Xcel Energy 2008 Annual Report Download - page 141

NSP-Minnesota is pursuing capacity increases of Monticello and Prairie Island that will total approximately 230 MW,
to be implemented, if approved, between 2009 and 2015. The life extension and capacity increase for Prairie Island
Unit 2 is contingent on replacement of Unit 2’s original steam generators, currently planned during the refueling outage
in 2013. Total capital investment for these activities is estimated to be over $1 billion between 2006 and 2015.
NSP-Minnesota submitted the certificate of need and site permit applications for Monticello’s power uprate in the first
quarter of 2008 and the certificate of need and site permit applications for Prairie Island’s power uprate in the second
quarter of 2008. The MPUC approved the Monticello power uprate certificate of need and site permit in December
2008. Action by the MPUC on the Prairie Island power uprate certificate of need and site permit is expected in fourth
quarter of 2009.
Wind Generation — NSP-Minnesota plans to invest approximately $900 million over three years for a 201 MW project
in southwestern Minnesota’s Nobles County, called the Nobles Wind Project, and a 150 MW project in southeastern
North Dakota, called the Merricourt Wind Project, expected to be operational by the end of 2010 and 2011,
respectively. NSP-Minnesota is in the process of seeking regulatory approval for the projects, which would be eligible for
rider recovery in Minnesota.
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 several groups of transmission projects
that proposed to be complete by 2020. Group 1 project investments are expected to total approximately $1.7 billion,
with major construction targeted to begin in 2010 and ending three to five years later. Xcel Energy’s investment is
expected to be approximately $900 million depending on the route and configuration approved by the MPUC.
Approximately 75 percent of the capital expenditures and return on investment for transmission projects are expected to
be recovered under an NSP-Minnesota TCR tariff rider mechanism authorized by Minnesota legislation, as well as a
similar TCR mechanism passed in South Dakota. Cost recovery by NSP-Wisconsin is expected to occur through the
biennial PSCW rate case process.
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. New state-of-the-art emission control equipment was placed
in-service for the Allen S. King plant in 2007, and the existing High Bridge facility was replaced with a 575 MW
natural gas combined cycle unit, which went into service in May 2008. The final phase of the MERP program, the
new Riverside combined cycle plant, is currently in start-up and scheduled to be in-service by May 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 plant being built in Colorado, is expected to cost approximately
$1.3 billion, with major construction initiated in 2006 and is expected to be completed in the fall of 2009. The CPUC
has approved sharing one-third ownership of this plant.
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.
Fuel Contracts — Xcel Energy and its subsidiaries have contracts providing for the purchase and delivery of a
significant portion of its current coal, nuclear fuel and natural gas requirements. These contracts expire in various years
between 2009 and 2040. In total, Xcel Energy is committed to the minimum purchase of approximately $2.7 billion of
coal, $345.3 million of nuclear fuel and $4.4 billion of natural gas, including $3.5 billion of natural gas storage and
transportation, or to make payments in lieu thereof, under these contracts. In addition, Xcel Energy is required to pay
additional amounts depending on actual quantities shipped under these agreements. Xcel Energy’s risk of loss, in the
form of increased costs from market price changes in fuel, is mitigated through the use of natural gas and energy cost
rate adjustment mechanisms, which provide for pass-through of most fuel, storage and transportation costs to
customers.
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