Monthly Project Review February 2020

Projects covered in February include Appalachian Power’s Joshua Falls-Gladstone phase of the Central Virginia Transmission Reliability Project and the New York Power Authority’s Moses-Adirondack Smart Path Reliability Project

TransmissionHub presents a roundup of most of the transmission project news that occurred in February, including the California ISO selecting LS Power Grid California, LLC (LSPGC) as the approved project sponsor to finance, build, own, operate, and maintain the Round Mountain 500-kV Dynamic Reactive Support transmission solution.

East

Starting in South Carolina, Dominion Energy South Carolina (DESC) on Feb. 3 filed with the Public Service Commission of South Carolina an application for a certificate of environmental compatibility and public convenience and necessity for the construction and operation of the Toolebeck-Aiken 230-kV Tie and segments of the Graniteville #2-Toolebeck 230-kV and Toolebeck-South Augusta 230-kV Tie, as well as associated facilities in Aiken County, S.C. The company noted that the Graniteville #2-Toolebeck line would extend from the Graniteville No. 2 substation in Aiken County to the Toolebeck substation in Aiken County. The line would be an estimated 22.1 miles long, of which a 10.6-mile segment is the subject of the application. The Toolebeck-South Augusta line would extend from the Toolebeck substation to Southern Company’s South Augusta substation on Dan Bowles Road in Augusta, Ga. The company added that the line would be an estimated 17.42 miles long, of which a 10.6-mile segment is the subject of the application. The Toolebeck-Aiken line would extend from the Toolebeck substation to the South Carolina Public Service Authority’s (SCPSA) Aiken substation in Aiken County. The line would be an estimated 7.1 miles, the company added, noting that that distance is the portion of the line to be owned and operated by DESC and is measured to the tie point with SCPSA, which is on or near existing DESC right of way (ROW). As noted in the transmission line siting and environmental report for the project, the schedule calls for the facilities to be in service by March 1, 2022.

In Virginia, American Electric Power’s Appalachian Power on Feb. 13 noted that the Joshua Falls-Gladstone phase of the Central Virginia Transmission Reliability Project — one of several phases of the project over the next few years in five central Virginia counties — involves building about 15 miles of transmission line and improving four substations in Amherst, Appomattox, Campbell, and Nelson counties. The company said that the project team plans to select a line route and seek approval from the Virginia State Corporation Commission in the summer. If approved, construction for the Joshua Falls-Gladstone phase would begin in summer 2022 and last for about a year.

Also in Virginia, commission staff, in a Feb. 28 report filed with the commission, said that it does not oppose Virginia Electric and Power’s (d/b/a Dominion Energy Virginia) request that the commission issue the certificate of public convenience and necessity (CPCN) necessary for the Loudoun-Ox 230-kV Transmission Line Partial Rebuild Project. As noted by staff, Dominion in August 2019 filed an application with the commission for a CPCN to rebuild, entirely within existing ROW, segments of its existing 230-kV transmission Lines #2173, #295, #265, #200, #2051, #2063, #266, and #2008, which are collocated within the existing 19.2-mile transmission line corridor between the company’s existing Loudoun and Ox substations. The project crosses through Loudoun, Prince William, and Fairfax counties; is estimated to cost $67.5m, including about $59m for transmission-related work and about $8.5m for substation-related work (2019 dollars); and has an expected in-service date of December 2024.

In Massachusetts, NSTAR Electric d/b/a Eversource Energy on Feb. 13 told the Massachusetts Energy Facilities Siting Board that the company’s current updated cost estimate for its 115-kV West Roxbury to Needham Project has increased to $45.7m, which is $5.5m higher than the cost estimate provided during the proceeding involving its petition to build, operate, and maintain the project. As noted in the filing, the board’s final decision issued in May 2018 for the project included Condition P, which directed the company to submit to the board an updated and certified cost estimate for the project prior to the start of construction. The projected cost for the project is $45.7m, compared to the $40.2m projected in prior Condition P filings, the company said, adding that the increase primarily reflects actual design and construction costs for the line greater than estimated costs for the underground cable portion of the project, primarily driven by greater than anticipated underground utility congestion and ledge. The actual cost incurred as of Dec. 31, 2019, was $31m, which includes actual costs as of that date, plus remaining forecast items, the company said. Work on the overhead portion of the project is substantially complete, except for clean-up work removing the old overhead conductors, which will be removed by the completion date of the underground portion of the project, the company said.

In other Eversource news, the company on Feb. 14 filed with the siting board its initial brief regarding its proposal to build, operate, and maintain the proposed 115-kV Andrew Square to Dewar Street Transmission Reliability Project. The company noted that the project involves an approximately two-mile, underground electric transmission line between two existing Eversource substations — the Andrew Square Station #106 located in South Boston and the Dewar Street Station #483 located in Dorchester — with a 150 MVA summer normal rating, which would operate in conjunction with the two existing radial transmission lines from the company’s K Street Substation #385 that currently supply the Andrew Square substation and the two that currently supply the Dewar Street substation. The company noted that the current cost estimate for the project along the preferred route is about $68.3m (2019 dollars), estimated at a planning grade level (-25%/+25%).

In Maryland, Exelon’s Baltimore Gas and Electric (BGE) on Feb. 21 filed with the Maryland Public Service Commission an application for a certificate of public convenience and necessity to complete the estimated $8.7m Five Forks to Maryland/Pennsylvania Border Transmission Line Reliability Project. The project consists of the rebuild of a 1.89-mile existing 115-kV dual-circuit transmission line segment between BGE’s Five Forks substation in northern Harford County, Md., and the Maryland/Pennsylvania border. The company added that the project involves removing two existing parallel, single-circuit, steel lattice tower-supported electric transmission lines spanning 1.89 miles, and replacing them with one double-circuit, weathering steel monopole line. BGE said that it would remove 40 steel lattice towers as part of the project and replace them with 12 weathering steel monopoles along the 1.89-mile stretch of BGE-controlled ROW. BGE said that the project has a target in-service date of Dec. 31, 2021, for the new double-circuit, steel monopole line, with site stabilization expected to be complete in early spring 2022. Under current plans for the project, BGE said that it anticipates performing construction from June through December 2021.

In New York, the New York Power Authority (NYPA) on Feb. 24 told the New York State Public Service Commission that it intends to begin construction activities for the Moses-Adirondack Smart Path Reliability Project on March 6. NYPA noted that the commission’s Feb. 6 order approving the environmental management and construction plan (EM&CP) for the project states, “The certificate holder shall not commence construction until it has received a ‘notice to proceed with construction’ sent by the deputy director of the Environmental Certification and Compliance Section of the Office of Electric, Gas and Water.” In a Feb. 25 letter to NYPA, the director of facility certification & compliance, Environmental Certification and Compliance of the Office of Electric, Gas and Water, said that state Department of Public Service (DPS) staff has determined that the information provided in NYPA’s Feb. 24 letter “sufficiently meets the requirements of the orders issued in the” proceeding (Case 18-T-0207). The director said, “You are hereby authorized to begin activities required for the construction to rebuild the existing Moses-Adirondack 1&2 230 kV Transmission Lines for Phase One, Segment One (proposed structures 9/1 E&W to proposed structures 33/4 E&W).” According to a notice of the start of construction included in NYPA’s Feb. 24 filing, NYPA will build the project in two phases, with Phase One of the project involving rebuilding the existing approximately 78-mile, single-circuit, predominantly wood pole portion of the line with single-circuit steel monopoles.

Also in New York, Niagara Mohawk Power d/b/a National Grid in late February filed with the New York commission a Part 102 Report for construction activities associated with the National Grid Black River-Taylorville Conductor Clearance Refurbishment Project located in Jefferson and Lewis counties in New York. The project, the company added, involves replacing 35 double-circuit structures and installing one new intermediate structure. The transmission line consists of the National Grid Black River-Taylorville 115-kV #2 (T3060) line, double-circuited with the Black River-North Carthage #1 (T3050) 115-kV line from Structure 128 to Structure 230, and the North Carthage-Taylorville #8 (T6270) 115-kV line from Structure 1 to the North Carthage substation. The line is about 40 miles long and originates at the Black River substation in the Town of LeRay in Jefferson County, and terminates at the Taylorville substation in the Town of Croghan in Lewis County. The company also said that it proposes to begin construction of the project in late spring and complete the project by fall.

South/Midwest

Moving to Texas, a proposed order filed on Feb. 12 with the Public Utility Commission of Texas by the Office of Policy & Docket Management calls for the approval of AEP Texas Inc.’s proposed Three Rivers to Borglum to Tuleta 138-kV Transmission Line in Live Oak and Bee counties. According to the proposed order, AEP Texas and all intervenors in the docket filed an unopposed agreement to route the Three Rivers-to-Borglum line along route TRB-19A and the Borglum-to-Tuleta line along route BT-1B. The commission approves the agreed routes, the proposed order said. The Three Rivers route TRB-19A is 28.95 miles long and has an estimated cost of about $36.7m, while Tuleta route BT-1B is 22.53 miles long and has an estimated cost of about $41.3m. The proposed order added that the estimated cost of the new intermediate Borglum substation for any route, including Three Rivers route TRB-19A and Tuleta route BT-1B is about $15.4m. The total estimated cost of the Three Rivers line and the Tuleta line using Three Rivers route TRB-19A and Tuleta route BT-1B, the line terminations in the existing substations, and the new intermediate substation is about $95m. The proposed order also noted that AEP Texas estimated that it would complete construction and energize the transmission facilities by August 2022.

In other AEP Texas news, the company on Feb. 28 filed with the Texas commission an application to amend its certificate of convenience and necessity (CCN) for the Bracketville to Escondido 138-kV Transmission Line in Kinney and Maverick counties. As noted in the filing, the line would begin at the existing AEP Texas Bracketville substation, located northeast of the City of Bracketville on Farm to Market (FM) Road 334 in Kinney County, and extend to the south until it reaches the AEP Texas Escondido substation, located in northeast Eagle Pass in Maverick County. AEP Texas said that it has determined that the estimated $57.6m Route H — which has about 44.86 miles of ROW — provides the best balance of routing characteristics and best addresses certain requirements. According to the estimated schedule, construction of the facilities would begin in August 2022 and be completed in July 2023, which is also when the facilities would be energized.

Also in Texas, Sam Houston Electric Cooperative, Inc., (SHECO) on Feb. 13 filed with the Texas commission an application to amend its CCN for the proposed Fred 138-kV Transmission Line in Tyler County, Texas. SHECO said that in furtherance of its efforts to ensure that reliable service is maintained to all members at an adequate level, it is proposing to build the project with the associated Fred substation; the substation facilities portion of the project has an estimated total cost of $3.5m. SHECO said that it concluded that the estimated $19.1m, 16.6-mile “Route 4” is the route that best addresses certain requirements and rules. According to the estimated schedule, construction of the facilities would begin in May 2022 and be completed in September 2022, which is also when the facilities would be energized.

On Feb. 19, Texas commission staff recommended that the commission approve Upshur Rural Electric Cooperative Corporation’s (URECC) application to amend its CCN in order to build a new 138-kV electric transmission line in Harrison County, Texas, using the estimated $5.5m “Route 13.” As noted in the filing, the project consists of the new single-circuit line to be built on concrete or steel monopole structures, originating from the existing Hallsville substation located just east of the intersection of County Road 3428 and Fort Crawford Drive in Hallsville, and terminating at the proposed Gum Springs substation to be located about one-half mile northwest of the intersection of Whitehurst Drive and Coleman Road. Staff noted that the project is the first step in mitigating future loading constraints on the existing transmission network by providing a looped service between URECC’s Diana Metering Point and the Gum Springs substation, allowing the Diana Auto Station, the Noonday substation, and the Hallsville substation to have redundant 138-kV transmission service in the case of an outage event on any other line segment.

Moving to Mississippi, a Mississippi Public Service Commission hearing examiner on Feb. 5 recommended that the commission grant to Cooperative Energy and Delta Electric Power Association — referred to as the petitioners — a certificate of public convenience and necessity authorizing the petitioners to acquire the necessary sites and ROWs for Cooperative Energy to build, maintain, and operate two 115-kV electric transmission lines and switching station in Leflore and Sunflower counties in Mississippi, as well as for Delta to build, maintain, and operate a 115:13.2-kV substation facility in Leflore County. Describing the facilities, the hearing examiner noted that Cooperative Energy’s estimated $5.5m 115-kV line (L620 Half Mile to Itta Bena 115-kV Line), for instance, would be about 10.5 miles and run between Cooperative Energy’s proposed 115-kV 3-way GOAB switch to be located at Delta’s proposed Half Mile 115:13.2-kV substation and Cooperative Energy’s proposed new Itta Bena 115-kV switching station.

Also in Mississippi, a commission hearing examiner on Feb. 7 recommended that the commission grant to Mississippi Power Company (MPC) a certificate of public convenience and necessity for a transmission project in George County, Miss. The Lucedale Evanston Rd 115-12.47-kV transmission project in George County would allow MPC to serve new and existing customers; improve the reliability and resiliency of MPC’s electric grid; and serve the public interest, according to the company. The cost to design and build the project is estimated to be about $8.95m and the project is expected to be completed by Jan. 31, 2021, the company said.

In Indiana, American Electric Power’s Indiana Michigan Power (I&M) on Feb. 21 said that it plans an approximate $77m investment to upgrade the electric transmission network serving customers in Allen and Whitley counties in northeastern Indiana through the Western Fort Wayne Area Improvements Project, which includes building about 24 miles of new 69-kV transmission line. The project also includes upgrading about four miles of 34.5-kV transmission line to 69-kV standards; upgrading several area substations; and building the new Snapper substation in southern Churubusco. According to the project schedule, construction is set to occur from spring 2021 to late summer 2022, with the facilities placed in service in late summer 2022.

In other I&M news, the company on Feb. 25 said that it plans to invest about $292m to upgrade the electric transmission system to ensure safe and reliable electric service for customers in northeast Indiana through the Fort Wayne-Richmond Transmission Line Rebuild Project, which involves updating about 140 miles of 138-kV transmission line and upgrading two substations. According to the project schedule, construction is slated to occur summer 2021 to late 2025, with the project placed in service in late 2025.

In Wisconsin, American Transmission Company (ATC) on Feb. 26 filed with the Public Service Commission of Wisconsin the company’s final cost report for the Branch River Electric Reliability Project, which, as TransmissionHub reported, was placed in service on Feb. 28, 2018. ATC said that a number of factors contributed to project cost savings, noting that the 138-kV transmission line was re-spanned during final design, resulting in one planned structure being eliminated. The final total gross project cost is about $28.1m, compared to the “ordered” total gross project cost of about $40.9m, the company said.

West

Moving further West, the Arizona Power Plant and Transmission Line Siting Committee voted 7-1 to grant DCR Transmission, L.L.C., a certificate of environmental compatibility for construction of the Ten West Link Project, a 500-kV transmission line, according to the Feb. 12 certificate. As noted in the certificate, the project includes the construction and operation of the line, associated appurtenances, and infrastructure to run about 103.5 miles from Arizona Public Service’s Delaney substation near Tonopah, Ariz., until it crosses the Colorado River into California. The entire length of the line will be 125 miles long, using a combination of existing utility corridors, the Department of Energy’s Energy Corridor, as well as private and state land. The committee added in its certificate that the line will ultimately terminate at Southern California Edison’s Colorado River substation near Blythe, Calif. The committee noted that the certificate is granted upon certain conditions, including that the authorization to build the project is to expire 10 years from the date the certificate is approved by the Arizona Corporation Commission, with or without modification.

In Colorado, Public Service Company of Colorado on Feb. 21 filed with the Colorado Public Utilities Commission an application requesting that the commission grant a certificate of public convenience and necessity to build the Greenwood to Denver Terminal 230-kV Transmission Project (GDT Project) and three transmission line update projects. The GDT Project includes installing about 15 miles of new 230-kV transmission facilities located in existing ROWs originating at the existing Greenwood substation located in the southeastern Denver Metro area and terminating at the Denver Terminal substation located on the west side of the City of Denver’s city center. The GDT Project and transmission line uprates are needed to implement the Colorado Energy Plan Portfolio approved by the commission in another proceeding (16A-0396E). The company also said that it estimates that the construction of the project using the preferred approach would cost about $50.1m with an additional $1.8m for the three transmission line uprate projects, both components plus or minus 20%. The GDT Project is included in the company’s capital budget and Public Service plans to begin construction in July 2021. The company added that it anticipates the project to be in service in December 2022.

Lastly, in California, the California ISO, in a Feb. 28 notice, said that it has selected LSPGC as the approved project sponsor to finance, build, own, operate, and maintain the Round Mountain 500-kV Dynamic Reactive Support transmission solution. The ISO noted that it conducted a comparative analysis of six qualified project sponsors and their 12 applications. In a March 2 statement, LS Power President Paul Thessen said, in part: “The project to be constructed by LS Power consists of two static synchronous compensator (STATCOM) units and a new 500 kV switching station to be installed in rural Shasta County, California, interconnecting the two existing Round Mountain to Table Mountain 500 kV transmission lines. The in-service date is planned for June 2024.” The ISO noted that LSPGC proposed several cost containment mechanisms, including binding capital cost of $75.5m, with certain exceptions; AFUDC included in project cost cap; binding return on equity cap of 9.80% for the life of the project; and binding equity percentage cap of no more than 45% equity for the life of the project.