Xcel Energy 2006 Annual Report Download - page 109

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the inclusion of ineligible purchased power capacity and energy payments in the FPPCAC. The testimony also proposed limits on
SPS’ future use of the FPPCAC. Related to these issues some intervenors have requested disallowances for past periods, which in the
aggregate total approximately $45 million. Other issues in the case include the treatment of renewable energy certificates and sulfur
dioxide allowance credit proceeds in relation to SPS’ New Mexico retail fuel and purchased power recovery clause. The hearing was
held in April 2006, and the hearing examiner’s recommended decision and a NMPRC decision is expected in early 2007.
14. Commitments and Contingent Liabilities
Commitments
Capital Commitments — The estimated cost as of Dec. 31, 2006 of capital requirements of Xcel Energy and its subsidiaries and the
capital expenditure programs is approximately $1.9 billion in 2007, $1.9 billion in 2008 and $1.7 billion in 2009. Xcel Energy’s
capital forecast includes the following major projects:
CAPX 2020 — In June 2006, CapX 2020, an alliance of electric cooperatives, municipals and investor-owned utilities in the upper
Midwest, including Xcel Energy, announced that it had identified three groups of transmission projects that proposed to be complete
by 2020. Group 1 project investments are expected to total approximately $1.3 billion, with major construction targeted to begin in
2009 or 2010 and ending three or four years later. Xcel Energy’s investment is expected to be approximately $700 million.
Approximately 75 percent of the capital expenditures and return on investment for transmission projects are expected to be recovered
under an NSP-Minnesota transmission cost recovery tariff rider mechanism authorized by Minnesota legislation and pending MPUC
approval. Similar transmission cost recovery mechanisms have been proposed in North Dakota and South Dakota. Cost recovery by
NSP-Wisconsin is expected to occur through the biennial PSCW rate case process.
Nuclear Capacity Increases and Life Extension — In August 2004, NSP-Minnesota announced plans to pursue 20-year license
renewals for the Monticello and Prairie Island nuclear plants, whose licenses will expire between 2010 and 2014. License renewal
applications for Monticello were submitted to the NRC and the MPUC in early 2005. License renewal was approved by the NRC in
November 2006, and the MPUC issued its approval in October 2006 allowing additional spent fuel storage. The MPUC stayed the
order until June 2007, following the Minnesota legislative session. Similar applications will be submitted for Prairie Island in 2008,
with approval expected in 2010.
At the direction of the MPUC, NSP-Minnesota is pursuing capacity increases of all three units that will total approximately 250 MW,
to be implemented, if approved, between 2009 and 2015. The life extension and a capacity increase for Prairie Island Unit 2 is
contingent on replacement of Unit 2’s original steam generators, currently planned for replacement during the refueling outage in
2013. Total capital investment for these activities is estimated to be approximately $1 billion between 2006 and 2015. NSP-Minnesota
plans to seek approval for an alternative recovery mechanism from customers of its nuclear costs. It is NSP-Minnesota’s plan to
submit the certificate of need for Monticello in the second quarter of 2007 and the certificate of need for Prairie Island in the third
quarter of 2007.
MERP Project — In December 2003, the MPUC approved NSP-Minnesota’s MERP proposal to convert two coal-fueled electric
generating plants to natural gas, and to install advanced pollution control equipment at a third coal-fired plant. These improvements
are expected to significantly reduce air emissions from these facilities, while increasing the capacity at system peak by 300 MW.
Major construction for the MERP project began in 2005, and these projects are expected to come on line between 2007 and 2009. The
cumulative investment is approximately $1 billion. The MPUC has approved a more current recovery of the financing costs related to
the MERP. The in-service plant costs, including the financing costs during construction, are recovered from customers through a
MERP rider, which was effective Jan. 1, 2006.
Comanche 3 — Comanche 3, a 750 MW coal-fired plantbeing built in Colorado, is expected to cost approximately $1.35 billion, with
major construction initiated in 2006 and completed in the fall of 2009. The CPUC has approved sharing one-third ownership of this
plant with other parties. Consequently, PSCo’s investment in Comanche 3 will be approximately $1 billion.
Sherco Project — NSP-Minnesota has proposed a $905 million upgrade at the Sherburne County (Sherco) coal-fired power plant. The
project will increase capacity and reduce emissions. The MPUC is expected to rule on the project in 2008. If approved, construction
would start in late 2008 and be completed in 2012.
Wind Generation — NSP-Minnesota plans to invest $205 million to acquire 100-MW of wind generation. The project would be
eligible for rider recovery in Minnesota. The project requires approval by the MPUC.
The capital expenditure programs of Xcel Energy are subject to continuing review and modification. Actual utility construction
expenditures may vary from the estimates due to changes in electric and natural gas projected load growth regulatory decisions, the
desired reserve margin and the availability of purchased power, as well as alternative plans for meeting Xcel Energy’s long-term
energy needs. In addition, Xcel Energy’s ongoing evaluation of compliance with future requirements to install emission-control
equipment, and merger, acquisition and divestiture opportunities to support corporate strategies may impact actual capital
requirements.