WECC report: Building transmission in the West costs $1m to $3m/mile

A Western Electricity Coordinating Council (WECC) draft report says building new transmission projects in the West is estimated to cost between approximately $1m and $3m per mile, depending on the size and length of the line, terrain crossed, and multiple additional factors.

The report, “Capital Costs for Transmission and Substations” was prepared for WECC by the engineering firm Black & Veatch, for WECC’s transmission expansion planning policy committee (TEPPC). 

The firm studied transmission and substation facilities at 230-kV and higher, “as these were indicative of the majority of transmission infrastructure projects being proposed on the bulk electric transmission network in the WECC,” the company said in the report.

Projects studied for the report included PacifiCorp’s Gateway Central line, NV Energy’s (NYSE:NVE) One Nevada line (ON Line), Bonneville Power Administration’s (BPA) McNary – John Day line, and Xcel Energy’s (NYSE:XEL) Comanche – Daniels Park project.

The report provided estimated costs of building 230-kV, 345-kV, and 500-kV single- and double-circuit AC lines as well as 500-kV HVDC bi-pole lines. It also looked at 230-kV, 345-kV, and 500-kV AC substation costs as well as 500-kV DC substation facilities.

Other factors, including conductor type, pole structure, length of the line, terrain type, right-of-way (ROW) and whether a project involved new or existing construction were also considered.

The estimated baseline cost of new transmission in WECC ranged from a low of $927,000 per mile for new 230-kV single-circuit lines to a high of $2.9m per mile for a 500-kV double circuit line, according to the report.

Black & Veatch identified several additional factors that would increase project costs, and developed multipliers for each.

For example, the report identified aluminum conductor steel reinforced (ACSR) conductor as the type used in its baseline assumption. Multipliers were provided for aluminum conductor steel supported (ACSS) and high tensile low sag (HTLS) conductors, both of which increase the ampacity of the transmission line. While ACSS conductor increases the conductor cost by a factor of 1.08 (8%), HTLS conductor increases the cost by a factor of 3.6 (360%) across all voltage categories.

The type of support structure used also had an impact on cost. 

“While most 230-kV transmission lines are made of steel poles, 345-kV and above transmission lines use lattice steel structures; however, this is not always the case,” the report noted. “For instance, in urban areas, some 345-kV transmission lines may use steel poles, as they reduce the amount of land coverage.”

Accordingly, lattice structures provided the baseline cost for 345-kV and above. For 230-kV, lattice structures reduced the structure cost by a factor of 0.9 (10% reduction). Tubular steel poles were the baseline reference for 230-kV lines; use of such structures for higher voltages increased the cost from 30% to 50% (factors of 1.3 to 1.5), according to the report.

Project length was another consideration. For purposes of the study, Black & Veatch assumed project lengths longer than 10 miles. Shorter lines cost more per mile, primarily because “the construction, engineering, and equipment costs are compressed into a smaller distance for short transmission lines,” the report noted. 

Lines of three to 10 miles in length were estimated to cost 20% more (factor of 1.2), while lines of less than three miles were estimated to cost 50% more (factor of 1.5), according to the draft report.

In many cases, it may be more cost-effective to reconductor a transmission line to gain incremental current carrying capacity, the report noted. In this methodology, reconductoring was defined strictly as replacing the conductor only to increase ampacity, and it was assumed that the new conductor would be of similar size and weight so upgrading poles or insulators would not be required.

In such cases, reconductoring was estimated at 35% of the total capital cost for 230-kV projects, 45% for 345-kV lines, and 55% for 500-kV applications.

The report also included terrain multipliers. From a construction difficulty perspective, the easiest construction environment was scrub or flat terrain, and the most difficult was forested areas. Accordingly, scrub, desert, and farmland provided the baseline. Multipliers were provided for other types of terrain, including rolling hills, mountains, wetlands, and urban versus suburban terrain.

In addition, regional differences resulted in cost variances. According to the report, construction in terrains other than the baseline terrains was incrementally more expensive within the Southern California Edison (SCE) service area than in either the Pacific Gas & Electric (PG&E), San Diego Gas & Electric (SDG&E) or the Western Renewable Energy Zone (WREZ) areas. 

The cost of land rented or purchased for ROW also varied. Based on estimates provided by the Bureau of Land Management (BLM) for its 12 zones, rental costs ranged from $9 per acre per year to $3,449 per acre per year. Purchase cost ranged from $85 to $34,141 per acre. Notably, the BLM estimates include the ROW cost for all types of land within each zone, not just lands administered by BLM. 

Substation and other costs 

The draft report also included estimated base costs for new substations at $1.6m for a 230-kV substation, $2.1m for a 345-kV facility, and $2.5m for a 500-kV substation. Line/transformer position costs, transformer capital costs, and reactive components including shunt reactors, series capacitors, and static var compensators (SVC) all added to the base cost.

The cost of an HVDC 500-kV converter station was estimated at $445m.  

Because the transmission and substation costs described in the draft report were given as “overnight” costs —  i.e. the cost if the project could be engineered, procured and constructed overnight without any financing costs — the report also contained estimates for allowable funds used during construction (AFUDC) and overhead costs. 

Such costs varied widely between investor owned utilities (IOUs), public utilities, and independent project developers. 

While Black & Veatch estimated each category at 10% for independent developers, data obtained from NV Energy/PacifiCorp and BPA revealed that BPA’s AFUCD cost was 4.1%, while its overhead cost was 23%. By contrast, NV Energy/PacifiCorp reported 8.6% AFUDC and 6.2% overhead cost. As a result, the report recommended an average of 7.5% AFUDC and 10% overhead for planning purposes.

The firm said the costs included in its report are believed to “reasonably represent the cost to develop transmission and substation facilities in the WECC region.” However, the company added that it was imperative to note that transmission lines and substations are all unique, “and the cost of a specific line or substation may be vastly different than the costs provided here due to a variety of factors.”

The recommendations will be considered at WECC’s technical advisory subcommittee (TAS) meeting Oct. 29. Pending TAS’s recommendation for approval, the cost recommendations will be considered by TEPPC at its meeting Oct. 31.

SCE is a subsidiary of Edison International (NYSE:EIX).

SDG&E is a subsidiary of Sempra Energy (NYSE:SRE).

PG&E is a subsidiary of PG&E (NYSE:PCG).