TransmissionHub presents a roundup of most of the transmission project news that occurred in June, including Massachusetts regulators approving power purchase agreements (PPAs) for hydroelectric generation and associated environmental attributes in relation to the New England Clean Energy Connect transmission line.
Starting in Texas, Public Utility Commission of Texas staff on June 3 told the commission that a 345-kV transmission line and a 115-kV transmission line proposed by Oncor Electric Delivery Company and the City of Lubbock, acting by and through Lubbock Power and Light (LP&L), are “necessary for the service, accommodation, convenience, and safety of the public.”
Staff – in its recommendations concerning the joint application of Oncor and LP&L to amend their certificate of convenience and necessity (CCN) to build the new single-circuit, 345-kV Wadsworth to New Oliver to Farmland Line (WNF Line) on double-circuit-capable structures in Lubbock and Lynn counties, as well as the new single-circuit, 115-kV Southeast to New Oliver to Oliver Line (SNO Line) in Lubbock County – said that the applicants’ proposed routes are adequate in number and geographic diversity. Staff noted that as stated in the application, the CCN is needed to integrate a portion of LP&L’s system, about 470 MW of load, into the interconnect managed by ERCOT.
On June 4, the Texas Parks and Wildlife Department (TPWD) on June 4 issued recommendations to the Texas commission regarding AEP Texas, Inc.’s proposed Three Rivers to Borglum to Tuleta 138-kV Transmission Line in Live Oak and Bee counties in Texas. As noted in the filing, American Electric Power’s (AEP) AEP Texas proposes to build the new line, which would be comprised of two segments, with the first segment beginning at the existing AEP Texas Three Rivers substation located northeast of Three Rivers on State Highway (SH) 72 in Live Oak County and extending southeast to the proposed AEP Texas Borglum substation to be located south of the City of Beeville on U.S. Highway (US Hwy) 181 Business in Bee County, Texas. That segment would be referred to as the Three Rivers to Borglum Segment (TRB), which would be a single-circuit, 138-kV line and could include rebuilding portions of an existing AEP Texas 138-kV line.
The TPWD added that the second segment would begin at the proposed Borglum substation and continue northerly to the existing AEP Texas Tuleta substation in Bee County. That segment, referred to as the Borglum to Tuleta Segment (BT), would be a double-circuit transmission line to accommodate a new 138-kV circuit and an existing 69-kV circuit. Route TRB 19 appears to be the route that causes the least adverse impacts to natural resources, the TPWD said, adding that Route BT 1 appears to best minimize adverse impacts to natural resources.
According to the estimated schedule, construction of the facilities would begin in June 2021 and be completed in August 2022, which is also when the facilities would be energized.
In a June 17 order, the Texas commission amended Lower Colorado River Authority Transmission Services Corporation’s (LCRA TSC) CCN to include the construction and operation of the Cooks Point substation and a new 138-kV transmission line that will connect that substation to Bluebonnet Electric Cooperative, Inc.’s existing Lyle Wolz substation. The commission noted that Route 12 – which the commission adopted as the route for the project is, for instance, estimated to be the second least costly route with an estimated cost of about $35.7m, and is the sixth shortest route at 18.3 miles.
According to a June 18 notice of approval signed by a commission administrative law judge, the Texas commission amends Wind Energy Transmission Texas’ (WETT) CCN to permit construction and operation of the Long Draw Solar Station to Long Draw Switching Station 138-kV Transmission Line in Borden County using the proposed route. WETT proposed a single route, which will be about 1.8 miles long and built primarily on steel monopole structures between the proposed 138-kV expansion of WETT’s existing Long Draw 345-kV switching station and proposed Long Draw Solar collector substation.
The project is necessary to implement the request of ENGIE Long Draw Solar, LLC for direct interconnection of its 225-MW solar project to WETT’s 345-kV transmission system, the notice added. The project’s total estimated cost is about $14.6m, the notice said, adding that based on the total amount, about $2.2m is attributable to transmission line costs; the substation facilities account for the remaining estimated total amount, about $12.4m.
In a June 26 order, the Texas commission approved the construction and operation of the Sand Lake-to-Solstice proposed transmission facilities on Route 320, with certain modifications. As noted in the order, Oncor Electric Delivery Company, LLC and AEP Texas in November 2018 filed a joint application to amend their CCNs for the proposed double-circuit 345-kV transmission facilities in Pecos, Reeves, and Ward counties.
In Minnesota, Great River Energy on June 3 filed with the state Public Utilities Commission an application for a route permit for the approximately $1.5m Lake Eunice 115-kV Transmission Conversion Project. Great River Energy noted that the project involves converting about a 0.80-mile portion of its 41.6-kV LR-LET transmission line to 115-kV standards in Becker County, Minn., to serve the proposed 115-kV conversion of the Lake Eunice substation. Great River Energy proposes to remove 3.65 miles of the 10.24-mile 41.6-kV LR-LET transmission line and build a 0.80-mile 115-kV transmission line between the existing Lake Eunice substation and the existing Great River Energy LR-CF 115-kV transmission line.
Great River Energy added that it anticipates start of construction in fall 2020, and energization of the 115-kV line in spring 2021.
AEP’s Indiana Michigan Power (I&M) on June 6 said that it would hold an open house on June 20 in Yorktown, Ind., regarding its proposed Yorktown Area Improvements Project, which involves upgrading about two miles of 34.5-kV transmission line to 69-kV standards. The company said that the approximate $6.5m investment to upgrade the electric transmission network serving customers in Delaware County in eastern Indiana are designed to help ensure reliability for customers, as well as support economic development. According to the project schedule included in a fact sheet, transmission line construction would occur early 2022 to summer 2022, with the facilities placed in service that summer, as well.
In other AEP news, Ohio Power Siting Board (OPSB) staff, in a June 7 report, said that it recommends that the OPSB approve AEP Ohio Transmission Company’s (AEP Ohio Transco) December 2018 application regarding proposed modifications to the company’s approved Dennison-Yager 138-kV Transmission Line Rebuild Project. As noted in the filing, AEP Ohio Transco is proposing an amendment to the project which was approved by the OPSB in May 2017. Proposed adjustments are proffered following final detailed engineering, land surveying, and property owner discussions regarding the approved route, staff said.
On June 21, AEP Ohio Transco filed with the OPSB an amendment application for a certificate of environmental compatibility and public need for the Rouse to Bell Ridge 138-kV Transmission Line Project. As noted in the filing, the OPSB in September 2018 issued its certificate of environmental compatibility and public need for the preferred route. The purpose of the amendment is to document the changes to the preferred route alignment since the OPSB’s approval of the preferred route, as well as to seek OPSB approval of the revised alignment, the company said. The project is about 12.6 to 12.8 miles in length, depending on the route selected, and will be built using primarily steel H-frame structures. Construction of the project would take place from summer 2020 to early 2021, with the project completed and in-service in early 2021, the company added.
In a June 11 order, the Mississippi Public Service Commission granted to Entergy’s Entergy Mississippi a certificate of public convenience and necessity to acquire, build, expand, operate, own, and maintain proposed electrical facilities in Simpson and Rankin counties. As noted in the order, Entergy Mississippi proposed to rebuild a 15-mile section of the South Jackson-Magee 115-kV transmission circuit from the Star substation to the Mendenhall substation – referred to as the Star-Mendenhall 115-kV Line Rebuild project – as well as a 10-mile section of the South Jackson-Magee 115-kV transmission circuit from the Mendenhall substation to the Magee substation – referred to as the Mendenhall-Magee 115-kV Line Rebuild project.
According to the direct testimony of Milton Watts, a manager in the Project Management and Construction Department for Entergy Services, LLC (ESL), the total estimated cost of the proposed electrical facilities is $27m. The project is planned for the Star-Mendenhall 115-kV Line Rebuild project to be operational by June 2020, and for the Mendenhall-Magee 115-kV Line Rebuild project to be operational by December 2020, subject to the receipt of necessary permits and required approvals, according to Watts.
According to a June 18 order signed by an Arkansas Public Service Commission administrative law judge, the commission granted a certificate of environmental compatibility and public need (CECPN) to Carroll Electric Cooperative Corporation (CECC) to build and operate a 161-kV transmission line and associated facilities in Carroll County, Ark. As noted in the order, CECC in February filed an application with the commission seeking a CECPN to build and operate about 14 miles of new 161-kV transmission line between CECC’s planned Green Forest substation in Carroll County, and Arkansas Electric Cooperative Corporation‘s (AECC) planned 161-69-kV Long Creek transmission substation in Stone County, Mo.
As noted in the order, the $9m line will provide a transmission source to AECC’s 161-69-kV Long Creek transmission substation located in the vicinity of the existing transmission feed to the JJ Highway substation on KAMO Electric Cooperative, Inc.’s existing 69-kV transmission system located in Missouri. CECC plans to begin clearing in 4Q19; construction would begin in early 2020, and complete prior to the end of 2020.
In Kentucky, AEP’s Kentucky Power on June 27 filed with the state Public Service Commission an application for a certificate of public convenience and necessity authorizing the company to upgrade, replace, and install work in connection with facilities and equipment at its existing Hazard 161/138/69-kV substation in Hazard, Ky., and Wooton 161-kV substation in Leslie County, Ky. The company said that the total estimated cost of the project is $25.3m, which comprises about $25m for improvements at the Hazard substation and about $0.3m improvements to the Wooton substation.
In Virginia, the State Corporation Commission said in a June 5 order for notice and comment that persons interested in Virginia Electric and Power’s (Dominion) May application for a certificate of public convenience and necessity (CPCN) to rebuild about 11.1 miles of the existing 230-kV, overhead, single-circuit transmission Line #247 are to file written comments on the matter with the commission by Aug. 2. The company seeks approval to, for instance, rebuild, entirely within existing right of way (ROW) or on company owned property, about 31.2 miles of its existing 230-kV transmission Line #247 on single-circuit structures, of which 11.1 miles are located in Virginia – in the City of Suffolk – between the Suffolk substation and the Virginia state line – which runs from Structure #247/1A through Structure #247/103 – with the remaining portion of the line located in North Carolina.
The commission also said that the company anticipates a Dec. 30, 2022 in-service date for the proposed project, subject to commission approval and outage scheduling. The company anticipates the proposed project would cost about $17.2m, including $17.1m for transmission-related work and about $0.1m for substation-related work (2019 dollars), the commission said.
In a June 19 final order, the Virginia commission authorized Dominion to build and operate the Fork Union Substation and related Line Cut-In Project, subject to certain conditions. The order added that Dominion seeks to build the new Fork Union substation located in Fluvanna County, Va., 1.5 miles from the Bremo Power Station; and, as part of this effort, cut the Bremo-Cunningham Line #5, Bremo-Sherwood Line #91, and Bremo Charlottesville Line #2028 (Line Cut-Ins) into the proposed Fork Union substation. In total, according to Dominion, the proposed project involves removing five transmission structures and the installation of 15 new transmission structures. The order added that the Line Cut-Ins entail a total increase of 0.2 mile of transmission line.
Dominion estimates the conceptual cost of the project to be about $27.2m, which includes $5.4m for transmission-related work and $21.8m for substation-related work (2018 dollars). The commission also said that the project must be built and in service by May 25, 2020; however, the company is granted leave to apply for an extension for good cause shown.
In a June 25 report, commission staff said that Dominion has reasonably demonstrated the need for a proposed project that includes converting the overhead portion of the 230-kV Glebe-Ox Line #248 and 230-kV Glebe-North Alexandria Line #2023 between the Glebe substation, located in Arlington, Va., and the Potomac Yards North Terminal Station, located in the City of Alexandria, Va., to underground lines and to tie the converted lines into the Glebe substation. The project also involves converting and rebuilding the company’s existing Glebe substation to a Gas Insulated Substation (GIS).
As noted by staff, the project is estimated to cost $122.8m, and has an expected in-service date of May 2022.
In Maryland, Exelon’s Baltimore Gas and Electric (BGE) on June 6 filed with the state Public Service Commission a request for a waiver of the requirement to obtain a CPCN in relation to its proposal to modify an existing 230-kV, overhead transmission line. BGE said that it has been directed by PJM Interconnection to modify the existing line that runs between BGE’s Northwest #2 substation in Baltimore County and BGE’s Conastone substation in Harford County. BGE said that it has been requested to deliver an installation that provides circuit ratings of 900 MVA and 1200 MVA for Summer Normal and Summer Emergency conditions, respectively.
In a June 27 order, the Maryland commission granted a joint motion to temporarily suspend the procedural schedule filed by Transource Maryland, LLC and the Department of Natural Resources, Power Plant Research Program (PPRP) in relation to Transource’s application for a CPCN to build two new 230-kV transmission lines associated with the Independence Energy Connection project in portions of Harford and Washington counties in Maryland.
Transource and PPRP on June 21 jointly filed the motion to temporarily suspend the schedule for a period of 60 days. The commission added that Transource and PPRP submit that they are in the process of engaging in settlement discussions, and that Transource has engaged in settlement discussions with each of the other parties in the case. In order to allow the parties additional time to continue settlement discussions, Transource and PPRP request that the briefing schedule be postponed by 60 days from the date of the commission’s order on their motion.
As noted on Transource’s website, the new overhead electric transmission project would be built in two segments – East and West – totaling about 45 miles of transmission line in Pennsylvania and Maryland. The project also includes construction of two substations in Pennsylvania and upgrading two existing substations in Maryland, according to the site.
In Pennsylvania, FirstEnergy’s West Penn Power on June 19 filed with the state Public Utility Commission a letter of notification (LON) requesting approval for the Charleroi-Allenport 138-kV Transmission Line Rebuild Project. Subject to commission approval, construction is scheduled to begin in October in order to meet the required in-service date of June 2020, West Penn said, adding that it is seeking approval to rebuild about 5.1 miles of the line entirely within its existing 100-foot-wide ROW. The line exits the Charleroi substation in Fallowfield Township and extends in a south/southeasterly direction to the Allenport substation located near the Monongahela River in Allenport Borough.
Noting that the project was presented at a June 2018 PJM Transmission Expansion Advisory Committee (TEAC) meeting with an accelerated required in-service date of June 1, 2020, West Penn said that the in-service date was accelerated due to the announcement of planned generations deactivation associated with the Beaver Valley, Davis-Besse, and Perry nuclear plants, totaling about 3,950 MW. West Penn said that the total projected cost of the project is about $10.7m, and would be incurred by the company.
In Massachusetts, the state Department of Public Utilities, in a June 25 order, approved the PPAs between NSTAR Electric d/b/a Eversource Energy and H.Q. Energy Services (U.S.) Inc., (HQUS); between Massachusetts Electric and Nantucket Electric d/b/a National Grid and HQUS; and between Fitchburg Gas and Electric Light d/b/a Unitil and HQUS for hydroelectric generation and associated environmental attributes.
The companies jointly solicited bids for clean energy generation resources, and as a result of that solicitation, each company seeks department approval of a power purchase agreement (PPA) to acquire its apportioned share of an annual aggregate quantity of 9,554,940 MWh of hydroelectric generation and associated environmental attributes from HQUS, an affiliate of Hydro-Québec, to be delivered into New England over new transmission infrastructure, referred to as the New England Clean Energy Connect (NECEC) transmission line, in accordance with a transmission service agreement (TSA) between each company and Central Maine Power (CMP). The department added that CMP will make transmission capacity on NECEC available to the companies to deliver electrical energy, as scheduled by the companies, up to 1,090 MW measured at the delivery point in Lewiston, Maine.
The target date for commercial operation of NECEC is Dec. 13, 2020, the department said, adding that the commercial operation date may be extended by up to four six-month periods, for a maximum combined period of two years, but not to extend beyond Dec. 13, 2024, unless the extension is due to a regulatory approval delay or an event of force majeure.
TransmissionHub reported on June 5 that Clines Corners Wind Farm LLC has filed with the New Mexico Public Regulation Commission an application requesting approval of the location of the Clines Corners Wind Farm and the associated transmission system (referred to as the Clines Corners Gen-Tie System), consisting of an approximately 18.72-mile, 345-kV, alternating current transmission line and associated facilities to be located in a 150-foot ROW within a one-mile-wide corridor. The wind farm would consist of up to 600 MW of wind power facilities and be located within an area of about 40,000 acres across Torrance and Guadalupe counties on private land.
Clines Corners added that it intends that the wind farm would be interconnected via the Gen-Tie System to the proposed Western Spirit transmission line at a point that is about 11 miles west-northwest of Encino. The Gen-Tie System is contemplated to include a single substation, as well as an interconnection facility at the Western Spirit point of interconnection.
According to the filing, through the project, Clines Corners would invest a total of about $589m in renewable energy generation in New Mexico. The filing also noted that the project is expected to be in service as early as the end of 2020.
In June 5 comments, the Regulatory Operations Staff of the Public Utilities Commission of Nevada recommended that the commission grant a petition filed by GridLiance West LLC for an advisory opinion or declaratory order seeking a determination as to whether the company’s proposed replacement of a 230-kV transmission line and 20 transmission towers, with the addition of one new tower, constitutes a “like facility.”
Staff said that it recommends that the commission find that the project is a replacement of “like kind, existing facilities, and equipment replacement within footprints of existing transmission towers,” and to determine that the project does not require a UEPA permit to construct.
In a June 11 application, Powder River Energy Corporation (PRECorp) requested an order by July 31 from the Wyoming Public Service Commission on PRECorp’s proposed Peabody 69-kV Line Reroute project, which is needed to accommodate advancing mining activities in the area.
The purpose of the project is to reroute about 3.1 miles of existing 69-kV power line with 4.8 miles of a 556 Aluminum-Conductor Steel-Reinforced cable (ACSR) conductor in a similar H-frame two-pole configuration, resulting in a net increase of power line in that area of 1.7 miles, PRECorp said. The rerouted power line would be built to current internal standards and guidelines, PRECorp said, adding that the project is anticipated to begin in August and be completed by the end of the year.