] a way to generate grid stability…To get more than four hours of charge, multiple four-hour batteries can be stacked to discharge sequentially. If a battery needs more charge output at one time than the battery can provide, then the batteries need to be used simultaneously…[This makes it] possible to transition to a fully renewable system without any blackouts or batteries with ultra-long-duration battery technology…

    …Planning, of course, is also key to keeping the grid stable…Also, there needs to be changes in pricing structures to motivate customers to do high energy demand activities at off-peak times…[There is stronger support for including other technologies like advanced nuclear in planning but Jacobson argues] the timeline for getting some of these technologies to commercialization is too long to be useful…” click here for more

    Monday, December 27, 2021

    Seeking Equity On Electricity Bills

    Advancing Equity in Utility Regulation

    Chandra Farley, Partnership for Southern Equity; John Howat and Jenifer Bosco, National Consumer Law Center; Nidhi Thakar and Jake Wise, Portland General Electric; Jean Su, Center for Biological Diversity; November 2021 (Lawrence Berkeley National Laboratory)

    Executive Summary

    According to the Partnership for Southern Equity, equity is just and fair inclusion, and energy equity is the fair distribution of the benefits and burdens of energy production and consumption. 1 In the context of electric utility regulation, equity can be a goal, tool, or metric. For example, the primary goal of electricity affordability programs, disconnection moratoriums, and rate discounts is to advance equity. Public participation and intervenor compensation are critical equity tools. Appropriate metrics are needed to track and evaluate results of policies, regulations, and programs intended to deliver equitable outcomes. All of these approaches are needed for successful energy equity initiatives.

    States are increasingly recognizing equity as a goal of utility regulation, going beyond the traditionally stated objectives to ensure that electricity systems are reliable, safe, and fairly priced. State initiatives are critical not only to address historical inequities, but to ensure equitable benefits and burdens in the transition to net-zero emissions by 2050. 2 Several states have enacted legislation to require or explicitly authorize utility regulators to consider equity, for all decision-making or for specific types of decisions— for example:

    • California adopted legislation two decades ago (SB 89, 2000) requiring environmental justice achievements to be part of the state’s mission. The state subsequently adopted several statutes directing the Public Utilities Commission to incorporate environmental and social justice objectives into various types of decisions, including prioritizing disadvantaged communities in integrated resource planning (SB 350, 2015) and implementing new approaches to reach communities affected by commission decisions (SB 512, 2016). A commission working group is identifying equity metrics for energy efficiency programs for customers of regulated utilities. 3

    • Colorado (SB 21-272, 2021) requires the Public Utilities Commission to adopt rules for “all of its work” to “…consider how best to provide equity, minimize impacts, and prioritize benefits to disproportionately impacted communities and address historical inequalities.” Another bill (SB 21-103, 2021) gives the Colorado Office of the Utility Consumer Advocate expanded authority to intervene before the commission on environmental justice, just transition, and decarbonization issues.

    • Among its provisions to advance equity and environmental justice, Illinois’ Climate and Equitable Jobs Act (SB 2408, 2021) requires the Commerce Commission to conduct a comprehensive study and submit a report to the General Assembly by January 1, 2023, assessing whether low-income discount rates for electric (and natural gas) residential customers are appropriate and potential design and implementation. Upon completion of the study, the commission is authorized to permit or require utilities to file a tariff establishing low-income discount rates. The bill also significantly increased minimum spending levels for low-income energy efficiency programs.

    • Maine (HP 1251, 2021) requires equity considerations to be incorporated in decision-making for state agencies, including the Public Utilities Commission.

    • In Massachusetts (Bill S.9, 2021), the Department of Public Utilities must include equity among six priorities for meeting statewide greenhouse gas (GHG) emission limits, in addition to safety, security, reliability of service, affordability, and reductions in GHG emissions.

    • In New York, the Climate Leadership and Community Protection Act (S6599, 2019) includes several energy justice provisions, including a requirement to direct at least 35%–40% of the program’s benefits to historically disadvantaged communities.

    • Oregon (HB 2475, 2021) recently added the following factors the Public Utility Commission may consider for classifying utility services for retail rates: “differential energy burdens on lowincome customers and other economic, social equity or environmental justice factors that affect affordability for certain classes of utility customers.”

    • Washington’s Clean Energy Transformation Act (SB 5116, 2019) charges the Washington Utilities and Transportation Commission with “Ensuring that all customers are benefiting from the transition to clean energy…[t]hrough the equitable distribution of energy and non-energy benefits and the reduction of burdens to vulnerable populations and highly impacted communities….”

    In other states, public utility commissions are taking action to ensure energy equity under existing authorities. For example, the New Jersey Board of Public Utilities created an Office of Clean Energy Equity, charged with ensuring the state’s clean energy future is accessible to all residents.4 As part of its new performance-based regulatory framework, the Hawaii Public Utilities Commission approved an energy efficiency performance incentive mechanism to encourage increased collaboration between the utility and the third-party efficiency program administrator to provide low-to-moderate income customers with opportunities to better manage energy consumption.5 The Connecticut Public Utilities Regulatory Authority embedded equity throughout its Framework for an Equitable Modern Grid, 6 such as planning to deploy 40% of residential storage installations for low-income households statewide and low-to-moderate income households in underserved communities. The agency also is prioritizing increased resilience for these households, as well as for environmental justice and economically distressed communities, customers with medical hardships, and public housing authorities.7

    To formalize its promotion of diversity, equity, and inclusion (DEI), the Michigan Public Service Commission updated its bylaws to include a nondiscrimination policy as an employer and a regulator. Further, commissioners and staff comprehensively examined commission practices and identified opportunities to meaningfully promote DEI, including development of an official DEI policy statement, review of existing hiring and advancement practices, consideration of DEI in regulatory strategies, promoting DEI education and awareness, and surveying employees about diversity issues. 89 In addition, the commission will coordinate with and provide data10 for the Department of Environment, Great Lakes, and Energy as the department considers environmental justice and public health in advisory opinions in utility integrated resource planning proceedings. 11

    Utilities also are targeting new energy programs to address historical inequities, with support of state policy and regulatory actions.12

    At the national level, the Biden Administration issued an Executive Order13 and created the Justice40 initiative14 to ensure that federal agencies work with state and local governments to “deliver at least 40 percent of the overall benefits from federal investments in climate and clean energy to disadvantaged communities.”

    All of these activities are important steps toward ensuring an equitable transition to a clean energy future.

    Earlier reports in the Future Electric Utility Regulation series15 considered equity issues for low-income households with respect to recovery of utility fixed costs and transportation electrification. This report provides four perspectives on systemic changes to advance equity in electric utility regulation, from representatives of energy justice and consumer organizations and a leading utility in this area.

    Chandra Farley, Partnership for Southern Equity (chapter 1), begins the conversation by examining energy equity and explaining why it is a crucial goal of utility regulation. She examines current inequities through a regional lens and provides practical steps toward energy justice, listed further below.

    John Howat and Jenifer Bosco, National Consumer Law Center (chapter 2), use data from the U.S. Energy Information Administration to develop a series of graphs that illustrate historical inequities in the allocation of energy system costs and benefits based on household income, race, and ethnicity. The Center’s “Equity Enhancement Toolbox” includes: (1) regular filing of granular utility data on residential customer counts, billing, receipts, arrearages, disconnections, and related credit and collections protocols to make visible the challenges and consequences of home energy affordability; and (2) bill affordability programs that meet key objectives for home energy security. They also make the case for additional consumer protections; programs that extend access to energy efficiency, solar, and electrification for disadvantaged households; and improved public participation in regulatory decisions for electric utilities.

    Nidhi Thakar and Jake Wise, Portland General Electric (chapter 3), describe “the need to address historic and systemic barriers that have prevented and continue to prevent the progress and participation of historically underrepresented groups, in support of fostering equitable outcomes for all.” Their essay explores how the utility is working to address three core energy justice principles—procedural justice, distributive justice, and restorative justice—in regulatory relationships and service to utility customers and communities. They provide examples in the context of state legislation, responses to the COVID-19 pandemic and wildfires, a new multi-year planning process for utility investments in distribution infrastructure, a community-based smart grid test bed, engagement with community-based organizations and Tribes, and workforce initiatives. Jean Su, Center for Biological Diversity (chapter 4), lays out the injustices of the current energy system disproportionately experienced by communities of color and low-wealth communities due to fossil fuel pollution and health impacts; energy burden, energy insecurity, and energy poverty; climate disasters; and ecocide. She then focuses on legal and regulatory pathways toward addressing chronic energy injustices.

    Following are top recommendations gleaned from each of these essays: 16

    Chapter 1

    • Extend public engagement in utility regulatory decision making to include environmental justice organizations and provide the capacity for their effective participation through intervenor funding. • Prioritize knowledge- and capacity-building on energy equity issues, both for people who may bear the brunt of inequitable outcomes and in statehouses and utility commissions. • Mobilize coalitions of “uncommon allies”—clean energy, civil rights, and equity and environmental justice groups—to inform and educate “first-person advocates” on energy issues and utility decision-making. • Expand the meaning of safe, reliable, and reasonable electricity service to include equity impacts. • Enact legislation that protects against service disconnections, eliminates predatory disconnection fees, and funds bill assistance programs like percentage of income payment plans. • Support utility programs and retail rate design that increase deployment of energy efficiency and other clean distributed resources for energy-burdened households. • Involve impacted individuals and communities and environmental justice organizations in program design and evaluation and resource planning activities. • Publicly post shutoff and arrearages data and use it to tailor programmatic solutions.

    Chapter 2

    • Protect vulnerable populations while also working to reduce greenhouse gas emissions by guiding utility investments and services toward achieving both equity and clean energy imperatives for electricity systems of the future. • Reverse the regressivity in the distribution of electricity system costs and benefits through comprehensive and proactive actions that at a minimum address the following inequities: o The proportion of income required to maintain basic electric service o Access to on-site energy generation, storage, and energy efficiency technologies—and the bill savings and resilience benefits they can provide o Uninterrupted and affordable access to a basic level of electricity service • Require electric service providers to report at a zip code-level the key data points needed to determine the extent to which residential customers are affordably accessing and retaining essential utility service. • Ensure that utility affordability programs: serve residential electricity customers who are incomeeligible to receive federal energy assistance; lower participants’ energy burdens to an affordable level; promote regular, timely payment of utility bills by participants; comprehensively address payment problems associated with participants’ current and past-due bills; are funded through a mechanism that is reliable while providing sufficient resources to serve all income-eligible customers and meet policy objectives over an extended time frame; and are administered efficiently and effectively. • Reexamine existing utility consumer protections to ensure that vulnerable customers who demonstrate good faith efforts to make affordable utility payments are protected from loss or degradation of service. • Design low-income energy efficiency and technology distribution programs to require no up-front payments, result in positive cash flows, and mitigate any financing risks for participants.

    Chapter 3

    • Approach community engagement, in pursuit of the twin goals of equity and decarbonization, through the lens of environmental justice and in alignment with the Government Alliance on Race and Equity’s Racial Equity Toolkit: listen and communicate, use data, ensure budget, ensure relevancy, and ensure time. • Provide financial support to community-based organizations to enable their participation in utility proceedings and incorporate recommendations from these organizations in community engagement plans. • Ensure that all communities the utility serves may benefit from a clean energy future by acknowledging those hardest hit by climate change impacts—and least able to avoid them—and providing access to opportunities. • Consider distributive justice in utility program design and pricing. • Acknowledge and seek to repair past harm by working with stakeholders on resilient solutions to climate change impacts. • Partner with local cities and counties to advance their climate and sustainability action plans, work with community action agencies to deliver energy assistance to utility customers, and support state and federal legislation that assists low-income and vulnerable communities.

    Chapter 4

    • Expand the definition of “public interest” to encompass climate, environmental, and energy justice goals—for example: o When considering certificates of public convenience and necessity for new energy infrastructure o To protect utility customers from undue financial risk, including financial losses from stranded carbon-emitting assets, climate change-induced damages to generating facilities and delivery systems, reputational damage that may drive loss of investors, and access to insurance • Consider energy burden, energy insecurity, and energy poverty as requisite factors in rate design. • Prioritize deployment of energy efficiency, demand-side management, rooftop and communityowned solar, distributed storage, and microgrids for low-income households and energy-burdened communities…

    Saturday, December 25, 2021

    Texas Christmas

    From RTannamal via YouTube

    Australian Christmas

    From Fascinating Aida via YouTube

    European Christmas

    So many people in so many places have forgotten that we have things in common that can overcome our differences if we just let go of what drives us to war. From John Huffman via YouTube

    Friday, December 24, 2021

    The Climate Crisis And The Carbon NOT Burned

    Metaverse Fights Climate Crisis

    Zen Analyst, December 22, 2021 (Seeking Alpha)

    “…[The metaverse] holds the promise of radically altering individual and institutional behaviors to reduce the global economy's carbon intensity significantly…[I]nternet and software industries, or the information technology sector, are not among the top emitters, although they are multiple times more valuable in market valuation…As the economies advance and more economic activities shift from analog to digital, the carbon intensity of economies should decrease over time…Technology tends to reduce the carbon intensity of economic output since technology tends to do more with fewer inputs…[and] the carbon emission intensity of per dollar GDP has been falling globally…

    The internet is currently transitioning into the metaverse…[and] the metaverse will likely impact every industry, much like the internet…[The primary opportunities are in] the digitalization of transportation and manufactured goods…[The metaverse of work] should over time make remote work a more compelling option for more workers…[That] will reduce the need for office construction and commuting…[T]he rise of the consumer metaverse is digitalizing travel, social interaction, play, and goods…

    If metaverse companies are perceived to play a crucial role in fighting climate change, it should help their valuation…[though the metaverse's uncertain impact on mental health] could negate its positive contribution to lowering emissions…[M]ental health concerns have persistently dogged social media platforms, video games, and digital collaboration…[But] the positives may] outweigh the negatives for most…which should ultimately lead to a reduction in carbon emissions per capita…” click here for more

    Europe’s New Energy Price

    Renewable capture prices: why they are crucial for energy transition

    Kira Savcenko and Mario Perez, 21 December 2021 (S&P Global)

    “…In Western Europe, S&P Global Platts Analytics expects wind and solar generation to account for 47% of power demand by 2030, compared to an estimated 23% in 2021. Renewable production revenues are becoming increasingly important…Power grids accept the most affordable form of generation available, which often ends up in periods of cheap supply influx during favorable weather conditions…

    And priority dispatch now puts an obligation on transmission system operators to schedule and transmit electricity from renewable sources ahead of other producers, as long as it allows secure running of the system…[The capture price] is on average below baseload power contracts…Capture prices are expected to decrease as renewable capacity continues to grow, with sharp deviations from baseload prices registered during extreme weather periods…[and already happens in] Germany, Spain and the UK…Traders can use the capture price values for market-to-market in their hedging, as the indices will help to identify risk and opportunities in renewable behavior…

    …[Gradual coal phase-out] ended up in power prices being much more exposed to gas. This helped to lift power prices…[Power price spikes] typically take place, when wind generation is very low. This means that significant flexible capacity – mostly gas – is needed, with wind generators not able to capture these prices…[A] road to energy transition, with global stilling [of wind supply], extreme price swings and limited gas supply in the midst of coal phase-out…brings fresh challenges on a daily basis…[Transparent capture price indices will help] provide the industry with essential intelligence to reach climate targets.” click here for more

    Wednesday, December 22, 2021

    ORIGINAL REPORTING: California’s Grid Operator Makes A Big Rule Change

    Grid Operator Reform with Big Implications for a Western Energy Market

    Herman K. Trabish, September 6, 2021 (California Current)

    Editor’s note: This rule change brought a wide range of out-of-state utilities to a new initiative to build a regional market.

    The California Independent System Operator leaders enabled a critical governance change that gives new powers to the Energy Imbalance Market Governing Body, which could transform the energy markets across the entire West, analysts said.

    The CAISO Board, appointed by California’s governor, voted Aug. 20 to give the EIM Governing Body more authority in decisions applicable to each the CAISO and EIM markets. The revision also lays out procedures for settling disputes when the two interests diverge.

    Any proposal impacting both markets would require a majority vote from each authority to go into effect, according to EIM Governance Review Committee Chair Therese Hampton.

    The governance change was a “necessary” but by no means final step towards a western-wide Regional Transmission Organization because stakeholders outside California will not accept market governance with dominating California leverage, said Western Grid Group Director Douglas Howe. He is a member of the CAISO Board-appointed Governance Review Committee that developed the new joint authority.

    The voluntary EIM was launched by PacifiCorp, a subsidiary of Warren Buffett’s Berkshire Hathaway Energy, and CAISO in November 2014 to optimize real time dispatch. Previously, the West’s 38 balancing authorities met real time supply-demand needs independently. The EIM’s second quarter 2021 filing showed quarterly benefits of $132.7 million for its 15 participants from optimized cost-effective dispatch.

    With EIM cumulative benefits now at $1.42 billion, with six participants being added by 2023, regional leaders see a new opportunity. Moving from the estimated 5% of real-time power flows in the EIM to optimizing dispatch of all the resources in Western markets could save billions of dollars in meeting the high renewables and emissions reduction mandates across the West, stakeholders told Current…” click here for more

    Five New Energy Insights From 2021

    The 5 biggest clean energy stories from 2021

    Sarah Golden, December 16, 2021 (GreenBiz)

    “…[T]he public and private sectors are spurring forward the great energy transition in meaningful ways…[But, one, past] performance is no indication of future grid stability…All signs point to weather getting more extreme…Power outages jumped 73 percent in the U.S. last year…As a result, communities and organizations are beginning to think about the value of resilience…During COP26, 40 world leaders signed onto an agreement to, two. decarbonize five high-carbon sectors: steel; transport; agriculture; hydrogen; and electricity. The countries represent more than 70 percent of the world’s economy…[And] industry is showing that [green steel produced using clean energy] is possible…

    Long-duration energy storage — defined as a system that can store energy for more than 10 hours — has been the Next Big Thing for about 20 years. But 2021 may, three, just have been the tipping point…[After the U.S. Department of Energy’s Energy Earthshot Initiative to drive down the costs of long-duration energy storage by 90 percent by 2030,] a tremendous amount of finance flowed to the sector, with funds backing new technologies and companies that have the potential to unlock the Holy Grail of deep decarbonization…As the clean energy procurement market matures, some corporate buyers are, four, looking beyond the number of megawatts to more holistic criteria when considering new energy deals…

    …[D]eals are increasingly taking into account land use and the full life cycle of materials used in clean energy technologies…[But, five,] supply chain disruptions have increased the cost of projects…As a result, some corporate buyers are waiting for costs to fall before engaging in new projects…[A] marginal increase in costs could derail important progress in the clean energy transition…” click here for more

    Monday, December 20, 2021

    MONDAY STUDY – Rates To Grow Customer-Owned Resources

    Smart Rate Design for Distributed Energy Resources

    Mark LeBel, Jessica Shipley, Carl Linvill and Camille Kadoch, November 2021 (Regulatory Assistance Project)

    Reforms to Consider and Evaluation of Potential DER Rate Design Pathways

    Defining the Key Issues

    With at least four important rate-making principles and numerous additional policy goals for utility regulation, sorting through the key issues can be a challenge. We suggest four primary criteria, derived from long-standing regulatory principles, by which to evaluate DER rate designs:

    Fair cost allocation.

    Efficient customer price signals.

    Customer understanding and acceptance.

    Administrative feasibility.

    This is not to imply that other principles and goals are unimportant but rather that other goals are less directly affected by DER rate design (e.g., it’s likely that revenue stability would be significantly affected only in extreme cases) or require further quantitative analysis to determine (e.g., impact on DER-related jobs and industries). Progress toward the policy goal of societal equity, for example, is also possible through structural reforms. See the text box below for a discussion of equitable distribution of program benefits, particularly the potential for remedying inequity concerns through community solar.

    The easiest reference point for comparing our three alternative pathways below is the current inflow/outflow method and framework used in the DG program in Michigan.

    Equitable distribution of program benefits

    In some places with higher levels of distributed solar PV adoption, concerns have arisen that the customers adopting solar were primarily homeowners with above-average incomes and broader demographic characteristics that were not representative of the entire population. In particular, renters and other residents of multifamily buildings cannot generally install solar on their rooftops. While these concerns should be evaluated fairly, there are two ways of resolving them. One is to shut down program participation, but the other is to try to open the programs to broader public participation. This can be done through additional incentives but can also be achieved through more structural reforms. Introducing community solar, in which larger solar projects are separately interconnected to the distribution system and the utility credits subscribing customers, could be one such structural reform. Community solar customers enjoy a lower electricity bill but also make a monthly payment to the owner or operator of the community solar project, often having substantial overall net bill savings. Of course, if there are concerns about the crediting mechanism and levels for community solar projects, that raises another set of potential concerns, which was one of the significant motivations for the New York VDER tariff reforms.

    In addition, it has been the case in many jurisdictions that commercial and industrial customers were also effectively prevented from meaningful participation in net metering programs, either because of size restrictions on projects or the fact that substantial demand charges for these classes meant significantly lower compensation through net metering. Reforming crediting mechanisms and other program rules to allow for comparable adoption levels by C&I customers is another way to promote an equitable distribution of program benefits.

    Fair Cost Allocation

    The concept of fair cost allocation typically goes back to the foundational questions mentioned earlier around the principles of cost causation and costs following benefits. Although these principles are often applied at the stage of a rate case when costs are being divided up among customer classes, they apply equally to dividing up costs among customers within a class, sometimes called intraclass cost allocation. As may be evident, the question of cost causation is typically linked to efficient marginal cost pricing; we discuss this further below.

    The broader principle of “costs follow benefits” is typically applied to categories of costs that do not have a direct cost causation basis related to customer usage or other characteristics. At a minimum, this includes A&G costs and any program costs primarily motivated by societal benefits (e.g., low-income discounts), albeit under two slightly different theories. A&G costs literally benefit all customers because none of the services provided by the utility could be carried out without those costs. Programs justified by societal benefits are somewhat different because the benefits are not directly related to utility service provided to customers. Instead, broad allocation of these costs, across and within customer classes, is about shared responsibility.103 In both these cases, there is not an economically correct division of costs.

    A more complex case arises in regard to elements of the electric system that do not necessarily have a direct cost-causation link to customer behavior, such as the “minimumsized distribution system” referenced in the Bonbright quote on Page 41 of this report. These costs vary most directly with the size of the area the system covers or length of the lines, a factor that is not simple to include in rates; the practice of postage stamp rates generally prohibits including it. However, there is an important sense in which different customers benefit from this distribution system backbone in proportion to their usage. With the further development of DERs and with more customers exporting to the grid, the best way to think about this phenomenon may be changing in the modern grid. In other words, the distribution system may no longer be built simply to ensure deliveries and sales, but also to support bidirectional flows.

    Efficient Customer Price Signals

    The principle that prices should send efficient signals to customers has long applied to customer usage, and in a modern grid this concept must be extended to a customer’s ability to store and generate electricity. According to microeconomic theory, prices are most efficient if they reflect marginal costs, although this statement glosses over many theoretical difficulties and practical disputes. For example, some analysts prefer to consider only short-run marginal costs, particularly locational marginal prices in wholesale energy markets. The better perspective is to include long-run marginal costs of generation, transmission and distribution capacity, as these costs are ultimately caused and justified by customer usage, generation and storage optimization choices. It is also generally the case that maximizing societal well-being requires the inclusion of externalities as a marginal cost. This can justify a higher assignment of residual embedded costs to certain pricing elements or the overall assessment of program costs and benefits using the societal cost test. Of course, externalities are not included directly in the cost of service, except as motivation for certain programs and various costs the utility incurs. Furthermore, the consideration of externalities in pricing has other practical consequences, including distributional impacts.

    The customer behavior factors that underlie marginal cost are often referred to as cost causation, as discussed previously. From the perspective of the electric system, an additional unit of energy exported from a customer has largely the same impact as an additional unit of reduced consumption or an additional unit of generation consumed behind the meter that reduces imports, at least until the point of substantial reverse flows on elements of the grid. The marginal emissions impact, with associated environmental and public health consequences, can, however, be different, depending on the emissions profile of the distributed generation. REC policy is one way of accounting for these distinctions, which can be incorporated into DER rate design.

    Cost causation, and the associated optimal marginal cost price structure, can be different for different elements of the electric system. Sending a monthly bill (either physically or electronically) has associated recurring costs that arguably fit into a customer charge. The broadly shared electric system fits well into a time-varying kWh pricing framework, although there are numerous disputes about how best to draw the connection between cost causation and workable pricing schemes. Service lines, secondary voltage lines and line transformers are mixed cases where the best proxy is subject to significant uncertainty. Depending on one’s assumptions about cost causation at this part of the system and trade-offs with other rate-making principles, these costs could be best recovered through customer charges, demand charges or kWh rates.

    All deviations from efficient marginal cost pricing produce “inefficient” behavior, and any real-world pricing scheme will reflect such deviations for at least two reasons: (1) marginal cost pricing, regardless of someone’s preferred definition of marginal cost, virtually never matches the cost-of-service revenue requirement and (2) in most cases, proxies for marginal cost are often necessary instead of more precise and accurate pricing schemes, particularly for smaller and less sophisticated customers. In either case, deviation of pricing from marginal costs will cause distortionary behavior from customers, at least compared to the theoretical optimum. This is true regardless of the pricing element where a deviation is applied. For example, customer charges that are higher than marginal cost provide an inefficient incentive for customers to avoid those charges, either through formal or informal master metering or outright disconnection from the electric system. The latter possibility, also known as grid defection, was traditionally held to be unlikely, but continued cost declines for solar and storage, along with the availability of other backup generation options, may make it economically feasible for some customers in the near future. Extremely rural customers and specialized end uses (e.g., crosswalk lights and highway signs) that used to be connected to the grid have already defected to solar and storage in many places.

    Customer Understanding and Acceptance

    The criterion of customer understanding and acceptance for residential customers covers several related issues. To begin, basic principles of fair play in a modern marketplace dictate that customers understand what they are paying for and why. Any differences compared with what their friends and neighbors are paying should be intuitive and explainable without recourse to jargon impenetrable to the public. Furthermore, many customers are making choices within an overall budget and would like to know their options and how they can save on electricity or other utility bills.

    There is also a meaningful sense in which customer understanding impacts the effectiveness of price signals built into electricity rates. Price signals can only work as intended if customers are able to respond to those incentives. Customer education, gradual introduction of reforms that build on each other, and understandable rules of thumb (e.g., consume less on hot summer afternoons) are all helpful tools to improve customer response. More sophisticated tools and efforts are possible as well. Online data provision, automated energy management technology and storage, and the availability of third-party aggregators or other energy management companies can all augment a customer’s capabilities

    Administrative Feasibility

    Typical utility rate-making practices across the United States today are already fairly lengthy and resource intensive, with significant administrative costs throughout the process. Introducing reforms into this process can be resource intensive as well, including the cost of new types of proceedings and new analytical requirements. Smaller reforms that make gradual changes to existing processes are likely easier to manage with little incremental costs once a clear decision has been made. However, major reforms that make serious improvement to the efficiency and equity of programs or rate structures can have benefits that justify the administrative costs. In any case, weighing these implementation concerns is important to make sure that reforms are implemented well and are not an unnecessary and unfair burden on implementing agencies or any of the stakeholders…

    Potential Pathways for New Rate Designs for DERs

    Sections 4 and 5 discussed a wide range of options for overall program structure and rate and credit design. These different options can be combined into even more overall reform packages. We present three illustrative potential pathways in this section:

    Gradual evolution pathway.

    Modest improvements to the efficiency of pricing for new DG customers and overall rate design, along with associated cost allocation improvements, with a minimal need for new customer education efforts, process reforms or administrative burdens.

    Advanced residential rate design for DERs pathway.

    An aggressive effort to enlist a large segment of residential customers in more sophisticated time-varying rates on a default or mandatory basis to optimize their usage, storage and generation patterns to lower overall system costs while ensuring fair cost recovery with new rate structures. This effort may require significant new analysis and process reforms, as well as customer education and assistance with energy management.

    Customer choice and stability pathway.

    A simple and understandable set of options for customers that are fair to nonparticipating ratepayers, with stable payment schemes that may lower barriers for both customers and DER companies. This model requires significant administrative efforts to determine and update value-based credits and set the grid access charge.

    These three potential pathways are not exhaustive and do not even use all the program elements discussed in Section 4 or every rate design and credit option in Section 5. However, they do present coherent frameworks to illustrate key principles and trade-offs. As policymakers and stakeholders consider the best path forward for DER rate design, and electric system reform more generally, we hope that this framing illustrates key choices and how to think about constructing overall reforms…

    Key State Examples

    A. Duke Energy Settlement in North and South Carolina

    In September 2020, Duke Energy Carolinas and Duke Energy Progress reached an agreement with solar and environmental advocates in North and South Carolina to revise the tariffs offered to residential solar customers. The development of the agreement was largely in response to South Carolina’s Energy Freedom Act (Act 62 passed in 2019) and North Carolina’s House Bill 589 (passed in 2017). In May 2021, the South Carolina Public Service Commission unanimously approved the settlement.111 The new compensation mechanism, called solar choice metering, is scheduled to apply to all new residential customers on or after January 1, 2022.

    The agreement includes several key elements:

    1. A minimum monthly bill of $30 for each solar choice metering customer. The agreement states that this is to ensure the utilities can recover estimated customer and distribution costs.

    2. Time-varying pricing, including TOU periods and critical peak pricing, which will encourage DG customers to reduce consumption when prices are high. Customer energy imports and exports are netted within each TOU pricing tier, and monthly net exports are given a bill credit at the approved avoided cost rate. This credit can be used to reduce a customer’s bill after the minimum bill has been applied. Critical peak pricing applies to imports during specified hours, and any energy exports during those hours are netted against peak imports.

    3. A monthly grid access fee for facilities larger than 15 kW.

    4. Nonbypassable charges for demand-side management, energy efficiency programs, storm cost recovery and cybersecurity costs.

    5. A new incentive for qualifying solar choice metering customers to enroll in the proposed smart winter thermostat program. The agreement also includes a commitment on the part of the utilities to file a broader incentive program by June 1, 2022, that includes other peak load reduction technologies that can be paired with solar.

    Utility proponents of the agreement note that cost recovery from solar customers will be fairer under this structure. Duke Energy estimated that this structure would eliminate 92% or more of the current cost shift from solar owners to nonsolar owners, and the utility will be able to charge solar customers more during peak demand times when most customers are drawing a lot of power from the grid. Solar proponents note that customers whose panels can send energy to the grid during peak hours will be properly compensated, and solar customers will also be able to save money by participating in the peak load reduction aspects of the program.

    B. California: From NEM 2.0 Toward NEM 3.0

    California utilities have been obligated to offer a net energy metering tariff to their residential and commercial customers since the passage of SB 656 in 1995.112 From the first tariffs in 1996 up through 2016, NEM was priced at the full retail rate with an annual true-up. Rate design in California during this period was an increasing block rate with TOU tariffs offered as an option. Each utility was obligated to offer the NEM rate to all customers on a first come, first served basis until a prescribed cap was met. The cap was initially set at 0.1% of peak load but was raised several times before settling at 5% of peak load. The maximum size of NEM eligible systems settled at 1 MW.

    By 2013 utility-scale solar adoption was becoming significant in California. The combination of distributed solar approaching its 5% cap and the presence of thousands of MW of utility-scale solar contributed to the emergence of the duck curve at the California ISO. Assembly Bill 327 passed in 2013 to address a perceived disconnect between the compensation being provided to solar DG adopters and the value of solar DG to California’s electric system. For the first decade of solar DG adoption, the electric system peak coincided with hours of peak solar production, making solar production valuable in addressing increasing peak loads. However, utility-scale and distributed solar collectively surpassed 20% of annual peak load, with utility-scale solar reaching 4,495 MW in 2013, while distributed PV approached its 5% cap. This dramatic increase in solar production caused the peak to shift from the afternoon to the very late afternoon and early evening. With solar production no longer coinciding with the electric system’s peak and net peak, AB 327 mandated a reconsideration of the default NEM tariff, with the new default to become effective as the 5% cap was reached in the respective utility service territories.

    The California Public Utilities Commission issued Decision 16-01-044 in 2016 to implement the NEM successor tariff, commonly referred to as NEM 2.0.113 AB 327 specified some parameters for the revised NEM tariff, while others arose as the commission considered testimony and data from proceeding participants. AB 327 was concerned that NEM customers pay their share of nonbypassable expenses, which largely arise from public purpose programs incurring costs that utility ratepayers bear. These include programs like energy efficiency and low-income support. The issue of ensuring that solar adopting customers pay their share of system costs was addressed partly with this mandated feature and partly through additional features of the revised tariff, including:

    A mandatory interconnection fee.

    A minimum bill provision.

    The phase-in of mandatory TOU rates.

    NEM 1.0 customers were allowed to remain on that tariff, and NEM 2.0 customers were given a guarantee that their NEM 2.0 tariff would be available for 20 years.

    Since 2016, solar has grown rapidly in California. By 2020, utility-scale solar had grown past 15,000 MW and distributed solar had surpassed 10,000 MW. The California ISO peak load is a bit less than 50,000 MW, so the 25,000 MW of solar is quite significant. In 2020, California utility regulators commissioned the Net-Energy Metering 2.0 Lookback Study to assess the performance of the NEM 2.0 tariff.114 The study indicates that further changes in the NEM framework will be needed to address persistent cost shifting. Although commercial customers do not impose a cost shift, residential customers appear to significantly underpay their share of system costs. The California commission has launched NEM 3.0 to consider additional changes in rate and tariff design to address the cost shift and to better align rate design with cost causation.

    C. Arizona: Solar DG Export Tariff at the Resource Comparison Proxy

    The Arizona Corporation Commission (ACC) directed its staff to begin rule-making to develop net energy metering rules in 2007.116 The commission adopted NEM rules in 2008 that provided for annual netting where any end-of-year net kWh sales would be compensated at an avoided cost rate.117 The avoided cost rate was defined to be “the incremental cost to an Electric utility for electric energy or capacity or both which, but for the purchase from the NEM facility, such utility would generate itself or purchase from another source.”118 On December 3, 2013, the ACC issued Decision No. 74022, which ordered that a generic docket be opened on net energy metering issues.

    Docket E-00000J-14-0023 was opened in early 2014 to consider these issues. The ACC issued Decision No. 75859 on January 3, 2017, finding that NEM should be replaced with an instantaneous netting mechanism, known as the inflow/outflow model in Michigan, that compensates DG exports at the “actual value of DG.”119 NEM customers with an interconnection request that was filed before the effective date of the export credit tariff could remain with NEM for 20 years.

    The ACC determined that the value of DG should be set at an administratively determined avoided cost and advanced two methodologies: the staff avoided cost methodology and the staff resource comparison proxy (RCP) methodology, as modified by the ACC. The staff avoided cost methodology specifies energy, generation capacity, transmission capacity and distribution capacity, line losses and environmental costs at specified levels for five years.120 The RCP methodology uses the five-year rolling weighted average of a utility’s solar power purchase agreement and utility-owned solar generating resources with additions for the benefits of avoided transmission and distribution capacity investment and avoided line losses. The ACC specified that the inputs to the avoided cost methodology be updated every year and that the methodology be considered in full with each new rate case. The five-year duration was selected to reflect an expectation that a new rate case would occur approximately every five years.

    Arizona Public Service implemented the RCP methodology through its RCP Rate Rider.121 The rate rider specifies a 10-year rate (exceeding the initial five-year duration contemplated in the originating commission order) and carries the provision that the proxy will not decline by more than 10% per year. With utility-scale solar prices declining rapidly over the last five years, the 10% protection has proven important. For solar DG installed in 2017, the RCP is 12.9 cents per kWh. By 2021, the RCP declined to 9.405 cents per kWh.

    Residential solar customers at Arizona Public Service have three TOU rate design options, two of which include a demand charge. Nonsolar customers have the same TOU options and two options that are not TOU.

    D. Minnesota Value of Solar Tariff

    Minnesota passed legislation122 in 2013 that allows investor-owned utilities to apply to the Public Utilities Commission (PUC) for a value of solar tariff as an alternative to net metering and as a rate identified for community solar gardens. The 2013 legislation specifically mandated that the VOS legislation take into account the following values of distributed photovoltaics: energy and its delivery, generation capacity, transmission capacity, transmission and distribution line losses, and environmental value. The legislation also mandated a method of implementation whereby solar customers will be billed for their gross electricity consumption under their applicable tariff and will receive a VOS credit for their gross solar electricity production. To date, the VOS tariff has only been used for Xcel’s community solar gardens, and no utility has opted in to use it for rooftop solar PV projects.

    The Minnesota Department of Commerce was directed123 to establish a calculation methodology to quantify the value of distributed PV. The department submitted the draft methodology to the Minnesota PUC in January 2014.124 The PUC approved125 the methodology at a hearing on March 12, 2014, and posted the written order approving the methodology, with modifications the Department of Commerce had approved, on April 1, 2014.126

    VOS Methodology and Formula

    To calculate a utility’s VOS figure, several avoided cost components are each multiplied by a load match factor, if one is appropriate, and a loss savings factor. Adding the results of these separate component calculations produces the utility’s VOS figure. As a final step, the methodology calls for the conversion of the 25-year levelized value to an equivalent inflation-adjusted credit. The utility would then use the first-year value as the credit for solar customers and would adjust each year using the latest Consumer Price Index data

    There are eight components of value in the tariff:

    Avoided fuel cost.

    Avoided plant operation and maintenance — fixed. Avoided plant operation and maintenance — variable.

    Avoided generation capacity cost.

    Avoided reserve capacity cost.

    Avoided transmission capacity cost.

    Avoided distribution capacity cost.

    Avoided environmental cost.

    There are two placeholder components: avoided voltage control cost and solar integration cost. These components are not part of the VOS calculation at this time, but the Minnesota Department of Commerce anticipates that these categories of costs and benefits will be known and measurable in the future.

    Some key characteristics of the Minnesota VOS policy include:

    Investor-owned utilities may voluntarily apply to the PUC to enact a program in lieu of net energy metering.

    PV systems must be under 1 MW in size. Additionally, on-site production cannot exceed 120% of annual on-site consumption.

    Customer electricity usage is separate from production.

    o Customers are billed for their total electricity consumption at the retail rate.

    o Compensation for the solar system is through a bill credit, at the VOS tariff rate. Net excess generation is forfeit to the utility. The utility automatically obtains the solar REC.

    Value calculation:

    o It is production based and expressed in dollars per kWh, levelized over 25 years.

    o It is estimated as the combined value to the utility, its customers and society.

    o Value calculation process:

    -Once the VOS is established in any one year, that VOS is held constant for participating customers who install solar PV in that year.

    -The valuation will be updated annually for new VOS participants to incorporate utility inputs for the value of PV in the year of installation.

    -A utility-specific VOS input assumption table is part of the utility’s application and made publicly available.

    -A utility-specific VOS output calculation table will break out the value of components and the computation of total levelized value and be made public.

    o A tariff is not an incentive, and it is not intended to replace or prevent incentives. The utility automatically obtains a solar REC with zero compensation to the customer.

    Evolution in VOS Methodology Components

    In 2019 the PUC updated the VOS methodology for the avoided distribution capacity cost component. Since 2017, the VOS has been used as the basis for the bill credit in Xcel’s community solar garden program. In its May 1 compliance filing and its petition, Xcel argued that the current VOS methodology produces a VOS rate that is “unreasonable, unrepresentative, and clearly falls outside of the public interest.” Xcel pointed to the avoided-distribution-capacity-cost component of the methodology as the cause for volatility in the VOS rate because the component used peak demand data to arrive at the capacity cost, and peak demand is volatile year to year due to variables such as customer requirements and weather. Xcel argued that a volatile VOS rate is confusing to customers and inaccurately represents the value of distributed solar to the system, which does not significantly change from year to year.

    The PUC approved Xcel’s proposal to move to a five-year average of per-kW distribution spending to calculate the avoided distribution cost for the 2020 VOS rate applied to the community solar garden program. The PUC also directed Xcel to file a framework showing how specific types of distribution projects will be categorized for future calculations of the VOS avoided-distribution-capacity-cost component. Finally, the PUC directed Xcel to discuss with stakeholders how the following could improve the VOS methodology: (1) long-term load growth assumptions, (2) sensitivity analysis of different time periods for systemwide calculation and (3) methods to de-average avoided distribution costs to account for specific location differences…