The Connecticut legislature passed legislation on May 6 that would require the Energy and Environmental Protection Department in consultation with the Green Bank to create a shared clean energy program by Dec. 1. The bill would require electric distribution companies Eversource Energy and United Illuminating Company to operate the program and recover reasonable costs incurred through rates. A shared clean energy facility would comprise of a solar or wind source of up to 5 megawatts. The program would allow participation of 300 megawatts of aggregate capacity. United Illuminating is a subsidiary of Avangrid Inc. which is owned by Iberdrola SA. (SB 00336)

The Virginia State Corporation Commission issued a ruling on May 7 finding that Virginia Electric and Power Company’s proposal to offer 100 percent renewable energy plans to its larger customers would give the company too much discretion in setting prices. The company proposed two options for customers with less than one megawatt of peak demand to displace 100 percent of their electricity with renewable generation at rates based on market prices, according to its November 17 application. Virginia Electric and Power Company is a subsidiary of Dominion Energy Inc.

Vineyard Wind LLC filed a draft environmental review for its 800-megawatt offshore wind project in the federally-designated wind energy area off Massachusetts, according to a May 1 filing with the Massachusetts Department of Public Utilities. The Vineyard Wind Connector project would link with the New England power grid and would help the state meet a goal to secure 1,600 megawatts of offshore wind within the next decade. The company expects to start construction in 2019 and become operational by 2021. Vineyard Wind LLC is co-owned by Copenhagen Infrastructure Partners and Avangrid Renewables. Avangrid is owned by Iberdrola SA.

A string of typographical errors in contracts by Portland General Electric Company lie at the heart of a dispute between the Oregon utility and a coalition of power producers eager to sell power under coveted long term contracts. The producers argued in an April 23 complaint with the Oregon Public Utilities Commission that Portland General used the excuse of errors to avoid entering into contracts before May 1, when the payout rates to alternative energy suppliers are due to be lowered. The groups asked the commission to direct Portland General to complete all contracts that had been initiated and to delay the rate cuts until all affected power purchase agreements are executed. Chief Administrative Law Judge Michael Grant said in an April 27 email that he will consider the power producers’ request for injunctive relief prior to the May 22 meeting when the commission is slated to consider the rate cut. Complainants are Northwest and Intermountain Power Producers Coalition, Renewable Energy Coalition and the Community Renewable Energy Association.

Idahydro, Shorock Hydro Inc., J.R. Simplot Company, and Renewable Energy Coalition asked the Idaho Public Utilities Commission to revisit a provision that allows utilities to pay a lower market-based rate, rather than the avoided cost rate, to small hydropower, cogeneration, biomass, and baseload qualifying facilities when their output did not fall within a prescribed range, according to the commission’s May 8 notice. The provision, called “90/110 Performance Band,” applies when the output is less than 90 percent or more than 110 percent of projections, and in 2007 the commission eliminated the provision for wind facilities that agreed to provide a guarantee of their output and share the cost of forecasting services. The petitioners sell or are attempting to sell their output to IDACORP Inc. subsidiary Idaho Power Company under the Public Utilities Regulatory Policy Act of 1978 that requires utilities to buy power from independent producers called qualifying facilities at commission-approved avoided cost rates. They argue that hydropower and other non-wind and non-solar facilities are predictable enough in the aggregate, enabling the company to incorporate their variability in its planning and operations.

U.S. Solar-powered generation has seen continued growth in recent years reaching 77 million megawatt-hours in 2017, overtaking biomass which has remained relatively unchanged representing 64 million megawatt-hours, according to a May 9 report from the Energy Information Administration. Hydropower remains the top renewable source generating 300 million megawatt-hours followed by wind that accounted for 254 million megawatt-hours. The agency underscored the consistent growth in solar photovoltaic systems, with large-scale systems representing 50 million megawatt-hours in 2017, up from 15 million in 2014.

The Southwest Power Pool Inc. saw a seven percent boost in its monthly real-time generation during the winter period from December 2017 through February compared to the previous winter period, according to the grid operator’s May 1 market report. Coal-powered generation dropped to 46 percent from 52 percent in the previous winter, while wind accounted for 26 percent of generation, up from 23 percent. The region set a new peak of 15,690 megawatts of wind generation on December 16. The report said that energy prices were low, with winter prices averaging around $24 per megawatt-hour. The Missouri-Kansas-Oklahoma area experienced high prices due largely to congestion created by high levels of wind generation.

New Jersey’s solar industry has completed 90,000 solar projects over the past 18 years, reaching over 2.4 gigawatts of installed solar generating capacity, according to a May 2 press release from the New Jersey Board of Public Utilities. This year, the state completed 3,137 solar projects from January through March. Since 2003, the state’s clean energy program has been providing incentives to residential customers, businesses, and local governments to install renewable energy generators.

The Connecticut legislature approved legislation on May 7 that would set a July 1 deadline for municipal electric companies to determine whether to implement rate design standards such as cost of service, time of day, and seasonal rates. Current law requires a determination within two years, but does not specify the date. Municipal utilities that have already completed the study would be exempt from the requirement. (SB 00333)

Kansas City Power & Light Company, a subsidiary of Great Plains Energy Inc., asked the Kansas State Corporation Commission to approve a 4.5 percent hike, or $26.2 million increase, to its rates after taking into account the federal Tax Cuts and Jobs Act that would result in about $34.5 million in ongoing annual savings to customers, according to a May 1 filing. The utility seeks to recover costs associated with a new customer information system and increase in depreciation expenses. The utility said that approval of its proposed merger settlement with Westar while the rate update is pending would extend to customers $39.3 million in one-time savings and $18.3 million in ongoing annual savings. The utility is also proposing rate design changes for pilot programs to implement demand and time of use rates, as well as new demand rates for residential customers and standby tariff for commercial customers with onsite generation.

Kansas City Power & Light Company, a subsidiary of Great Plains Energy Inc., asked the Kansas State Corporation Commission to approve a 4.5 percent hike, or $26.2 million increase, to its rates after taking into account the federal Tax Cuts and Jobs Act that would result in about $34.5 million in ongoing annual savings to customers, according to a May 1 filing. The utility seeks to recover costs associated with a new customer information system and increase in depreciation expenses. The utility said that approval of its proposed merger settlement with Westar while the rate update is pending would extend to customers $39.3 million in one-time savings and $18.3 million in ongoing annual savings. The utility is also proposing rate design changes for pilot programs to implement demand and time of use rates, as well as new demand rates for residential customers and standby tariff for commercial customers with onsite generation.

The Office of Consumer Counsel, Connecticut’s ratepayer advocate, asked the Connecticut Public Utilities Regulatory Authority to examine whether electric supply choice is appropriate for customers classified as “hardship cases” who are under financial distress, according to an April 30 filing. The office said that placing such customers on standard service would support the agency’s objective to curb uncollectible expenses subsidized by general class ratepayers through electric distribution companies’ programs. The situation of hardship customers could worsen if electric supply charges exceed standard service rates and also raise the uncollectible expenses. The office pointed to a two-year study from the Massachusetts Attorney General’s office showing that Massachusetts low-income households enrolled with competitive suppliers were twice as that of other households and paid 17 percent more than if they had received service from their utility.

California’s grid operator projects that below-average hydroelectricity supplies combined with 860 megawatts of generation retirements since last summer will leave the system with low power reserves during the night, when solar plants aren’t generating, and may require the emergency dispatch of power plants. The California Independent System Operator Corp. projects peak demand to be about the same as last year at 50,116 megawatts.

PJM Interconnection LLC anticipates a hotter-than-normal summer leading electricity use to peak at about 150,000 megawatts over the coming months, around 5,000 megawatts more than last year, according to a May 7 press release. The operator of the nation’s largest electric grid is preparing for above-average temperatures by securing a 28 percent reserve margin, which represents nearly 41,000 megawatts of capacity on hand to meet the added electricity consumption. Demand on the system hit a record of 165,492 megawatts in the summer of 2006 as sweltering conditions drove up the use of energy-intensive air conditioners.

The Puerto Rico Electric Power Authority, manager of Puerto Rico’s grid, is working with the New York State Smart Grid Consortium, a public-private partnership for grid modernization, and ProsumerGrid Inc., a software developer, to simulate the impact and potential for integrating distributed energy resources like solar power, small wind power and battery systems into the island’s electrical network, according to a May 9 press release from the U.S. Energy Department. The initiative is the latest in a string of measures by regulators and system operators to adapt the grid to a proliferation of distributed generation, and make it more resilient to storms, like Hurricanes Irma and Maria.

The U.S. Energy Department on May 1 announced funding opportunities for advanced electric vehicle projects focused on batteries and electrification including cyber security, materials for lighter weight vehicle structures and powertrains, as well as technology integration for overall system efficiency. The department also announced funding for a new program called “Duration Addition to electricity Storage,” or DAYS, to facilitate long-duration energy storage that can last up to 100 hours. The department is observant of the critical role of storage in the future grid with the ability to improve grid stability, provide backup power, and support renewable integration.

The Idaho Public Utilities Commission on May 9 ordered Idaho Power Company, a subsidiary of IDACORP Inc., to close its current net-metering program and create two rate classes for residential and small general service on-site generation customers. The commission determined that the difference in electricity consumption patterns and demand characteristics justifies the separation, and also directed the utility to conduct a study of the costs and benefits of net metering to determine rate design and compensation for excess generation. Under the current program, launched in 1983, customer generators can offset their consumption by exporting excess energy and have remained in the same customer class as standard service customers. Last July, the utility sought new classes contending that net metering customers do not pay for the transmission and distribution of exported energy and pass on these fixed charges to standard customers.

An extended minimum offer price rule or “MOPR-Ex” is a better way to limit the impact of state subsidies on markets compared to PJM Interconnection LLC’s repricing proposal that could allow subsidized units to displace competitive units, according to a May 10 report by Monitoring Analytics LLC. The market monitor also underscored the need for a market approach rather than a “technology- or unit-specific subsidy approach” whether it is to boost revenues for specific technologies or price carbon. Pointing to developments in Ohio, Illinois, New Jersey, and Pennsylvania to prop up nuclear plants, the report notes that the subsidies were requested by owners of specific uneconomic units to improve their profitability rather than accomplish broader social goals, which can be met with market mechanisms on a competitive basis without discrimination. The report notes that potential retirements do not imply a reliability issue as PJM will have excess reserves of more than 15,000 MW on June 1.

Unplanned reactor retirements are projected to cut total U.S. nuclear generating capacity to 79 gigawatts by 2050 from 99 gigawatts in 2017, according to a May 8 report from the U.S. Energy Information Administration. The economics of nuclear generation are being adversely impacted by competition from lower-cost gas-fired plants, growing renewable generation, and moderation in electricity demand. With over half the existing fleet operating in deregulated wholesale markets where natural gas sometimes sets the marginal prices for electricity, lower natural gas prices could force more retirements. Potential policies that price carbon emissions would boost wholesale electricity prices, allowing nuclear power plants to become more economically competitive. Based on various study scenarios, the agency found that lower natural gas prices could cause nuclear capacity to plummet to 55 gigawatts by 2050, whereas a fee of $25 per ton of emissions increasing at 5 percent per year from 2020 could boost nuclear capacity to 145 gigawatts in 2050.

The West Virginia Department of Environmental Protection issued a letter May 2 ending its cease and desist order imposed on parts of Energy Transfer Partners LP’s 713-mile Rover natural gas pipeline. The environmental regulator had ordered a halt to construction until a full inspection was undertaken following more than a dozen environmental violations, according to a March 5 order.

The Florida Public Service Commission approved two natural gas-fired power plants determining there is need for the additional generation to meet power demand, according to the commission’ May 8 press release. The plants will use existing transmission and water resource infrastructure, allowing the utility to save money. Seminole Electric Cooperative Inc.’s 1,122-megawatt facility in Putnam County plans to become operational in December 2022. Shady Hills Energy Center LLC, a subsidiary of General Electric Company, will build a 573-megawatt facility in Pasco County to begin service in December 2021, and sell its power output to Seminole.

The U.S. Energy Department is seeking information to develop modular coal-based power plants built with advanced methods to meet the requirements of the evolving electric grid, according to the department’s May 8 press release. The department expects the small-scale design to be cheaper, more efficient, low-emitting, and operationally flexible. In February the department announced funding for carbon capture and transformational coal technologies. The Trump administration has been exploring ways to aid the coal industry, which has seen its fortunes dim with the advent of cheap, abundant natural gas.

The Alberta government, in a May 10 filing with the Minnesota Public Utilities Commission, said that it supports Enbridge Inc’s preferred rout for the Line 3 oil pipeline replacement project, arguing that using the existing path, as recommended by a commission judge, would require the pipeline to be shut down for an extended period of time, causing service disruptions. Enbridge currently meets 80 percent of the demand in Minnesota and 70 percent in the broader Midwest. The Alberta government said that shifting current volumes to other lines could reduce available capacity, potentially raising the price differential between the Western Canadian Select and West Texas Intermediate. A prolonged shutdown would prompt shippers to increase crude oil by rail, affecting transport of other goods in the rail network that is already congested. Last month, administrative law judge Ann O’Reilly recommended approval of an “in trench” replacement alternative in which existing Line 3 would be removed and the new pipeline placed in the same trench for most of the route. Enbridge’s preferred route consists of a new route segment for nearly 50 percent of the line. The Line 3 project is designed to fully replace 1,031 miles of pipeline between Hardisty, Alberta, and Superior, Wisconsin.

The Washington Utilities and Transportation Commission accepted the 20-year energy resource plans of the state’s investor-owned utilities Avista Corporation, Pacific Power, and Puget Sound Energy Inc., but expressed concern over the costs of continued operation of their coal-fired power plants and the economic risk posed by future investment in those generation sources, according to the commission’s May 7 press release. The commission directed the utilities to assess those costs, and also examine developments in carbon policy to incorporate the cost of emissions regulations in in their long-term portfolios. The utilities are required to update their resource plans every two years detailing the state of their energy mix to meet future demand. Pacific Power is a unit of PacifiCorp, and Puget Sound Energy is a subsidiary of Puget Energy Inc.