The Nevada Public Utilities Commission announced that it’s lowering the credits that it awards to customers for excess generation exported onto the grid to 88 percent of the retail electricity rate, from 95 percent, after new and existing solar capacity on the system topped 80 megawatts. Legislation passed in June 2017 that reinstated net metering set a tiered system to reimburse customers at slightly less than the retail rate of electricity, starting at 95 percent and decreasing in 7-percent increments for every 80 megawatts of supplies that are added, with a floor of 75 percent. Payouts for power from customer-sited renewables are falling from Nevada to South Carolina amid a flood of supplies of the zero-emitting generation.

The Illinois Power Agency finalized its first long-term plan for renewable procurements and programs for the years 2018 and 2019 to meet the state’s stronger renewable portfolio standard targets, according to an Aug. 6 filing with the Illinois Commerce Commission. The measure follows legislation enacted in 2016 that required a separate plan for procuring renewable energy certificates, or RECs, for utilities, rather than including renewable procurement in the agency’s annual plan, which now deals with electricity and wholesale products for utilities. The update retains the goal of 25 percent by 2025, but applies the goal to all retail customers beyond those on utility service, thus increasing the quantity of RECs, and phases out obligations for alternative retail electric suppliers. The revisions include a public interest criteria for RECs from neighboring states and prohibit certificates from facilities that recover costs via regulated rates. Utilities must develop an adjustable block program that includes administratively determined REC prices, a change from the prior competitive procurement model. Wind and solar carve-outs are expressed as a minimum number of RECs rather than a percentage of load. The agency seeks approval of the proposed targets, budget estimates for utilities, procurements, adjustable block program design, and community and low-income program terms.

The U.S. Bureau of Land Management found that First Solar Development LLC’s 450-megawatt Desert Quartzite Solar Project in eastern Riverside County, California, will result in temporary exceedances of air quality standards, temporary visual qualify impacts from dust, and potential groundwater contamination from releases of fuels and other materials, according to a draft environmental review from the agency. First Solar’s project includes a photovoltaic facility, battery storage, and a 3-mile gen-tie transmission line spanning about 3,800 acres of public lands. The project is estimated to avoid 787,500 metric tons of carbon emissions per year.

The Florida Public Service Commission clarified that Vivint Solar Developer LLC can offer residential solar equipment leases in the state, according to the agency’s Aug. 7 press release. The commission agreed that the company’s 20-year, fixed-payment lease is not a retail sale of electricity. Vivint Solar proposed the lease as a financing option to homeowners who are not prepared to or cannot afford to pay upfront for solar installations. At the end of the lease period, customers may buy the equipment at fair market price, renew their leases annually, or request removal at no extra cost. Last year, the state enacted legislation permitting the leasing of distributed energy generation systems.

New York Governor Andrew Cuomo, a Democrat, announced on Aug. 8 that the New York Power Authority will lead a research initiative to study successful offshore wind transmission models, particularly large-scale European projects, to guide the state toward achieving the goal of 2.4 gigawatts of offshore wind by 2030. The agency will explore the advanced technologies used in the transmission and interconnection models currently deployed in Europe. The study will help determine the appropriate infrastructure design, identify best practices in connecting wind power to the gird, and reduce power delivery costs. In the initial phase, the agency will collaborate with the New York Independent System Operator, New York State Energy Research and Development Authority, Long Island Power Authority, and Consolidated Edison Inc. Last month, the Public Service Commission announced the first phase of solicitations in 2018 and 2019 for about 800 megawatts of offshore wind and set the stage for the next phase to examine transmission solutions for longer-term configurations, as well as ownership and planning processes. The study results are expected this fall.

The Maine Public Utilities Commission decided to re-examine its approval in 2014 of 20-year offshore wind contracts for the 12-megawatt Maine Aqua Ventus I offshore wind pilot program in light of changing market conditions that may have caused the project to fall short of statutory requirements, according to an Aug. 6 order. The commission said that the final costs and financing plan should be updated as the developer continues to secure additional funding through the U.S. Energy Department’s Advanced Technology Demonstration Projects for Offshore Wind. The contracts, between Maine Aqua Ventus I and Central Maine Power Company, stem from legislation enacted in 2010 and 2013 that required competitive solicitations for deep-water offshore wind pilots or tidal energy demonstrations projects. Maine has been slow to embrace wind energy, with Governor Paul LePage, a Republican, imposing a ban on new wind turbines over concerns that the state’s $6-billion tourism industry could be adversely impacted. The New England Aqua Ventus I project is a collaborative effort of Cianbro Corporation, University of Maine and the Advanced Structures and Composites Center, and Naval Energies. Central Maine Power is a unit of Avangrid Networks Inc., which is owned by Iberdrola SA.

EDF Renewable Energy Inc. and Fishermen’s Energy of New Jersey LLC filed a joint application with New Jersey regulators for approval of the 24-megawatt Nautilus Offshore Wind project, proposed off the coast of Atlantic City, according to an Aug. 6 press release by the developers. New Jersey has a goal of developing 3,500 megawatts of offshore-wind capacity, the most aggressive goal of any state. Following Democratic Gov. Phil Murphy’ executive order that set the goal in January, EDF entered into a preliminary agreement with Fishermen’s Energy to buy the fully developed wind project. Under legislation enacted earlier this year, the Board of Public Utilities has 90 days to review the proposal. The project is expected to come online by 2020. EDF Renewable Energy is a subsidiary of EDF Energies Nouvelles S.A.

Solar photovoltaic cells were the second-most popular technology installed in 2016, after wind turbines, as average construction costs of the projects have dropped to $2,436 per kilowatt, a 34 percent fall from $3,705 per kilowatt in 2013, according to an Aug. 8 report from the U.S. Energy Information Administration. The agency said that crystalline silicon technology has matured, making it the least expensive and most widely used photovoltaic technology, compared to thin film technology. Onshore wind generator costs decreased slightly to $1,630 per kilowatt in 2016 from the prior year, and costs tend to be lower for larger plants as siting and infrastructure costs are shared across more turbines. Solar photovoltaics, onshore wind, and natural gas added 8 gigawatts, 8.8 gigawatts, and 9.8 gigawatts, respectively, of generation capacity 2016. These technologies accounted for about 93 percent of new capacity in 2016, which saw a 50 percent rise in electric generation investments compared to the prior year.

New Jersey-based Footprint Power LLC asked the Federal Energy Regulatory Commission to reject the sanctions proposed by the Office of Enforcement on its Salem Harbor power plant in Massachusetts, arguing that the allegations don’t match up with the facts, according to an Aug. 3 filing. Footprint said that ISO New England Inc. was aware that it was unable to run the plant at maximum output for 24 hours due to limitations posed by start-up and ramp times and that the grid operator had itself incorporated these limitations into the facility’s day-ahead offers. Further, the facility was subject to a daily air-emission limit that restricted operations. The company argued that the office never asked ISO New England if it was misled, and also pointed to taped phone calls showing that the plant operators had repeatedly warned the grid operator about potential uncertainty of the plant’s availability. In June, the commission’s staff proposed a $4.4 million fine and disgorgement of profits, finding that the company submitted supply offers in New England’s capacity market that it couldn’t meet because of a lack of fuel supplies. In its answer, Footprint also noted that the allegations are time-barred as they exceeded the five-year deadline for court action, and further said that that extracting over $6 million in sanctions would violate due process, given that other suppliers would face minor tariff-based penalties that must follow a collaborative process. The company said it is prepared to meet with the commission to discuss the issues, describing that the allegations amount to a “conundrum where every option is a violation.

Ninety-five percent of Puerto Rico’s electricity customers had electric service as of April 2018, according to an Aug. 6 report from the U.S. Energy Information Administration, marking the final chapter in the restoration of the island’s grid, which was destroyed by hurricanes Irma and Maria in 2017. However, for about 62,000 customers, the longest outage in U.S. history still continues. The agency said that total electricity sales returned to pre-hurricane levels as of April and May, but residential sales have not picked up as much, reflecting some continued outages.

The District of Columbia Public Service Commission approved a settlement that addresses Potomac Electric Power Company’s electric distribution rates resulting from the federal tax law that took effect Jan. 1, according to the agency’s Aug. 10 press release. The agreement lowers Pepco’s distribution revenue by $24.1 million, and returns at least $19.25 million in deferred taxes accrued from January until the new rates take effect. Pepco also agreed to a moratorium on rate investigations or filing base rate changes until May 2019. The company initially sought a $65.7 million increase in its revenue requirement. Potomac Electric is a subsidiary of Pepco Holdings LLC, which is a unit of Exelon Corp.

The results of PJM Interconnection LLC’ capacity auction held in May for the 2021-2022 delivery year were not competitive because of issues with the definition of the offer caps, according to an Aug. 9 report from the market monitor Monitoring Analytics LLC. The monitor analyzed 21 scenarios, such as inclusion of seasonal products, effect of nuclear offers, and impact of noncompetitive offers, to quantify their market outcomes. If the noncompetitive offers identified by the monitor had been capped at their net avoidable cost rate, or ACR, the clearing price would have fallen to $90.47 per megawatt hour day from the actual price of $140.53, and the total revenue would have been $6.57 billion instead of the actual $9.3 billion, according to the analysis. The monitor concluded that offers above net ACR were allowed under market rules, but were inconsistent with competitive offers based on a properly calculated offer cap, and hence resulted in “economic withholding” by resources. In its response, PJM said that the auction complied with “tariff-specified requirements” approved by the Federal Energy Regulatory Commission and that the monitor itself confirmed that the results correctly reflect the application of offer caps. PJM also noted that sellers submit offer caps they intend to apply 120 days prior to the auction and the monitor, having access to relevant data, could have consulted the asset owner to address possible economic withholding and refer such sellers to the commission for investigation.

The Minnesota Public Utilities Commission directed the state’s investor-owned utilities to refund about $200 million in annual savings resulting from the federal tax law, which slashed the corporate income tax to 21 percent from 35 percent, according to the agency’s Aug. 9 press release. The reductions also reflect decisions in general rate cases including $21.3 million for CenterPoint Energy Resources Corp. and $18.7 million for Minnesota Power Company, and a pending decision estimated at $5.2 million for Minnesota Energy Resources Corporation. The commission also ordered Xcel Energy Inc. to invest $2 million of its $130 million in annual tax benefits in the “POWER On” program, which helps low-income households with their electric bills. CenterPoint Energy Resources is a subsidiary of Utility Holding LLC. Minnesota Energy Resources is a subsidiary of Integrys Holding Inc.

Georgia Power Company, a subsidiary of Southern Company, announced that the cost for its share of the Vogtle 3 & 4 nuclear generating units in Georgia increased to $8.4 billion from $7.3 billion, according to an Aug. 8 press release. Georgia Power, which has a 45.7 percent stake in the project, said it will absorb $700 million of the additional costs, with no impact on customer bills. The company said the revisions stem from decisions to provide labor incentives to maintain staffing levels and ensure stronger oversight to lower risks and keep up the project momentum. Last August, Georgia Power took over as the main contractor, following the bankruptcy of developer Westinghouse Electric. The U.S. Energy Department committed $1.67 billion in additional loan guarantees for the project and Toshiba, the parent company of Westinghouse, fulfilled a $3.68 billion parent guarantee for the plant’s co-owners. Oglethorpe Power Corporation, Municipal Electric Authority of Georgia, and Dalton Utilities own 30 percent, 22.7 percent, and 1.6 percent, respectively, in the plant. Vogtle is the only nuclear plant currently under construction in the U.S.

The New York Public Service Commission authorized Consolidated Edison Company of New York Inc. to implement a $5 million demand reduction pilot aimed to demonstrate the ability of customers to reduce natural gas use over three years, according to the agency’s Aug. 9 press release. The pilot will allow third-party demand-response aggregators to collaborate with customers in exploring innovative solutions to reduce gas consumption on peak days. The first component of the pilot will be similar to the electric peak-shaving program for commercial and industrial customers, while the second component will resemble the smart thermostat program for residential and small-commercial customers. The program complements the natural gas efficiency program approved in July as part of the utility’s strategy to reduce gas usage and procure alternative resources to address a growing shortfall of peak gas day pipeline capacity. The commission said that these programs will facilitate alternatives to the traditional business model to meet customer needs and is committed to work with the state’s gas utilities to implement successful non-pipes alternatives without compromising the natural gas system resiliency and safety. The utility is a subsidiary of Consolidated Edison Inc.

Massachusetts Governor Charlie Baker, a Republican, signed legislation on Aug. 9 that strengthens the state’s renewable portfolio standard by requiring a 2 percent boost in procurement of the supplies each year from 2020 to 2029, up from the current 1 percent annual increase. The current goal requires 15 percent by 2020, followed by a one percent increase each year. The bill also creates an energy storage target of 1,000 megawatt-hours by 2025, up from the current goal of 200 megawatt-hours by 2020. It requires an analysis to determine whether the state should procure an additional 1.6 gigawatts of offshore wind, and includes a “clean peak standard” requiring retail electricity suppliers to annually increase their kilowatt-hour sales from clean energy resources during seasonal peak demand hours. Baker also signed legislation that authorizes borrowing of up to $2.4 billion to fund programs that promote climate change adaptation, environmental protection, and recreational assets. (H 4857, H 4835)

The Hawaii Public Utilities Commission approved a long-term power purchase contract between Maui Electric Company Limited and Molokai New Energy Partners for a solar-plus-battery project capable of meeting about 40 percent of the island’s electricity demand. The approximately 5-megawatt photovoltaic project, combined with a 3-megawatt battery, is projected to slash the island’s reliance on diesel to produce electricity, allowing lower-cost renewable power to supplant expensive fossil fuel generation. Customers are expected to benefit from savings of $4.63 in 2019 and $35.92 in 2024 in monthly electric bills. The project is expected to come online in the second quarter of 2019. Molokai New Energy Partners is owned by Half Moon Ventures LLC.

The U.S. Court of Appeals for the Fourth Circuit vacated a federal right-of-way authorization for the Atlantic Coast Pipeline to cross the Blue Ridge Parkway, finding that the National Park Service invoked inapplicable laws to issue the permit and failed to ensure consistency with the scenic value and conservation goals of the park system, according to an Aug. 6 order. The court also clarified its May 15 order that invalidated a Fish and Wildlife Service permit, explaining that the agency failed to properly evaluate the project’s impact on five species covered by the Endangered Species Act. The decision comes on the heels of the Federal Regulatory Commission order halting work on the Mountain Valley natural gas pipeline due to a court decision that vacated two federal approvals. The Atlantic Coast project is a $5 billion, 604-mile natural gas pipeline that would extend from West Virginia into Virginia and North Carolina. The project is a joint proposal by Dominion Energy, Duke Energy, Piedmont Natural Gas, and Southern Company Gas. It received federal approval last October. The case is Sierra Club v. National Park Service. (18-1082)

The Bureau of Land Management is seeking public input on the environmental impacts of oil and gas development on 400,000 acres of public land and an additional 1.2 million acres of federal mineral estate in eight counties in California. The agency is considering an environmental review and potential amendment of a 2014 resource management plan to analyze issues related to air, water, seismicity, and mineral resources. Comments are due by Sep. 7.

The New York Department of Environmental Conservation rejected Competitive Power Ventures Inc.’s application to renew an environmental permit for its Valley Energy Center, forcing the generator to shut operations until a new license is obtained, according to the agency’s Aug. 1 notice. The agency said that the plant owner has failed to apply for a Title V clean air permit, which is now required to run the facility under new rules. The plant’s permit expired on July 31. The 680-megawatt natural gas-fired combined-cycle plant, located in Wawayanda, New York, had previously run on ultra-low sulfur diesel. The company has 30 days to request a hearing.

The Federal Energy Regulatory Commission on Aug. 6 authorized Florida Southeast Connection LLC to acquire the 38-mile Riviera Lateral gas pipeline and related facilities from Florida Power & Light Company. The project will add up to 384,000 dekatherms per day of firm transportation service and are said to benefit Florida Southeast’s customers as the facilities will be made available on an open-access basis, allowing any qualified shipper to use the facilities. Currently, Florida Power & Light is the only user of the line. In 2016, Florida Southeast Connection was approved to build the pipeline, which extends from an interconnection with Sabal Trail to Florida Power & Light’s Martin plant, where the delivered gas is used to generate power or sent via the Riviera Lateral to supply the Riviera Beach Clean Energy Center. The companies are subsidiaries of NextEra Energy Inc.

The Pennsylvania Department of Environmental Protection announced an additional fine of $148,000 levied against Energy Transfer Partners LP’s Sunoco Pipeline LP after construction on its Mariner East 2 pipeline was linked to degraded water quality in three counties. Residents in Chester, Berks and Lebanon counties reported cloudy, turbid, discolored or lost water supplies. Sunoco also failed to promptly issue notifications of the impacts in one of the counties, according to the agency press release. The 350-mile underground natural gas liquids pipeline, which is the second phase of the $3 billion Mariner East project, has faced repeated delays, penalties and legal challenges. In February the project drew a $12.6 million civil penalty for permit violations. The project was also recently hit with a penalty of about $356,000 for violations that occurred from May 2017 through February, as a result of the discharge of drilling fluids into wetlands and streams. Last month, the agency reached a settlement agreement with environmental groups, which calls for the regulator to improve environmental protection procedures associated with building natural gas pipelines in the state.