Transmission expenses included in NSPC’s proposed rate increase

Northern States Power Company (NSPC), doing business as Xcel Energy (NYSE:XEL) has asked Minnesota state regulators for permission to increase electric rates as of Jan. 1, 2013 by $285.5m, or 10.7% (Docket No. E002/GR-12-961).

In its Nov. 2 application to the Minnesota Public Utilities Commission (PSC), the utility said it the increased rates “reflect the current cost of providing service to our customers, including an appropriate return on common equity.”

In testimony filed with the application, company officials provided details about the company’s transmission-related expenses and planned expansion projects.

“We expect to add $141.7m of new [transmission] plant in service in 2012 and $329.1m in new transmission plant in service in 2013,” Kent Larson, senior vice president of operations for Xcel Energy Services, said in testimony.

Larson noted that the investments are primarily focused on regional expansion, reliability requirements, and asset health.

Regional expansion

The company reported making “significant investments in regional expansion through the CapX2020 initiative,” he said.

The first portion of the Fargo CapX2020 345-kV project from Monticello, Minn., to St. Cloud, Minn., was placed in service in December 2011, while the entire Bemidji 230-kV project, from Bemidji to Grand Rapids, Mich., was placed in service in 2012, Larson said. Accordingly, the company’s share of the project costs, which are currently recovered through a transmission cost recovery (TCR) rider are proposed to be moved to base rates.

Other regional expansion projects have more than one benefit, the company said. “The Southwest Twin Cities project is also an example of where we are replacing existing line to increase capacity and address reliability issues, while also adding new line,” Larson said.

Additional capacity or growth-related projects include upgrades for generation interconnections required by the Midwest ISO (MISO) Tariff, transmission-to-transmission and load interconnections, and regional expansion projects, he said, citing the CapX2020 projects as an example.

While the company also makes interconnection investments, they are a relatively minor component of its overall investments for 2013, at $3.3m, Larson said. The reason is that the customer requesting interconnections at voltages lower than 345-kV pays the costs associated with that interconnection, either substantially or in their entirety.

Operating & Maintenance budget needed to maintain health of existing assets

Xcel Energy has budgeted $41.8m for transmission O&M in 2013, an increase of $4.8m or 13% over actual expenses for 2011. The main drivers of the increase are the costs associated with existing asset maintenance and capital support, according to Larson, who added that over 80% of the transmission O&M budget is related to employee and contract labor. The remainder is comprised primarily of regulatory fees, materials, and fleet costs, he said.

Specific “asset health” projects include the replacement of 19 structures, 51 cross arms, and two line switches over 45 miles of line running from Rapidan to Butterfield in southern Minnesota at a cost estimated at $1.1m. The line originally dates to 1931 and is being refurbished to address issues related to its age and condition.

Xcel is also rebuilding 9.5 miles of 69-kV line from Annandale to Kimball due to the age of the line, the presence of woodpecker damage to wood structures, and a failing conductor. The estimated cost of that project is $2.3m.

Beginning in 2013, the company has budgeted $1.2m per year for five years to address transmission pole corrosion, as well as vibration and “galloping conductor” issues.

“Many steel poles purchased in the 1960s, 1970s, and 1980s are corroding, which can undermine the structural integrity of the pole over time and has prompted complaints from local residents regarding their appearance,” Larson said. The company plans to paint the poles and remove corrosion where possible as a more cost-effective solution than pole replacement.

Galloping conductors, which are caused by wind blowing across iced overhead conductors causing them to oscillate, is beginning to cause failures of the dampers that are used to deaden the vibration, he said. That condition will also be addressed through the O&M budget.

The company also cited projects that were driven by mandatory reliability standards.

One example is the Southwest Twin Cities project, where the company is replacing the 69-kV line from the city of Glencoe substation to West Waconia with 115-kV line, rebuilding several miles of 69-kV line between Waconia and Aue Lake to higher capacity, and adding three miles of new 69-kV line.  The $15m project is needed to improve reliability of service to five parts of the company’s service territory because “the current facilities will soon not satisfy more stringent NERC standards for single contingency operation,” Larson said.

Compliance requirements were also cited as driving expenses in other areas. Specifically, Larson cited a data request from NERC related to FERC Order 754 that requires each transmission planner to conduct studies and submit data related to single points of failure on protection systems that may result in adverse reliability risks. That data request alone accounts for $240,000 in O&M funds to pay for consulting services.

Overall, $440,000 of the 2013 O&M budget is related to expansion of compliance requirements.

Because the NSPC system is operated as an integrated system, the company receives revenues and pays expenses for transmission services. In 2011, the net transmission cost was an expense of $8.5m; in 2013, it is forecast to be net revenue of $6.1m.

To address the variability in revenues and expenses, the company has proposed an expense and revenue tracking mechanism for certain third party costs and revenues and MISO administrative charges, which are outside of the company’s control, according to Larson.

The company is also taking actions to increase third-party transmission revenue while also controlling its transmission expenses.

The company noted that approximately $11m of the requested rate increase is associated with transmission projects including the Buffalo Ridge Restoration, Chisago – Apple River, Pleasant Valley – Byron, and CapX2020 Bemidji transmission projects. Costs for those projects are currently recovered or proposed to be recovered through a TCR rider but need to be moved into base rates now that the lines are in service.

The utility will apply its increased rate to customer bills on an interim basis starting in January, an NSPC spokesperson told TransmissionHub Nov. 6. If the PSC approves a smaller increase than requested, the company will then refund the difference. The utility expects a decision later in 2013, the company spokesperson said.