Monthly Project Review July 2018

TransmissionHub presents a roundup of most of the transmission project news that occurred in July, including American Electric Power (NYSE:AEP) saying on July 27 that it is canceling the Wind Catcher Energy Connection project as a result of the Public Utility Commission of Texas’ July 26 decision to deny approval of the project.

South/Midwest

Starting in Ohio, American Electric Power’s (NYSE:AEP) AEP Ohio Transmission Company (AEP Ohio Transco) and Ohio Power Siting Board (OPSB) staff – collectively referred to as the parties – on July 5 filed with the OPSB a stipulation intended by the parties to resolve all matters pertinent to the company’s proposed Buckley Road-Fremont Center 138-kV Transmission Line Project.

As noted in the stipulation, the company plans to rebuild 15.4 miles of the existing 17.6-mile Allendale-Fremont Center 69-kV transmission line in Seneca and Sandusky counties in Ohio to 138-kV standards. The proposed project would be built to 138-kV design capabilities and energized at 69 kV. The stipulation also noted that the parties recommend that the OPSB issue a certificate of environmental compatibility and public need for construction and operation of the project, subject to certain conditions.

According to the stipulation, the recommended conditions of the certificate include that the facility is to be installed on the applicant’s alternate route, which, as TransmissionHub reported, has an estimated total cost of about $24.1m.

AEP’s AEP Ohio on July 10 said that it and AEP Ohio Transco would host an open house on July 19 in Wapakoneta, Ohio, regarding the Wapakoneta Area Improvements Project, which consists of building about 15 miles of 138-kV transmission line, building two new substations, and expanding a substation.

AEP Ohio said that after a transmission line route is determined, it would seek regulatory approval from the OPSB. The company said that upon approval, it would work with landowners to secure easements necessary for the safe construction, operation and maintenance of the transmission line.

The preliminary schedule anticipates a construction start date of summer 2019, the company said. According to a project fact sheet, construction is slated to be complete in late 2021.

A company spokesperson on July 10 told TransmissionHub: "We don’t have a cost estimate at this time. The project is still in a preliminary planning phase."

Another AEP company, Indiana Michigan Power (I&M), on July 24 said that an open house would be held on Aug. 7 in Eaton, Ind., regarding its proposed Hartford City Area Improvements Project. Elements of the project – which is designed to strengthen the electric system in Blackford, northern Delaware, and southwestern Jay counties – include upgrading about four miles of 34.5-kV transmission line to 69-kV standards; rebuilding about eight miles of 69-kV line between Hartford City and Dunkirk; and building nearly three miles of new line in Dunkirk.

The proposed timeline calls for transmission line construction to occur in spring 2020 to late 2021; substation construction to occur in spring 2020 to spring 2021; and for the facilities to be placed in service in late 2021.

A company spokesperson on July 31 told TransmissionHub, “We will not have an estimated cost available until the route is selected.”

In late July, AEP said that it is canceling the Wind Catcher Energy Connection. A Public Utility Commission of Texas spokesperson on July 31 told TransmissionHub: “The letter is still in the ‘routing for approval’ process. When it is signed by all three commissioners, we will make it available online.”

The Arkansas Public Service Commission, Louisiana Public Service Commission, and FERC had approved the project, AEP said, adding that a decision was pending at the Oklahoma Corporation Commission.

As TransmissionHub reported, the $4.5bn, 350-mile, 765-kV project was expected to be in service in 2020. AEP’s Southwestern Electric Power Co. (SWEPCO) in June said that the project included the acquisition of a 2,000-MW wind farm under construction in the Oklahoma Panhandle, as well as construction of the dedicated power line that would carry the wind energy to the Tulsa area, where the existing grid would deliver it to customers in Oklahoma, Louisiana, Arkansas, and Texas.

Moving on to Texas, according to a July 12 proposed order sent by Irene Montelongo, director, Docket Management, to the Public Utility Commission of Texas and all parties of record, the commission approves – as modified by an agreement – Lyntegar Electric Cooperative’s December 2017 application involving the new single-circuit Welch 115-kV Transmission Line Project.

According to the proposed order, Lyntegar’s application seeks to amend its certificate of convenience and necessity (CCN) to build the project, composed of two parts, in Gaines and Dawson counties. Lyntegar filed the unopposed agreement that resolves all of the issues between the parties to the proceeding, the proposed order noted.

As part of the project, Lyntegar proposes to disconnect a portion of its load from an Oncor Electric Delivery Company 69-kV transmission line and reconnect it to a Southwestern Public Service (SPS) 115-kV transmission line, resulting in about 5 MW of load transferring from the ERCOT region to the Southwest Power Pool (SPP).

The proposed order also noted that the project’s agreed route – “route 4” – moderates the impact of the project and meets the commission’s routing criteria because it, for instance, is the second least expensive route with an estimated cost of about $10.9m, and is the third shortest route at 19.54 miles.

SPS and commission staff on July 17 filed with the commission a joint proposed notice of approval regarding SPS’ application to amend a CCN for a proposed 230-kV transmission line within Hale County.

As noted in the filing, staff on July 16 filed with the commission a pleading recommending approval of SPS’ application. In that July 16 filing, staff said that it recommends that the application be approved using the company proposed route, subject to the conditions stated in the “Measures to Mitigate Construction Impacts” in a July 16 memorandum from David Smithson, Infrastructure and Reliability Division, to Heath Armstrong, Legal Division.

Those conditions, according to the memorandum, include that in the event that SPS or its contractors encounter any artifacts or other cultural resources during project construction, work is to cease immediately in the vicinity of the resource and the discovery is to be reported to the Texas Historical Commission.

According to the July 17 joint proposed notice of approval, SPS proposes to build the line that would connect the existing TUCO substation and the new Hale Wind collection substation, which will serve a 478-MW wind generation plant and associated facilities – the Hale Wind Project – for which SPS has received generation CCN approval.

SPS proposed only one route in the application, the filing added, noting that the route is about 14.59 miles long. The project’s estimated total cost is about $9.4m, consisting of about $9.3m for transmission facilities and $124,174 for substation facilities.

In a separate matter, staff recommends that the commission approve Electric Transmission Texas’ (ETT) application to amend its CCN in order to build a new double-circuit, 345-kV electric transmission line, according to John Poole, an engineering specialist with the commission’s Infrastructure and Reliability Division.

Poole also said in his July 23 direct testimony – which was filed with the commission and provides staff’s recommendation regarding the need for the project as well as route selection – that the proposed project is necessary for the service, accommodation, convenience, and safety of the public.

As noted in his testimony, the proposed line would be supported by monopole steel structures connecting the existing AEP Texas Inc., Stewart Road substation, located south of the City of Donna, east of Farm-to-Market (FM) Road 2557/Stewart Road, to an interconnection point along the existing AEP Texas North Edinburg to Sharyland Utilities, L.P., Palmito 345-kV transmission line in Hidalgo County, Texas.

According to the filing, ETT’s estimated cost of “Route B3” is about $16.8m.

South Texas Electric Cooperative, Inc., (STEC) on July 25 filed with the commission an application to amend its certificate of convenience and necessity for the proposed Palmas to East Rio Hondo 138-kV Transmission Line in Cameron County, Texas.

STEC said that it is seeking approval to build the double-circuit, overhead line to connect the Palmas Wind Energy Project to the ERCOT grid. Palmas Wind, LLC requested that STEC interconnect its Palmas Wind Energy Project generating facilities at the Palmas station, which would be owned by STEC. The wind generation facility will be comprised of 46 wind turbine generators rated 3.15 MW each with a total nominal capacity of about 145 MW, STEC added.

The length of the line ranges between 6.2 miles and 6.6 miles in length, depending on which route is selected by the commission.

To install the initial 138-kV circuit along “Route H,” it would cost about $6.5m for the transmission facilities portion of the project; about $2.7m for the East Rio Hondo facilities; and about $1.9m for the Palmas facilities, STEC said.

According to a July 30 notice of approval signed by Montelongo, the commission approves Oncor’s application to amend its CCN for a 138-kV transmission line within Winkler County. Regulatory staff recommends approval of the application, the notice said.

According to the notice, Oncor proposes to build the new double-circuit transmission line on double-circuit-capable structures between the proposed Dune Switch station – located about three miles south of State Highway 302 and about nine miles west of Notrees – and Oncor’s existing Wink-Yukon 138-kV transmission line, located about two miles south of the proposed Dune Switch station.

The notice also said that the estimated cost of the project for transmission line facilities along the proposed route is about $2.9m. The Dune Switch station and tap point work is estimated to cost an additional approximate $4m.

In Wisconsin news, American Transmission Company (ATC), in a July 17 quarterly progress report for the period April 1 through June 30 regarding its Bunker Hill-Blackbrook (M13) Project, told Wisconsin regulators that expenditures as of June 30 were about $22.2m, or about 75% of the authorized total of about $29.7m.

As TransmissionHub reported, the Public Service Commission of Wisconsin in July 2016 granted, subject to conditions, ATC’s application to build and place in service facilities for the project, which includes building a new substation; rebuilding the 115-kV M13 transmission line from the Bunker Hill switching station in Lincoln County, Wis., to the Blackbrook switching station in Langlade County, Wis.; uprating the 115-kV M13 transmission line from the Kelly substation in Marathon County, Wis., to the Blackbrook switching station; as well as retiring and removing the Bunker Hill and Blackbrook substations.

In its July 17 filing, ATC discussed transmission line construction milestones, noting that construction in the rebuild section of the project is complete and that the demolition of the old Line M13 between the Bunker Hill and Blackbrook substation sites is also complete. Restoration work on the right of way (ROW) will continue through the summer, ATC said, noting that the final phase of T-line construction will start in late 2018, with all work scheduled to be complete by next spring.

Separately on July 17, ATC said that gross project expenditures for the Spring Valley-N. Lake Geneva Project as of June 30 were about $22.3m, or 31.5% of the authorized total of $70.6m.

As noted on the company’s website, the commission in March 2016 approved the project, which includes construction of a new, approximately 23-mile, 138-kV transmission line that stretches from the existing North Lake Geneva substation in southern Walworth County to the existing Spring Valley substation in western Kenosha County.

In its July 17 quarterly progress report for the period April 1 through June 30 filed with the commission, ATC said, among other things, that the project is currently in design for the transmission lines and two of the four substations.

In another report received on July 17 by the commission, ATC said that gross project expenditures on the Riverside Project as of June 30 were about $12.5m, or 29.7% of the authorized total of about $42.1m.

As TransmissionHub reported, the commission, in a Jan. 12 final decision, approved ATC’s June 2017 application for a certificate of public convenience and necessity (CPCN) regarding new 345-kV electric transmission facilities. As noted in that decision, the West Riverside interconnection project includes 345-kV electric transmission facilities required to connect the West Riverside Electric Generation facility (West Riverside) to ATC’s existing electric transmission system. The commission noted that it has previously approved the construction by Wisconsin Power and Light (WP&L) of West Riverside in a separate docket.

Describing the transmission project and its purpose, the commission noted that ATC proposes to build a new loop-in, loop-out 345-kV transmission line from its Line W10. The project includes construction of a new 345-kV substation to be named Kittyhawk.

In its July filing submitted to the commission, ATC said that construction at the Kittyhawk substation has begun; construction on the transmission line will begin this month, including matting installation and vegetation clearing; and remote end construction will begin in March 2019. The anticipated in-service date for the project is April 19, 2019.

In a July 24 quarterly progress report for the period April 1 through June 30 filed with the commission, ATC said that its Boscobel to Lone Rock (Line Y124) Rebuild Project is on schedule for substantial completion of the Y-124 rebuild in December 2019.

Detailed design activities for the transmission line portion of the project are nearly complete, ATC said, adding that the final construction drawings and specifications are under review. Concrete foundation work for that portion of the project is planned to begin in late August, and the remaining vegetation management activities will be completed in the fall. ATC also said that detailed design activities for the substation portion of the project are nearly complete.

Actual project costs as of June 30 were about $6m out of the approved $32.4m, the company said.

Separately on July 24, ATC told the commission that its St. Martins-Edgewood-Mukwonago Rebuild Project remains on schedule for completion in June 2019. ATC said that vegetation management activities continued on both transmission lines that are part of the project, and that final design was complete for all substations.

Actual project costs as of June 30 were about $4.8m of the “approved” approximately $24.7m, the company said.

At its July 26 open meeting, the commission determined that it was in the public interest to approve ATC’s application regarding the proposed Mount Pleasant Tech Interconnection Project.

As TransmissionHub reported, ATC in late January filed with the commission an application for a CPCN, seeking authority to build the new 345/138-kV Mount Pleasant substation in the village of Mount Pleasant in Racine County, and to build 345-kV transmission lines to interconnect with ATC’s existing 345-kV transmission network.

According to the minutes of the commission’s open meeting, the commission determined that ATC’s estimated costs of the project – from $117.2m to $120.3m – are appropriate.

Moving on to Arkansas, Carroll Electric Cooperative Corporation (CECC) on July 25 filed with the Arkansas Public Service Commission an application for a certificate of public convenience and necessity allowing it to build, operate, and maintain an estimated $3.2m high capacity electric transmission line in Benton County, Ark.

The new line would begin at a tap point on the Centerton-Highfill transmission line in Section 25, Township 19 North, Range 32 West, and end at the Simmons substation to be built in Section 30, Township 19 North, Range 32 West, all in Benton County. While the new line would initially be operated at 69 kV, it would be built for future operation at 161 kV, CECC added.

CECC noted that it has been requested by Simmons Foods to provide electric power to a new poultry facility being built northeast of Gentry, Ark. That facility is anticipated to utilize about 7 MW of electricity when it is initially operational in late 2019, and increase to 12 MW by 2022. CECC added that to provide for that service, it needs to build the new line and substation.

Cleco (NYSE:CNL) recently said that it began construction in July on a 12-mile, storm-hardened transmission line from Amelia, La., to its Bayou Vista substation that is designed to strengthen power service reliability for customers in southeast Louisiana.

A Cleco spokesperson on Aug. 3 told TransmissionHub that the name of the 230-kV line is the Bayou Vista to Terrebonne line, and that Cleco is building its portion of the line from its Bayou Vista substation near Patterson, La., to a point at Bayou Boeuf near Amelia, where it will interconnect with Entergy’s (NYSE:ETR) line. Construction is expected to end June 30, 2019, the spokesperson said.

The company said that the project will cost about $62m.

Following completion of construction and successful performance testing, the line and equipment are expected to be placed into service in mid-2019, Cleco said.

East

Eversource Energy (NYSE:ES) on July 2 said that a study comparing potential methods to cross Little Bay with a new power transmission line – the Seacoast Reliability Project – shows that the burial of the line in the bottom sediment of the bay would have minimal impact on the environment.

The study also showed that burying the proposed 115-kV line in the bottom sediment of the bay would have the least disruption on area residents and properties, the lowest cost, as well as the shortest schedule, and would be the most appropriate method.

The line would pass through Madbury, Durham, Newington, and Portsmouth along existing utility corridors, including the Little Bay crossing, Eversource said. The project includes proposed substation upgrades and the new line connecting two existing substations in Madbury and Portsmouth, the company said.

The company noted that the “jet plow” burial method would have a total project cost of $84m, and a construction period of three months; the land rights required are secured. The company also said that the full “Horizontal Directional Drilling,” or HDD, method would have a total project cost of $216m, and a construction period of 28 months; the land rights required involve more than 10 properties. In addition, the company said that the shore landing, or partial HDD, method would have a total project cost of $184m, and a construction period of 10 months; the land rights required involve more than 10 properties.

In Virginia news, AEP’s Appalachian Power on July 11 said that it would host an open house on Aug. 2 in Galax, Va., regarding its proposed estimated $40m Glendale Area Improvements Project, which is designed to strengthen the transmission system in Carroll and Wythe counties. The project would include construction of three miles of transmission line and a substation, as well as removal of other transmission lines and an existing substation, the company said.

The company said that it will file an application seeking approval for the project later this year with the Virginia State Corporation Commission. If the project is approved, construction is expected to begin in early 2020, and be complete by summer 2021.

A Virginia State Corporation Commission hearing examiner, in a July 12 report filed with the commission, concluded that Virginia Electric and Power’s (Dominion) 500-kV Dooms-Valley Line #549 rebuild project in Augusta County should be approved with the use of single-circuit, chemically dulled, galvanized steel lattice towers, and subject to the state Department of Environmental Quality’s (DEQ) unopposed recommendations.

As TransmissionHub reported, the company proposes to rebuild, entirely within existing right of way (ROW) that has been in use since about 1966, its 500-kV Line #549 from the existing Dooms substation to the existing Valley substation; and to use double-circuit structures providing capacity for the 500-kV line and an additional, underbuilt 230-kV line to be installed at a later date.

Regulatory staff, in a March report about the project, noted that according to the company, assuming that a CPCN is granted by September, the projected in-service date for the estimated $62m project is June 1, 2020.

The commission, in a July 26 order, approved a request by Dominion Energy Virginia to participate – via its proposed Haymarket transmission project – in a pilot program that involves underground electric transmission lines.

As noted in the order, Dominion in November 2015 filed with the commission an application for a CPCN for the proposed Haymarket 230-kV, double-circuit transmission line and 230-34.5-kV Haymarket substation.

As noted in Dominion’s July 2 written request to participate in the pilot program, Enactment Clause No. 2 of the Grid Transformation and Security Act of 2018 (GTSA) establishes a pilot program “to further the understanding of underground electric transmission lines in regard to electric reliability, construction methods and related cost and timeline estimating, and the probability of meeting such projections” (the pilot program).

Dominion added that that program consists of “a total of two qualifying electrical transmission line projects, constructed in whole or in part underground, as specified and set forth in this act.”

A proposed route for the Haymarket project qualifies under Section 2 of the pilot program, Dominion said.

The commission, in its July 26 order, said that the Carver Road Route, which the commission approved in its June 2017 final order, would have cost consumers about $62m. The order also noted that given the unavailability of that route, on remand, a hearing examiner received from commission staff updated estimated cost information on the remaining available routes as such: I-66 Hybrid Route – $171.9m; Madison Route – $67.8m; and I-66 Overhead Route – $51.2m.

Based on those updated cost estimates, the I-66 Hybrid Route, which is the route required under the provisions of SB 966 (GTSA), will cost ratepayers an additional $120.7m, the order said. The project must be built and in service by Dec. 31, 2021; however, the company is granted leave to apply for an extension for good cause shown, the order said.

The New York State Public Service Commission on July 31 said that it is seeking comment on a request by Central Hudson Gas and Electric to rebuild and upgrade about 23.6 miles of existing 69-kV transmission lines located in the City of Kingston and towns of Ulster and Saugerties in Ulster County, as well as the Town and Village of Catskill in Greene County.

A public statement hearing was to be held on Aug. 7 in Saugerties, N.Y.

Fortis’ (NYSE:FTS) Central Hudson requests commission authorization to rebuild the existing lines designated “H” and “SB,” the commission said, adding that according to the company, the rebuild would generally occur within an existing 23.6-mile right of way, with about 1.2 miles of the H line relocated to avoid the state-designated Great Vly Wildlife Management Area.

The total estimated cost of the proposed H & SB Electric Transmission Lines Rebuild is about $41m, according to the company.

West

The Colorado Public Utilities Commission, in a July 11 decision, granted Tri-State Generation and Transmission’s May application for a CPCN for the construction of the estimated $16.2m Gateway Transmission Project, which consists of a new 230/115/12.47-kV substation.

The commission noted that it “finds that the proposed project is needed to serve load growth and for reliability purposes.”

As noted in the decision, Tri-State had requested that the commission, among other things, grant the CPCN and find that the 115-kV transmission facilities to be built in conjunction with the project are in the ordinary course of business and do not require a CPCN or, in the alternative, grant a CPCN for such facilities.

The substation will be located adjacent to the existing Platte River Power Authority (PRPA) Boyd-Longs Peak 230-kV transmission line, which will run through the Gateway substation, the commission noted. PRPA will be responsible for sectionalizing its line to serve the Gateway substation and will also build the 230-kV transmission spans that are necessary to connect the substation to the line, the commission said.

As part of its project, Tri-State plans to build a short 115-kV transmission line to interconnect with Tri-State’s existing Boyd-Lone Tree 115-kV transmission line. The commission added that while Tri-State considers the 115-kV facilities to be in the ordinary course of business under commission rules, it requests an affirmative ordinary course of business determination by the commission for those facilities.

New Mexico Public Regulation Commission Hearing Examiner Ashley Schannauer, in a July 31 recommended decision, recommended that the commission order that SunZia Transmission, LLC’s request for location approval regarding its proposed SunZia Southwest Transmission Project is denied without prejudice.

Schannauer also recommended that the commission order that SunZia’s request for the determination of a 200-foot width of right of way (ROW) for each of the two proposed transmission lines that are part of the project is granted.

The SunZia project consists of two transmission lines about 520 miles long, Schannauer said, adding that the lines would start at the proposed SunZia East substation in Lincoln County near Corona, N.M., just east of highway US 54, and terminate at the existing Pinal Central substation in Pinal County, Ariz., near the Town of Coolidge. Schannauer also noted that the two separate 500-kV lines would operate in alternating current (AC) configuration with a total approximate length within New Mexico of 320 miles.

According to the filing, SunZia states that it has spent more than $70m to date for a project ultimately expected to cost $2bn.

About Corina Rivera-Linares 3058 Articles
Corina Rivera-Linares, chief editor for TransmissionHub, has covered the U.S. power industry for the past 15 years. Before joining TransmissionHub, Corina covered renewable energy and environmental issues, as well as transmission, generation, regulation, legislation and ISO/RTO matters at SNL Financial. She has also covered such topics as health, politics, and education for weekly newspapers and national magazines. She can be reached at clinares@endeavorb2b.com.