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.


  • Monday Study: Getting All The Way To New Energy

  • Weekend Video: Climate Tipping Points Approaching
  • Weekend Video: Moms Take On The Climate Crisis
  • Weekend Video: Ocean Wind Is Coming

  • FRIDAY WORLD HEADLINE-World Faces Climate’s Ultimatum
  • FRIDAY WORLD HEADLINE-Four Ways The World Can Store New Energy


  • TTTA Wednesday-ORIGINAL REPORTING: The Grid The Energy Transition Needs
  • TTTA Wednesday-The Fight Over Distributed Solar Compensation Goes On

  • Monday Study - Battery Storage Beats NatGas Peakers On Price
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    Founding Editor Herman K. Trabish



    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




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


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

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  • ORIGINAL REPORTING: Hawaii PBR Would Change Entrenched Power System Business Model
  • Efforts In Grid Modernization Leap Ahead

    Wednesday, May 05, 2021

    ORIGINAL REPORTING: Hawaii PBR Would Change Entrenched Power System Business Model

    Hawaii finalizes utility regulation considered potential template for US power system transformation; Stakeholders agree the final performance-based regulation order from the state's regulators includes opportunities and safeguards that can be lead to a new regulatory paradigm.

    Herman K. Trabish, Jan. 19, 2021 (Utility Dive)

    Editor’s note: Policymakers across the U.S. have tested changes to the century-old regulatory paradigm but Hawaii may break through.

    A Dec. 23 order by Hawaii's utility commission may lead to the most significant change in power system regulation in U.S. history by giving Hawaiian Electric new control over its future, proceeding participants said.

    Hawaiian Electric will become the first U.S. investor-owned utility to transition away from cost of service (COS) regulation. Over five years, it will move from earning revenues based on capital expenditures to Performance Based Regulation (PBR) and financial stability, based on limited rate-based revenues and rewards for achieving public policy goals and cutting customer costs.

    The commission's order, developed over an almost three-year stakeholder proceeding, aligns "the company's actions, the customers' experience and Hawaii's ambitious clean energy goals," Hawaiian Electric spokesperson Jim Kelly said in a statement. It provides "the right incentives to aggressively move ahead with modernizing our company and Hawaii's energy system."

    Hawaii's regulators and stakeholders acknowledged they are asking a lot of their electricity provider. "The utility has faced more regulatory innovation in the last ten years than over the prior century, and this holds its feet to the fire," said Murray Clay, president of the Ulupono Initiative, which led advocacy for a key PBR component. COS regulation "has protected Hawaiian Electric and this asks it to act more like it is in a competitive environment."

    To support the utility through this unprecedented transition, the order includes reviews, opportunities to revise, and allowances for limited guaranteed returns. But the commission asserted its intention to make PBR work and "not to return" to traditional regulation.

    If successful, this PBR framework could be a template for U.S. power system transformation, said commissioners from the mainland who helped design the framework. The PBR order accomplished three guiding principles set out in the first phase of the proceeding (Docket 2018-0088) to align utility and customer interests and state policy goals, Hawaii Public Utilities Commission Chair James Griffin told Utility Dive. It offers "day 1 customer savings," streamlines the utility's "regulatory burden," and provides safeguards to protect the utility's finances and credit ratings… click here for more

    Efforts In Grid Modernization Leap Ahead

    The 50 States of Grid Modernization Q1 2021: Grid Modernization Sees Busiest Quarter Yet, Driven by State Legislative Activity

    April 28, 2021 (The N.C. Clean Energy Technology Center [NCCETC])

    “…[NCCETC’s Q1 2021 50 States of Grid Modernization on] state regulatory and legislative discussions and actions on grid modernization, utility business model and rate reforms, energy storage, microgrids, and demand response…[found] that 47 states, as well as the District of Columbia, took actions related to grid modernization…[The greatest number of actions related] to energy storage deployment (62), utility business model reforms (31), energy storage interconnection rules (30), smart grid deployment (29), data access policies (27), and distribution system planning (25)…

    A total of 502 grid modernization actions were taken…New York, Texas, California, Minnesota, and New Jersey took the greatest number of actions…[Three trends in grid modernization actions taken in Q1 2021 were] (1) states focusing on improving grid resilience; (2) state lawmakers considering financial incentives for grid modernization; and (3) states examining permitting, decommissioning, and recycling requirements for energy storage facilities…

    …[The quarter’s top five policy developments] were…North Carolina regulators approving deferral treatment for Duke Energy’s proposed grid investments; The Maine Public Utilities Commission launching a grid modernization proceeding; National Grid filing advanced metering and grid modernization proposals in Rhode Island; Virginia lawmakers enacting a series of energy storage bills; and Connecticut regulators releasing an energy storage incentive straw proposal…” click here for more

    Monday, May 03, 2021

    Monday Study: Getting All The Way To New Energy

    Pathways to Build Back Better: Investing in 100% Clean Electricity

    John Larsen, Ben King, Hannah Kolus, and Whitney Herndon, March 23, 2021 (Rhodium Group)

    The electric power sector accounts for 28% of the United States’ net greenhouse gas emissions and is the second highest emitting sector after transportation. While reducing emissions from the electric power sector is only part of what’s needed to decarbonize the US economy, the power sector is where the fastest and cheapest emission reduction opportunities reside. Over the past 15 years, carbon emissions from the electric power sector in the US have dropped by 40%—more than any other US sector. As part of its Build Back Better plan, the Biden administration has a goal to get to 100% clean electricity in 2035— effectively getting the electric power sector all the way to zero emissions within the next 15 years. At the same time, the Biden administration is expected to step up regulation of fossil fuel-fired electric plants in order to cut pollution that endangers public health.

    With the $1.9 trillion COVID-19 relief bill enacted, the Biden administration and congressional leaders are now turning their attention to a major infrastructure investment package, which may include new infrastructure investment in clean energy. In this note, we explore ways in which congressional clean energy investments in the electric power sector can help accelerate decarbonization and put the sector on a path to zero emissions. We then consider how these investments can complement new power plant regulations that could be put in place in President Biden’s first term.

    We find that a combination of investment and regulations can achieve CO2 emission reductions of 69-76% below 2005 levels in 2031, accelerating progress towards the 2035 goal. This can be done without imposing new costs on households while also cutting conventional pollutants by up to 84% in just the next five years. To achieve this, Congress will need to enact long-term incentives for new and existing clean generation and inducements to retire carbon-intensive generation. All of these investments can complement other decarbonization policy efforts such as a clean electricity standard or a carbon price.

    Decarbonization to date and the need to accelerate progress

    Over the past 15 years, CO2 emissions from the electric power sector have dropped by just under a billion tons, 0r 40% below 2005 levels (Figure 1). In both absolute and relative terms, that’s more than any other major emitting sector in the US. These gains are the result of state and federal policies, rapidly declining costs for renewable generation, and persistently cheap natural gas, which together have undermined the market dominance of carbon-intensive coal plants.

    However, this 40% cut does not put the electric power sector on track to zero emissions by 2035. Under current policy, progress on decarbonization will stall out in the next few years (Figure 1).1 Renewables will continue to grow but continued cheap natural gas will increasingly drive the retirement of zero-emitting nuclear plants, canceling out gains in emission reductions. At best, the electric power sector maintains emissions in the range of 46%-50% below 2005 levels in 2030 without additional action, which is nowhere near a straight-line path towards the goal of zero emissions in 2035.

    The Biden administration and congressional leaders have announced plans to pursue a major infrastructure investment package this year. While we don’t know exactly what will be in the legislation, we do know that budget reconciliation is a potential procedural path for the effort. Under reconciliation, all measures must have a direct effect on the federal budget. Taxes, tax credits, and direct spending are all clearly in bounds. New policies such as a clean electricity standard (CES) may also be in play.

    While reducing emissions from the electric power sector is only part of what’s needed to decarbonize the US economy, the power sector is where the largest and cheapest emission reduction opportunities reside. In order to help assess potential pathways to decarbonizing the electric power sector, in this note we quantify the extent of emission reductions that are achievable through just federal spending on its own and in combination with pollution regulations that a Biden EPA may pursue.

    An investment approach and a CES are not mutually exclusive. If a CES or other decarbonization policy does get enacted, the spending initiatives we consider here can complement those programs. If other policies are not enacted this year but a robust spending package is, investment can buy time and build support for future more ambitious action.

    Reintroducing the GREEN Act: the starting point for clean energy investment

    The House has already put forward legislation to increase clean electricity investment. H.R. 848, the Growing Renewable Energy and Efficiency Now (GREEN) Act, sponsored by Michael Thompson and co-sponsored by all Democratic members of the Ways and Means Committee, extends and expands existing tax credits in all major energy sectors. Focusing on just the electric sector, the bill contains an array of tax credit extensions and other provisions including:

    Renewable energy production tax credit: Extension through 2026 of the Section 45 production tax credit (PTC) for wind, solar, biomass, municipal solid waste, and certain water power sources. Wind continues to claim the credit at 60% of its statutory level. Business energy investment tax credits: Extension through 2028 of the Section 48 investment tax credit (ITC) for solar, offshore wind, fuel cells, and a handful of other clean technologies, plus new ITC eligibility for energy storage and geothermal. Solar and geothermal begin to phase down the size of the ITC in 2026.

    Residential energy efficient property tax credits: Extension through 2028 of the Section 25D residential energy efficient property tax credits for investment in distributed solar, small wind, geothermal heat pumps, and fuel cells, plus new eligibility for battery storage technologies. Like the Section 48 ITC, this credit also begins to phase down in 2026. Carbon capture tax credit: Extension through 2026 of the Section 45Q credits for investments in capture and use or storage (CCS) of CO2.

    Public traded partnerships for clean energy: Extends to renewables and carbon capture special tax rules currently available to oil and gas producers and transporters. Direct pay in place of tax credits: Allows ITC, PTC, and 45Q eligible projects to take direct payment instead of tax credits at 85% of the value of the applicable credit. Workforce development: Provides a bonus credit to projects that meet certain labor requirements such as paying prevailing wages.

    To assess the impact of the GREEN Act on emissions and electric power generation, we modeled the GREEN Act in RHG-NEMS. RHG-NEMS is a version of the National Energy Modeling System created by the Energy Information Administration as modified and maintained by Rhodium Group. As our baseline, we used the current policy scenario detailed above, which relies on our Taking Stock 2020 V-shaped macroeconomic recovery scenario, coupled with the latest mid and low technology cost assumptions from National Renewable Energy Laboratory.

    The GREEN Act has a small impact on emissions

    We find that Congress will need to do more than pass the GREEN Act to get the electric power sector on track for zero emissions. Looking out over the next ten years, the GREEN Act increases average annual wind and solar additions to the grid by 5% and total utility-scale storage additions by 28% compared to current policy. This new generation primarily displaces natural gas and nuclear, depending on tech cost assumptions, leading to almost no change in CO2 emissions in 2026 and reductions of 15-53 million tons compared to current policy in 2031 (Figure 2). ,p> The results are far smaller than reduction estimates from our analysis of a previous version of the GREEN Act. Why are we not seeing larger reductions from renewable energy tax credits? There are several reasons. Under current policy, more than half of the current coal fleet retires by 2030 because of low growth in electric power demand, cheap natural gas, and cheap renewables. Remaining coal plants are more competitive and largely not displaced by additional renewables from the GREEN Act. The impact of the additional renewable generation driven by the GREEN Act is smaller than we’ve previously seen with other tax extenders proposals since it is displacing more lower-emission natural gas and zero-emission nuclear instead of coal.

    Another reason is the fact that wind and solar are commercially mature technologies. A vast amount of new renewable capacity is already set to come online over the next decade. That’s in part because renewables are cost-effective even if they aren’t deployed at levels needed to decarbonize the grid. Any extension of credits means the federal government will subsidize some projects that will get built anyway. This dynamic has always been in play, but it becomes more significant as technologies get cheaper and more mainstream. One way to counter this is to increase the value and duration of tax credits. The bigger the incentive, the more likely it is that we’ll see more clean energy get built than will happen anyway.

    The four Rs of electric power decarbonization

    More broadly, the GREEN Act focuses on just two of the four key actions that need to happen to decarbonize electric power generation. We call them the four Rs of decarbonization:

    1-Redouble the pace of clean capacity additions: Renewable energy deployment reached a record in 2020 of nearly 30 GW. However, recent studies suggest the annual average pace may need to be double that to fully decarbonize the US economy. Down the road, advanced nuclear and advanced fossil plants with near 100% carbon capture may also play a role in decarbonization.

    2-Retire as much uncontrolled fossil capacity as possible: In 2019, nearly 220 GW of coal was connected to the grid. Under current policy, that number will be cut by more than half by 2030. In order to get to zero emissions, much of the remaining 100 GW of competitive coal plants as well as the hundreds of GW of existing and soon-to-be-built natural gas combined cycle (NGCC) plants will need to retire.

    3-Retain existing clean capacity: Getting to zero will be easier and happen faster if existing clean generators such as hydro and nuclear plants stay on the grid longer. Last year none of the nuclear plants in the nation’s largest power market made money. Under current policy more than half of the nuclear fleet will retire by 2030, leaving a huge gap. Policies that support retention of plants that have community support and safe operations also help to make sure that new renewables displace fossil capacity, maximizing emission reductions.

    4-Retrofit the fossil capacity that remains: Persistently cheap natural gas for the foreseeable future means existing and new NGCC plants will continue to play a major role in the electric system without requirements or incentives to install carbon capture technology. There’s no room for a vast fleet of uncontrolled fossil plants in a 100% clean power system.

    The GREEN Act primarily incentivizes the first R, redoubling new clean capacity but at levels that don’t accelerate additions to the scale that’s needed. It also incentivizes the fourth R, retrofitting fossil capacity through the section 45Q carbon capture tax credit, but again not at levels sufficient to change the system. Meanwhile, existing clean resources are not retained and coal generation is largely unaffected. The result is a 2031 generation mix that is almost the same between the GREEN Act and current policy.

    Investing in decarbonization

    Can a clean energy investment package make a difference? To answer this question, we constructed a potential investment package scenario that draws from existing and draft policy ideas currently in play in this Congress. The package focuses on programs that push progress on all four Rs and relies on spending mechanisms that can fit within budget reconciliation. The scenario assumes Congress puts in place a 10-year spending package that starts in 2022 and goes through 2031. The scenario is intended to illustrate the potential of spending to decarbonize the electric sector. There are certainly alternative pathways that could be pursued. This specific package is comprised of four key components:

    Tech-neutral tax credits for new clean capacity: An ITC of 30% or a PTC at $25/MWH (67% higher than the current wind PTC) is available for any zero emitting capacity that enters into service before the end of 2031. Fossil capacity with carbon capture, including new retrofits, qualify and get a discounted credit depending on the level of capture. Developers can choose the ITC or PTC, whichever suits them best.

    Existing coal retirement incentive: Any coal plant owned by a rural cooperative can have its federal Rural Utility Service loans written off if the plant is retired by the end of 2025 and the energy is replaced with clean generation. We estimate that up to 30 GW of coal could be eligible, which wouldn’t retire under current policy. These plants have an associated outstanding federal debt of roughly $10 billion.

    Existing clean retention incentive: An incentive is available for any existing nuclear capacity to stay online at least through 2031. The incentive can be made available to all generators or scaled based on need, similar to a recent proposal by Senators Whitehouse and Barrasso. We assume the incentive is sufficient to prevent roughly 50 GW of economic nuclear retirements that we see in our current policy scenario.

    Extension of carbon capture incentives: New and retrofitted fossil plants equipped with carbon capture that enter into service by the end of 2031 can claim the section 45Q carbon capture tax credit of $50/ton if coupled with storage and $35/ton if coupled with utilization or EOR. Developers cannot claim both this and the tech neutral credit.

    We find that a robust, long-term spending package that focuses on all aspects of decarbonization can make meaningful progress on electric power emission reductions. This investment package gets emissions on a straight-line path to zero at least through 2025, and by 2031 emissions are 66-74% below 2005 levels when accounting for clean energy technology cost uncertainty (Figure 4). That’s a major step forward.

    1-Which issues are currently most important to your organization? Renewables, sustainability, or the environment 45% Reliability of retail distribution grid 29% Climate change impacts and resilience 28% Bulk power system reliability 27% Aging grid infrastructure 26% Cybersecurity and physical security 24% State regulatory model reform 21%...

    2-Which approaches are most effective in decarbonizing the power system? Financial incentives for renewable energy development 50% Strong federal decarbonization policy, backed up with clear targets, regulation and enforcement 45% Updated transmission infrastructure 43% Performance-based rates or other strategies to shift the utility business model 37%

    3-What is the best way to get more renewables on the grid? Extending federal tax credits 17% Facilitating the build of new transmission infrastructure 15% Incentivizing and simplifying the addition of energy storage resources to the grid 14% State mandates 12% 4-What has your utility done to prepare for, or to support increased adoption of, electric vehicles? Pilot or test projects for EV charging 55% Feasibility studies for providing EV charging infrastructure 50% Deployed public charging stations in partnership with third-party networks 37%

    The long-term tax credit for new clean capacity with flexible election of the ITC or PTC in the investment package scenario hypercharges renewable energy deployment. With the tax credit in place, in our mid tech cost case, average annual renewable capacity additions are 33 GW per year through 2031, just over 10% more than the 2020 record. In our low tech cost case, average capacity additions are double that, at 66 GW a year. This new renewable capacity displaces fossil generation, both coal and natural gas, thanks to the nuclear retention incentive. Without the nuclear retention incentive, electric power sector emissions would be 23-28% higher, up to 188 million metric tons more in 2031. Looking at the fossil fleet, we find clean energy and coal retirement incentives combined lead to an additional 34-38 GW of coal retirements in 2031 compared to current policy. Extending the section 45Q carbon capture tax credit does not drive deployment of more plants equipped with carbon capture. The incentive is not high enough for the technology to compete.

    All together, the aggregate impact of the investment package leads to a dramatically different electric power generation mix in 2031 than under current policy. Under the investment package, wind and solar nearly double their contribution to total generation, and nuclear generation more than doubles. The net effect is that total zero emitting generation gets as high as 67% in the low tech cost case. This clean generation plus the coal retirement incentives cut coal generation by one-half to two-thirds compared to current policy and NGCC generation by 30-43% (Figure 5).

    Budget implications of investment

    The decarbonization and generation shifts in the investment scenario come in at up to double the current $10.5 billion the government spends annually on clean energy tax credits. We estimate that the average net annual budget outlay from 2022-2031 is $14.9-$20.3 billion depending on technology costs. The coal retirement incentive represents 5-7% of total outlays while the nuclear retention incentive makes up 28-38%. More than half of total outlays—55%-67%—are associated with new renewable energy deployment.

    Potential complements to investment

    There are other potential policy ideas not included in our scenario that could complement our results depending on overall policy goals. For example, a tax credit for high voltage transmission could unlock more renewables. A bonus credit for projects that meet fair labor practices can help boost worker wages. Spending programs could be put in place to drive additional renewable investments in low-income and historically disadvantaged communities. All of these programs can change the total budgetary costs as would any other provisions beyond what we’ve considered.

    Another key design element we consider is whether developers can receive a direct payment instead of a tax credit as contemplated in the GREEN Act. At the moment, developers often require tax equity financing partners to fully monetize tax credits. The tax equity market was able to accommodate the record renewable builds of 2020, but at times some developers struggled to find tax equity partners. Since we find renewable builds under the investment scenario may far surpass 2020 levels, and since there may be demand for tax equity from other energy tax credits, it may be prudent to provide developers with more financing flexibility through some sort of direct pay or refundability provision. Otherwise, there is a real chance that the tax equity market may become a bottleneck to accelerated decarbonization. It is not at all guaranteed that tax equity can scale at the same pace and as clean energy deployment in our scenarios.

    Investment combined with public health regulations can accelerate progress Just as clean energy investment can complement a federal clean electricity standard, a carbon price or other comprehensive climate policy, spending can support common sense public health regulations on fossil power plants. A combination of investment & regulations can achieve even faster decarbonization as well as bigger and faster conventional pollutant reductions. Investments can also blunt any potential ratepayer impacts from regulations.

    While the Biden administration has not outlined its plans for regulating conventional pollutants and CO2 from power plants, we have constructed a scenario based on our experience analyzing Obama-era regulations, which we consider to be a plausible first-term agenda.[2] We couple our investment scenario with a series of regulations modeled on Obama administration rules targeting toxics, NOx, SO2, particulate matter, coal ash, effluent, CO2, and other pollutants primarily at coal plants. We also assume that EPA requires all new coal and NGCC plants to be equipped with carbon capture starting in 2023. These regulations steadily increase coal plants’ operating costs, leading to lower coal generation and more coal plant retirements. NGCCs end up having a reduced role as well. Power plant regulations can drive progress on the retrofit and retire components of the four Rs of decarbonization.

    Investment & regulations can cut pollution by more than half compared to 2020 levels

    Investment can help regulations achieve even larger conventional pollutant reductions. Here we focus on NOx and SO2, two of the primary pollutants from electric power plants. Both pollutants cause asthma in children, as well as other respiratory diseases and premature death. While EPA regulations under the Clean Air Act have led to huge progress in cutting emissions of these pollutants to date, we find that an investment package coupled with a new round of regulations can catalyze dramatic new gains. We find that five years from now, in 2026, investment & regulations can cut NOx emissions by 52-62% compared to 2020 levels. The same combination can cut SO2 by 81-84% (Figure 6). This is at least 10 percentage points more than what investments can do alone and represents more than double and nearly double the reductions achieved under current policy for NOx and SO2 respectively. While these national level results don’t necessarily reflect the conditions on the ground for all front-line communities, on the whole this progress should provide a wide range of health benefits across the country.

    The pollution reductions achieved from investment & regulations are due not just to a surge of renewables but also a reduction in fossil generation. With both regulations and investment, in 2031 renewables contribute 41-52% of all generation depending on technology costs (Figure 7), slightly more than under the investment scenario alone. Meanwhile, coal represents just 2% of total generation, more than a 90% reduction from 2020 levels. NGCCs contribute as little as 25% of generation and, importantly, no new uncontrolled NGCCs are built after 2023 thanks to the EPA regulatory requirements for carbon capture. This is important for limiting stranded assets in the 2030s. Finally, the carbon capture requirements coupled with incentives don’t drive a surge in carbon capture. 3-5 GW of new advanced gas plants with carbon capture are in operation in 2031 in the investment & regulations scenario. This represents 0.2-0.3% of total installed electric power capacity in 2031. The additional clean capacity in this scenario pushes the budgetary costs up slightly relative to the investment only scenario.

    The major shift away from fossil and towards clean generation due to a combination of investment & regulations furthers progress towards decarbonization beyond the investment scenario alone. Emissions can get below a straight-line path to zero in 2035 through the first half of the 2020s and stay within the range of that path as far as 2028 (Figure 8). This results in 2031 emissions that are 69-76% below 2005 levels. If no other policies get through this Congress, a combination of investment & regulations can still achieve progress and build support for more ambitious action down the road.

    Decarbonization does not have to raise electric bills

    One fear often stoked during clean electric policy debates is that ratepayers will have to bear the brunt of the costs of emission reductions through higher bills. We find that this is not the case. In fact, we find that in 2031, national average household electric bills are no more than $1 per month higher under the investment or investment & regulations scenarios than under current policy (Figure 9). Moreover, bills are lower than what households paid in 2020. Renewables have become so cheap (and continue their cost declines through this window), so the impact of accelerated deployment on electric bills is small. In addition, federal investment shifts the cost of decarbonization from ratepayers to the federal government, resulting in negligible changes in bills even when regulations add costs to the electric system. While there will certainly be regional differences in bill impacts, they are unlikely to be large due to these dynamics.

    Next step: Congress

    It’s clear that federal clean energy spending, especially when coupled with public health regulations, can lead to substantial pollution reductions and major progress towards a 100% clean electric sector. A well-crafted investment package passed by Congress, possibly through budget reconciliation can get the sector on track for long-term deep decarbonization. We plan to monitor developments in Congress to see how the next wave of legislative proposals addresses the four Rs of decarbonization. Watch this space for more on how leading proposals stack up.

    [1] Our current policy scenario takes into account all state and federal policies as of May 2020, plus the clean energy tax extenders included in the December 2020 federal tax package. Scenarios considered in this analysis assume all electric power market actors behave rationally and optimize for least cost operations over the long-term. [2] While we consider this scenario to be plausible, it should not be interpreted as an estimate of the maximum or minimum level of regulation that EPA could pursue. The Biden administration could potentially go far further in regulating electric power sector pollutants than we consider in this analysis.

    Saturday, May 01, 2021

    Climate Tipping Points Approaching

    Earth’s lungs are going as the heat rises and the ice melts. It’s on.From CBS This Morning via YouTube

    Moms Take On The Climate Crisis

    Moms are in the fight now, so the climate crisis hasn’t got a chance.From Science Moms via YouTube

    Ocean Wind Is Coming

    Offshore wind is about to take a big place into the New Energy power mix. From American Clean Power Association via YouTube

    Friday, April 30, 2021

    World Faces Climate’s Ultimatum

    World on the verge of climate ‘abyss’, as temperature rise continues: UN chief

    19 April 2021 (UN News)

    “…[T]he global average temperature in 2020 was about 1.2-degree Celsius above pre-industrial level….[which] is ‘dangerously close’ to the 1.5-degree Celsius limit advocated by scientists to stave off the worst impacts of climate change…[According to the World Meteorological Organization (WMO) State of the Global Climate, the] six years since 2015, have been the warmest on record, and the decade beginning up to this year, was the warmest ever…

    …[The world is ‘on the verge of the abyss’ and] 2021, ‘must be the year for action’ on] new nationally determined contributions (NDCs)…[because] climate change undermines sustainable development efforts, through a cascading chain of interrelated events that can worsen existing inequalities, as well as raise the potential for feedback loops, perpetuating the deteriorating cycle of climate change…

    …[The WMO reported concentrations of the major greenhouse gases continued to increase in 2019 and 2020, with global average for carbon dioxide concentrations having already exceeded 410 parts per million (ppm)…” click here for more

    Four Ways The World Can Store New Energy

    How can we store renewable energy? 4 technologies that can help

    Victoria Masteron, 23 April 2021 (World Economic Forum)

    “…[If the sun isn’t shining or the wind isn’t blowing,] four storage technologies are fundamental to smoothing out peaks and dips in energy demand without resorting to fossil fuels…1. Pumped hydro…involves pumping water uphill at times of low energy demand. The water is stored in a reservoir and, in periods of high demand, released through turbines to create electricity…More than half of new hydropower capacity additions in Europe by 2025 will be pumped storage…In China, pumped storage will also account for more than half of new hydropower capacity annually between 2023 and 2025…

    …2. Batteries… convert stored chemical energy into electrical energy…Advances in technology and falling prices mean grid-scale battery facilities that can store increasingly large amounts of energy are enjoying record growth…[in California,] Australia, Germany, Japan, the UK, Lithuania and Chile…3. Thermal energy storage…involves storing excess energy – typically surplus energy from renewable sources, or waste heat – to be used later for heating, cooling or power generation…Liquids – such as water – or solid material - such as sand or rocks - can store thermal energy. Chemical reactions or changes in materials can also be used to store and release thermal energy…Water tanks in buildings are simple examples…

    …4. Mechanical energy storage…harnesses motion or gravity to store electricity…[A] flywheel is a rotating mechanical device that is used to store rotational energy that can be called up instantaneously…Other mechanical systems include compressed air energy storage, which… involves storing pressurised air or gas and then heating and expanding it in a turbine to generate power…” click here for more

    Wednesday, April 28, 2021

    ORIGINAL REPORTING: The Grid The Energy Transition Needs

    2021 Outlook: The DER boom continues, driving a 'reimagining' of the distribution system; As new customer-owned resources grow, the old way of delivering them will evolve to make load more flexible.

    Herman K. Trabish, Jan. 12, 2021 (Utility Dive)

    Editor’s note: Operating technologies like these will be critical to the energy transition.

    Acceleration of the growth of distributed energy resources (DER) has power system analysts anticipating big changes on utility distribution systems in 2021 and throughout the 2020s. Continued falling prices of DER, ambitious new state and federal policies, and customer demand in 2021 will drive growth, power industry representatives said. And while utility-scale renewables growth will still boom, DER, including rooftop solar, batteries and electric vehicles (EVs), can be central to protecting reliability, according to a new Southern California Edison (SCE) paper describing the evolution of tomorrow's grid.

    SCE’s Reimagining the Grid "is to help establish where and why we should turn right or turn left in building a distribution system to address evolving needs," said SCE Vice President of Asset Management, Strategy & Engineering Paul J. Grigaux. Those turns "will be determined by the growth of distributed resources and we want to have the system technologies to see and manage their impacts."

    "We're reaching a threshold where distributed energy resources add up to enough megawatts to matter," Brattle Group Principal Ryan Hledik added. "And the idea of managing them in an aggregated coordinated way is being taken more seriously now."

    There is likely to be much more attention in 2021 on proposals like SCE's for a future distribution system that can use DER to provide grid services, other power system analysts agreed. That attention is now needed because the DER are increasingly showing up and will accelerate in the coming year, the analysts said.

    Concrete predictions about growth are difficult only because economies of scale are driving costs down and growth up faster than forecasts can be made, according to DER advocates. Prices continue to steadily fall, the December 2020 Lawrence Berkeley National Laboratory distributed solar data update confirmed. From approximately $12/watt in 2000, prices had fallen in 2019 to between $2.30/watt and $3.80/watt, depending on system size and market.

    Residential solar 2020 installations were forecast by the 2020 Q4 SEIA-Wood Mackenzie U.S. Solar Market Insight Report, released Dec. 15, to have "13% growth in 2021." And that was before the recent extension of solar’s federal tax credit, which will help drive even greater growth into the early 2020s. The COVID-19 relief bill’s functional extension of the tax credit through 2025 and anticipated further clean energy support from the Biden administration and a Democrat-controlled congress are likely to accelerate distributed solar growth and cost declines, click here for more

    The 50 States of Solar: States Consider Over 120 Bills Related to Distributed Solar Policy in Q1 202

    April 21, 2021 (The North Carolina Clean Energy Technology Center [NCCETC])

    “…The NCCETC Q1 2021 edition of The 50 States of Solar found 42 states, plus the District of Columbia, had] state regulatory and legislative discussions and actions on distributed solar policy, with a focus on net metering, distributed solar valuation, community solar, residential fixed charges, residential demand and solar charges, third-party ownership, and utility-led rooftop solar programs…[The greatest number of actions were in] continuing to address net metering policies (51), community solar policies (33), and residential fixed charge or minimum bill increases (23). A total of 155 distributed solar policy actions were taken during Q1 2021, with the greatest number of actions taken in South Carolina, California, New York, Maine, and Kentucky…

    The report identifies three trends in solar policy activity taken in Q1 2021: (1) fees based on distributed generation system capacity gaining traction, (2) states revisiting net metering successor tariffs, and (3) states increasing net metering system size limits and aggregate caps…

    …[The top five distributed solar policy actions of Q1 were] Connecticut regulators approving net metering successor tariff designs…New Mexico lawmakers enacting community solar legislation…California utilities and stakeholder filing Net Metering 3.0 proposals…Kansas regulators rejecting Evergy’s proposed distributed generation fees…[and] West Virginia lawmakers passing legislation authorizing third-party solar power purchase agreements…” click here for more

    Monday, April 26, 2021

    Monday Study: Battery Storage Beats NatGas Peakers On Price

    Battery Storage – The New Clean Peaker

    April 2021 (Australian Clean Energy Council)

    Large-scale battery storage is now the superior choice for electricity peaking services, based on cost, flexibility, services to the network and emissions. It is the new clean peaker that Australia needs.

    Batteries can store low-cost, zero-emission, excess renewable energy from the grid to support periods of peak demand with clean, cheap and reliable energy.

    Between 6 and 19 GW of new dispatchable resources are needed across the National Electricity Market by 2040. Batteries are now a prudent choice to meet this level of dispatchable capacity.

    Two- and four-hour batteries outcompete open-cycle gas turbine peakers on both a levelised cost of energy and levelised cost of capacity basis.

    Batteries can provide a premium peaking service in periods of high demand traditionally met by peaking gas plants. Batteries can ramp up quickly, have near zero start-up time and provide a better frequency response.

    The commercial case for batteries will continue to improve as advancements are made with battery technology and new markets are established to reward the services they provide.

    Up-to-date information on battery projects in Australia can be found on the project tracker page on the Clean Energy Council website.

    The National Electricity Market is undergoing an unprecedented transition.

    The Australian Energy Market Operator’s (AEMO’s) 2020 Integrated System Plan (ISP) anticipates an additional 26 to 50 GW of new large-scale renewable energy generation (depending on the scenario) will be needed in the National Electricity Market (NEM) by 2040, supported by between 6 and 19 GW of new dispatchable resources.

    These dispatchable resources will be made up of pumped hydro, large-scale battery energy storage systems, distributed batteries, virtual power plants and other demand-side participation.

    The Role Of Peakers And The Services They Provide

    While the ISP has a limited role for new gas generation, there are some that hold a preference for new gas peakers as the firming support for variable renewable energy generation. Peaking generation plants are generators that can respond in a short timeframe to periods of both expected and unexpected high electricity demand. These generators traditionally have high short-run marginal costs and as such, are only used for short periods in times of sharp increases in demand or peak periods. In the NEM, peaking plants are generally needed for generation after 6.00pm for an average of three to four hours as solar systems ramp down and demand peaks.

    Traditionally, peaking plants have been gas-fired generators due to their ability to begin generating within 15 minutes. The market is now seeing a rapid transition to battery storage systems as a replacement for gas peakers as battery technology has advanced to the point where it can provide faster response for a much lower cost. Battery solutions can serve the same role traditionally performed by gas peakers by discharging when demand (and correspondingly prices) approach peak levels and sustaining output to cover the typical daily peak duration.

    Battery storage, known for its fast and accurate response across numerous energy applications, has improved its capability and cost-effectiveness to become the pre-eminent peaking plant solution for energy grids across the world. The key barrier for batteries has been capital cost, but rapid and continuing cost efficiencies driven by product innovations and manufacturing at scale are reducing this barrier, to the extent that it is no longer economically rational (or necessary) for proponents, investors or governments to build gas peaking plants in Australia

    The Case For Battery Peakers

    Battery storage is the true bridge to a clean energy future, providing a modern, more flexible alternative to gas turbines for meeting peaking and firming needs.

    Premium Peaking Services

    Battery storage offers a ‘premium’ peaking service (faster ramp rate, higher accuracy and better-quality frequency response) and a wider range of network services (including digital inertia, voltage support, system strength and fast frequency response) at lower cost (both upfront capital cost and ongoing operational expenditure) – making it far more suitable to complement increasing levels of variable renewables.

    Optimal Firming Duration

    Batteries have quickly expanded energy capacity to four hours and more, outcompeting gas to play the optimum intraday ‘firming’ role. Given Australia’s existing energy mix and diversity in renewable output, there are very few periods forecast to require more than four hours of storage in the next decade. For interday ‘seasonal’ firming, a combination of different storage technologies will be required in the longer term.

    Emissions Reduction

    By shifting renewable energy through the day, batteries allow for greater uptake of renewable energy technologies while providing system stability and network security services in parallel. On the other hand, there are clear direct emissions from gas peakers.

    Deployment Flexibility

    Batteries offer fast, modular and scalable deployment profiles, and can be deployed in any location on the network. Relative to equivalent gas or pumped hydro developments, batteries have a minimal land footprint and a reduced carbon footprint.

    Diverse Value

    Batteries offer diverse value streams from negative price events (being paid to charge), network services (demand response, system integrity protection, loss factor improvements, voltage stability, investment deferral), proposed market reforms (five-minute settlement) and essential system services (inertia, fast frequency response, premium frequency stability and system strength).

    Guaranteed Technical Life

    As variable renewable generation increases, the cost of operating gas plants goes up due to increased ramping causing more wear-and-tear that will shorten their technical lives. In addition, gas plants require more regular downtime to perform maintenance. In contrast, batteries have higher availability (given less maintenance work is required) and can offer guaranteed fixed power and energy for over 20 years to effectively maintain capacity over the entire useful life.

    Gets Better Over Time

    Battery technology continues to receive new features and functionality updates, making it highly adaptable to new markets and system settings.

    Fuel Independence

    Independence from fossil fuels reduces exposure to commodity price risk and enables the provision of more responsive, lower-cost and carbon-free capacity.

    While the case for battery peakers is compelling, the risks for gas peakers are increasing. For example, the NEM’s move to five-minute settlement from October 2021 is one of the initial market reforms that will undercut gas peaking revenue opportunities – with five-minute timeframes challenging the ability for peaking plants to defend cap contracts and respond to price spikes.

    Historically, gas peakers have relied more heavily on cap contracts (with their longer runtime duration), but cap prices have softened and are not expected to see the same extreme volatility as evidenced in the one or two isolated years since the commencement of Australia’s national market. The lower price outlook for caps is therefore removing much of the future earnings potential for both existing and new build plants. Coupled with increased uncertainty and volatility in input gas fuel prices, unclear supply volumes, carbon risk premiums and broader policy and political sentiments, the case for new gas investments is becoming increasingly challenging.

    Batteries Vs Gas Peakers: Which Is Cheaper?

    Comparing the levelised cost of energy (LCOE) and levelised cost of capacity (LCOC) for a new-build 250 MW gas peaker with new-build 250 MW two-hour and four-hour battery storage systems, all located in New South Wales, grid-scale battery storage systems provide a peaking solution with a lower LCOC than an equivalent new-build open cycle gas turbine plant (OCGT or ‘gas peaker’). Battery storage also provides more than 30 per cent in LCOE savings, with both capital and operational cost advantages (before considering fuel and carbon risks).

    While this analysis does not include NEM dispatch or revenue modelling, from first principles the lower variable operating costs and higher operational agility of battery storage will result in better utilisation and therefore larger market revenues. Battery storage can also generate strong revenues from arbitrage opportunities, even if the average price of electricity declines (or is negative) due to strong growth in renewables. For the assumptions used in this study, please see the Appendix.

    A key sensitivity for gas peakers is the exposure to natural gas price fluctuations. Figure 2 includes a base case of AUD$6.5/GJ (aligning with AEMO’s latest gas supply hub data and verified by independent experts) as well as three sensitivities to account for forecast cost pressures: AUD$7/GJ, AUD$11/GJ and AUD$14/GJ. These sensitivities are based on independent advice suggesting long-run levels below AUD$8/GJ are hard to achieve given cost estimates of new supply.

    Capacity factors also have some influence, however OCGTs would need to triple their typical utilisation to over 30 per cent and benefit from low gas prices to even start to compete.

    Carbon price risk is another known unknown with potentially substantial cost impacts on gas peakers. While not modelled in this analysis, it remains front of mind for policy makers and investors. In reality, by choosing a battery energy storage system, developers can shield themselves from these downside risks and uncertainties.

    Battery storage offers a compelling new technology to serve traditional peaking and firming roles.

    Battery storage outcompetes gas peakers because of its faster reaction time, higher accuracy and flexibility to respond to price variability by both charging and discharging. With the rapid reduction in capital costs complementing its already lower operating costs, battery storage offers this superior performance at much greater commercial value than its gas peaker alternative, and at much lower exposure against future gas, carbon and market reform risk.

    Both two-hour and four-hour battery storage solutions are more cost-competitive than a conventional OCGT peaker – outperforming it on an LCOC and LCOE basis. The competitiveness of battery storage will only increase over time as costs continue to fall, average electricity prices decline as renewable penetration accelerates and natural gas prices remain volatile and at the behest of global market economics. Given these risks and opportunities, developing a new gas peaker in Australia is both irrational and imprudent, exposing shareholders to potential losses, taxpayers to unnecessary debt and electricity customers to high costs.

    Battery storage is the true bridge to a clean energy future and can become the new flexible peaker to accelerate Australia’s transition to sustainable energy. The case for batteries as the new clean peaker is impossible to ignore

    Saturday, April 24, 2021

    Biden Old And Getting It DONE!

    This is Bill’s most vicious attack yet on one of his favorite targets – millennials. But along the way he makes a great case for Joe’s work on covid, climate, and other major issues.From Real Time with Bill Maher via YouTube

    The Fight For New Energy Goes On

    Despite 22 billion dollar climate disasters in the U.S. in 2020, some voices still call for the use of energy sources that aggravate the climate crisis and resist the transition the nation must make to New Energy. From greenmanbucket via YouTube

    Tesla’s Second Life Battery Solution

    Tesla’s original mastermind has turned his attention on recycling the valuable parts of EV batteries. From CNBC via YouTube