Alliant Energy Corporation signed a contract with Invenergy LLC to build a 210-megawatt wind farm, in what will be the fifth project as part of Alliant’s plan to add 1,000 megawatts of wind generation for Iowa customers by 2020, according to a July 16 press release. The project, expected to be completed by early 2020, is part of Alliant’s $1.8 billion wind investment in the state and supports its goal to reduce emissions by 40 percent by 2030, relative to 2005 levels.

The Missouri Public Service Commission announced its approval of Empire District Electric Company’s bid to develop 600 megawatts of wind generation with a tax equity partner, using federal tax incentives, in light of the customer savings and generation diversification the plan will provide, according to the agency’s July 11 press release. The plan is estimated to result in savings of about $169 million over 20 years and $295 million over 30 years. In a settlement reached in April, Empire agreed to delay the closure of its Asbury coal plant. Empire District Electric is a subsidiary of Liberty Utilities Co.

The Federal Energy Regulatory Commission on July 19 declined to reconsider Verdant Power LLC’s request to extend the 10-year pilot license for its 1,050-kilowatt tidal power project saying that the initial 2012-2021 period should be adequate to conduct a testing program and decide on whether to move to a build-out license. Drawing from a staff whitepaper on licensing hydrokinetic pilots, the commission noted that Verdant received double the suggested five-year pilot term. In May, the commission denied a five-year extension request filed by Verdant last December to gather operational monitoring data to inform subsequent stages of the project and relicensing decision. Verdant sought rehearing last month saying that the commission has latitude to vary the pilot term and there were no valid stakeholder objections on its request. The commission said that there is no evidence that even 15 years would be enough to make a decision.

The cost of installing wind turbines in the U.S. dropped to $1,587 per kilowatt in 2016, down by one-third from 2010, according to a July 12 report from the U.S. Energy Information Administration. The agency attributed the trend to technology and manufacturing improvements, as well as increasing project concentrations in the U.S. Interior region, which boast the lowest installation costs. The Interior region, spanning from New Mexico and Texas in the south to Montana and Minnesota to the north, has the advantage of favorable wind resources, vast expanses of flat land that allow for larger project sizes, and ready access to transport turbine components made in the region. Costs in the U.S. Interior region fell by 25 percent between 2010 and 2016, compared to the rest of the U.S. which saw a 10 percent decline over the same period. The agency noted that the Interior region accounted for nearly 90 percent of incremental capacity by 2016 compared to 2010 when there was an even split of capacity installations between the Interior and the rest of the U.S.

The Hawaii Public Utilities Commission opened a proceeding to establish rules to spur the deployment of microgrids by the state’s main utilities. The initiative responds to passage of legislation that seeks to harness the systems to enhance integration of renewable generation and add resilience to the grid by providing backup generation during emergencies. Hawaii has a goal to get 100 percent of its energy from renewables by 2045. The utilities are the Hawaiian Electric Company Inc., Hawaii Electric Light Company Inc., and Maui Electric Company Limited.

The Federal Energy Regulatory Commission on July 19 asked the North American Electric Reliability Corporation to make revisions to its reliability standards to include compulsory reporting of cybersecurity incidents that compromise, or try to compromise, a responsible entity’s electronic access control and monitoring systems. The revisions would enhance awareness of existing and future threats, and help with identification of potential vulnerabilities. Last December, the commission proposed to expand cybersecurity incident reporting in view of the disparity under existing reporting requirements. Currently, entities must only report incidents if they have “compromised or disrupted one or more reliability tasks.” NERC must file revisions within six months.

Annual capital investment by major electric utilities, representing about 70 percent of total U.S. demand, almost doubled from 1996 to 2017, similar to the rise in transmission spending over the same period, according to a July 20 report from the U.S. Energy Information Administration. Utility expenditure on distribution systems rose by 54 percent over the past two decades, to reach $51 billion. Capital investment has the largest share in distribution costs, as utilities upgrade equipment such as poles, wires, and substation transformers – some of which are 25 years or older – with advanced materials and technology that can endure storms and facilitate greater use of intermittent resources such as wind and solar. Spending on customer meters doubled over the last 10 years as utilities upgrade to remotely-accessible smart meters that enhance customer interaction and allow for smart applications using real-time or near real-time data. The agency noted that spending related to customer accounts and sales dropped, but utilities continue to invest heavily on customer services and information systems to provide better outage communications and outreach tools.

The U.S. Energy Department issued a solicitation to provide up to $2 billion in partial loan guarantees to support energy development projects by Native American and Alaska Native communities, according to a July 17 press release. The issuance marks the first solicitation under the Tribal Energy Loan Guarantee Program that seeks to provide economic opportunities for tribes. The program aims to leverage private sector lending to increase access to commercial debt financing in tribal markets. The department said that it now has more than $40 billion in energy infrastructure loans and loan guarantees in the areas of advanced fossil energy, advanced nuclear energy, renewable energy and efficient energy, and advanced vehicle manufacturing. The first Part I application are due by Sept. 19, with subsequent deadlines every other month.

The Federal Energy Regulatory Commission on July 19 authorized Northwest Pipeline LLC’s North Seattle Lateral Upgrade Project designed to add about 160,000 dekatherms per day of transportation service to supply Puget Sound Energy Inc. and Columbia Gas Transmission LLC’s Eastern Panhandle Expansion Project to add up to 47,500 dekatherms per day of capacity to serve markets in West Virginia. The commission also authorized Texas Eastern Transmission LP’s Texas Industrial Market Expansion Project and Louisiana Market Expansion Project, called TX-LA Markets Project, to provide about 157,000 dekatherms per day of incremental capacity to its mainline facilities. Commissioner Richard Glick issued a partial dissent for each pipeline approval over concerns of the projects’ contribution to climate change. Commissioner Cheryl LaFleur’s dissent on the Texas project concerns with accounting for downstream emissions. The commission denied an appeal by Williams Companies Inc. that asks the agency to find that permitting delays by New York regulators waived the requirement to obtain a water permit for the approximately $700-million Constitution gas line. Northwest Pipeline and Constitution Pipeline are subsidiaries of Williams Partners L.P. Columbia Gas Transmission is a subsidiary of TransCanada PipeLines Limited.

The Federal Energy Regulatory Commission on July 13 approved an agreement allowing Exelon Corp.’s Mystic 8 and 9 natural gas-fired generating units to collect cost-of-service payments to stay in operation through May 2024. FERC and ISO New England Inc. found that the plant is needed to avoid risks to the reliability of the six-state New England grid. The agreement takes effect June 2022, subject to the outcome of the commission’s July 2 order that directed ISO New England Inc. to file interim revisions for a short-term agreement for the units and permanent revisions to address regional fuel security needs, or show cause why revisions are not needed. In the show cause order, the commission rejected ISO New England’s request for waivers to maintain the units saying that the grid operator’s rules lack provisions to address reliability risks related to fuel security, although it accepted that their retirement could threaten reliability. The commission set an expedited hearing citing the Jan. 4, 2019 deadline for Exelon to submit its retirement decision and the start of the capacity auction on Feb. 4, 2019. The order directs the presiding judge to conduct hearing procedures and certify the record by Oct. 12. Participants’ initial briefs and reply briefs are due by Nov. 2 and Nov. 16, respectively.

Piedmont Natural Gas Company Inc., a unit of Duke Energy Corporation, plans to build a liquefied natural gas facility in North Carolina to ensure reliable supply of gas during peak usage days, when demand for the fuel is higher-than-normal due to low temperatures, according to the company’s July 13 press release. The facility, with one billion cubic feet of capacity, will be located in Robeson County and is scheduled to be complete in the summer of 2021.

U.S. Senator James Inhofe, a Republican representing Oklahoma, introduced legislation on July 17 that would direct the U.S. Environmental Protection Agency to put natural gas vehicles on an equal regulatory footing with electric vehicles. Inhofe also wrote a letter to the agency asking for policy changes and incentives, saying that natural gas vehicles have the potential for widespread adoption in pickups and light-duty trucks. Although Congress granted regulatory incentives for dual-fuel gas vehicles, Inhofe pointed to EPA regulations that impose unfavorable requirements that are not needed for electric vehicles. (S.3226)

Natural gas spot prices in the Permian Basin have been trending lower than the U.S. national benchmark over the past year due to pipeline capacity constraints impeding transportation of the growing production in the region, according to a July 18 report from the U.S. Energy Information Administration. The agency said that the Permian Basin prices, as priced at the Waha Hub, are almost one dollar lower than the Henry Hub prices per million British thermal units. Production in the Permian Basin averaged 10.4 billion cubic feet per day in June 2018, an increase of 2.1 billion cubic feet per day from June 2017, with much of the increase attributed to natural gas produced as a byproduct of oil production. Flaring or venting of natural gas during drilling are regulated and require exemptions from state agencies after a certain period of time. Some producers are expected to stop oil production if prices continue to drop because of growing natural gas production, according to the agency. Several pipeline projects are under development to move Permian Basin gas to the Gulf Coast, with only one expected to come online in October 2019.