Monday Study – Will California’s New Net Metering Plan Kill Rooftop Solar?

Is NEM 3.0 the End of rooftop solar? Unlikely. Customer Economics Deep Dive

19 January 2022 (Bank of America Global Research)

Key Takeaways

We provide our latest 'mini-model' on resi solar economics in California premised upon earlier PD: see a path forward

We see trend towards smaller systems, substantial battery integration & dynamic load mgmt as all substantively minimizing NEM

Buys on RUN and NOVA. We breakdown in detail impacts of a shift in resi solar rates.

Load mgmt will be novel piece to puzzle.

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CA Net Metering: We present a simplified customer model

We think that CA NEM 3.0 remains the near term wild card for resi solar investors; oral arguments were cancelled last week while the latest published CPUC agenda for Jan 27th now shows that the NEM 3.0 Proposal Decision has been removed (see key takes).

As investors try to make sense of these moving parts, we present for the first time, a detailed, yet simplified customer economic model that attempts to demystify the array of inbound questions we've fielded over the last month. Specifically, we quantify the impact of fixed charges and lower export rates against realistic cost assumptions for rooftop solar and solar + storage in the lens of simple payback on a cash sale - directly mirroring the CPUC but in a more "real world" lens. With our model completely dynamic in nature - outputs below are just one scenario with the full model available upon request.

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Glide path works: Fixed charge $3/kW or less initially

More so than anything else, the debate around NEM 3.0 has centered on the inclusion of a fixed charge, proposed at $8/KW-mo based on system size or equivalent to ~$670/yr vs a 7KW average system. Targeting a 10 year payback, the PD includes a "Market Transition Credit" or more simply a net fixed charge that balances payback targets with dynamic cost inputs. The problem, however, is that by any account, the costs used for solar and storage look aggressively low within the PD - so much so that even the NRDC, a strong utility side advocate, has suggested this needs revisiting in recent written commentary. All that said, we calculate that under a realistic scenario of $3.9/W solar (v CPUC at $2.34) and $1000/KW-hr for fully installed paired storage (v CPUC at ~$700/KW-hr), 10 year payback can be achieved If the Transition Credit is >$5/KW-mo initially implying a net fixed charge of ~$3/KW-mo. The output, we think there are some tweaks needed, but a better glide path can achieve a 10 yr payback.

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…but NEM 3.0 is more so an optimization game

Incorporating our more realistic cost inputs we suggest payback of 13 years for solar and 12 years for solar + storage before adjusting glide path. As a critical note, this includes an assumption of optimized load management - without it, solar only payback rises to 16 years. We emphasize that NEM 3.0 presents an optimization issue on smaller sizes & shifting load to align with solar output midday. We estimate payback can be cut in half by simply under-sizing solar by -20% - expect smaller systems in CA as a major consequence alongside ramp in storage. Further, we highlight limited marginal impact on payback as supportive of larger battery installs. Finally, load management to clip evenings & align usage during peak solar presents a material uplift - we estimate 30% higher savings over 25 yrs for solar only installs. Expect solar co's to take a huge focus on these dynamic controls on behalf of customers.

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Is NEM 3.0 the death of CA rooftop solar? Unlikely.

Despite political, media and investor sentiment suggest it may be, our hard look at the economics says otherwise. Glide path and optimization potential leaves clear routes to maintain a compelling payback. We stress that co's have already calibrated their guidance to accommodate NEM 3.0 outcomes and see shares as likely approaching a low point on this debate in the near-term. Maintain Buy on RUN and NOVA.

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Customer Economics in a NEM 3.0 California

With the confluence of debates surrounding NEM 3.0, we present for the first time a model aligned with the Proposed Decision released by the CPUC including detailed analysis of the puts and takes on customer economics. As a disclaimer, we acknowledge that this analysis is in and of itself, illustrative in nature, and intended as a simplification of highly complex and multivariate modeling done to determine payback periods within the Proposed Decision released on Dec 13th. But given broad based industry pushback on some of the base level assumptions used to calculate payback - most notably solar capex indicated at $2.34/W fully installed - we suggest this analysis as a sense check on what the PD really means for solar installs in CA going forward, but extrapolated to "real world" economics. Further, we use this modeling as a means to determine optimized installations under a NEM 3.0 world.

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We summarize 5 key takeaways that are well supported by our analysis:

Solar + storage presents a more compelling economic incentive vs solar only, even given current battery costs. We highlight prospective catalyst from permissible system oversizing and deflationary pressures on battery costs in the coming years as being incremental for paired storage economics.

Under-sizing solar only systems presents a material benefit from a payback lens: Net of storage, overall weak export rates and fixed grid charges clearly incentivize minimizing overall system size for solar only installs. Lower system size = lower fixed costs while limited midday export incentive means that solar generation should ideally match closely to midday consumption. We calculate that under-sizing systems by 20% as compared to daily load could cut payback time in half vs current upfront costs. Expect under-sizing could be a very real trend in CA going forward; the question is how much scale is lost. On balance the new 'optimal' is likely well below the more massive historic 10kW systems.

For solar only installs, load management is critical: By our analysis, managing residential load to clip evening peak use in favor of higher midday consumption presents a material uplift on economics. We emphasize 16 year payback under a scenario where load is not managed in this manner vs the 13 years without. This suggest relative economics on CA resi solar will increasingly be as much of a software function as they are improving hardware. For solar + storage, we see load shifting as less incremental to economics. Expect resi installers and component providers to increasingly lean into this theme. Dynamic load control midday is a real and new dynamic to watch; will customers 'sign on' remains an open question.

For solar + storage, TOU export rates are trivial - batteries are now optimized to avoid peak rates. It's worth noting that under the example rate structure presented by the CPUC, export rates are, at their best, half of the retail import rate. By consequence, the incentive on storage is firmly geared towards self-consumption which still presents a partial benefit to CAISO by reducing peak evening load. We see relatively balanced puts and takes by adjusting battery sizing from a payback lens though with enhanced resiliency coming at limited marginal cost. Expect larger battery attachment could be a theme in CA, albeit not dramatically so if aligned with load mgmt (10KWhs could help plenty for instance). NEM 3.0 is not a death sentence to CA Solar: Glide path and better system optimization both present real opportunities to target a <10 year payback. Higher utility rate inflation keeps an upward moving baseline for CA solar while we expect labor cost compression under a NEM 3.0 world - given, its dealings with third party dealers, NOVA in particular has suggested this as an output. While we believe that tweaks are necessary to align the outputs within the PD to real world economics, we see a payback in all key scenarios considered with clear routes to optimize.

What role SHOULD rooftop solar play? … Designing our 'mock' rooftop system…Load Management is no longer a 'nice to have'…What about paired storage? Oh, yes, this is the 'new thing'…So what does all this mean for payback?...So where's the point of compromise?

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Is NEM 3.0 the death of rooftop solar in CA? Hardly

So is NEM 3.0 the death of rooftop solar in CA? Despite political, media and investor sentiment that may suggest it is, our hard look at the economics seems to suggest otherwise. We suggest that the balance between fixed charges, reasonable cost assumptions and deflationary expectations on storage in particular do in fact leave a glide path for the CPUC to target a still competitive 10 year payback without a more extensive overhaul entailed in an alternate decision. All that said, we think there are still further ways to make the economics more attractive beyond any adjustments to fixed charges by the CPUC.

NEM 3.0 is now an optimization game:

As mentioned earlier we have further considered optimization parameters particularly when it comes to relative sizing of solar and paired storage. For solar only installs, we see real economic incentive to go smaller - specifically to undersize daily output vs daily load. We highlight what we calculate as a 7 year payback (assuming fixed charge of ~$6/kW) at 80% system sizing at $3.75-4/W vs 13-14 years at 1:1 sizing.

Logically, this should not surprise - the midday export rate provides little incentive to solar only installations and is far more than offset by punitive fixed charges associated with a larger system. We expect a real trend in California could be to undersize systems going forward.

For storage the results are more nuanced representing more balanced puts and takes as compared to solar only. To be clear, this does not mean that there's no benefit to adjusting sizing, but rather suggests that the trade in upfront cost looks largely balanced by capacities to further modulate self-consumption. That said, we emphasize real intangible benefits from larger a larger battery packs during an outage as presumably accompanying limited increase in payback. As a consequence we expect that larger battery installs may be another trend to watch as the marginal cost is minimal relative to the upsized resiliency benefit.

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Summary

The long and short is that NEM 3.0 likely needs some tweaking to appease both parties, though significant overhaul may not be necessary in our view. We see opportunity for a glide path that meets the targeted 10 year payback even with higher cost assumptions albeit also assuming load management as an offset, particularly for solar only installs. We emphasize that rooftop system sizing and load management are material considerations for solar only installs - we perceive that optimizing both leaves sub 10 year paybacks firmly on the table even with full fixed charges as proposed. On 1:1 sizing, paired storage does present a stronger economic proposition while we see incentives for larger battery capacities alongside cost deflation at limited marginal cost.

We look for still to be rescheduled oral arguments as the next data point to determine the latest sentiment on NEM 3.0 from stakeholders while timing on a final decision now looks up in the air. On balance, the pushback in timing, while not at all unexpected based on our recent investor surveys, presents yet another volatile data point for resi solar names into year-end earnings announcements - watch this space… click here for more

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Trevor Noah Looks At Climate Crisis Headlines

The situation is dire but there’s always time for a laugh. From The Daily Show with Trevor Noah via YouTube

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Transactive Energy On The Horizon

This would be a new kind of power system that includes all resources, from individual homes to giant wind and solar projects, and it would compensate each for exactly what each is worth to the market. From Pacific Northwest National Laboratory via YouTube

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How The U.S. Could Replace Russia In Ukraine

If the Ukraine face-off terminates the Nordstream pipeline between Russia and Ukraine, demand in Europe could drive a boom in U.S. liquified natural gas exports, making natgas more expensive and opening domestic electrification to more utility-scale and distributed renewables. From YaleClimateConnections via YouTube

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New Forecast Of Costs For Fighting The Climate Crisis

McKinsey: fundamental transformation of global economy needed for net zero; $9tn of annual investment required to avoid most catastrophic climate impacts, consultancy says

Damian Carrington, 25 January 2022 (UK Guardian)

“…$9.2tn will need to be invested every year for decades to limit the global temperature rise to 1.5C and end the climate emergency... [According global consultant McKinsey, that] is a 40% increase on current investment levels and equivalent to half of global corporate profits…[The vitally needed] economic transformation will affect every country and every sector, with those most reliant on fossil-fuel-burning experiencing the most change…[T]he transition will be front-loaded with, for example, the cost of electricity rising before falling later…[but there will be low-carbon investment opportunities that] lead to a lower-cost, more efficient economy…

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…[T]he transformation becomes more expensive the longer action is delayed…[and this] front-loaded transformation raises a ‘critical question’ of who will pay and whether higher costs of electricity, steel and cement are passed on to people or whether those on low-incomes are protected by governments…[I]nvestment in energy, transport, buildings, industry and agriculture would need to rise by $3.5tn, with an additional $1tn of today’s spending switching from high-carbon to low-carbon goods, such as electric cars and heat pumps…

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…[The cost’s percent of GDP start at] 6.8%, rising to as much as 8.8% between 2026 and 2030 before falling…[E]lectricity costs could rise by 25% by 2040 before falling below today’s levels after 2050, because of the lower operating cost of renewable energy. Steel and cement face cost increases of about 30% and 45% respectively…” click here for more

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Imagining A Global New Energy SuperGrid

New HVDC prototype and powerful economic analysis make the case for a global energy grid based on 100% renewable energy

20 January 2022 (Renewables Now)

“…[An industrial scale prototype of a next generation high-voltage, direct current (HVDC) power transmission technology] could pave the way for a global electricity grid, based on renewable energy…[University of Birmingham researchers expect innovations] that improve the reliability and efficiency…[An economic analysis showed] that coupling HVDC transmission with 100% renewable energy generation can deliver significant cost-savings (a minimum of 20%) when the world’s continents are joined together by a global energy supply grid…

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…[The] vision for the global grid involves connecting renewable energy supply from 14 regions [including the European Union, North Africa and the Middle East, Eastern Russia, Western Russia, Central, South, East and South East Asia, Oceania, Western, Eastern and North-eastern North America, and South America], which span all continents and all time zones…

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…[Theoretically, the plan would increase the availability and decrease the cost] of renewable energy…[and] use renewable energy to provide a vital safety mechanism for controlling frequency dips in national power grids…[The analysis included renewable energy supply, global electricity demand, and] transmission costs over land and sea, potential power losses during transmission, and the operational and management costs of an HVDC-based global grid…[Adopting this approach regionally has been estimated to reduce the cost of electricity] for Europe, North-East Asia and North America respectively…” click here for more

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ORIGINAL REPORTING: The Electrification In The Infrastructure Bill

Federal Infrastructure Bills Would Drive Transportation Electrification

Herman K. Trabish | October 5, 2021 (California Current)

Editor’s note: The bipartisan bill was passed and is successfully being put to work. Build Back Better is all but bupkus.

Two federal proposals to advance electric vehicles in California and across the nation are the $1.2 trillion Invest in America (HR 3684) bill, already passed by the Senate, and the House’s controversial and still evolving $3.5 trillion .

There is $30.7 billion in Invest in America to advance EVs, according to Atlas EV Hub. That includes $7.7 billion in funding for ZEVs, $12.7 billion for “clean” vehicles, including hybrids, and $10.3 billion for battery manufacturing and recycling and transportation electrification-related power system infrastructure.

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There are grants for charging and fueling infrastructure, public school efficiency and renewable energy, and advanced manufacturing, Atlas reported. Funds also are included for studies on electrification impacts and critical minerals mining, charging station standards, network interoperability, and medium- and heavy-duty truck, fleet, bus, ferry, and port emissions reductions.

The more ambitious but uncertain House Act provides $34.5 billion for ZEV-related projects, Atlas reported. It also could provide as much as $117.1 billion in “clean” funding for which ZEV-related manufacturing, production, deployment projects are eligible.

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The House Act adds $10 billion in grants for vehicle and charging infrastructure deployment, for battery recycling, and for transportation electrification at ports and airports. It also provides $22.5 billion for federal fleet electrification and $15 billion for charging station and rapid transit project development in low-income and disadvantaged communities.

Importantly, it also provides $10 million to continue the $7,500 tax credit for ZEV purchases. Bonuses for a ZEV’s domestic and union-made product could make the tax credit as high as $12,500. A House provision removing the current limit of $200,000 in tax credits per ZEV manufacturer would be especially valuable at driving the market, automakers, charger providers, and advocates agreed. Many transportation electrification stakeholders seem to prefer the certainty of the Senate bill… "click here for more

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Feds Streamline New Energy On Public Lands

The U.S. Government has announced a new MOU to expedite and streamline processes for renewable energy development on public lands across federal agencies.

Alexander Richter, 23 January 2022 (Think GeoEnergy)

“…[The U.S. Departments of the Interior, Agriculture, Defense, Energy and the Environmental Protection Agency will] improve federal agency coordination and streamline reviews for clean energy projects located on public lands…[and the Bureau of Land Management (BLM, Department of the Interior) has consented to geothermal leasing [and permitting on National Forest Service] lands…

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…[This] supports the Biden-Harris administration’s goal of a carbon pollution-free power sector by 2035, as well as Congress’ direction in the Energy Act of 2020 to permit 25 GW of solar, wind and geothermal production on public lands no later than 2025…” click here for more

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The Conundrum of Electricity’s Cost In California

Utility Costs And Affordability Of The Grid Of The Future An Evaluation Of Electric Costs, Rates And Equity Issues

May 2021 (California Public Utilities Commission)

Executive Summary

“Senate Bill (SB) 695 (Kehoe, 2009) requires the CPUC to prepare an annual report addressing electric and gas cost and rate trends as well as actions to limit or reduce utility costs. 1 For 2021, the CPUC is taking a different approach to this report in order to provide a longer-term rate forecast and to leverage a wider array of subject matter expertise from within the CPUC as well as externally in academia and the energy industry. The goal is to evaluate longer term system costs and policy risks. The draft of this report (the SB 695 Report or White Paper) laid the foundation for an “En Banc Meeting on Cost and Rate Trends” held on February 24, 2021, which provided a venue for discussing potential options for addressing the trends and impacts identified herein.

The CPUC faces multiple intersecting policy mandates that require a delicate balance to avoid unintended consequences. If handled incorrectly, California’s policy goals could result in rate and bill increases that would make other policy goals more difficult to achieve and could result in overall energy bills becoming unaffordable for some Californians. Electrification goals and wildfire mitigation planning are among the near-term needs, for example, that place upward pressure on rates and bills.

Another regulatory risk that has been identified in prior SB 695 reports and is further detailed in this white paper is a continuing increase in capital investments that are recovered in rate base by the investor-owned utilities (IOUs). While capital investments by IOUs will be necessary to meet California’s energy and climate policy goals, they can result in higher bills for customers. Evaluating the reasonableness of these investments in a cleaner, more efficient grid raises affordability and equity implications that merit further investigation.

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While this white paper does not explore a comprehensive, detailed breakout of all essential cost categories and their incremental impacts on IOU rates, it evaluates select areas of projected costs of specific programs and policy priorities, including transportation electrification (TE) and wildfire mitigation plan (WMP) implementation. The decision to highlight these specific areas of cost is informed by recent findings of staff analysis and the desire to bring their relative impacts on overall rate forecasts into sharper focus within the broader operations and revenue requirements of California’s IOUs. The figures below provide the illustrative impacts of projected wildfire spending relative to the other major bundled2 residential rate components from 2021 through 2030.

The rate forecasts developed as part of this white paper, in conjunction with estimates of natural gas rates and gasoline prices, were used to project total energy bills for a representative high energy usage household located in a hot climate zone based on rates for each of the major IOUs, as presented in the figures below. These projections show that, for energy price sensitive households, bills are expected to outpace inflation over the coming decade. The implication is that, if household incomes are expected to generally increase at the rate of inflation, energy bills will become less affordable over time.

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The policy goals and regulatory requirements that create upward cost pressures appear manageable over a longer time horizon, but if not managed correctly, they could trigger equity and affordability concerns for vulnerable customer populations over the short- to mid-term horizon. There is the potential for a growing divide in the cost of service between customers participating in behind-the-meter (BTM) or distributed energy resources (DER) and those who are less likely to do so. Moderate- to higher-income customers are more likely to invest in DERs such as solar photovoltaic (PV) systems, electric vehicles (EV), and storage technologies, and the advanced rate offerings that support them. This enables them to shift load and take advantage of potential structural billing benefits, which often results in a cost shift onto lower-income and otherwise vulnerable customers. Without the prudent management of IOU revenue requirements, rate base, rate structures, and DER incentives, California’s continued progress toward the optimized grid of the future may widen this chasm between participants and non-participants of DER opportunities.

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There are three critical and overlapping regulatory fronts that must be actively managed to address this fundamental equity risk for vulnerable customers:

1. The costs and timing of fulfilling clean energy and electrification mandates;

2. The relatively rapid pace of rate base growth; and,

3. Revenue shifts to lower-income non-participants from Net Energy Metering (NEM) and other DER incentives

Problem Statement

The need to improve the safety and reliability of the electric system while meeting California’s climate goals and various statutory mandates will require careful management of rate and bill impacts to ensure that electric services remain affordable. As California continues transitioning to a more robust distributed energy resources marketplace with greater deployment of electric vehicles, it will be essential to employ aggressive actions to minimize growth in utility rate base and to protect lower-income ratepayers from cost shifts and bill impacts. This white paper explores the affordability of the grid of the future and is intended to stimulate discussion of potential solutions that will be necessary to ease this transition, particularly for California’s most vulnerable customers.

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Key Findings

Across all three IOUs since 2013, rates have increased by 37% for PG&E, 6% for SCE, and 48% for SDG&E. 4 The growth in rates can be largely attributed to increases in capital additions driven by rising investments in transmission by PG&E and distribution by SCE and SDG&E. While the utilities have made major financial commitments to wildfire mitigation and transportation electrification, these costs have not been fully reflected in rates so far. This paper finds that transportation electrification investments are not expected to contribute to significant rate growth in the near term, but that wildfire mitigation efforts will. Furthermore, higher than national average returns on equity (ROE) are a more modest but not insignificant factor that has amplified the three IOUs’ revenue growth in recent years.

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While tracking rates is important, customers care more about their bills than rates. California bills have typically been lower than most of the country in recent years, but those trends are changing. In 2019, SDG&E’s bundled residential average monthly bill ranked 142nd highest out of about 200 IOUs, even though its rate was among the top 20 highest. PG&E, however, is showing a 2018 and 2019 monthly bill ranking of 94th highest and 70th highest, respectively, meaning PG&E’s bills are higher than most of the IOUs being ranked. Further, SCE’s bills, while still lower than the median (#100 ranking), moved up in the rankings from 136th highest to 122nd highest between 2018 and 2019.

Looking forward, the paper’s 10-year baseline forecast shows steady growth in customer rates (nominal $/kWh) between 2020 and 2030 for the three IOUs:

• PG&E: $0.240 to $0.329, or about an annual average increase of 3.7 percent

• SCE: $0.217 to $0.293, or about an annual average increase of 3.5 percent

• SDG&E: $0.302 to $0.443, or about an annual average increase of 4.7 percent

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By 2030, bundled residential rates are forecasted to be approximately 12 percent, 10 percent, and 20 percent higher, respectively, than they would have been if 2020 actual rates for each IOU had grown at the rate of inflation.5 However, when the analysis focuses on households in the hotter regions of the state, household bills (electric, natural gas, and gasoline) are forecasted to rise at an annual rate of 4.5 percent, as compared to a 1.9% inflation rate.

While the cost to further reduce GHG emissions in the electric sector to 38 million metric tons (MMT) compared to a target of 46 MMT would increase bills by $4 to $9 a month, a well-managed effort to move customers to all electric homes and electric vehicles could result in over a $100 a month reduction in overall energy bills. This means that, in order to avoid large increases in energy bills, customers will need to adopt technologies that require large up-front investments. In the absence of subsidies and low-cost financing options, this could create equity concerns for low- to moderate-income households and exacerbate existing disparities in electricity affordability…” click here for more

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An “Unequivocal” Increase In The Global Temperature

This is why they call it a crisis. From NASA Goddard via YouTube

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The Nuclear Re-evaluation

Until small modular reactor technology proves itself and brings down costs, the available investment will and should go to today’s low cost New Energy. From Yale Climate Connections via YouTube

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A White Wash For The Climate Crisis

It will take every good idea to beat the climate crisis and this is one. From PBS NewsHour via YouTube

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The Affordable Cost To Stop The Climate Crisis

The Surprisingly Low Price Tag on Preventing Climate Disaster

Yuval Noah Harari, January 18, 2022 (Time Magazine)

“As the climate crisis worsens, too many people are swinging from denial straight to despair…Despair is as dangerous as denial. And it is equally false. Humanity has enormous resources under its command…[No one knows the full cost to] prevent catastrophic climate change…[Achieving a net-zero carbon economy has been estimated to require just] 2% to 3% of annual global GDP…We can quibble endlessly about the numbers, tweaking the models this way and that…[But the] crucial news is that the price tag of preventing the apocalypse is in the low single digits of annual global GDP…

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…[And it is] about making investments in new technologies and infrastructure, such as advanced batteries to store solar energy and updated power grids to distribute it. These investments will create numerous new jobs and economic opportunities, and are likely to be economically profitable in the long run in part by reducing health care expenditures and saving millions of people from sickness caused by air pollution…

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Since global GDP is now about $85 trillion USD, 2% currently totals about $1.7 trillion…[That will not] derail the economy or abandon the achievements of modern civilization. We just need to get our priorities right…During the 2008–09 financial crisis, the U.S. government spent about 3.5% of GDP to save financial institutions…[In just the first nine months of 2020 COVID stimulus measures were] worth nearly 14% of global GDP…[Right now, 2.4% of global GDP goes to militaries, 2% of annual global GDP subsidizes the fossil-fuel industry, and tax evasion costs] around 10% of global GDP…The money is there…[Instead of defeatism, demand] 2% of annual global GDP.” click here for more

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Global Geothermal’s Double-Barreled Power

The world is hungry for lithium. Geothermal energy could transform how it’s sourced

Anmar Frangoul, January 19, 2022 (CNBC)

“..In the Uk’s county of Cornwall, efforts are underway to tap into the area’s natural resources and establish an industry which could, one day, produce both renewable energy and establish a local source of lithium…[L]ithium is crucial to electric vehicles and battery storage, two technologies with a big role to play in the planet’s shift to a low and zero emission future…

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Cornwall’s Geothermal Engineering Ltd (GEL) wants] to demonstrate that lithium hydroxide, a key component of lithium-ion batteries used in electric vehicles, can be produced in Cornwall from naturally occurring geothermal water with a net zero carbon footprint…[Processing falls into] three main categories: adsorption using porous materials that enable lithium bonding, ion exchange, and solvent extraction…[Doing it] remains a challenging task…The security of global supply chains is another issue, especially when the vast majority of lithium production is currently dominated by countries including Chile, China, Australia and Argentina… [C]ommercializing less intensive, more local and easily accessible ways of sourcing lithium could be hugely important going forward…

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…[Major economies and automotive manufacturers are planning] to increase the number of electric vehicles on our roads…[and] the push to expand renewable energy capacity shows no sign of letting up…[Much lithium is expected to come from recycling batteries but] the majority of lithium that will be in use in 2030 had not been extracted yet…[GeoCubed, Cornish Lithium, Vulcan Energy Resources in Germany, Controlled Thermal Resources in California are all working on geothermal-lithium] engineering, procurement, construction and commissioning…” click here for more

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ORIGINAL REPORTING: An Overview Of The Net Metering Debate In California

As California's solar net metering battle goes to regulators, a focus on reliability may be the best answer; Customer advocates say the current rooftop solar rate is "unsustainable," while solar advocates say "they want to kill us."

Herman K. Trabish | October 1, 2021 (Utility Dive)

Editor’s note: The commission ruling significantly changed existing compensation to solar owners, producing a big protest from the solar industry. The commission’s final ruling is due at the end of this month.

Uncompromising final arguments were filed Sept. 14 in the nationally-watched debate to set a behind-the-meter (BTM) solar tariff in California to succeed the state's retail rate net energy metering (NEM).

Proposals to cut NEM export compensation to customers will "kill" their right of self-generation and are "hostile" to solar businesses, solar advocates said. But current compensation for solar owners creates a "massive" shift of system costs to non-solar owners and a "crisis" of rising electricity rates, customer advocates and U.C. Berkeley economists noted.

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NEM changes proposed by a coalition of stakeholders that "want us dead" may alter the "payback period" on solar purchases and "devastate today's market," California Solar and Storage Association (CalSSA) Policy Director Brad Heavner said.

That coalition, which includes environmental advocate the Natural Resources Defense Council (NRDC) and ratepayer advocate The Utility Reform Network (TURN), sees a threat of higher costs to all electricity consumers.

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"The solar industry is attacking groups that support reform," but today's NEM "is a material driver of rate increases," TURN Staff Attorney Matthew Freedman said. Without reform that recognizes "the needs of the many outweigh the needs of the few," the cost shift "will explode in the coming decade and threaten affordability for all customers."

The "fundamental tension" in California's NEM legislation is that compensation must both drive solar growth and protect all customers, a CPUC-ordered study on cost shifts concluded. Standard regulatory metrics show retail rate NEM shifts costs unjustly. But a new approach to solar that recognizes its reliability value may remedy that, some stakeholders suggested…” click here for more

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Geothermal And Politics

The renewable energy source Democrats hope will break out; Climate advocates and lawmakers believe the $320 billion in tax incentives promoting renewables like geothermal will remain mostly unchanged.

Jonathan Custodio, January 17, 2022 (Politico)

“…[Geothermal energy was included in the bipartisan infrastructure package passed last fall which could lead to technology breakthroughs and cost reductions. The] initial cost for a geothermal energy field and power plant is about $2,500 per kilowatt…In 2019, the average cost for onshore wind generators was $1,391 per kilowatt, while solar energy averaged at $1,796 per kilowatt…

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Geothermal energy only accounted for two percent of total energy consumption in 2020…[But researchers] are working to better identify areas where the rocks have the permeability best suited for geothermal development. So far that’s mostly limited to hotspots in states such as California and Nevada, which combined account for 95% of domestic production…But a newer technology, called enhanced geothermal systems, or EGS, only needs a heat source and uses hydraulic fracturing, or fracking — the same technology used by the oil and gas industries — to increase the permeability of the rock…

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Since geothermal energy is essentially a heat exchanger, it thrives better in colder temperatures…[and some systems] emit very low levels of greenhouse gases, including carbon dioxide and sulfur dioxide…Environmental impacts include increased [but cirmcumscribed and limited] seismic activity…Possibly the strongest argument for greater adoption of geothermal systems is that power plants can produce energy around the clock since the heat in the earth’s core is available 24/7, unlike its wind and solar companions…” click here for more

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Monday Study – Utility Financial Viability At Risk

Hidden Risks of US Utilities

Management, February 2021 (Lazard asset Management)

The Lazard Global Listed Infrastructure strategy currently has low exposure to the US utility sector. This low weight is in direct contrast with listed infrastructure indices and many active managers in this asset class. While many US utilities are high quality natural monopoly assets, we are unable to find value in the sector today. Current valuations imply that the rare combination of low interest rates, generous allowed returns, and solid rate base growth will continue indefinitely. Although this situation has persisted for several years, we believe the risks of a reversal are rising.

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US Utility Earnings

US utilities that are in our preferred infrastructure universe transmit essential commodities like gas, electricity, and water. They are not the power generators or energy retailers that sell to the consumer, rather they own network assets. Utilities that deliver these essential services earn a return on invested capital as determined by a regulator while their fuel, operational and maintenance costs are generally passed-through directly to the consumer.

In the US, each state has its own regulatory agency and the Federal Energy Regulatory Commission regulates interstate transmission assets. As a result, there is a degree of variability in the utilities’ authorised rate of return earned on invested capital. Utilities invest in their networks, maintaining and extending these assets, and improving their efficiency and safety, as well as building new assets for, say, transmission of renewable energy. The more the utility can invest in its infrastructure, the more revenue it can generate.

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The Current Situation

US utilities have enjoyed a widening spread over the risk-free rate since the early 1980s, as allowed returns have declined less than bond yields, a trend that accelerated in the ultra-low rate environment of the last decade (Exhibit 1). This has allowed the utilities to earn a premium to global peers, whose returns are usually linked via formula to the risk-free rate.

Exhibit 2 highlights the experience of regulated UK water utilities, where allowed returns have tracked lower alongside the cost of debt.

While US utilities’ allowed returns are typically not linked to interest rates by any formula, we expect that regulators will not allow them to over-earn forever, so our long-term projections assume a lower cost of capital spread than what is currently allowed.

At the same time as US utilities have been earning quite generous returns on rate base, the rate base has been growing consistently (Exhibit 3)

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Some of the areas of network and generation investment add to the rate base, and at the same time reduce operations and maintenance expense (O&M) which is a pass-through cost to customers. These areas of investment include:

• Installing advanced metering infrastructure, which dramatically improves workforce efficiency.

• Phasing out coal plants in favour of gas and renewable generation (renewable assets add to the rate base and eliminate the variable fossil fuel costs).

• Retrofitting existing generation assets to reduce emissions.

• Building out transmission networks to interconnect regions.

As a result, while rate base growth has been high, the reduction in O&M has helped offset the impact on customer bills.

Other areas of capital expenditure, which are critical, have also added to rate base growth, including:

• Safety and reliability investment (e.g., the federally mandated pipeline replacement project to reduce leaks and wildfire risk by hardening the network).

• Grid investment to keep pace with the widespread adoption of innovative technologies (e.g., electric vehicles).

• Network investment to accommodate the addition of renewables (e.g., household solar)

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Can rate base growth persist at such high rates?

While US utilities’ projections of rate base growth over the next five years suggests that rate base growth levels will be similar to history, there is significant variability within the broader cohort of US utilities. The key question for investors, then, is whether the combination of extreme low interest rates, high allowed returns, and rate base growth will continue.

In our view, at the valuations where these assets are trading, any breakdown in this perfect set of circumstances could see a material de-rating.

US electricity prices have not risen in real terms over the last decade. In fact, they have regressed slightly, while personal income has grown (Exhibit 4). Customer bills have been largely flat with increases in capital investment (net plant) being offset by various cost savings, primarily in energy costs—the price of natural gas has fallen significantly (Exhibit 5).

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The utilities have had the additional advantage of macroeconomic tailwinds over the past decade:

• The decline in interest rates, reducing interest expense.

• The reduction in the federal corporate tax rate

• The gradual ongoing refunds to customers of over-collected tax (deferred tax liabilities)—this liability materialized at the time of the corporate tax rate cut.

• Federal tax credits arising from the construction and electricity production of renewables.

• Network expansion for customer growth (for some utilities, but not all).

Although these tailwinds should be to some extent sustainable, we think they are unlikely to be as strong in the future as they have been in the past. Ultimately, we think that ongoing high levels of capital expenditure (and rate base growth) will flow through to customer utility bills, and regulators will need to consider curbing rate base growth or lowering utilities’ allowed rate of return. Neither option is positive for US utility valuations.

Above and beyond industry-specific risks looms the prospect of higher interest rates. Should the downward rate trend of the past 30 years start to reverse, it could add a further obstacle to US utility valuations. Such a scenario would, we believe, automatically start to correct the over-earning issue, by reducing the spread between allowed returns and interest rates. US regulators would probably avoid lifting allowed returns in response, likely keeping returns flat and letting the spread return to more normal levels. In simple terms, the discount rate will rise with no offsetting change in earnings - leading to a decline in values.

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Valuations

We think these risks are heightened because US regulated utilities are currently trading significantly above their long-term averages (Exhibit 6). US utilities are the single biggest sector in global infrastructure indices.

Their performance consequently makes up a major portion of the returns from passive infrastructure investments and active portfolios with large positions in US utilities.

Our internal value rank highlights the challenges facing the sector. In Exhibit 7, each bar represents the expected annualised return over three years, for each stock in our Preferred Infrastructure universe, based on the assumption that all stocks will trade at our valuation in three-years’ time. As the chart shows, we see potential negative returns over the next three years for US utilities. Only one US utility has positive expected returns over the period. click to enlarge

Announcing The Clean Energy Corps

1000 new jobs dedicated to building New Energy. Apply! “Your planet needs you.” From U.S. Department of Energy via YouTube

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Al Gore On Today’s Climate

The problem is still ahead of the solutions. From CBS Mornings via YouTube

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Comparing New Energy And Old Energy

Rosie explains "Levelized Cost of Energy" (LCOE) and why New Energy ultimately wins. From Engineering with Rosie via YouTube

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Global Leaders Name Climate Crisis World’s Biggest Risk

Climate Crisis Is Top Risk Facing World for Next Decade: World Economic Forum Survey

Alessandra Migliaccio (with Samuel Dodge, Demetrios Pogkas, Kailey Leinz, Matthew Miller and Craig Stirling), January 11, 2022 (Insurance Journal)

“…[Officials and business leaders surveyed for the World Economic Forum Global Risks Report for 2022 see] climate change and rising social tensions, alongside the pandemic, among their top risks…

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Only one in six survey respondents from government, civil society and commerce described their outlook as optimistic, while just one in 10 thinks worldwide economic expansion will pick up speed…Worries over climate-transition failures and extreme weather conditions are among the biggest concerns, particularly in the next five to 10 years…

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Short-term fears include health and social cleavages caused by COVID-19, while economic and debt-related issues are cited as medium-term dangers…Respondents would like greater coordination among leaders to try to solve the world’s problems, even as diverging recoveries from the crisis threaten cooperation…” click here for more

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New Energy’s New Storage Options

Here’s how to solve the UK energy crisis for the long term – store more power; Four storage solutions to help Britain keep the lights on deep into the future

Jillian Ambrose, 10 January 2022 (UK Guardian)

“…A storage boom has been forecast over the coming decade as governments race to meet their climate targets…Within the next five years, the International Energy Agency (IEA) expects global energy storage capacity to expand by 56% to reach more than 270 GW by 2026, driven by a growing need to create flexible electricity systems…Well-established lithium-ion batteries are expected to dominate… [Hydropower can be a form of energy storage if] electricity is used to pump water upwards into a reservoir when the market has ample power available. When electricity supplies become tight the water can be released at short notice to flow over a generating turbine to create electricity for the grid to use…

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…[A new breed of pumped storage uses] a mineral-rich fluid, which has more than two-and-a-half times the density of water, projects could generate the same amount of electricity from slopes which are less than half as high…[Another option is] harnessing “gravity energy” to create electricity by using electric winches to hoist 12,000-tonne weights to the top of a disused mine shaft when there is plenty of renewable energy available, then dropping the weights hundreds of metres down vertical shafts to generate electricity when needed…

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…[Concentrated solar power can be stored as heat in molten salt and] the heat is used to run a conventional steam turbine…Demand for hydrogen made from water and renewable energy is expected to boom in the decades ahead as governments plan to replace the fossil fuels used in power plants, factories and heavy transport with the clean-burning, green alternative. But green hydrogen can also be used as a form of energy storage…[‘Cryogenic’ batteries] could help store renewable energy for weeks rather than hours…[It uses renewable electricity to chill air to -196C, transforming it into a liquid that could be stored in large metal tanks for weeks. When needed, the liquid can be turned back into gas, and used to turn a turbine…” click here for more

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