Massachusetts lawmakers approved legislation on July 31 to strengthen 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 would also create an energy storage target of 1,000 megawatt-hours by 2025, up from the current goal of 200 megawatt-hours by 2020. The bill requires an analysis to determine whether the state should procure an additional 1.6 gigawatts of offshore wind. The measure 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, when the highest polluting, most expensive generation is dispatched. (H 4857)

NRG Community Solar LLC lodged a protest over the lower-than-expected credits Central Hudson Gas and Electric Corp. and Orange and Rockland Utilities Inc. said that they will award for power from community solar projects, with the developer arguing that the reduced rates jeopardize the viability of its renewable facilities. NRG said that it was recently and unexpectedly informed by Central Hudson and Orange and Rockland that because of the size and the type of grid connection of its community solar facilities, the projects fall under the utilities’ demand rate class, which will cut by up to half the economic value of the credits provided. NRG said that the utilities’ interpretation of the rules and the lower rates are inconsistent with the position of the New York Public Service Commission, which called for a non-demand rate classification that offers a more generous volumetric credit to account for the fact that most of the customers will be smaller in size. NRG Community Solar, a unit of NRG Energy Inc., said it has invested millions of dollars primarily in the territory of Central Hudson and Orange and Rockland.

The Massachusetts Department of Energy Resources reached a compromise proposal with stakeholders regarding ownership capacity rights of facilities under net metering and, Solar Massachusetts Renewable Target or SMART programs participating in the ISO New England Inc.’s forward capacity market. The agreement would allow owners of storage facilities to retain their rights to bid capacity into the New England market. Electric distribution companies would hold capacity rights for Class II and Class III net metered and SMART facilities, under two options – retain 20 percent of capacity market proceeds or use 100 percent of the proceeds to offset program costs. Developers would have the opportunity to buy out the capacity rights of those facilities from the utility except for standalone solar not paired with storage. The SMART program, announced last January, is a 1,600 MW AC declining-block program, which includes a tariff-based compensation for solar projects as well a non-net metering bill crediting option. Stakeholders include Attorney General’s Office, National Grid plc, EverSource Energy, Northeast Clean Energy Council, Borrego Solar Systems Inc., EnerNOC Inc., Engie Storage, SunRun Inc., and Tesla Inc. EnerNOC is a subsidiary of Enel Green Power North America Inc.

The California Independent System Operator Corporation proposed enhancements to demand response resources participating in its markets, including new bidding and real-time dispatch options. The proposal also includes an energy storage load-shift product that would allow a resource to be dispatched for both load consumption and curtailment. The changes represent the third phase of the grid operator’s storage and distributed resources initiative, which aims to remove barriers to the participation of storage and distribution-connected resources in California’s power markets. The changes would also apply to demand response participation models used in the energy imbalance market, an automated system to find the lowest-cost energy to serve real-time customer demand over a broad region spanning across multiple western states. The proposal is subject to approval from the ISO board with advisory input from the governing body of the energy imbalance market.

The U.S. Court of Appeals for the District of Columbia Circuit on July 31 rejected challenges to ISO New England Inc.’s rules that provide an exemption to the minimum offer price rule, or MOPR, for certain renewable resources participating in the capacity market. In 2014, the Federal Energy Regulatory Commission approved revisions to allow up to 200 megawatts of state-sponsored renewable capacity to submit price offers below the MOPR from the ninth auction for the 2018-2019 commitment period, and allow up to 600 megawatts of unused portion of the capacity to be carried forward to two subsequent auctions. The reforms also replaced the vertical demand curve with system-wide sloped curve that procures capacity to meet variable demand set by supply prices, rather than a fixed demand. Petitioners, comprising power generators, utility holding companies, and distribution and sales companies, argued that the exemption undermines competition and causes price suppression. The court deferred to the commission’s conclusion that the potential for price suppression is limited because of the sloped demand curve, low cap on the exempted capacity, and expectations of lower load growth. The decision is a win for state policies supporting specific resource types. The case is NextEra Energy Resources LLC, et al v. FERC (17-1110).

Over a dozen states renewed calls for the Federal Energy Regulatory Commission to reconsider its decision to re-write the rules for the nation’s largest, multi-billion-dollar capacity market to address an influx of subsidized generation, arguing that the sweeping changes unlawfully intrude on state energy policies. The coalition, called the Organization of PJM States Inc., said that the overhaul wasn’t needed to begin with, underscoring that concerns about the price-suppressing effects of subsidized generation in the capacity market are based on “theory, conjecture and speculation.” In June FERC proposed to set a limit on how low state-backed generation can bid in the capacity market by expanding its minimum offer price rule, or MOPR, to all sponsored resources regardless of resource type. FERC also established a means for subsidized resources to be removed from the capacity auction. The commission expects to issue a final ruling by early January 2019.

U.S. expenditures on energy fell for the fifth consecutive year in 2016 to $1 trillion, entirely on lower commodity prices, according to a July 30 report from the U.S. Energy Information Administration. The U.S. average energy price plummeted to $15.92 per million British thermal units in 2016, reaching the lowest since 2003, and down 34 percent from the record high in 2008 of $24.13 per million British thermal units. Total energy demand has remained flat over the period. As a share of U.S. economic growth, the nation’s spending on energy fell for the fifth consecutive year to 5.6 percent, reaching the lowest since at least 1970. The agency said that the downward trend is unlikely to continue due to the overall increase in prices of motor gasoline, natural gas, and retail electricity since 2016. The price of petroleum products heavily influences energy spending as it accounts for much of the consumption in the transportation and industrial sectors, which are the largest energy consumers.

The Oklahoma Corporation Commission on Aug. 1 directed the Public Service Company of Oklahoma to refund about $428 million to its customers to pass on savings from the federal tax law that took effect Jan. 1. In January, the commission ordered utilities to start tracking the overcollection of taxes after the federal law slashed the corporate income tax to 21 percent from 35 percent. The commission denied the company’s petition to keep a portion of the money to offset a deficit. Public Service is a subsidiary of American Electric Power Company Inc.

Avista Corporation filed an application with the Idaho Public Utilities Commission to lower rates for electric service by 5 percent and natural gas service by 4.2 percent after the colder-than-normal winter boosted sales in 2017 above approved levels. The lower power rates, to run from October through September 2019, would reduce the average monthly electric bill to $84.33 from $88.49. The lower natural gas rate, to run from November through October 2019, would reduce the average natural gas bill to $46.28 from $48.31. The rates are being revised under its annual fixed cost adjustment, a measure intended to remove the disincentive for promoting energy efficiency and conservation by ensuring the utility can recover its fixed costs for maintaining the grid and operations. The FCA is adjusted annually, via a surcharge when expenses exceed revenue, or a rebate when revenue surpasses costs. Comments on the electric and natural gas cost adjustments are due by Sept. 13 and Sept. 20, respectively.

Massachusetts lawmakers approved legislation on July 31 that would authorize borrowing of up to $2.4 billion to fund programs that promote climate change adaptation, environmental protection, and recreational assets. The bill would provide for a statewide adaptation strategy every five years, incorporating climate trends based on extreme weather events, drought, flooding, storms, and wildfires. The measure would support a wide range of projects including dam repairs, culvert replacements, coastal resiliency measures, water infrastructure, land conservation, and transportation. (H 4835)

Connecticut’s lifeline for Dominion Energy Inc.’s 2,100-megawatt Millstone nuclear plant will be available at least a year earlier than originally proposed. The Connecticut Department of Energy and Environmental Protection on July 31 issued a request for proposals for zero carbon resources, setting an “at risk” time period of June 1, 2022, to account for capacity obligations for existing resources participating in ISO New England Inc.’s forward capacity market. Bidders may also seek an earlier date if they can prove that they are at risk of closure before 2022. While Dominion had committed Millstone to fulfill capacity obligations for 2020-2021 and 2021-2022, it said it needed “certainty and a clear path forward” to ensure the plant would extend operations beyond that period. Connecticut passed a law last year allowing the Millstone generator, the state’s only nuclear power plant, to compete for long-term contracts with other zero-carbon resources such as wind, solar and hydropower. Regulators concluded that Millstone is critical for the region’s fuel security and emission reduction goals, while also underscoring the need for the generator to prove its at-risk status. The agency will hold a bidders’ conference on Aug. 13. Bids are due by Sep. 14.

The combined emissions of six key air pollutants in the U.S. fell by 73 percent between 1970 and 2017 even as U.S. economic growth more than tripled over the period, according to the U.S. Environmental Protection Agency’s annual air quality report issued on July 31. Under the Clean Air Act, the agency regulates pollution of sulfur dioxide, lead, carbon monoxide, nitrogen dioxide, particulate matter, and ground-level ozone or smog. The agency underscored its collaboration with states and local governments to help meet national standards as it strives to achieve further improvements. The Trump administration has sought to weaken many of the clean air mandates underpinning the reductions, including standards forcing emission cuts from power plants, automobiles, and drilling operations.

Virginia Electric and Power Company, a subsidiary of Dominion Energy Inc., asked the Virginia State Corporation Commission to approve the first phase of a 10-year program to strengthen the distribution grid and improve service for customers. The initial three year phase, expected to cost over $900 million and span from 2019 through 2021, includes the deployment of over 1.4 million meters, which will serve as a “foundational component” of the initiative. The plan also features the creation of a platform that will allow customers to select rate structures, including time-variable rates, and to respond quickly to changing energy use patterns and equipment malfunctions. “Intelligent” digital devices will equip the grid with self-healing capabilities to isolate faults and reroute power flows to restore outages with minimal intervention from operators. In addition to physical hardening, the company said it will implement stringent cyber security standards for the digital devices and automated systems. The plan looks to improve the integration of growing amount of distributed energy by mitigating the impacts the supplies will have on voltage stability, operations, and reliability.

Programs to harden Florida’s power grid against hurricanes and extreme weather “are working,” according to the Florida Public Service Commission’s July 31 report on electric utilities’ hurricane preparedness. The regulator found that “very few” transmission structure failures occurred during the 2016-2017 storm seasons, with many outages caused by falling trees and vegetation outside utilities’ control. Florida Power & Light Co., the state’s largest utility, found that half as many man hours were required to restore hardened feeders than non-hardened feeders. The report also found that the rate of service restoration after Hurricane Irma slammed into the state in September 2017 was “fairly rapid.” The agency said that the number of customers without power had dropped below 1 percent just ten days following the outage peak, when more than 6.5 million residences lacked electricity. The agency found that utilities need to improve undergrounding programs, customer communication and tree-trimming coordination with local governments. The commission pursued extensive storm hardening efforts after the destructive 2004-2005 storm season, and ordered utilities to update their plans every three years.

Electricity demand in the region served by the Electricity Reliability Council of Texas Inc. set a new hourly peak record of 73,259 megawatts on July 19, surpassing the previous day’s record of 72,192 megawatts, according to a July 31 report from the U.S. Energy Information Administration. The previous record was set in August 2016. The peak load on July 19 was 2,100 megawatts higher than the 2016 peak, exceeding forecasts in the grid operator’s seasonal assessment, which projected the peak to be 1,600 higher. Ercot tackled the record demand with only some sporadic outages. Coal plant retirements and higher summer demand led to a lower estimated reserve margin of 10.9 percent of peak demand, compared to the planned margin of 13.8 percent.

The U.S. State Department found that TransCanada Corp.’s proposed Keystone XL oil pipeline route in Nebraska would have no significant impacts, according to the agency’s draft review issued on July 30, paving the way for the heavily contested project to move forward. The review found the project’s environmental, cultural and socioeconomic impacts will be negligible to moderate. Nebraska regulators approved an alternate route to construct the pipeline in November 2017 after the company resubmitted an application in response to President Trump’s January 2017 executive action to advance the project. The line has been delayed for nearly 10 years amid opposition from environmentalists and landowners. The pipeline is designed to ship 830,000 barrels per day of crude oil from Cushing, Oklahoma to the Gulf Coast refinery market. The cost of the U.S. portion of the project, from the U.S-Canada border to Steele City, Nebraska, is estimated to be $5.3 billion. Comments on the draft are due within 30 days.

The U.S. used 661 million short tons of coal for power generation in 2017, the lowest level since 1983, and a 36 percent drop from 2008 levels when production hit a high point, according to an Aug. 3 report from the U.S. Energy Information Administration. The amount of coal shipped by rail fell by 33 percent over the same period. Shipments by river barge rose to 12 percent from 7 percent because of the Illinois Basin’s dependence on the Ohio River for transportation. Truck shipments fell to 9 percent from 12 percent due to lower Appalachian production caused by plant closures and production declines. Overall transportation costs slipped by 4 percent, with the increase in rail shipping costs offset by declines in truck and river barge costs.