Federal subsidies for renewable energy dropped to $6.7 billion in the 2016 fiscal year, a 56 percent decline from 2013, according to an April 26 report from the U.S. Energy Information Administration. Tax expenditures provided 80 percent of renewable subsidies in 2016 with biofuels representing 51 percent of the expenditures. Biofuel demand was driven by increasing targets under the renewable fuel standard that mandates blending of biofuels into the fuel supply. Renewable electricity-related tax expenditures dropped to about half in 2016 compared to 70 percent in 2013. Most of the renewable energy direct expenditures for 2010, 2013 and 2016 came from the American Recovery and Reinvestment Act of 2009, which was intended to speed economic recovery including energy infrastructure. Through the act, the U.S. Energy Department invested over $31 billion since 2009, but most provisions for energy programs had expired by 2016. U.S. Secretary of Energy Rick Perry requested updated subsidy information as part of the study on grid resiliency.

U.S. fuel ethanol exports continued to grow over the past eight years reaching about 1.4 billion gallons in 2017, exceeding the 2011 record high of 1.2 billion gallons, according to an April 27 report from the U.S. Energy Information Administration. The U.S. exported to 35 countries in 2017, with Brazil and Canada accounting for more than half the volume. The agency attributed the export growth to U.S. corn and ethanol production outpacing domestic consumption. In the 2017–2018 harvest year, the U.S. produced 14.6 billion bushels of corn, 4 percent lower than the record 2016–2017 harvest year. Large harvests and stable prices of corn, the main feedstock of fuel ethanol, have led to increased production in recent years.

U.S. Senator John Barrasso, a Republican, introduced legislation on April 26 that would roll back provisions of the 1978 Public Utility Regulatory Policies Act by empowering state regulators and non-regulated utilities to waive the mandatory power purchase obligations under the act when there is no need for additional power to meet customer requirements. The act was originally intended to reduce dependence on foreign oil and promote small renewable energy and cogeneration facilities, known as qualifying facilities, from which utilities must buy power at administratively-set avoided costs the utility would incur to produce the power. Oil-fired generation represents less than one percent of U.S. generation, down from 17 percent in 1978, while wind and solar account for about 9 percent, after being almost non-existent four decades ago. With declining renewable costs, utilities have complained that the mandates have resulted in overpayments and forced them to buy electricity even when they do not need it. (S.2776)

Lawmakers with Massachusetts legislature’s Joint Committee on Telecommunications, Utilities and Energy proposed legislation on April 30 that would strengthen the state’s renewable portfolio standard by requiring retail electricity suppliers to increase their procurement from renewable resources by 3 percent annually after 2018, up from the current one percent increase. (S 2503)

CSOLAR IV South LLC and CSOLAR IV West LLC requested approval from the Federal Energy Regulatory Commission for a transaction under which Tenaska CSOLAR South Holdings II LLC will acquire the indirect interests of CSOLAR South, and subsequently, CD Global Solar II CSolar Holdings LLC will buy those interests as well as 25 percent interest in CSOLAR West, according to an April 26 filing. The buyer, CD Global Solar II CSolar Holdings is indirectly controlled by Capital Dynamics Holdings AG, a Swiss-based firm that invests in private equity funds and clean energy infrastructure. CSOLAR South and CSOLAR West each own solar facilities of capacity 130 megawatts and 150 megawatts, respectively, in California, and are indirect subsidiaries of Tenaska Energy Inc. and Tenaska Energy Holdings LLC. Applicants seek approval by June 15.

The U.S. Energy Department said it will fund research and development of the next-generation of marine energy technology to support industry advancement in wave, tidal, ocean, and river current technologies, according to the department’s April 30 press release. Research efforts include early stage design of power take off systems that convert absorbed energy into electricity and associated controls, which are considered important to facilitate increased energy capture. The department will also explore potential environmental impacts from marine energy advancement. Last month, the Oregon State University filed a license application for a wave energy test site supported by Energy Department grants.

The California Air Resources Board on April 18 proposed final amendments to its cap-and-trade program clarifying that a successor entity is liable for the outstanding compliance obligation of its predecessor after a change in ownership occurs. Cap and trade is a central part of California’s plan to reduce greenhouse gas emissions 40 percent below 1990 levels by 2030.

The Public Utilities Commission of Ohio approved American Electric Power’s electric security plan, a rate plan for the supply and pricing of electric generation, for the period of June 1 through May 31, 2024. The plan, which stems from a settlement involving more than a dozen groups, includes provisions to establish rebate programs for electric vehicle charging stations and microgrids, and riders for renewable investments and the Power Forward grid modernization initiative. The plan allows continued cost recovery of distribution infrastructure and vegetation management programs until a new distribution rate case required to be filed by June 1, 2020. The distribution investment rider is capped at $215 million for 2018, $240 million for 2019, and $265 million for 2020. The company said that plan will result in a monthly bill increase of less than $0.50 for a residential customer using 1,000 kilowatt-hours per month.

Iowa Governor Kim Reynolds, a Republican, signed legislation on May 4 that limits spending for energy efficiency plans for electric and gas utilities to 2 percent and 1.5 percent, respectively, of the annual rate revenue collected from participating customers. The bill establishes a process for utility customers to request exemptions from these programs. (SF 2311)

Avista Corporation and Hydro One Limited reached a settlement that would protect Avista’s Idaho customers from costs associated with the merger transaction and shield Avista from the potential financial issues of Hydro One, according to a May 1 memo issued by the state deputy attorney general Brandon Karpen. Avista customers will receive a $15.8 million rate credit over a five-year period and continue to benefit from renewable power programs including a $5.3 million over a ten-year period from Hydro One for energy efficiency and low-income programs. The settlement also supports a December 31, 2027 depreciation end of life relating to Avista’s ownership in a Montana coal-fired plant. The deal, authorized by the federal energy regulator in January, requires approvals from state regulators within Avista’s territory covering Washington, Idaho, Oregon and Montana. Hydro One is a Canadian transmission and distribution service provider.

The Washington Utilities and Transportation Commission approved a measure to have Puget Sound Energy Inc. extend savings from the federal Tax Cuts and Jobs Act to customers, according to the commission’s May 1 press release. The changes along with other adjustments will slash the company’s electric and natural gas revenues by $108.5 million and $10.7 million, respectively. Residential electric customers will see a $6.91 decrease in monthly bills. Natural gas customers’ savings will be offset by increases in decoupling surcharges resulting in a 48-cent increase in monthly bills. The new rates are effective May 1. Puget Sound Energy is a subsidiary of Puget Energy Inc.

Kansas City Power & Light Company, a subsidiary of Great Plains Energy Inc., asked the Kansas State Corporation Commission to approve a rate hike of 4.5 percent, or $26.2 million, 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 Federal Energy Regulatory Commission on April 27 rejected a request by the Midcontinent Independent System Operator Inc. and certain transmission owners in its footprint to apply a two-step averaging methodology for annual true-up calculations. The companies proposed to apply the same method they currently use in calculating the balances of their projected accumulated deferred income tax or ADIT, which is the difference between taxes received in rates and what they actually owe to the internal revenue service. The commission requires companies to deduct this balance from the rate base through a normalization method to pass on benefits to ratepayers, and has also allowed an additional averaging step to prevent a normalization violation. The commission said that the two-step method “disproportionately skews” the ADIT component, thereby understating rate reduction and resulting in higher rates.

The Washington Utilities and Transportation Commission approved a one-year rate plan for Avista Corporation including passing on the utility’s tax savings of $26.9 million for electric customers and $5.5 million for gas customers as a result of the corporate tax cuts resulting from the federal tax reform law, according to the commission’s April 26 press release. The commission denied the utility’s request for a three-year plan due to uncertainties created by Avista’s pending merger deal with Canada-based Hydro One, additional tax impacts, and depreciation schedules related to its ownership in the Montana-based Colstrip coal plant. The new rates effective May 1 will result in a 2.7 percent increase in electric bills and a 1.2 percent decrease in gas bills.

ISO New England Inc. projects power demand this summer to peak at 25,729 megawatts under normal temperatures of about 90 degrees Fahrenheit, up about seven percent from last summer’s high of 23,968 megawatts, according to a May 1 press release. The manager of the six-state power grid said that it has more than 32,000 megawatts of capacity on hand to meet the electricity consumption. Demand on the system hit a record of 28,130 megawatts in August 2006. Power use is highest in the summer in New England as sweltering conditions drive up the use of energy-intensive air conditioners.

U.S. power grid operators are adequately equipped to restore their systems using blackstart resources when widespread outages occur, according to a May 2 report from the Federal Energy Regulatory Commission and the North American Electric Reliability Corporation. Blackstart resources are capable of operating and delivering electric power without support from the electric system. Based on an assessment of nine utilities registered with the corporation, the study found that although some utilities saw a drop in blackstart resources due to retirements over the past decade, they have enough resources in their restoration plans and they have adequate strategies in place to mitigate further loss of resources. The study recommends industry-wide review of approaches to improve system restoration and blackstart capability planning and testing. The study builds on a 2016 review that evaluated utilities’ plans for restoration and recovery after an outage or blackout.

The Electric Reliability Council of Texas Inc. projects peak demand this summer to reach 72,756 megawatts, which is 1,600 megawatts higher than the record set in August 2016, according to an April 30 press release. The grid operator expects tighter reserves on peak summer days driven by the growing economy, but anticipates adequate generation to meet peak demand. Since the preliminary assessment released in March, the grid operator said that generation capacity rose by over 500 megawatts as units returned from mothball and outage status and with new natural gas-fired resources coming online earlier than expected.

Maryland Governor Larry Hogan, a Republican, signed legislation on April 24 that requires a public service company to provide notification to landowners within the vicinity of a proposed transmission line. Current law requires a notice only for owners of the land over which a line is proposed to be placed. The requirement applies to proposals filed after the October 1, 2018. (HB 869)

The Energy Choice Initiative, a ballot initiative to create a competitive retail power market in the state, would likely raise electric bills of Nevadans at least for the first decade, while large commercial customers would see immediate savings, according to an analysis issued by the Public Utilities Commission of Nevada on April 27. NV Energy would have to divest its generating assets and assign power purchase contracts to new owners, leaving ratepayers vulnerable to the utility’s financial losses from stranded costs. Net metering and other solar policies are expected to be adversely impacted. The ballot measure, which was approved by over 70 percent of Nevada voters in 2016, must pass another round of voting in 2018 to become a constitutional amendment. The measure would direct the legislature to pass law to establish an open, competitive retail electric energy market by July 1, 2023. Nevada would be the first state to deregulate its energy market by amending its constitution.

The New York Independent System Operator Inc. on April 30 unveiled a blueprint for incorporating the cost of carbon emissions into its wholesale electricity markets by applying a carbon price to both internal suppliers and out-of-state transactions. Suppliers would be debited a carbon charge that can be embedded in their energy offers, so as to incorporate the carbon price into prices. Because charging only internal resources would make them less competitive, the proposal would charge imports for emissions and credit exports for avoiding emissions. The grid operator envisions carbon pricing as a means to better harmonize wholesale energy markets and state policy objectives. The state has a goal of reducing emissions 40 percent by 2030 and 80 percent by 2050, relative to 1990 levels.

Distributed energy resources and energy efficiency are projected to reduce electricity demand from the bulk power system by about 3,700 megawatts over the next decade as consumers continue to install onsite generation systems to meet their electricity needs, according to the New York Independent System Operator Inc.’s Power Trends report released on May 3. As the state’s policies seek accelerated changes towards a cleaner grid, the system operator plans new products to address the intermittency of renewable resources, refinements to existing products to value resources needed for reliability, and enhancements to address potential reliability issues from the changing resource mix. The annual report analyzes current and emerging trends that are transforming the power grid and wholesale markets.

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. Battery storage is seen as a critical piece of the evolving power grid, serving multiple functions including bolstering grid stability, providing backup power, and supporting renewable integration.

The Maryland legislature approved legislation on April 5 that would extend the date for authorizing plug-in electric vehicles to use high-occupancy vehicle lanes to September 30, 2022, from the current September 30 termination date. The authorization was first established in 2010 and later extended in 2013 and 2016. A high-occupancy lane is restricted to certain time periods to certain vehicles with two or more occupants. A highway designated as high-occupancy lane may be used at all times by plug-in vehicles that have a permit from the state motor vehicle administration irrespective of the number of passengers it is carrying. (HB 714)

The Minnesota Public Utilities Commission should approve Enbridge Inc.’s proposed Line 3 Replacement Project only if the commission selects the “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, according to a recommendation issued on April 24 by administrative law judge Ann O’Reilly. The recommended route called Route Alternative 07 would prevent the abandonment of nearly 300 miles of pipeline and avoid a new oil pipeline corridor in a sensitive region of the state. Under its preferred route, the company seeks to replace the old line with new line in the existing corridor in Wisconsin and North Dakota, but in Minnesota where the majority of the U.S. portion of Line 3 runs, the company is proposing an entirely new corridor for about 47 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 Federal Energy Regulatory Commission on April 30 approved a settlement between Calpine Corporation, Pacific Gas and Electric Company, and California Independent System Operator Corporation establishing reliability-must-run agreements to prevent retirement of three Calpine gas plants needed to meet local reliability. The plants are Yuba City Energy Center and Feather River Energy Center which are peaking plants each having a capacity of 47.6 megawatts, and the 580-megawatt Metcalf Energy Center. The California grid operator’s board approved the measures last November, but the California Public Utilities Commission, which has opposed them, allowed Pacific Gas and Electric to hold competitive solicitations for energy storage or preferred resources to address local area needs in areas previously served by those plants.

Big Rivers Electric Corporation, a rural electric cooperative, notified the Kentucky Public Service Commission on May 1 that it can no longer economically operate and maintain the 312-megawatt Station Two coal power plant beyond May 31, 2019. The corporation has operated the plant’s two coal-fired units owned by Henderson Municipal Power & Light under a series of contracts executed in 1970. Because Henderson has said it will push back on attempts to cease performance, the corporation is requesting a finding from the commission supporting its determination that the plant is no longer viable. The corporation provides wholesale electricity service to Jackson Purchase Energy Corporation, Kenergy Corp., and Meade County Rural Electric Cooperative Corporation. Henderson Municipal Power & Light is owned by City of Henderson, Kentucky.

The Pennsylvania Public Utility Commission voted to allow Sunoco Pipeline LP to resume operations of the Mariner East 1 Pipeline after a two-month closure prompted by sinkholes emerging around the pipeline. The commission’s investigation and enforcement bureau made a thorough investigation finding that analysis and corrective actions planned and conducted after the suspension adequately address safety concerns, according to a May 3 press release. The pipeline operator will be required to comply with additional conditions including timely notification of subsidence events or construction variances. Sunoco is unit of Energy Transfer Partners LP.

Canada’s exports of crude oil to the U.S. by rail increased in 2017 setting a monthly record of 205,000 barrels per day last December as the country’s growing production outpaced pipeline capacity, according to a May 2 report from the U.S. Energy Information Administration. Heavy crude oil has demand in the Gulf Coast where refineries are designed to process them, but traditional suppliers, such as Venezuela and Mexico, have reduced their exports due to production declines, thus making Canada an important source for U.S. demand. Canadian crude oil can also be re-exported from the Gulf Coast as the U.S. has removed restrictions on crude oil exports. Canadian rail companies are requiring long-term commitments for rail transport of crude oil, but producers are not willing because pipeline capacity could increase in the near future as new projects come online and operating pipelines reduce volume restrictions.