ORIGINAL REPORTING: Texas Messes With Itself, Makes A Mess

Texas must increase ties to the national grid and DER to avoid another power catastrophe, analysts say; Planning for inter-regional transmission and distributed resources could do what ERCOT’s competitive, energy-only market didn’t – keep the heat and lights on, energy advisors say.

Herman K. Trabish, March 2, 2021 (Utility Dive)

Editor’s note: When the power in Texas goes off this summer or next winter, it’s leaders will be able to say they would have fixed the power system if politics had not been in the way.

Texans were left in the cold and dark this February, following extreme cold weather that had the Texas competitive energy market unable to prevent deadly power failures. Leaving behind its historic commitment to power system independence and joining the larger U.S. grid can relieve some of the consequences of extreme weather events Texas is likely to see again, many energy analysts in and out of Texas said.

"We designed this system for Ozzie and Harriet weather and we now have Mad Max," said Texas energy consultant Alison Silverstein, a former Public Utility Commission of Texas (PUCT) and Federal Energy Regulatory Commission (FERC) adviser, during a Feb. 24 webinar cohosted by the Advanced Power Alliance and Conservative Texans for Energy Innovation. "Texas is now reaping the bitter harvest of avoiding federal transmission regulation and state energy sector regulation."

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The Electric Reliability Council of Texas (ERCOT) competitive, energy-only market "seemed like it was saving money until last week, when losses equaled the cost of three years of generation," agreed Rice University Associate Professor of Civil and Environmental Engineering Daniel Cohan. "The free-market ideology ignores risks. Most people want to keep the lights on more than to make a market theory work."

All types of generation, especially natural gas, failed, analysts have widely acknowledged. Leaders must enforce weatherization and build cooperation among the PUCT, ERCOT and municipal authorities to address future crises, many have added. But for its best future, Texas should also consider expanding demand-side resources and connect with out-of-state markets, because the benefits can justify the investments, analysts said.

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The average Dallas, Texas, low temperature for February is 39°F. But from Feb. 14-16, 2021, temperatures were significantly lower. On Feb. 11, power sector agencies began preparing for demand spikes, according to the PUCT. ERCOT asked customers to limit usage on Feb. 14 and announced generation capacity losses and outages starting Feb. 15. Boil water notices and reports of outage-related deaths soon followed.

Early on Feb. 15, when system frequency fell to 59.3 Hertz, the grid was less than 5 minutes from a cascading statewide blackout, ERCOT CEO Bill Magness said at a Feb. 24 ERCOT board meeting. ERCOT called a load shed event that lasted 70.5 hours, according to ERCOT's documentation. Peak load and outages were significantly higher than Texas has seen, said ICF Wholesale Power Market Advisory Manager Patrick Milligan. The bulk of the "missing capacity" was from natural gas and coal generation outages… click here for more

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The Process of Energy Transition

Energy transformation may 'feel like a slog' before gains - NextEra exec

Carl Surran, June 20, 2021 (Seeking Alpha)

“The integration of new power technologies may cause short-term discomfort but will launch a "wonderful transformation towards a cleaner power grid for society" within a decade, says Mark Ahlstrom, VP of renewable energy policy at NextEra Energy (NYSE:NEE)…

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...[Ahlstrom co-authored] a draft report from the North American Electric Reliability Corporation focusing on grid transformation…[The] integration of large amounts of new technologies, including distributed resources, storage and inverter-based technologies…[comes with challenges and can feel like a ‘slog,’ problems result from] inaccurate forecasting of anticipated net demand…

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Grid operators must improve the interconnection and use of inverter-based resources on the bulk power system, or they risk disruption to electric reliability, particularly in times of extreme weather…[The recent blackouts in Texas and California show it will take more than adding capacity] to ensure sufficient energy is available…” click here for more

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Monday Study – New Energy Waits For Wires To Deliver It

Queued Up: Characteristics of Power Plants Seeking Transmission Interconnection as of the end of 2020

Joseph Rand, Mark Bolinger, Ryan Wiser, Seongeun Jeong, May 2021 (Lawrence Berkeley National Laboratory)

What are interconnection queues? Utilities and regional grid operators (a.k.a., ISOs or RTOs) require projects seeking to connect to the grid to undergo a system impact study before they can be built. This process establishes what new transmission equipment or upgrades may be needed before a project can connect to the system and assigns the costs of that equipment. The lists of projects in this process are known as “interconnection queues”.

High-Level Findings

Developer interest in solar, wind, storage, and gas is strong

 Over 755 GW of generator capacity and 200 GW of storage currently seeking interconnection

 Most (~680 GW) proposed generation is zero-carbon

 Hybrids now comprise a large – and increasing – share of proposed projects

Completion rates are generally low; wait times may be increasing

 For five ISOs where data were available, only ~24% of projects in the queues reached commercial operations

 Completion rates are even lower for wind (19%) and solar (16%)

 For four ISOs where data were available, the time projects spent in queues before being built increased from ~1.9 years for projects built in 2000-2009 up to ~3.5 years for those built in 2010-2020.

Proposed capacity is widely distributed across the U.S.

 Substantial proposed solar capacity exists in most regions of the U.S.

 Wind capacity is highest in SPP, NYISO, and the non-ISO West, with increasing share of offshore projects

 Proposed gas is primarily in the Southeast and PJM

 Storage is primarily in CAISO and the West

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Methods and Data Sources

Data for “active” projects collected from interconnection queues for 7 ISOs / RTOs and 35 utilities, which collectively represent >85% of U.S. electricity load  Projects that connect to the bulk power system: not behind-the-meter  Includes all projects in queues through the end of 2020  Sample includes 5,639 “active” projects

• “Completed” and “Withdrawn” project data were only available for 5 ISOs (CAISO, ISO-NE, MISO, NYISO, PJM)  Sample includes 1,706 “completed”, and 6,896 “withdrawn” projects.

• Hybrid / co-located projects were identified and categorized  Storage capacity for hybrids (i.e., broken out from generator capacity) was not available in all queues

• Note that being in an interconnection queue does not guarantee ultimate construction: majority of plants are not subsequently built

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Completed and Withdrawn Projects

Completed and withdrawn data were available from 5 ISOs, and total 1,706 completed projects and 6,896 withdrawn projects The time from interconnection request (IR) date to commercial operations date (COD) is increasing for some regions and generator types; typically longer for CAISO and for wind

Trends are less evident in time from interconnection request to withdrawn date, though a series of queue reforms from 2010-20121 may have helped reduce backlog Across the five ISOs studied, just 24% of projects proposed from 2000-2015 have reached commercial operations

The completion rate may have increased temporarily after 2010-2012 queue reforms1 but appears to be declining for projects proposed from 2014-2016. Trends for projects proposed in 2017 and after cannot yet be determined

Increase in completion rates for projects proposed in 2012-2014 is visible across several ISOs; wind (19%) and solar (16%) have lower completion rates from 2000-2015 than other types

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Active Projects in Interconnection Queues

Includes data from all 7 ISOs and 35 non-ISO utilities, totaling 5,639 proposed projects

Interconnection queues indicate that commercial interest in solar and storage has grown, including via hybridization; wind and gas have declined

Trends over time vary somewhat by region: Wind capacity has contracted in some regions, solar and storage see consistent growth, gas largely declines

Regional: Proposed solar is widespread, with less in SPP and Northeast; Most wind in SPP with new offshore in NY; Most storage in CAISO, West, ERCOT, and PJM; Gas is largely in the Southeast

State Level: Most proposed solar TX, AZ, IN; proposed wind in TX, “wind belt”, and CA, with offshore in NY; Storage is mainly proposed in CA, TX, NY; Proposed gas in TX and Southeast

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71% (653 GW) of total capacity in queues has expected online date by end of 2023; 13% (117 GW) has an executed interconnection agreement (IA)

The median project with an executed IA (but not yet built) has spent 1,387 days in the queues, over 2.5 years more than the median project without an IA (469 days)

Among projects without signed IAs, those in SPP (median = 915 days) tend to have spent the longest time in the queues, followed by MISO (612) and NYISO (602).

Among projects with signed IAs, those in CAISO (median = 2,072 days) tend to have spent the longest time in queues, followed by SPP (1,645), and West (non-ISO) (1,555).

Considerable variation also exists between resource types, with coal, hydropower, nuclear, and wind projects spending the longest time in queues

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Among projects without signed IAs, nuclear projects (median = 1,004 days) tend to have spent the longest time in the queues, followed by wind (964)

Among projects with signed IAs, coal projects (median = 4,081 days) are by far the oldest, followed by Hydropower (2,444 days)

Interest in hybrid plants has increased: 34% of solar (159 GW) proposed as hybrids, 6% of wind (13 GW) proposed as hybrids (up from 28% and 5% in 2019, respectively) Solar+Storage and Wind+Storage configurations are more common than other hybrid types

Hybrids comprise a sizable fraction of all proposed solar plants in multiple regions; proposed wind hybrids dominated by CAISO

• Solar hybridization relative to total amount of solar in each queue is highest in CAISO (89%) and non-ISO West (67%), and is above 20% in SPP and ERCOT

• Wind hybridization relative to total amount of wind in each queue is highest in CAISO (37%) and non-ISO West (13%), and is less than 7% in all other regions

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Solar+storage is dominant hybrid type in queues, wind+storage is much less common; CAISO & West of greatest interest so far

Solar+storage projects typically feature a higher storage contribution than wind+storage; POI limits are typically based on generator capacity (at least in CAISO)

Storage capacity for hybrid projects was provided in a subset of queues. Where available, we calculated the ratio of storage capacity to generator capacity. Median storage:generator capacity ratio for solar+storage (60%) is higher than for wind+storage (35%), and the ratio is generally higher where solar penetration is higher.

Point of interconnection (POI) capacity limits were only provided in CAISO’s queue. For solar+storage projects, the solar capacity alone equals or exceeds the POI limit in 91% of projects, and the median combined (solar+storage) capacity is double (200%) the POI limit. For wind+storage projects, the wind capacity alone equals or exceeds the POI limit in 67% of projects, and the median total (wind+storage) capacity is 126% of the POI limit. These values suggest that these projects are maximizing their POI limit by using storage to supply power at times when the generator is not generating

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Conclusions

As of the end of 2020, there were over 5,600 projects seeking grid interconnection across the U.S., representing over 755 GW of generation and an estimated ~204 GW of storage.

• Solar (462 GW) accounts for >60% of all active generator capacity in the queues, though substantial wind (209 GW) and gas (74 GW) capacity is also in development. Notably, 29% of the wind capacity in the queues is for offshore projects (61 GW).

• Considerable standalone (89 GW) and hybrid (~112 GW1) battery capacity is also in development, along with 4 GW of other storage.

• Growth in proposed solar and storage capacity is consistent across regions. Proposed wind has contracted in some regions, but continues to grow in those with proposed offshore development. Gas is declining in all regions except for non-ISO Southeast.

• Hybrids now comprise a large – and increasing – share of proposed projects, particularly in CAISO and non-ISO West. 159 GW of solar hybrids (primarily solar+battery) and 13 GW of wind hybrids are in the queues.

• The vast majority (71%) of capacity in the queues has requested to come online by the end of 2023, and some (13%) already has an executed interconnection agreement.

• The time projects spend in queues before reaching COD may be increasing. For the four ISOs studied2, the typical duration from IR to COD went from ~1.9 years for projects built in 2000-2009 up to ~3.5 years for those built in 2010-2020.

• More than half (671 GW) of the estimated 1,100 GW of wind and solar capacity needed to approach a zero-carbon electricity target is already in development3.

• Ultimately, much of this proposed capacity will not be built. Historically only ~24% of projects in the queues reached commercial operations, and less for wind (19%) and solar (16%). There are growing calls for queue reform to reduce cost, lead times, and speculation.

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The Biden Moon Shot

Not because it is easy…Change can happen…Opportunities will open… From Yale Climate Connections via YouTube

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The Health In Cooking With New Energy

The transition to building electrification brings health home. From NationalSierraClub via YouTube

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Record Hot And Dry And Fires Coming

The worst drought in U.S. history. And it has become the norm. From Channel 4 News via YouTube

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World New Energy’s Next Steps

After Capacity Battle, Shifting Renewables’ Focus to Generation Key, Says REN21

Soumya Duggal, June 21, 2021 (Saur Energy International)

“…[R]enewables added 83% of new power capacity in 2020, [but] their share in global electricity generation increased by only 2.7%, [according to the Renewables 2021 Global Status Report]… More than 256 GW of renewable power capacity was added globally during the year, surpassing the previous record by nearly 30%...[The share of renewables in total final energy consumption (TEFC) grew from 8.7% in 2009 to 11.2% (excluding the traditional use of biomass) in 2019…[But the share of fossil fuels changed only] from 80.3% in 2009 to 80.2% in 2019…[because of] rising global energy demand…continuing consumption of and investment in new fossil fuels, resulting in fossil fuels meeting most of the increasing demand…[and] declining traditional use of biomass…

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…[I]nnovation is still needed to enable their widespread adoption in harder-to-decarbonise sectors, such as transport, heating and cooling sectors…[Renewables overtook] fossil fuels as the European Union’s main source of electricity for the first time in 2020 as new projects came online and coal-power shrank…[but] the power sector also accounts for a very small share (17%, of which 27.1% comes from RE) of final energy use when compared to transport (32%, of which 3.4% comes from RE) and thermal (51%, of which 10.2% is RE-based).

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Fossil fuels continue to dominate these sectors…[and renewables’ share in electricity generation] recorded a dismal rise from 27.3% in 2019 to 29.0% in 2020…[F]resh renewables capacity has been taking care of fresh demand, not tackling base demand…[T] he renewable energy industry needs to increase its efforts to impact core global energy demand…[by shifting focus from capacity addition to generation.” click here for more

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Diet For A Climate Crisis Planet

How Animal Agriculture Is Accelerating the Climate Crisis

June 21, 2021 (Sentient Media)

"The meat and dairy industries have a much bigger part to play in the climate crisis than most people are willing to admit…[Animal agriculture’s contribution to the climate crisis is often overlooked… To avoid irreversible impacts, we must limit CO2 in the atmosphere to below 430 parts per million (ppm). This number is currently at 417 ppm, and is increasing by around 2.5 ppm every year…[Industrial animal farming] generates at least 37 percent of global GHG emissions…

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Factory farming drives land-use change and biodiversity loss—all of which depletes Earth’s natural carbon sequestration capabilities which increases the likelihood of irreversible climate change…The number of farmed animals is predicted to double by 2050. Half of all food-related emissions come from beef and lamb. Beef and dairy farming are also a major source of methane, which is 72x more effective at trapping heat compared to CO2…

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A large amount of farmland is used to grow crops for farmed animal feed. This kind of industrial monocropping is known to increase GHG emissions… Natural habitats are cleared to create grazing lands, which causes even more emissions. The top 5 meat and dairy corporations emit more GHGs than ExxonMobil, Shell, or BP…Because animal farming is responsible for so many of these emissions, we can significantly reduce our carbon footprint with a sustainable, plant-based diet…” click here for more

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ORIGINAL REPORTING: Bankers Call For Scrutiny Before Securitization

Possible hundreds of billions in US power sector securitizations spur ratepayer protection debate; Securitization can ease impacts of COVID-19 moratoria debt, stranded asset costs, and extreme weather losses, but bankers and regulators agree that customer costs need oversight.

Herman K. Trabish, Feb. 22, 2021 (Utility Dive)

Editor’s note: More scrutiny is needed of how the hundreds of billions – if not trillions – of customer dollars will be spent to cover accrued power sector costs for COVID and the climate crisis.

Securitization is a financial tool that can reduce utility debt with low interest bonds secured by ratepayers, and with utilities' growing costs related to COVID-19, the energy transition, and climate change, interest is accelerating. But utilities and their customers are facing hundreds of millions or even billions of dollars in such costs, which is raising oversight concerns. When oversight has been introduced, it has led to lower interest rates and lower transaction costs, stakeholders in such proceedings told Utility Dive.

Duke Energy's $1 billion proposal to use securitization to meet storm recovery expenses in North Carolina provides the criteria necessary for the commission to evaluate Duke Energy's proposed transactions, Duke spokesperson Meredith Archie said in an email. It allows the commission "to determine whether and to what extent it wants to be involved in the transaction once it issues its order."

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But clear state laws on securitization are needed to "protect the public," former Colorado Public Utilities Commission Chair and authority on securitization Ron Lehr said. State laws "should encourage regulators to ask what incentives are involved when big banks and a big utility work together and whether those incentives align with the public interest."

Utilities and customer advocates differ on oversight. Duke, though committed to legislative and regulatory guidance on securitization, argued in its proceeding that it can manage bond term negotiations, and the financial transactions that follow, on its own. But with hundreds of billions in potentially securitized dollars at stake, customer advocates contend experts representing ratepayers should have a role in those negotiations.

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Securitization allows utilities to offer long-term bonds to investors to pay off short-term debt. Ratepayers benefit because the cost of the securitized debt is lower than the utility's typical cost of debt, which reduces the monthly bill impact, Moody's added. The bonds have lower interest rates because they are long-term and secured by the high likelihood of customers paying their bills. But enabling state legislation is necessary for credit agencies to provide the AAA credit rating for securitized debt that makes interest rates low.

At least five states passed legislation approving regulatory consideration of securitization by utility regulators in 2019, and at least 18 others have some kind of regulatory, legislative or advocacy effort in the works, according to Energy Innovation and others. The 2020s are likely to see a lot more securitizations, said RMI Electricity Practice Principal and Stanford-Precourt Institute for Energy Research Associate Uday Varadarajan. The Biden administration's commitment to addressing climate issues is likely to accelerate retirements among the approximately 130 GW of remaining operating coal plant assets, he said, leaving about $90 billion in stranded costs eligible for securitization, not counting gas plants or other infrastructure that could be eligible… click here for more

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The New Texas New Energy Boom

Texas likely to add record utility-scale solar capacity in the next two years

Suparna Ray, April 21, 2021 (U.S. Energy Information Administration)

“…Texas will add 10 gigawatts (GW) of utility-scale solar capacity by the end of 2022, compared with 3.2 GW in California. One-third of the utility-scale solar capacity planned to come online in the United States in the next two years (30 GW) will be in Texas…The installation of 2.5 GW of solar capacity in 2020 marked the beginning of the solar boom in Texas…[It is expected] add another 4.6 GW of solar capacity in 2021 and 5.4 GW in 2022, which will bring total installed solar capacity in Texas to 14.9 GW…

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Utility-scale solar projects that start construction in 2021 or 2022 are eligible for a 26% [investment tax] credit. The tax credit drops to 22% for projects that start in 2023 and to 10% for projects that start in 2024 or later…Other factors driving solar investment in Texas include lower solar technology costs and plentiful sunlight, particularly in West Texas’s Permian Basin, where about 30% of the state’s planned solar capacity will be built. In addition, because solar generation is greatest in the middle of the day, when wind generation is typically lower, available transmission lines that already handle the large amount of wind power in the state have helped set the path for record-breaking planned solar capacity additions…

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…[U]tility-scale solar only made up 4% of the state’s generating capacity in 2020 and 2% of in-state electricity generation. In comparison, natural gas made up 53% of Texas’s capacity in 2020 and 52% of in-state generation; wind made up 23% of capacity and 20% of in-state generation…[But] solar is expected to make up the largest share of the state’s capacity additions between 2020 and 2022. Almost half of the additions during this time period will be solar, surpassing wind (35%) and natural gas (13%) additions.” click here for more

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Monday Study: The High Cost Of The Climate Crisis

The economics of climate change: no action not an option

April 2021 (Swiss RE Institute)

Executive Summary

The world economy could be 10% smaller if the 2050 net-zero emissions and Paris Agreement targets on climate change are not met.

The world stands to lose close to 10% of total economic value by mid-century if climate change stays on the currently-anticipated trajectory, and the Paris Agreement and 2050 net-zero emissions targets are not met. Many emerging markets have most to gain if the world is able to rein in temperature gains. For example, action today to get back to the Paris temperature rise scenario would mean economies in southeast Asia could prevent around a quarter of the gross domestic product (GDP) loss by mid-century that they may otherwise suffer. Our analysis in this report is unique in explicitly simulating for the many uncertainties around the impacts of climate change. It shows that those economies most vulnerable to the potential physical risks of climate change stand to benefit most from keeping temperature rises in check. This includes some of the world's most dynamic emerging economies, the engines of global growth in the years to come. The message from the analysis is clear: no action on climate change is not an option.

Under the current trajectory, global GDP could be 11–14% less by mid-century than in a world without climate change. The loss under Paris Agreement targets would be significantly less (around 4%).

Recent scientific research indicates that current likely temperature-rise trajectories, supported by implementation of mitigation pledges, would entail 2.0–2.6°C global warming by mid-century. We use this as the baseline to simulate the impact of rising temperatures over time, while also modelling for the uncertainties around most severe possible physical outcomes. The result is that global GDP would be 11–14% less than in a world without climate change (ie, 0°C change). Under the same no climate change comparative, the Paris target too result in negative GDP impact, but less much so (–4.2%). We also consider a severe scenario in which temperatures rise by 3.2°C by mid-century, with society doing nothing to combat climate change. In this scenario, the global economy would be 18% smaller than in a world without warming, reinforcing the imperative of, if anything, more action on climate change.

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Economies in south and southeast Asia are the most vulnerable to climate change effects; advanced economies in the northern hemisphere least so.

In terms of exposure to severe weather risks resulting from climate change, south east Asia and Latin America will likely be most susceptible to dry conditions. Many countries in north and eastern Europe, meanwhile, are set to see more excess precipitation and flood events. Combining these observations with our GDP-impact analysis, our Climate Economics Index indicates that many advanced economies in the northern hemisphere are least vulnerable to the overall effects of climate change, being both less exposed to the associated risks and better resourced to cope. The US, Canada and Germany are among the top 10 least vulnerable. Of the major economies, China ranks lower, in part due to lesser adaptive capacity in place today relative to peers. However, with rising investment in green energy and increasing awareness of climate risks, we believe China is on course for rapid catch-up here.

Climate change also poses transition risks: Asia may be most impacted.

In addition to physical, climate change also gives rise to transition risks. These can show in large shifts in asset values and higher cost of doing business as the world moves to a low-carbon economy. As a separate exercise, we use carbon-tax scenario analysis as a proxy to gauge the associated financial and economic impacts. We find that earnings in the utilities, materials and energy sectors would be the most impacted and lose between 40–80% of earnings per share by immediate imposition of a global carbon tax of USD 100 per metric ton. By region, revenue-weighted earnings would fall by about a fifth in Asia Pacific, and by 15% in the Americas and Europe. The scale of loss depends on the speed at which carbon taxes and mitigation actions are implemented, and the pace of technological adoption.

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More than what is being pledged today is needed to achieve the Paris agreement. International convergence on data, standards, metrics and disclosure of roadmaps towards “net zero” are key

Climate risk is a systemic risk, one that can be managed with coordinated global policy action. There exists a unique opportunity to green our economies. The public and private sectors, including insurers as providers of risk transfer capacity, risk knowledge and long-term investment, can facilitate transition to a low-carbon economy. Increasing transparency, data and disclosure to price and transfer risks is needed. To this end we should see more policy action on carbon pricing coupled with incentivising nature based and carbon-offsetting solutions. International convergence on the taxonomy on counts for green and sustainable investments is also needed. As part of corporate reporting, institutions should also disclose their roadmaps on how they intend to reach the Paris and 2050 net-zero targets.

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Key Takeaways

Global temperature rises will negatively impact GDP in all regions by mid-century. The current trajectory of temperature increases, assuming action with respect to climate change mitigation pledges, points to global warming of 2.0–2.6°C by midcentury. The loss in global economic value in this scenario could be up to 10% higher than if the Paris Agreement of much less than 2°C rise in temperatures is reached. Economies in southeast Asia (ASEAN) countries would be hardest hit. In a severe scenario of a 3.2°C-rise in temperatures, the global GDP loss could be as much as 14% higher than that under the Paris targets

Achieving the Paris Agreement temperature target is the most-desirable outcome. Compared to 2.6°C warming, if the Paris Agreement target of well below 2°C warming is met, up to 10% of anticipated mid-century global GDP loss could be prevented. As the figure below shows, in more exposed regions, the benefit in terms of mitigated or prevented GDP-loss by mid century if the Paris Agreement target is met as opposed to a 2.6°C rise in temperatures, could be as much as 25%. Many emerging markets would benefit most, with Indonesia, Thailand and Saudi Arabia among the biggest relative winners.

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Top- and bottom-five Climate Economics Index rankings. Economies in south and southeast Asia are particularly vulnerable to adverse effects of climate change, and advanced economies in the northern hemisphere least so. In simple ranking terms, our index considers the GDP impact of the physical risks emanating from gradual climate change over time, and vulnerability to extreme weather risks (wet and dry conditions). The index also factors in countries’ existing levels of adaptive capacity.

Transition risk. Imposition of a global carbon tax of USD 100 per metric ton would impact the energy, materials and utilities sectors most. By region, revenue-weighted earnings would fall by a fifth in Asia Pacific, and by 15% in the Americas and Europe.

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A New Energy Unification Emerges

“Dreaming bigger and reaching higher,” the New Energies have come together to lead a transition for “the United States of clean power.” From American Clean Power Association via YouTube

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Can’t Deny This Climate Crisis

All anybody needs to know is what they see in the headlines. From Today via YouTube

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The Urgent Need For New Wires

It is time for a transmission planning process that supports the energy transition, not one that resists it.From Grid Strategies via YouTube

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Better Ways To Talk About The Climate

Tailoring climate change messaging for conservatives could shift understanding of crisis: Study; Researchers studied how to make climate change communication more persuasive.

Julia Jacobo, June 14, 2021 (ABC News)

“…Tailoring online messaging and advertising toward Republican voters could shift their views on climate change…[Research shows that in 2020,] 73% of Americans believed that global warming was happening, and 62% think that it was caused by human activities…[up from 2010’s] 57%...But, the shift in public opinion on climate change has largely been driven by Democrats…just 22% of Republicans said it should be a ‘high’ or ‘very high’ priority, compared to 83% of Democrats…

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…[A]ltering the messages to appeal to conservative ideals can increase Republicans' opinions of climate change…[according to a] one-month advertising campaign field experiment that tailored climate change-themed online messaging for conservative voters in two competitive districts -- Missouri-02 and Georgia-07…The campaign presented a series of videos called ‘New Climate Voices,’ which used social identity theory, elite cues and theories of persuasion presented by spokespersons who were likely to resonate with conservatives… [The videos increased by several percentage points] understanding among Republicans in the two districts on two topics: that global warming is happening and that it's being ‘caused mostly by human activities.’

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…The belief that climate change is ‘somewhat,’ ‘very’ or ‘extremely’ personally important and that it would cause ‘moderated’ to a ‘great deal’ of harm to future generations also increased…The tricky part is getting the messaging through in a competitive environment where people are fielding messages across multiple platforms…[and] it is unclear how much results might vary depending on geographic location or cultural context…” click here for more

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The World’s Huge New Energy Need

The Future Of Wind Power Depends On Deployment

Felicia Jackson, June 15, 2021 (Forbes)

“Fossil fuel’s share in the energy mix is as high today as ten years ago, despite the falling costs of renewables. [With less than a decade to embed low carbon transition in the energy markets, politicians and policy makers must] stop talking and start acting…The coming decade is critical, as infrastructure built over the next few years will lock in path dependency for years to come…[The world needs to be installing wind power at around 3-4 times the level of 2020, which saw a record 93GW installed. In these scenarios, wind and solar PV make up 70% of electricity generation by 2050…

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Despite a growing acceptance that the world is facing a climate emergency, and increasing country and corporate commitments to net zero, fossil fossils have continued to dominate growing energy demand…[T]he share of fossil fuels in the global energy mix was 80.2% in 2019, compared to 80.3% in 2009, while renewables such as wind and solar made up 11.2% of the energy mix in 2019, up from 8.7% in 2009…It is increasingly clear that commitments alone are not enough.

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…Many existing planning frameworks, subsidy regimes and market designs are woefully out of date…The scale of renewable energy deployment is no longer about cost…The economic argument has been won, and there is no lack of appetite from investors…What is necessary is a change in culture around planning, permitting, priority access to the grid and subsidy regimes. One question as to whether or not the industry can scale up at such a rapid pace…[T]here are certain barriers to entry, for example the cost of infrastructure can be high…[But the] opportunities are as high as the potential investment…” click here for more

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ORIGINAL REPORTING: Arizona Climate Deniers Using The Law

Arizona showdown: Lawmakers face regulators in fight over zero-emissions mandate; Conservatives say regulator's proposed zero-carbon mandate oversteps its constitutional authority while defenders say the legal debate is an excuse to impede the state's climate fight.

Herman K. Trabish, Feb. 10, 2021 (Utility Dive)

Editor’s note: After this story ran, the legislature took control away from the commission and essentially stopped the zero-emissions initiative.

Controversial proposed Arizona legislation would impose limits on the authority of the state's elected utility regulators and make their recent groundbreaking zero-emissions mandate unconstitutional.

Senate Bill 1175 expresses longstanding concerns from some lawmakers regarding overreach by the elected Arizona Corporation Commission (ACC), stakeholders agreed. But those concerns were aggravated by the ACC's November approval of draft energy rules that included a zero emissions by 2050 mandate for electric utilities in the state, seen by some as an attempt to reverse the 2018 defeat of Proposition 127 and its 50% renewables by 2030 mandate.

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Legislators are following Republican Gov. Doug Ducey's lead in attempting to amend Arizona law and prevent ACC from using its constitutional power to set "critical energy generation" policy. "I want to see the corporation commission setting rates and the legislature setting energy policy and I hope that will be straightened out in this session," Ducey told the Arizona Chamber of Commerce Jan. 15.

The ACC voted 4-1 Nov. 13 to approve its draft rules. Three Republicans and one Democrats voted in favor, with only Republican Commissioner Justin Olson voting against. But the debate over SB 1175 has turned highly partisan, and opponents believe its inception was driven largely by that November vote.

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The legislation "seems to be about the clean energy rules and not the constitutional issue because it is suspiciously retroactive to June 30, just before ACC staff filed the rules in July," said Democratic Sen. Kirsten Engel, who is leading opposition to the legislation. "And I have not been impressed by Republican bill supporters' constitutional arguments, which seem really about opposition to the clean energy rules."

The 2050 mandate can grow Arizona's economy and jobs, many in the business community say, but advocates for SB 1175 say the rules could raise electricity rates. The bill debate, however, centers on interpretations of constitutional law, and the final word may come from Arizona's Supreme Court after a long legal battle, both sides acknowledged… click here for more

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New Energy Going Up, NatGas Use, Emissions Going Down

Short-Term Energy Outlook

June 8, 2021 (U.S. Energy Information Administration)

…We forecast that retail sales of electricity in the United States will increase by 2.3% in 2021 after falling by 3.9% in 2020. The largest increase in consumption will occur in the residential sector, where [due primarily to 1Q cold temperatures] we forecast retail sales of electricity will grow by 2.8% this year…[The forecast increase in electricity consumption in the commercial and industrial sectors reflects improving economic conditions in 2021…We expect the share of electric power generation produced by natural gas in the United States will [due to an average $4.09/MMBtu in 2021 compared with an average of $2.39/MMBtu in 2020price] average 36% in 2021 and 35% in 2022, down from 39% in 2020…

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…[The renewables share of U.S. generation [is forecast to] rise from 20% in 2020 to 21% in 2021 and to 23% in 2022…[T]he U.S. electric power sector added 14.8 gigawatts (GW) of new wind capacity in 2020. We expect 16.0 GW of new wind capacity will come online in 2021 and 5.3 GW in 2022. Utility-scale solar capacity rose by an estimated 10.5 GW in 2020. Our forecast for added utility-scale solar capacity is 15.5 GW 2021 and 16.6 GW for 2022…[plus] 4 GW to 5 GW of small-scale solar capacity…

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We estimate that U.S. energy-related carbon dioxide (CO2) emissions decreased by 11% in 2020 as a result of less energy consumption related to reduced economic activity and responses to COVID-19. In 2021, we forecast energy-related CO2 emissions will increase about 6% from the 2020 level as economic activity increases and leads to rising energy use…” click here for more

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Monday Study – Keeping The Lights On In Texas

Never Again: How To Prevent Another Major Texas Electricity Failure

Pat Wood III (PUCT Chairman 1995-2001, FERC Chairman 2001-2005), Robert W. Gee (PUCT Chairman/Commissioner, 1991-1997), Judy Walsh (PUCT Commissioner 1995-2001), Brett Perlman (PUCT Commissioner 1999-2003), Becky Klein (PUCT Commissioner/Chairman 2001-2004), Alison Silverstein (PUCT advisor 1995-2001, FERC advisor 2001-2004), June 3, 2021 (The Cynthia and George Mitchell Foundation)

The historic weather system that hit the South Central United States in February 2021 led to the deaths of nearly 200 Texans[1] and caused over $100 billion in damages to Texans’ homes and property.[2] Its impacts on power, natural gas, water, and transportation infrastructure were profound, leading the power grid operator, Electric Reliability Council of Texas (ERCOT), to order all local utilities to immediately decrease power demand early on February 15. This grid reliability order led to cuts in electric service to over four million premises, leaving millions of Texans out of power and in miserable conditions for up to four days.

The Texas Legislature has sent to Governor Abbott new statutes to address some of the problems that contributed to this disaster. But beyond these new laws, Texas has more work ahead to protect customers and ensure that our energy infrastructure works adequately. The February outages were triggered by an extreme weather event but were exacerbated by underlying problems that affected the entire energy system from the production of natural gas to the delivery of electricity to the customer.

These problems extend beyond the Electric Reliability Council of Texas (ERCOT) and the Public Utility Commission of Texas (PUCT) to include parts of the energy system regulated by the Texas Railroad Commission, the Texas Reliability Entity, and the North American Electric Reliability Corporation, all of which bear some responsibility for the reliability of our energy system. If Texas is to mitigate future energy system disasters and restore our state’s reputation, we must do more than just tighten governance on ERCOT and the PUCT, weatherize power plants, patch the electric market, and reform some utility and retail practices.

As past PUCT Commissioners, the authors helped to design and implement many elements of ERCOT’s electric system and market structure between 1995 and 2004. The mission of the PUCT is to protect customers, foster competition, and promote high-quality infrastructure. Until this February, the Texas electricity system had largely achieved that goal. We created a strong, competitive, reliable electricity system whose overall performance for more than 20 years lowered electric bills for all customer classes, created innovative options for electricity customers, attracted an unprecedented level of new natural gas and renewable generation, and kept the lights on as our state population grew by 40%.

While the February 2021 event was clearly unprecedented, prior outages should have provided a wake-up call to policymakers and regulators to address reliability issues. The events of February 2021 resulted from several policy failures as well as from operational and planning failures across our state’s electric, natural gas and water systems. We must address the causes of this winter’s weather challenge and prepare to deal with emerging economic, technology and extreme weather realities.

Texas is the world’s ninth-largest economy. We owe it to our families and fellow citizens to learn from this event, plan for the future, and do the right thing for the good of Texas. We offer the following observations and 20 recommendations, which are organized based on the outage’s contributing factors. Some of these require further legislative action; others can and should be implemented by the PUCT under existing authorities.

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Problem 1¬—Almost half of ERCOT’s gas, coal and nuclear plants failed to produce when needed

ERCOT’s publicly released data[3] and other analyses indicate that almost 9 GW (8%) of ERCOT’s generation fleet was already out for maintenance on February 14 and another 22 GW (21%) of ERCOT’s total generation fleet failed before 1am on February 15, when ERCOT was forced to initiate customer load-shedding. Natural gas generators represented the greatest loss of production (26 GW, including units out for maintenance). Most of those plants failed due to insufficient preparation for the intense winter storm and/or because fuel became unavailable (whether on-site, like coal plants, or due to lack of natural gas availability or delivery capability). Forty-six percent of ERCOT’s total thermal generation capacity was unavailable or failed during the outage.[4] SB3, the new reliability statute, requires the PUCT to adopt power plant winterization standards, informed by adverse weather forecasts, with compliance requirements and penalties for non-performance. This is a good start, particularly given that a recent analysis from the Federal Reserve Bank of Dallas suggests that the weatherization of Texas gas and wind power plants would be cost-effective.[5] The PUCT and ERCOT will have to ensure that these standards are appropriately rigorous and receive adequate enforcement.

SB3 directs the PUCT to examine ancillary services and incentives for dispatchable generation such as natural gas plants, and modify the design, procurement, and cost allocation of ancillary services to assure that appropriate services are available for weather emergencies. ERCOT and the PUCT are also directed to look at whether dual-fuel capability, fuel storage and different fuel procurement supply policies are appropriate solutions for extreme weather performance. The statute even calls for operation under drought conditions. These measures are a good start to assure that gas-fired power plants retain reliable fuel access.

Recommendation 1-1—Mandatory weatherization to minimum standards for natural gas production and pipelines, with meaningful enforcement…

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Problem 2—Electric demand skyrocketed 20% over forecast

In February, Texas and its neighboring states experienced a multi-day run of Arctic temperatures and winds that drove ERCOT electricity demand for heating to unprecedented levels. As much as 35 GW (over 40%) of the total Texas electric demand was for heating. Much of Texas’ housing stock has little or no insulation and relies only on electric resistance heaters rather than gas heat, but at such low temperatures, uninsulated homes cannot be heated effectively. This drove ERCOT’s winter electricity demand to unprecedented levels; had ERCOT not called rolling outages early in the morning on February 15th, we were on the way to an all-time system peak later that day. Between leaky buildings, lack of electricity and poor public communications, over 100 Texans died of hypothermia or carbon monoxide poisoning during the February blackout.

Texas must fix this by improving the energy efficiency of our buildings. Over half of Texas homes were built before the state adopted building energy codes with insulation requirements in 2001. And over 60% of Texas homes are heated with electricity rather than gas. If these homes had energy-efficient building shells and heaters before February 14, that could have reduced electricity demand by at least 15 GW—enough to drop peak demand down to 62 GW and offset the loss of most of the generators that failed on February 14 and 15. Estimates developed for the U.S. Department of Energy indicate that Texas could use cost-effective energy efficiency measures to reduce 2030 residential electricity use by 18.5% and total electricity sales by 17%.[6]

Recommendation 2-1—Update Texas building energy codes and require them to be automatically updated as international building codes are updated…Recommendation 2-2—Raise TDU energy efficiency program goals to increase both annual kWh savings and peak reduction…Recommendation 2-3—Increase energy efficiency retrofits for low-income and multi-family housing across Texas…Recommendation 2-4—Increase demand response for grid emergencies…

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Problem 3—Distribution utilities didn’t rotate outages, leaving two-thirds of Texans without electricity for up to 70 hours

SB3 requires the PUCT and utilities to update criteria and recognition of critical residential customers and critical facilities. It also requires the utilities to conduct annual load-shed exercises. These are valuable first steps. But if Texas identifies more critical customers yet cannot manage distribution outages more effectively, this measure may not help us better manage future outages.

Texas’ electric utilities had to cut service to millions of customers because the critical facilities (those they knew of) are located on large circuits serving large numbers of customers and high electric loads on every circuit. Once those circuits were protected, there was no electricity left to serve the remaining circuits that don’t serve critical facilities, so all the remaining circuits were cut. Although utilities aim to rotate small-scale outages across many circuits, in February there were so many circuits out relative to the available generation that there was no way for the utilities to rotate the outage burden among circuits and customers. Thus, many customers on circuits without critical facilities stayed out of power for several days in a row. The lack of outage rotation in February was the most customer-impacting part of this disaster—many homes reached freezing temperatures during multi-day outages, causing many deaths from hypothermia and carbon monoxide poisoning, and millions of frozen pipes and damaged property and possessions.

This outage management process must be overhauled. It is easier to manage outages and rotate outages fairly if circuits containing critical facilities are smaller and require less power, and if non-critical circuits are smaller so that outage burdens can be shared. Dividing the grid into smaller operational segments will enable the utilities to conduct smaller, more granular and targeted outages affecting fewer customers.

Texas customers have funded major utility investments in smart meters and other smart grid infrastructure. But the utilities have not yet leveraged these investments for better outage management. Extreme weather conditions are a perfect opportunity to deliver that functionality. Until it is clear that meter functionality and control capability can be used dependably for surgical outage management, other solutions are needed…

Recommendation 3-1—Require TDUs to modify distribution circuits for more granular outage management…Recommendation 3-2—Require large industrial and commercial customers to be able to reduce load remotely…Recommendation 3-3—Require all critical facilities to have two days’ worth of backup power

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Problem 4—Poor demand and supply forecasting and planning by ERCOT…Recommendation 4-1—ERCOT should improve demand forecasting capabilities…Recommendation 4-2—ERCOT should broaden its use of scenario analysis with more aggressive worst-case outcomes…Recommendation 4-3—Acknowledge changing extreme weather threats…

Problem 5—Power market operation was ineffective…Recommendation 5-1—Evaluate whether ERCOT needs different winter versus summer planning, operations and protocols…Recommendation 5-2—Reassess requirements and compensation for black-start capacity and test and drill twice/year…Recommendation 5-3—Do not add an out-of-market “generation capacity reserve” scheme…

Problem 6—Inadequate or inappropriate governance…Recommendation 6-1—Strengthen Texas’ Public Utility Commission…Recommendation 6-2—Give ERCOT an independent, expert Board of Directors…Recommendation 6-3—Establish active reliability compliance oversight…Recommendation 6-4—Study the potential benefits and costs of adding additional high-voltage transmission between ERCOT and its neighboring interconnections…

Problem 7—We don’t have full information on the contributing causes of the blackout and the sequence of events and actions by ERCOT, power plants, fuel suppliers, regulators, and customers before and during the event…Recommendation 7-1—Release all Texas investigative findings to the public…Recommendation 7-2—Routinely collect data on all grid and fuel supply failures and make it public…

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Conclusions

SB3 and other new statutes adopted by the Texas Legislature have provided a swift and focused response to the February disaster, but there is more work to be done to address all of the causes of the February 2021 Arctic outage and prepare for the challenges ahead.

This paper offers a broad set of recommendations; with multiple investigations under way, we hope to learn more to refine these and other solutions in the future. Although the Legislature has taken initial action, many of the recommendations above can be implemented by the PUCT, RRC and ERCOT under existing statutory authorities, as indicated in the table below.

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The Water-Wanting West

Lake Mead is at 37% of it’s capacity. “It’s an existential issue…” From CBS This Morning via YouTube

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Never Mind Water In The Idiocracy Future

This is what it has been like talking to climate change deniers for the last decade. From Dan Nguyen via YouTube

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