The California Public Utilities Commission authorized cost recovery for Pacific Gas and Electric Company’s battery storage projects totaling about 567 megawatts to meet local capacity requirements, according to a resolution issued on Nov. 9. In January, the commission authorized the utility to hold competitive solicitations for storage or preferred resources to ensure local reliability in areas previously served by Calpine Corporation’s gas-fired plants that are at the risk of retirement. Pacific Gas and Electric will own a 182.5-megawatt project built by Tesla Inc. Dynegy Inc., Hummingbird Energy Storage LLC, and Micronoc Inc. will own the other three projects sized 300 megawatts, 75 megawatts, and 10 megawatts, respectively. Pacific Gas and Electric is a subsidiary of PG&E Corp. Dynegy is a subsidiary of Vistra Energy Corp.

The California Public Utilities Commission approved energy storage procurement proposals of the state’s large investor-owned utilities for the 2018 biennial procurement period, according to an Oct. 31 decision. The 2018 cycle is the third of the four solicitation cycles the commission directed the utilities to conduct following the 2010 Energy Storage Law. In 2013, California set a target of 1,325 megawatts by 2020, and has since added another 500 megawatts to the goal. The commission authorized Pacific Gas and Electric Company to hold a solicitation for up to 160 megawatts of storage for the cycle, and an additional 30 megawatts to make up for any shortfall due to project termination. In May, PG&E and Golden Hills Energy Storage LLC, a subsidiary of NextEra Energy Resources LLC, agreed to cancel a 30-megawatt project. The agency found that Southern California Edison Company and San Diego Gas & Electric Company have met their target for 2018 with existing resources and should not be required to conduct a solicitation for the cycle. SCE is in the process of selecting projects to meet its obligation under SB 801, which directed the company to procure 20 megawatts of additional capacity – that counts towards the storage goal – to address limitations resulting from gas supply constraints after the 2015 Aliso Canyon natural gas leak.

Pacific Gas and Electric Company proposed to create a commercial electric vehicle charging rate class, which would include two new rate schedules – EV-Small and EV-Large – to accelerate EV deployment and support for commercial customers, according to a Nov. 6 filing with the California Public Utilities Commission. The charges would feature a monthly subscription charge based on maximum charging capacity, and a time-of-use volumetric rate intended to encourage charging during times of higher renewable generation and lower marginal cost. The utility said that the proposal would replace demand charges with subscription pricing, allowing customers to select the required amount of power for their charging stations. This charge would be much lower than current demand charges and provide customers with simpler, more consistent monthly costs. The new rates are expected encourage investments in clean transportation by improving ownership costs for EV drivers, fleets, and charging infrastructure developers.

Governor Ralph Northam, a Democrat, announced that 15 percent of the Volkswagen Environmental Mitigation Trust will be used to deploy electric transit buses across Virginia, according to an Oct. 31 press release. The Department of Environmental Quality which is tasked with implementing Virginia’s allocation of $93.6 million from the Volkswagen settlement will provide the funding through a new program that will replace the heavy and medium-duty vehicles with cleaner ones. The project will be implemented under the Department of Rail and Public Transportation’s annual public transportation capital grant cycle, which begins Dec. 1 and runs through Feb. 1, 2019. In August, the department selected charging station company EVgo for a contract to develop a statewide public electric vehicle charging network. The two announcements account for 30 percent of state’s total allocation from the settlement. Last year, Volkswagen agreed to criminal penalty and pleaded guilty for selling vehicles that turned on full emissions controls during testing but lowered them during normal driving.

The Pennsylvania Public Utility Commission issued a final policy clarifying that third-party electric vehicle charging is not considered resale or redistribution of power, in a bid to remove regulatory uncertainty and support the continued build-out of charging infrastructure, according to a Nov. 8 press release. The commission directed electric distribution companies to revise tariffs to exclude third party charging from resale or redistribution pricing restrictions, and make provisions for owners and operators of charging stations to notify the companies of planned installations. The move stems from an inquiry launched in June 2017 to examine the differing interpretations of rules pertaining to resale of utility service by third party charging stations.

NorthWestern Energy plans to participate in the Energy Imbalance Market operated by the California Independent System Operator Corporation by April 2021, according to a Nov. 8 press release. The market is an automated system that secures the lowest-cost energy to serve real-time customer demand over a broad region spanning across multiple western states. The company said that participation in the market would result in lower costs for customers, more efficient use of renewables, and greater grid reliability. NorthWestern underscored the need to access other generation resources that are available on demand as Montana is experiencing a growth in wind generation. The market generated about $100 million in savings in the third quarter of this year, with total benefits reaching $502 million since its launch in November 2014. Since its launch, the market has delivered 734,437 megawatt-hours of renewable energy that otherwise would have been curtailed.

The U.S. Environmental Protection Agency on Nov. 7 reinstated a 2009 action clarifying “project aggregation” for the New Source Review permitting program that governs emission permits for building new or significantly retrofitted industrial facilities including power plants. Under the policy, the agency will combine multiple changes to a facility into a single project for permitting considerations if they are “substantially related.” In 2010, the Obama Administration had proposed to revoke the project aggregation action. EPA’s move is the latest in a series of actions to update the permitting program, as part of the Trump administration’s efforts to reduce regulatory burden. In January, the agency removed a 1995 Clean Air Act provision that disallowed reclassification of facilities categorized as “major sources” of hazardous air pollution even after their emissions drop below the major source threshold level of 10 tons per year.

U.S. electric utilities installed nearly 71 million advanced meters, accounting for about 47 percent of meters that were operational in 2016, according to the Federal Energy Regulatory Commission’s annual report on demand response and advanced metering. The report, issued by commission staff on Nov. 7, found that several states are considering large-scale smart meter projects, in some cases as part of their grid modernization initiatives. The agency said that demand response has experienced a surge, with potential peak demand savings from retail programs increasing by nine percent between 2015 and 2016 to nearly 36 gigawatts. Demand resource participation in the wholesale markets rose by about three percent from 2016 to 2017 to about 27.5 gigawatts. The number of customers enrolled in retail demand response programs in 2016 increased by eight percent, the highest since 2013. While enrollment in time-based rate programs has increased in most regions since 2013, the report identified slow implementation of these programs as the main barrier to customer participation in demand response. Several states have taken efforts to support time-based efforts via pilot programs, grid modernization efforts, or integration of electric vehicles. In addition to regulatory developments, nascent technological developments, such as blockchain technology and associated “smart contracts” to the energy sector, are expected to support meaningful response to prices.

PJM Interconnection LLC’s wholesale power markets work although “not perfectly,” and are faced with new challenges that potentially threaten their viability, according to Nov. 8 report from Monitoring Analytics LLC. The monitor questioned the ability of markets and the market-based regulatory construct to coexist with efforts to increase the role of renewable resources via nonmarket revenue. Although state policies that provide nonmarket payments for renewables are intended to lower emissions and not undercut competitive power markets, their impacts are real and growing. The unit-specific subsidy approach for existing uneconomic coal and nuclear power plants poses a threat to the market design and paradigm. If carbon is determined to be a pollutant with a negative value, it should be addressed with a market approach rather than a technology or unit specific subsidy approach and PJM should collaborate with states to consider a form of carbon pricing and revenue distribution that all the states could agree to, the report said. The monitor found that the level of potential retirements does not imply reliability or fuel security issues, noting that PJM will have excess reserves of almost 16,000 megawatts on June 1, 2019 and that nearly 21,912 megawatts of new generation are expected to go into service.

The Federal Energy Regulatory Commission extended the time Constitution Pipeline Co. LLC has to build the natural gas line until Dec. 2, 2020, according to a Nov. 5 order issued before the previous extension was set to expire. The Williams Partners LP’s project has been left in limbo by legal challenges and regulatory hurdles since Federal regulators approved construction in 2014. Earlier this year, FERC denied a requested to reconsider its decision to uphold the New York State Department of Environmental Conservation’s rejection of a water permit that’s put construction of the gas line on hold. The 125-mile link, which is designed to ship shale supplies from Pennsylvania to New York, has been met with resistance from landowners and environmental groups.

The U.S. Environmental Protection Agency on Nov. 8 released final state plan requirements to implement its 2015 standards for ground-level ozone. The rule applies to nonattainment areas and 13 northeastern states that comprise the ozone transport region. The rule allows flexibilities for states to consider factors outside their control, such as international pollution. The EPA said it is committed to maximize flexibility for regulatory relief noting that background and international emissions contribute significantly to air quality issues.The rule follows a memo issued by President Trump in April directing the agency to ensure efficiency and cost-effectiveness in implementing air quality standards. The agency said that since 1990, “this is the fastest” that state plan requirements have been finalized for a revised ozone standard. Emissions of nitrogen oxides, the main precursor for ground-level ozone, dropped by over 40 percent in the last decade and the majority of U.S. states are expected to attain the 2015 standards by the early 2020s. The Clean Air Act requires EPA to set standards for pollutants that are considered harmful to public health and the environment, and review them periodically. The agency must designate areas based on their attainment of the standard and develop plans to attain and maintain the standards. EPA revised the standards for ozone on Oct. 1, 2015.

The U.S. Energy Department authorized a unit of Cheniere Energy Inc. to export liquefied natural gas equivalent to 2.1 billion cubic feet per day from the Corpus Christi Liquefaction facility in Texas to non-free trade agreement countries over the next two years, according to a Nov. 2 press release. The move allows for the initial commissioning volumes from the facility. The order takes effect Dec. 31 or the date of the first export from the facility, whichever occurs first. The $15 billion facility, which represents the first large-scale export project in Texas, is one of four additional LNG export projects expected to be completed over the next two years. Upon completion, these projects are expected to increase U.S. LNG export capacity to about 11 billion cubic feet per day. There are currently two major export projects in operation, Sabine Pass and Dominion Cove Point, which have a combined export capacity of approximately 3.5 billion cubic feet per day. The U.S. exported over 1.5 trillion cubic feet of natural gas since 2016 when LNG exports began, and has reached 30 destinations.

The Federal Energy Regulatory Commission on Nov. 5 authorized AltaGas Power Holdings (U.S.) Inc. to sell its interests in AltaGas San Joaquin Energy Inc., which owns three natural gas power plants, to SJ Power Holdings LLC. The power generated by the facilities, which have a combined capacity of 523 megawatts, is fully committed under long-term power purchase contracts with Pacific Gas and Electric Company. AltaGas San Joaquin Energy is a subsidiary of AltaGas Ltd. SJ Power is a subsidiary of Middle River Power III LLC which is controlled by two individuals. Pacific Gas and Electric is a subsidiary of PG&E Corp.