Duke Energy Florida LLC seeks to cut to two years the duration for fixing prices for the purchase of electricity from small renewable power suppliers that is mandated under a federal statute, citing the need to protect consumers from rate hikes and overpayments resulting from rapidly changing market conditions. Under the statute, the Public Utility Regulatory Policies Act of 1978, or PURPA, independent generators that meet certain criteria based on size and technology are entitled to sell their output to regulated utilities at the avoided cost, or the cost the utility would spend to generate the electricity or purchase supplies from another source. Duke is raising concerns about the provision, saying that it has seen an unprecedented surge in requests from solar projects over the last three years, with interconnection requests from over 80 projects with over 6,000 megawatts of solar capacity. The utility said that the growing levels of intermittent power supplies, which are unscheduled and unconstrained, will risk undermining system reliability at times when there’s excess generation and given the state’s limited export capabilities. Duke said locking into prices for the supplies over shorter periods will allow it to better respond to energy market changes, operational challenges, or reliability issues. Duke Energy Florida is a unit of Duke Energy Corp.

The Michigan Public Service Commission suspended a controversial requirement that would call on competitive energy suppliers to lock in forward capacity supplies, amid challenges by trade groups and an adverse legal ruling. In June 2018, the commission imposed local clearing requirements for all electric providers in the Midcontinent Independent System Operator Inc.’s Zone 7 for the delivery years beginning in 2022 and 2023. In July the Michigan Court of Appeals subsequently found that the commission lacked authority to implement the program, spurring the trade group Energy Michigan Inc. to file a request for the rules to be stayed, which the agency granted. The commission has appealed the decision to the Michigan Supreme Court. DTE Energy and other utilities sought to block the suspension, arguing that it unfairly requires them to continue to backstop the reliability needs of electric choice customers. The forward local clearing requirement was established under legislation enacted in 2016 to ensure reliable electric service in Michigan as older electric generation plants retire.

Hydro One Limited’s chief legal officer sought to downplay the impact that a credit downgrade should have on its application before state regulators to merge with Avista Corp., underscoring that the utility remains investment grade. S&P Global Ratings issued a report Sept. 13 lowering the rating of Hydro One and its subsidiary to A- from A after the government of Ontario enacted legislation requiring the board to develop a new compensation plan for the executive leadership. S&P said that the changes cut its management and governance assessment to fair from satisfactory. Hydro One said in a letter to the Montana commission that its credit rating remains investment grade and that the actions apply to Hydro One’s subsidiaries in Canada, and not Avista if the merger is approved. The credit downgrade is just the latest hurdle for Hydro One, coming on the heels of a shakeup of executive leadership at the utility, which led regulators to pump the brakes on approval of the transaction.

The Arizona Corporation Commission announced Sept. 12 that it approved applications by Tucson Electric Power Co. and UNS Electric Inc. to adjust compensation to customers exporting electricity onto the grid, wrapping up the agency’s years-long bid to develop a replacement of its net metering program. Export rates for Tucson Electric customers who connected solar power rooftop systems after Feb. 24, 2017, was set at $0.0964, while rates for UNS Electric customers who linked systems to the grid after Aug. 18, 2016, was set at $0.115. The rates apply to new distributed generation customers who will have the option of selecting from existing time-of-use rate schedules. The rates for the excess energy is determined by a “Resource Comparison Proxy” with a five-year rolling average of a utility’s solar power purchase agreements and utility-owned solar generating facilities. Both companies are units of Fortis Inc.

A unit of The Kroger Co., an American supermarket and retail chain, filed a request with the Virginia State Corporation Commission to aggregate the demand of 70 nonresidential customers within Virginia Electric and Power Co.’s service territory accounting for nearly 23 megawatts of demand. Kroger said that it simultaneously submitted a request to aggregate demand and engage in retail choice on behalf of Harris Teeter LLC involving 58 accounts totaling over 22 megawatts of load in the Dominion Energy Inc. service territory. Kroger said it joins other grocers that have been approved or petitioned to serve as aggregators, including Wal-Mart Stores and Costco Wholesale Corp. in the Dominion service territory and Sam’s East Inc. in the Appalachian Power Co. service territory. Virginia Electric and Power is a unit of Dominion Energy Inc.

The Electric Reliability Council of Texas Inc. announced Sept. 6 that it expects more than 81,000 megawatts of resource capacity to be available to meet forecasted peak demand in the fall of nearly 59,000 megawatts. The grid operator’s preliminary projections also show sufficient supplies to meet peak consumption of nearly 62,000 megawatts in the winter period, spanning from December through February 2019. The Texas power grid has added over 900 megawatts of capacity since the spring, with the start of two natural gas-fired power plants, one wind project and three solar projects, according to the assessment.

The U.S. Environmental Protection Agency announced Sept. 10 that it will pass on control of clean air programs addressing regional haze to Missouri, South Carolina, Tennessee, West Virginia, building on efforts to curtail the reach of the federal government. The EPA said that it will soon approve the states’ plans to meet the emissions limits, in a move it said reduces state planning burdens, and leverages emission reductions from other Clean Air Act programs. The Clean Air Act sets goals to improve visibility in national parks and wilderness areas due to man-made pollution, including pollution from coal-fired generators. Under the Trump Administration, the EPA has converted one federal plan into a state-led plan every month, according to the press release.

The U.S. EPA announced a proposal to curtail monitoring requirements for leaks of methane, a potent global warming pollutant, at natural gas and oil drilling operations, in a move said to save the industry up to $75 million a year, or nearly $500 million through 2025. The proposal would have EPA tailor the frequency of the monitoring of the leaks, known as fugitive emissions, to the output of the well. Semi-annual monitoring surveys are required under the existing 2016 regulation. The proposal responds to industry concerns that have been raised two years since the final standards were issued, and come as the Trump Administration looks to cement the nation’s position as a leading energy producer. The EPA is taking comments for sixty days after publication of the draft. The agency said that it will address the regulation of greenhouse gases in the oil and natural gas sector under a separate proposal at a later date.

A proposal by the New York Independent System Operator Inc. to implement a charge on the emissions of greenhouse gases from power plants would have a modest impact on customer costs, especially over the long run as the state moves toward renewables, according to a Sept. 13 report by the Brattle Group. A carbon charge of $40 per ton is expected to boost retail power rates by 2.2 percent, or about 0.38 cents per kilowatt-hour, over the baseline amount in 2020. The increase would then fall to 0.4 percent, or 0.08 cents per kilowatt-hour in 2025, based on a carbon charge of $49 per ton. Among the factors keeping prices from rising higher include a shift to more renewables and more energy efficiency and conservation, and cheaper renewable energy credits and zero emissions credits. Savings could also accrue as the higher wholesale prices drive a push for more innovative emissions reductions including low-cost renewable generation and higher efficiency of the existing power fleet.

New York’s six main utilities say that the state should prioritize bigger battery projects over customer-sited ones to get the most from $350 million in investments geared toward reaching a goal to deploy 1,500 megawatts of the systems by 2025. The utilities said that distribution system and bulk system projects will allow for the development of larger and more economic installations that can be targeted to meet the needs of the grid, while customer-sited applications generally benefit only the installing customer, except when the project is in a constrained area. Costs are a major concern as the battery program, estimated to come with a $2.5-billion price tag, risks inflating New York rates, which are already among the highest in the nation. The utilities underscored the need for the program to remain flexible because it is too early to gauge how the market will develop, particularly as technology evolves and costs fall. The service providers consist of Central Hudson Gas & Electric Corp., Consolidated Edison Inc., New York State Electric & Gas Corp., Niagara Mohawk Power Corp., Orange and Rockland Utilities Inc., and Rochester Gas and Electric Corp.

The Federal Energy Regulatory Commission granted a request by Gateway Energy Storage LLC, a unit of LS Power Development LLC, for an order directing San Diego Gas & Electric Co. to provide transmission and grid-connections to deliver the output of its battery storage system onto its service territory within the California grid. FERC said that the request is in the public interest, noting that as a general principle, the availability of transmission service enhances competition in power markets by increasing power supply options of buyers and sales options of sellers, resulting in lower costs to consumers. San Diego Gas & Electric said that the commission’s consent was needed to preserve its status as a “local furnishing utility” that qualifies for tax-exempt bonds for financing transmission, distribution, and generation facilities. Gateway requested approval by Sept. 15 so that the battery facility, under development in San Diego, can achieve its expected commercial operation date in January 2020.

The Texas Public Utility Commission seeks feedback on over a dozen questions as it looks to formulate rules on the use of battery storage and other “non-traditional technologies” in electric delivery service. The probe arises from the fact that batteries serve many functions, from absorbing as well as dispatching electricity to respond to swings in supplies or demand, to grid reliability services, and deferral of transmission projects. Among the inquiries include whether utilities can legally own energy storage equipment and facilities to support grid reliability without an exemption from the agency, and whether they should be required to contract with a non-utility service provider to deploy the systems. The regulator also questioned how energy from the devices should be measured and accounted for within the market run by the Electric Reliability Council of Texas Corp. and under which circumstances it would be appropriate for the utility to dispatch the devices. Other questions concern the effects the policy would have on the wholesale and competitive retail markets and what steps utilities could take to mitigate adverse impacts. Comments are due Nov. 2.

New York’s goal to add 1,500 megawatts of energy storage capacity by 2025 could create about 30,000 research, development and manufacturing jobs, while also cutting about 2 million metric tons of greenhouse gases, according to a Sept. 12 report commissioned by state regulators. Expanded deployment of energy storage figures prominently in the state’s efforts to source half of its power from renewables by 2030 in a bid to combat climate change as well as to tame consumer prices which, at 17.74 cents per kilowatt-hour in January, are among the highest in the U.S. Energy storage can also help defer or avoid upgrades and replacements to the state’s aging transmission and distribution grid, which will require more than $30 billion of investments over the next ten years, according to the report. In January the governor proposed to commit over $200 million from the New York Green Bank to drive down costs and to deploy new projects.

The New York Public Service Commission announced Sept. 12 that it approved the addition of medium- and heavy-duty electric vehicles to the types of cars eligible to participate in Consolidated Edison Inc.’s off-peak charging program, SmartCharge NY, the latest in a series of EV incentives within the state. Expanding the program to include larger vehicles is a key step in advancing the state’s goal to cut greenhouse gas emissions 40 percent by 2030 and 80 percent by 2050, as the cars account for an outsized share of total automobile pollution in the transportation sector – the highest-emitting segment of the economy. New York has sought to become a leader in electric vehicles through its Zero-Emissions Vehicle plan, which calls for installing a state-wide network of chargers to support a goal to drive up to 40,000 in electric vehicle sales by the end of 2018. About 26,500 electric vehicles are currently registered in the state.

The Iowa Utilities Board launched an inquiry Sept. 12 to consider whether power sold to charge electric vehicles should be considered the resale of electric energy, subject to state regulatory oversight. The board was compelled to open the investigation after Interstate Power and Light Co. made a request for the regulator to find that the chargers don’t constitute resale of electricity so long as the energy is not sold on a per kilowatt-hour basis. The board had rejected the petition, finding that the request warrants further study because it raises significant legal and policy issues. The board also noted that state lawmakers passed legislation directing the regulator and other agencies to make recommendations to the general assembly regarding electric vehicle charging infrastructure and to assess cost and benefits. Final comments are due Nov. 9. Interstate Power is a unit of Alliant Energy Corp.

The Colorado Public Utilities Commission approved Public Service Company of Colorado, a subsidiary of Xcel Energy Inc., to retire two-coal fired units in the Comanche Station, a decade ahead of schedule, as part of the company’s 2016 electric resource plan, according to the agency’s Sept. 10 decision. The commission found that the retirement of the coal units in 2022 and 2025 is in the public interest, allowing Xcel to take advantage of the “exceptionally low bid prices” from its competitive solicitation in the resource planning process. The plan includes the acquisition of over 1.1 gigawatts of new wind generating capacity, and the procurement of over 700-megawatt of new solar and 275-megawatt of battery storage. The utility expects the plan to result in more than $200 million savings to ratepayers.

The New York Public Service Commission ruled in favor of NRG Community Solar LLC, finding that the power supplier’s community solar project should be awarded more generous so-called volumetric credits than the rates offered by Central Hudson Gas and Electric Corp. and Orange and Rockland Utilities Inc. In its Sept. 12 ruling, the commission dismissed arguments by the utilities that the size and the type of grid connection caused the community solar projects to fall under the less favorable demand rate class, a designation which would cut by up to half the economic value of the credits provided. The commission said that consistent with its March 2017 order, regardless of a project’s service class, meter type, or billing method, projects that receive compensation under Phase One Net Energy Metering rules should have credits awarded via volumetric crediting. 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.

U.S. Democratic Senators Sheldon Whitehouse, representing Rhode Island, and Edward Markey, representing Massachusetts, introduced legislation on Jan. 11 that would ban offshore oil and gas leasing off the New England coast. The measure would protect ocean and coastal resources said to be an “economic engine” that contributes $17.5 billion annually to the region’s economy. The proposal follows a move by the Trump administration to open more than 90 percent of the outer continental shelf to natural gas and oil extraction. (S. 2298)

The U.S. Bureau of Land Management’s third-quarter oil and gas sale in New Mexico generated $972 million, more than twice the record set in 2008, according to the agency’s Sept. 6 press release. The auction also set a national record for the highest bid for a single parcel, as well as the highest per-acre bid. Southeastern New Mexico, where the leased areas are located, sits atop the booming Permian Basin. The nation’s path to toppling a 1970s-era record for oil production runs through the Permian oil basin thanks to the shale formation’s favorable geology and advancements in technology and operations. EIA projects that Permian production will average 3.3 million barrels per day in 2018, and build to 3.9 million in 2019.

California Gov. Jerry Brown, a Democrat, signed legislation on Sept. 8 banning the construction of pipelines and other oil and natural gas infrastructure within state waters, hitting back against a proposal by the U.S. Interior Department to open more than 90 percent of the Outer Continental Shelf acreage to drilling. Gov. Brown also submitted the state’s formal opposition to the agency’s proposal to open new public land for drilling activities, saying that it contradicts the state’s move to fight climate change and meet its objectives under the Paris climate accord. The measure comes on the heels of a verdict by a jury in Santa Barbara County finding Plains All American Pipeline LP guilty of nine criminal charges related to the 2015 oil spill near Refugio State Beach, including a felony for improper maintenance of its highly-pressurized pipeline that led to the discharge of oil into the Pacific Ocean. (SB 834, AB 2864)

The Federal Energy Regulatory Commission found that adverse environmental impacts from Tellurian Inc.’s Driftwood LNG liquefaction plant in Louisiana can be mitigated to less-than-significant levels, with the exception of visual impacts to nearby residents. FERC’s environmental report, which is a precursor for obtaining a permit to site and construct the project, finds that the plant would need to implement measures to reduce the impacts. Among the impacts, nearby residents to the LNG facility would see flares and lighting at night. Once the LNG facility is completed, the aesthetics would be consistent with existing industrial developments, the report said. Telurian’s project, which is scheduled to begin construction in the first half of 2019 and commence operations in 2023, would have 27.6 million metric tonnes per year of capacity from five liquefaction plants.

The U.S. Energy Department authorized Freeport LNG Development LP to export 2.14 billion cubic feet per day of liquefied natural gas over a two-year period from the company’s Texas facility to free-trade and non-free trade agreement nations, according to the agency’s Sept. 13 press release. The move will increase flexibility for Freeport to export LNG via short-term contracts as well as commissioning volumes. Freeport is among four projects scheduled for completion over the next two years, set to boost U.S. LNG export capacity to 11 billion cubic feet per day, up from the current 3.5 billion cubic feet. Natural gas exports are projected to average 9.9 billion cubic feet per day in 2018 and soar 38 percent in 2019 to 13.7 billion cubic feet per day, according to the U.S. Energy Information Administration.

The U.S. led the world in crude oil output at multiple intervals over the winter and summer, besting Russia for the first time since 1999 in June and August, while surpassing Saudi Arabia for the first time in more than two decades in February, according to a Sept. 12 report from the U.S. Energy Information Administration. The agency said that higher oil prices in early 2016 spurred investment and production by the U.S., leading to gains against the rival producers. Much of the growth is attributed to the surge in output in the Permian basin, offshore Gulf of Mexico, and the Bakken region. The agency forecasts production to average 10.7 million barrels per day in 2018, up from 9.4 million last year, and reach 11.5 million in 2019. The U.S. is expected to stay ahead of the two nations through 2019.

Coal dominated the power generation mix in 18 U.S. states last year, down from 28 states in 2007, according to a Sept. 10 report from the U.S. Energy Information Administration. Over the same period, the number of states where natural gas had the largest generation share increased to 16 from 11. Last year, the share of natural gas in the total U.S. generation mix was 32 percent, compared to coal’s share of 30 percent. In the 10 states where coal’s share fell, five rely on natural gas and the remainder on nuclear as the primary generation source. The agency attributed the trend to retirements or diminishing use of coal plants, new gas fired plants, and uprates to existing nuclear plants.