Total transmission investment reached $14.8bn in 2012, the Edison Electric Institute (EEI) said in a new report, adding that it expects that increases in year-over-year total transmission investment by EEI’s members will have peaked in 2013 with estimated investment at about $17.5bn.
“The high level of investment in our nation’s transmission infrastructure will enable electric utilities to improve reliability, relieve congestion, facilitate wholesale market competition, and support a diverse and changing generation portfolio for the benefit of electricity customers,” EEI Vice President of Energy Delivery Jim Fama said in a March 27 statement. “Investments to deploy new technologies, such as advanced monitoring systems, are helping to make the grid more flexible and resilient.”
More than 170 projects are highlighted in the report and total about $60.6bn in transmission investments through 2024, EEI said, noting that that figure is up from the approximately $51.1bn highlighted in the 2013 report due to changing projections of system needs.
Since transmission projects address various needs and deliver numerous benefits, most projects in the report are multifaceted. That is, EEI, added, the projects are not developed solely to meet any one specific purpose. Accordingly, one project may fall into more than one transmission investment category.
Of the total $60.6bn worth of transmission projects highlighted in the report, EEI added, interstate transmission projects represent $26.2bn, or 43%; projects supporting the integration of renewable resources represent about $46.1bn, or 76%; projects where EEI member companies are collaborating with other utilities, including non-EEI members, to develop the project represent about $29.8bn, or 49%; and high-voltage projects of 345-kV and above represent about $45.7bn, or 75%.
Several of the projects included in the report are in the proposal stages and are subject to additional review. EEI added that system planners will review the costs and benefits of transmission facilities and will consider alternatives such as new generation supply, demand response, energy efficiency and increased deployment of distributed generation resources. Furthermore, the local and regional transmission planning processes may lead to modification, delay or cancelation of some of those projects or the addition of new ones.
Effective policies for planning and siting, cost allocation and cost recovery are important to achieve the levels of transmission investments needed for reliable and cost-effective service to electricity customers, EEI said. Despite recent disagreements regarding transmission incentives and adequate returns on investment, FERC should continue to foster the construction and upgrade of beneficial transmission by balancing the need to promote investment in long-term infrastructure assets with the short-term, cyclical movements in the capital markets in order to ensure sufficient access to capital to build needed transmission projects that present significant risks to developers, EEI said.
Noting that planned transmission investments are affected by economic conditions and the rate of electricity demand growth, EEI said that it forecasts a slight decrease in transmission investment after 2013, primarily attributable to load growth forecast revisions in response to the current economic environment, as well as lower long-term growth rates due to increases in demand side management and energy efficiency. Still, EEI expects investment by its members during 2014 and 2015 to be significantly higher than in years before 2013.
EEI also addressed FERC Order 1000, noting that starting in 2012 and continuing into this year, each planning region developed or is developing proposals to reform: planning, including procedures to identify transmission needs driven by public policy requirements; cost allocation methodologies; and non-incumbent developer participation.
Last year, the industry submitted to FERC interregional compliance proposals that provide a cost allocation method for new interregional transmission facilities, and those reforms are intended to provide further support for transmission development. At the same time, EEI added, EEI members continue active participation in initiatives to coordinate transmission planning activities.
The report also highlighted projects completed last year, including the Michigan Thumb Loop Transmission Project (Phase One) in the Midcontinent ISO (MISO); the Devers – Colorado River and Devers – Valley No. 2 Transmission Project in the California ISO (Cal-ISO); the Greater Springfield Reliability Project and Lower SEMA Transmission Project in ISO New England (ISO-NE); and the Seminole – Muskogee 345-kV Line in the Southwest Power Pool (SPP).
Also highlighted were such projects as the Prairie Wind Transmission project, which consists of about 108 miles of new double-circuit 345-kV transmission line linking an existing 345-kV substation near Wichita, Kan., to a new 345-kV Thistle substation northeast of Medicine Lodge, Kan. The line continues south from the wind farm to the Kansas-Oklahoma border. The total project is estimated to cost $170m.
EEI also noted that the project broke ground on Aug. 1, 2012, and is under construction. It is scheduled to be in service by December. The investment partners are Electric Transmission America, which is a 50/50 joint venture between subsidiaries of American Electric Power (NYSE:AEP) and MidAmerican Energy Holdings, and Westar Energy (NYSE:WR). The line will increase the reliability of the transmission system and the capacity to move power in the area, providing utilities and their customers with access to lower-cost electricity. Also, EEI added, the project will facilitate wind generation development and allow utilities to operate their existing power plants more efficiently.
Another AEP project included in the report is the Pioneer Transmission project, which also involves Duke Energy (NYSE:DUK). The project consists of about 286 miles of new 765-kV line linking Duke’s Greentown station, near Kokomo, Ind., to AEP’s Rockport station, near Evansville, Ind. Beginning at the Greentown station, the line runs west to the existing Reynolds 345-kV substation just north of Lafayette, Ind., before extending southwest to AEP’s Sullivan station and further south to the Rockport station. The total project is estimated to cost $1.1bn, and the anticipated in-service date for the Greentown to Reynolds segment is 2018.
EEI noted that the project will enhance the reliability of power delivery by creating a major new route for power, and it will better link the region’s power plants as well as create a route for new generation, such as wind energy.
Ameren’s more than $1.3bn Grand Rivers Project was also highlighted in the report. EEI noted that the project consists of three new transmission projects in Illinois and Missouri consisting of more than 500 miles of 345-kV lines. The projects are named Illinois Rivers, Mark Twain and Spoon River. The Illinois Rivers project consists of about 375 miles of 345-kV transmission from northeastern Missouri, crossing the Mississippi River and continuing east across Illinois to the Indiana border. The first transmission line sections of Illinois Rivers are expected to be in service in 2016, with all portions of the project expected to be completed by the end of 2019.
The Mark Twain Project is about 90 miles of 345-kV transmission from the Missouri-Iowa border in northeast Missouri connecting to the Missouri terminus of the Illinois Rivers project.
The Spoon River project consists of 70 miles of 345-kV transmission in northwest Illinois, EEI, said, adding that those three projects will primarily be built by Ameren Transmission Company of Illinois.
The Mark Twain and Spoon River projects are in the planning and design stage and both are expected to be placed into service by the end of 2018.
The projects will enable the integration of wind and other renewable energy resources into the MISO system to meet the MISO member renewable energy standards and goals, EEI said.
Another project mentioned was American Transmission Company’s Badger Coulee project, which consists of 160 to 180 miles of new single-circuit 345-kV transmission line from Xcel Energy’s Briggs Road substation near La Crosse to ATC’s North Madison substation near Madison, Wis., and will continue to ATC’s Cardinal 345-kV substation in the town of Middleton in Dane County, Wis.
The project will cost about $514m to $552m, depending on the ordered route. ATC and Xcel Energy filed an application with Wisconsin state regulators last October and if approved, construction would begin in 2016 to meet an in-service date of late 2018. The project provides economic, reliability and public policy benefits to ATC and Xcel Energy, their customers and the MISO region, EEI said.
EEI also noted that Arizona Public Service’s Hassayampa – North Gila 500-kV project consists of about 112 miles of new single-circuit 500-kV line between the Hassayampa switchyard located near the Pal Verde Hub and the existing North Gila substation, northeast of Yuma, Ariz. The line will be built on tubular or lattice tower structures 130 to 150 feet high, spaced about 600 to 1,800 feet apart. The project, which costs about $300m, has an anticipated in-service date of 2015 and will provide the electrical transmission infrastructure to import power into the high-growth Yuma area from additional generation resources around the Palo Verde Hub, which is the area around the Palo Verde nuclear generating station.
In Texas, CenterPoint Energy, for instance, is working on the Mont Belvieu Area upgrade project, which consists of a new Jordan 345-kV/138-kV substation, a new 800 MVA 345-kV/138-kV autotransformer, and other miscellaneous transmission system upgrades. The Jordan substation will connect six 138-kV circuits as well as loop in an existing 345-kV circuit. The project is estimated to cost about $42m and construction began early last year. The overall project is scheduled for completion by May.
EEI also said that National Grid plc’s National Grid USA is working on the Northeast Energy Link project, which consists of about 230 miles of new 1,100 MW HVDC line from Orrington, Maine to eastern Massachusetts and is estimated to cost $2bn. Preliminary engineering and permitting work is underway and the in-service date for the project, which also involves Emera Maine, is expected to be late 2018.
The project, EEI added, will deliver cost-effective renewable and low-carbon resources from northern New England and the Canadian maritime to southern New England customers, providing energy to meet state renewable portfolio standards.
EEI also noted that Northeast Utilities’ wholly owned subsidiary Northern Pass Transmission’s Northern Pass Project consists of about 153 miles of new 300-kV HVDC line and an associated 34-mile radial 345-kV line that will interconnect Quebec with the bulk power system in New Hampshire for the purpose of importing 1,200 MW of low-carbon emissions power into New England. The estimated capital cost for the U.S. portion of the line is about $1.4bn, EEI said, noting that the target in-service date for the project is anticipated for mid-2017.
Northern Pass is an economic and environmental project that will provide a competitively priced, reliable supply of large quantities of primarily – 98% – hydroelectric power energy, EEI said.
Among other projects, EEI noted that Public Service Enterprise Group’s (NYSE:PEG) Public Service Electric and Gas’ Burlington – Camden 230-kV Network Reinforcement Project consists of upgrading 37 circuit miles of transmission operating from 138-kV to 230-kV, building a new 230-kV switching station at Burlington and converting five existing stations to 230-kV operation. The upgraded stations are Levittown, Cinnaminson, Camden, Gloucester and Cuthbert Boulevard.
The cost is about $399m and the total project is about 85% complete. EEI also said that the project is needed to maintain transmission system reliability by addressing several PJM Interconnection-identified voltage violations that are anticipated to occur beginning this year.