NewEnergyNews: 02/01/2022 - 03/01/2022

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-New Energy Boomed With World 2021 Power Demand, Emissions
  • FRIDAY WORLD HEADLINE-Collaboration Can Cut Cost To Beat World's Climate Crisis
  • THE DAY BEFORE

    THINGS-TO-THINK-ABOUT WEDNESDAY,:

  • TTTA Wednesday-ORIGINAL REPORTING: Trying To Make Arizona’s Just Energy Transition More Just
  • TTTA Wednesday-Solar Prices Keep Getting Better
  • THE DAY BEFORE THE DAY BEFORE

  • Monday Study – New Insights On The Impacts Of Electricity Costs
  • THE DAY BEFORE THAT

  • Weekend Video: Diversity Commitment Growing In New Energy Industries
  • Weekend Video: Next-Gen Geothermal
  • Weekend Video: New Energy For New Build Housing
  • THE LAST DAY UP HERE

  • FRIDAY WORLD HEADLINE-Earth’s Numbers Show Record-Breaking Heat
  • FRIDAY WORLD HEADLINE-New Energy Could Save $$$Millions
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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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  • WEEKEND VIDEOS, October 1-2:
  • The Light From Solar Power
  • New Energy’s Delivery Needs
  • Think About Power To The Plug

    Monday, February 28, 2022

    Monday Study - Why Emissions Are Rising

    Preliminary US Greenhouse Gas Emissions Estimates for 2021

    Alredo, Rivera, Kate Larsen, Hannah Pitt, and Shweta Movalia January 10, 2022 (Rhodium Group)

    After the global pandemic spurred a year of economic upheaval in 2020, many looked to 2021 as a year for recovery. Despite the political and financial measures to support recovery in the US, 2021 was characterized by continued uncertainty as the country navigated a patchwork of COVID-19 prevention measures, access to vaccines, and the emergence of new variants. Consequently, the US economy—and production of greenhouse gas (GHG) emissions—remained below pre-pandemic levels.

    Based on preliminary data for 2021, Rhodium Group estimates that economy-wide GHG emissions increased 6.2% relative to 2020, though emissions remained 5% below 2019 levels. We don’t have final estimates of overall economic growth for 2021, but current estimates put year-on-year GDP growth at 5.7%. This indicates that GHG emissions rebounded slightly faster than the overall economy in 2021, largely due to a jump in coal-fired power generation, which increased 17% from 2020, and a rapid rebound in road transportation (primarily freight). As a result, progress in reducing US GHG emissions was reversed in 2021, moving from 22.2% below 2005 levels in 2020 to only 17.4% in 2021, putting the US even further off track from achieving its 2025 and 2030 climate targets.

    COVID-19’s economic and emissions impact in 2021

    As 2020 drew to a close, expectations for a rapid recovery in 2021 were high. Even as late as October 2021, the International Monetary Fund was forecasting a 6% rise in US GDP, more than recovering from the drop of 3.4% in 2020. But with the rise of the Omicron variant and its expected drag on growth, experts have since modified expectations. As of January 7, 2021, Goldman’s estimate of GDP growth in 2021 was 5.7%.

    Although we will need to wait for final economic growth estimates, greenhouse gas emissions appear to have rebounded faster than GDP in 2021, bouncing back 6.2%. The transportation and electric power sectors experienced the steepest rise in emissions relative to 2020—10% and 6.6%, respectively—both claiming back about two-thirds of the drop from 2019 levels (Figure 2). Industry, which saw the most modest drop in emissions in 2020 at 6.2%, rebounded 3.6% in 2021—making up just over half the difference from 2019 levels. Buildings saw the smallest rise in GHG emissions in 2021, growing only 1.9% from 2020, returning only a quarter of the drop in emissions from 2020.

    Modest rebound in transportation demand

    The largest increase in emissions in 2021 came from the transportation sector, reflecting high demand for freight transportation of consumer products and a modest recovery of passenger travel. The transportation sector—which accounts for 31% of net US emissions—experienced the largest decline in GHG emissions in 2020, dropping over 15% (283 million metric tons of CO2e) below 2019 levels (Figure 2). In 2021, despite seasonal rebounds, overall transportation fuel demand never fully returned to 2019 levels.

    During the first two quarters of 2021, fuel demand increased as COVID-19 vaccines became available (Figure 3). However, the appearance of new variants and breakthrough cases in late summer led to staggered fuel demand for the remainder of the year. Despite hopes that life would get back to normal in 2021, passenger travel never fully recovered to 2019 levels. After falling 13% in 2020, gasoline demand—indicative of demand for on-road passenger travel—rose steadily through 2021, ending the year 10% above 2020 levels. Despite air travel’s dramatic surge in 2021 (rising 26%), it remained down 24% below 2019 levels. Road freight was the only transport mode that rebounded beyond 2019 levels in 2021. Continued demand for consumer goods kept freight demand high, even surpassing 2019 levels for several months of the year. On a year-on-year basis, aggregate diesel demand rose 9% from 2020 levels, putting it at 0.4% above 2019 levels.

    Coal’s comeback

    The electric power sector, which accounts for 28% of net US emissions, saw the second largest increase in GHG emissions from 2020 levels. In 2021, emissions increased 6% (95 million metric tons CO2e) above 2020 levels (Figure 2). Despite the bounce back from 2020, emissions remained 4% lower than 2019 levels.

    With only modest growth in overall electric power demand in 2021 (up 3% from 2020), the more robust growth in power sector GHG emissions was due to a sharp rise in coal generation, jumping 17% in 2021. This marks the first annual increase in coal generation since 2014, according to the US Energy Information Administration (Figure 4).

    Coal’s rebound was driven largely by a run-up in natural gas prices, with Henry Hub spot prices averaging $4.93 per million Btu in 2021, or more than double their 2020 rate. Prices rose as oil and gas producers ramped down new production in 2021 in response to the COVID oil price collapse and ensuing slow growth in demand. High natural gas prices made gas-fired generation less economical in 2021, leading to a 3% decline in gas generation in 2021, dropping gas’s share of overall generation back down to 37% (Figure 5). Renewables continued their growth in 2021, with generation rising 4% (about half the rate of renewables growth in 2020), reaching 20% of US electricity generation for the first time.

    The 2021 emissions rebound puts the US further off track to meeting its Paris Agreement target

    The uptick in GHG emissions in 2021 moves the country even further from meeting its Paris Agreement climate target of reducing emissions 50-52% below 2005 levels by 2030. In 2020, due to the economic impacts of the COVID-19 pandemic, emissions fell to 22.2% below 2005 levels. In 2021, US emissions ticked up to 17.4% below 2005 levels (Figure 6). As we discuss in our recent report, Pathways to Paris: A Policy Assessment of the 2030 US Climate Target, joint accelerated action by Congress, the federal executive branch, and leading states can put the 2030 target within reach, but all must act quickly in order to put the US on track.

    Saturday, February 26, 2022

    All About Nord Stream Two

    More than a pipe – but stuck with it? Not anymore. From The B1M via YouTube

    Heads Of Energy And Transportation Drive Electric

    A joint agency rollout of 500,000 charging stations is coming. From U.S. Dept. of Energy via YouTube

    Tomorrow’s New Energy Inches On

    Fusion energy will be a gamechanger – if it ever actually becomes tomorrow’s New Energy. Wind, solar, and batteries work now. From SciShow via YouTube

    Friday, February 25, 2022

    Ukraine And Europe’s Natural Gas

    Is Putin’s Ukraine invasion about fossil fuels? The continent has grown over-reliant on Russian gas – but Putin knows he is vulnerable to Europe cleaning up its energy sector

    Fiona Harvey, 24 February 2022 (UK Guardian)

    “…Europe is dependent on Russia for about 40% of its natural gas supplies, and despite the expansion of renewable energy over the past two decades, that dependency is increasing as countries shift to gas, away from dirtier coal. Germany is particularly vulnerable, as it has shut down nearly all of its nuclear power stations and aims to eliminate coal by 2030…[Gazprom’s $11bn Nord Stream 2 from Russia across the Baltic to Germany] was announced in 2015. Construction on the 1,200km pipeline was completed last year, but no gas has yet flowed and its future is now in doubt as Germany’s chancellor Olaf Scholz dramatically halted approval for the project on Tuesday…

    Vladimir Putin has a long history of territorial ambitions in former Soviet nations…[T]he Ukraine crisis is not a war over resources, but it has many implications for resource use…[In] the longer term, as Europe weans itself off gas and pursues net zero emissions, the value of this political weapon will wane rapidly…Any further reductions of Russian gas supply to Europe would have severe consequences, for Europe but also for Russia itself…

    Russia makes little or no attempt to capture methane from its oil and gas drilling…Russia could provide an invaluable service to the rest of the world by plugging these leaks – reducing methane globally by a third by 2030…Putin believes he has to the largest extent sanction-proofed Russia, but Russia earns hundreds of millions of dollars a day from sales of oil and refined products, and more from sales of gas and minerals…The crisis in Ukraine shows that some fossil fuel producers at least may not want to give up without a struggle…” click here for more

    Big Money Moves In Global New Energy

    Global decarbonization goals drive renewables M&A

    February 23, 2022 (White and Case)

    “…[D]ealmaking within the global energy sector reached new heights in 2021. A total of 973 [mergers and acquisitions] were announced over the course of the year—the highest annual total on record. An annual deal value of US$218.8 billion, meanwhile, was second only to 2007’s US$247.7 billion and follows two consecutive annual increases…[C]ompanies engaged in the production and distribution of renewable energy sources have become hot properties. M&A has become a crucial tool for companies looking to gain market share in this ever-expanding industry…

    Among the largest renewables transactions in 2021 was US-based energy firm Avangrid’s issue of US$4 billion of stock in a private placement to new investor Qatar Investment Authority (QIA) and existing majority shareholder Iberdrola, a Spanish energy firm. Avangrid is a sustainable energy company with both natural gas and renewables assets, and is the third-largest wind operator in the US…

    The high-growth potential of the sector has drawn interest from infrastructure investment funds across the globe…India’s renewables sector is set for rapid growth in 2022, with ambitious government decarbonization targets driving investment in the sector…In a bid to expand into Spain’s high-growth renewables market, French utility giant Engie teamed up with insurance firm Credit Agricole Assurances [in a US$2.3 billion acquisition of] Eolia Renovables…Renewable energy firms, particularly wind and solar, were hotly sought after in 2021 as the pressure to meet decarbonization goals ramped up across the globe…” click here for more

    Wednesday, February 23, 2022

    ORIGINAL REPORTING: Utilities Ally To Fight Bill Scammers

    CA Utilities Join Forces to Thwart Growing Utility Bill Scams

    Herman Trabish, November 16, 2021 (California Current)

    Editor’s note: This is an on-going joint utility effort that can’t do much to slow customers’ rising electricity costs

    Customers’ increased reliance on home utility services has caused a rise in scammers preying on them and in increasingly nefarious ways, according to California’s investor-owned utilities and public utilities. Pacific Gas & Electric and Southern California Edison customers were cheated out of more than $1 million recently. San Diego Gas & Electric customers lost half a million dollars to scammers since 2020.

    The rising numbers are “just the tip of the iceberg” because so many scams go unreported, PG&E spokesperson Jason King told Current. “During September and October, the number of attempted scams reported to PG&E increased by 65%,” King said. For July through September, there were 7,853 reports, and 468 customers were victimized, paying over $370,166 to scammers, he added. Customers “are being targeted by scammers impersonating utilities, typically online, in-person and by telephone.”

    Scams have long been a concern, but Southern California Edison is receiving increased reports of attempted and successful scams, SCE spokesperson Ron Gales agreed. This year, “customers reported more than $590,000 in fraud, surpassing the $426,000 reported lost to scammers in all of last year, he said.

    Because of COVID-19, more people are working, studying, or following social distancing guidance at home. Also, more customers are behind on their bills so they more readily comply without checking when scammers call threatening disconnection due to late payment.

    Over the past two years, SDG&E, the smallest of California’s IOU majors, received 806 reports of scams from customers with estimated losses totaling about $513,100, spokesperson Helen Gao reported. Prominent California public utilities Los Angeles Department of Water and Power and Sacramento Municipal Utility District reported the same trend. To combat scams, both regularly work at customer education through press releases, social media posts, and other channels, their spokespersons wrote in emails to Current. The utilities highlighted the problem as part of the sixth annual Utility Scam Awareness Dayclick here for more

    A Natural Gas Pipeline Called Nord Stream Two

    EXPLAINER: What is the Nord Stream 2 pipeline? Germany has suspended the approval process for Russia's Nord Stream 2 gas pipeline in response to Moscow's recognition of separatist regions in Ukraine

    David McHugh, February 22, 2022 (Associated Press via ABC News)

    “…German Chancellor Olaf Scholz has suspended the certification process for the Nord Stream 2 natural gas pipeline after Russia recognized separatist-held regions in eastern Ukraine, with the West fearing a full-scale invasion is next…[The 1,230-kilometer-long (764-mile-long) natural gas pipeline under the Baltic Sea] runs parallel to an earlier Nord Stream pipeline and would double its capacity, to 110 billion cubic meters of gas a year…[allowing Gazprom to] send gas to Europe's pipeline system without using existing pipelines running through Ukraine and Poland…

    Germany was required to submit a report on how the pipeline would affect energy security, and Scholz said that report was being withdrawn…[because Russia’s recognition of rebel-held areas in Ukraine marked a ‘serious break of international law’…Europe is a key market for Gazprom, whose sales support the Russian government budget. Europe needs gas because it's replacing decommissioned coal and nuclear plants before renewable energy sources such as wind and solar are sufficiently built up…[The pipeline] has been an irritant in U.S.-German relations…

    In Congress, Republicans and Democrats — in a rare bit of agreement — have long objected to Nord Stream 2…While Europe needs Russian gas, Gazprom also needs the European market. That interdependence is why many think Russia won't cut off supplies to Europe even if the Ukraine conflict escalates further, and Russian officials have underlined they have no intention to do that…[European governments have already been developing alternative natural gas supplies from] liquefied gas brought by ship from the U.S., Algeria and other places…” click here for more

    Monday, February 21, 2022

    Monday Study: Protecting The Power Supply In The Solar-Rich Southwest

    Resource Adequacy in the Desert Southwest

    Nick Schlag, Adrian Au, et. al., February 2022 (Energy and Environmental Economics)

    Executive Summary

    In the aftermath of recent blackouts in California and Texas, the subjects of reliability and resource adequacy have risen to national prominence. Regulators and policymakers – as well as the general public and media – have taken a keen interest in these topics, and many have questioned whether the industry is adequately prepared to confront the challenge of preserving reliability during a period of rapid transition. Yet despite its importance and the recent attention it has received, the topic of resource adequacy – and what will be needed to ensure it can be maintained during the transition to cleaner energy sources – remains an esoteric and poorly understood aspect of power system planning. This study sheds light on this important topic to support utilities, regulators, policymakers, and stakeholders in the Desert Southwest as they endeavor to plan, construct, and operate a reliable grid. The goals of this study are threefold:

    1. Examine the current situation in the Desert Southwest in light of recent challenges in neighboring regions and identify any immediate risks to reliability in the region;

    2. Identify and define best practices for resource adequacy planning that will provide a durable foundation for utilities’ efforts to preserve reliability within the region; and

    3. Utilize these techniques to evaluate the region’s readiness to meet the resource adequacy challenges it will face over the next decade.

    Study Highlights & Recommendations

    ► Load growth and resource retirements are creating a significant and urgent need for new resources in the Southwest region; maintaining regional reliability will hinge on whether utilities can add new resources quickly enough to meet this growing need and will require a pace of development largely unprecedented for the region

    ► An increasingly significant share of long-term resource needs is expected to be met with solar and storage resources, but a large quantity of “firm” generation capacity – including the region’s nuclear and natural gas resources – will also be needed to maintain reliability

    ► Substantial reliability risks remain as the region’s electricity resource portfolio transitions, most notably: weather- and climate-related uncertainties, performance of battery storage, and risks related to the timing of new additions

    ► To plan most effectively for resource adequacy, utilities should utilize the best practices identified in this study to the extent practicable, including the use of probabilistic methods to assess the need for capacity and the broad application of an ELCC methodology to assess the capacity value of all resources on an equivalent basis

    New Challenges in Resource Adequacy in the Southwest

    Due to a far-reaching combination of factors – technological, economic, policy, environmental and societal dynamics – the energy landscape of the Southwest region is in a period of rapid transformation. Many of these changes have direct implications on the utilities’ ability to maintain reliable electric service. Figure ES-2 summarizes six key trends that are fundamentally altering the Southwest’s energy system and will have large and immediate ramifications for resource adequacy planning in the region.

    While each of these trends will impact utilities’ efforts to plan for reliability, the shift towards a portfolio more heavily reliant on renewables, storage, and distributed energy resources is notable because it will require advances beyond the simple techniques and common heuristics that have been used in planning for decades. The North American Electric Reliability Corporation (NERC) has described this transition “the greatest challenge to reliability”1 ; a growing body of research has shed light on the complex dynamics of how variable and energy-limited resources impact resource adequacy (illustrated in Figure ES-3):

    1. As the penetration of variable resources grows and traditional generation retires, the periods in which the system is most vulnerable to reliability risks shift away from the traditional peak and toward periods of lower renewable production; this effect is exemplified by the shift in reliability risk to the evening net peak that occurs as solar penetration increases.

    2. As the penetration of energy-limited resources grows, the risk of loss of load events will spread across an increasing number of hours; as the number of hours in which the system is at risk increases, the value of energy-limited resources with finite durations diminishes.

    3. Variable and energy-limited resources exhibit complex “interactive effects,” meaning that the combined value of a portfolio of resources may differ from the sum of its individual parts.

    Best Practices for Resource Adequacy Planning

    The trends described above pose challenges to resource adequacy planners, but these challenges are not unique to the Southwest region. Utilities, regulators, and stakeholders throughout the country and around the world have already taken important steps to modernize their approaches to resource adequacy planning. “Best practices” continue to evolve as the understanding of these challenges advances and new information becomes available. However, the basic foundation of a robust framework for future resource adequacy planning is well-established and relies on the use of a loss of load probability (LOLP) model to (a) establish a planning reserve margin (PRM)requirement and (b) evaluate the effectiveness of resources using an effective load carrying capability (ELCC) methodology.

    Probabilistic methods for resource adequacy analysis (or LOLP models) were first popularized in the middle of the twentieth century when planners recognized the usefulness of measuring risks to reliability statistically based on probabilities of extreme weather events and power plant outages. Today and in the future, reliability outcomes will continue to depend on weather variability (and its impacts on load, renewables, and other resources) and generator availability; the idea of a probabilistic approach to measuring reliability risk remains fundamentally sound, and the methods established in this early era serve as a foundation for the future of resource adequacy planning. However, the complexity of the probabilistic simulations needed will increase significantly as an unavoidable consequence of the transition to a portfolio that is less reliant upon conventional firm resources. The future of resource adequacy depends upon continued enhancements to probabilistic methods and data that capture this complexity, including simulation of chronological operations and resource interactions and considering weather variability, energy use limitations, and evolving load patterns.

    While rigorous probabilistic modeling is essential to planning for resource adequacy for a power system, it is also important to understand how individual resources contribute to system reliability. To this end, a complementary capacity-based accounting construct akin to the familiar “planning reserve margin” will also remain useful. The key to robust capacity accounting is that all megawatts of capacity – both the requirement and the contribution of resources – be denominated in terms of “perfect capacity,” a unit of capacity that is available in all hours of the year at full capacity. The use of this fictional benchmark to both establish the requirement and count resources towards it provides for a balanced, technologyagnostic framework that values each resource based on its relative contribution to system needs.

    Within this framework, the capacity value assigned to each resource (or portfolio of resources) should be determined using an ELCC methodology, which relies on the same LOLP modeling techniques to determine the amount of perfect capacity that provides an equivalent value to system reliability. Properly applied, an ELCC-based framework for capacity accreditation naturally accounts for the oft-cited complications that will arise in this transition, including the “shift to the net peak,” the need to account for energy sufficiency as well as capacity, and the saturation effects and diversity benefits that accrue to portfolios of variable and energy-limited resources. ELCC is therefore broadly viewed as the cornerstone of a robust approach to capacity accreditation and has quickly gained widespread usage within the industry.

    Analysis Highlights

    This study relies on E3’s Renewable Energy Capacity Planning (RECAP) model, a chronological loss-ofload probability (LOLP) model to analyze the evolution of resource adequacy needs of the Southwest over the decade. The analysis addresses three questions over this time horizon:

     How much new capacity is needed to ensure resource adequacy in the region?

     How effective are different types of resources in meeting this need, considering their specific constraints and limitations?

     Do the utilities’ current resource plans, as reflected by the portfolios produced in their IRPs, position the region to meet resource adequacy needs in the future?

    Regional Demand Forecast

    A region’s demand for electricity – in particular, its highest “peak” demand – is the main driver of its capacity needs for resource adequacy. For this study, an hourly future load forecast representative of the Southwest region as a whole was developed through aggregation of individual utilities’ annual load forecasts and historical hourly load shapes. In aggregate, peak demand in the region is forecasted to grow significantly in the coming years due to net migration to major population centers in the region, increased adoption of electric vehicles, and the growing trend of new large commercial and industrial customers. Based on utilities’ projected impacts of these trends, regional coincident peak under "typical” weather conditions is expected to grow by roughly 700 MW per year across the study horizon, reaching 26,700 MW by 2025 and 31,700 MW by 2033. Of course, more extreme weather conditions that occur during some years could result in even higher peak demands; this possibility is captured in the analysis by simulating hourly load shapes under 70 distinct weather years to capture potential year-to-year variability in extreme temperatures and peak demand.

    Changing Characteristics of Customer Demand

    Changing customer preferences and increasing customer engagement also has implications for how utilities plan for resource adequacy. Distributed energy resources (DERs) – including solar, energy storage, and demand response capable devices such as programmable thermostats – are growing in popularity, and their adoption changes how customers consume – and produce and store – electricity. NER ’s 202 LTRA succinctly summarizes the opportunities and complexities resulting from increased deployment of DERs:

    “Distributed energy resources DER growth promises both opportunity and risks for reliability. Increased DER penetrations can improve local resilience and offset peak electric demand on the [bulk power system]. However DER can also increase variability and uncertainty in demand and therefore requires careful attention in planning for resource adequacy and energy sufficiency. DERs also increase the complexity of operating the BPS as operators often lack visibility into the effect of the DER on loads. Consequently, there is an immediate concern to ensure that data transfer, models, and information protocols are in place to support BPS planners and operators.”15

    In many ways, the effects of DERs on resource adequacy will parallel the impacts of utility-scale non-firm resources: they are generally variable and/or energy-limited and will be subject to saturation effects and interactive effects. A durable framework for resource adequacy must therefore account for the impacts of customer-sited resources in a manner that accounts for their contributions to resource adequacy consistent with methods applied to utility-scale resources.

    Electrification of new end uses will also have implications for future resource adequacy planning. Transportation electrification is already occurring today, but electrification of buildings and industry may follow as the imperative to electrify in pursuit of economy-wide decarbonization intensifies. Growing shares of these new end uses will further add complexity to resource adequacy planning, as the shape of electricity demand will evolve in the future. Transportation load impacts are both uncertain and complex, since they depend on customer driving behavior, charging infrastructure availability (home vs. workplace vs. public), charging speed (high-power rapid charging vs. slower overnight charging), charging costs, and electricity rate design.

    Electrification of building loads will further increase resource adequacy needs in deeply decarbonized electric grids due to its outsized impact on winter loads. The addition of load during winter heating seasons further compounds the challenge that planners will have to ensure adequacy during the winter as well as the summer. A recent analysis of wind and solar droughts – defined as week-long anomalies of low wind and solar resource availability – in the Western Interconnection notes that these periods tend to occur during the coldest periods of the year, during which demand for space heating would be highest:

    “Compound wind and solar droughts occurred seasonally when [heating degree days] were largest and the synoptic circulation associated with the compound drought events exacerbates this to a small degree. This means that the electrification of heating could potentially make these compound wind and solar droughts high stress events on a hypothetical underlying energy system (though this may be simultaneously mitigated by global warming).” 16

    But while meeting newly electrified loads will likely require additional resources, the addition of these new loads also offers opportunities for new demand-side flexibility. Electric water heating has already proven itself as a flexible load resource and space heating may provide similar demand response opportunities as space cooling has (one of the primary demand response resources today). Industrial customers often have savvy energy managers dedicated to minimizing energy costs, who are likely to unlock relevant load flexibility opportunities…

    Regional Resource Portfolios

    This study focuses on the ability of two future resource portfolios to meet the region’s reliability needs in two snapshot years (2025 and 2033); the installed capacity of different resources in each of these scenarios is illustrated in Figure ES-7. All four portfolios incorporate retirements of coal and natural gas resources as currently planned by utilities within the region, totaling 1,400 MW of capacity by 2025 and 5,400 MW by 2033. New additions vary according to scenario:

     The “Existing Committed Resources” scenarios include only new resources that have executed contracts with utilities and/or requisite regulatory approvals, which include roughly 3,000 MW of new solar and 1,200 MW of new energy storage.

     The “IRP Portfolios” scenarios include all future resource additions captured in utilities’ current IRPs (or comparable planning processes) in addition to the existing & committed resources; these additions total roughly 10,000 MW of new installed capacity by 2025 and 35,000 MW by 2033, comprising large amounts of solar and storage and smaller amounts of wind, geothermal, demand response, and natural gas.

    Summary Reliability Statistics

    Outputs from the LOLP simulation of each of these four scenarios are summarized in Table ES-1. These results inform several notable observations:

     As of 2021, the region’s loads and resources were roughly in balance; the frequency of expected unserved energy events was slightly higher than a traditional “one-day-in-ten-years” reliability standard. This reliability benchmark (an LOLE of 0.1 days per year) is used throughout this study as a reference point for resource adequacy.

     Existing and committed resources alone will be insufficient to meet the region’s reliability needs. Without additional resources, the region’s resources would be insufficient to meet demand 2 days each year – far more than envisioned in a “one-day-in-ten-year” standard. Filling this gap will require close to 4,000 MW of new effective capacity by 2025 and over 13,000 MW by 2025.

     The utilities’ plans for new resources, as reflected in their IRPs, appear sufficient to meet regional reliability needs as defined by a “one-day-in-ten-years” standard under Base Case assumptions of load and resource performance.

    Key Findings

    1. Load growth and resource retirements are creating a significant need for new resources in the Southwest region

    2. Utilities’ current resource plans have identified enough resources to maintain regional reliability over the next decade

    3. A significant share of long-term resource needs is expected to be met with solar and storage, which together are well-suited to meet a large portion of the region’s loads on summer peak days

    4. The Southwest will continue to rely on a large quantity of “firm” generation resources to maintain resource adequacy; the region’s remaining nuclear and natural gas resources will be crucial to meeting the need for firm resources through the study horizon and beyond

    5. Substantial reliability risks will accompany the transition of the region’s electricity resource portfolio; managing and responding to these risks will require continuous efforts to refresh resource adequacy planning as more information becomes available and utilities gain more experience operating new resource portfolios

    Recommendations

    This analysis finds that utilities’ IRPs in aggregate will position the region to meet regional resource adequacy needs. In the absence of any systemic deficiency that can be traced to current planning conventions, this study concludes that no immediate changes to utility planning practices are needed to maintain reliable electric service.

    This finding notwithstanding, utilities should continue to advance their resource adequacy planning practices to take advantage of new information and modeling techniques. These improvements will enable utilities to mitigate the risks identified herein and improve their efforts to balance planning for reliability portfolio alongside affordability and sustainability objectives. Most importantly, utilities should implement the resource adequacy planning “best practices” as identified in this study to the extent practicable, including:

     Assess the need for capacity using a probabilistic analysis framework that captures the range of potential energy demands under an increasingly volatile climate and should update this analysis periodically as new information becomes available or as load shapes change.

     Apply an ELCC methodology to assess the capacity value of all resources in their portfolios on an equitable basis, capturing all of the risks and limitations to resource availability that are well understood and quantifiable.

    Additionally, in recognition of the uncertainties and associated risks identified in this report, utilities should regularly update inputs and assumptions in their resource adequacy planning.

     Ensure load forecast captures plausible weather conditions that reflect the best available climate science. The upward climate trend and associated changes to the distribution of extreme weather conditions will have major implications on the abilities of the utilities’ portfolios to supply their needs to an acceptable level of reliability.

     Align planning assumptions used to characterize each resource with expectations for performance under extreme heat. The extreme heat conditions that drive resource adequacy challenges in the Southwest region may also impact the availability of generation, both through increased risk of plant outages and degradation of plant output. Utilities should ensure their planning reflects an understanding of these impacts for all types of resources; to the extent these effects are material, they could represent a correlated risk to resource adequacy.

     Gather and incorporate real-world information on performance of emerging technologies. In the absence of historical data, performance assumptions for nascent technologies like battery storage are often idealized in resource adequacy modeling. Replacing idealized assumptions with real-world performance data will improve utilities’ abilities to value the capacity contribution of these resources accurately. A centralized database with records of battery storage outages such as NERC’s Generation Availability Data Set for other technologies would provide significant value to utilities’ planning efforts throughout the country.

    Finally, in recognition of the increasing systemic threats posed by catastrophic extreme weather events and common mode failures – both of which are difficult to incorporate into a probabilistic analysis framework – utilities should supplement probabilistic resource adequacy studies with resilience planning studies that examine the potential consequences of extreme weather and/or system contingencies…

    Saturday, February 19, 2022

    A Renewable Research Resource

    DOE’s national labs are a cumulative source of information and research like no other. From U.S. Department of Energy via YouTube

    Knowing Where To Build Wind

    Very informative piece. Reliable predictable wind is better than powerful wind. From SciShow via YouTube

    How Food Is Heating The Planet

    The food industry is a big part of the climate crisis.From the New York Times via YouTube

    Friday, February 18, 2022

    Climate Consensus Grows With Understanding Of What People See

    Mind the gaps: how experience data can help fight climate change

    Ali Henriques, 14 February 2022 (World Economic Forum)

    “…[A study of more than 11,000 people in 28 countries found] 78% agree that climate change is human-caused and 87% believe it is extremely important for countries to work together to address the problem…[But there is little] consensus about who is responsible for taking action and who is trusted to do so…[That] difficulty of agreeing on how to work together and what to focus on has proven to be a stumbling block in the way of progress…[W]hile 81% say businesses are primarily responsible for taking action, only 28% trust businesses’ claims about sustainable practices…

    Understanding people’s experiences is crucial to knowing what solutions will drive impact. Experience data – data that reveals how people are thinking, feeling and behaving – can help governments and businesses understand what motivates people to support climate efforts and make sustainable changes of their own in order to restore and sustain the healthy planet we all want to live on…[T]erms such as renewable, net-zero emissions, recycled and carbon offset can leave consumers confused about what a company is actually doing for the environment…

    …[G]reenwashing (or conveying false or misleading information about the environmental impact of a company’s products and services) is a growing problem and one of the main reasons there is so little trust in businesses’ claims…More than half of the people in the study (59%) believe governments are doing too little to address climate change…Most people trust what scientists are saying about the consequences of inaction, but 51%, say change is happening too slowly…Public trust in climate science is higher than ever…[Understanding people’s experiences will further] build consensus around solutions that really drive impact.” click here for more

    12 Global Solar Insights Revealed

    12 Solar Energy Facts You Might Not Know About

    Olivia Lai, February 10, 2022 (Earth.org)

    “…As time is ticking before the world crosses the tipping point to limit global temperature increase under 1.5C, switching to renewable energy such as solar is now more crucial than ever…These 12 solar energy facts] help make the argument…Solar is the Most Abundant Energy Source on Earth…Solar is the Fastest and Most Popular Form of New Electricity Generation…[I]t grew from 0.8% in 2010 to 10.3% in 2019…Minimal Greenhouse Gas Emissions are Generated in a Solar Life Cycle…Most estimates of life-cycle emissions for photovoltaic (PV) solar cell systems are between 0.07 and 0.18 pounds of carbon dioxide equivalent per kilowatt-hour…

    …[China led as] generation from solar PV in 2020 grew by a record 156 TWh to reach 921 TWh…Solar Power Plants Can Last 40 Years or More…Solar Power Plants Do Have Some Environmental Impacts…[To] meet the energy consumption needs of the US, 18,734,500 acres would be required], which is equivalent to 0.8% of the entire country…Solar Will Become 35% Cheaper By 2024…Solar Power in 2020 was the Cheapest Electricity in History…The Biggest Solar Farm in the World is in Morocco…Its geographical location allows for optimal access to sunlight and is said to have a 580-megawatt capacity and can provide electricity to more than one million people…

    …China’s Solar Power Capacity is the Fastest Growing in the World…India Aims to be a Global Leader in Solar Energy…Recent Supply Chain Issues Could Hinder Solar Energy Growth…[T]he solar energy industry is expected to experience decline in growth due to rising costs in raw materials such as steel and aluminium, global supply chain bottlenecks, and elevated shipping costs…[This could force] many to remain relying on fossil fuels such as coal and natural gas…” click here for more

    Wednesday, February 16, 2022

    ORIGINAL REPORTING: Major Utility Plans Big Batteries For Emergencies

    SCE Emergency Big Battery Project May Be a Gamechanger

    Herman K. Trabish, October 28, 2021 (California Current)

    Editor’s note: Batteries big and small are increasingly the key point in planning for the power system’s future.

    Southern California Edison just announced it is procuring 537.5 MW of battery energy storage to be online mid-summer, a move that could accelerate the transition away from fossil fuels to using clean energy to provide reliability.

    This would be “a significant benchmark in our transition to a carbon-free electric system,” Center for Energy Efficiency and Renewable Technologies Executive Director V. John White told Current. “It will add important utility experience with large-scale batteries in the real world under [a July 1 joint statement from] stress conditions.”

    Three large lithium-ion battery installations at existing SCE substations totaling 2,150 MWh are scheduled to be online by August 2022. They were bought pursuant to the authority in the California Public Utilities Commission 2020 Emergency Reliability rulemaking (R.20-11-003). They are to provide system and local reliability beyond next year.

    The 537.5 MW will be installed at SCE-owned substations in San Joaquin Valley, Rancho Cucamonga, and Long Beach. It will significantly help meet the utility’s 675 MW emergency reliability system resource adequacy requirement and just increased 19% planning reserve margin for June through October 2022, William Walsh, VP for Energy Procurement and Management, told Current.

    The battery project, costing an estimated $1.23 billion to install and operate, will be discharged to meet local or system emergency power shortages, Walsh said. They will be charged during low cost, low load, high solar periods and discharged during high cost “net peaks,” when stored solar can avoid the natural gas generation normally used to meet peak demand after the sun sets.

    These installations also will show that batteries at substations can displace “diesel generators and ratepayer costs for burning diesel fuel” that PG&E has initiated, CEERT’s White said. The SCE project’s size, location, and accelerated timeline show battery storage is becoming a crucial part of the power system as California regulators expand efforts to protect against [Emergency Proclamation] increasing threats to reliability… … click here for more

    Plans In Every State Drive Electric Transportation

    The 50 States of Electric Vehicles: Transportation Electrification Plans, Fast Charging Networks, & Underserved Communities in Focus During 2021

    February 9, 2022, (North Carolina Clean Energy Technology Center [NCCETC])

    “…[NCCETC’s 2021 annual review and Q4 2021 update edition of The 50 States of Electric Vehicles found] that, for the second year in a row, all 50 states and DC took actions related to electric vehicles and charging infrastructure during 2021…The greatest number of actions related to rebate programs, rate design, electric vehicle registration fees, and charging station deployment…The report highlights ten of the top electric vehicle trends of 2021: Utilities working to develop fast charging networks; Dedicated support for low-income customers and underserved communities; Utilities continue to file expansive transportation electrification plans; Growing attention on medium- and heavy-duty vehicle electrification…

    …States and utilities using rebates to advance transportation electrification; Consideration of demand charge alternatives based on load factor; Growing use of the make-ready deployment model; States setting zero-emission vehicle procurement targets; Utilities developing managed charging programs; and Policymakers addressing local barriers to charging infrastructure development…A total of 775 electric vehicle actions were taken during 2021, with activity increasing by 30% over 2020. The report notes the top ten states taking the greatest number or most impactful actions in 2021 were California, Connecticut, Illinois, New Mexico, Hawaii, New Jersey, Colorado, Massachusetts, Oregon, and Nevada…” click here for more

    Monday, February 14, 2022

    Monday Study – The Cost Of A Renewed Power System

    The Cost Of Upgrading Electric Distribution

    Ewelina Czapla, January 2022 (Deloitte)

    Executive Summary

    The Biden Administration committed the United States to generating carbon pollution-free electricity by 2035 in its submission under the Paris Climate Agreement—a commitment that will require modifying electrical distribution systems. Distribution systems deliver electricity to consumers, and these systems will face added strain in response to upstream expansion of the transmission system and consumer adoption of photovoltaic solar panels and electric vehicles.

    The cost imposed on the distribution system by electric vehicle and photovoltaic solar panel adoption alone is nearly $1 trillion.

    Introduction

    The Biden Administration has committed the United States to generating carbon pollution-free electricity by 2035 under the United Nations Paris Climate Agreement.[1] Achieving this goal will require an unprecedented amount of investment in generation infrastructure—approximately $2 trillion of investment in capital and operations and maintenance costs[2]—as well as the transmission system—an estimated $314 to $504 billion in capital costs.[3] In addition, meeting this goal will require modifying the distribution system (meaning the system that brings electricity to the end user). Not only will upstream expansion and modification require changes to the distribution system, but consumers’ growing use of distributed energy resources (DERs) must be addressed through distribution upgrades to ensure reliability.

    Utility bills are comprised of costs associated with generation, transmission, and distribution. This analysis builds upon the prior American Action Forum research, which estimated the generation and transmission costs to meet the 2035 goal. Like the prior research, it relies on the provisions of congressional Democrats’ proposed Climate Leadership and Environmental Action for our Nation’s (CLEAN) Future Act to illustrate potential policy pathways to achieve the Biden Administration’s goal, as this bill shares the same goal while containing more policy specifics.

    This analysis finds that, as with new generation and transmission, distribution investment would need to increase dramatically as distribution costs would increase by as much $1 trillion to support the adoption of electric vehicles (EV) and photovoltaic (PV) solar panels.

    Distribution Development

    Distribution systems operated by local utilities were designed to deliver electricity to consumers. These systems could be described as unidirectional, delivering a centralized source of electricity to a passive consumer. Consumers are installing increasing numbers of DERs, however, changing the nature of the distribution system. DERs include solar photovoltaics (PV), battery storage, demand response systems, and energy efficiency systems. With these technologies, consumers can generate electricity, curb their demand, and send electricity to the grid. These changes have resulted in an increasingly multidirectional, decentralized system where consumers are participants.[4]

    Of the total generating capacity in the United States in 2020, about 27 gigawatts (GW) was small-scale solar PV installed in residential, commercial, and industrial settings. The EIA’s 2021 Annual Energy Outlook reference case estimates that in 2035 residential distributed generating capacity will be 57 GW (84 billion kilowatt hours [kWh])[5] while commercial distributed generating capacity will be 40 GW (63 billion kWh).[6] That said, “[m]anaging a grid with increasing amounts of customer-sited variable generation increases wear and tear on the distribution equipment required to maintain voltage and frequency within acceptable limits and to manage excessive heating of transformers during reverse power flow.”[7] As a result, reliability can be undermined and additional flexibility is required in distribution systems.

    The CLEAN Future Act aims to increase the adoption of DERs, such as PV solar panels and EVs. The bill reforms the Public Utility Regulatory Policies Act (PURPA) to establish a standard under which electric utilities offer a community solar program to all ratepayers. It also calls for the establishment of a program to provide loans and grants for the construction or installation of community solar facilities or solar generating facilities to serve multi-family affordable housing.

    The CLEAN Future Act also amends PURPA to require states to consider implementing policies that encourage deployment of battery storage systems, microgrids, electric vehicle charging stations, and other DERs. The amendments would also allow utilities’ rate recovery to include DERs in the same way it includes transmission and distribution costs; historically, decided by states . The bill suggests that the Department of Energy (DOE) take on a role traditionally reserved for the private sector, and utilities in particular, by determining where it thinks demand for EV charging may occur in the future. It would create grants to determine where charging stations may be needed to meet demand and to make that data publicly available. It would also seek to increase the deployment and accessibility of electric vehicle charging infrastructure in underserved or disadvantaged communities.

    Assumptions

    The following analysis is focused on the impact of consumer adoption of PV solar panel installations and EVs. The analysis does not include the cost incurred by the consumer to purchase the equipment. Instead, the analysis reflects the capital costs incurred to modify the distribution system to accommodate the adoption of PV and EVs.

    Costs to the distribution system associated with the adoption of PV solar panels and EVs by consumers will ultimately vary from one utility to another. In particular, the costs will be driven by each utility’s ability to successfully forecast the adoption of this technology in their service area.

    PV Solar Panel

    In a study of utilities in the Western Interconnection, the western half of the domestic grid, the National Renewable Energy Laboratory found that during a 15-year period (2016–2030), “systematically misforecasting DPV adoption over multiple successive planning cycles increases the present value of utility system costs by up to $7 million per terawatt-hour ([2017$/]TWh) of electricity sales, relative to utility system costs under a perfect forecast.”[8] Since this value represents the highest possible cost, this analysis assumes a cost of $3.5 million per TWh.

    The analysis assumes that the installation of small-scale solar photovoltaic systems (capacity less than 1 megawatt) will continue to grow from 23.2 GW in 2019 by about 5 GW per year.[9] The capacity is assumed to generate electricity in 2035 at the same rate as in 2020, about 4 hours each day.[10]

    EV Adoption

    A study conducted by Boston Consulting Group (BCG) found that “depending on charging patterns, [utilities] will need to invest between $1,630 and $5,380 in grid upgrades per electric vehicle (EV) through 2030.” The variation in cost is associated with the number of electric vehicles attempting to charge as well as the time of day in which the charging takes place. It considers the fluctuations in electricity demand throughout the day and the cost of optimized and unoptimized EV charging. The costs are based on an estimated 10 to 20 percent market penetration by EVs. The study also found that with increasing EV market penetration, utility rates for consumers continue to grow.[11] The study was completed in 2019 and only estimates cost through 2030, an approximately 10-year period. For the purposes of this analysis, an additional 5 years of cost will be added to the total cost.

    The number of new vehicles sales is estimated to grow until 2035 when it reaches about 19 million new car sales per year, according to a Deloitte study. Similarly, the number of new EV sales per years is expected to grow. In 2035, 45 percent of new cars sold in the United States are projected to be EVs, in Deloitte’s “disruptive” scenario.[12] This estimate is also in keeping with President Biden‘s executive order calling for 50 percent of car sales in the United States produce zero-emissions by 2030.[13] This analysis will rely on the disruptive estimates. The total number of EVs on the road will be determined by assuming linear growth in sales between 2020, when 2 percent of the 14.6 million cars sold were EVs, and 2035.[14]

    Analysis

    To determine the cost to the distribution system due to the installation of PV solar panels, the total generating capacity was calculated by adding 5 GW per year from 2020 to 2035 resulting in a total of approximately 102 GW of generating capacity in 2035. The generating capacity installed since 2020 was multiplied by the hours of generation time to produce 154,656,606,550.28 MWh. When the assumed $3.5 million per TWh cost is applied to the total electricity generated in 2035, the result is a cost of $395 billion. To determine the costs associated with electric vehicles, the assumed linear trend in the growth of car sales and percentage of EV sales were calculated. The compounded annual growth rate for EV sales was applied to the annual car sales to determine the total quantity of cars sold between 2020 and 2030. The total quantity of vehicles sold was then multiplied by $1,630 and $5,380 per EV and an additional 50 percent was added to capture the additional 5 years of cost. The total cost ranges from $161 billion to $533 billion.

    In total, the adoption of EVs and PV solar panels could create nearly $1 trillion of costs for the distribution system. These costs, however, only reflect a portion of the modifications necessary. They do not account for costs associated with battery storage that has been increasingly adopted in recent years. And, more broadly, costs will be created for the distribution system when the transmissions system is expanded and modified.

    Over the course of 15 years, up to $61 billion would need to be invested annually to meet these costs. In 2019, when utility spending was at record highs, $31.4 billion was spent by utilities to replace, modernize, and expand existing distribution infrastructure. These costs were largely attributed to the construction and expansion of power lines.[15] The level of PV and EV adoption forecasted would therefore require distribution investment to double.

    Discussion

    Estimating the cost incurred by the distribution system is difficult because it is responsive to consumer trends. The extent to which consumers choose to adopt electric vehicles, PV solar panels, and other DER as well as the duration and timing of their usage impacts the rate at which utilities will modify distribution systems. Rebates and grants such as those that the CLEAN Future Act proposes may incentivize adoption.

    In addition, utilities may implement policies that incentivize beneficial consumer behavior that reduces the need for constructing additional distribution facilities. Pricing schemes, such as time-of-use rates, may incentivize consumers to use DERs at a particular time of day that is most beneficial to the distribution system, reducing the modifications necessary to maintain reliability. The graphic below demonstrates the use of solar and accompanying battery storage to reduce reliance on the distribution system during peak demand periods. Alternatively, consumers may allow utilities to limit the power they consume by granting them access to control DERs.

    Novel policies in electric regulation have proven difficult to implement due to increasingly competing interests posed by consumers who have or have not chosen to install DERs and utilities that are obligated to provide electricity at a reasonable rate while responding to state and federal policies. For example, net metering, the practice by which utilities pay consumers for the electricity they introduce to the grid, has become contentious. Consumers that introduce electricity to grid from their PV solar panels generate income that is reflected on their utility bill. The costs that are borne by the utility in modifying its system to accommodate PV solar panels, however, are passed on to all its ratepayers. As a result, those that do not install PV solar panels pay for these costs as well. Consumers who do not install PV solar panels may even carry a larger portion of the costs than those who do.[16]

    Ultimately, the costs to distribution systems are reflected in the utility rates paid by consumers. In the case of EV adoption, for example, BCG found that a majority of its modeling resulted in rate increases between 1.4 and 12 percent.

    Conclusion

    The Biden Administration’s commitment to attain carbon pollution-free electricity by 2035 will require expansion and modification of generation, transmission, and distribution infrastructure. These modifications are further complicated by the increasing adoption of DERs, such as PV solar panels and EVs. Distribution system modifications would require unprecedented amounts of investment, nearly $1 trillion, in ways similar to the generation and transmission systems. Together the three sectors could require over $3 trillion of investment over the next 15 years.