NewEnergyNews: 04/01/2023 - 05/01/2023/


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.



  • TTTA Wednesday-ORIGINAL REPORTING: The IRA And The New Energy Boom
  • TTTA Wednesday-ORIGINAL REPORTING: The IRA And the EV Revolution

  • Weekend Video: Coming Ocean Current Collapse Could Up Climate Crisis
  • Weekend Video: Impacts Of The Atlantic Meridional Overturning Current Collapse
  • Weekend Video: More Facts On The AMOC

    WEEKEND VIDEOS, July 15-16:

  • Weekend Video: The Truth About China And The Climate Crisis
  • Weekend Video: Florida Insurance At The Climate Crisis Storm’s Eye
  • Weekend Video: The 9-1-1 On Rooftop Solar

    WEEKEND VIDEOS, July 8-9:

  • Weekend Video: Bill Nye Science Guy On The Climate Crisis
  • Weekend Video: The Changes Causing The Crisis
  • Weekend Video: A “Massive Global Solar Boom” Now

    WEEKEND VIDEOS, July 1-2:

  • The Global New Energy Boom Accelerates
  • Ukraine Faces The Climate Crisis While Fighting To Survive
  • Texas Heat And Politics Of Denial
  • --------------------------


    Founding Editor Herman K. Trabish



    WEEKEND VIDEOS, June 17-18

  • Fixing The Power System
  • The Energy Storage Solution
  • New Energy Equity With Community Solar
  • Weekend Video: The Way Wind Can Help Win Wars
  • Weekend Video: New Support For Hydropower
  • 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.

  • ---------------
  • WEEKEND VIDEOS, August 24-26:
  • Happy One-Year Birthday, Inflation Reduction Act
  • The Virtual Power Plant Boom, Part 1
  • The Virtual Power Plant Boom, Part 2

    Saturday, April 29, 2023

    Energy Sec. Granholm On The Big Apple’s Big Greening

    The strong new federal financial and policy support makes this move possible is available to cities, towns, and individuals all across the country. From U.S. Dept. of Energy via YouTube

    Data From The Global EV Boom

    New EV sales remain strong in established economies and are doubling and tripling in emerging economies. From the International Energy Agency via YouTube

    Ghost Forests May Haunt Climate Deniers

    Sea level rise, coastal flooding, salt in the mud, trees die, and only bare stumps and dry twigs remain. From CBS News via YouTube

    Friday, April 28, 2023

    New Energy Took The World In 2022

    ‘Beginning of the end’ for fossil fuels: Global wind and solar reached record levels in 2022, study finds

    Sophie Tanno, April 12, 2023 (CNN)

    “A boom in wind and solar has pushed the amount of electricity produced by renewable energy to record levels last year [and the use of coal, oil and gas to produce electricity is expected to fall in 2023], according to a new analysis…This would mark the first year to see a decline in the use of fossil fuels to generate electricity, outside of a global recession or pandemic [suggesting levels of planet-heating pollution from fossil fuel electricity generation may have already peaked…Nearly 40% of global electricity is now powered by renewables and nuclear energy…

    Wind and solar made up 12% of global energy generation in 2022, up from 10% the previous year…Solar energy was the fastest-growing source of electricity in 2022 for the 18th year in a row, rising by 24% compared to the previous year. Wind generation increased by 17%...[I]n 2023, clean energy will be able to meet the total growth in electricity demand…Coal power remained the single largest source of electricity across the globe, accounting for 36% of global electricity production in 2022. This is because overall demand for electricity rose…” click here for more

    Law And The Global Climate Crisis

    These laws have formed a foundation to fight climate change

    John Letzing, April 14, 2023 (World Economic Forum)

    “Nearly four decades ago, a US senator proposed legislation to draw up a national strategy for studying and addressing climate change. It quickly went nowhere…[But the steady construction of climate laws] around the world over the years has created the legal footing necessary to confront the threat of physical and financial destruction…[A Grantham Research Institute/Columbia Law School database] puts the cumulative number of global climate laws and policies at 3,145. It stretches back to Japan’s 1947 Disaster Relief Act to recent entries like] a UK plan to decarbonize and domesticate energy production, and Türkiye’s policy bid to ramp up the production and use of hydrogen…

    EU member states just approved a plan requiring that all new cars sold there must be emissions-free by 2035…[The historic legislation and policies crucial for climate progress] share a focus on curbing pollutants, fossil fuels, and the damage they can unleash…[from the Clean Air Act passed in the US in 1963 to Norway’s 1976 law to prevent products from damaging health and [the environment, and France’s law supporting nuclear power that made it] the advanced economy with the lowest emissions per capita…

    Climate policy is a boring necessity drawn up in backrooms…It’s been nudged forward by decades of international efforts to spur discussion and pool global knowledge, setting crucial guideposts along the way for domestic lawmakers…[The UN’s International Panel on Climate Change included 743 experts from around the world in environmental physics, energy efficiency, and economics who] tend to be both profoundly committed and broadminded…[But the] recent UN panel report found that there’s very little remaining chance of limiting warming to the crucial threshold of 1.5°C, barring dramatic emissions reductions…” click here for more

    Saturday, April 22, 2023

    Tipping Points Loom As Solutions Emerge

    There is never a time to stop working to turn back the climate crisis but it is clear the change is gaining momentum. First Stop Burning. From American Museum of Natural History via YouTube

    The Answer Is In The Energy Sector

    New Energy will keep electrons flowing in 2050’s net zero emissions economy. From the International Energy Agency via YouTube

    Heat And The Global Climate Crisis

    Weather is about immediate impacts, climate is about long-term trends. Weather happens in a place, climate happens to the planet. Weather is hot sometimes and cold sometimes, the climate has been slowly and steadily getting hotter for over a century. From via YouTube

    Thursday, April 20, 2023

    ORIGINAL REPORTING: Better Planning For A Better Power System

    Duke, APS planning reforms show ways to work with stakeholders to meet emerging power system needs; Better integrated planning can lower rates and transform the resource mix for any power provider, an RMI analysis found.

    Herman K. Trabish | February 28, 2023 (Utility Dive)

    Editor’s note: Efforts continue in many states to find ways to expand the power system’s resource mix.

    The energy transition’s new resources, technologies and voices require the utility integrated resource plan, or IRP, to be better, many planners and analysts say.

    An IRP is the strategy a utility submits to its regulators every one to three years in most states for investing in reliable affordable power and meeting its policy goals and obligations. But new approaches, like those being explored by Arizona Public Service, or APS, and Duke Energy Indiana, are needed to meet upward pressures on rates, stakeholder calls for clean energy options and equity, and federal and state policies, many regulators and stakeholders agree.

    “Market forces are shaping utility resource portfolios,” acknowledged Commissioner Pat O’Connell of the New Mexico Public Regulation Commission. “But this moment of change is an opportunity to go big on high-level IRP reforms with more analysis of more factors,” he added.

    For APS, “the changing landscape requires transparency with stakeholders in the IRP process,” said APS Vice President of Resource Management Justin Joiner. “That means coming to planning sessions with stakeholders without answers, because two heads are better than one, and decisions about affordability, reliability and clean energy can best be reached with diverse stakeholder viewpoints,” he added.

    Reform efforts to introduce best practices like all-source solicitations, distribution system planning, and engaging new voices could add more work for already overburdened utility planners and regulators, some said. But developing integrated system planning with state-of-the-art modeling that optimizes solutions to today’s reliability and affordability challenges will be easier than undoing bad planning decisions, others responded.

    Utility “planning processes are being stretched and challenged” to meet the power system’s emerging dynamics, according to a new report from independent analyst RMI. But utilities, regulators and stakeholders can “shape the future electricity system” by “reimagining” IRP “rules and guidelines,” to make planning more comprehensive, transparent, and aligned with policy, RMI said… click here for more

    Major Western Transmission Project Finally Gets Green Light

    Massive transmission line will send wind power from Wyoming to California; After 18 years, the TransWest Express line receives final approval.

    Gabriela Aoun Angueira, April 17, 2023 (Grist)

    “…[After a nearly two-decades-long permitting process, the Bureau of Land Management, or BLM, gave final approval to begin building the $3 billion, 732-mile TransWest Express high-voltage transmission line] capable of sending power from what will be the largest onshore wind farm in North America to western states…[It] will deliver three gigawatts of power from the 600-turbine Chokecherry and Sierra Madre Wind Energy Project, which broke ground this year in a former coal-mining community in Wyoming, to grids in Arizona, Nevada, and California…

    …[C]omplicated permitting processes can slow the country’s transition to clean energy…Projects built on federal lands are subject to the National Environmental Policy Act, or NEPA, which dictates the environmental review process. NEPA does not include time limits for when environmental reviews must be completed…[and the] TransWest Express crosses four states, through both public and private lands, and required approvals from various federal, state, tribal, and local agencies, as well as some determined property owners…

    …[Despite support for permitting reforms by Democratic Senator Joe Manchin of West Virginia and Energy Secretary Jennifer Granholm,] substantive changes have not yet materialized…[House Republican permitting reform in the Lower Costs Energy Act were so antithetical to clean energy goals that it] was a “nonstarter” in the Senate…[TransWest Express delivered wind[ could be particularly impactful for California…TransWest Express LLC, a subsidiary of Anschutz Corp., which also owns the wind farm project, said it expects to complete the project by 2028.” click here for more

    Monday, April 17, 2023

    Monday Study – Transmission Queue Clog Getting Worse

    Queued Up: Characteristics of Power Plants Seeking Transmission Interconnection

    Joseph Rand, Rose Strauss, Will Gorman, Joachim Seel, Julie Mulvaney Kemp, Seongeun Jeong, Dana Robson, Ryan Wiser, April 2023 (Lawrence Berkeley National Laboratory)

    High-Level Findings

    Developer interest in solar, storage, and wind is strong

     Over 10,000 projects representing 1,350 gigawatts (GW) of generator capacity and 680 GW of storage actively seeking interconnection  Most (~1260 GW) proposed generation is zero-carbon  Hybrids comprise a large share of proposed projects

    Completion rates are generally low; wait times are increasing

     Only ~21% of projects (14% of capacity) from 2000-2017 reached commercial operations by the end of 2022  Completion rates are even lower for wind (20%) and solar (14%)  The average time projects spent in queues before being built has increased markedly. The typical project built in 2022 took 5 years from the interconnection request to commercial operations1, compared to 3 years in 2015 and <2 years in 2008.

    Proposed capacity is widely distributed across the U.S.

     Substantial proposed solar capacity exists in most regions of the U.S.; 947 GW of solar active in queues  Wind capacity is highest in NYISO, the non-ISO West, PJM, and SPP, with increasing share of offshore projects  Storage is primarily in the West and CAISO, but also strong in ERCOT, MISO, and PJM; much in hybrid configurations  Only 82 GW of gas capacity active in the queues, less than 10% of active solar capacity

    Typical Interconnection Study Process and Timeline

    • A project developer initiates a new interconnection request (IR) and thereby enters the queue • A series of interconnection studies establish what new transmission equipment or upgrades may be needed and assigns the costs of that equipment • The studies culminate in an interconnection agreement (IA): a contract between the ISO or utility and the generation owner that stipulates operational terms and cost responsibilities • Most proposed projects are withdrawn, which may occur at any point in the process • After executing an IA, some projects are built and reach commercial operation

    There has been a substantial increase in annual interconnection requests (both in terms of number and capacity) since 2013; over 700 GW added in 2022 alone

    Over 2,000 GW (2 TW) of generation & storage capacity active in queues; Especially strong developer interest in solar (~947 GW) and storage (~680 GW), including hybrid

    62% (1,262 GW) of total capacity in queues has proposed online date by end of 2025; 13% (257 GW) already has an executed interconnection agreement (IA)

    Interest in hybrid plants has increased over time: Hybrids comprise 52% of active storage capacity (358 GW), 48% of solar (457 GW), and 8% of wind (24 GW)

    Only 21% of all projects proposed from 2000-20171 had reached commercial operations by the end of 2022 – 72% had withdrawn from queues

    After falling from a 2012 peak, the typical duration from interconnection request (IR) to interconnection agreement (IA) increased sharply since 2015, reaching 35 months in 2022

    Typical duration from IA to commercial operations date (COD) has increased modestly since 2007, except in CAISO where recently built solar projects took 4-6 years after securing an IA


    As of the end of 2022, there were over 10,200 projects seeking grid interconnection across the U.S., representing over 1,350 GW of generation and an estimated 680 GW of storage.

    • Solar (947 GW) accounts for >70% of all active generator capacity in the queues, though substantial wind (300 GW) and gas (82 GW) capacity is also in development. 113 GW of offshore wind is currently active in the queues.

    • Considerable standalone (325 GW) and hybrid (~358 GW1) storage capacity has also requested interconnection.

    • The combined capacity of solar and wind now active in the queues (~1,250 GW) approximately equals the total installed U.S. power plant fleet capacity, and is greater than the estimated 1,100 GW needed to approach a zero-carbon electricity target2.


    • Capacity in queues is widespread across U.S. but some states dominate: Texas has 13% of proposed solar, storage, and gas, and 7% of proposed wind; New York has 23% of all proposed wind (mostly offshore); California has 14% of proposed storage.

    • Hybrids now comprise a large – and increasing – share of proposed projects, particularly in CAISO and the West. 457 GW of solar hybrids (primarily solar+battery) and 24 GW of wind hybrids are in the queues.

    • The majority (62%) of capacity in the queues is proposed to come online before 2025, and some (13%) already has an executed interconnection agreement (IA).

    • The time projects spend in queues before reaching COD is increasing. For the regions with available data3, the median duration from IR to COD has doubled from 20 MW.

    • Ultimately, much of this proposed capacity will not be built. Historically only ~21% of projects (and only 14% of capacity) requesting interconnection from 2000-2017 have reached commercial operations. As well, late-stage withdrawals may be on the rise…

    Saturday, April 15, 2023

    The Greenhouse Gas Emissions Of The World’s Rich

    The top 1% of emissions come from people who generate 1000 times more CO2 than the bottom 1%, and the world’s richest 1% create ten times the emissions of the rest of the world’s richest 10%. From the International Energy Agency via YouTube

    Time For Wall Street To Make Climate Changes

    It’s time to turn investors away from fossil fuel financing. From National Sierra Club via YouTube

    California’s Hills Alive With Colors of Climate Crisis

    The super bloom is a beauteous indicator of how weird the climate has become. From Today via YouTube

    Wednesday, April 12, 2023

    ORIGINAL REPORTING: Designing A Cybersecure Power System

    New power system cybersecurity architectures can be ‘vaults’ against insider attacks, analysts say; Layered, automated, deep defenses for growing distribution system vulnerabilities will be tested by an NREL-private partnership.

    Herman K. Trabish, February 17, 2023 (Utility Dive)

    Editor’s note: Threats and protections continue to grapple over the fate of the power system.

    New utility cybersecurity strategies are needed to counter sophisticated intrusions now threatening the operations of an increasingly distributed power system’s widening attack surface, security analysts agree.

    There are cyber vulnerabilities in “every piece of hardware and software” being added to the power system, the September 2022 Cybersecurity and Infrastructure Security Agency, or CISA, Strategic Plan 2023-25 for U.S. cybersecurity reported. Yet 2022 saw U.S. utilities propose $29.22 billion for hardware and software-dependent modernizations, the North Carolina Clean Energy Technology Center reported Feb. 1.

    New hardware and software can allow malicious actors to have insider access through utilities’ firewalled internet technology to vital operations technology, cyber analysts said. “No amount of traditional security will block the insider threat to critical infrastructure,” said Erfan Ibrahim, CEO and founder of independent cybersecurity consultant The Bit Bazaar. “The mindset of trusted versus untrusted users must be replaced with a new zero trust paradigm with multiple levels of authentication and monitoring,” he added.

    Growing “distribution system entry points” make “keeping hackers away from operations infrastructure almost unworkable,” agreed CEO Duncan Greatwood of cybersecurity provider Xage. But distributed resources can provide “resilience” if a distributed cybersecurity architecture “mirrors” the structure of the distribution system where they are growing to “contain and isolate intrusions before they spread to operations,” he said.

    New multi-level cybersecurity designs can provide both rapid automated distributed protections for distributed resources and layers of protections for core assets, cybersecurity providers said. But the new strategies remain at the concept stage and many utilities remain unwilling to take on the costs and complexities of cybersecurity modernization, analysts said.

    Critical infrastructure is already vulnerable to insider attacks. After the 2021 Colonial Pipeline shutdown, a 2019-2020 attack known as SUNBURST and directed against U.S. online corporate and government networks, and Russia’s 2015 shutdown of Ukraine’s power system, 14 of the 16 2021 ransomware attacks on U.S. “critical infrastructure” sectors, including the energy sector, the FBI reported. And new vulnerabilities allowed attacks that also caused data losses, disrupted network traffic, and even denial-of-service shutdowns, according to technological and research firm Gartnerclick here for more

    Carbon Capture And Storage – The Questions And Opportunity

    SMUD wants to be carbon-free by 2030. Should it capture carbon and store it underground?

    Ari Plachta, April 10, 2023 (Sacramento Bee)

    “In a project that would be the first of its kind in the country, the Sacramento Municipal Utility District is considering a proposal to capture carbon emissions from a natural gas power plant and deposit them deep underground. Calpine Corporation, one of the nation’s largest producers of natural gas and geothermal electricity, is appealing to SMUD to develop carbon capture and storage technology at the Sutter Energy Center, a gas plant outside Yuba City.

    The project involves taking carbon dioxide generated by burning fossil fuels and transporting it half a mile into the earth for permanent storage, with a goal to reduce atmospheric greenhouse gases that trap heat and cause climate change…[T]he relatively new technological process has yet to win wide acceptance, particularly in the electricity sector where carbon-free alternatives like solar and battery storage are abundant. Critics, meanwhile, warn of unknown environmental consequences and argue that carbon capture merely prolongs the life of fossil fuel facilities…

    New machinery would include a tall tower that, through a chemical process, separates carbon from the facility’s exhaust. Carbon is then compressed and sent more than half a mile underground by pipeline into layers of porous rock for permanent storage…SMUD plans to hold a public workshop to discuss carbon capture and sequestration in April. A project update and final decision on the project by the board is expected in May.” click here for more

    Monday, April 10, 2023

    Monday Study – Price Signals In Rates To Grow Heat Pump Use

    Heat Pump–Friendly Cost-Based Rate Designs

    Sanem Sergici, Akhilesh Ramakrishnan, Goksin Kavlak, Adam Bigelow, and Megan Diehl, January 2023 (The Brattle Group and Energy Systems Integration Group)

    The economics of heat pumps relative to natural gas heating will be an important driver of customer adoption of these technologies and will determine the extent to which ambitious building electrification goals can be met in a timely manner. If the operating costs for heat pumps turn out to be favorable compared to the operating costs for natural gas equipment, it is possible to see a significant uptake of the heat pumps even before the technology cost declines. In this white paper, we examine the role of alternative “cost-based” and “cost-reflective” electricity rate designs in improving the economics of heat pumps by reducing their operating costs. We use a proprietary dataset of gas and electricity usage for 80 single-family residential customers of a large investor-owned utility for modeling customers’ electric and gas heating bills before and after electrification. We find that the operating cost gap is positive for all 80 customers under the default electricity rate (energy costs for operating the heating equipment are higher post-electrification). However, moving to one of the three alternative rates flips all 80 customers from a positive cost gap to a negative cost gap, in which energy costs for operating the heating equipment are lower post-electrification.


    Residential and commercial buildings consume large amounts of energy for cooling, heating, and lighting needs. In the U.S., the building sector has been contributing roughly 30 percent of total greenhouse gas emissions. According to a recent United Nations report, the building sector was responsible for 38 percent of CO2 emissions globally in 2019 (UNEP/GABC, 2020). Given the magnitude of building sector emissions, the decarbonization of this sector, mainly through heating electrification using heat pumps, constitutes a key component of state and city climate action plans.

    The economics of heat pumps relative to natural gas heating will be an important driver of customer adoption of these technologies, and thereby determine the extent to which ambitious building electrification goals can be met in a timely manner. While heat pumps are much more efficient in converting energy into heating output than efficient natural gas boilers and furnaces, they also have higher initial capital costs.1 Heat pumps’ operating costs can also be higher than natural gas equipment depending on climate, equipment type and efficiency, electricity rates, and rate structures. Even in regions where heat pump operating costs are lower than operating costs for natural gas equipment, the operating cost gap will need to be significant to offset the upfront cost premium and return a reasonable payback for customers who are in the market to purchase a new heating system.

    Technology costs are expected to come down over time, and heat pumps will likely reach cost-parity with natural gas equipment eventually. However, if the operating costs for heat pumps turn out to be favorable compared to the operating costs for natural gas equipment, it is possible to see a significant uptake of the heat pumps even before the technology cost declines. In this white paper, we examine the role of alternative “cost-based” and “costreflective” rate designs in improving the economics of heat pumps by reducing their operating costs. We define cost-based rates as rates that recover a utility’s entire cost of providing service to a class of customers, and define cost-reflective rates as rates that send efficient price signals reflective of the extent to which a change in a customer’s timing or magnitude of usage would change overall utility costs. Default utility rates for the residential class typically consist of a small fixed monthly charge and a volumetric charge on kWh consumption. This type of rate is typically cost-based because it recovers the utility’s revenue requirement for the class, but not very cost-reflective because transmission and distribution costs are not driven by kWh consumption.

    This analysis considers alternative rates that are costbased in the sense that they would collect the same amount of revenue from the average customer (who has not yet electrified) as the default rate. Therefore, the rates need not be limited to electric heating customers but could be designed for the residential class and made available to all residential customers (not just the electric heating customers) on a voluntary basis. In addition, all three alternative rates put forth in this analysis incorporate more cost-reflective components than the default rate. This includes components such as higher fixed charges, time-varying volumetric charges, and time-varying demand charges, all of which are more reflective of utility cost causation than flat volumetric charges. In other words, we are not advancing differing, subsidized rates for different end uses here. Rather, we are assessing the broader appeal of these structures, finding that there are alternative cost-based rates that could be made available to all customers, with customers with different appliances and use cases opting into these rates if the structure of the rates is better aligned with their usage profiles.

    This white paper is structured in four sections. The second section describes our analytical approach to modeling customers’ gas and electric usage for heating. The third section describes our modeling results from calculating heat pump and natural gas boiler heating bills under various rate structures. The fourth section concludes with the key takeaways from the white paper…

    Key Takeaways

    This analysis shows that there are alternative costbased rate designs that can improve the economics of heat pumps by resulting in electric heating bills being lower than natural gas heating bills (i.e., a negative operating cost gap). Specifically, we show that while the operating cost gap is positive for all 80 customers under the default electricity rate (Rate I) (energy costs for operating the heating equipment are higher postelectrification), moving to one of the three alternative rates flips all 80 customers from a positive cost gap to a negative cost gap, in which energy costs for operating the heating equipment are lower post-electrification.

    Increasing the fixed charge and lowering the volumetric charge (Rate II) reduces the electric heating bill to a sufficient extent that the operating cost gap turns negative for all customers. Further, switching to a TOU day/night structure (Rate III) or a demand-based structure (Rate IV) results in even larger negative operating cost gaps. Rate IV is the most effective rate for reducing electric heating bills, for our sample of 80 single-family residential customers, with Rate III closely following it.

    More Cost-Reflective Rate Designs Improve the Economics of Electrification

    These results reflect the fact that all of the alternative rate designs are better aligned with the marginal cost of generating and delivering power, compared to the default residential rate design, which typically is not. In many jurisdictions across the country, retail electricity prices are largely disconnected from the marginal costs. As Borenstein and Bushnell (2022) argued, “residential electricity rates exceed average social marginal cost in most of the U.S.” and “there is large variation both geographically and temporally.” To the extent that retail prices are above the short-run marginal costs because a large portion of the fixed costs of delivering power are also collected through volumetric rates, this creates a distortion in price signals and leads to suboptimal levels of electricity consumption and adoption of new customersited technologies. One of the unintended consequences of this phenomenon is the slower adoption of heat pumps, because heat pump usage increases total electricity consumption and therefore electricity bills, turning out to be uneconomic under typically volumetric default residential electricity rate structures.

    All of the alternative rates modeled in this study are cost-based and revenue-neutral in that they recover the same costs as the default rate. They also improve upon the cost-reflectivity of the default rate by better aligning one or more components of the rate design with the underlying cost structure. These alternative rates also favor the operating characteristics of heat pumps:

    • Rate II has a higher fixed charge and lower volumetric charge, which is favorable for heat pumps since this equipment substantially increases a household’s electricity usage.

    • Rate III is a seasonal day/night TOU rate, with lower rates for off-peak (night) hours and also lower day and night rates for the non-summer season. A significant portion of the heat pump load tends to fall into the off-peak periods because those tend to be the coldest, which implies that various cost-based TOU rates might favor heat pump usage, all else equal. Moreover, most of the heat pump load materializes in the nonsummer months; therefore, seasonally differentiated rates in summer-peaking systems (with lower nonsummer rates) might favor heat pump usage, all else equal.

    • Rate IV is a seasonal TOU-based demand rate. Heat pumps tend to have high load factors, which implies that demand-based rates might favor heat pump usage, all else equal. In our rate design, we defined the billing demand to be the average of the top four demand hours, with the averaging intended to avoid the unpleasant customer experience of getting a high bill due to one high hour.

    It is important to note that as the system conditions evolve, and summer-peaking systems become winter peaking with increasing levels of building electrification, rate structures may need to be refreshed to maintain their cost-reflectivity. Some of the attractive features of the rates modeled in this study (i.e., lower non-summer rates due to seasonality) may need to be eliminated at that time since the system cost drivers would no longer support these design choices. These revisions and adjustments are all part of the rate design process, since it is not possible to “future-proof ” rate designs.

    These Alternative Rate Structures Have Implications for Customers’ Other Electric Loads

    While our analysis showed that these alternative rates were effective in creating a negative operating cost gap for heating (a lower cost of heating after electrification), it is important to understand the implications of these rates for customers’ other electric loads. Rate migration can create costs or savings independent of heating electrification, depending on the nature of customers’ nonheating loads. This is an important consideration when marketing alternative rates to customers. For some of the customers in the sample, even before any electrification, switching to the TOU rate (Rate III) would increase their electricity bill by ~$200/year. (This increase could be reduced or eliminated through load response to TOU rates, although we did not model this impact in our study.) On the other hand, there are some customers for whom switching to one of the demand-based rates would reduce the bill by ~$100/year even before any electrification. Utilities may choose to develop screening tools to determine which customers may benefit from these alternative rates and market these rates accordingly to the customer base.

    For the purposes of this study, we assumed that customers maintain their gas service for non-heating-related use cases such as cooking. This implies that these customers continue to pay the fixed customer charges for the gas service, along with the cost of volumetric gas usage. Fully electrifying a household would create additional savings by allowing it to avoid all gas charges (an additional $350/year in fixed gas charges for a single-family home). It is very likely that gas rates will increase faster than electricity rates in the next decade; therefore, the cost advantage of heat pumps will only increase over time. It is important to note that as the system conditions evolve, and summer-peaking systems become winter peaking with increasing levels of building electrification, rate structures may need to be refreshed to maintain their cost-reflectivity.

    Information Barriers Need to Be Addressed

    Lastly, the availability of alternative rates that favor the economics of heat pumps does not necessarily mean that customers will start taking advantage of these rates in droves. Information barriers need to be addressed through utility programs targeting customers and pairing them with the rate design most favorable to them. Utilities can develop data analytics tools to identify customers who may be getting close to replacing their heating systems and “catch” them before they make their investment decision. Contractor training programs could be developed in which contractors increase awareness for new rates for customers who are in the market for a new heating system. With the availability of alternative rates, contractors could take into account the rate characteristics to make system recommendations. For example, if the demand charges are very high in an alternative rate, it could mean that purchasing a highly efficient cold climate heat pump is a better choice than a less efficient heat pump with resistance backup even if there is an upfront cost premium for the cold climate heat pump.

    The Use of Cost-Reflective Rate Designs Is Increasing

    More and more utilities are starting to move toward more cost-reflective rate designs. Some are increasing their fixed customer charges to move them closer to the values implied by their cost-of-service studies. Others are moving toward time-varying rates, mostly in the form of voluntary/opt-in rates, but in a few cases offered as default, opt-out rates. When utilities offer opt-in cost-reflective rates, customers are able to opt in to the rates that are most convenient for their “energy lifestyle.” To the extent that all of these alternative voluntary rates are cost-reflective, it will be possible to achieve a win-win: customer satisfaction will increase and utility cost recovery will become more equitable…

    Saturday, April 08, 2023

    Upgrading To A 21ST Century Power System

    It is a critical but “monumental task” covering 6.3 million miles of lines that will take time and money, but it is vital to protect reliability. From the U.S. Dept. of Energy via YouTube

    Yes, Solar Panels Are Recycled

    Old solar panels can be a New Energy resource. From Solar Ranch via YouTube

    Heat Pumps In The Energy Transition

    Heat pumps are powered by electricity which can be generated by zero emissions New Energies. Natural gas heating cannot. From the International Energy Agency via YouTube

    Friday, April 07, 2023

    Big Transmission Planned Around The World

    Column: A global guide to electric grid development plans

    Gavin Maguire, April 4, 2023 (Reuters)

    “…Utilities and power system planners are acutely aware of the vital role that grids will play in the energy transition, and are ramping up spending on grid upgrades and expansions alongside the roll out of green energy production capacity…[But current global spending] on grid upgrades is roughly half the estimated $600 billion required annually through 2030 if net-zero emissions targets are to be accomplished…[The build out] is also uneven, with roughly half of current extra-high voltage transmission lines (eHV) - capable of handling bulk power transfers [at 375,000 volts to 765,000 volts] across long distances - concentrated in China, North America and Europe…

    …[eHV] will be key arteries that will enable transition efforts…These lines already account for 46.4% of the installed global transmission network in 2023…[but will see] an expected 260% rise in installed capacity from current levels…[Installed global capacity of ultra-high voltage (UHV) lines that can carry more than 765,000 volts] will expand by nearly 300% by 2050 to become the second most common line type by mid-century…Roughly 66% of current UHV capacity is in Greater China (36%) and the Indian subcontinent (30%), and around 10% is in North America…

    The Indian subcontinent, home to some of the world's most aggressive green energy supply road maps, will take over from Greater China as the region with the largest UHV capacity from around 2030…Latin America looks also set to rapidly increase UHV capacity, especially after 2035…The Middle East and North African region will become a major hub for eHV capacity by 2040, while Northeast Eurasia and Sub-Saharan Africa will leave it until nearer 2050…Southeast Asia and the Pacific areas also look set to construct a majority of their capacity build outs after 2035…” click here for more

    EU Goes For More New Energy

    EU reaches deal on higher renewable energy share by 2030

    April 5, 2023 (World Economic Forum)

    The European Union reached a provisional deal on 30 March on higher renewable energy targets, an important pillar of the bloc's plans to fight climate change and end dependence on fossil fuels imported from Russia…[Negotiators] agreed that by 2030, the 27-country EU would commit to sourcing 42.5% of its energy from renewable sources like wind and solar, with a potential top-up to 45%...The EU's current 2030 target is for a 32% renewable energy share…The EU got 22% of its energy from renewable sources in 2021, but the level varied significantly between countries.

    Sweden leads the 27 EU countries with its 63% renewable energy share, while in Luxembourg, Malta, the Netherlands and Ireland, renewable sources make up less than 13% of total energy use…A rapid shift to renewable energy is crucial if the EU is to meet its climate change goals, including a legally binding aim to cut net greenhouse gas emissions by 55% by 2030, from 1990 levels.” click here for more

    Wednesday, April 05, 2023

    ORIGINAL REPORTING: A Long Term Strategy To Reach Zero Carbon Is Emerging

    ‘No regrets’ approach to big batteries, green hydrogen and grid reliability urgently needed, analysts say; Uncertainty and opportunity in the Biden administration’s infrastructure and climate bill incentives challenge regulators and utilities to plan smarter.

    Herman K. Trabish, January 31, 2023 (Utility Dive)

    Editor’s note: Although stakeholders and vested interests continue to try to force the logic of their technologies forward, investors and federal agencies continue to focus on building wind, solar, batteries, and transmission and study the spectrum of other possibilities.

    While they are potential key resources of a net zero emissions energy sector, advanced long-duration battery technologies and green hydrogen generated from water with clean energy face perplexing uncertainties.

    First, they may not be ready until the late 2030s and early 2040s, global consultant DNV said Oct. 13. Or Form Energy’s 100-hour battery systems will see “broad commercialization” by 2024, as the company said Dec. 22, and green hydrogen will “play a major role in global emissions reductions by 2030,” as reported by RMI Oct. 11.

    Second, that uncertainty may be amplified by significant long-term incentives for both resources in 2022’s Inflation Reduction Act, or IRA and 2021’s bipartisan infrastructure law as well as the just-released national transportation decarbonization plan, analysts said. RH2 and battery providers are seeking the new billions available in the legislation, with either potentially winning overlapping opportunities.

    The incentives “are shifting possibilities” for long-duration energy storage, or LDES, technologies “like Form Energy’s battery and green hydrogen” that can meet extended system outages, said American Clean Power Association, or ACP, Vice President, Energy Storage, Jason Burwen. But “neither has been deployed at grid scale yet, which makes this a horse race between two hypotheticals,” he added.

    But there are ways advanced batteries and renewables-generated hydrogen, or RH2, could be synergistic with each other or with other clean firm resources in a post-2030 power supply, utility planners and energy sector analysts agreed. Clean firm energy technologies will be needed for a “zero-carbon grid,” but both advanced batteries and RH2 seem to have advantages and disadvantages, and “there’s a future where each finds a niche role in the market,” said Energy Plus Environmental Economics, or E3, Senior Partner Arne Olson. “It only seems now like a race because it is not possible to know which will fit the energy mix best in 20 years,” he added.

    The general consensus, that lithium-ion, or li-ion, batteries are the answer now for light-duty electric vehicles, and RH2 is heavy industry’s best clean energy option, leaves the LDES future in the power sector uncertain, analysts said. But LDES will be vital at high levels of variable renewables and regulators and utilities can apply a “no-regrets” planning strategy now to ensure a reliable, least-cost future power system, they added… click here for more

    Getting More From Electrification With Heat Pumps

    Heat Pump-Friendly Cost-Based Rate Designs

    Sanem Sergici, Akhilesh Ramakrishnan, Goksin Kavlak, Adam Bigelow, and Megan Diehl, January 26, 2023 (Energy Systems Integration Group)

    “…[R]etail pricing may be used more widely and more efficiently to allow flexible demand to respond to grid needs as the role of demand becomes increasingly important for the reliability of the grid…The economics of heat pumps relative to natural gas heating will be an important driver of customer adoption of these technologies and will determine the extent to which ambitious building electrification goals can be met in a timely manner.

    If the operating costs for heat pumps turn out to be favorable compared to the operating costs for natural gas equipment, it is possible to see a significant uptake of the heat pumps even before the technology cost declines…[Roles may different for] alternative “cost-based” and “cost-reflective” electricity rate designs in improving the economics of heat pumps by reducing their operating costs…

    ...[A proprietary dataset of gas and electricity usage for 80 single-family residential customers of a large investor-owned utility is used] for modeling customers’ electric and gas heating bills before and after electrification…[It finds] the operating cost gap is positive for all 80 customers under the default electricity rate (energy costs for operating the heating equipment are higher post-electrification). However, moving to one of the three alternative rates flips all 80 customers from a positive cost gap to a negative cost gap, in which energy costs for operating the heating equipment are lower post-electrification.” click here for more

    Monday, April 03, 2023

    Monday Study – Making The Smart Grid Smart

    Why Is the Smart Grid So Dumb? Missing Incentives In Regulatory Policy For An Active Demand Side In The Electricity Sector

    Travis Kavulla, January 2023 (Energy Systems Integration Group)

    The Smart Grid’s Unfulfilled Promises

    It was 2009, President Barack Obama had just taken office, a huge federal stimulus to jolt the electricity sector into the 21st century had been passed, and utilities had their eyes fixed on a transformational opportunity: the smart grid.

    “Change is in the air,” wrote Commissioner Rick Morgan of the District of Columbia’s Public Service Commission. “The smart grid that’s beginning to emerge in North America will rely on hardware like ‘smart’ meters, ‘smart’ appliances and thermostats, remote sensors, and sophisticated communications systems. These devices, when linked together, will enable utilities and their customers to respond in real time to conditions on the power grid, thereby creating new opportunities to reduce costs and increase customer value” (Morgan, 2009).

    In the succeeding years, billions of dollars were spent in advanced metering infrastructure (AMI)—automated meters that precisely measure consumption or production at more granular intervals than the past’s monthly meter reads, relaying those data instantaneously between customers, substations, and utility back offices with high fidelity. If the transmission grid is the physical network on which the wholesale electricity market is founded, these smart meters are the physical basis for retail customer empowerment. They unlock the opportunity to make the sector into a genuinely two-sided market where sources of flexible demand and distributed energy resources actively participate in response to prices driven by grid needs that are transmitted through the smart meter.

    Yet those ambitions have largely failed to materialize. To take but one concrete example, Pennsylvania’s FirstEnergy electric utilities commenced their AMI roll-out in 2014 and by mid-2019 had achieved a nearly universal, 98.5 percent deployment across all customers, spending $920 million to deploy just over 2 million smart meters.1 As part of the Pennsylvania statute that laid the groundwork for these investments, the FirstEnergy Companies were required to create at least one rate offering that made use of the technology by having a time-varying component—a reasonable requirement given the soaring rhetoric about the transformed customer experience foretold by the smart grid.2 Echoing Commissioner Morgan’s comments, Pennsylvania utility commissioner Rob Powelson, later appointed to the Federal Energy Regulatory Commission, wrote a separate opinion concurring in the AMI spending, but noting, “To be frank, it is pointless to have smart meters if you are still going to have ‘dumb’ rates.”3

    The FirstEnergy Companies did introduce a time-ofuse rate. Between June 2019 and December 2021, the number of residential customers enrolled in it ranged from 44 to 97.4 Those numbers are not missing digits. Taking the figure at the upper range, that is approximately one residential customer for every 20,000 smart meters installed or an enrollment rate of five-thousandths of one percent (0.005%).

    This sorry outcome is hardly out of the ordinary. The Brattle Group estimated in a 2019 survey that only 1.7 percent of all residential customers in the United States were enrolled in time-of-use rates (Faruqui, Hledik, and Sergici, 2019). Only a handful of state and provincial regulatory commissions in North America have determined to make time-of-use rates the default option for residential and small commercial customers. Everywhere else, utilities charge flat rates—the same perkilowatt-hour price in all hours.5 Thus have “smart meters” perpetuated “dumb rates.” While smart meters might convey more information to consumers about their energy usage, this on its own has been found to have no significant effect whatsoever on a household’s use of energy (List, Metcalfe, and Price, 2018). Again, whatever else smart meters achieve, if they are paired with “dumb rates,” they do not achieve outcomes around the shape and volume of demand. Prices matter.

    On the opposite pole, there exists a mostly hypothetical landscape where utilities and other businesses that serve retail electricity customers use smart meters to completely absent themselves of an intermediary function, letting the wholesale market and the retail market converge. We have one recent but catastrophic example of this in the United States: Griddy, the only American business exclusively dedicated to the use of the smart grid to pass through real-time wholesale price signals directly to residential customers.

    Griddy imploded in the aftermath of Winter Storm Uri in 2021 as supply fell from outages at power plants and wellheads, demand rose in the face of extreme cold, and wholesale prices in the face of these supply shortages settled at Texas regulators’ pre-established “value of lost load” that also functioned as the wholesale market’s price cap (then, $9,000 per megawatt-hour). Passing through those prices as promised, Griddy customers received bills for thousands of dollars for mere days of electricity service—if they were lucky enough (or perhaps unlucky enough) to have it at all.6 Griddy constituted less than one-half of one percent of all customers in Texas, though their experience came to characterize a free-wheeling and inadequately regulated marketplace. Ironically, the state’s competitive retail market otherwise caused retailers to bear the costs of unhedged wholesale positions, protecting their customers, since customers themselves generally were served by contracts with fixed prices.7 Texas lawmakers outlawed the Griddy business model shortly thereafter.8 In Griddy’s bankruptcy proceedings, all its erstwhile customers were forgiven any obligation they had to pay outstanding charges to the company (Moritz, 2021).

    These are the two extremes in how an electricity retailer might use the smart grid to transform the customer experience: not at all, signaling to customers that each and every kilowatt-hour they use has the same value as any other kilowatt-hour, or, on the other extreme, by making retail prices a mirror of wholesale prices, issuing customers a new price as often as every five minutes without any protection from extreme price spikes. Live in the cave or on the roller coaster, as it were. An appropriate outcome almost certainly lies somewhere in the middle.

    The unfulfilled promises of the smart grid in mind, the main purpose of this paper is to understand the intersection between an energy transition that is badly in need of a more active demand side and the regulatory policies that have restrained that from happening. In an attempt to get back on track toward fulfilling the smart grid’s promise, I will also propose some solutions.

    This paper is organized in three parts:

    • A survey of the growing importance of activating mass-market (which is to say residential and small commercial customers’) demand in the modern electricity economy, the AMI and smart-device landscape that makes this possible, and what utility regulatory commissions are doing (or, as the case may be, not doing) to activate this demand through their rate-design and retail-market-structure decisions.

    • An examination of how this landscape fits into the incentives that face two very different business models of energy supply service: cost-of-service-regulated utilities that typically lack any genuine financial exposure to marginal energy costs and thus lack an incentive to activate demand, and competitive retailers that do face some positive version of this incentive, though it is diffuse and sometimes incomplete.

    • A reform agenda which can be summarized simply: Every electricity customer in the United States should either take service under a time-varying rate as a default option or should be supplied by a provider that does have the financial incentive and ability to activate the customer’s demand in relation to the dynamic wholesale market on the customer’s behalf. Someone, somewhere must face the clear price incentive to actively manage demand in order for it to happen.

    Ratemaking and Technology, Supply and Demand, and the Imperative for Time-Varying Prices

    Two Types of Retailers and Their Financial Incentives

    A Reform Agenda for Retail Rate Design and Market Structure…Cost-of-Service-Regulated Monopolies…Competitive Retailers…

    REFORM 1 Make Time-Varying Rates Opt-Out for Regulated Utilities and Default Service Providers…REFORM 2 Ensure That Competitive Retailers Are Exposed to All Relevant Grid Costs…REFORM 3 Put Competitive Providers in Charge of the Customer Bill…REFORM 4 Encourage Public Investment and Standards for Automated Devices…

    Conclusion: A Two-Sided Market Where Demand Acts as Demand

    Regulation’s attempt to date to activate demand has been to jerry-rig it as a supply resource, bidding into energy and capacity programs. Or, sometimes demand activation has been relegated to niche utility programming, where all comers must subordinate their innovative spirit to become the vendors to a monopoly. This model of demand response—a term this paper has avoided, since demand inevitably is responsive to the incentives with which it is faced—has been a poor substitute for what should be our goal: a marketplace where smart meters and automated devices make possible a genuinely two-sided marketplace where demand is active.

    The status quo of demand response has been defined by endless arguments about how the wholesale market for supply should accommodate demand acting as a supply resource. Is demand response really showing up?44 Has the regulator appropriately defined the baseline usage on which demand reductions should be established and compensated? What obligations does demand have to pay for the option to use energy, which it has foregone? These are immensely thorny questions, and, so long as demand response is a jerry-rigged supply resource, all of them need government-defined answers within the administrative construct that is the wholesale electricity markets.

    In the paradigm this paper lays out, retailers’ end-use customers have agreed to pay them a retail price for what they might use, and the retailer has agreed to serve the customer at that price. When the marginal cost exceeds that price, an opportunity for shared savings emerges, and there is no need—except through private commercial agreement, not government intervention—to calculate a baseline. The retailer retains responsibility for privately managing the costs to serve demand, drawing on supply (owned resources, contracted resources, financial hedges, and the spot market) as well as demand (inducing its retail customers to reduce their needs). Under timevarying rates, customers are themselves faced instead with this incentive, since we must concede that certain retailers—cost-of-service regulated utilities—do not face that incentive.

    When retailers serve demand, all demand is demand. In nearly every other market, we have empowered consumers to decide whether, when, and how to buy products—and those decisions inform but are not supplyside decisions. So too it should be in the electricity economy. Treating demand response as a lucrative source of supply will, in some ways, drive demand participation into an administrative construct, rather than a freer market that is characterized by demand’s genuine elasticity and its ability to say “no” to supply’s too-high offers to sell their goods, as other consumers do in every other two-sided market.45 It is high time for demand to act like demand, the co-equal and opposite force to supply, and not just a junior-varsity source of supply.

    This role for demand is made possible by the consumerfacing, digital and internet-connected technological advances that have transformed our lives in so many ways—but not yet, not really, in the electricity sector, even if the smart meter hangs on the side of your house. Much of other sectors’ technological change does not seem to have made us better people. We can entertain ourselves to death on streaming services, have packages endlessly brought to our door by couriers, and camp out permanently on social media, all while disconnected from our families and nature. But the consumer technology revolution as applied to our electricity networks need not be consumptive. It can instead give us better information about what we are using and, importantly, allows us to adjust our consumption in ways that benefit us as well as the power grid that serves us, so long as regulators take steps to enable that. These are welcome developments in a time of what can seem like a throwaway culture, living up to an important and timely exhortation that “technologically advanced societies must be prepared to encourage more sober lifestyles, while reducing their energy consumption and improving its efficiency.”