Xcel Energy (NYSE:XEL) said that its capital expenditures are projected to be about $18.4bn from 2017 through 2021, and that its capital plan includes investments in renewables, transmission, distribution, electric generation, and natural gas.
In its Form 10-K filed with the U.S. Securities and Exchange Commission for the fiscal year ended Dec. 31, 2016 – which was filed on March 2 with the Public Utility Commission of Texas – Xcel also said that its plan includes about $1.3bn of investment for grid modernization to improve the customer experience, enhance grid reliability, and enable new and innovative programs and rate structures.
As TransmissionHub reported, Xcel Chairman, President and CEO Ben Fowke said on Feb. 2 during the company’s 4Q16 earnings call that the company is planning to invest about $3.5bn in renewables over the next five years.
In its Form 10-K, Xcel discussed several transmission projects. For instance, the company said that the estimated cost of the five major CapX2020 transmission projects is $2bn, with NSP-Minnesota and NSP-Wisconsin responsible for about $1.06bn of the total investment, and that most of this investment has occurred.
Construction of the Big Stone South to Brookings County, S.D., 345-kV transmission line began in September 2015, and completion is anticipated in September, the company said.
Another CapX2020 project, the Bemidji, Minn., to Grand Rapids, Minn., 230-kV transmission line, was placed in service in September 2012, while the Brookings County, S.D., to Hampton, Minn., 345-kV transmission line was placed in service in March 2015.
Xcel also said that the final portion of the Monticello, Minn., to Fargo, N.D., 345-kV transmission line was placed in service in April 2015, while the final 161-kV and 345-kV segments of the Hampton, Minn., to Rochester, Minn., to La Crosse, Wis., 161/345-kV transmission lines went into service in January 2016, and September 2016, respectively.
Xcel further noted that NSP-Wisconsin and American Transmission Company (ATC) in 2013 jointly filed with the Public Service Commission of Wisconsin an application for a certificate of public convenience and necessity (CPCN) for a new 180-mile, 345-kV transmission line that would extend from La Crosse to Madison, Wis.
NSP-Wisconsin’s half of the line – which, as noted on the company’s website, is also known as the Badger-Coulee Project – will be shared with three co-owners, Dairyland Power Cooperative, WPPI Energy, and Southern Minnesota Municipal Power Agency-Wisconsin.
NSP-Wisconsin’s portion of the approximately $541 project investment – which includes allowance for funds used during construction (AFUDC) – is estimated to be about $200m, the company added, noting that updated forecast costs are primarily due to better material pricing than originally anticipated.
Xcel said that the Wisconsin regulators in 2015 issued an order approving a CPCN and route for the project, and subsequently, denied two requests for rehearing. Two groups have appealed the CPCN order to county circuit court, the company said, adding that court action is pending in one remaining appeal. The CPCN, Xcel said, remains in full effect unless one of the parties seeks and receives a stay from the court, as well as posts a bond to cover damages that the utilities may incur due to the delay.
Construction on the line began in January 2016, and completion is anticipated by late 2018, the company said.
Xcel also noted that Public Service Company of Colorado (PSCo) in 2016 filed an application for a CPCN to build, own, and operate the 600-MW Rush Creek Wind facility for a cost of about $1bn, including transmission investment. The Colorado Public Utilities Commission in 2016 approved a settlement between PSCo and various parties, and granted the CPCN, the company said.
Key terms of the settlement include that the estimated $178m Pawnee-Daniels Park transmission line should be accelerated and operations are expected to begin by October 2019, as well as that PSCo committed to develop a rate for third-party access to available capacity in the Rush Creek transmission line to be filed at FERC, Xcel added.
The company also noted that Texas regulators in March 2016 approved Southwestern Public Service’s (SPS) certificate of convenience and necessity (CCN) for the 33-mile Yoakum County to Texas/New Mexico state line portion of the TUCO Substation to Yoakum County Substation to Hobbs Plant Substation 345-kV Transmission Line project. A request for a CCN for the 111-mile TUCO to Yoakum County substation segment was filed in June 2016, and assuming approval of that CCN, that segment is scheduled to be in service in 2019.
Xcel also said that a request for a CCN for the 36-mile Texas/New Mexico state line to Hobbs Plant segment is planned to be filed in 1Q17. The estimated project cost for all three segments is about $242m, the company said.
Xcel further noted that the New Mexico Public Regulation Commission in November 2016 approved SPS’ CCN for the approximately $163m Hobbs Plant to China Draw transmission line, which is anticipated to be in service in 2018.
Among other things, Xcel discussed pending regulatory proceedings, noting that in November 2013, a group of customers filed a complaint at FERC against Midcontinent ISO (MISO) transmission owners (TOs), including NSP-Minnesota and NSP-Wisconsin. The complaint argued for a reduction in the return on equity (ROE) in transmission formula rates in the MISO region from 12.38% to 9.15%, a prohibition on capital structures in excess of 50% equity, and the removal of ROE adders, effective Nov. 12, 2013.
In December 2015, Xcel added, an administrative law judge (ALJ) initial decision recommended that FERC approve an ROE of 10.32%, which FERC upheld in an order issued in September 2016. The total prospective ROE is 10.82%, which includes a previously approved 50 basis point adder for RTO membership, Xcel said, noting that that ROE is applicable for the 15-month refund period from Nov. 12, 2013, to Feb. 11, 2015, and prospectively from the date of FERC’s order.
In February 2015, a second complaint seeking to reduce the MISO region ROE from 12.38% to 8.67% prior to any adder was filed, which FERC set for hearings, resulting in a second period of potential refund from Feb. 12, 2015, to May 11, 2016, the company said.
The Minnesota Public Utilities Commission, North Dakota Public Service Commission, South Dakota Public Utilities Commission, and the Minnesota Department of Commerce joined a joint complainant/intervenor initial brief recommending an ROE of about 8.81%, Xcel said, adding that FERC staff recommended an ROE of 8.78%, while the MISO TOs recommended an ROE of 10.92%.
On June 30, 2016, the ALJ recommended an ROE of 9.7%, the midpoint of the upper half of the discounted cash flow range, Xcel said, adding that a FERC decision is expected later this year.