NewEnergyNews

NewEnergyNews

Gleanings from the web and the world, condensed for convenience, illustrated for enlightenment, arranged for impact...

The challenge now: To make every day Earth Day.

While the OFFICE of President remains in highest regard at NewEnergyNews, the administration's position on the climate crisis makes it impossible to regard THIS president with respect. Therefore, until November 2020, the NewEnergyNews theme song:

YESTERDAY

  • MONDAY STUDY: How Electric Cooperatives Can Move To New Energy
  • THE DAY BEFORE

  • Weekend Video: More On How Michael Moore Got New Energy All Wrong
  • Weekend Video: New Energy Is Good For What Ails The World
  • Weekend Video: Will The Florida Keys Sink?
  • THE DAY BEFORE THE DAY BEFORE

  • FRIDAY WORLD HEADLINE-A Global Recovery Script, Starring New Energy
  • FRIDAY WORLD HEADLINE-Global New Energy To Hesitate, Then Bounce Back
  • THE DAY BEFORE THAT

    THINGS-TO-THINK-ABOUT WEDNESDAY,:

  • TTTA Wednesday-ORIGINAL REPORTING: Solar’s Changing Market And Policy Landscape
  • TTTA Wednesday-The Green Hydrogen Solution
  • THE LAST DAY UP HERE

    MONDAY’S STUDY AT NewEnergyNews, May 25:

  • Bringing New Energy To Heating; A Case Study
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    Founding Editor Herman K. Trabish

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    Some details about NewEnergyNews and the man behind the curtain: Herman K. Trabish, Agua Dulce, CA., Doctor with my hands, Writer with my head, Student of New Energy and Human Experience with my heart

    email: herman@NewEnergyNews.net

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

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

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  • THINGS-TO-THINK-ABOUT WEDNESDAY, June 3:
  • ORIGINAL REPORTING: How To Get The Investments Needed For A New Grid
  • New Energy Beating Coal, Nuclear In 2020

    Wednesday, June 03, 2020

    ORIGINAL REPORTING: How To Get The Investments Needed For A New Grid

    Making the case for billion-dollar investments in grid modernization by answering 3 key questions; A “Why-What-How" framework can help guide regulators, and get stakeholder buy-in for big spending

    Herman K. Trabish | Jan. 6, 2020 (Utility Dive)

    Editor’s note: Trsnsforming today’s century-old grid into one capable of handling 21st century capabilities is vital to New Energy’s future.

    Some of the biggest investor-owned utilities in the country have in recent years had signficant grid modernization proposals rejected by regulators. But utilities may be able to avoid such rejection by answering three basic, but critical questions…Regulators for Dominion Virginia, Duke Carolinas and others have spurned billion-dollar grid modernization proposals that would prepare the power system for 21st century renewable and distributed technologies because the expenditures were inadequately justified. Utilities can avoid that fate by adopting a "Why-What-How" framework that can keep them from being "mired in details" and "chasing shiny objects," according to a November paper from Boston Consulting Group (BCG).

    With the framework, utilities first "set a vision and objectives by asking, ‘Why are we modernizing our grid?’" BCG recommended. "This naturally leads to the next question: ‘What are the solutions that will help us achieve our vision and objectives?’ After the what is defined, utilities are ready to address the how."

    Nearly every state is exploring policies pertaining to new technologies foundational to the emerging customer-centric, low carbon power system. Few stakeholders debate the need for investing in the grid, but the critical question is which expenditures to prioritize, and BCG’s framework may help them answer the question, state regulators and grid modernization proceeding participants told Utility Dive.

    Modernization of the distribution system is largely done through deployment of distributed energy resources (DER) and technologies that monitor and control them, like advanced metering infrastructure (AMI). The need for modernization is being driven by customer demand for DER to lower their electricity bills and the opportunities utilities see in DER to flatten peak demand and protect reliability, according to both NCCETC and BCG.

    Data show they are right. AMI installations were at almost 87 million and growing at the end of 2018, according to the Energy Information Administration. Today’s two million distributed solar installations are expected to double by 2023, Wood Mackenzie (WoodMac) and the Solar Energy Industries Association reported in mid-2019. And U.S. energy storage annual capacity additions are projected to grow twelve times by 2024, WoodMac and the Energy Storage Association reported in December.

    DER could meet an estimated 20% of peak load by 2030, according to a June 2019 Brattle Group study. With a modernized grid's situational awareness and controls, that flexible load could deliver over $15 billion per year in avoided system costs, Brattle estimated. In Q3 2019, there were 383 regulatory and legislative actions in 45 states and the District of Columbia on to plan and fund grid modernization, according to NCCETC Grid modernization actions jumped from 288 in 2017 to 480 in 2018, and with Q3 2019’s 39% increase from Q3 2018, there was likely another substantial year-over-year increase… click here for more

    New Energy Beating Coal, Nuclear In 2020

    U.S. Renewables Produce 17.5% More Electricity Than Coal During First Quarter Of 2020 As Solar Grows 23% And Wind 17%; Renewables Also Outpace Nuclear Power In Both February And March And Provide 21% Of Nation’s Electricity

    Ken Bossong, May 27, 2020 (Sun Day)

    “Renewable energy sources (i.e., biomass, geothermal, hydropower, solar, wind) produced significantly more electricity than coal during the first quarter of 2020 and also topped nuclear power in both February and March…[Data through March 31, 2020] reveals that solar and wind both showed continued, strong growth, expanding faster than all other energy sources. During the first three months of this year, solar-generated electricity expanded by 22.5% (compared to the same period in 2019) and provided almost 2.6% of the nation’s total while wind grew by 17.4% and accounted for 9.0% of total generation…

    …[Together, wind and solar] provided more than 11.5% of total U.S. electrical production during the first three months of 2020. Combined with hydropower, biomass, and geothermal, renewables provided 20.8% of total electrical output…[That was 17.5% more than coal during the first quarter of 2020, which] was 33.8% lower than a year earlier and accounted for just 17.7% of the nation’s total; by comparison, coal’s share was 25.9% in the first quarter of 2019…[New Energy also produced 3.6% more electricity than nuclear in February and 6.0% more] in March…[March 2020 also suggested New Energy’s response to Covid is strong. Growth] in solar-generated electricity slowed a bit but still was 10.1% higher than March 2019 while wind’s output was 12.9% more than a year earlier and that of non-hydro renewables overall was up 10.0%. By comparison, coal plummeted by 35.6% and nuclear dropped by 1.7%...” click here for more

    Monday, June 01, 2020

    MONDAY STUDY:How Electric Cooperatives Can Move To New Energy

    Transition to Clean Energy for Cooperative Utilities; Tri-State’s Responsible Energy Plan

    May 2020 (Rocky Mountain Institute)

    Between 2018 and 2020, one of the largest power suppliers in the West planned for and unveiled a new pathway toward a renewably powered future. When Tri-State Generation & Transmission Association embarked on this process over two years ago, the co-op faced criticism from external stakeholders as well as its member distribution co-ops for its continued reliance on legacy fossil-fueled generation. By the start of 2020, Tri-State had a plan in place for retiring coal assets, slashing emissions, and adding over 1 GW of new renewables to its portfolio. The case study that follows, independently authored by Rocky Mountain Institute (RMI) and supported by interviews with Tri-State staff, provides perspective into that shift.

    Responsible Energy Plan Origins and Process

    Spanning 250,000 square miles and four western states, Tri-State Generation & Transmission Association (TSGT) provides power and transmission services to 43 distribution co-op members that serve over 1 million end-use customers. Tri-State territory is diverse, encompassing different load profiles, member priorities, and policy contexts in rural communities across Colorado, New Mexico, Wyoming, and Nebraska. Established in 1952 to harness economies of scale that might otherwise elude small, rural electric cooperatives, Tri-State owns over 5,500 miles of transmission and 3,000 MW of generation assets.1

    Historically, that power was mostly coal-fired, derived from a fleet of five coal-burning power plants constructed between 1959 and 2006.2 Today, bilateral and market purchases as well as changing economics are steering Tri-State toward a more diversified mix of fossil and renewable resources, and its recently released Responsible Energy Plan (REP) accelerates that trend.

    Released in January 2020, the Responsible Energy Plan (REP) includes specific actions to retire coal capacity and increase clean energy generation. Specifically, the REP calls for the retirement of the 253 MW Escalante Station in New Mexico by the end of 2020 and all three units of the 1,285 MW Craig Station in Colorado by 2030. On the renewables side, TriState plans to bring more than 1,000 MW of new wind and solar online by 2024, with eight projects in the works across Colorado and New Mexico.

    As a result of this generation shift, Tri-State expects to reduce emissions from its Colorado wholesale electric sales 70 percent by 2030, in line with state carbon regulations. The plan is also likely to have a substantial positive impact on regional economic development, including job creation and local investment dollars: numerous economic development studies have concluded that wind and solar development create significant direct, indirect, and induced jobs in host communities and beyond (UC-Berkeley, NREL, DOE, etc.). For comparison, Xcel Energy’s Colorado Energy Plan, which includes roughly 1,800 MW of new renewable energy, is projected to result in nearly 2,000 jobs and $2.5 billion in local investments.

    In developing the REP, Tri-State leaders recognized they had to go beyond announcing an aspirational goal; in order to maintain trust and good standing with their member co-ops and lenders, Tri-State felt it needed concrete targets as well as a clear plan for dealing with the debt that remains tied up in existing generation assets.3 To arrive at the specific planned retirements and new generation additions, Tri-State spent months conducting forecasts, weighing options for stranded asset management, and meeting with its board, which consists of representatives from each distribution co-op member—some of whom were supportive from the start of the process, and others who took more convincing. Ultimately, they arrived at a plan that was widely supported by the board and “ambitious but achievable,” according to Tri-State.

    Tri-State’s transition is driven by economics, policy, changing member priorities, and co-op leadership. Renewable power prices have dropped significantly in recent years, as Tri-State recognized in its recent requests for proposals (RFPs) for wind and solar projects: while a 2018 renewables RFP returned competitive prices, by January 2019, a new RFP returned bids that were “spectacular,” and substantially lower than they had been just the previous year.4 Those numbers helped convince reluctant board members of the REP’s feasibility.

    At the same time, new administrations and policy shifts in Colorado and New Mexico introduced ambitious carbon reduction targets in those two states, which Tri-State would have to accommodate in its future generation planning. Additionally, several distribution co-ops in Tri-State’s system have set renewable energy targets of their own, reflecting member demands for a cleaner and more localized energy supply. In the midst of these external drivers of change, Duane Highley stepped in as the new CEO of Tri-State in 2019, the goal of transforming Tri-State into a model 21st-century generation and transmission utility cooperative (G&T).

    The Responsible Energy Plan’s development predated Highley’s arrival, but the new CEO added momentum and external engagement to the effort. Under Highley, Tri-State convened a multi-stakeholder advisory group facilitated by Colorado State University’s Center for a New Energy Economy (CNEE) and former Colorado Governor Bill Ritter. Participants hailed from all four states in Tri-State’s territory and represented academic, agricultural, electric industry, environmental, and local government perspectives.5 The collaborative dialogue helped Tri-State develop the credibility and buy-in the G&T will need to fulfill its REP commitments.

    “The board set a goal for our cooperative to comply with all applicable environmental and renewable energy requirements while striving to reduce members’ rates, preserve electricity reliability and affordability, and maintain financial strength,” said Tri-State CEO Duane Highley of the motivation for the REP. “With this clear direction, staff worked with members and stakeholders to develop a plan that we believe will achieve that goal.”

    Plan Implementation: Transitioning the Generation Mix

    Realizing the goals of the Responsible Energy Plan will dramatically transform Tri-State’s generation mix and the spread of renewable resources across its territory. By 2024, the G&T will double its renewable electricity generation and set itself on a path toward 100 percent clean energy in Colorado by 2040. TriState also has plans to increase the flexibility of the “all-requirements” contracts that govern the power it supplies to distribution co-op members.

    While historically these contracts required distribution co-ops to procure all but 5 percent of their power from the G&T, the rise of distributed energy resources (DERs) has made many of Tri-State’s member coops eager to generate more of their energy locally. Depending on the specific implementation of new rules, allowing distribution co-ops to develop or procure more distribution-scale renewables and storage could pave the way for an increase in DER deployment in Tri-State territory.

    At the same time, the shift away from coal will have ramifications for the communities where the plants are sited, and Tri-State is thinking hard about how to lessen the impacts to workers and the local economy. As SVP of policy and compliance Barbara Walz put it, “co-ops are a family.” Tri-State is committed to engaging with the communities near the retiring Craig and Escalante plants, as well as state government, to provide economic assistance, retraining, and new opportunities in those areas.7 The recent energy legislation passed in Colorado and New Mexico each provide for some form of transition support for communities impacted by fossil fuel retirements and Tri-State is working with state leaders to ensure that support is channeled to Craig and Escalante workers and community members.

    Retiring the two coal plants before the end of their useful life also raises financial considerations. The plants’ outstanding debt remains to be repaid; at the same time, one of the goals of the REP is to maintain or lower member rates. Tri-State recognizes that reduced rates are one way of supporting economic development in its territory, particularly the areas impacted by plant closures. The Tri-State board is currently reviewing its options for mitigating the financial burden of early retirement, but in all cases, the low and still-falling cost of renewables can help offset the cost burden associated with the coal retirements.

    Additional challenges line the path toward a high renewables generation mix for Tri-State. Chief among those is the lack of a full-fledged organized wholesale electricity market, or Regional Transmission Organization (RTO), in the western United States. According to dialogue with co-op staff, Tri-State views RTO participation as a vehicle for securing low-cost energy—via competitive wholesale markets—and reliability, stemming from greater connectivity with other utilities. While Tri-State is a part of the SPP Energy Imbalance Service, which provides some market benefits, the G&T’s leaders see that as just a first step toward realizing the full cost savings and other benefits of joining an RTO. Tri-State will continue to review all options as the current energy imbalance markets in the West evolve.8

    Transmission development looms as another potential stumbling block. New renewable energy projects often require transmission upgrades or new lines to carry the power from rural areas to load centers. Tri-State estimates that building new transmission is currently an 8–12-year process, fraught with siting and permitting issues, local opposition, and significant expense. What’s more, as an increasing number of new renewables projects come online, the siting and permitting issues associated with renewable energy development could also increase.

    G&T leaders have flagged funding and policy fixes, such as extending renewable energy tax credits to associated transmission projects, as potential solutions for improving the process. With this and other challenges, Tri-State noted that state and federal policy support would enable more efficient and costeffective implementation of their REP.

    All that said, Tri-State has widespread buy-in for the REP among board members, as well as the external stakeholders engaged through the advisory group. The G&T now has years of experience issuing RFPs and procuring wind and solar capacity and appears poised to build out a network of renewable power purchase agreements (PPAs) at ever-lower prices. The REP is on solid footing for delivering a higher renewables portfolio at comparable or lower rates for members, with strong upside potential given promising favorable developments in policy support, RTO development, or transmission siting.

    Lessons Learned and Takeaways for Other Utilities

    Tri-State’s energy generation and transmission services are at a crossroads, and the G&T has recently selected a path forward—the low-carbon path. TriState leadership knows that many will be watching as it continues down that path, some with a skeptical eye and some with an eye toward emulation. Tri-State member co-ops, through the board and through ongoing negotiations with the G&T, will also be closely monitoring and shaping the plan’s implementation. “The cooperative family is watching Tri-State and what we are doing to reduce emissions, add renewables, and provide more contract flexibility for our members,” observed Highley. “While no two G&Ts are alike and each have different circumstances, Tri-State is in a position to show that such a transition can be accomplished while maintaining reliability and affordability.”

    Takeaway #1: A robust stakeholder engagement process builds credibility and support.

    While the reaction to the Responsible Energy Plan has been very positive to date, Tri-State acknowledges that some are withholding judgement until they see the G&T walk the talk.

    “Cooperatives across the country have a reputation for being supporters of coal,” Walz noted. “So, when we were setting out to develop the REP, we knew we were going to have a trust factor to overcome. That’s one of the reasons we decided to convene the advisory group with CNEE: that dialogue engaged all four states, co-ops, environmental groups, counties, agricultural groups, etc. That open discussion with stakeholders was an important part of the process.”10

    Tri-State sees the CNEE advisory group as critical for building buy-in and helping the G&T overcome potential credibility issues around plan implementation. Despite the difficulty of convening and working with stakeholders who might have been critical of Tri-State in the past, the G&T ultimately found that process to be worthwhile. Tri-State Senior Manager for External Affairs Bob Frankmore said he would recommend the advisory group approach to other co-ops thinking about a similar shift in direction.

    Takeaway #2: A specific plan makes for a better roadmap than an aspirational target.

    In developing the REP, Tri-State decided early on that it didn’t want to simply release an aspirational goal for a certain level of emissions reductions or clean energy generation. Mindful that releasing a target without concrete actions for achieving it might concern member co-ops and lenders, Tri-State developed the REP to be more of a roadmap than just a final destination. The clear action items around coal retirements and renewable PPAs give Tri-State and external observers a transparent benchmark against which to measure the G&T’s progress down the path it has set for itself, and leadership is continuing to finetune the details underpinning each action. Additionally, flagging obstacles to successful implementation helps Tri-State and relevant policymakers—as well as other stakeholders—maintain awareness of the challenges that must be overcome as the plan progresses. Such transparency supports energy transition efforts writ large, as the shift toward a decarbonized electricity system entails systemic change that no single electricity provider can tackle on its own.

    The more the co-op community sets its sights on a high-renewable, low-carbon future, the better it can fulfill the co-op principle of “cooperation among cooperatives,” with cooperatives mutually assisting each other in realizing their goals. Tri-State anticipates other co-ops following its example, and indeed, hard on the heels of its January announcement, two other G&Ts—Hoosier Energy in Indiana and Dairyland Power, headquartered in Wisconsin—announced coal retirements and renewable transitions of their own.

    Tri-State’s story is the latest example of co-ops participating in the clean energy transition, but it is far from an outlier. Distribution co-ops and G&Ts across the country have set goals or are contemplating similar plans, and Tri-State’s experience demonstrates that the sooner it commits to a path, the more effectively it can then plan for and realize all of the changes and benefits that the transition entails.

    Saturday, May 30, 2020

    More On How Michael Moore Got New Energy All Wrong

    Michael Moore’s former fact-checker speaks out about his sloppiness with the facts. From greenmanbucket via YouTube

    New Energy Is Good For What Ails The World

    New Energy can rebuild the economy by renewing the power system and redeeming the climate.From Unreserved via YouTube

    Will The Florida Keys Sink?

    The Keys are the U.S. canary in the coal mine of the climate crisis – and the canary is struggling to breathe. From Yale Climate Connections via YouTube

    Friday, May 29, 2020

    A Global Recovery Script, Starring New Energy

    Recovery packages must make clean-energy a cornerstone of the new global economy; As Covid-19 restrictions ease, Europe is working on its recovery script, with renewables in the starring role

    Remi Gruet, 11 May 2020 (RECharge)

    “…[Europe’s recovery script, with renewables cast in the starring role, is expected to include loans for commercial investments and] grants for new renewable technologies…[Its two messages are] ‘green’ means economic development…[and] we need new, flexible renewables technologies…[Studies show] clean-energy investments deliver higher returns, in both the short and long term, than conventional fiscal stimulus…

    …[All recent major models of the future energy system] show Europe running on between 80-100% renewable energy in 2050…In other parts of the world, the future share of renewables is still anticipated to be well above 50-60%...Mature renewables like wind power and PV will generate the bulk of low-cost, emissions-free energy for consumers…[and] now is the moment to widely deploy a second-generation of renewables…” click here for more

    Global New Energy To Hesitate, Then Bounce Back

    Renewable energy market update; Outlook for 2020 and 2021

    May 2020 (International Energy Agency)

    “The Covid-19 crisis is hurting – but not halting – global growth in renewable power capacity. The number of new renewable power installations worldwide is set to fall this year…But, given supportive government policies, growth is expected to resume next year as most of the delayed projects come online…In 2020, the IEA forecasts net additions of renewable electricity capacity to decline by 13% compared with 2019. The decline reflects delays in construction activity due to supply chain disruption, lockdown measures and social distancing guidelines, and emerging financing challenges…[but see] a 6% increase in global installed renewable power capacity…In 2021, renewables are expected to show their resilience…

    …The forecast expects utility-scale PV and wind to rebound as the majority of projects in the pipeline are already financed and under construction…The impact of Covid-19 on renewable electricity technologies with long lead times, such as hydropower, offshore wind, CSP and geothermal, remains limited…The Covid-19 crisis has radically changed the global context for biofuels…Longer term implications for growth may arise from the suspension of new policy initiatives in some countries due to low oil prices…[G]overnments have the opportunity to reverse this trend by making investment in renewables a key part of stimulus packages designed to reinvigorate their economies…” click here for more

    Wednesday, May 27, 2020

    ORIGINAL REPORTING: Solar’s Changing Market And Policy Landscape Tax credit, net metering declines strike distributed solar, but falling costs, storage offer new hope; With tax credits and net metering threatened, previous withdrawals of financial support mechanisms show what the distributed solar industry may soon face.

    Herman K. Trabish, Dec. 19, 2019 (Utility Dive)

    Editor’s note: Few knew what real turmoil is last December.

    Despite turmoil on key incentives and financial support that could threaten the distributed solar market, falling prices and battery storage are giving advocates something to cling to. Congress this week rejected an opportunity to extend the investment tax credit (ITC) for solar, likely impeding industry growth. Net energy metering (NEM), a key compensation mechanism for distributed solar in 39 states, and other financial supports for solar are also facing new challenges.

    In addition, the market and changing incentives for distributed solar are working in opposite directions. Driven by new efficiencies in hardware and labor, installed prices continue to fall in most markets, Lawrence Berkeley National Laboratory (LBNL) reported in October. But rebates and incentives have "largely phased out" in leading markets and fallen very low in most others, creating "a significant counterbalance."

    "It is very hard to say how one factor impacts a market because there are so many moving parts," Vikram Aggarwal, CEO of national online solar marketplace EnergySage, told Utility Dive. As changes compromise predictability, "consumers need certainty, and even a financial support [mechanism] scheduled to phase down with certainty will attract consumers to the next question, which is the price of solar, the electricity rate and the payback period."

    The uncertainty and potential market impact brought about from the withdrawal of the ITC and retail rate NEM can be seen in past changes to distributed solar's financial supports, researchers and stakeholders said. Whether solar can sustain its growth depends in part on how the solar industry faces the coming changes, and how utilities and policymakers choose to understand the value of solar+storage.

    Growth is slowing overall for distributed solar. U.S. residential solar grew 8% nationally in 2018, but only 7% year over year in the first half of 2019, according to the Q3 2019 Wood Mackenzie-Solar Energy Industries Association (SEIA) market report. In Q2 2019, non-residential distributed solar grew 2% less than in Q1 2019 and 16% less than in Q2 last year. "Since 2000, installed prices have fallen by $0.50/W per year," but that "has been substantially offset by a corresponding drop in rebates or other incentives," LBNL's Tracking the Sun 2019 reported.

    The payback period for distributed PV went up from 7.8 years in the second half of 2018 to eight years in the first half of 2019, EnergySage reported in September. At the same time, "customer hesitation created by utility and regulatory uncertainty leapfrogged the high cost of installation to become the second most common challenge in closing sales in 2018," the February 2019 EnergySage installer survey reported.There is, however, a "small but increasing share" of distributed solar being paired with battery storage, found. It ranged from "1% to 5%" of installations in major markets last year, but was over 60% of Hawaii installations… click here for more

    The Green Hydrogen Solution

    ‘Greener-than-green hydrogen to be produced at same cost as grey H2 at world’s largest facility’; US start-up's plasma-enhanced gasification plant, due to be completed in 2022, could be a major breakthrough for the much-needed zero-carbon fuel

    Leigh Collins 21 May 2020 (ReCharge)

    “Greener-than-green hydrogen” costing the same as grey H2 from unabated fossil fuels is set to be produced at a record-breaking facility in California by the end of 2022, in what could be a game changer for the rapidly developing sector…Washington DC-based start-up SGH2 — emerging from stealth mode today ¬— says its method of extracting hydrogen from waste, using plasma torches, will produce H2 at $2 per kilogram — five to six times cheaper than standard green hydrogen from renewables and at the same cost as the cheapest grey hydrogen available today…SGH2 describes its hydrogen as “greener than green” as it uses biomass-based waste that would otherwise rot in landfills and emit methane, a greenhouse gas 84 times more potent than CO2 over a 20-year period…This claim is slightly contentious as several larger green hydrogen projects have been announced…

    Because clean hydrogen is not being produced anywhere at scale, and the price of electricity and natural gas is so variable, it is hard to put a figure on how much it costs to produce — either via renewables (by splitting water molecules into hydrogen and oxygen using an electric current), known as green hydrogen, or via natural gas with its emissions captured and stored (or used), which is referred to as blue hydrogen…[Calculations from engineer Fluor put] the cost of electrolytic green hydrogen at $10-13 per kg, grey hydrogen (from unabated fossil fuels) at $2-6/kg, and blue hydrogen at $6-10/kg…Trade body Hydrogen Europe says green hydrogen from wind or solar power costs about $11-16 per kg today, although it adds that this cost could halve by 2023-25…[The International Energy Agency puts] the cost of grey hydrogen at “generally around” $1.50-3 per kg, and as low as $1/kg in the Middle East, with blue hydrogen at $1.40-1.50 “in the most promising regions” and green hydrogen from PV or onshore wind “generally around” $2.50-6.00 per kg…” click here for more

    Monday, May 25, 2020

    Bringing New Energy To Heating; A Case Study

    Heating Sector Transformation in Rhode Island; Pathways to Decarbonization by 2050

    Dean Murphy and Jürgen Weiss, May 2020 (The Brattle Group)

    Executive Summary

    As part of Rhode Island’s commitment to economywide decarbonization, this report examines solutions to transform the state’s heating sector. Dominated by space heating for the residential and commercial sectors, but also including water heating and industrial heating, the heating sector represents approximately one-third of the state’s overall greenhouse gas emissions.

    There are many solutions for decarbonizing the heating sector, but they fall into three broad categories:

    1. Reducing energy needs by improving building energy efficiency

    2. Replacing current fossil heating fuels with carbonneutral renewable gas or oil

    3. Replacing current fossil-fueled boilers and furnaces with electric ground source or air source heat pumps powered by carbon-free electricity

    The industrial sector may need other types of solutions, which can be very application-specific.

    To transition to decarbonized heating fast enough to meet mid-century decarbonization targets, Rhode Island will need substantial policy support. The reasons include low fossil fuel prices (particularly for natural gas), which also do not reflect the social costs of greenhouse gas emissions; switching to electrified heating solutions requires substantial initial costs for equipment and installation compared to replacing boilers or furnaces; and other more qualitative factors such as information deficits, immature supply chains, a natural reluctance by consumers to change what seems to work well.

    Rhode Island must base its policy framework for heating sector transformation on an understanding of the relative economic attractiveness of various decarbonization solutions. Figure ES 1 shows the projected range of average annual heating costs in 2050 for a representative existing single-family home in Rhode Island, using existing fossil fuels (on the left) or several alternative decarbonized heating solutions (on the right). This figure shows two key insights:

    1. For natural gas customers, who represent the majority of heating customers in the state, all of the decarbonized heating solutions will likely result in some increase in overall heating costs. This is less clear for fuel oil and propane customers. However, customer adoption of no-to-low carbon heating solutions will not take place in isolation. Viewing heating transformation within the context of broader decarbonization efforts across the electric and transportation sectors, total consumer energy expenditures are likely to be similar to what is paid today in a fossil fuel-based system.

    2. From today’s perspective, no single solution is clearly more economically attractive than the others. This is due to the high uncertainty related to how the costs of all decarbonized heating solutions will evolve over the coming decades. The heights of the bars themselves are less important than the uncertainty bands around them (represented by black bands extending above and below the tops of the bars). These uncertainty bands are largely overlapping for the decarbonized technologies, indicating that it is not clear at this point which of these technologies will be most economical in the long run.

    The analysis in Figure ES 1 assumes that as part of decarbonizing the heating sector, cost-effective energy efficiency measures such as air sealing and attic insulation will be implemented in essentially all Rhode Island buildings. Doing so lowers the challenge to decarbonize heating and saves consumers money, which is relevant for all consumers and may be particularly important for disadvantaged communities.

    This particular analysis is based on a set of “bookend” scenarios that assume for each decarbonized technology that this technology provides all heat across New England. It compares cases where fuels (gas and oil, in renewable forms) continue to primarily provide heat; or for electric heat pumps, assumes 100% adoption of either ground source heat pumps (GSHPs) or air source heat pumps (ASHPs). This captures the potential impacts of these technologies on the region’s overall energy systems. For instance, the economic attractiveness of electric heat pumps depends in part on the cost of (clean) electricity, which in turn depends on the impact that heat pumps will have on the electric system. Heat pumps themselves represent a substantial demand for electricity and can affect the price of power. Similarly, the attractiveness of renewable gas depends on its cost, which depends on the total gas volume demanded regionally and nationally, since low-cost supplies are limited.

    One important lesson from these bookend scenarios is that widespread ASHP adoption could require substantial additional investments in the regional electric power system, and could create operational challenges. At very low outside temperatures, when the need for heat is greatest, ASHPs become significantly less efficient. If ASHPs are adopted widely, this could create extremely high peak electric demand during a few very cold days.

    Since such bookend scenarios are unlikely to represent actual adoption of decarbonized heating solutions, Figure ES 2 shows how the results might change under one of many possible more-balanced adoption scenarios. This example shows a scenario that assumes that by 2050, electric heat pumps (one-third each by ASHPs and GSHPs) are providing two-thirds of heating; that (renewable) gas – which loses only 50% of volume relative to today – is providing most of the remaining heat; and that oil is providing the remaining amount.

    This more mixed adoption of all the decarbonized heating solutions partially mitigates the extreme impact of 100% ASHP adoption on electric system peaks (and the resulting cost of electricity), making ASHPs relatively more attractive. On the other hand, reducing delivered gas volumes, due to increasing energy efficiency or conversions to electrified heat, could increase the delivery cost of renewable gas, making it relatively less attractive. But, importantly, the more balanced adoption pattern of the Mixed Scenario does not alter the basic conclusion that no decarbonization solution is clearly preferred. The uncertainty ranges of the decarbonized technologies still largely overlap one another. Because the relative attractiveness of heating decarbonization solutions is sensitive to a) peak electric impacts and b) gas volume impacts, developing a better understanding of these effects, and opportunities to mitigate them, will be an important policy focus in the coming years.

    Finally, the decarbonization of heating will not take place in isolation. Rather, it is embedded in broader economy-wide decarbonization efforts, including a likely shift toward electrified transportation. Heating decarbonization, and in particular the level of electric heat pump penetration, can affect electricity prices. This could have broader impacts on consumers’ “energy wallet” – their total energy expenditures on baseline electricity consumption and electric vehicle (EV) charging, in addition to heating. However, changes in heating costs could be offset or exacerbated by impacts on other elements of the energy wallet, particularly transportation. EVs are expected – at least by 2050 – to have lower operating costs than current internal combustion engines.

    Figure ES 3 compares a representative consumer’s energy wallet spending today with what energy spending might look like by 2050, considering the various decarbonized heating solutions. The figure indicates that the attractiveness of ASHPs would not decrease substantially when considering the overall energy wallet. It also shows that, compared to 2020, any potential increase in heating cost could be at least partly offset by cost decreases elsewhere in the energy wallet, and by savings through energy efficiency. This does not mean that individual consumers or businesses will not see changes in their heating (and energy wallet) costs. Policy likely plays a key role in mitigating any potential cost increases, particularly where it may affect populations or industries that are vulnerable to increasing energy costs (and thus could be reflected in the state’s economy).

    The same broad conclusions apply to space heating uses in other settings, such as larger (multifamily) residential and commercial buildings, as well as to domestic water heating. Finally, various decarbonization solutions also exist for the remaining smaller uses of heat, such as electric cooking and clothes drying.

    FIVE THEMES TO GUIDE RHODE ISLAND’S PATH FORWARD

    The conclusion of this quantitative assessment of the relative attractiveness of various heating decarbonization solutions in Rhode Island is that, at present, there is no clear winning approach. Rather, the relative attractiveness of decarbonizing heating in the state depends on the evolution of the relevant costs – renewable gas, renewable oil, ASHPs, and GSHPs – which are highly uncertain today. Also, the attractiveness of the solutions in specific instances will depend on the particular context – the particular building, location, or application. In addition, each of the decarbonization solutions faces unique adoption and implementation challenges that Rhode Island will need to address to enable broad adoption over time.

    This implies that, for policy to support Rhode Island’s heating sector transformation, the next 10 years should not focus on advancing a single or limited set of solutions. Instead, Rhode Island should ensure that it is making progress, regardless of which solution (or mix of solutions) ultimately prevails. As illustrated in Figure ES 4, a policy framework for the next 10 years should involve five elements: Ensure, Learn, Inform, Enable, and Plan.

    As an initial step to ensure decarbonization, improving the energy efficiency of buildings will provide several immediate benefits. By reducing heat needs, it will reduce greenhouse gas emissions, regardless of what heating technology is utilized (and to the extent heating is electrified, improved building efficiency will reduce heating’s impact on electric loads). Importantly, cost-effective energy efficiency measures will reduce the total cost of heating, which will mitigate any potential increase in the cost of providing heat with decarbonized solutions. Finally, existing efficiency programs provide an effective program delivery network that can support the state’s expanded heating-sectorrelated decarbonization efforts.

    A second key policy element that will ensure progress towards decarbonizing the heating sector is enacting a set of technology-neutral measures that will reduce the carbon intensity of all energy sources used for heating – electricity, gas, oil, and propane – over time. Such measures may include renewable electricity requirements, carbon pricing or cap and trade policies, renewable fuel or heating standards, or other approaches. Complementary fuel-neutral policies include continued and increased efforts to improve the energy efficiency of Rhode Island’s existing buildings, while also tightening the efficiency requirements for new construction.

    Rhode Island must emphasize learning over the next decade, given the large uncertainties about both general and state-specific factors related to each of the decarbonized solutions and their implementation. Learning strategies should use pilot and demonstration projects, targeting state-specific issues or in collaboration for more general issues. At a minimum, learning policies should include:

    • Information gathering to enable better incentive targeting (such as information on the type and age of heating-related equipment in the state)

    • Proper research and development targeting Rhode Island-specific issues

    • More general information in collaboration with other states or organizations

    Rhode Island must inform key stakeholders, including consumers and the building trades, about the technical and economic issues related to decarbonized heat solutions that will require significant efforts to improve information level and flow. Potential policies in this area include broad information campaigns about the available solutions, including their pros and cons; publicly visible demonstration projects; developing training and certification programs for installers; and making information about qualified and experienced installers available to consumers.

    Policymakers will need to enact several additional strategies to enable a heating sector transformation. These include policies that identify and address the implementation barriers, which may take the form of incentives to consumers and businesses designed to overcome both overall cost and especially first cost barriers, such as the high upfront cost of heat pumps. In addition, Rhode Island should realign its regulatory frameworks. Examples include removing existing incentives that favor gas system expansion, reconsidering rate structures for both electricity and gas, and exploring ways to integrate the regulatory treatment of National Grid’s gas and electric businesses.

    Another important enabling policy principle relates to identifying and capitalizing on “natural investment opportunities” where decarbonized solutions may be implemented at a lower cost and with less disruption by coordinating with other work being done on the infrastructure or building. Examples include instances where natural gas or electricity infrastructure is being upgraded or replaced, buildings undergoing deep renovations, or existing heating equipment that needs to be replaced as it approaches the end of its useful life. Policies that enable progress can also target existing codes, rules, etc. that may inadvertently create barriers to deploying decarbonized heating solutions that are otherwise attractive. Finally, enabling policies should identify and mitigate instances where heating decarbonization could impose undue burdens on vulnerable populations.

    Planning will also be important. Changes to current planning approaches and some specific planning efforts will need to be part of the heating transformation strategy. In general, planning efforts should consider a long time horizon – 2050 or beyond – even if a typical planning exercise might only cover the next 10 years. This will allow Rhode Island to plan for the magnitude of changes needed to decarbonize the heating sector by mid-century, and account for the long lives of most heating-related infrastructure – buildings; pipelines; electric transmission and distribution equipment; GSHP ground loops; and even furnaces, boilers, and heat pumps themselves.

    Also, some specific planning efforts will be necessary. An example is planning for the expansion of the electric distribution grid. Significant new electric loads are likely to come online over the next several decades, not just for heat but also for EV charging. This provides an opportunity to better understand the tradeoffs between “future-proofing” the grid by anticipating additional future demands, vs. planning only for nearterm demands, which may lead to a series of smaller upgrades that could ultimately cost more. Similarly, even ahead of any clarity about the long-term role of the gas distribution system, developing plans for how the gas system might be altered to accommodate reduced gas use for heating, and whether there may be ways to do it more economically, will help inform the decisions that Rhode Island must undertake over the next few decades.

    This report identifies several important technical issues that will affect the transformation of the heating sector. These include the potential impacts of electrified heat on the power sector, and the future role of the gas system and how reduced gas delivery volumes could affect it. These insights support an economic analysis of the different pathways to decarbonize heating – using renewable fuels with heating infrastructure similar to today’s, or alternatively, electrifying heat with GSHP or ASHP.

    That analysis showed that there is substantial overlapping uncertainty about the future economic attractiveness of the decarbonized solutions – regarding the long-run cost of renewable fuels (which is likely to be substantially above the current cost of fossil fuels), as well as the cost of heat pumps themselves and the clean electricity to power them. Because of these overlapping uncertainties, it is not possible to identify a clear winner among the technologies. However, it appears that decarbonized heat is likely to be somewhat more costly than natural gas heat is today, and potentially comparable with oil or propane. Still, overall consumer expenditures on energy in a fully decarbonized economy may be roughly comparable to today’s costs.

    This has several policy implications for driving a heating sector transformation over the next several decades. Policy approaches should support enabling early progress on decarbonization – by pursuing energy efficiency to reduce heat needs, and by decarbonizing all the energy sources used for heating – both fuels such as gas and oil, and also electricity to power new electrified heating systems. Beyond this, policies should support both the learning and informing stages, to begin to address the uncertainties, collect information that will be necessary for the transformation, and ensure a widespread understanding of the solutions and their implications. Regulatory changes can enable the transformation, addressing barriers and facilitating progress on any or all of the pathways. Policies that create structures to identify and capitalize on natural investment opportunities will also enable the transformation.

    Broadening planning approaches for both the electric and gas systems will allow policymakers to consider longer time horizons consistent with the natural lives of heating infrastructure components and the timeframe and magnitude of the transformation. While it seems counterintuitive, Rhode Island must develop action plans knowing that it might not ultimately need them, since developing the plans will inform decisions about whether to implement them. The transformation of the heating sector over the next several decades will be a major undertaking, but it is achievable with early and sustained policy focus.

    Saturday, May 23, 2020

    Covid, Mega-Flooding, And The Big Crisis

    For at least two decades, climate scientists have predicted more frequent, severe flooding. This is not a prediction. From MSNBC via YouTube

    Meanwhile, Mega-Drought In The West

    “Mega-drought here and mega-flooding there is why many call it global weirding.” From CBS This Morning via YouTube

    More Michael Moore Mistakes

    “…Not even worth debunking…” From friendlyjordies via YouTube