TransmissionHub presents a roundup of most of the transmission project news that occurred in January, including the Ohio Power Siting Board (OPSB), in an order entered on Jan. 16, directing that a certificate be issued to American Transmission Systems, Incorporated, (ATSI) for construction of the Wood County 138-kV Reinforcement Project, which involves a new 138-kV transmission line in Wood County, Ohio.
Starting in Texas, as noted in a Jan. 2 notice of approval signed by an administrative law judge (ALJ), the Public Utility Commission of Texas approves Wind Energy Transmission Texas’ (WETT) October 2019 application to amend its certificate of convenience and necessity (CCN) for the design and construction of a new single-circuit, 138-kV transmission line in Borden County to interconnect a new 300-MW solar generation facility. As noted in the filing, the line will interconnect the existing Long Draw high-voltage switching station and the new Juno Solar collector substation. The estimated cost of the line is about $5.9m, with an additional estimated $1.6m in substation construction costs, the ALJ said.
In other WETT news, WETT and Oncor Electric Delivery Company on Jan. 14 filed with the Texas commission a joint application to amend their respective certificates of convenience and necessity (CCN) for the proposed Bearkat Switching Station to Longshore Switching Station 345-kV Transmission Line in Glasscock and Howard counties. The companies noted that the proposed double-circuit-capable line would be built between a new 345-kV bay at WETT’s existing Bearkat 345-kV high-voltage switching station — located about 7.2 miles southwest of Garden City in Glasscock County — and a new 345-kV bay at Oncor’s existing Longshore switching station — located about 4.8 miles west of the community of Forsan in Howard County. The estimated capital cost for the project using the approximately 30.8-mile “Route 102,” which is the route that the companies recommend as best meeting certain requirements, is about $63.9m, the companies said. According to the estimated schedule, construction of the facilities would begin in July 2021 and be completed in March 2022, which is also when the facilities would be energized.
In other Oncor news, the company and Texas commission staff on Jan. 24 filed with the commission a joint proposed notice of approval for Oncor’s 138-kV transmission line in Dallas County, known as the Sargent Road-to-Oakland Avenue Tap. The new single-circuit line would be built between Oncor’s existing Sargent Road switch station in Dallas County, and an existing tap point between Oncor’s existing Parkdale to Sargent Road 138-kV transmission line and its Oakland Avenue Tap 138-kV transmission line in Dallas County. The route that Oncor proposed in the application is about 2.5 miles long. The filing added that the estimated cost of the project’s transmission line facilities is about $4.9m, while the estimated substation facilities cost is about $1.4m and includes the costs associated with the Sargent Road switch station, East Network substation, and Oakland Avenue substation.
Also in Texas, AEP Texas, Inc., on Jan. 8 filed with the commission an unopposed settlement agreement involving the company’s proposed Three Rivers to Borglum to Tuleta 138-kV Transmission Line in Live Oak and Bee counties. As noted in the filing, AEP Texas in April 2019 filed with the commission an application to amend a certificate of convenience and necessity (CCN) to build, own, and operate a new 138-kV transmission line that would be comprised of two transmission line segments. The first segment would begin at the existing AEP Texas Three Rivers substation located northeast of the City of Three Rivers in Live Oak County, and extend southeast until it reaches the proposed AEP Texas Borglum substation to be located south of the City of Beeville in Bee County. The filing added that the second segment of the project would begin at the proposed Borglum substation and would continue in a northerly direction until it reaches the existing AEP Texas Tuleta substation located north of the community of Tuleta in Bee County. According to a proposed order filed by AEP Texas with the commission on Jan. 8, the total estimated cost of the settlement routes, the line terminations in the existing substations, and the new intermediate substation is about $95m.
In Ohio, FirstEnergy’s ATSI on Jan. 2 filed with the OPSB a preapplication notification letter for the Beaver-Wellington 138-kV Transmission Line Project, which involves building an approximately 23.2-mile line that would extend from the existing Beaver substation in the City of Lorain, Lorain County, Ohio, to the existing Wellington substation in Wellington Township, Lorain County. The project is needed to improve the reliability of electrical service to the area, the company said, adding that the project would reduce the risk of a regional outage, improve voltage stability in the area, and allow for future load growth as new businesses and homes are built.
Also in Ohio, the OPSB, in an order entered on Jan. 16, directed that a certificate be issued to ATSI for construction of the Wood County 138-kV Reinforcement Project, which involves a new 138-kV transmission line in Wood County, Ohio, that will be about six miles long and run from the existing Lemoyne-Midway 138-kV Transmission Line to the Brim substation. Total estimated capital and intangible costs are expected to be nearly $8.5m for either the preferred or alternative route, the board noted. ATSI proposes to place the line in service by June, according to the order.
In another Jan. 16 order, the OPSB directed that a certificate of environmental compatibility and public need be issued to Dayton Power and Light (DP&L) for the construction, operation, and maintenance of the West Milton to Eldean 138-kV Transmission Line Project in Miami County, Ohio, which will connect the West Milton substation located just south of the Village of West Milton in Union Township and the existing Eldean substation located on Experiment Farm Road northwest of Troy, Ohio. According to DP&L, total estimated capital and intangible costs are expected to be nearly $13m for either the alternate route or the preferred route.
On Jan. 6, Ameren said that its wholly owned subsidiary, Ameren Transmission Company of Illinois (ATXI), has completed and energized the $267m, 345-kV Mark Twain Transmission Project, which involves a substation and a 96-mile transmission line that travels west from Palmyra to Kirksville, Mo., then north to the Iowa border. The project, which includes the Zachary substation in Adair County, Mo., was placed into service as expected on Dec. 19, 2019, the company said.
Separately on Jan. 6, AEP’s Indiana Michigan Power said that it plans to invest about $62m to upgrade the electric transmission systems to ensure safe and reliable electric service to customers in Berrien County through the Berrien Springs Area Improvements Project. The project includes building the Blossom Trail substation in Eau Claire. According to the project schedule, construction would occur early 2020-late 2020, and the facilities would be placed in service in late 2020.
On Jan. 13, the Tennessee Valley Authority said that the deadline for public comments on a transmission project that involves building about 11 miles of 161-kV transmission line to provide power for growing load and increase power reliability in the Trade area of Cullman County, Ala., served by Cullman Electric Cooperative (Cullman EC), is Feb. 18. Cullman EC plans to expand and upgrade the Trade 46-kV substation to 161 kV, TVA said, adding that its proposed line would begin at Cullman EC’s existing Bremen 161-kV substation located on Alabama Highway 69, and then extend northwest 11 miles to the upgraded Trade substation located west of the intersection of County Roads 937 and 933. The project is expected to be in service in early 2023, with construction scheduled to begin in fall-winter 2022-2023, the site said. TVA spokesperson Malinda Hunter on Jan. 17 told TransmissionHub that the budget for the project is about $10m.
In Wisconsin, American Transmission Company (ATC), in a Jan. 21 quarterly progress report for the period Oct. 1, 2019, through Dec. 31, 2019, on its Boscobel to Lone Rock (Line Y124) Rebuild Project, told the state Public Service Commission that the rebuild of Y124 is substantially complete, with Y124 placed in service on Nov. 20, 2019. A 1.7-mile segment of Y124 remains to be rebuilt in coordination with the Muscoda Utilities expansion of an industrial substation, ATC said, adding that the rebuild of that portion of the line is expected to be completed by Dec. 1. The actual total project cost through Dec. 31, 2019, was about $29.7m, while the commission-approved total project cost is about $32.4m, and the estimated total project cost at completion is about $31.9m, ATC said.
On Jan. 23, ATC told the Wisconsin commission that physical construction of the Caldron Falls-Goodman (J-88) Project is about 90% complete, and that restoration of the right of way (ROW) continues. In its quarterly progress report for the period Oct. 1, 2019 through Dec. 31, 2019, ATC said that the planned project in-service date is 1Q20, and that all activities necessary to support that in-service date remain on schedule. The actual total gross project cost as of Dec. 31, 2019, was about $20.4m, ATC said, adding that the commission-authorized total gross project cost is about $28.2m, while the revised total gross project cost estimate as of Dec. 31, 2019, is about $23.2m. As noted on the project’s webpage, ATC plans to rebuild a 21-mile, 69-kV transmission line in Marinette County between the Caldron Falls Hydro substation on Boat Landing 8 Road and the Goodman substation on 614 Woods Lake Road.
On Jan. 30, ATC filed with the Wisconsin commission a progress report for the period Oct. 1, 2019 through Dec. 31, 2019, for the company’s Cardinal-Hickory Creek Transmission Line Project, noting that it expects to begin construction of the Hill Valley substation in 2Q21. ATC in August 2019 said that it, ITC Midwest, and Dairyland Power Cooperative – collectively referred to as the applicants – received approval for the estimated $492m project from the Wisconsin state commissioners, who, at their Aug. 20, 2019, open meeting, verbally approved issuance of the CPCN, and selected the route for the Wisconsin portion of the project. Of real estate activities, ATC said in its Jan. 30 filing that it has assembled title and parcel ownership information for its portion of the project. ITC Midwest began meeting with landowners in Wisconsin regarding voluntary access for pre-construction activities in 4Q19. ATC said that the total project cost as of Dec. 31, 2019, was about $51m of the approved approximately $492.2m total project cost.
Central Maine Power (CMP) on Jan. 8 said that the Maine Land Use Planning Commission has voted to issue site law certification to the company to build the New England Clean Energy Connect (NECEC), with certain conditions, including that CMP maintain buffering measures at the Kennebec River gorge area. As noted in the company’s statement, the project is designed to provide 1,200 MW of transmission capacity and to deliver renewable electricity to the New England grid from hydropower resources in Québec. The commission noted that CMP describes the project in five segments, with Segment 1, for instance, being about 53.5 miles long, beginning in Beattie Township and ending in Moxie Gore, entirely within townships and plantations served by the commission.
The New York State Public Service Commission on Jan. 10 told New York State Electric & Gas (NYSEG) that the commission will not require an investigation of the project involving a new substation that the company will build adjacent to the existing Willet substation, which in turn requires four additional structures to be added to the existing 115-kV Circuit 945 to allow continued connection into and out of the new substation. The commission said, “The work proposed in the Line 945 Structure Additions for Willet Substation Relocation Project located in the Town of Willet, Cortland County, has been reviewed pursuant to 16 NYCRR Part 102.” As TransmissionHub reported, according to NYSEG’s Part 102 Report filed in November 2019, presently, sub-marginal voltages appear in the areas served from the Marathon, Chenango Forks, Dorchester, Greene, Kattelville, Willet, High Street, Tarbell, and Whitney Avenue substation upon loss of the Willet 115/34.5-kV transformer. NYSEG said that construction of the new substation is proposed to begin in December and that the four additional 115-kV structures that are subject of the Part 102 Report are proposed to be built in March 2020.
On Jan. 17, the New York commission said that informational forums and public statement hearings on the “Edic/Marcy to New Scotland; Princetown to Rotterdam Project” will be held from March 3 to March 5 in various locations, starting in Utica and Herkimer in New York. As noted in the filing, public comment is sought on the request by LS Power Grid New York, LLC, LS Power Grid New York Corporation I, and the New York Power Authority — collectively referred to as the joint applicants — for a certificate of environmental compatibility and public need under Article VII of the Public Service Law to build the approximately 93-mile, 345-kV transmission line that would begin at the Edic substation in Marcy and end at the New Scotland substation in Albany.
In Pennsylvania, Exelon’s PECO on Jan. 10 told the state Public Utility Commission that it completed the work on its Emilie-Falls 138-kV Transmission Line reconductoring project in Bristol and Falls townships in Bucks County, Pa., for a project cost of about $5.7m, comprised of about $1.2m for materials and $4.5m for labor and related overheads. As TransmissionHub reported, PECO in June 2019 filed with the commission a letter of notification, stating that it proposes to reconductor the existing 138-kV line from the company’s Emilie substation, extending about four route miles through Bristol Township and Falls Township. Noting the expected project cost of $6.5m, PECO said in its Jan. 10 filing that the additional $800,000 that was not spent was for budgeted contingency events that did not occur and for which expenditures were thus not required.
On Jan. 23, a PPL Electric Utilities spokesperson told TransmissionHub that while the company continues to believe that Project Compass “would benefit customers, we do not expect to make a filing until there is a clearer path to regulatory approval.”
Joe Nixon, PPL Electric Utilities strategic communications manager, also said: “There are no updates to share at this time. We continue to monitor the New York and Pennsylvania political environment with an eye toward pursuing potential avenues for a successful Project Compass in the future.”
As TransmissionHub reported in February 2017, PPL, in a presentation related to its 4Q16 earnings call, said that the estimated in-service date for the proposed first segment of Project Compass was in 2023. As noted on PPL Electric Utilities’ website at the time, the first segment of the project was a 95-mile, 345-kV line between Blakely, Pa., and Ramapo, N.Y., that would “be an important link between the” regions of PJM Interconnection and the New York ISO. That webpage on the company’s website does not exist at this time. According to the presentation, the proposed first segment of the project had an estimated cost of $400m to $500m. PPL Electric Utilities had also noted that while the first segment could stand alone as a valuable grid component, the company was continuing to refine the overall plan for the rest of Project Compass, which, as envisioned at the time, would run about 475 miles from western Pennsylvania into southeastern New York. Project Compass’ cost was estimated at $3bn to $4bn, PPL said at the time.
NSTAR Electric Company d/b/a Eversource Energy told the Massachusetts Energy Facilities Siting Board that as of Jan. 14, the projected completion date for a new 115-kV line, as well as for the Sharon switching station improvements, that are part of the Walpole to Holbrook Reliability Project, is in June. The projected total cost for the new line is $29.9m, and $20.3m for the station improvements, for a total of $50.2m. The company added that actual costs as of Dec. 31, 2019, were $28.4m for the new line and $15.8m for the station improvements, for a total of $44.2m. As noted on the project’s webpage, the project will cover about 14.7 miles between the West Walpole and Holbrook substations, with the new line to be placed almost entirely on existing structures.
In Virginia, Virginia Electric and Power (Dominion) on Jan. 28 filed with the State Corporation Commission an application for approval of the Chesterfield-Tyler 230-kV Transmission Lines #205 and #2003 Partial Rebuild Project. The company said that it proposes to rebuild, within an existing right of way (ROW) or on company owned property, an approximately 3.2-mile section of the existing 230-kV Chesterfield-Locks Line #205 and Chesterfield-Poe Line #2003 between the company’s existing Chesterfield substation, which is located on the company’s Chesterfield power station site, to Structure #205/19A, #2003/25, which is located about 0.6 mile south of the company’s existing Tyler substation, all within Chesterfield County, Va. The company noted that it also proposes to perform minor work at the Chesterfield and Tyler substations. Should the commission issue a final order by March 1, 2021, the company estimates that construction should begin on Jan. 1, 2022, and be completed by Dec. 31, 2022. The company added that the estimated conceptual cost of the rebuild project is about $11.1m, which includes about $10.8m for transmission-related work and about $0.3m for substation-related work (2019 dollars).
Tucson Electric Power (TEP) on Jan. 15 filed with the Arizona Power Plant and Transmission Line Siting Committee an application for a certificate of environmental compatibility for the Irvington to East Loop 138-kV Transmission Line Project. As noted in the filing, the project would provide increased transmission capacity that would improve reliability; enable and enhance TEP’s ability to respond to future load growth; provide contingency support to existing distribution substations; assist Davis-Monthan Air Force Base (DMAFB) in fulfilling the Department of Defense (DOD) directive for enhancing energy resiliency; and over time, allow replacement of part of the existing aging 46-kV system serving the area. The line would be about 11 to 13 miles long, depending on the alternative approved, and connect the existing Irvington substation to the East Loop substation. The total project cost is anticipated to range between $17.8m to $19.8m, depending on which alternative is selected, TEP added. The siting committee on Jan. 15 said that a public hearing on the proposed project will begin on Feb. 24 in Tucson, Ariz., and continue on Feb. 25 through Feb. 28, as necessary.
The California ISO, in a Jan. 17 notice, said that it has selected LS Power Associates, L.P.’s wholly owned subsidiary, LS Power Grid California, LLC, (LSPGC) as the approved project sponsor to finance, build, own, operate, and maintain the Gates 500-kV Dynamic Reactive Support transmission solution. The ISO said that it conducted a comparative analysis of four qualified project sponsors and their 10 applications. As noted in the Jan. 17 selection report concluding the competitive solicitation process for the project, the project involves an approximately 800 MVAR dynamic reactive device to be installed in two equally sized blocks independently connected to the 500-kV bus at the Gates substation owned by Pacific Gas and Electric (PG&E). LSPGC proposed a final completion date of December 2023, almost six months earlier than the ISO-specified in-service date for the project of June 1, 2024. The ISO said that LSPGC proposed several cost containment mechanisms, including a binding capital cost cap of $68.3m, with certain exceptions; a binding return on equity cap of 9.80%; and a binding equity percentage cap of no more than 45% equity for the life of the project.
In other California news, the ISO, in its Jan. 31 Draft 2019-2020 Transmission Plan, said that it has identified nine transmission projects with an estimated cost of about $141.7m as needed to maintain transmission system reliability, with one of the projects being advanced for economic benefit purposes from when it would otherwise be needed for reliability purposes. The ISO said that the reliability projects found to be needed include the $19m-$38m Salinas-Firestone #1 and #2 60-kV lines located in the PG&E service area, with an expected in-service date of 2024. Consistent with past studies of transmission system capabilities to achieve renewable portfolio standard (RPS) levels beyond 33%, no policy driven transmission was considered for approval in this planning cycle to achieve the 60% RPS goal established in SB 100, and sensitivities have been undertaken at higher – 71% – RPS levels, identifying potential reinforcement needs subject to resource location considerations in future California Public Utilities Commission (CPUC) integrated resource planning efforts. The ISO added that no economic-driven transmission projects are recommended for approval in this planning cycle.
On Jan. 23, Public Service Company of Colorado filed with the Colorado Public Utilities Commission its “2019 Semi-Annual Progress Report #5,” on the Pawnee-Daniels Park 345-kV Transmission Project, noting that as of Dec. 31, 2019, the project cost estimate at completion was $169.4m. That estimate has increased about $7.6m since the last semi-annual progress report was filed in July 2019, due to increased project costs for contractor labor — premium time — for construction sequencing changes, foundation and structure field design changes, helicopter construction and additional traffic control for Interstate-25 and Parker Road, overhead line construction required by the Colorado Department of Transportation and the Federal Aviation Administration (FAA), company substation construction and equipment failure mitigations, as well as a corresponding increase to the project overheads and contingency. The company added that the Pawnee-Daniels Park 345-kV system was completed and the last segment energized on Dec. 26, 2019. There are about $1.3m of expenditures forecast through April to complete Phases 8 and 9 of the Smoky Hill 230-kV substation (east and west bus differential modifications), FAA structure lighting communications check, project site restoration, and transmission line corridor revegetation, the company said.
The Hawai’i Public Utilities Commission, in a Jan. 24 order established a procedural schedule and statement of issues regarding Hawai’i Electric Light Company’s application for approval to build 69-kV overhead transmission line segments to reconnect the Puna Geothermal Venture (PGV) generating facility. As noted in the company’s June 2019 application, the 2018 Kilauea eruptions destroyed the interconnection facilities that connected PGV’s geothermal energy facility with the company’s Hawai’i Island electric grid. Hawai’i Electric Light and PGV have since entered into a rebuild agreement to restore power to PGV and reconnect its facility to the company’s system, the company added in its application, noting that under the agreement, it would rebuild two segments of its 69-kV transmission lines: an approximately one-mile segment of the 6500 line and an approximately one-and-a-half-mile segment of the 8700 line. The overhead transmission reconstruction work for the 8700 line consists of the installation of 23 new 70-foot steel poles and five new 75-foot steel poles; 15 anchors; and about 7,139 circuit feet of 556.5 MCM AAC 69-kV overhead conductors and #3/0 AAAC shield wire for the 69-kV transmission pole line reconstruction.