[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

[USA] DOE announces $28 million to develop ultrahigh temperature materials for gas turbine applications

On April 21, 2020, the U.S. Department of Energy (DOE) announced up to $28 million in funding for a new Advanced Research Projects Agency-Energy (ARPA-E) program called ULtrahigh Temperature Impervious Materials Advancing Turbine Efficiency (ULTIMATE).[1][2] The goal of the ULTIMATE program is to improve the efficiency of gas turbines by increasing the temperature capability of the materials used in parts such as the turbine blade. Blade material temperature capability has improved steadily over the last few decades to 1100 ºC, the DOE believes there are opportunities to discover, develop, and implement novel materials that work at temperatures significantly higher than industry standard superalloys. ULTIMATE projects will develop and demonstrate ultrahigh temperature materials that can operate in high temperature and high stress environments of a gas-turbine blade. The ULTIMATE program will target enabling gas-turbines blades to operate continuously at 1300 ºC in a material test environment—or with coatings, with turbine inlet gas temperatures of 1800 ºC or higher. According to the DOE, improving gas turbine efficiency will create opportunities to generate more energy savings, lower carbon emissions, and benefit the economy.

[1] https://www.energy.gov/articles/department-energy-announces-28-million-develop-ultrahigh-temperature-materials-gas-turbine

[2] https://arpa-e.energy.gov/?q=arpa-e-programs/ultimate

[USA] Trump administration to reinstate tariff on two-sided solar modules

According to a notice published in the Federal Register on April 17, 2020, the U.S. Trade Representative will withdraw its exclusion of two-sided solar panel imports from the Section 201 tariffs established in 2018 following a review of the exclusion.[1] The two-sided solar panel exemption will be lifted as early as May 18, 2020 and the tariffs will end in 2022. Two-sided solar modules, a newer technology not widely manufactured in the U.S., are projected to grow in popularity due to power-generation advantages and relative cost-competitiveness, but a big part of their price advantage over one-sided panels is the tariff exemption.

In December 2019, when the U.S. International Trade Commission (ITC) first reviewed the effectiveness of the 2018 tariffs, several U.S. solar panel manufacturers argued for applying the tariffs to two-sided solar modules. Other members of the solar industry like the Solar Energy Industries Association (SEIA) and solar developers oppose the Trade Representative’s decision and are considering opportunities for a legal challenge.[2] [3] According to SEIA and other solar analysts, China's manufacturing and production, and the global solar module market, are starting to recover after the worldwide response to COVID-19. For developers, regaining supply of solar modules is critical for projects that have not already purchased and stocked up on panels. For solar manufacturers, though, the 2018 tariffs have spurred growth; five module manufacturing utilities have opened in the U.S. since 2018.

[1] https://www.federalregister.gov/documents/2020/04/17/2020-08189/determination-on-the-exclusion-of-bifacial-solar-panels-from-the-safeguard-measure-on-solar-products

[2] https://www.seia.org/news/seia-statement-ustr-calling-remove-tariff-exclusions-bifacial-solar-modules

[3] https://www.seia.org/initiatives/international-trade

[USA] FERC approves NERC’s request for delay on reliability standards

On April 17, 2020, the Federal Energy Regulatory Commission (FERC) approved the North American Electric Reliability Corporation’s (NERC) request to delay the implementation of seven reliability standards by three to six months (October 2020-January 2021), citing the substantial impacts of the pandemic on registered entities.[1] NERC stated that registered entities "would need to expend significant effort and resources in the coming months" in order to document compliance; the pandemic would make gathering these resources substantially harder.[2]

The delayed reliability standards include four other requirements focused on bulk electric system personnel and protection control standards, and three cybersecurity Critical Infrastructure Protection (CIP) rules. CIP rules are standards for preparedness and response to serious incidents that involve critical infrastructure. Protect Our Power, a non-profit focused on grid security, advocated for FERC to approve a shorter 30-day delay to the CIP standards, arguing that cybersecurity vulnerabilities in the electric sector supply chain need to be eliminated quickly. However, NERC says the three-month delay for the cybersecurity rules is unlikely to leave the grid vulnerable and is appropriate given the current crisis.

[1]https://www.nerc.com/FilingsOrders/us/FERCOrdersRules/order%20granting%20motion%20to%20defer%20the%20implementation%20dates.pdf

[2]https://www.nerc.com/news/Headlines%20DL/Motion%20to%20Defer%20Implementation%20of%20Reliability%20Standards.pdf

[USA] DOE Announces Crude Oil Storage Contracts to Help Alleviate U.S. Oil Industry Storage Crunch

The U.S. Department of Energy (DOE) announced on April 14, 2020 that it is discussing contract awards with nine U.S. companies with the intention to storing their U.S. produced crude oil in the U.S.’s Strategic Petroleum Reserve (SPR).[1] The U.S. oil industry is currently faced with storage demand exceeding availability which stems from the combined effects of a sharp decline in demand due to COVID-19 and an excess of supply. In a response to this, President Trump directed the DOE to fill the SPR to capacity in mid-March 2020, though Democrats were strongly critical of the move, stating that it is a waste of resources to save the oil industry.[2] [3] On April 2, 2020, the DOE issued a Request for Proposals to use available storage capacity at the SPR for temporary storage to alleviate the strain on oil companies.[4] The awards under negotiation are for approximately 23 million barrels of crude oil storage, to be distributed across all four SPR sites. Many of the deliveries will be received in May and June 2020, but there is a possibility of early deliveries in April 2020. Companies can schedule the return of their oil through March 2021, minus a small amount of oil to cover the cost of storage.

[1] https://www.energy.gov/articles/doe-announces-crude-oil-storage-contracts-help-alleviate-us-oil-industry-storage-crunch

[2] https://www.energy.gov/articles/doe-applauds-swift-action-president-trump-initiates-process-purchase-oil-strategic

[3]https://www.markey.senate.gov/imo/media/doc/2020_03_12%20COVID%2019%20Oil%20Tax%20Break%20Trump%20signed%20copy.pdf

[4] https://www.energy.gov/articles/us-department-energy-make-strategic-petroleum-reserve-storage-capacity-available-struggling

[USA] Environmental groups sue DOE over revised appliance standards process

On April 14, 2020 the Natural Resources Defense Council (NRDC) sued the U.S. Department of Energy (DOE) in the 9th U.S. Circuit Court of Appeals in San Francisco over the DOE’s revised process for setting appliance standards.[1] Along with NRDC, parties to the suit include Earthjustice, representing the Sierra Club, Consumer Federation of America, and Massachusetts Union of Public Housing Tenants; the U.S. Public Interest Research Group; and Environment America. According to the NRDC, this lawsuit is the 107th legal challenge to the administration’s rulings on environmental issues, and the third time in five months that groups have filed suit over the appliance standards program. DOE’s revised process requires a new standard to save 0.3 quadrillion BTUs of energy consumed by appliances on site over 30 years. However, the lawsuit argues that the new process sets an arbitrary baseline for “significant savings” to establish a new standard.

The DOE, however, argues that the current rules require too much investment for savings that are not always significant. The DOE is now taking public comment on how to prioritize its review of appliance standards under the revised process.[2] Environmental advocates say they will be following it closely and believe the move is unnecessary.

[1] https://www.nrdc.org/sites/default/files/energy-efficiency-standards-20200414.pdf

[2] https://www.federalregister.gov/documents/2020/04/15/2020-07721/energy-conservation-program-procedures-for-use-in-new-or-revised-energy-conservation-standards-and

[USA] EPA rule change to save 4 coal plants across Pennsylvania and West Virginia

On April 9, 2020, the U.S. Environmental Protection Agency (EPA) updated its Mercury and Air Toxics Standards (MATS) to assist four struggling coal plants in Pennsylvania and West Virginia.[1] The coal plants burn low-quality coal refuse—waste abandoned from mining and burning coal. Under Obama-era MATS standards these plants did not meet acid gas hazardous air pollutant emissions standards, but the new rule creates a subcategory for these plants. This particular change to MATS is not likely to have a major environmental impact because of its limited scope.

According to the Anthracite Region Independent Power Producers Association (ARIPPA), a group that represents the coal refuse-to-energy industry across West Virginia and Pennsylvania, there are more than 5,000 abandoned mines across Pennsylvania that were never reclaimed, totaling between 200 million and 8 million cubic yards of waste.[2] One remediation solution for the problem, burning waste into energy, became viable in the late 1970s through the Public Utility Regulatory Policies Act (PURPA), which sought to diversify the country’s electric resource profile. Since 1987, more than 212 million tons of coal refuse have been removed in Pennsylvania alone, but the coal plants are now struggling as their economic viability has declined. Without the rule change, two of the four plants affected would have likely closed by the end of May.

[1] https://www.epa.gov/mats/regulatory-actions-final-mercury-and-air-toxics-standards-mats-power-plants

[2] https://arippa.org/wp-content/uploads/2018/12/ARIPPA-Coal-Refuse-Whitepaper-with-Photos-10_05_15.pdf

[USA] EIA April STEO—Coronavirus to cut coal use, CO2, electricity demand

In April 2020, the U.S. Energy Information Association (EIA) released its April Short-Term Energy Outlook (STEO) which documents the broad impacts of the coronavirus pandemic on the energy sector, including annual plunges in energy-related carbon emissions, electricity demand, and production of U.S. crude oil and natural gas.[1] According to the report, total U.S. power-sector generation will drop 3% in 2020 compared to an increase of 6% in 2019, leading “to an expected decline in fossil-fuel generation, especially at coal-fired power plants;”. U.S. coal production in 2020 will decrease 22% from 2019. The economic slowdown and restrictions on business and travel activity from COVID-19 will also cut energy-related carbon emissions by 7.5% in 2020. However, the agency expects emissions will increase by 3.6% in 2021.

Renewable energy is still expected to be the fastest-growing source of electricity generation and is projected to grow by 11% in 2020, but COVID-19 is "likely to have an impact" on new generating capacity buildouts. The April STEO projects that the energy sector will add more than 19 GW of wind capacity and more than 12 GW of utility-scale solar capacity in 2020. These additions are 5% and 10% lower, respectively, than in previous STEOs from the EIA.

[1] https://www.eia.gov/outlooks/steo/pdf/steo_full.pdf

[USA] S&P Global Ratings revises its utility outlook to “negative”

In a report released on April 2, 2020, S&P Global Ratings revised its outlook for North American regulated utilities from "stable" to "negative" due to the risks posed by COVID-19 which will deplete many utilities’ “financial cushions.” [1] Despite this new vulnerability, S&P Global stated that regulated utilities are still in a better position to access credit than most other corporate industries because they sell necessities and receive a rate of return set by regulators, rather than the market. Certain utilities may be more precarious position than others, though, such as those that disproportionately depend upon commercial and industrial (C&I) customers for their revenue.

Beyond the current disaster, according to the report, circumstances like natural disasters and acquisitions had led some utilities to take on even more debt which has negatively affected the utilities’ ability to withstand current events. Some examples include PG&E, Edison International, and Sempra Energy’s issues with wildfires; NiSource Inc., which had to sell Columbia Gas of Massachusetts to Eversource Energy following charges regarding violations of federal pipeline safety laws; and Southern Co., SCANA Corp., Eversource, Duke Energy Corp., and Dominion Energy Inc., which have all been engaged in large capital projects.

[1] https://www.spglobal.com/ratings/en/research/articles/200402-covid-19-the-outlook-for-north-american-regulated-utilities-turns-negative-11415155