[USA] Supreme Court reverses lower court decision, allows construction on Atlantic Coast Pipeline

On June 15, 2020, the Supreme Court issued a 7-2 ruling reversing a lower court decision on Atlantic Coast Pipeline LLC v. Cowpasture River Preservation Association which stopped construction on the $7.4 billion, 600-mile Atlantic Coast Pipeline (ACP) owned by Duke Energy and Dominion Energy.[1] The Supreme Court ruling gives the U.S. Forest Service, an agency of the U.S. Department of Agriculture that administers U.S. national forests and grasslands, the authority to grant the ACP developers right of way on the project because it goes over 600 feet underground across a portion of the Appalachian Trail, which is part of the National Park System. This does not necessarily mean that the U.S. Forest Service will approve the project. Critics of the pipeline say that the pipeline still has other hurdles in its path and the decision is not a definitive greenlight for the project. However, both utilities issued statements that the ruling is "an affirmation for the Atlantic Coast Pipeline."

The Supreme Court ruling will also affect the Mountain Valley Pipeline, a 303-mile project running from West Virginia to southern Virginia by crossing the Jefferson National Forest.[2] Construction on the nearly completed project was previously halted due to the Atlantic Coast Pipeline case.

[1] https://www.scotusblog.com/case-files/cases/atlantic-coast-pipeline-llc-v-cowpasture-river-preservation-association/

[2] https://www.mountainvalleypipeline.info/

[USA] Minnesota Power energizes Great Northern Transmission Line

On June 11, 2020, Minnesota Power, the state’s second largest investor-owned utility, energized its 224-mile, 500 kV transmission line, Great Northern Transmission Line (GNTL), that will bring the utility to 50% renewable energy in 2021.[1] The GNTL brings 250 MW of hydropower from Manitoba, Canada to Northern Minnesota and was completed in February 2020. With the GNTL energized and connected to Manitoba Hydro’s Manitoba Minnesota Transmission Project, the utilities now have a unique “mechanism that quickly balances energy supply and demand in Minnesota and Manitoba" which enables the utilities to use wind power more effectively. The utility first filed permits for the project in 2014. This is a big shift for Minnesota Power which generated most of its power from coal in the early 2000s.[2] Now, the only coal units in the utility’s portfolio are Boswell Energy Center’s 355 MW and 585 MW units 3 and 4, respectively.

[1]https://minnesotapower.blob.core.windows.net/content/Content/Documents/Company/PressReleases/2020/20200611_NewsRelease.pdf

[2] https://www.mnpower.com/Company/Generation

[USA] DOE announces $11 billion in energy cost-savings from Better Buildings Initiative partners

On June 9, 2020, the U.S. Department of Energy (DOE) announced the roughly 950 public and private sector organizations in DOE’s Better Buildings Initiative have reached nearly $11 billion in energy-cost saving.[1] [2] Better Buildings Initiative partners have also saved nearly 1.8 quadrillion British thermal units of energy (Btu), which is equivalent to the electricity consumption of 27 million homes in one year. Partners represent 32 of America’s Fortune 100 companies, 12 of the top 25 U.S. employers, 12% of the U.S. manufacturing energy footprint, and 13% of U.S. commercial building space. Of these partners, 20 reached their energy efficiency goals in the past year, including Bank of America, Michigan State University, and University of Utah. Other partners like Iron Mountain and Kohl’s Department Stores have previously reached their energy efficiency goals and have set new ones.

DOE’s Office of Energy Efficiency and Renewable Energy also announced four new Better Buildings efforts: the Better Buildings Workforce Accelerator, the Better Buildings Sustainable Corrections Infrastructure Accelerator, the Integrated Lighting Campaign, and the Building Envelope Campaign.[3] [4] [5] [6] These new programs aim to increase energy productivity, encourage investments in renewable energy and energy storage in public facilities, integrate advanced lighting controls in buildings, and help building owners and managers develop more energy-efficient building materials.

[1] https://www.energy.gov/articles/doe-announces-11-billion-energy-cost-savings-better-buildings-initiative-partners

[2]https://betterbuildingssolutioncenter.energy.gov/sites/default/files/attachments/DOE_BBI_2020_Progress_Report.pdf

[3] https://betterbuildingssolutioncenter.energy.gov/accelerators/workforce

[4] https://betterbuildingssolutioncenter.energy.gov/accelerators/corrections-infrastructure

[5] https://betterbuildingssolutioncenter.energy.gov/alliance/technology-campaigns/integrated-lighting-campaign

[6] https://betterbuildingssolutioncenter.energy.gov/alliance/technology-campaigns/building-envelope-campaign

[USA] Alabama regulators approve Southern Company’s request for nearly 2 GW of natural gas

On June 9, 2020, the Alabama Public Service Commission (PSC) unanimously voted to authorize Southern Company to buy, build, or contract for nearly 2 GW of natural gas resources to guarantee system resilience.[1] Previously, Alabama Power, a Southern Company subsidiary, had announced that it is switching from a summer-peaking to a winter-peaking system, and proposed several expansions in solar, energy efficiency, and natural gas for a total of about $1.1 billion. According to Alabama Power, the additions are part of a nearly 20% fleet capacity increase necessary for resilience. In addition to the approval of natural gas, about 200 MW of energy efficiency programs were approved. However, regulators did not approve the five proposed solar-plus-storage projects, stating that those resource additions should be considered on a separate docket not focused on resiliency.

The decision not to include solar-plus-storage has received backlash from environmental groups who claim that the solar-plus-storage projects would have saved customers more. According to Docket participants from Energy Alabama and the Southern Environmental Law Center, an environmental advocacy group and an environmental public interest law firm, respectively, Alabama Power’s analysis showed solar-plus-storage options were the least costly solution.[2]

[1] https://www.youtube.com/watch?v=XNRjWy1IgJo

[2] https://www.southernenvironment.org/news-and-press/press-releases/psc-approves-alabama-powers-1-billion-gas-expansion

[USA] FERC prohibits pipeline construction until legal issues are resolved

On June 10, 2020, the Federal Energy Regulatory Commission (FERC) issued an order prohibiting natural gas pipeline developers from beginning construction on a project until regulators act on rehearing requests.[1] The order partly addresses the issues raised during the D.C. Circuit Court of Appeals’ April 2020 en banc hearing, a hearing held in front all the judges in court, in Allegheny Defense Project v. FERC, which regards the Atlantic Sunrise Pipeline project to expand existing pipelines.[2] Under the Natural Gas Act (NGA), litigation is prevented until FERC makes a ruling on requests for rehearing, but FERC is capable of delaying those requests through tolling orders. Petitioners argued that the commission has been delaying requests for rehearing indefinitely while also allowing construction on pipeline projects to proceed. Critics say this practice has led to a legal purgatory of opposition to critical orders on wholesale markets which favors pipeline developers. FERC Commissioner Richard Glick dissented in part to the order, stating that although the order is a good first move, it does not address concerns that pipeline developers can still begin to condemn private land through eminent domain before the landowner is able to challenge the developer's ability to do so.[3]

[1] https://www.ferc.gov/CalendarFiles/20200609181333-RM20-15-000.pdf

[2] https://www.ferc.gov/legal/court-cases/briefs/2020/DC17-1098etalAlleghenyDefenseProject.pdf

[3] https://www.ferc.gov/media/statements-speeches/glick/2020/06-09-20-glick.asp#.XuKfvjpKg2y

[USA] Businesses, lawmakers urge federal investment and support of the clean energy sector

On June 2, 2020, two unrelated groups sent letters to Congressional leaders and lawmakers urging the government to increase support for the clean energy industry in the wake of the COVID-19 pandemic. In the first letter, 57 Democratic Senators and Representatives, led by Sen. Martin Heinrich, D-N.M., called for “additional flexibility” for energy tax credits in order to support the clean energy sector and work force.[1] According to the letter, the clean energy sector has seen a 17.4% decline in employment—nearly 600,000 jobs—compared to the April 2020 national unemployment rate of 14.7%.

The second letter included about 80 companies and organizations and proposed federal appropriations of $22 billion over five years to retrofit critical public facilities.[2] The group has also proposed $18 billion for state and local public buildings through the federal State Energy Program over five years, $2.5 billion for improvements to federal buildings through the Federal Energy Efficiency Fund, and $1.5 billion for energy efficiency improvements in public housing. The funding would go toward a range of efficiency and resilience measures. The letter claims that the federal funding could help leverage an estimated private investment of $88 billion to deliver a total of $110 billion in economic activity. Organizations signed on to the letter include: ConEdison Solutions, Constellation, DuPont Specialty Products USA, FPL Energy Services, Greentech Energy, Schneider Electric, Siemens Corporation USA, and the Sheet Metal and Air Conditioning Contractors National Association.

[1] https://www.heinrich.senate.gov/press-releases/heinrich-tonko-lead-bicameral-call-for-inclusion-of-clean-energy-workforce-support-in-covid-19-economic-recovery-packages

[2] https://www.documentcloud.org/documents/6935575-Mission-Critical-Facility-Renewal-Letter-to.html

[USA] DOE to provide $30 million to develop small-scale solid oxide fuel cell systems and hybrid energy systems

On May 29, 2020, the U.S. Department of Energy’s (DOE’s) Office of Fossil Energy (FE) announced up to $30 million in funding for cost-shared research and development projects for Small-Scale Solid Oxide Fuel Cell Systems and Hybrid Energy Systems.[1] The new funding supports the development of technologies that can advance the present state of small-scale solid oxide fuel cells (SOFC) hybrid systems, which produce electricity directly from oxidizing a fuel, using solid oxide electrolyzer cell (SOEC) technologies. The development of advanced technologies will increase the commercial readiness of hydrogen production and power generation. The funding will solicit applications for multiple areas of interest, corresponding to the research outline in DOE’s 2019 Congress report, Report on the Status of the Solid Oxide Fuel Cell Program.[2] The three primary areas of interest are small-scale distributed power generation SOFC systems, hybrid systems using solid oxide systems for hydrogen and electricity production, and cleaning process for coal-derived syngas to be used as SOFC fuel.

[1] https://www.energy.gov/articles/doe-provide-30-million-develop-small-scale-solid-oxide-fuel-cell-systems-and-hybrid-energy

[2] https://www.energy.gov/fe/report-congress-status-solid-oxide-fuel-cell-program

[USA] Energy efficiency continues to be cheaper than natural gas

According to new research released by the U.S. Department of Energy’s (DOE) Lawrence Berkley National Laboratory on May 13, 2020, natural gas energy efficiency programs through utilities saved energy at a cost of about $0.40/therm (1 therm is equal to 100,000 Btu) from 2012 to 2017.[1] [2] Compared to natural gas—which averaged about $1/therm—energy efficiency programs are significantly cheaper. Researchers also found that commercial and industrial (C&I) programs had the lowest savings-weighted average cost of gas savings ($0.18/therm) during the study period. However, C&I programs represented only about 20% of overall efficiency program spending. For residential and low-income program savings costs were $0.43/therm and $1.47/therm, respectively. Savings costs varied widely by geographic region. For instance, savings in the Midwest averaged $0.29/therm while in the West saving averaged $0.59/therm. The study says this is likely due to higher spending on low-income programs in the West, as well as differences in savings opportunities between cold and temperate regions.

In response to the study, many efficiency advocates claim there are even more savings to be had through the electrification of end-uses, but the study did not consider this in their analysis. Additionally, efficiency advocates say the natural gas industry may be building unnecessary infrastructure; the Natural Resources Defense Council says around 90% of proposed gas power plants and their respective pipelines will likely be unnecessary by 2035.[3]

[1] https://emp.lbl.gov/news/energy-efficiency-continues-be-cheaper

[2] https://eta-publications.lbl.gov/sites/default/files/cose_natural_gas_final_report_20200513.pdf

[3] https://www.nrdc.org/experts/sheryl-carter/energy-efficiency-still-abundant-and-cheaper-gas

[USA] Energy sector jobs plunge at 'historic' rate amid COVID-19 crisis

On May 18, 2020, the BW Research Partnership, an economic research firm, released a report that found that the coronavirus pandemic has eliminated five years of job growth across the U.S. energy sector.[1] Since the beginning of the pandemic, the energy sector has lost 1.3 million jobs and nearly a million of those were lost in April 2020 alone. According to the report, job losses in the fuels sector made up about 10% of the cuts in April 2020. The motor vehicles industry was the hardest hit in April 2020, with 340,000 jobs being cut in April 2020. Coal mining (including electric power generation) experienced 4,000 job losses in April 2020, bringing the total losses to more than 9,000 jobs since the beginning of the pandemic. For oil and gas drilling and refineries, 40,000 jobs were cut in April 2020 and nearly 90,000 jobs have been lost since the beginning of March 2020.

Out of all the state, California has taken the greatest hit, losing more than 124,000 jobs since the onset of the pandemic. Texas and Michigan also had high job losses with 78,700 and 64,500, respectively. The report also notes that despite only making up 14% of the industry, Latino workers made up 23% of total job losses.

[1] https://bwresearch.com/covid/docs/BWResearch_EnergyJobsAprilCOVID-19Memo_05-18-2020.pdf

[USA] Colorado judge clears way for Tri-State exit fee determinations

On May 15, 2020 Colorado Administrative Law Judge (ALJ) Robert Garvey granted a motion for summary judgement filed by La Plata Electric Association (LPEA) and United Power—two cooperative power providers—to not allow Tri-State Generation and Transmission (G&T) to raise a federal preemption defense.[1] In 2019, modifications to Tri-State’s bylaws allowed Tri-State to add new non-utility members which brought Tri-State under FERC jurisdiction. Therefore, Tri-State had argued that federal law preempts state law in the issue of exit fees . The ruling, however, has stated that the issue falls under state purview and has cleared the way for state regulators to determine the fees the two cooperatives will pay to exit Tri-State’s service.

United Power, LPEA and other members of Tri-State have pressed to leave Tri-State's service over dissatisfaction with the G&T provider’s generation mix which heavily relies on coal. Tri-State, however, says it is working to eliminate coal emissions in New Mexico by the end of 2020 and in Colorado by 2030. According to a new report by the Rocky Mountain Institute, Tri-State’s new clean energy plan is a well thought out approach to phasing out 1 GW of coal.[2]

[1] https://www.documentcloud.org/documents/6895523-Interim-Decision-Granting-Motion-for-Summary.html

[2] https://rmi.org/tri-state-chooses-the-low-carbon-path/

[USA] PJM MOPR could cost market consumers up to $2.6B annually according to new report

According to a May 2020 report released by consulting firm Grid Strategies, the Federal Energy Regulatory Commission’s (FERC) 2019 Minimum Offer Price Rule (MOPR) decision could cost customers in the PJM Interconnection from $1 billion to $2.6 billion annually.[1] The new estimate updates a previous cost analysis done by the group in August 2019 which found the MOPR could cost up to $5.7 billion per year.[2] The newest analysis finds the rule could cost consumers nearly $24 billion over the next nine years if FERC adopts minimum bid levels closer to PJM’s initial proposal rather then its most recent finding. Under that scenario, it is likely that subsidized nuclear units in Illinois, New Jersey, and Ohio will not be able to clear the capacity market. Under another scenario that assumes FERC adopts more recent PJM minimum bid levels, Grid Strategies still estimates that the rule will cost customers $10 billion over the same period. In this scenario, it is still possible that some units would not clear under PJM’s newest bid numbers.

Grid Strategies’ analysis comes in the midst of efforts by PJM to negotiate with stakeholders concerned by the MOPR’s potential impacts on state resource goals. Maryland and New Jersey have stated that they are looking at pursuing a Fixed Resource Requirement alternative which would allow parts or all of their state to secure capacity outside the wholesale market.[3]

[1] https://gridprogress.files.wordpress.com/2020/05/a-moving-target-paper.pdf

[2] https://gridprogress.files.wordpress.com/2019/08/consumer-impacts-of-ferc-interference-with-state-policies-an-analysis-of-the-pjm-region.pdf

[3] https://www.bpu.state.nj.us/bpu/pdf/boardorders/2020/20200325/3-27-20-2H.pdf

[USA] Great River Energy to close 1.15 GW North Dakota coal plant

On May 7, 2020, Great River Energy, an electric transmission and generation cooperative in Minnesota, announced that it plans to significantly reduce its carbon footprint by replacing a North Dakota coal plant with renewable energy projects, market purchases and grid-scale battery technology.[1] Under the plan, the 1,151 MW Coal Creek Station would be retired in the second half of 2022 and 1,100 MW of wind energy would be purchased by the end of 2023. Great River Energy will also modify the 99 MW lignite coal-fired Spiritwood Station power plant to burn natural gas, install a 1-MW/150-MWh battery demonstration system, and repower its Blue Flint biorefinery with natural gas. According to the cooperative, the changes will significantly reduce member power supply costs, and will allow it to provide a 95% carbon-free energy portfolio.

Environmental activists praised the decision to close the Coal Creek Station, but North Dakota lawmakers are concerned that it will affect the state’s economy. North Dakota Governor Doug Burgum (R) said his administration is "more determined than ever to find a path forward for Coal Creek Station that preserves high-paying jobs. ... We remain committed to bringing stakeholders to the table to evaluate all options and find opportunity in this uncertainty."[2]

[1] https://greatriverenergy.com/major-power-supply-changes-to-reduce-costs-to-member-owner-cooperatives/

[2] https://www.governor.nd.gov/news/burgum-statement-great-river-energys-announcement-retire-coal-creek-station-2022

[USA] New report finds oil demand may not recover until 2026

According to a report released by Wood Mackenzie on May 12, 2020, demand for crude oil will take until at least 2026 to recover under a full recovery scenario.[1] In its report, Wood Mackenzie examined several trends happening as a result of the pandemic: reduced travel and trade, greater government involvement, and increased automation. The analysts then developed three scenarios for how those trends could affect energy over the next two decades. In the ‘Full recovery’ scenario, there is a rapid return to pre-pandemic conditions. Under the ‘Go it alone’ scenario, economies are slow to recover from the pandemic, with mixed outcomes for coal, oil and natural gas. And finally, in the ‘Greener growth’ scenario, governments focus stimulus programs on supporting the energy transition.

While natural gas use and coal use are expected to trend upward and downward, respectively, across all scenarios, crude oil demand is less predictable. Under the ‘Greener growth’ scenario, for example, oil demand would slowly rebound over the next decade, followed by a sudden decline in 2030 as policies reinforce the energy transition and electric vehicles take hold. In the other scenarios, oil demand slowly increases over the next two decades.

[1] https://www.eenews.net/assets/2020/05/13/document_ew_02.pdf

[USA] St. Louis becomes first Midwest city to pass a Building Energy Performance Standard

On May 7, 2020, St. Louis, Missouri Mayor Lyda Krewson signed into law a Building Energy Performance Standard (BEPS) plan that requires buildings in the city to meet energy efficiency standards and establishes resources to help building owners achieve the savings associated with energy efficiency.[1] [2] St. Louis is the first Midwest city and one of only four jurisdictions (includes: Washington State, Washington, D.C., and New York City) in the U.S. to pass a BEPS. The BEPS plan will help the city achieve its goal of eliminating community-wide greenhouse gas emissions by 2050.

The BEPS plan only applies to buildings that are 50,000 square feet or larger and were already required to report their energy and water use under current city law.[3] Under BEPS, these buildings will be required to meet several levels of energy performance. The BEPS plan also requires several energy-saving actions, including upgrading HVAC units, ventilation, lighting and elevators. In addition, the new law sets up a Building Energy Improvement Board to help ensure buildings are complying with new standards and consider owners’ alternative plans when compliance is not possible. The board will be made up of nine members from utilities, labor, affordable housing owners and tenants, and commercial buildings.

[1] https://www.nrdc.org/media/2020/200506

[2] https://www.nrdc.org/experts/nrdc/st-louis-becomes-third-us-city-adopt-bold-standards-slash-energy-waste-buildings

[3] https://www.stlouis-mo.gov/internal-apps/legislative/upload/as-amended/BB219AACombined.pdf

[USA] New Mexico regulators delay two solar+storage projects intended to replace San Juan coal plant

On April 29, 2020 the New Mexico Public Regulation Commission voted 3-2 to delay the decision on whether to approve two solar-plus-storage projects that the Public Service Company of New Mexico (PNM), the New Mexico’s largest investor-owned utility, had proposed as part of the replacement generation for its San Juan coal plant.[1] The regulators determined that they could not approve the two solar projects before taking a closer look at the utility’s full replacement plan. The two projects in question are the Arroyo (300 MW of solar and 40 MW/160 MWh of battery storage) and the Jicarilla (50 MW solar and 20 MW/80MWh of battery storage) projects. The two projects are part of PNM's broader plan to add 350 MW of solar capacity, 380 MWh battery storage, and 280 MW of natural gas to replace its coal-fired generation. PNM has plans to spend $733 million in order to replace its coal-fired generation.[2]

Environmental groups and PNM have both stated that they were not happy with the decision, though they both understood in part the commission's reasoning. A major downfall to the delay is that the projects won’t be able to secure the full value of the solar investment tax credit as it winds down, making the projects' future prices unknown.

[1] https://www.santafenewmexican.com/news/local_news/regulators-again-delay-decision-on-pnms-solar-proposals/article_475242f8-8a32-11ea-aa6c-571c28313f6f.html

[2] https://www.prnewswire.com/news-releases/pnm-files-consolidated-application-for-san-juan-generating-station-300878854.html

[USA] SCE procures 770 MW of battery storage to bolster California's grid

On May 1, 2020, Southern California Edison (SCE) announced that it is procuring a 770 MW/3,080 MWh package of battery resources to bolster grid reliability.[1] This procurement is more than the entire energy storage market in the U.S. for all of 2019. The utility has contracts with seven battery projects developers, ranging from 50 MW to 230 MW and slated to come online in August 2021. The largest of the projects is a 230 MW facility by NextEra Energy in California’s Riverside County. Most of the projects will be co-located with adjacent solar plants. The utility plans to ask the CPUC for approval of the contracts later in May 2020. According to SCE, the battery projects will enhance electric grid reliability and help address potential energy shortfalls identified by regulators in California. In 2019, the California Public Utilities Commission (CPUC)raised concerns that retiring fossil fuel resources, shifting peak periods, and increasing levels of renewables would create reliability issues.[2] The CPUC has also stated that battery storage will play a critical role in California’s effort to supply all electricity from zero-carbon resources by 2045. Recently, the CPUC adopted an optimal resource portfolio to reach California’s goals; the portfolio requires 1 GW of long-duration storage by 2026 and tripling battery storage capacity from 2020 levels.

[1] https://newsroom.edison.com/releases/sce-grows-clean-energy-portfolio-enhances-system-reliability-with-770-megawatts-of-new-energy-storage-capacity

[2] http://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M319/K349/319349071.PDF

[USA] Dominion Energy Virginia set to quadruple renewable energy in new integrated resource plan

On May 1, 2020, Dominion Energy filed its 15-year, long-term integrated resource plan (IRP) for Virginia which includes three separate models to increase solar, wind, and energy storage capacity.[1][2] According to the IRP, the utility has already begun to transition its generation fleet away from fossil fuels; over the past decade more than 2.2 GW of coal, oil, and gas-fired generation has been retired. Currently the utility has 396 MW of solar, 1.8 GW of energy storage, and 12 MW of offshore wind under construction or in operation. Its latest IRP would add between 6.7 GW and 18.8 GW of solar, up to 2.7 GW of storage and up to 5.1 GW of offshore wind in the next 15 years. It would also add natural gas resources and potentially keep more gas-fired generation on the system to address system reliability.

In April 2020, Virginia passed the Virginia Clean Economy Act (VCEA) which set a goal of 100% clean energy resources by 2045 and requires the addition of up to 5.2 GW of offshore wind.[3] Three of the four scenarios Dominion proposed take into account the VCEA and other legislation passed in spring 2020, while one presents a “low cost” plan.

[1] https://news.dominionenergy.com/2020-05-01-Dominion-Energy-Virginia-Quadruples-Renewable-Energy-and-Energy-Storage-in-Long-Term-Integrated-Resource-Plan

[2] https://www.dominionenergy.com/library/domcom/media/about-us/making-energy/2020-va-integrated-resource-plan.pdf?modified=20200501191108

[3] https://www.governor.virginia.gov/newsroom/all-releases/2020/april/headline-856056-en.html

[USA] Duke Energy sets goal to double renewable capacity by 2025

On April 28, 2020, Duke Energy released two new documents, a 2019 Sustainability Report and a 2020 Climate Report, and announced plans to add 8,000 MW of wind, solar and biomass by 2025, which would double its total renewable energy.[1] [2] [3] The announcement is a part of Duke’s larger plan to achieve 50% lower CO2 emissions by 2030 and net-zero carbon emissions by 2050. Currently, Duke's regulated electric utility generation is 31% natural gas, 31% nuclear, 24% coal and 5% renewables. By 2030, Duke predicts its mix will be 42% natural gas, 30% nuclear, 11% coal, and 14% renewables. Duke says by 2050 renewables will make up the largest share at 36% while natural gas will drop to 6%.

Fossil fuels will still account for more than half of its generation, but the utility says it remains on track to achieve its 2030 goal. Although it has received criticism for relying on natural gas when it could use energy storage, Duke has asserted that adding new natural gas is necessary. According to Duke’s climate report, a “no new gas” scenario would create installation and operational challenges because current energy storage technology would not be able to handle the capacity and energy gap created by coal retirement. Duke also noted that the incremental costs of achieving net zero emissions under a no new gas scenario "would increase by three to four times" compared to adding gas resources.

[1] https://news.duke-energy.com/releases/new-duke-energy-reports-show-progress-toward-ambitious-climate-and-sustainability-goals?_ga=2.46264229.348135488.1588192929-1661836963.1588192929

[2] https://www.duke-energy.com/_/media/PDFs/our-company/Climate-Report-2020.pdf

[3] https://sustainabilityreport.duke-energy.com/

[USA] Chicago requires new residential, commercial construction include EV charging capabilities

On April 24, 2020, the Chicago City Council approved an ordinance that requires new construction of residential and commercial buildings to guarantee at least 20% of parking spaces are ready for electric vehicle (EV) charging equipment to be installed.[1] . The ordinance also requires at least one of the EV-ready spaces be disability accessible and new buildings must have charging infrastructure in place or actual charging stations installed during construction. The new rules only apply to residential buildings with five or more units and commercial buildings with 30 or more parking spaces.

Chicago is committed to reaching 100% renewable energy for all its municipal buildings by 2025 and all city buildings by 2035. In addition, the Chicago Transit Authority plans to electrify its fleet of over 1,850 buses by 2040. According to Chicago officials, the new ordinance is in response to growing EV adoption across the United States; by 2040 more than half of all new car sales will be electric. Consumer advocates like Citizens Utility Board (CUB) say the new ordinance makes Chicago a national leader in its efforts to increase adoption of EVs, and called for similar policies to be adopted more widely.[2]

[1]https://www.chicago.gov/city/en/depts/cdot/provdrs/conservation_outreachgreenprograms/news/2020/april/chicago-city-council--approves-ordinance-to-increase-chicago-s-e.html

[2] https://www.prnewswire.com/news-releases/new-electric-vehicle-ordinance-makes-chicago-national-leader-301047088.html

[USA] Rooftop solar applications up 40% despite COVID-19

According to a filing with the Hawaiian Public Utilities Commission (PUC) released on April 22, 2020, Hawaiian Electric (HECO) has not seen a drop in applications for rooftop solar system interconnections despite the shelter-in-place order; between March 5 and April 15, 2020, the company received 40% more applications than the same period in 2019.[1] The filing was in response to a letter submitted to the PUC by Hawaiian distributed energy resource (DER) groups on April 3, 2020, which outlines various measures to expedite interconnection processes and support the DER sector during the COVID-19 pandemic.[2] According to the groups, which include the Distributed Energy Resources Council, Hawaii PV Coalition, and Hawaii Solar Energy Association, streamlining HECO’s interconnection processes could help customers complete installations and shrink their electric bills. The groups recommended that distributed systems below 25 kW be allowed to operate once they are installed as well as other provisions to help the distributed solar sector.

In its response, the HECO remarked that solar contractors are continuing to work and building inspections are still progressing so the pandemic should not significantly hamper the installation of DER in the near term. The utility also listed some of the measures it is taking to ensure interconnection processes are smooth such as remotely reviewing applications and loosening deadlines for installations to be completed, but noted that some of the group’s suggestions would lead to safety risks.

[1] https://dms.puc.hawaii.gov/dms/DocumentViewer?pid=A1001001A20D22B62259D00190

[2] https://dms.puc.hawaii.gov/dms/DocumentViewer?pid=A1001001A20D03B54540J00106