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Xcel Energy

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FY2005 Annual Report · Xcel Energy
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(cid:34) (cid:53) (cid:41) (cid:44) (cid:36) (cid:41) (cid:46) (cid:39) (cid:0) (cid:54) (cid:33) (cid:44) (cid:53) (cid:37) (cid:0)

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(cid:37) (cid:56) (cid:35) (cid:37) (cid:44) (cid:44) (cid:37) (cid:46) (cid:52) (cid:0) (cid:47) (cid:48) (cid:37) (cid:50) (cid:33) (cid:52) (cid:41) (cid:47) (cid:46) (cid:51)

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(cid:55) (cid:47) (cid:50) (cid:43) (cid:41) (cid:46) (cid:39) (cid:0) (cid:38) (cid:47) (cid:50) (cid:0) (cid:35) (cid:53) (cid:51) (cid:52) (cid:47) (cid:45) (cid:37) (cid:50) (cid:51)

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(cid:69)(cid:78)(cid:69)(cid:82)(cid:71)(cid:89)(cid:0)(cid:65)(cid:78)(cid:68)(cid:0)(cid:69)(cid:78)(cid:84)(cid:72)(cid:85)(cid:83)(cid:73)(cid:65)(cid:83)(cid:77)(cid:0)(cid:65)(cid:82)(cid:69)(cid:0)(cid:73)(cid:78)(cid:83)(cid:84)(cid:82)(cid:85)(cid:77)(cid:69)(cid:78)(cid:84)(cid:65)(cid:76)(cid:0)(cid:73)(cid:78)(cid:0)(cid:65)(cid:67)(cid:67)(cid:79)(cid:77)(cid:80)(cid:76)(cid:73)(cid:83)(cid:72)(cid:73)(cid:78)(cid:71)(cid:0)

(cid:79)(cid:85)(cid:82)(cid:0)(cid:67)(cid:79)(cid:82)(cid:80)(cid:79)(cid:82)(cid:65)(cid:84)(cid:69)(cid:0)(cid:83)(cid:84)(cid:82)(cid:65)(cid:84)(cid:69)(cid:71)(cid:89)(cid:0)(cid:65)(cid:78)(cid:68)(cid:0)(cid:66)(cid:85)(cid:73)(cid:76)(cid:68)(cid:73)(cid:78)(cid:71)(cid:0)(cid:86)(cid:65)(cid:76)(cid:85)(cid:69)(cid:0)(cid:70)(cid:79)(cid:82)(cid:0)(cid:89)(cid:79)(cid:85)(cid:14)(cid:0)

(cid:17)(cid:20)(cid:0)(cid:0)(cid:56)(cid:35)(cid:37)(cid:44)(cid:0)(cid:37)(cid:46)(cid:37)(cid:50)(cid:39)(cid:57)(cid:0)(cid:18)(cid:16)(cid:16)(cid:21)(cid:0)(cid:33)(cid:46)(cid:46)(cid:53)(cid:33)(cid:44)(cid:0)(cid:50)(cid:37)(cid:48)(cid:47)(cid:50)(cid:52)

(cid:35) (cid:47) (cid:45) (cid:45) (cid:41) (cid:52) (cid:52) (cid:37) (cid:36) (cid:0) (cid:52) (cid:47) (cid:0) (cid:35) (cid:47) (cid:45) (cid:45) (cid:53) (cid:46) (cid:41) (cid:52) (cid:41) (cid:37) (cid:51)

(cid:48)(cid:65)(cid:77)(cid:0)(cid:47)(cid:83)(cid:84)(cid:72)(cid:85)(cid:83)(cid:12)(cid:0)(cid:68)(cid:69)(cid:83)(cid:73)(cid:71)(cid:78)(cid:69)(cid:82)(cid:12)(cid:0)(cid:65)(cid:78)(cid:68)(cid:0)(cid:42)(cid:69)(cid:70)(cid:70)(cid:0)(cid:48)(cid:69)(cid:76)(cid:84)(cid:73)(cid:69)(cid:82)(cid:12)(cid:0)

(cid:69)(cid:76)(cid:69)(cid:67)(cid:84)(cid:82)(cid:73)(cid:67)(cid:0)(cid:77)(cid:69)(cid:84)(cid:69)(cid:82)(cid:0)(cid:84)(cid:69)(cid:67)(cid:72)(cid:78)(cid:73)(cid:67)(cid:73)(cid:65)(cid:78)(cid:12)(cid:0)(cid:65)(cid:82)(cid:69)(cid:0)(cid:56)(cid:67)(cid:69)(cid:76)(cid:0)(cid:37)(cid:78)(cid:69)(cid:82)(cid:71)(cid:89)(cid:0)

(cid:69)(cid:77)(cid:80)(cid:76)(cid:79)(cid:89)(cid:69)(cid:69)(cid:83)(cid:0)(cid:73)(cid:78)(cid:0)(cid:51)(cid:79)(cid:85)(cid:84)(cid:72)(cid:0)(cid:36)(cid:65)(cid:75)(cid:79)(cid:84)(cid:65)(cid:0)(cid:87)(cid:72)(cid:79)(cid:0)(cid:83)(cid:72)(cid:65)(cid:82)(cid:69)(cid:0)

(cid:84)(cid:72)(cid:69)(cid:0)(cid:67)(cid:79)(cid:77)(cid:80)(cid:65)(cid:78)(cid:89)(cid:7)(cid:83)(cid:0)(cid:83)(cid:84)(cid:82)(cid:79)(cid:78)(cid:71)(cid:0)(cid:67)(cid:79)(cid:77)(cid:77)(cid:73)(cid:84)(cid:77)(cid:69)(cid:78)(cid:84)(cid:0)(cid:84)(cid:79)(cid:0)(cid:0)

(cid:84)(cid:72)(cid:69)(cid:0)(cid:67)(cid:79)(cid:77)(cid:77)(cid:85)(cid:78)(cid:73)(cid:84)(cid:73)(cid:69)(cid:83)(cid:0)(cid:73)(cid:78)(cid:0)(cid:73)(cid:84)(cid:83)(cid:0)(cid:83)(cid:69)(cid:82)(cid:86)(cid:73)(cid:67)(cid:69)(cid:0)(cid:84)(cid:69)(cid:82)(cid:82)(cid:73)(cid:84)(cid:79)(cid:82)(cid:89)(cid:14)

(cid:56)(cid:35)(cid:37)(cid:44)(cid:0)(cid:37)(cid:46)(cid:37)(cid:50)(cid:39)(cid:57)(cid:0)(cid:18)(cid:16)(cid:16)(cid:21)(cid:0)(cid:33)(cid:46)(cid:46)(cid:53)(cid:33)(cid:44)(cid:0)(cid:50)(cid:37)(cid:48)(cid:47)(cid:50)(cid:52)(cid:0)(cid:0)(cid:17)(cid:21)(cid:0)(cid:0)

M A N A G E M E N T ’ S D I S C U S S I O N A N D A N A LY S I S O F F I N A N C I A L C O N D I T I O N A N D R E S U L T S O F O P E R A T I O N S

BUSINESS  SEGMENTS AND  ORGANIZATIONAL  OVERVIEW

Xcel Energy Inc. (Xcel Energy), a Minnesota corporation, is a public utility holding company. In 2005, Xcel Energy continuing operations
included the activity of four utility subsidiaries that serve electric and natural gas customers in 10 states. These utility subsidiaries are
Northern States Power Co., a Minnesota corporation (NSP-Minnesota); Northern States Power Co., a Wisconsin corporation (NSP-Wisconsin);
Public Service Company of Colorado (PSCo); and Southwestern Public Service Co. (SPS). These utilities serve customers in portions of
Colorado, Kansas, Michigan, Minnesota, New Mexico, North Dakota, Oklahoma, South Dakota, Texas and Wisconsin. Along with WestGas
InterState Inc. (WGI), an interstate natural gas pipeline, these companies comprise our continuing regulated utility operations.

Xcel Energy’s nonregulated subsidiaries reported in continuing operations include Eloigne Co. (investments in rental housing projects
that qualify for low-income housing tax reported credits). 

Discontinued utility operations include Viking Gas Transmission Co. (Viking), an interstate natural gas pipeline company that was sold in
January 2003; Black Mountain Gas Co. (BMG), a regulated natural gas and propane distribution company that was sold in October 2003; and
Cheyenne Light, Fuel and Power Co. (Cheyenne), a regulated electric and natural gas utility that was sold in January 2005.

During 2003, Planergy International, Inc. (Planergy), (energy management solutions) closed, with final dissolution completed in 2004. Several
nonregulated subsidiaries are presented as a component of discontinued operations. They include Utility Engineering (UE), an engineering,
design and construction management firm; Quixx Corp., a former subsidiary of UE that partners in cogeneration projects; Seren Innovations,
Inc. (Seren), a broadband communications services company; NRG Energy, Inc. (NRG), an independent power producer; Xcel Energy
International, Inc., an international independent power producer; and e prime inc. (e prime), a natural gas marketing and trading company. 

Discontinued operations classifications are the result of sales or plans to sell by management. See Note 2 to the Consolidated Financial
Statements for further discussion of discontinued operations.

FORWARD-LOOKING  STATEMENTS

Except for the historical statements contained in this report, the matters discussed in the following discussion and analysis are forward-looking
statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements are intended to be identified in
this document by the words “anticipate,” “believe,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,”
“potential,” “should” and similar expressions. Actual results may vary materially. Factors that could cause actual results to differ materially
include, but are not limited to: general economic conditions, including the availability of credit and its impact on capital expenditures and the
ability of Xcel Energy and its subsidiaries to obtain financing on favorable terms; business conditions in the energy industry; actions of credit
rating agencies; competitive factors, including the extent and timing of the entry of additional competition in the markets served by Xcel Energy
and its subsidiaries; unusual weather; effects of geopolitical events, including war and acts of terrorism; state, federal and foreign legislative and
regulatory initiatives that affect cost and investment recovery, have an impact on rates or have an impact on asset operation or ownership;
structures that affect the speed and degree to which competition enters the electric and natural gas markets; the higher risk associated with
Xcel Energy’s nonregulated businesses compared with its regulated businesses; costs and other effects of legal and administrative proceedings,
settlements, investigations and claims; actions of accounting regulatory bodies; the items described under Factors Affecting Results of Continuing
Operations; and the other risk factors listed from time to time by Xcel Energy in reports filed with the Securities and Exchange Commission
(SEC), including “Risk Factors” in Item 1A of Xcel Energy’s Annual Report on Form 10-K for the year ended Dec. 31, 2005, and Exhibit 99.01
to Xcel Energy’s Annual Report on Form 10-K for the year ended Dec. 31, 2005.

MANAGEMENT’S  STRATEGIC  PLAN

Xcel Energy’s strategy, which we call Building the Core, is to invest in our core utility businesses and earn the return authorized by our
regulatory commissions. We plan to invest approximately $7 billion over the next five years in our core operations to grow our business in
response to an increase in customer demand. We anticipate a need for additional energy supply in both Colorado and Minnesota during
the next 15 years. Additionally, we continue to focus on enhancing the reliability of our electrical system, which includes making significant
investment in our transmission and distribution systems.

Over the past five years, we’ve divested 10 businesses or subsidiaries that were not closely linked to our core electric and natural gas
businesses, realizing cash proceeds of nearly $440 million. Today, we’re a vertically integrated utility and we intend to stay that way. 

Our strategy of Building the Core has three phases. The first phase is obtaining legislative and regulatory support for our large investment
initiatives prior to making the investment. To avoid excessive risk for the company, it is critical to reduce regulatory uncertainty before making
large capital investments. We accomplished this for both the Metro Emission Reduction Project (MERP) in Minnesota and the Comanche 3
coal plant in Colorado. Transmission legislation has been passed in Minnesota, allowing that state’s regulatory commission to approve
recovery for transmission investments without filing a general rate case. In Texas, the legislature authorized annual recovery for transmission
infrastructure improvements. Both pieces of legislation will support necessary new investment in our transmission system.

The second phase is making those investments. In a normal year, we spend approximately $1 billion on capital projects. In addition to our
base level of capital investment, we expect to spend approximately $1 billion on MERP and $1 billion on Comanche 3 through 2010. As a result
of these investments, as well as continued investments in our transmission and distribution system to ensure continued reliability and to meet
our customer growth requirements, we expect that our rate base, or the amount on which we earn a return, will grow annually by slightly
more than 4 percent on average. Finally, such investments will always be made with a clear focus on optimizing environmental protection,
a significant priority for Xcel Energy.

16 XCEL ENERGY 2005 ANNUAL REPORT

M A N A G E M E N T ’ S D I S C U S S I O N A N D A N A LY S I S O F F I N A N C I A L C O N D I T I O N A N D R E S U L T S O F O P E R A T I O N S

The third phase is earning a fair return on our investments. To ensure that we earn a fair return, our regulatory strategy is to receive regulatory
approval for rate riders as well as general rate cases. A rate rider is a mechanism that allows us to recover certain costs and returns on investments
without the costs and delays of filing a rate case. These riders allow for timely revenue recovery and are good mechanisms to recover the costs
of large projects or other costs that vary over time. As an example, a rider for MERP went into effect in January 2006, allowing us to earn a
return on the project while the facility is being constructed.

We also are filing general rate cases to increase revenue recovery in most of the states in which we operate. In 2005, we filed several rate
cases as part of our regulatory strategy. These rate cases, and others that we plan to file in 2006, are some of the building blocks of our
earnings growth plan. Following is the current status of these initiatives:
– We reached constructive decisions in the Colorado natural gas case and Wisconsin electric and natural gas cases, which will increase revenue

in 2006 (see Factors Affecting Results of Continuing Operations for further discussion).

– We are on track with the Minnesota electric case, where interim rates, subject to refund, went into effect in January 2006. We expect a

decision in the third quarter of this year.

– Later in the year we plan to file electric cases in Colorado, Texas, New Mexico, and possibly North Dakota and South Dakota. If we are

successful, these cases should increase revenue and earnings in 2007.

Our regulatory strategy is based on filing reasonable rate requests designed to provide recovery of legitimate expenses and a return on our
utility investments. We believe that our commissions will provide us with reasonable recovery, and it’s important to note that our financial
plans include this assumption. Recent constructive results, along with past rulings, are evidence of reasonable regulatory treatment and give
us confidence that we are pursuing the right strategy.

With any strategic plan, there are goals and objectives. We feel the following financial objectives are both realistic and achievable:
– Annual earnings-per-share growth rate target of 5 percent to 7 percent from 2005–2009;
– Annual dividend increases of 2 percent to 4 percent; and
– Senior unsecured debt credit ratings in the BBB+ to A range.

Successful execution of our Building the Core strategic plan should allow us to achieve our financial objectives, which in turn should provide
investors with an attractive total return on a low-risk investment.

FINANCIAL  REVIEW

The following discussion and analysis by management focuses on those factors that had a material effect on Xcel Energy’s financial condition,
results of operations and cash flows during the periods presented, or are expected to have a material impact in the future. It should be read
in conjunction with the accompanying Consolidated Financial Statements and Notes. All note references refer to the Notes to Consolidated
Financial Statements.

S U M M A RY O F F I N A N C I A L R E S U LT S

The following table summarizes the earnings contributions of Xcel Energy’s business segments on the basis of generally accepted accounting
principles (GAAP). Continuing operations consist of the following:
– Regulated utility subsidiaries, operating in the electric and natural gas segments; and
– Several nonregulated subsidiaries and the holding company, where corporate financing activity occurs.

Discontinued operations consist of the following:
– Quixx Corp., which was classified as held for sale in the third quarter of 2005 based on a decision to divest this investment;
– Utility Engineering Corp., which was sold in April 2005;
– Seren, a portion of which was sold in November 2005, with the remainder sold in January 2006;
– Viking and BMG, which were sold in 2003;
– Cheyenne, which was sold in January 2005;
– NRG, which emerged from bankruptcy and was divested in late 2003; and
– Xcel Energy International and e prime, which were classified as held for sale in late 2003 based on the decision to divest them.

Certain items in the statements of operations have been reclassified from prior-period presentation to conform to the 2005 presentation.
See Note 2 to the Consolidated Financial Statements for a further discussion of discontinued operations.

Contribution to earnings (Millions of dollars)

2005

2004

2003

GAAP income (loss) by segment
Regulated electric utility segment income – continuing operations
Regulated natural gas utility segment income – continuing operations
Other utility results (a)

Total utility segment income – continuing operations

Holding company costs and other results (a)
Total income – continuing operations

Regulated utility income (loss) – discontinued operations
NRG loss – discontinued operations
Other nonregulated income (loss) – discontinued operations (b)

Total income (loss) – discontinued operations

Total GAAP net income

$440.6
71.2
27.6
539.4
(40.3)
499.1
0.2
(1.1)
14.8
13.9
$513.0

$466.3
86.1
6.1
558.5
(36.2)
522.3
(9.0)
–
(157.3)
(166.3)
$356.0

$461.3
94.1
6.0
561.4
(38.6)
522.8
26.8
(251.4)
324.2
99.6
$622.4

XCEL ENERGY 2005 ANNUAL REPORT 17

M A N A G E M E N T ’ S D I S C U S S I O N A N D A N A LY S I S O F F I N A N C I A L C O N D I T I O N A N D R E S U L T S O F O P E R A T I O N S

Contribution to earnings per share

2005

2004

2003

GAAP earnings (loss) per share contribution by segment
Regulated electric utility segment – continuing operations
Regulated natural gas utility segment – continuing operations
Other utility results (a)

Total utility segment earnings per share – continuing operations

Holding company costs and other results (a)

Total earnings per share – continuing operations
Regulated utility earnings (loss) – discontinued operations
NRG loss – discontinued operations
Other nonregulated earnings (loss) – discontinued operations (b)
Total earnings (loss) per share – discontinued operations

Total GAAP earnings per share – diluted

$1.04
0.17
0.06
1.27
(0.07)
1.20
–
–
0.03
0.03
$1.23

$1.10
0.20
0.02
1.32
(0.06)
1.26
(0.02)
–
(0.37)
(0.39)
$0.87

$1.10
0.22
0.01
1.33
(0.07)
1.26
0.06
(0.60)
0.78
0.24
$1.50

(a) Not a reportable segment. Included in All Other segment results in Note 17 to the Consolidated Financial Statements.

(b) Includes tax benefit related to NRG. See Note 2 to the Consolidated Financial Statements.

Earnings from continuing operations for 2005 were lower than in 2004. The 2005 results had higher operating margins, which were offset by
higher operating and maintenance expenses, including scheduled nuclear plant outages in 2005, higher employee benefit costs, higher
uncollectible receivable expense and higher depreciation expense. In addition, tax expense recorded in 2005 was higher than 2004, primarily
attributable to tax benefits recorded in 2004 related to the successful resolution of various income tax audit issues.

While earnings from continuing operations for 2004 were flat compared with 2003, 2004 results were favorably impacted by electric sales
growth, short-term wholesale markets and lower depreciation, offset by the negative impact of unfavorable weather, legal settlement costs
and the impact of certain regulatory accruals, compared with the same period in 2003.

Income from discontinued operations in 2005 includes the positive impact of a $17 million tax benefit recorded to reflect the final resolution
of Xcel Energy’s divested interest in NRG. This was partially offset by Seren’s operating losses during 2005.

The loss from discontinued operations in 2004 is largely due to an after-tax impairment charge of $143 million, or 34 cents per share, related
to Seren. In addition, the loss from discontinued operations in 2004 is attributable in part to an after-tax loss of $13 million, or 3 cents per
share, associated with the disposition of Cheyenne. 

The earnings in 2003 from discontinued operations are primarily due to an adjustment to previously estimated tax benefits related to Xcel
Energy’s write-off of its investment in NRG. Results from discontinued operations are discussed in the Discontinued Operations section later.

Weather  Xcel Energy’s earnings can be significantly affected by weather. Unseasonably hot summers or cold winters increase electric and
natural gas sales, but also can increase expenses. Unseasonably mild weather reduces electric and natural gas sales, but may not reduce
expenses. The impact of weather on earnings is based on the number of customers, temperature variances and the amount of natural gas or
electricity the average customer historically has used per degree of temperature.

The following summarizes the estimated impact on the earnings of the utility subsidiaries of Xcel Energy due to temperature variations from
historical averages:
– Weather in 2005 increased earnings by an estimated 3 cents per share;
– Weather in 2004 decreased earnings by an estimated 8 cents per share; and
– Weather in 2003 was close to normal and had minimal impact on earnings per share.

STAT E M E N T O F O P E R AT I O N S A N A LYS I S – C O N T I N U I N G O P E R AT I O N S
The following discussion summarizes the items that affected the individual revenue and expense items reported in the Consolidated
Statements of Operations.

E L E C T R I C U T I L I T Y, S H O RT- T E R M W H O L E SA L E A N D C O M M O D I T Y T R A D I N G M A R G I N S
Electric fuel and purchased power expenses tend to vary with changing retail and wholesale sales requirements and unit cost changes in fuel
and purchased power. Due to fuel and purchased energy cost-recovery mechanisms for retail customers in several states, most fluctuations
in these costs do not materially affect electric utility margin.

Xcel Energy has two distinct forms of wholesale sales: short-term wholesale and commodity trading. Short-term wholesale refers to
energy-related purchase and sales activity, and the use of certain financial instruments associated with the fuel required for, and energy
produced from, Xcel Energy’s generation assets or the energy and capacity purchased to serve native load. Commodity trading is not
associated with Xcel Energy’s generation assets or the energy and capacity purchased to serve native load. Short-term wholesale and
commodity trading activities are considered part of the electric utility segment.

Short-term wholesale and commodity trading margins reflect the estimated impact of regulatory sharing, if applicable. Commodity trading
revenues are reported net of related costs (i.e., on a margin basis) in the Consolidated Statements of Operations. Commodity trading costs
include purchased power, transmission, broker fees and other related costs.

18 XCEL ENERGY 2005 ANNUAL REPORT

M A N A G E M E N T ’ S D I S C U S S I O N A N D A N A LY S I S O F F I N A N C I A L C O N D I T I O N A N D R E S U L T S O F O P E R A T I O N S

The following table details the revenue and margin for base electric utility, short-term wholesale and commodity trading activities:

(Millions of dollars)

2005
Electric utility revenue (excluding commodity trading)
Fuel and purchased power
Commodity trading revenue
Commodity trading costs
Gross margin before operating expenses
Margin as a percentage of revenue

2004
Electric utility revenue (excluding commodity trading)
Fuel and purchased power
Commodity trading revenue
Commodity trading costs
Gross margin before operating expenses
Margin as a percentage of revenue

2003
Electric utility revenue (excluding commodity trading)
Fuel and purchased power
Commodity trading revenue
Commodity trading costs
Gross margin before operating expenses
Margin as a percentage of revenue

Base Electric
Utility

Short-Term
Wholesale

Commodity
Trading

Consolidated
Totals

$ 7,038
(3,802)
–
–
$3,236

46.0%

$5,989
(2,916)
–
–
$3,073

51.3%

$5,724
(2,588)
–
–
$3,136

54.8%

$196
(120)
–
–
$ 76
38.8%

$220
(125)
–
–
$ 95
43.2%

$179
(118)
–
–
$  61
34.1%

$

–
–
730
(720)
$ 10

1.4%

$    –
–
610
(594)
$  16

2.6%

$    –
–
333
(316)
$  17

5.1%

$ 7,234
(3,922)
730
(720)
$3,322

41.7%

$6,209
(3,041)
610
(594)
$3,184

46.7%

$5,903
(2,706)
333
(316)
$3,214

51.5%

The following summarizes the components of the changes in base electric utility revenue and base electric utility margin for the years
ended Dec. 31: 

Base Electric Utility Revenue

(Millions of dollars)

Sales growth (excluding weather impact)
Estimated impact of weather
Fuel and purchased power cost recovery
Firm wholesale
Capacity sales
Quality-of-service obligations
Conservation and non-fuel riders
Texas fuel reconciliation settlement
Other

Total base electric utility revenue increase

2005 vs. 2004 2004 vs. 2003

$

57
91
706
67
15
7
16
21
69
$1,049

$ 73
(74)
230
62
(2)
(12)
(5)
(25)
18
$265

2005 Comparison with 2004  Base electric revenues increased due to higher fuel and purchased power costs, which are largely recovered
from customers; weather-normalized retail sales growth of approximately 1.4 percent; higher sales attributable to warmer than normal
summer temperatures in 2005; higher revenues from firm wholesale customers; and lower regulatory accruals related to the Texas fuel
reconciliation settlement.

2004 Comparison with 2003 Base electric utility revenues increased due to higher fuel and purchased power costs, which are largely recovered
from customers; weather-normalized retail sales growth of approximately 1.8 percent; and higher revenues from firm wholesale customers.
Partially offsetting the higher revenues was the impact of significantly cooler summer temperatures in 2004, compared with the summer of 2003,
as well as estimated customer refunds related to quality-of-service obligations in Colorado and the estimated Texas fuel reconciliation settlement.

Base Electric Utility Margin

(Millions of dollars)

Estimated impact of weather on sales
Sales growth (excluding weather impact)
Conservation and non-fuel revenue
Texas fuel reconciliation settlement
Quality-of-service obligations
Under-recovery of fuel costs (NSP-Wisconsin)
Under-recovery and timing of recovery of fuel costs (other jurisdictions)
Firm wholesale
Pricing and other

Total base electric utility margin increase (decrease)

2005 vs. 2004 2004 vs. 2003

$ 75
42
16
21
7
(15)
(14)
23
8
$163

$(56)
55
(6)
(25)
(12)
(10)
(20)
27
(16)
$(63)

XCEL ENERGY 2005 ANNUAL REPORT 19

M A N A G E M E N T ’ S D I S C U S S I O N A N D A N A LY S I S O F F I N A N C I A L C O N D I T I O N A N D R E S U L T S O F O P E R A T I O N S

2005 Comparison to 2004  Base electric utility margin increased due to the impact of weather, weather-normalized sales growth, higher
firm wholesale margins, higher conservation and non-fuel rider revenues and lower accruals related to the fuel reconciliation proceedings in
Texas, partially offset by higher amortization expense and lower regulatory accruals associated with potential customer refunds related to
service-quality obligations in Colorado. These increases were partially offset by higher fuel and purchased energy costs not recovered through
direct pass-through recovery mechanisms.

2004 Comparison to 2003  Base electric utility margin decreased due to the impact of weather, higher fuel and purchased energy costs not
recovered through direct pass-through recovery mechanisms and regulatory accruals associated with potential customer refunds related to
service-quality obligations in Colorado and fuel-reconciliation proceedings in Texas. These decreases were partially offset by weather-normalized
sales growth.

Short-Term Wholesale and Commodity Trading Margin

2005 Comparison to 2004  Short-term wholesale and commodity trading margins decreased $25 million for 2005 compared with 2004. The
higher 2004 results reflect the impact of more favorable market conditions and higher levels of surplus generation available to sell. In addition,
a pre-existing contract contributed $17 million of margin in the first quarter of 2004 and expired at that time.

2004 Comparison to 2003  Short-term wholesale and commodity trading margins increased approximately $33 million in 2004 compared
with 2003. The increase reflects a number of market factors, including higher market prices and additional resources available for sale, and
the pre-existing contract described above.

N AT U R A L G AS U T I L I T Y M A R G I N S

The following table details the changes in natural gas utility revenue and margin. The cost of natural gas tends to vary with changing sales
requirements and the unit cost of wholesale natural gas purchases. However, due to purchased natural gas cost-recovery mechanisms for
sales to retail customers, fluctuations in the wholesale cost of natural gas have little effect on natural gas margin. See further discussion
under Factors Affecting Results of Continuing Operations.

(Millions of dollars)

Natural gas utility revenue
Cost of natural gas purchased and transported

Natural gas utility margin

2005

$2,307
(1,823)
$ 484

2004

$1,916
(1,446)
$ 470

2003

$1,678
(1,191)
$ 487

The following summarizes the components of the changes in natural gas revenue and margin for the years ended Dec. 31:

Natural Gas Revenue

(Millions of dollars)

Sales growth (excluding weather impact)
Purchased natural gas adjustment clause recovery
Rate changes – Colorado, Minnesota and North Dakota
Estimated impact of weather
Transportation and other

Total natural gas revenue increase

2005 vs. 2004 2004 vs. 2003

$

–
397
6
(5)
(7)
$391

$ (3)
257
(15)
(10)
9
$238

2005 Comparison to 2004  Natural gas revenue increased primarily due to higher natural gas costs in 2005, which are recovered from
customers. Retail natural gas weather-normalized sales were flat when compared to 2004, largely due to the rising cost of natural gas and its
impact on customer usage.

2004 Comparison to 2003  Natural gas revenue increased primarily due to higher natural gas costs in 2004, which are recovered from
customers. Retail natural gas weather-normalized sales declined in 2004, largely due to the rising cost of natural gas and its impact on
customer usage.

Natural Gas Margin

(Millions of dollars)

Sales growth (excluding weather impact)
Estimated impact of weather on firm sales 
Rate changes – Colorado, Minnesota and North Dakota
Transportation 
Other

Total natural gas margin increase (decrease)

2005 vs. 2004 2004 vs. 2003

$ 1
(2)
6
6
3
$14

$ –
(5)
(15)
1
2
$(17)

2005 Comparison to 2004  Natural gas margin increased due to rate changes in Minnesota and North Dakota, and higher transportation
margins, partially offset by the impact of warmer winter temperatures in 2005 compared with 2004.

2004 Comparison to 2003  Natural gas margin decreased due to a full year of a base rate decrease in Colorado, which was effective
July 1, 2003, and the impact of warmer winter temperatures in 2004 compared with 2003.

20 XCEL ENERGY 2005 ANNUAL REPORT

M A N A G E M E N T ’ S D I S C U S S I O N A N D A N A LY S I S O F F I N A N C I A L C O N D I T I O N A N D R E S U L T S O F O P E R A T I O N S

N O N R EG U L AT E D O P E R AT I N G M A R G I N S

The following table details the changes in nonregulated revenue and margin included in continuing operations:

(Millions of dollars)

Nonregulated and other revenue
Nonregulated cost of goods sold

Nonregulated margin

2005

2004

$74
(25)
$49

$75
(29)
$46

2003

$134
(81)
$ 53

2004 Comparison to 2003  Nonregulated revenue decreased in 2004, due primarily to the discontinued consolidation of an investment in
an independent power-producing entity that was no longer majority owned.

N O N- F U E L O P E R AT I N G E X P E N S E S A N D OT H E R I T E M S
Other Utility Operating and Maintenance Expenses Other operating and maintenance expenses for 2005 increased by approximately
$87 million, or 5.5 percent, compared with 2004. An outage at the Monticello nuclear plant and higher outage costs at Prairie Island in 2005
increased costs by approximately $26 million. Employee benefit costs were higher in 2005, primarily due to increased pension benefits and
long-term disability costs. Also contributing to the increase were higher uncollectible receivable costs, attributable in part to modifications
to the bankruptcy laws, higher fuel prices and certain changes in the credit and collections process.

Other operating and maintenance expenses for 2004 increased by approximately $21 million, or 1.4 percent, compared with 2003. Of the
increase, $12 million was incurred to assist with the storm damage repair in Florida and was offset by increased revenue. The remaining
increase of $9 million is primarily due to higher electric service reliability costs, higher information technology costs, higher plant-related costs,
higher costs related to a customer billing system conversion and increased costs primarily related to compliance with the Sarbanes-Oxley
Act of 2002. The higher costs were partially offset by lower employee benefit and compensation costs and lower nuclear plant outage costs.

(Millions of dollars)

2005 vs. 2004 2004 vs. 2003

Higher (lower) employee benefit costs
Higher (lower) nuclear plant outage costs
Higher uncollectible receivable costs
Higher donations to energy assistance programs
Higher mutual aid assistance costs
Higher electric service reliability costs
Higher (lower) information technology costs
Higher (lower) plant-related costs
Higher costs related to customer billing system conversion
Higher costs to comply with Sarbanes-Oxley Act of 2002
Other

Total operating and maintenance expense increase

$ 31
26
19
4
1
9
(6)
(7)
4
–
6
$ 87

$(12)
(13)
2
1
12
9
8
4
4
4
2
$ 21

Other Nonregulated Operating and Maintenance Expenses Other nonregulated operating and maintenance expenses decreased 
$16 million, or 35.4 percent, in 2005 compared with 2004, primarily due to the accrual of $18 million in 2004 for a settlement agreement
related to shareholder lawsuits.

Other nonregulated operating and maintenance expenses decreased $9 million, or 17.5 percent, in 2004 compared with 2003. This decrease
resulted from the dissolution of Planergy International and the discontinued consolidation of an investment in an independent power-
producing entity that was no longer majority owned after the divestiture of NRG.

Depreciation and Amortization  Depreciation and amortization expense for 2005 increased by approximately $61 million, or 8.7 percent,
compared with 2004. The changes were primarily due to the installation of new steam generators at Unit 1 of the Prairie Island nuclear plant
and software system additions, both of which have relatively short depreciable lives compared with other capital additions. The Prairie Island
steam generators are being depreciated over the remaining life of the plant operating license, which expires in 2013. In addition, the Minnesota
Renewable Development Fund and renewable cost-recovery amortization, which is recovered in revenue as a non-fuel rider and does not
have an impact on net income, increased over 2004. The increase was partially offset by the changes in useful lives and net salvage rates
approved by Minnesota regulators in August 2005.

Depreciation and amortization expense for 2004 decreased by $21 million, or 2.9 percent, compared with 2003. The reduction is largely due
to several regulatory decisions. In 2004, as a result of a Minnesota Public Utilities Commission (MPUC) order, NSP-Minnesota modified
its decommissioning expense recognition, which served to reduce decommissioning accruals by approximately $18 million in 2004 compared
with 2003.

In addition, effective July 1, 2003, the Colorado Public Utilities Commission (CPUC) lengthened the depreciable lives of certain electric utility
plant at PSCo as a part of the general Colorado rate case, reducing annual depreciation expense by $20 million. PSCo experienced the full
impact of the annual reduction in 2004, resulting in a decrease in depreciation expense of $10 million for 2004 compared with 2003. These
decreases were partially offset by plant additions.

XCEL ENERGY 2005 ANNUAL REPORT 21

M A N A G E M E N T ’ S D I S C U S S I O N A N D A N A LY S I S O F F I N A N C I A L C O N D I T I O N A N D R E S U L T S O F O P E R A T I O N S

Interest and Other Income (Expense), Net Interest and other income (expense), net decreased $8 million in 2005 compared with 2004.
The decrease is due to interest income related to the finalization of prior-period IRS audits of $10.5 million in 2004, partially offset by a
$2.2 million gain on the sale of water rights in 2005.

Interest and other income, net of nonoperating expenses increased $15 million in 2004 compared with 2003. The increase is due mostly to
interest income related to the finalization of prior-period IRS audits of $10.5 million.

Interest and Financing Costs The 2005 interest charges and financing costs increased approximately $8 million, or 1.9 percent when
compared with 2004, primarily due to increased short-term borrowing levels.

The 2004 interest charges and financing costs decreased approximately $17 million, or 3.7 percent when compared with 2003. The decrease
for the year reflects savings from refinancing higher coupon debt during 2003 and lower credit line fees, partially offset by interest expense
related to prior-period IRS audits.

Income Tax Expense  The effective income tax rate for continuing operations was 25.8 percent for 2005, compared with 23.7 percent in
2004. Income taxes recorded in 2005 reflect tax benefits of $10.0 million, primarily from increased research credits and a net operating loss
carry back. Excluding the tax benefits, the effective rate for 2005 would have been 27.3 percent.

In 2004, income tax benefits of $37.1 million were recorded, which included $22.3 million related to the successful resolution of various audit
issues and other adjustments to current and deferred taxes. The effective income tax rate for continuing operations was 23.7 percent for
2004, compared with 24.6 percent for the same period in 2003. Excluding the tax benefits, the effective rate for 2004 would have been
29.1 percent.

See Note 8 to the Consolidated Financial Statements.

H O L D I N G C O M PA N Y A N D OT H E R R E S U LT S

The following tables summarize the net income and earnings-per-share contributions of the continuing operations of Xcel Energy’s nonregulated
businesses and holding company results:

Contribution to Xcel Energy’s earnings (Millions of dollars)

Eloigne Company
Financing costs – holding company
Holding company and other results

Total nonregulated/holding company loss – continuing operations

Contribution to Xcel Energy’s earnings per share

Eloigne Company
Financing costs and preferred dividends – holding company
Holding company and other results

Total nonregulated/holding company loss per share – continuing operations

2005

$ 6.2
(52.7)
6.2
$(40.3)

2005

$ 0.01
(0.09)
0.01
$(0.07)

2004

$ 8.5
(44.7)
–
$(36.2)

2004

$ 0.02
(0.08)
–
$(0.06)

2003

$ 7.7
(44.1)
(2.2)
$(38.6)

2003

$ 0.02
(0.09)
–
$(0.07)

Financing Costs and Preferred Dividends  Nonregulated results include interest expense and the earnings-per-share impact of preferred
dividends, which are incurred at the Xcel Energy and intermediate holding company levels, and are not directly assigned to individual
subsidiaries.

The earnings-per-share impact of financing costs and preferred dividends for 2005, 2004 and 2003 included above reflects dilutive securities,
as discussed further in Note 9 to the Consolidated Financial Statements. The impact of the dilutive securities, if converted, is a reduction of
interest expense resulting in an increase in net income of approximately $14 million, or 3 cents per share, in 2005; $15 million, or 4 cents per
share, in 2004; and $11 million, or 3 cents per share, in 2003.

22 XCEL ENERGY 2005 ANNUAL REPORT

M A N A G E M E N T ’ S D I S C U S S I O N A N D A N A LY S I S O F F I N A N C I A L C O N D I T I O N A N D R E S U L T S O F O P E R A T I O N S

STAT E M E N T O F O P E R AT I O N S A N A LYS I S – D I S C O N T I N U E D O P E R AT I O N S ( N E T O F TA X)
A summary of the various components of discontinued operations is as follows for the years ended Dec. 31:

Income (loss) in millions
Viking Gas Transmission Co.
Black Mountain Gas
Cheyenne Light, Fuel and Power Co.

Regulated utility segments – income (loss)

NRG segment – loss

NRG-related tax benefits (expense)
Xcel Energy International
e prime
Seren 
Utility Engineering / Quixx Corp.
Other

Nonregulated/other – income (loss)

Total income (loss) from discontinued operations

Income (loss) per share
Viking Gas Transmission Co.
Black Mountain Gas
Cheyenne Light, Fuel and Power Co.

Regulated utility segments – income per share

NRG segment – loss per share

NRG-related tax benefits (expense)
Xcel Energy International
e prime
Seren 
Utility Engineering / Quixx Corp.
Other

Nonregulated/other – income (loss) per share

Total income (loss) per share from discontinued operations

2005

2004

2003

$

–
–
0.2
0.2

(1.1)

17.2
0.1
(0.1)
1.8
(4.4)
0.2
14.8
$13.9

$

–
–
–
–

–

0.04
–
–
–
(0.01)
–
0.03
$0.03

$

1.3
–
(10.3)
(9.0)

$ 21.9
2.4
2.5
26.8

–

(251.4)

(12.8)
7.3
(1.8)
(156.6)
4.7
1.9
(157.3)
$(166.3)

$

–
–
(0.02)
(0.02)

404.4
(45.5)
(17.8)
(18.3)
3.0
(1.6)
324.2
$ 99.6

$ 0.05
0.01
–
0.06

–

(0.60)

(0.03)
0.02
–
(0.37)
0.01
–
(0.37)
$ (0.39)

0.96
(0.11)
(0.04)
(0.04)
0.01
–
0.78
$ 0.24

R EG U L AT E D U T I L I T Y R E S U LT S – D I S C O NT I N U E D O P E R AT I O N S
In January 2004, Xcel Energy agreed to sell Cheyenne. Consequently, Xcel Energy reported Cheyenne results as a component of discontinued
operations for all periods presented. The sale was completed in January 2005 and resulted in an after-tax loss of approximately $13 million,
or 3 cents per share, which was accrued in December 2004.

During 2003, Xcel Energy sold Viking and BMG. After-tax disposal gains of $23.3 million, or 6 cents per share, were recorded primarily related
to the sale of Viking. Xcel Energy recorded minimal income related to Viking in 2003, due to its sale in January of that year.

N R G R E S U LT S – D I S C O NT I N U E D O P E R AT I O N S
Xcel Energy’s share of NRG results for 2003 is shown as a component of discontinued operations due to NRG’s emergence from bankruptcy
in December 2003 and Xcel Energy’s corresponding divestiture of its ownership interest in NRG. Xcel Energy financial statements do not
contain any results of NRG operations in 2005 and 2004.

NRG’s results included in Xcel Energy’s earnings for 2003 were as follows:

(Millions of dollars)

Six months ended June 30, 2003

Total NRG loss
Losses not recorded by Xcel Energy under the equity method*

Equity in losses of NRG included in Xcel Energy results for 2003

$(621)
370
$(251)

* These represent NRG losses incurred in the first and second quarters of 2003 that were in excess of the amounts recordable by Xcel Energy under

the equity method of accounting limitations.

As of the bankruptcy filing date (May 14, 2003), Xcel Energy had recognized $263 million of NRG’s impairments and related charges as these
charges were recorded by NRG prior to May 14, 2003. Consequently, Xcel Energy recorded its equity in NRG results in excess of its financial
commitment to NRG under the settlement agreement reached in March 2003 among Xcel Energy, NRG and NRG’s creditors. These excess
losses were reversed upon NRG’s emergence from bankruptcy in December 2003.

XCEL ENERGY 2005 ANNUAL REPORT 23

M A N A G E M E N T ’ S D I S C U S S I O N A N D A N A LY S I S O F F I N A N C I A L C O N D I T I O N A N D R E S U L T S O F O P E R A T I O N S

OT H E R N O N R EG U L AT E D R E S U LT S – D I S C O NT I N U E D O P E R AT I O N S
In April 2005, Zachry Group, Inc. acquired all of the outstanding shares of UE, a nonregulated subsidiary. In August 2005, Xcel Energy’s
board of directors approved management’s plan to pursue the sale of Quixx Corp., a former subsidiary of UE that partners in cogeneration
projects and was not included in the sale of UE to Zachry. As a result, Xcel Energy is reporting UE and Quixx as components of discontinued
operations for all periods presented.

In September 2004, Xcel Energy’s board of directors approved management’s plan to pursue the sale of Seren. As a result of the decision,
Seren is accounted for as discontinued operations. In November 2005, Xcel Energy sold Seren’s California assets to WaveDivision Holdings,
LLC. In January 2006, Xcel Energy sold Seren’s Minnesota assets to Charter Communications.

During 2003, Xcel Energy’s board of directors approved management’s plan to exit businesses conducted by e prime and Xcel Energy
International. e prime ceased conducting business in 2004. Also during 2004, Xcel Energy completed the sales of the Argentina subsidiaries
of Xcel Energy International.

2005 Nonregulated Results Compared with 2004  Results of discontinued nonregulated operations in 2005 include the impact of a 
$5 million reduction to the original asset impairment for Seren and the positive impact of a $17 million tax benefit recorded to reflect the
final resolution of Xcel Energy’s divested interest in NRG. In 2004, the NRG tax basis study was updated and previously recognized tax benefits
were reduced by $13 million.

2004 Nonregulated Results Compared with 2003  Results of discontinued nonregulated operations in 2004 include the impact of the
sales of the Argentina subsidiaries of Xcel Energy International. The sales were completed in three transactions, with a total sales price of
approximately $31 million. In addition to the sales price, Xcel Energy also received approximately $21 million at the closing of one transaction
as redemption of its capital investment. The sales resulted in a gain of approximately $8 million, including approximately $7 million of
income tax benefits realizable upon the sale of the Xcel Energy International assets.

In addition, 2004 results from discontinued operations include the impact of an after-tax impairment charge for Seren of $143 million, or
34 cents per share. The impairment charge was recorded based on operating results, market conditions and preliminary feedback from
prospective buyers.

Tax Benefits Related to Investment in NRG  Xcel Energy has recognized tax benefits related to the divestiture of NRG. Since these tax
benefits are related to Xcel Energy’s investment in discontinued NRG operations, they are reported as discontinued operations.

During 2002, Xcel Energy recognized an initial estimate of the expected tax benefits of $706 million. Based on the results of a 2003 preliminary
tax basis study of NRG, Xcel Energy recorded $404 million of additional tax benefits in 2003. In 2004, the NRG basis study was updated and
previously recognized tax benefits were reduced by $13 million. In 2005, a $17 million tax benefit was recorded to reflect the final federal
income tax resolution of Xcel Energy’s divested interest in NRG.

Based on current forecasts of taxable income and tax liabilities, Xcel Energy expects to realize approximately $1.1 billion of cash savings
from these tax benefits through a refund of taxes paid in prior years and reduced taxes payable in future years. In 2005, 2004 and 2003, Xcel
Energy used $24 million, $345 million and $116 million, respectively, of these tax benefits, and expects to use $180 million in 2006. The
remainder of the tax benefit carry forward is expected to be used over subsequent years.

FAC TO R S A F F E C T I N G R E S U LT S O F C O N T I N U I N G O P E R AT I O N S

Xcel Energy’s utility revenues depend on customer usage, which varies with weather conditions, general business conditions and the cost of
energy services. Various regulatory agencies approve the prices for electric and natural gas service within their respective jurisdictions and
affect Xcel Energy’s ability to recover its costs from customers. The historical and future trends of Xcel Energy’s operating results have been,
and are expected to be, affected by a number of factors, including the following:

General Economic Conditions

Economic conditions may have a material impact on Xcel Energy’s operating results. The United States economy continues to grow as
measured by projected growth in the gross domestic product. Management cannot predict the impact of a future economic slowdown,
fluctuating energy prices, terrorist activity, war or the threat of war. However, Xcel Energy could experience a material adverse impact to its
results of operations, future growth or ability to raise capital resulting from a general slowdown in future economic growth or a significant
increase in interest rates.

Sales Growth

In addition to the impact of weather, customer sales levels in Xcel Energy’s utility businesses can vary with economic conditions, energy
prices, customer usage patterns and other factors. Weather-normalized sales growth for retail electric utility customers was 1.4 percent in
2005 compared with 2004, and 1.8 percent in 2004 compared with 2003. Weather-normalized sales growth for firm natural gas utility customers
was approximately 0.2 percent in 2005 compared with 2004, and (1.9) percent in 2004 compared with 2003. Projections indicate that weather-
normalized sales growth in 2006 compared with 2005 will range between 1.3 percent and 1.7 percent for retail electric utility customers and
0.0 percent to 1.0 percent for firm natural gas utility customers.

24 XCEL ENERGY 2005 ANNUAL REPORT

M A N A G E M E N T ’ S D I S C U S S I O N A N D A N A LY S I S O F F I N A N C I A L C O N D I T I O N A N D R E S U L T S O F O P E R A T I O N S

Fuel Supply and Costs

Coal Deliverability   Xcel Energy’s operating utilities have varying dependence on coal-fired generation. At the utilities, coal-fired generation
comprises between 60 percent and 85 percent of the total annual generation. Approximately 70 percent of the annual coal requirements are
supplied from the Powder River Basin in Wyoming. Delivery of coal from the Powder River Basin has been disrupted by train derailments
and other operational problems purportedly caused by deteriorated rail track beds of approximately 140 miles in length in Wyoming. The
BNSF Railway Co. (BNSF) and the Union Pacific Railroad (UPRR) jointly own the rail line. The BNSF operates and maintains the rail line. 

The coal delivery issues began in the first half of 2005. Based on discussions with the railroads, Xcel Energy expects that disrupted coal
deliveries will continue at least through the first part of 2006. Xcel Energy has taken a number of steps to mitigate the impact of the reduced
coal deliveries. These steps include modifying the dispatch of certain generation facilities to conserve coal inventories. This modified dispatch
was in place during the second half of 2005 and has continued in 2006, to date. In response to this reduced coal dispatch, Xcel Energy
has increased purchases from third parties and has increased the use of natural gas for electric generation. In addition, Xcel Energy negotiated
for the acquisition of additional, higher capacity rail cars and is working to upgrade certain coal-handling facilities. Delivery of the new cars
began in January 2006 and will continue over the course of the year. The upgrades to the coal-handling facilities are expected to be completed
in the first half of 2006.

Despite these efforts, coal inventories have declined to below target levels. While Xcel Energy has secured, under contract, approximately
99 percent of anticipated 2006 coal requirements, it cannot predict the likelihood of receiving the required coal. While Xcel Energy is planning
to rebuild inventories during the year, there is no guarantee that it will be able to do so. The ultimate impact of coal availability cannot be fully
assessed at this time, but could impact future financial results. 

The cost of purchased power and natural gas for electric generation is higher than for coal-fired electric generation. The use of these sources
to replace coal-fired electric generation increased the price of electricity for retail and wholesale customers. Xcel Energy’s utility subsidiaries
have discussed this situation with their respective state regulatory commissions.

In Colorado, PSCo is subject to a retail electric adjustment clause that recovers fuel, purchased energy and resource costs. The Electric Commodity
Adjustment (ECA) is an incentive adjustment mechanism that compares actual fuel and purchased energy expenses in a calendar year to a
benchmark formula. The benchmark formula increases with natural gas prices, but not necessarily with increased volumes of natural gas
usage due to coal supply disruption. Therefore, any disruption in coal supply could adversely affect fuel cost recovery. For 2005, PSCo recorded
an incentive accrual of $8.5 million. The ECA provides for an $11.25 million cap on any cost sharing over or under the allowed ECA formula
rate. Any cost in excess of the $11.25 million cap is completely recovered from customers, while any savings in excess of the $11.25 million
cap is completely refunded to customers. Subject to the terms of the ECA, PSCo anticipates it would recover any increased fuel and purchased
energy costs greater than the cap from its customers.

Natural gas prices in 2005 were higher than projected when the ECA tariff rates were set in January 2005. On Oct. 5, 2005, PSCo filed an
application to adjust the ECA rate for November and December 2005 to reduce the ECA deferred balance and to update its projection of natural
gas prices. This application was granted, which resulted in an increase to 2005 electric revenue of approximately $70 million, including unbilled
revenues. As of Dec. 31, 2005, PSCo was carrying a deferred ECA balance, including unbilled revenue, of approximately $15 million.

In Texas, fuel and purchased energy costs are recovered through a fixed fuel and purchased energy recovery factor, which is part of SPS’ retail
electric rates. If SPS will materially over-recover or under-recover these costs, the factor may be revised upon application by SPS or action
by the Public Utility Commission of Texas (PUCT). The regulations require surcharging of under-recovered amounts, including interest, when
they exceed 4 percent of SPS’ annual fuel and purchased energy costs, as allowed by the PUCT, if the condition is expected to continue. On
Dec. 21, 2005, SPS reached a settlement with various parties that set the fuel surcharge request at $76.9 million, to be recovered over a 15-
month period. The PUCT approved this settlement on Feb. 9, 2006, and the surcharge went into effect Feb. 13, 2006.

In New Mexico, increases and decreases in fuel and purchased energy costs, including deferred amounts, are recovered through a monthly
fuel and purchased power clause with a two-month lag. Wholesale customers, under the Federal Energy Regulatory Commission (FERC)
jurisdiction also pay a monthly fuel cost adjustment calculated on actual fuel and purchased power costs in accordance with the FERC’s
fuel clause regulations.

While SPS believes that it should be allowed to recover these higher costs, the ultimate success of recovery could significantly impact the
future of SPS and possibly Xcel Energy.

NSP-Minnesota’s retail electric rate schedules in the Minnesota, North Dakota and South Dakota jurisdictions include a fuel clause adjustment
(FCA) to billings and revenues for changes in prudently incurred cost of fuel, fuel-related items and purchased energy. NSP-Minnesota is
permitted to recover these costs through FCA mechanisms individually approved by the regulators in each jurisdiction. The FCA mechanisms
allow NSP-Minnesota to bill customers for the cost of fuel and fuel-related items used to generate electricity at its plants and energy purchased
from other suppliers. In general, capacity costs are not recovered through the FCA. NSP-Minnesota’s electric wholesale customers also
have an FCA provision in their contracts. NSP-Minnesota anticipates it will recover increased costs resulting from its mitigation plan through
the FCA.

In Wisconsin, NSP-Wisconsin does not have an automatic electric fuel clause adjustment for Wisconsin retail customers. NSP-Wisconsin may
seek deferred accounting treatment and future rate recovery of increased costs due to an “emergency” event, if that event causes fuel and
purchased power costs to exceed the amount included in rates on an annual basis by more than 2 percent. Coal deliverability has not resulted
in an emergency event to date.

XCEL ENERGY 2005 ANNUAL REPORT 25

M A N A G E M E N T ’ S D I S C U S S I O N A N D A N A LY S I S O F F I N A N C I A L C O N D I T I O N A N D R E S U L T S O F O P E R A T I O N S

Natural Gas Costs A variety of market factors have contributed to significantly higher natural gas prices.  The direct impact of these higher
costs is generally mitigated for Xcel Energy through recovery of such costs from customers through various fuel cost-recovery mechanisms.
However, higher fuel costs could significantly impact the results of operations, if requests for recovery are unsuccessful. In addition, the higher
fuel costs could reduce customer demand or increase bad debt expense, which could also have a material impact on Xcel Energy’s results
of operations. Delays in the timing of the collection of fuel cost recoveries as compared with expenditures for fuel purchases are expected
to have an impact on the cash flows of Xcel Energy. Xcel Energy is unable to predict the future natural gas prices or the ultimate impact of such
prices on its results of operations or cash flows.

Pension Plan Costs and Assumptions

Xcel Energy’s pension costs are based on an actuarial calculation that includes a number of key assumptions, most notably the annual return
level that pension investment assets will earn in the future and the interest rate used to discount future pension benefit payments to a present
value obligation for financial reporting. In addition, the actuarial calculation uses an asset-smoothing methodology to reduce the volatility of
varying investment performance over time. Note 10 to the Consolidated Financial Statements discusses the rate of return and discount rate
used in the calculation of pension costs and obligations in the accompanying financial statements.

Pension costs have been increasing in recent years, and are expected to increase further over the next several years, due to lower-than-expected
investment returns experienced in prior years and decreases in interest rates used to discount benefit obligations. While investment returns
exceeded the assumed level of 8.75 percent in 2005, 9.0 percent in 2004 and 9.25 percent in 2003, investment returns in 2002 and 2001 were
below the assumed level of 9.5 percent, and discount rates have declined from the 7.25-percent to 8-percent levels used in the 1999 through
2002 cost determinations, to 6.0 percent used in 2005. Xcel Energy continually reviews its pension assumptions and, in 2006, expects to
maintain the investment return assumption at 8.75 percent and to lower the discount rate assumption to 5.75 percent.

The investment gains or losses resulting from the difference between the expected pension returns assumed on asset levels and actual returns
earned are deferred in the year the difference arises and recognized over the subsequent five-year period. This gain or loss recognition occurs
by using a five-year, moving-average value of pension assets to measure expected asset returns in the cost-determination process, and by
amortizing deferred investment gains or losses over the subsequent five-year period. Based on current assumptions and the recognition of
past investment gains and losses over the next five years, Xcel Energy currently projects that the pension costs recognized for financial reporting
purposes in continuing operations will increase from a credit, or negative expense, of $2.4 million in 2005 to an expense of $15.3 million in 2006
and $18.7 million in 2007. Pension costs were a credit in 2005 due to the recognized investment asset returns exceeding the other pension cost
components, such as benefits earned for current service and interest costs for the effects of the passage of time on discounted obligations.

Xcel Energy bases its discount rate assumption on benchmark interest rates from Moody’s Investors Service (Moody’s), and has consistently
benchmarked the interest rate used to derive the discount rate to the movements in the long-term corporate bond indices for bonds rated
Aaa through Baa by Moody’s, which have a period to maturity comparable to our projected benefit obligations. At Dec. 31, 2005, the annualized
Moody’s Baa index rate was 6.21 percent, and the Aaa index rate was 5.26 percent. Accordingly, Xcel Energy lowered the discount rate to
5.75 percent as of Dec. 31, 2005. This rate was used to value the actuarial benefit obligations at that date, and will be used in 2006 pension
cost determinations. At Dec. 31, 2004, the annualized Moody’s Baa index rate was 6.10 percent and the Aaa index rate was 5.43 percent.
The corresponding pension discount rate was 6.00 percent.

If Xcel Energy were to use alternative assumptions for pension cost determinations, a 1-percent change would result in the following impact
on the estimated pension costs recognized by Xcel Energy:
– A 100 basis point higher rate of return, 9.75 percent, would decrease 2006 recognized pension costs by $17.0 million;
– A 100 basis point lower rate of return, 7.75 percent, would increase 2006 recognized pension costs by $17.0 million;
– A 100 basis point higher discount rate, 6.75 percent, would decrease 2006 recognized pension costs by $5.4 million; and
– A 100 basis point lower discount rate, 4.75 percent, would increase 2006 recognized pension costs by $7.1 million.

Alternative Employee Retirement Income Security Act of 1974 (ERISA) funding assumptions would also change the expected future cash
funding requirements for the pension plans. Cash funding requirements can be affected by changes to actuarial assumptions, actual asset
levels and other calculations prescribed by the funding requirements of income tax and other pension-related regulations. These regulations
did not require cash funding in recent years for Xcel Energy’s pension plans, and do not require funding in 2006. Assuming that future asset
return levels equal the actuarial assumption of 8.75 percent for the years 2006 and 2007, Xcel Energy projects, under current funding
regulations, that no cash funding would be required for 2006 or 2007. Actual performance can affect these funding requirements significantly.
Current funding regulations are under legislative review in 2006 and, if not retained in their current form, could change these funding
requirements materially.

Regulation

Public Utility Holding Company Act of 1935 (PUHCA) Historically, Xcel Energy has been a registered holding company under the PUHCA.
As a registered holding company, Xcel Energy, its utility subsidiaries and certain of its nonutility subsidiaries have been subject to extensive
regulation by the SEC under the PUHCA with respect to numerous matters, including issuances and sales of securities, acquisitions and
sales of certain utility properties, payments of dividends out of capital and surplus, and intra-system sales of certain nonpower goods
and services. In addition, the PUHCA generally limited the ability of registered holding companies to acquire additional public utility systems
and to acquire and retain businesses unrelated to the utility operations of the holding company.

On Aug. 8, 2005, President Bush signed into law the Energy Policy Act of 2005 (Energy Act), significantly changing many federal statutes and
repealing the PUHCA as of Feb. 8, 2006. However, as part of the repeal of the PUHCA, the FERC was given authority to review the books
and records of holding companies and their nonutility subsidiaries to the extent relevant to the charges of jurisdictional utilities, authority
to review service company cost allocations, and more authority over the merger and acquisition of public utilities. With the repeal of the PUHCA,

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state commissions were given similar authority to review the books and records of holding companies and their nonutility subsidiaries.
Despite these increases in the FERC’s authority, Xcel Energy believes that the repeal of the PUHCA will lessen its regulatory burdens and
give it more flexibility in the event it were to choose to expand its utility or nonutility businesses.

Besides repealing the PUHCA, the Energy Act is also expected to have substantial long-term effects on energy markets, energy investment
and regulation of public utilities and holding company systems by the FERC and the U.S. Department of Energy (DOE). The FERC and the DOE
are in various stages of rulemaking in implementing the Energy Policy Act. While the precise impact of these rulemakings cannot be determined
at this time, Xcel Energy generally views the Energy Act as legislation that will enhance the utility industry going forward.

Customer Rate Regulation  The FERC and various state regulatory commissions regulate Xcel Energy’s utility subsidiaries. Decisions by
these regulators can significantly impact Xcel Energy’s results of operations. Xcel Energy expects to periodically file for rate changes based
on changing energy market and general economic conditions.

The electric and natural gas rates charged to customers of Xcel Energy’s utility subsidiaries are approved by the FERC and the regulatory
commissions in the states in which they operate. The rates are generally designed to recover plant investment, operating costs and an
allowed return on investment. Xcel Energy requests changes in rates for utility services through filings with the governing commissions.
Because comprehensive general rate changes are requested infrequently in some states, changes in operating costs can affect Xcel Energy’s
financial results. In addition to changes in operating costs, other factors affecting rate filings are new investments, sales growth, conservation
and demand-side management efforts, and the cost of capital. In addition, the return on equity authorized is set by regulatory commissions in
rate proceedings. The most recently authorized electric utility returns are 11.47 percent for NSP-Minnesota; 11.0 percent for NSP-Wisconsin;
10.75 percent for PSCo; and 11.5 percent for SPS. The most recently authorized natural gas utility returns are 10.4 percent for NSP-Minnesota,
11.0 percent for NSP-Wisconsin and 10.5 percent for PSCo.

Wholesale Energy Market Regulation  In April 2005, a Day 2 wholesale energy market operated by the Midwest Independent Transmission
System Operator, Inc. (MISO) was implemented to centrally dispatch all regional electric generation and apply a regional transmission
congestion management system. MISO now centrally issues bills and payments for many costs formerly incurred directly by NSP-Minnesota
and NSP-Wisconsin. Both bills and payments from MISO for participation in this centrally dispatched market are received, resulting in a
net cost in serving Xcel Energy’s native load obligation. This net result is recorded as a component of operating and maintenance expenses.
The MPUC issued an interim order in April 2005 allowing MISO Day 2 charges to be recovered through the NSP-Minnesota Fuel Clause
Adjustment (FCA) mechanism. In December 2005, the MPUC issued a second interim order approving the recovery of certain MISO charges
through the FCA mechanism, but requiring that additional charges either be recovered as part of a general rate case or through an annual
review process outside the FCA mechanism, and requiring refunds of non-FCA costs. However, the December 2005 MPUC order also suspended
the refund obligation until such time as it could reconsider the matter. On Feb. 9, 2006, the MPUC voted to reconsider its December 2005 order.
The MPUC on reconsideration determined that parties be directed to determine which charges are appropriately in the FCA and which are
more appropriately established in base rates, and report back to the MPUC in 60 days; to grant deferred accounting treatment for costs ultimately
determined to be included in base rates for a period of 36 months, with recovery of deferred amounts to be reviewed in a general rate case;
and that amounts collected to date through the FCA under the April and December 2005 interim orders are not subject to refund. As a result,
NSP-Minnesota will be allowed to recover its prudently incurred MISO costs either through existing fuel clause mechanisms or in base rates.
In March 2005, the PSCW issued an interim order allowing NSP-Wisconsin deferred accounting treatment of MISO charges. However, the PSCW
staff issued an interpretive memorandum in October 2005 asserting that certain MISO costs may not be recovered through the interim fuel
cost mechanism and may not be deferrable. NSP-Wisconsin and the other Wisconsin utilities contested the PSCW’s interpretation in their
November comments to the PSCW. To date, NSP-Wisconsin has deferred approximately $5.7 million of MISO Day 2 costs as a regulatory asset. 

Xcel Energy has notified MISO that NSP-Minnesota and NSP-Wisconsin may seek to withdraw from MISO if rate recovery of Day 2 costs is not
allowed. Withdrawal would require the FERC’s approval and could require Xcel Energy to pay a withdrawal fee.

In addition, pursuant to the FERC’s orders, NSP-Minnesota and NSP-Wisconsin are billed for certain MISO charges associated with the loads
of certain wholesale transmission service customers taking service under pre-MISO grandfathered agreements (GFA). In March 2005, Xcel
Energy filed for the FERC’s approval to pass through these charges to GFA customers. The FERC accepted the filing subject to refund and
hearing procedures. In 2005, NSP-Minnesota and NSP-Wisconsin were billed for $1.1 million of MISO charges, which have not yet been
recovered from GFA customers. The likelihood of full rate recovery is uncertain at this time. In addition, Xcel Energy has filed an appeal of
the FERC orders.

Capital Expenditure Regulation  Xcel Energy’s utility subsidiaries make substantial investments in plant additions to build and upgrade
power plants, and expand and maintain the reliability of the energy distribution system. In addition to filing for increases in base rates charged
to customers to recover the costs associated with such investments, in 2003 the CPUC and MPUC approved proposals to recover, through a
rate surcharge, certain costs to upgrade generation plants and lower emissions in the Denver and Minneapolis-St. Paul metropolitan areas.
These rate-recovery mechanisms are expected to provide significant cash flows to enable recovery of costs incurred on a timely basis.

Future Cost Recovery  Regulated public utilities are allowed to record as regulatory assets certain costs that are expected to be recovered
from customers in future periods, and to record as regulatory liabilities certain income items that are expected to be refunded to customers in
future periods. In contrast, nonregulated enterprises would expense these costs and recognize the income in the current period. If restructuring
or other changes in the regulatory environment occur, Xcel Energy may no longer be eligible to apply this accounting treatment, and may
be required to eliminate such regulatory assets and liabilities from its balance sheet. Such changes could have a material effect on Xcel Energy’s
results of operations in the period the write-off is recorded.

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At Dec. 31, 2005, Xcel Energy reported on its balance sheet regulatory assets of approximately $963 million and regulatory liabilities of
approximately $1.7 billion that would be recognized in the statement of operations in the absence of regulation. In addition to a potential
write-off of regulatory assets and liabilities, restructuring and competition may require recognition of certain stranded costs not recoverable
under market pricing. See Notes 1 and 16 to the Consolidated Financial Statements for further discussion of regulatory deferrals.

Pending and Recently Concluded Regulatory Proceedings

NSP-Minnesota Electric Rate Case  In November 2005, NSP-Minnesota requested an electric rate increase of $168 million, or 8.05 percent.
This increase was based on a requested 11 percent return on common equity, a projected common equity ratio to total capitalization of
51.7 percent and a projected electric rate base of $3.2 billion. On Dec. 15, 2005, the MPUC authorized an interim rate increase of $147 million,
subject to refund, which became effective on Jan. 1, 2006. The anticipated procedural schedule is as follows:
– March 2nd – Intervenor Direct Testimony
– March 30th – Rebuttal Testimony
– April 13th – Surrebuttal Testimony
– April 20th – April 28th – Evidentiary Hearings
– May 24th – Initial Briefs
– June 6th – Reply Briefs
– July 6th – Administrative Law Judge Report
– September 5th – MPUC Order

NSP-Wisconsin 2006 General Rate Case  In 2005, NSP-Wisconsin requested an electric revenue increase of $58.3 million and a natural
gas revenue increase of $8.1 million, based on a 2006 test year, an 11.9 percent return on equity and a common equity ratio of 56.32 percent.
On Jan. 5, 2006, the PSCW approved an electric revenue increase of $43.4 million and a natural gas revenue increase of $3.9 million, based on
an 11.0 percent return on equity and a 54 percent common equity ratio target. The new rates were effective Jan. 9, 2006. The order authorized
the deferral of an additional $6.5 million in costs related to nuclear decommissioning and manufactured gas plant site clean up for recovery
in the next rate case. The order also prohibits NSP-Wisconsin from paying dividends above $42.7 million, if its actual calendar year average
common equity ratio is or will fall below 54.03 percent. It also imposes an asymmetrical electric fuel clause bandwidth of positive 2 percent
to negative 0.5 percent outside of which NSP-Wisconsin would be permitted to request or be required to change rates.

PSCo Natural Gas Rate Case  In 2005, PSCo filed for an increase of $34.5 million in natural gas base rates in Colorado, based on a return
on equity of 11.0 percent with a common equity ratio of 55.49 percent.

On Jan. 19, 2006, the CPUC approved a settlement agreement between PSCo and other parties to the case. Final rates became effective
Feb. 6, 2006. The terms of the settlement include:
– Natural gas revenue increase of $22 million;
– Return on common equity of 10.5 percent;
– Earnings over 10.5 percent return on common equity will be refunded back to customers;
– Common equity ratio of 55.49 percent; and
– Customer charges for the residential and commercial sales classes of $10 and $20 per month, respectively.

Tax Matters

Interest Expense Deductibility PSCo’s wholly owned subsidiary, PSR Investments, Inc. (PSRI), owns and manages permanent life insurance
policies, known as COLI policies, on some of PSCo’s employees. At various times, borrowings have been made against the cash values of
these COLI policies and deductions taken on the interest expense on these borrowings. The IRS has challenged the deductibility of such interest
expense deductions and has disallowed the deductions taken in tax years 1993 through 1999. Should the IRS ultimately prevail on this issue,
tax and interest payable through Dec. 31, 2005, would reduce earnings by an estimated $361 million. In 2004, Xcel Energy received formal
notification that the IRS will seek penalties. If penalties (plus associated interest) are also included, the total exposure through Dec. 31, 2005,
is approximately $428 million. Xcel Energy estimates its annual earnings for 2006 would be reduced by $44 million, after tax, which represents
10 cents per share, if COLI interest expense deductions were no longer available. See Note 14 to the Consolidated Financial Statements for
further discussion.

COLI Dow Chemical Court Decision  On Jan. 23, 2006, the 6th Circuit of the U.S. Court of Appeals issued an opinion in a federal income tax
case involving the interest deductions for a COLI program at Dow Chemical Company. The 6th Circuit denied the tax deductions and reversed
the decision of the trial court in the case.

Xcel Energy has analyzed the impact of the Dow decision on its pending COLI litigation and concluded there are significant factual differences
between its case and the Dow case. The court’s opinion in the Dow case outlined three indicators of potential economic benefits to be examined
in a COLI case and noted that the outcome of COLI cases is very fact determinative. These indicators are:
– Positive pre-deduction cash flows;
– Mortality gains; and
– The buildup of cash values.

In a split decision, the 6th Circuit found that the Dow COLI plans possessed none of these indicators of economic substance. However, in
Xcel Energy’s COLI case, the plans were projected to have sizeable pre-deduction cash flows, based upon the relevant assumptions when
purchased. Moreover, the plans presented the opportunity for mortality gains that were not eliminated either retroactively or prospectively.
Xcel Energy’s COLI plans had no provision for giving back any mortality gains that it might realize. In addition, Xcel Energy’s plans had large
cash value increases that were not encumbered by loans during the first seven years of the policies. Consequently, Xcel Energy believes that
the facts and circumstances of its case are stronger than Dow’s case and continues to believe its case has strong merit. 

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Environmental Matters

Environmental costs include payments for nuclear plant decommissioning, storage and ultimate disposal of spent nuclear fuel, disposal of
hazardous materials and waste, remediation of contaminated sites and monitoring of discharges to the environment. A trend of greater
environmental awareness and increasingly stringent regulation has caused, and may continue to cause, higher operating expenses and capital
expenditures for environmental compliance.

In addition to nuclear decommissioning and spent nuclear fuel disposal expenses, costs charged to operating expenses for environmental
monitoring and disposal of hazardous materials and waste were approximately:
– $147 million in 2005;
– $133 million in 2004; and
– $133 million in 2003.

Xcel Energy expects to expense an average of approximately $176 million per year from 2006 through 2010 for similar costs. However, the
precise timing and amount of environmental costs, including those for site remediation and disposal of hazardous materials, are currently
unknown. Additionally, the extent to which environmental costs will be included in and recovered through rates is not certain.

Capital expenditures placed in service on environmental improvements at regulated facilities were approximately:
– $37.1 million in 2005;
– $20.9 million in 2004; and
– $58.5 million in 2003.

The regulated utilities expect to incur approximately $438 million in capital expenditures for compliance with environmental regulations and
environmental improvements in 2006, and approximately $714 million of related expenditures during the period from 2007 through 2010.
Included in these amounts are expenditures to reduce emissions of generating plants in Minnesota and Colorado. Approximately $347 million
and $392 million of these expenditures, respectively, are related to modifications to reduce the emissions of NSP-Minnesota’s generating
plants located in the Minneapolis-St. Paul metropolitan area pursuant to MERP, which are recoverable from customers through cost-recovery
mechanisms. Expected expenditures related to environmental modifications on Comanche Units 1 and 2 are approximately $26 million in 2006
and $62 million during the period from 2007 through 2010. The remaining expected capital expenditures relate to various other environmental
projects. See Note 14 to the Consolidated Financial Statements for further discussion of Xcel Energy’s environmental contingencies.

The issue of global climate change is receiving increased attention. Debate continues concerning the extent to which the earth’s climate is
warming, the causes of climate variations that have been observed and the ultimate impact that might result from a changing climate.
There also is considerable debate regarding public policy for the approach that the United States should follow to address the issue. The
United Nations-sponsored Kyoto Protocol, which establishes greenhouse gas reduction targets for developed nations, entered into force on
Feb. 16, 2005. President Bush has declared that the United States will not ratify the protocol and is opposed to legislative mandates, preferring
a program based on voluntary efforts and research on new technologies. Xcel Energy is closely monitoring the issue from both scientific
and policy perspectives. While it is not possible to know the eventual outcome, Xcel Energy believes the issue merits close attention and is
taking actions it believes are prudent to be best positioned for a variety of possible outcomes. Xcel Energy is participating in a voluntary carbon
management program and has established goals to reduce its volume of carbon dioxide emissions by 12 million tons by 2009, and to reduce
carbon intensity by 7 percent by 2012. In certain regulatory jurisdictions, the evaluation process for future generating resources incorporates
the risk of future carbon limits through the use of a carbon cost adder or externality costs. Xcel Energy also is involved in other projects to
improve available methods for managing carbon.

Impact of Nonregulated Investments

In the past, Xcel Energy’s investments in nonregulated operations have had a significant impact on its results of operations. As a result of the
divestiture of NRG and other nonregulated operations, Xcel Energy does not expect that its investments in nonregulated operations will continue
to have such a significant impact on its results. Xcel Energy does not expect to make any material investments in nonregulated projects.

Inflation

Inflation at its current level is not expected to materially affect Xcel Energy’s prices or returns to shareholders.

C R I T I C A L AC C O U N T I N G P O L I C I E S A N D E ST I M AT E S

Preparation of the Consolidated Financial Statements and related disclosures in compliance with GAAP requires the application of appropriate
technical accounting rules and guidance, as well as the use of estimates. The application of these policies necessarily involves judgments
regarding future events, including the likelihood of success of particular projects, legal and regulatory challenges and anticipated recovery of
costs. These judgments, in and of themselves, could materially impact the Consolidated Financial Statements and disclosures based on varying
assumptions, which may be appropriate to use. In addition, the financial and operating environment also may have a significant effect, not
only on the operation of the business, but on the results reported through the application of accounting measures used in preparing the
Consolidated Financial Statements and related disclosures, even if the nature of the accounting policies applied have not changed. The
following is a list of accounting policies that are most significant to the portrayal of Xcel Energy’s financial condition and results, and that
require management’s most difficult, subjective or complex judgments. Each of these has a higher potential likelihood of resulting in
materially different reported amounts under different conditions or using different assumptions. Each critical accounting policy has been
discussed with the audit committee of the Xcel Energy board of directors.

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Accounting Policy

Judgments/Uncertainties Affecting Application

See Additional Discussion At

Regulatory Mechanisms and 
Cost Recovery

– External regulatory decisions, requirements 

and regulatory environment
– Anticipated future regulatory 
decisions and their impact

Management’s Discussion and Analysis:
Factors Affecting Results of Continuing Operations

Regulation

Notes to Consolidated Financial Statements

– Impact of deregulation and competition on 

Notes 1, 14 and 16

ratemaking process and ability to recover costs

Nuclear Plant Decommissioning
and Cost Recovery

– Costs of future decommissioning
– Availability of facilities for waste disposal
– Approved methods for waste disposal
– Useful lives of nuclear power plants
– Future recovery of plant investment and 

decommissioning costs

Notes to Consolidated Financial Statements

Notes 1, 14 and 15

Income Tax Accruals

– Application of tax statutes and 
regulations to transactions

Management’s Discussion and Analysis:
Factors Affecting Results of Continuing Operations

– Anticipated future decisions of tax authorities
– Ability of tax authority decisions/positions 
to withstand legal challenges and appeals 
– Ability to realize tax benefits through carry 
backs to prior periods or carry overs to 
future periods

Tax Matters

Notes to Consolidated Financial Statements

Notes 1, 8 and 14

Benefit Plan Accounting

– Future rate of return on pension and other 

plan assets, including impact of any changes 
to investment portfolio composition

Management’s Discussion and Analysis:
Factors Affecting Results of Continuing Operations

Pension Plan Costs and Assumptions

– Discount rates used in valuing benefit obligation Notes to Consolidated Financial Statements
– Actuarial period selected to recognize deferred 

Notes 1 and 10

investment gains and losses

Asset Valuation

– Regional economic conditions affecting asset 

Management’s Discussion and Analysis:

operation, market prices and related cash flows  Results of Operations

– Regulatory and political environments 

and requirements

Statement of Operations Analysis
Discontinued Operations

– Levels of future market penetration and 

Factors Affecting Results of Continuing Operations

customer growth 

Impact of Nonregulated Investments
Notes to Consolidated Financial Statements

Note 2

Xcel Energy continually makes informed judgments and estimates related to these critical accounting policy areas, based on an evaluation
of the varying assumptions and uncertainties for each area. For example:
– Probable outcomes of regulatory proceedings are assessed in cases of requested cost recovery or other approvals from regulators.
– The ability to operate plant facilities and recover the related costs over their useful operating lives, or such other period designated by

Xcel Energy’s regulators, is assumed.

– Probable outcomes of reviews and challenges raised by tax authorities, including appeals and litigation where necessary, are assessed.
– Projections are made regarding earnings on pension investments, and the salary increases provided to employees over their periods of

service.

– Future cash inflows of operations are projected in order to assess whether they will be sufficient to recover future cash outflows, including

the impact of product price changes and market penetration to customer groups.

The information and assumptions underlying many of these judgments and estimates will be affected by events beyond the control of Xcel
Energy, or otherwise change over time. This may require adjustments to recorded results to better reflect the events and updated information
that becomes available. The accompanying financial statements reflect management’s best estimates and judgments of the impact of these
factors as of Dec. 31, 2005.

R E C E N T LY I M P L E M E N T E D AC C O U N T I N G C H A N G E S

For a discussion of significant accounting policies, see Note 1 to the Consolidated Financial Statements.

P E N D I N G AC C O U NT I N G C H A N G E S

Statement of Financial Accounting Standards (SFAS) No. 123 (Revised 2004) – “Share Based Payment” (SFAS No. 123R)
In December 2004, the FASB issued SFAS No. 123R related to equity-based compensation. This statement replaces the original SFAS No. 123 –
“Accounting for Stock-Based Compensation.” Under SFAS No. 123R, companies are no longer allowed to account for their share-based payment
awards using the intrinsic value allowed by previous accounting requirements, which did not require any expense to be recorded on stock
options granted with an equal to or greater than fair market value exercise price. Instead, equity-based compensation arrangements will be

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measured and recognized based on the grant-date fair value using an option-pricing model (such as Black-Scholes or Binomial) that considers at
least six factors identified in SFAS No. 123R. An expense related to the difference between the grant-date fair value and the purchase price
would be recognized over the vesting period of the options. Under previous guidance, companies were allowed to initially estimate forfeitures
or recognize them as they actually occurred. SFAS No. 123R requires companies to estimate forfeitures on the date of grant and to adjust
that estimate when information becomes available that suggests actual forfeitures will differ from previous estimates. Revisions to forfeiture
estimates will be recorded as a cumulative effect of a change in accounting estimate in the period in which the revision occurs.

Previous accounting guidance allowed for compensation expense related to performance share plans to be reversed if the target was not met.
However, under SFAS No. 123R, compensation expense for performance share plans that expire unexercised due to the company’s failure to
reach a certain target stock price cannot be reversed. Any accruals made for Xcel Energy’s restricted stock unit plan that were granted in 2004
and based on a total shareholder return could not be reversed if the target was not met. Implementation of SFAS No. 123R is required for
annual periods beginning after June 15, 2005. Xcel Energy is required to adopt the provisions in the first quarter of 2006. Implementation is
not expected to have a material impact on net income or earnings per share.

Accounting for Uncertain Tax Positions  In July 2004, the FASB discussed potential changes or clarifications in the criteria for recognition
of income tax benefits, which may result in raising the threshold for recognizing tax benefits that have some degree of uncertainty. In July 2005,
the FASB issued an exposure draft on accounting for uncertain tax positions under SFAS No. 109 – “Accounting for Income Taxes.” As issued,
the exposure draft would have been effective Dec. 31, 2005, and only tax benefits that meet the “probable” recognition threshold would be
recognized or continue to be recognized on the effective date. Initial derecognition amounts would be reported as a cumulative effect of a
change in accounting principle.

Subsequent to the comment period that closed in September 2005, the FASB announced that the effective date of its new interpretation will
be delayed, with a revised pronouncement to be released no earlier than the first quarter of 2006. In redeliberations in November 2005, the
FASB decided that the benefit recognition approach in the exposure draft should be retained, but that the initial recognition threshold should
be “more likely than not” rather than “probable.” In redeliberations on Jan. 11, 2006, the FASB addressed the issues of transition and effective
date. For Xcel Energy, the new interpretation, if and when issued, is likely to be effective beginning Jan. 1, 2007, with any cumulative effect of
the change reflected in retained earnings. Although Xcel Energy has not assessed the impact of a new recognition threshold on all of its open
tax positions, based on available information, it believes that its COLI tax position meets the “more likely than not” threshold, and therefore
it plans to continue to recognize all COLI tax benefits in full. See Factors Affecting Results of Continuing Operations –  Tax Matters for further
discussion of this matter.

DERIVATIVES,  RISK  MANAGEMENT AND  MARKET  RISK

In the normal course of business, Xcel Energy and its subsidiaries are exposed to a variety of market risks. Market risk is the potential loss
that may occur as a result of changes in the market or fair value of a particular instrument or commodity. All financial and commodity-related
instruments, including derivatives, are subject to market risk. These risks, as applicable to Xcel Energy and its subsidiaries, are discussed in
further detail later.

Commodity Price Risk  Xcel Energy and its subsidiaries are exposed to commodity price risk in their electric and natural gas operations.
Commodity price risk is managed by entering into both long- and short-term physical purchase and sales contracts for electric capacity, energy
and energy-related products, and for various fuels used in generation and distribution activities. Commodity price risk is also managed through
the use of financial derivative instruments. Xcel Energy’s risk-management policy allows it to manage commodity price risk within each
rate-regulated operation to the extent such exposure exists.

Short-Term Wholesale and Commodity Trading Risk  Xcel Energy’s subsidiaries conduct various short-term wholesale and commodity
trading activities, including the purchase and sale of capacity, energy and energy-related instruments. These marketing activities are primarily
focused on specific regions where market knowledge and experience have been obtained and are generally less than one year in length.
Xcel Energy’s risk-management policy allows management to conduct these activities within approved guidelines and limitations as approved
by the company’s risk-management committee, which is made up of management personnel not directly involved in the activities governed
by the policy.

Certain contracts and financial instruments within the scope of these activities qualify for hedge accounting treatment under SFAS No. 133 –
“Accounting for Derivative Instruments and Hedging Activities,” as amended (SFAS No. 133).

The fair value of the commodity trading contracts as of Dec. 31, 2005, was as follows:

(Millions of dollars)

Fair value of trading contracts outstanding at Jan. 1, 2005
Contracts realized or settled during the year
Fair value of trading contract additions and changes during the year

Fair value of contracts outstanding at Dec. 31, 2005

$  –
(6.1)
10.0
$ 3.9

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As of Dec. 31, 2005, the fair values by source for the commodity trading and hedging net asset or liability balances were as follows:

C O M M O D I T Y T R A D I N G C O NT R AC T S

Futures/Forwards

(Thousands of dollars)

NSP-Minnesota

PSCo

Total futures/forwards fair value

Options

(Thousands of dollars)

NSP-Minnesota
PSCo

Total options fair value

H E D G E C O NT R AC T S

Futures/Forwards

(Thousands of dollars)

NSP-Minnesota
PSCo

Total futures/forwards fair value

Options

(Thousands of dollars)

NSP-Minnesota
NSP-Wisconsin
PSCo

Total options fair value

Source of Maturity Less
than 1 Year 
Fair Value

Maturity
1 to 3 Years

Maturity Maturity Greater
than 5 Years

4 to 5 Years

Total Futures/
Forwards Fair Value

1
2
1
2

$

663
15
1,352
1,382
$ 3,412

$

–
1,109
–
261
$1,370

$

–
322
–
–
$322

$ –
–
–
–
$ –

$

663
1,446
1,352
1,643
$ 5,104

Source of Maturity Less
than 1 Year 
Fair Value

Maturity
1 to 3 Years

Maturity Maturity Greater
than 5 Years

4 to 5 Years

Total Options
Fair Value

2
2

$ (251)
(922)
$(1,173)

$

$

–
–
–

$    –
–
$    –

$ –
–
$ –

$ (251)
(922)
$(1,173)

Source of Maturity Less
than 1 Year 
Fair Value

Maturity
1 to 3 Years

Maturity Maturity Greater
than 5 Years

4 to 5 Years

Total Futures/
Forwards Fair Value

2
2

$ 2,927
1,944
$ 4,871

$

$

–
–
–

$    –
–
$    –

$ –
–
$ –

$ 2,927
1,944
$ 4,871

Source of Maturity Less
than 1 Year 
Fair Value

Maturity
1 to 3 Years

Maturity Maturity Greater
than 5 Years

4 to 5 Years

Total Options
Fair Value

2
2
2

$ (583)
726
(1,954)
$ (1,811)

$

–
–
1,036
$1,036

$    –
–
–
$    –

$ –
–
–
$ –

$ (583)
726
(918)
$ (775)

1  Prices actively quoted or based on actively quoted prices.

2  Prices based on models and other valuation methods. These represent the fair value of positions calculated using internal models when directly and
indirectly quoted external prices or prices derived from external sources are not available. Internal models incorporate the use of options pricing and
estimates of the present value of cash flows based upon underlying contractual terms. The models reflect management’s estimates, taking into account
observable market prices, estimated market prices in the absence of quoted market prices, the risk-free market discount rate, volatility factors, estimated
correlations of commodity prices and contractual volumes. Market price uncertainty and other risks also are factored into the model.

Normal purchases and sales transactions, as defined by SFAS No. 133, and certain other long-term power purchase contracts are not included
in the fair values by source tables as they are not included in the commodity trading operations and are not qualifying hedges.

At Dec. 31, 2005, a 10-percent increase in market prices over the next 12 months for commodity trading contracts would decrease pretax
income from continuing operations by approximately $0.7 million, whereas a 10-percent decrease would increase pretax income from continuing
operations by approximately $0.8 million. 

Xcel Energy’s short-term wholesale and commodity trading operations measure the outstanding risk exposure to price changes on transactions,
contracts and obligations that have been entered into, but not closed, using an industry standard methodology known as Value-at-Risk (VaR).
VaR expresses the potential change in fair value on the outstanding transactions, contracts and obligations over a particular period of time,
with a given confidence interval under normal market conditions. Xcel Energy utilizes the variance/covariance approach in calculating VaR.
The VaR model employs a 95-percent confidence interval level based on historical price movement, lognormal price distribution assumption,
delta half-gamma approach for non-linear instruments and a three-day holding period for both electricity and natural gas.

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As of Dec. 31, 2005, the VaRs for the commodity trading operations were:

(Millions of dollars)

Commodity trading (a)

Year ended Dec. 31, 2005

Average

$2.06

$1.44

(a) Comprises transactions for NSP-Minnesota, PSCo and SPS.

As of Dec. 31, 2004, the VaRs for the commodity trading operations were:

(Millions of dollars)

Commodity trading (a)

Year ended Dec. 31, 2004

Average

$0.29

$0.97

(a) Comprises transactions for NSP-Minnesota, PSCo and SPS.

During 2005

High

$4.43

During 2004

High

$2.09

Low

$0.26

Low

$0.27

Interest Rate Risk  Xcel Energy and its subsidiaries are subject to the risk of fluctuating interest rates in the normal course of business.
Xcel Energy’s policy allows interest rate risk to be managed through the use of fixed rate debt, floating rate debt and interest rate derivatives
such as swaps, caps, collars and put or call options.

Xcel Energy engages in hedges of cash flow and fair value exposure. The fair value of interest rate swaps designated as cash flow hedges is
initially recorded in Other Comprehensive Income. Reclassification of unrealized gains or losses on cash flow hedges of variable rate debt
instruments from Other Comprehensive Income into earnings occurs as interest payments are accrued on the debt instrument, and generally
offsets the change in the interest accrued on the underlying variable rate debt. Hedges of fair value exposure are entered into to hedge the
fair value of a recognized asset, liability or firm commitment. Changes in the derivative fair values that are designated as fair value hedges
are recognized in earnings as offsets to the changes in fair values of related hedged assets, liabilities or firm commitments. To test the
effectiveness of such swaps, a hypothetical swap is used to mirror all the critical terms of the underlying debt and regression analysis is
utilized to assess the effectiveness of the actual swap at inception and on an ongoing basis. The fair value of interest rate swaps is determined
through counterparty valuations, internal valuations and broker quotes. There have been no material changes in the techniques or models
used in the valuation of interest rate swaps during the periods presented.

At Dec. 31, 2005 and 2004, a 100-basis-point change in the benchmark rate on Xcel Energy’s variable rate debt would impact pretax interest
expense by approximately $10.3 million and $6.8 million, respectively. See Note 12 to the Consolidated Financial Statements for a discussion
of Xcel Energy and its subsidiaries’ interest rate swaps.

Xcel Energy and its subsidiaries also maintain trust funds, as required by the Nuclear Regulatory Commission (NRC), to fund certain costs of
nuclear decommissioning, which are subject to interest rate risk and equity price risk. As of Dec. 31, 2005 and 2004, these funds were invested
primarily in domestic and international equity securities and fixed-rate fixed-income securities. Per NRC mandates, these funds may be used
only for activities related to nuclear decommissioning. The accounting for nuclear decommissioning recognizes that costs are recovered through
rates; therefore fluctuations in equity prices or interest rates do not have an impact on earnings.

Credit Risk In addition to the risks discussed previously, Xcel Energy and its subsidiaries are exposed to credit risk. Credit risk relates to the
risk of loss resulting from the nonperformance by a counterparty of its contractual obligations. Xcel Energy and its subsidiaries maintain credit
policies intended to minimize overall credit risk and actively monitor these policies to reflect changes and scope of operations.

Xcel Energy and its subsidiaries conduct standard credit reviews for all counterparties. Xcel Energy employs additional credit risk control
mechanisms when appropriate, such as letters of credit, parental guarantees, standardized master netting agreements and termination
provisions that allow for offsetting of positive and negative exposures. The credit exposure is monitored and, when necessary, the activity
with a specific counterparty is limited until credit enhancement is provided.

At Dec. 31, 2005, a 10-percent increase in prices would have resulted in a net mark-to-market increase in credit risk exposure of $44.2 million,
while a decrease of 10 percent would have resulted in a decrease of $41.1 million.

LIQUIDITY AND  CAPITAL  RESOURCES

C AS H F LOW S

(Millions of dollars)

Cash provided by (used in) operating activities
Continuing operations
Discontinued operations

Total

2005

2004

2003

$1,131
53
$1,184

$1,128
(315)
$ 813

$1,106
275
$1,381

Cash provided by operating activities for continuing operations was basically unchanged for 2005 and 2004. Cash provided by operating
activities for discontinued operations increased $368 million during 2005 compared with 2004. During 2004, Xcel Energy paid $752 million
pursuant to the NRG settlement agreement, which was partially offset by tax benefits received.

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Cash provided by operating activities for continuing operations increased $22 million during 2004 compared with 2003, due to timing of
payments made for trade payables partially offset by increased inventory costs related to higher natural gas costs, which will be collected
from customers in future periods. Cash provided by operating activities for discontinued operations decreased $590 million during 2004
compared with 2003. During 2004, Xcel Energy paid $752 million pursuant to the NRG settlement agreement, which was partially offset by
tax benefits received.

(Millions of dollars)

Cash provided by (used in) investing activities
Continuing operations
Discontinued operations

Total

2005

2004

2003

$(1,362)
136
$(1,226)

$(1,268)
37
$(1,231)

$(1,055)
126
$ (929)

Cash used in investing activities for continuing operations increased $94 million during 2005 compared with 2004, primarily due to increased
2005 utility capital expenditures and restricted cash released in 2004. Cash provided by investing activities for discontinued operations
increased $99 million during 2005 compared with 2004, primarily due to the receipt of proceeds from the sale of Cheyenne and Seren in 2005.

Cash used in investing activities for continuing operations increased $213 million during 2004 compared with 2003, primarily due to increased
utility capital expenditures. Cash provided by investing activities for discontinued operations decreased $89 million during 2004 compared
with 2003, primarily due to the receipt of proceeds from the sale of Viking in 2003.

(Millions of dollars)

Cash provided by (used in) financing activities
Continuing operations
Discontinued operations

Total

2005

2004

2003

$111
–
$111

$(111)
–
$(111)

$(346)
(21)
$(367)

Cash flow from financing activities related to continuing operations increased $222 million during 2005 compared with 2004, primarily due
to increased short-term borrowings.

Cash flow from financing activities related to continuing operations increased $235 million during 2004 compared with 2003, primarily due
to increased short-term borrowings partially offset by a common stock repurchase.

See discussion of trends, commitments and uncertainties with the potential for future impact on cash flow and liquidity under Capital Sources.

C A P I TA L R E QU I R E M E NT S

Utility Capital Expenditures, Nonregulated Investments and Long-Term Debt Obligations  The estimated cost of the capital expenditure
programs of Xcel Energy and its subsidiaries, excluding discontinued operations, and other capital requirements for the years 2006, 2007
and 2008 are shown in the table below.

(Millions of dollars)

Electric utility
Natural gas utility
Common utility
Total utility
Other nonregulated

Total capital expenditures

Debt maturities

Total capital requirements

2006

$1,386
110
84
1,580
–
1,580
835
$2,415

2007

$1,381
113
81
1,575
–
1,575
339
$1,914

2008

$1,169
132
81
1,382
2
1,384
632
$2,016

The capital expenditure forecast includes PSCo’s share of the 750-megawatt Comanche 3 coal-fired plant in Colorado and the MERP project,
which will reduce the emissions of three of NSP-Minnesota’s generating plants. The MERP project is expected to cost approximately $1 billion,
with major construction starting in 2005 and finishing in 2009. Xcel Energy began recovering the costs of the emission-reduction project
through customer rate increases effective Jan. 1, 2006. Comanche 3 is expected to cost approximately $1.35 billion, with major construction
starting in 2006 and finishing in 2010. The CPUC has approved sharing one-third ownership of this plant with other parties. Consequently,
Xcel Energy’s capital expenditure forecast includes $1 billion, approximately two-thirds of the total cost.

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, 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 restructuring requirements, compliance with future requirements to install emission-control equipment, and merger, acquisition and
divestiture opportunities to support corporate strategies may impact actual capital requirements.

Contractual Obligations and Other Commitments  Xcel Energy has contractual obligations and other commercial commitments that will
need to be funded in the future, in addition to its capital expenditure programs. The following is a summarized table of contractual obligations
and other commercial commitments at Dec. 31, 2005. See additional discussion in the Consolidated Statements of Capitalization and Notes
3, 4, 13 and 14 to the Consolidated Financial Statements.

34 XCEL ENERGY 2005 ANNUAL REPORT

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(Thousands of dollars)

Total

Less than 1 Year

1 to 3 Years

4 to 5 Years

After 5 Years

Long-term debt, principal and interest payments
Capital lease obligations
Operating leases (a)
Unconditional purchase obligations (b)
Other long-term obligations
Payments to vendors in process
Short-term debt

Total contractual cash obligations (c)

$ 10,387,694
98,684
208,249
11,972,606
265,925
129,315
746,120
$23,808,593

$1,236,074
6,447
41,376
2,573,587
38,213
129,315
746,120
$4,771,132

$1,672,323
12,426
64,589
2,639,833
55,376
–
–
$4,444,547

$2,148,700
11,794
48,055
2,057,622
52,706
–
–
$4,318,877

$ 5,330,597
68,017
54,229
4,701,564
119,630
–
–
$10,274,037

Payments Due by Period

(a) Under some leases, Xcel Energy would have to sell or purchase the property that it leases if it chose to terminate before the scheduled lease
expiration date. Most of Xcel Energy’s railcar, vehicle and equipment and aircraft leases have these terms. At Dec. 31, 2005, the amount that
Xcel Energy would have to pay if it chose to terminate these leases was approximately $110.8 million.

(b) Obligations to purchase fuel for electric generating plants, and electricity and natural gas for resale. Certain contractual purchase obligations are

adjusted based on indexes. However, the effects of price changes are mitigated through cost-of-energy adjustment mechanisms.

(c) Xcel Energy also has outstanding authority under contracts and blanket purchase orders to purchase up to approximately $600 million of goods

and services through the year 2020, in addition to the amounts disclosed in this table and in the forecasted capital expenditures.

Common Stock Dividends  Future dividend levels will be dependent on Xcel Energy’s results of operations, financial position, cash flows
and other factors, and will be evaluated by the Xcel Energy board of directors. Xcel Energy’s objective is to deliver the financial results that
will enable the board of directors to grant annual dividend increases in the range of 2 percent to 4 percent per year. Xcel Energy’s dividend
policy balances:
– Projected cash generation from utility operations;
– Projected capital investment in the utility businesses;
– A reasonable rate of return on shareholder investment; and
– The impact on Xcel Energy’s capital structure and credit ratings.

In addition, there are certain statutory limitations that could affect dividend levels. Under the PUHCA, unless there was an order from the SEC,
a holding company or any subsidiary could only declare and pay dividends out of retained earnings. Xcel Energy had $562 million of retained
earnings at Dec. 31, 2005, and expects to declare dividends as scheduled. With the repeal of the PUHCA, this limitation on a holding company’s
dividends will no longer apply. Notwithstanding the repeal of the PUHCA, federal law will still limit the ability of public utilities within a holding
company system to declare dividends. Specifically, under the Federal Power Act, a public utility may not pay dividends from any funds properly
included in a capital account. The cash to pay dividends to Xcel Energy shareholders is primarily derived from dividends received from the
utility subsidiaries. The utility subsidiaries are generally limited in the amount of dividends allowed by state regulatory commissions to be
paid to the holding company. The limitation is imposed through equity ratio limitations that range from 30 percent to 60 percent. Some utility
subsidiaries must comply with bond indenture covenants or restrictions under credit agreements for debt to total capitalization ratios. 

The Articles of Incorporation of Xcel Energy place restrictions on the amount of common stock dividends it can pay when preferred stock is
outstanding. Under the provisions, dividend payments may be restricted if Xcel Energy’s capitalization ratio (on a holding company basis
only, i.e., not on a consolidated basis) is less than 25 percent. For these purposes, the capitalization ratio is equal to common stock plus
surplus, divided by the sum of common stock plus surplus plus long-term debt. Based on this definition, Xcel Energy’s capitalization ratio
at Dec. 31, 2005, was 84 percent. Therefore, the restrictions do not place any effective limit on Xcel Energy’s ability to pay dividends because
the restrictions are only triggered when the capitalization ratio is less than 25 percent or will be reduced to less than 25 percent through
dividends (other than dividends payable in common stock), distributions or acquisitions of Xcel Energy common stock.

C A P I TA L S O U R C E S

Xcel Energy expects to meet future financing requirements by periodically issuing short-term debt, long-term debt, common stock and preferred
securities to maintain desired capitalization ratios.

Registered holding companies and certain of their subsidiaries, including Xcel Energy and its utility subsidiaries, were limited under the PUHCA
in their ability to issue securities. Registered holding companies and their subsidiaries could not issue securities unless authorized by an
exemptive rule or order of the SEC. Because Xcel Energy does not qualify for any of the main exemptive rules, it had received financing
authority from the SEC under the PUHCA for various financing arrangements. Xcel Energy’s current financing authority permits it, subject to
certain conditions, to issue through June 30, 2008, up to $1.8 billion of new long-term debt, common equity and equity-linked securities, and
$1.0 billion of short-term debt securities during the new authorization period, provided that the aggregate amount of long-term debt, common
equity, and equity-linked and short-term debt securities issued during the new authorization period does not exceed $2.0 billion.

Xcel Energy’s ability to issue securities under the financing authority was subject to a number of conditions. One of the conditions of the
financing authority was that Xcel Energy’s consolidated ratio of common equity to total capitalization be at least 30 percent. As of Dec. 31,
2005, the common equity ratio was approximately 42 percent. Additional conditions require that a security to be issued, must at least be
rated investment grade by at least one nationally recognized rating agency. Finally, all outstanding securities that are rated must be rated
investment grade by at least one nationally recognized rating agency. On Feb. 10, 2006, Xcel Energy’s senior unsecured debt was considered
investment grade by Standard & Poor’s Ratings Services (Standard & Poor’s), Moody’s and Fitch Ratings (Fitch).

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Upon the repeal of the PUHCA, these limitations on Xcel Energy’s financings generally will no longer apply, nor will the PUHCA restrictions
generally apply to the financings by the utility subsidiaries. However, utility financings and intra-system financing will become subject to
the jurisdiction of the FERC under the Federal Power Act.  The FERC has granted a blanket authorization for certain intra-system financings
involving holding companies. Requests to the FERC to clarify its rules or grant similar blanket authorizations are presently pending before
the FERC. Xcel Energy and the utility subsidiaries are presently evaluating the specific applications that they will need to file with the FERC
due to the repeal of the PUHCA.

It is possible that in lieu of requesting authority from the FERC for intra-system financings, Xcel Energy and the utility subsidiaries may rely in
the interim on a transitional savings clause that would permit such financing transactions to the extent authorized by the SEC financing order
and so long as the conditions in the SEC financing order continue to be satisfied.

Short-Term Funding Sources  Historically, Xcel Energy has used a number of sources to fulfill short-term funding needs, including operating
cash flow, notes payable, commercial paper and bank lines of credit. The amount and timing of short-term funding needs depend in large
part on financing needs for construction expenditures and working capital. Another significant short-term funding need is the dividend payment.

As of Feb. 14, 2006, Xcel Energy and its utility subsidiaries had the following committed credit facilities available to meet its liquidity needs:

(Millions of dollars)

Facility

Drawn* Available

Cash

Liquidity

Maturity

NSP-Minnesota
NSP-Wisconsin
PSCo
PSCo
SPS
Xcel Energy – holding company

Total

$ 450
–
600
50
250
700
$2,050

$162.7
–
212.0
–
82.0
393.5
$850.2

$ 287.3
–
388.0
50.0
168.0
306.5
$1,199.8

$

–
–
49.2
–
12.7
0.8
$62.7

$ 287.3
–
437.2
50.0
180.7
307.3
$1,262.5

April 2010

April 2010
April 2006
April 2010
November 2009

*  Includes direct borrowings, outstanding commercial paper and letters of credit.

Operating cash flow as a source of short-term funding is affected by such operating factors as weather; regulatory requirements, including
rate recovery of costs; environmental regulation compliance and industry deregulation; changes in the trends for energy prices; and supply
and operational uncertainties, all of which are difficult to predict. See further discussion of such factors under Statement of Operations Analysis.

Short-term borrowing as a source of funding is affected by regulatory actions and access to reasonably priced capital markets. For additional
information on Xcel Energy’s short-term borrowing arrangements, see Note 3 to the Consolidated Financial Statements. Access to reasonably
priced capital markets is dependent in part on credit agency reviews and ratings. The following ratings reflect the views of Moody’s, Standard
& Poor’s, and Fitch. A security rating is not a recommendation to buy, sell or hold securities, and is subject to revision or withdrawal at any
time by the rating agency. As of Feb. 23, 2006, the following represents the credit ratings assigned to various Xcel Energy companies:

Company

Credit Type

Moody’s

Standard & Poor’s

Xcel Energy
Xcel Energy
NSP-Minnesota
NSP-Minnesota
NSP-Minnesota
NSP-Wisconsin
NSP-Wisconsin
PSCo
PSCo
PSCo
SPS
SPS

Senior Unsecured Debt
Commercial Paper
Senior Unsecured Debt
Senior Secured Debt
Commercial Paper
Senior Unsecured Debt
Senior Secured Debt
Senior Unsecured Debt
Senior Secured Debt
Commercial Paper
Senior Unsecured Debt
Commercial Paper

Baa1
P-2
A3
A2
P-2
A3
A2
Baa1
A3
P-2
Baa1
P-2

BBB-
A-2
BBB-
A-
A-2
BBB
A-
BBB-
A-
A-2
BBB
A-2

Fitch

BBB+
F2
A
A+
F1
A
A+
BBB+
A-
F2
A-
F2

Note: Moody’s highest credit rating for debt is Aaa and lowest investment grade rating is Baa3. Both Standard & Poor’s and Fitch’s highest credit
rating for debt is AAA and lowest investment grade rating is BBB-. Moody’s prime ratings for commercial paper range from P-1 to P-3. Standard &
Poor’s ratings for commercial paper range from A-1 to A-3, and Fitch’s ratings for commercial paper range from F1 to F3.

In the event of a downgrade of its credit ratings to below investment grade, Xcel Energy may be required to provide credit enhancements
in the form of cash collateral, letters of credit or other security to satisfy all or a part of its exposures under guarantees outstanding. See a
list of guarantees at Note 13 to the Consolidated Financial Statements. Xcel Energy has no explicit rating triggers in its debt agreements.

Money Pool  Xcel Energy has established a utility money pool arrangement with the utility subsidiaries and received required state regulatory
approvals. The utility money pool allows for short-term loans between the utility subsidiaries and from the holding company to the utility
subsidiaries at market-based interest rates. The utility money pool arrangement does not allow loans from the utility subsidiaries to the
holding company. NSP-Minnesota, PSCo and SPS participate in the utility money pool pursuant to approval from their respective state
regulatory commissions. No borrowings or loans were outstanding at Dec. 31, 2005. Borrowing limits are $250 million, $250 million and
$100 million, respectively. As a consequence of the repeal of the PUHCA and the recent amendments to section 203 of the Federal Power

36 XCEL ENERGY 2005 ANNUAL REPORT

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Act, it may be necessary for Xcel Energy and the utility subsidiaries to submit its existing money pool arrangement to the FERC for its
approval. Xcel Energy and the utility subsidiaries are presently evaluating the situation.

Registration Statements  Xcel Energy’s Articles of Incorporation authorize the issuance of 1 billion shares of common stock. As of Dec. 31, 2005,
Xcel Energy had approximately 403 million shares of common stock outstanding. In addition, Xcel Energy’s Articles of Incorporation authorize
the issuance of 7 million shares of $100 par value preferred stock. On Dec. 31, 2005, Xcel Energy had approximately 1 million shares of
preferred stock outstanding. Xcel Energy and its subsidiaries have the following registration statements on file with the SEC, pursuant to
which they may sell, from time to time, securities:
– In February 2002, Xcel Energy filed a $1 billion shelf registration with the SEC. Xcel Energy may issue debt securities, common stock and rights
to purchase common stock under this shelf registration. Xcel Energy has approximately $482.5 million remaining under this registration. Xcel
Energy has approximately $400 million remaining under the $1 billion unsecured debt shelf registration filed with the SEC in 2000.

– On March 22, 2005, NSP-Minnesota filed a shelf registration statement with the SEC to register an additional $1 billion of secured or unsecured
debt securities, which may be issued from time to time in the future. This registration became effective on April 7, 2005, and supplements
the $40 million of debt securities previously registered with the SEC. After issuance of $250 million of first mortgage bonds in July 2005,
as discussed later, $790 million remains available under the currently effective registration statement.

– PSCo has an effective shelf registration statement with the SEC under which $800 million of secured first collateral trust bonds or unsecured

senior debt securities were registered. PSCo has approximately $225 million remaining under this registration.

F U T U R E F I N A N C I N G P L A N S

Xcel Energy generally expects to fund its operations and capital investments primarily through internally generated funds. Xcel Energy
plans to refinance existing long-term debt or scheduled long-term debt maturities at each of the regulated operating utilities based on
prevailing market conditions. To facilitate potential long-term debt issuances at the utility subsidiaries, SPS intends to file a long-term
debt shelf registration statement with the SEC for up to $500 million in 2006, and NSP-Wisconsin may file a long-term debt shelf registration
for up to $100 million.

O F F- B A L A N C E- S H E E T A R R A N G E M E NT S
Xcel Energy does not have any off-balance-sheet arrangements that have or are reasonably likely to have a current or future effect on financial
condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that
is material to investors.

E A R N I N G S G U I DA N C E

Xcel Energy’s 2006 earnings per share from continuing operations guidance and key assumptions are detailed in the following table.

Utility operations
COLI tax benefit
Other nonregulated subsidiaries

Xcel Energy Continuing Operations

2006 Diluted Earnings Per Share Range

$1.25 – $1.35
0.10
(0.10)
$1.25 – $1.35

Key Assumptions for 2006:
– Normal weather patterns are experienced;
– Reasonable rate recovery is approved in the Minnesota electric rate case;
– Weather-adjusted retail electric utility sales grow by approximately 1.3 percent to 1.7 percent;
– Weather-adjusted retail natural gas utility sales grow by approximately 0.0 percent to 1.0 percent;
– Short-term wholesale and commodity trading margins are projected to be within a range of approximately $30 million to $50 million;
– Other utility operating and maintenance expenses increase between 3 percent and 4 percent from 2005 levels;
– Depreciation expense increases approximately $100 million to $110 million, which includes increases in decommissioning accruals that are

expected to be recovered through rates approved in the Minnesota electric rate case;
– Interest expense increases approximately $10 million to $15 million from 2005 levels;
– Allowance for funds used during construction recorded for equity financing is expected to increase approximately $10 million to $15 million

from 2005 levels;

– Xcel Energy continues to recognize COLI tax benefits;
– The effective tax rate for continuing operations is approximately 27 percent to 29 percent; and
– Average common stock and equivalents total approximately 428 million shares, based on the “If Converted” method for convertible notes.

XCEL ENERGY 2005 ANNUAL REPORT 37

MANAGEMENT  REPORT  ON  INTERNAL  CONTROLS  OVER  FINANCIAL  REPORTING

The management of Xcel Energy is responsible for establishing and maintaining adequate internal control over financial reporting. Xcel
Energy’s internal control system was designed to provide reasonable assurance to the company’s management and board of directors
regarding the preparation and fair presentation of published financial statements.

All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective
can provide only reasonable assurance with respect to financial statement preparation and presentation.

Xcel Energy management assessed the effectiveness of the company’s internal control over financial reporting as of Dec. 31, 2005. In making
this assessment, it used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal
Control – Integrated Framework. Based on our assessment, we believe that, as of Dec. 31, 2005, the company’s internal control over financial
reporting is effective based on those criteria.

Xcel Energy’s independent auditors have issued an audit report on our assessment of the company’s internal control over financial reporting.
Their report appears on the following page.

R I C H A R D C. K E L LY
Chairman, President and Chief Executive Officer
February 24, 2006

B E N JA M I N G. S. F OW K E I I I
Vice President and Chief Financial Officer
February 24, 2006

38 XCEL ENERGY 2005 ANNUAL REPORT

REPORT  OF  INDEPENDENT  REGISTERED  PUBLIC ACCOUNTING  FIRM

Board of Directors and Stockholders 
Xcel Energy Inc.

We have audited management’s assessment, included in the accompanying Management Report On Internal ControlsOver Financial Reporting,
that Xcel Energy Inc. and subsidiaries (the “Company”) maintained effective internal control over financial reporting as of December 31,
2005, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for
its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express an opinion on management’s
assessment and an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards
require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting
was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, evaluating
management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other
procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive
and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and
other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for
external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes
those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the
transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to
permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures
of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide
reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets
that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management
override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of
any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls
may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, management’s assessment that the Company maintained effective internal control over financial reporting as of December 31,
2005, is fairly stated, in all material respects, based on the criteria established in Internal Control – Integrated Framework issued by the
Committee of Sponsoring Organizations of the Treadway Commission. Also in our opinion, the Company maintained, in all material respects,
effective internal control over financial reporting as of December 31, 2005, based on the criteria established in Internal Control – Integrated
Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated
financial statements as of and for the year ended December 31, 2005, of the Company and our report dated February 24, 2006, expressed an
unqualified opinion on those financial statements.

Minneapolis, Minnesota
February 24, 2006

XCEL ENERGY 2005 ANNUAL REPORT 39

REPORT  OF  INDEPENDENT  REGISTERED  PUBLIC ACCOUNTING  FIRM

Board of Directors and Stockholders
Xcel Energy Inc.

We have audited the accompanying consolidated balance sheets and consolidated statements of capitalization of Xcel Energy Inc. and
subsidiaries (the “Company”) as of December 31, 2005 and 2004, and the related consolidated statements of operations, common stockholders’
equity and comprehensive income, and cash flows for each of the three years in the period ended December 31, 2005. These financial
statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements
based on our audits. 

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards
require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements.
An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating
the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Xcel Energy Inc. and
subsidiaries as of December 31, 2005 and 2004, and the results of their operations and their cash flows for each of the three years in the
period ended December 31, 2005, in conformity with accounting principles generally accepted in the United States of America. 

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the effectiveness
of the Company’s internal control over financial reporting as of December 31, 2005, based on the criteria established in Internal Control –
Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 24,
2006, expressed an unqualified opinion on management’s assessment of the effectiveness of the Company’s internal control over financial
reporting and an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

Minneapolis, Minnesota
February 24, 2006

40 XCEL ENERGY 2005 ANNUAL REPORT

C O N S O L I D A T E D S T A T E M E N T S O F O P E R A T I O N S

(Thousands of dollars, except per share data)

Operating revenues
Electric utility
Natural gas utility
Nonregulated and other

Total operating revenues

Operating expenses
Electric fuel and purchased power – utility
Cost of natural gas sold and transported – utility
Cost of sales – nonregulated and other
Other operating and maintenance expenses – utility
Other operating and maintenance expenses – nonregulated
Depreciation and amortization
Taxes (other than income taxes) 
Total operating expenses

Operating income
Interest and other income (expense), net (see Note 11)
Allowance for funds used during construction – equity

Interest charges and financing costs
Interest charges – (includes other financing costs of $25,829, $27,296 

and $31,992, respectively) 

Allowance for funds used during construction – debt
Distributions on redeemable preferred securities of subsidiary trusts

Total interest charges and financing costs

Income from continuing operations before income taxes
Income taxes
Income from continuing operations
Income (loss) from discontinued operations – net of tax (see Note 2)
Net income
Dividend requirements on preferred stock
Earnings available to common shareholders

Weighted average common shares outstanding (in thousands)
Basic
Diluted
Earnings (loss) per share – basic
Income from continuing operations
Income (loss) from discontinued operations (see Note 2) 

Earnings per share

Earnings (loss) per share – diluted
Income from continuing operations
Income (loss) from discontinued operations (see Note 2) 

Earnings per share

See Notes to Consolidated Financial Statements.

Year ended Dec. 31
2004

2005

2003

$7,243,637
2,307,385
74,455
9,625,477

$6,225,245
1,915,514
74,802
8,215,561

$5,919,938
1,677,768
133,561
7,731,267

3,922,163
1,823,123
24,676
1,679,172
28,493
767,321
287,810
8,532,758

1,092,719
857
21,627

3,040,759
1,445,773
28,757
1,591,718
44,109
705,955
282,775
7,139,846

1,075,715
9,316
33,648

2,705,839
1,190,996
80,683
1,570,492
53,485
727,307
278,034
6,606,836

1,124,431
(5,234)
25,338

463,370
(20,744)
–
442,626
672,577
173,539
499,038
13,934
512,972
4,241
$ 508,731

458,294
(23,814)
–
434,480
684,199
161,935
522,264
(166,303)
355,961
4,241
$ 351,720

448,690
(20,402)
22,731
451,019
693,516
170,692
522,824
99,568
622,392
4,241
$ 618,151

402,330
425,671

399,456
423,334

398,765
418,912

$

$

$

$

1.23
0.03
1.26

1.20
0.03
1.23

$

$

$

$

1.30
(0.42)
0.88

1.26
(0.39)
0.87

$

$

$

$

1.30
0.25
1.55

1.26
0.24
1.50

XCEL ENERGY 2005 ANNUAL REPORT 41

C O N S O L I D A T E D S T A T E M E N T S O F C A S H F L O W S

(Thousands of dollars)

Operating activities
Net income
Remove (income) loss from discontinued operations
Adjustments to reconcile net income to cash provided by operating activities:

Depreciation and amortization
Nuclear fuel amortization
Deferred income taxes
Amortization of investment tax credits
Allowance for equity funds used during construction
Undistributed equity in earnings of unconsolidated affiliates
Impairment of assets
Unrealized gain (loss) on derivative financial instruments
Change in accounts receivable
Change in inventories
Change in other current assets
Change in accounts payable
Change in other current liabilities
Change in other noncurrent assets
Change in other noncurrent liabilities

Operating cash flows (used in) provided by discontinued operations

Net cash provided by operating activities

Investing activities

Utility capital/construction expenditures
Allowance for equity funds used during construction
Purchase of investments in external decommissioning fund
Proceeds from the sale of investments in external decommissioning fund
Nonregulated capital expenditures and asset acquisitions
Proceeds from sale of assets
Equity investments, loans, deposits and sales of nonregulated projects
Restricted cash
Other investments

Investing cash flows provided by discontinued operations

Net cash used in investing activities

Financing activities

Short-term borrowings – net
Proceeds from issuance of long-term debt
Repayment of long-term debt, including reacquisition premiums
Proceeds from issuance of common stock
Repurchase of common stock
Dividends paid

Financing cash flows (used in) provided by discontinued operations
Net cash (used in) provided by financing activities

Net increase (decrease) in cash and cash equivalents
Net increase (decrease) in cash and cash equivalents – discontinued operations
Net increase in cash and cash equivalents – adoption of FIN No. 46
Cash and cash equivalents at beginning of year
Cash and cash equivalents at end of year
Supplemental disclosure of cash flow information

Cash paid for interest (net of amounts capitalized) 
Cash paid for income taxes (net of refunds received) 

See Notes to Consolidated Financial Statements.

Year ended Dec. 31
2004

2005

2003

$ 512,972
(13,934)

$ 355,961
166,303

$622,392
(99,568)

782,074
45,330
205,058
(11,620)
(21,627)
(712)
2,887
(3,923)
(250,305)
(94,605)
(289,250)
281,430
30,923
(81,506)
37,242
53,283
1,183,717

(1,304,468)
21,627
(576,001)
494,529
(6,976)
11,228
–
(6,226)
5,075
135,577
(1,225,635)

433,820
2,529,408
(2,517,698)
9,085
–
(343,092)
(200)
111,323

69,405
(20,570)
–
23,361
72,196

$

739,025
43,296
57,273
(12,189)
(33,648)
(3,342)
–
6,206
(123,044)
(46,220)
(190,827)
133,278
2,494
(6,485)
39,669
(314,575)
813,175

(1,274,290)
33,648
(305,328)
228,676
(2,122)
–
(4,082)
42,628
12,474
37,119
(1,231,277)

253,737
419,848
(438,595)
6,985
(32,023)
(320,444)
(200)
(110,692)

(528,794)
(12,018)
3,439
560,734
$   23,361

757,838
43,401
100,869
(12,439)
(25,338)
(4,833)
8,856
2,404
(129,408)
(911)
(174,793)
106,087
(4,855)
(142,849)
59,306
274,582
1,380,741

(944,421)
25,338
(144,367)
61,031
(2,055)
–
10,588
(38,488)
(22,380)
125,904
(928,850)

(428,580)
1,689,317
(1,307,012)
3,219
–
(303,316)
(20,500)
(366,872)

85,019
6,510
–
469,205
$560,734

$ 417,016
10,625
$

$ 423,673
$(355,639)

$402,506
$ (6,379)

42 XCEL ENERGY 2005 ANNUAL REPORT

C O N S O L I D A T E D B A L A N C E S H E E T S

(Thousands of dollars)

Assets
Current assets:

Cash and cash equivalents
Accounts receivable – net of allowance for bad debts: $39,798 and $34,299, respectively
Accrued unbilled revenues
Materials and supplies inventories – at average cost
Fuel inventory – at average cost
Natural gas inventories – at average cost
Recoverable purchased natural gas and electric energy costs
Derivative instruments valuation – at market
Prepayments and other
Current assets held for sale and related to discontinued operations

Total current assets

Property, plant and equipment, at cost:

Electric utility plant
Natural gas utility plant
Common utility and other property
Construction work in progress

Total property, plant and equipment

Less accumulated depreciation
Nuclear fuel – net of accumulated amortization: $1,190,386 and $1,145,228, respectively

Net property, plant and equipment

Other assets:

Nuclear decommissioning fund and other investments
Regulatory assets
Derivative instruments valuation – at market
Prepaid pension asset
Other
Noncurrent assets held for sale and related to discontinued operations

Total other assets

Total assets

Liabilities and Equity
Current liabilities:

Current portion of long-term debt
Short-term debt
Accounts payable
Taxes accrued
Dividends payable
Derivative instruments valuation – at market
Other
Current liabilities held for sale and related to discontinued operations

Total current liabilities

Deferred credits and other liabilities:

Deferred income taxes
Deferred investment tax credits
Regulatory liabilities
Derivative instruments valuation – at market
Asset retirement obligations
Customer advances
Minimum pension liability
Benefit obligations and other
Noncurrent liabilities held for sale and related to discontinued operations

Total deferred credits and other liabilities

Minority interest in subsidiaries
Commitments and contingencies (see Note 14)
Capitalization (see Statements of Capitalization):

Long-term debt
Preferred stockholders’ equity
Common stockholders’ equity
Total liabilities and equity

See Notes to Consolidated Financial Statements.

Dec. 31

2005

2004

$

72,196
1,011,569
614,016
159,560
64,987
310,610
395,070
213,138
99,904
200,811
3,141,861

$

23,361
761,264
435,431
161,323
64,265
214,964
264,628
129,218
149,538
367,248
2,571,240

18,870,516
2,779,043
1,518,266
783,490
23,951,315
(9,357,414)
102,409
14,696,310

18,236,957
2,617,552
1,476,553
721,335
23,052,397
(9,050,636)
74,308
14,076,069

1,145,659
963,403
451,937
683,649
164,212
401,285
3,810,145
$21,648,316

1,023,481
850,636
424,786
642,873
175,174
540,584
3,657,534
$20,304,843

$

835,495
746,120
1,187,489
235,056
87,788
191,414
345,807
43,657
3,672,826

2,191,794
131,400
1,710,820
499,390
1,292,006
310,092
88,280
343,201
6,936
6,573,919
3,547

$

223,655
312,300
903,609
216,439
83,405
135,098
348,557
112,931
2,335,994

2,065,665
143,028
1,630,545
450,883
1,091,089
303,928
62,669
327,662
89,242
6,164,711
3,220

5,897,789
104,980
5,395,255
$21,648,316

6,493,020
104,980
5,202,918
$20,304,843

XCEL ENERGY 2005 ANNUAL REPORT 43

C O N S O L I D A T E D S T A T E M E N T S O F C O M M O N S T O C K H O L D E R S ’ E Q U I T Y A N D C O M P R E H E N S I V E I N C O M E

Common Stock Issued

Shares

Par Value

Capital in Excess 
of Par Value

398,714 $ 996,785

$4,038,151

Retained Accumulated Other
Earnings
(Deficit)

Total
Comprehensive Stockholders’
Equity

Income (Loss)

$(100,942)
622,392

$(269,010)

182,829
9,710

(14,005)
340

$ (90,136)

(3)
(7,935)

(8,024)
164

$(105,934)

(17,271)

(8,919)
63

$4,664,984
622,392
182,829
9,710

(14,005)
340
801,266

(3,901)
(299,127)
3,218
$5,166,440
355,961
(3)
(7,935)

(8,024)
164
340,163

(4,241)
(323,742)
56,321
(32,023)
$5,202,918
512,972
(17,271)

(8,919)
63
486,845

(4,241)
(343,234)
52,967
$5,395,255

251

627
398,965 $ 997,412

(720)
(149,521)
2,591
$3,890,501

(3,181)
(149,606)

$ 368,663
355,961

3,297
(1,800)

8,243
(4,500)
400,462 $1,001,155

48,078
(27,523)
$3,911,056

(4,241)
(323,742)

$ 396,641
512,972

(4,241)
(343,234)

2,925

7,313
403,387 $1,008,468

45,654
$3,956,710

$ 562,138

$(132,061)

(Thousands)

Balance at Dec. 31, 2002
Net income
Currency translation adjustments
Minimum pension liability
Net derivative instrument fair value changes 

during the period (see Note 12)
Unrealized gain – marketable securities
Comprehensive income for 2003
Dividends declared:

Cumulative preferred stock
Common stock

Issuances of common stock
Balance at Dec. 31, 2003
Net income
Currency translation adjustments
Minimum pension liability
Net derivative instrument fair value changes 

during the period (see Note 12)
Unrealized gain – marketable securities
Comprehensive income for 2004
Dividends declared:

Cumulative preferred stock
Common stock

Issuances of common stock
Purchases for restricted stock issuance
Balance at Dec. 31, 2004
Net income
Minimum pension liability
Net derivative instrument fair value changes 

during the period (see Note 12)
Unrealized gain – marketable securities
Comprehensive income for 2005
Dividends declared:

Cumulative preferred stock
Common stock

Issuances of common stock
Balance at Dec. 31, 2005

See Notes to Consolidated Financial Statements.

44 XCEL ENERGY 2005 ANNUAL REPORT

C O N S O L I D A T E D S T A T E M E N T S O F C A P I T A L I Z A T I O N

Long-Term Debt (Thousands of dollars)

NSP-Minnesota
First Mortgage Bonds, Series due:

Dec. 1, 2005, 6.125% 
Dec. 1, 2006, 4.1%(a)
Dec. 1, 2006–2008, 4.5%–5% (a)
Aug. 1, 2006, 2.875%
Aug. 1, 2010, 4.75%
Aug. 28, 2012, 8%
March 1, 2019, 8.5% (b)
Sept. 1, 2019, 8.5% (b)
July 1, 2025, 7.125%
March 1, 2028, 6.5%
April 1, 2030, 8.5% (b)
July 15, 2035, 5.25%

Senior Notes, due Aug. 1, 2009, 6.875%
Borrowings under credit facility, due April 2010, 5.05%
Retail Notes, due July 1, 2042, 8%
Other
Unamortized discount – net

Total

Less current maturities

Total NSP-Minnesota long-term debt

PSCo
First Mortgage Bonds, Series due:

Nov. 1, 2005, 6.375% 
June 1, 2006, 7.125%
April 1, 2008, 5.625% (b)
Oct. 1, 2008, 4.375%
June 1, 2012, 5.5% (b)
Oct. 1, 2012, 7.875%
March 1, 2013, 4.875%
April 1, 2014, 5.5%
April 1, 2014, 5.875% (b)
Sept. 1, 2017, 4.375% (b)
Jan. 1, 2019, 5.1% (b)
Jan. 1, 2024, 7.25%

Unsecured Senior A Notes, due July 15, 2009, 6.875%
Secured Medium-Term Notes, due March 5, 2007, 7.11%
Capital lease obligations, 11.2% due in installments through 2028
Unamortized discount

Total

Less current maturities

Total PSCo long-term debt

SPS
Unsecured Senior B Notes, due Nov. 1, 2006, 5.125%
Unsecured Senior A Notes, due March 1, 2009, 6.2%
Unsecured Senior C and D Notes, due Oct. 1, 2033, 6%
Pollution control obligations, securing pollution control revenue bonds, due:

July 1, 2011, 5.2%
July 1, 2016, 3.58% at Dec. 31, 2005, and 2% at Dec. 31, 2004
Sept. 1, 2016, 5.75%

Unamortized discount

Total

Less current maturities

Total SPS long-term debt

See Notes to Consolidated Financial Statements.

Dec. 31

2005

2004

$

–
2,420
7,490
200,000
175,000
450,000
27,900
100,000
250,000
150,000
69,000
250,000
250,000
250,000
185,000
519
(7,278)
2,360,051
204,833
$2,155,218

$

–
125,000
–
300,000
–
600,000
250,000
275,000
–
129,500
48,750
–
200,000
100,000
47,581
(3,524)
2,072,307
126,334
$1,945,973

$

70,000
4,750
9,790
200,000
175,000
450,000
27,900
100,000
250,000
150,000
69,000
–
250,000
–
185,000
367
(7,759)
1,934,048
74,685
$1,859,363

$ 134,500
125,000
18,000
300,000
50,000
600,000
250,000
275,000
61,500
–
48,750
110,000
200,000
100,000
48,935
(5,870)
2,315,815
135,854
$2,179,961

$ 500,000
100,000
100,000

$ 500,000
100,000
100,000

44,500
25,000
57,300
(1,024)
825,776
500,000
$ 325,776

44,500
25,000
57,300
(1,338)
825,462
–
$ 825,462

XCEL ENERGY 2005 ANNUAL REPORT 45

C O N S O L I D A T E D S T A T E M E N T S O F C A P I T A L I Z A T I O N

Long-Term Debt – continued (Thousands of dollars)

NSP-Wisconsin
First Mortgage Bonds, Series due:

Oct. 1, 2018, 5.25%
Dec. 1, 2026, 7.375%

Senior Notes, due Oct. 1, 2008, 7.64%
City of La Crosse Resource Recovery Bond, Series due Nov. 1, 2021, 6% (a)
Fort McCoy System Acquisition, due Oct. 15, 2030, 7%
Unamortized discount

Total

Less current maturities

Total NSP-Wisconsin long-term debt

Other Subsidiaries
Various Eloigne Co. Affordable Housing Project Notes, due 2007–2045, 0%–9.89%
Other

Total

Less current maturities

Total other subsidiaries long-term debt

Xcel Energy Inc.
Unsecured senior notes, Series due:

July 1, 2008, 3.4%
Dec. 1, 2010, 7%

Convertible notes, Series due:

Nov. 21, 2007, 7.5%
Nov. 21, 2008, 7.5%

Borrowings under credit facility, due November 2009, 3.09%
Fair value hedge, carrying value adjustment
Unamortized discount

Total Xcel Energy Inc. debt

Total long-term debt from continuing operations

Long-Term Debt from Discontinued Operations
First Mortgage Bonds – Cheyenne:

Due Jan. 1, 2024, 7.5%
Industrial Development Revenue Bonds, due Sept. 1, 2021–March 1, 2027, 

variable rate, 2.12% at Dec. 31, 2004

Total long-term debt from discontinued operations

Cumulative Preferred Stock – authorized 7,000,000 shares of $100 par value; 

outstanding shares: 2005: 1,049,800; 2004: 1,049,800

$3.60 series, 275,000 shares
$4.08 series, 150,000 shares
$4.10 series, 175,000 shares
$4.11 series, 200,000 shares
$4.16 series, 99,800 shares
$4.56 series, 150,000 shares

Total preferred stockholders’ equity

Common Stockholders’ Equity
Common stock – authorized 1,000,000,000 shares of $2.50 par value; outstanding shares: 

2005: 403,387,159; 2004: 400,461,804

Capital in excess of par value on common stock
Retained earnings
Accumulated other comprehensive income (loss)

Total common stockholders’ equity

(a) Resource recovery financing

(b) Pollution control financing

See Notes to Consolidated Financial Statements.

46 XCEL ENERGY 2005 ANNUAL REPORT

Dec. 31

2005

2004

$ 150,000
65,000
80,000
18,600
828
(919)
313,509
34
$ 313,475

$ 150,000
65,000
80,000
18,600
862
(985)
313,477
34
$ 313,443

$

$

95,692
2,217
97,909
4,294
93,615

$ 110,412
9,830
120,242
13,082
$ 107,160

$ 195,000
600,000

$ 195,000
600,000

230,000
57,500
–
(14,073)
(4,695)
$1,063,732
$ 5,897,789

230,000
57,500
140,000
(8,333)
(6,536)
$ 1,207,631
$6,493,020

$             –

–
$             –

$

$

7,800

17,000
24,800

$

27,500
15,000
17,500
20,000
9,980
15,000
$   104,980

$     27,500
15,000
17,500
20,000
9,980
15,000
$ 104,980

$1,008,468
3,956,710
562,138
(132,061)
$5,395,255

$1,001,155
3,911,056
396,641
(105,934)
$5,202,918

N O T E S T O C O N S O L I D A T E D F I N A N C I A L S T A T E M E N T S

1.  SUMMARY  OF  SIGNIFICANT ACCOUNTING  POLICIES

Business and System of Accounts Xcel Energy’s utility subsidiaries are engaged principally in the generation, purchase, transmission,
distribution and sale of electricity and in the purchase, transportation, distribution and sale of natural gas. Xcel Energy and its subsidiaries
were subject to the regulatory provisions of the PUHCA. The utility subsidiaries are subject to regulation by the FERC and state utility
commissions. All of the utility companies’ accounting records conform to the FERC uniform system of accounts or to systems required
by various state regulatory commissions, which are the same in all material respects.

On Aug. 8, 2005, President Bush signed into law the Energy Act, significantly changing many federal energy statutes. The Energy Act is expected
to have a substantial long-term effect on energy markets, energy investment, and regulation of public utilities and holding company systems by
the FERC, the SEC and the DOE. The FERC was directed by the Energy Act to address many areas previously regulated by other governmental
entities under the statutes and determine whether changes to such previous regulations are warranted. The issues that the FERC has been
required to consider associated with the repeal of the PUHCA include, but are not limited to, the expansion of the FERC authority to review
mergers and sales of public utility companies and the expansion of the FERC authority over the books and records of holding companies and
public utility companies, and the appropriate cost standard for the provision of non-power goods and services by service companies. The FERC
is in various stages of rulemaking on these and other issues. Xcel Energy cannot predict the impact the new rulemakings will have on its
operations or financial results, if any.

Principles of Consolidation  In 2005, Xcel Energy continuing operations included the activity of four utility subsidiaries that serve electric
and natural gas customers in 10 states. These utility subsidiaries are NSP-Minnesota, NSP-Wisconsin, PSCo and SPS. These utilities serve
customers in portions of Colorado, Kansas, Michigan, Minnesota, New Mexico, North Dakota, Oklahoma, South Dakota, Texas and Wisconsin.
Along with WGI, an interstate natural gas pipeline, these companies comprise our continuing regulated utility operations.

Xcel Energy’s nonregulated subsidiaries in continuing operations include Eloigne Co. (investments in rental housing projects that qualify
for low-income housing reported tax credits). Xcel Energy owns the following additional direct subsidiaries, some of which are intermediate
holding companies with additional subsidiaries: Xcel Energy Wholesale Energy Group Inc., Xcel Energy Markets Holdings Inc., Xcel Energy
Ventures Inc., Xcel Energy Retail Holdings Inc., Xcel Energy Communications Group Inc., Xcel Energy WYCO Inc. and Xcel Energy O&M
Services Inc. Xcel Energy and its subsidiaries collectively are referred to as Xcel Energy.

Discontinued utility operations include the activity of Viking, an interstate natural gas pipeline company that was sold in January 2003; BMG,
a regulated natural gas and propane distribution company that was sold in October 2003; and Cheyenne, a regulated electric and natural gas
utility that was sold in January 2005. See Note 2 to the Consolidated Financial Statements for more information on the discontinued operations
of Viking, BMG and Cheyenne.

During 2005, Xcel Energy’s board of directors approved management’s plan to pursue the sale of UE (engineering, construction and design)
and Quixx Corp. (a former subsidiary of UE that partners in cogeneration projects). During 2004, Xcel Energy’s board of directors approved
management’s plan to pursue the sale of Seren (broadband telecommunications services). During 2003, Planergy International, Inc. (energy
management solutions) closed and began selling a majority of its business operations, with final dissolution occurring in 2004. During 2003,
Xcel Energy also divested its ownership interest in NRG, an independent power producer. On May 14, 2003, NRG filed for bankruptcy to
restructure its debt. As a result of the reorganization, Xcel Energy relinquished its ownership interest in NRG. During 2003, the board of
directors of Xcel Energy also approved management’s plan to exit businesses conducted by the nonregulated subsidiaries Xcel Energy
International and e prime. NRG, Xcel Energy International, e prime, Seren, Planergy International, Inc., UE and Quixx Corp. are presented as
components of discontinued operations. See Note 2 to the Consolidated Financial Statements.

In 2004, Xcel Energy began consolidating the financial statements of subsidiaries in which it has a controlling financial interest, pursuant to
the requirements of FASB Interpretation No. 46, as revised (FIN No. 46). Historically, consolidation has been required only for subsidiaries in
which an enterprise has a majority voting interest. As a result, Xcel Energy is required to consolidate a portion of its affordable housing
investments made through Eloigne, which for periods prior to 2004 are accounted for under the equity method. As of Dec. 31, 2005, the
assets of the affordable housing investments consolidated as a result of FIN No. 46, as revised, were approximately $136 million and long-term
liabilities were approximately $75 million, including long-term debt of $72 million. Investments of $51 million, previously reflected as a
component of investments in unconsolidated affiliates, have been consolidated with the entities’ assets initially recorded at their carrying
amounts as of Jan. 1, 2004. The long-term debt is collateralized by the affordable housing projects and is nonrecourse to Xcel Energy.

Xcel Energy uses the equity method of accounting for its investments in partnerships, joint ventures and certain projects for which it does not
have a controlling financial interest. Under this method, a proportionate share of pretax income is recorded as equity earnings from investments
in affiliates. In the consolidation process, all significant intercompany transactions and balances are eliminated. Xcel Energy has investments in
several plants and transmission facilities jointly owned with other utilities. These projects are accounted for on a proportionate consolidation
basis, consistent with industry practice. See Note 7 to the Consolidated Financial Statements.

Revenue Recognition  Revenues related to the sale of energy are generally recorded when service is rendered or energy is delivered to
customers. However, the determination of the energy sales to individual customers is based on the reading of their meter, which occurs on a
systematic basis throughout the month. At the end of each month, amounts of energy delivered to customers since the date of the last meter
reading are estimated and the corresponding unbilled revenue is estimated.

Xcel Energy’s utility subsidiaries have various rate-adjustment mechanisms in place that currently provide for the recovery of certain purchased
natural gas and electric fuel and purchased energy costs. These cost-adjustment tariffs may increase or decrease the level of costs recovered
through base rates and are revised periodically, as prescribed by the appropriate regulatory agencies, for any difference between the total

XCEL ENERGY 2005 ANNUAL REPORT 47

N O T E S T O C O N S O L I D A T E D F I N A N C I A L S T A T E M E N T S

amount collected under the clauses and the recoverable costs incurred. In addition, Xcel Energy presents its revenue net of any excise or
other fiduciary-type taxes or fees. A summary of significant rate-adjustment mechanisms follows:
– NSP-Minnesota’s rates include a cost-of-fuel-and-purchased-energy and a cost-of-gas recovery mechanism allowing dollar-for-dollar recovery

of the respective costs, which are trued-up on a two-month and annual basis, respectively. 

– NSP-Wisconsin’s rates include a cost-of-gas adjustment clause for purchased natural gas, but not for purchased electric energy or electric
fuel. In Wisconsin, requests can be made for recovery of those electric costs prospectively through the rate review process, which normally
occurs every two years, and an interim fuel-cost hearing process. 

– PSCo generally recovers all prudently incurred electric fuel and purchased energy costs through an electric-commodity adjustment

clause. This fuel mechanism also has in place a sharing among customers and shareholders of certain fuel and energy costs, with an
$11.25 million maximum on any cost sharing over or under an allowed electric-commodity adjustment formula rate, and a sharing among
shareholders and customers of certain gains and losses on trading margins.

– In Texas, SPS may request periodic adjustments to provide electric fuel and purchased energy cost recovery. In New Mexico, SPS has a

monthly fuel and purchased power cost-recovery factor.

– In Colorado, PSCo operates under an electric performance-based regulatory plan, which provides for an annual earnings test in which earnings
above the authorized return on equity are refunded to customers. NSP-Minnesota and PSCo operate under various service standards in
Minnesota and Colorado, respectively, which could require customer refunds if certain criteria are not met. NSP-Minnesota and PSCo’s
rates in Minnesota and Colorado, respectively, also include monthly adjustments for the recovery of conservation and energy-management
program costs, which are reviewed annually.

– NSP-Minnesota, NSP-Wisconsin, PSCo and SPS sell firm power and energy in wholesale markets, which are regulated by the FERC. Certain

of these rates include monthly wholesale fuel cost-recovery mechanisms.

Commodity Trading Operations  All applicable gains and losses related to commodity trading activities, whether or not settled physically,
are shown on a net basis in the Consolidated Statements of Operations.

Xcel Energy’s commodity trading operations are conducted by NSP-Minnesota, PSCo and SPS. Commodity trading activities are not associated
with energy produced from Xcel Energy’s generation assets or energy and capacity purchased to serve native load. Commodity trading contracts
are recorded at fair market value in accordance with SFAS No. 133, as amended. In addition, commodity trading results include the impact
of any margin-sharing mechanisms.

Derivative Financial Instruments  Xcel Energy and its subsidiaries utilize a variety of derivatives, including commodity forwards, futures
and options, index or fixed price swaps and basis swaps, to mitigate market risk and to enhance its operations. For further discussion of
Xcel Energy’s risk management and derivative activities, see Note 12 to the Consolidated Financial Statements.

Property, Plant and Equipment and Depreciation  Property, plant and equipment is stated at original cost. The cost of plant includes
direct labor and materials, contracted work, overhead costs and applicable interest expense. The cost of plant retired is charged to accumulated
depreciation and amortization. Removal costs associated with regulatory obligations are recorded as regulatory liabilities. Significant additions
or improvements extending asset lives are capitalized, while repairs and maintenance are charged to expense as incurred. Maintenance and
replacement of items determined to be less than units of property are charged to operating expenses. Property, plant and equipment also
includes costs associated with property held for future use.

Xcel Energy determines the depreciation of its plant by using the straight-line method, which spreads the original cost equally over the plant’s
useful life. Depreciation expense, expressed as a percentage of average depreciable property, was approximately 3.2 percent, 3.1 percent and
3.0 percent for the years ended Dec. 31, 2005, 2004 and 2003, respectively.

Allowance for Funds Used During Construction (AFDC)  AFDC represents the cost of capital used to finance utility construction activity.
AFDC is computed by applying a composite pretax rate to qualified construction work in progress. The amount of AFDC capitalized as a utility
construction cost is credited to other nonoperating income (for equity capital) and interest charges (for debt capital). AFDC amounts capitalized
are included in Xcel Energy’s rate base for establishing utility service rates. In addition to construction-related amounts, AFDC also is recorded
to reflect returns on capital used to finance conservation programs in Minnesota.

Decommissioning Xcel Energy accounts for the future cost of decommissioning, or retirement, of its nuclear generating plants through
annual depreciation accruals using an annuity approach designed to provide for full rate recovery of the future decommissioning costs. The
decommissioning calculation covers all expenses, including decontamination and removal of radioactive material, and extends over the estimated
lives of the plants. The calculation assumes that NSP-Minnesota and NSP-Wisconsin will recover those costs through rates. The fair value of
external nuclear decommissioning fund investments are estimated based on quoted market prices for those or similar investments. Unrealized
gains or losses are deferred as regulatory assets or liabilities. For more information on nuclear decommissioning, see Note 15 to the Consolidated
Financial Statements.

PSCo also previously operated a nuclear generating plant, which has been decommissioned and was repowered using natural gas. PSCo’s
costs associated with decommissioning were deferred and amortized consistent with regulatory recovery. These costs were fully recovered
through rates in July 2005.

Nuclear Fuel Expense  Nuclear fuel expense, which is recorded as the nuclear generating plants use fuel, includes the cost of fuel used in
the current period, as well as future disposal costs of spent nuclear fuel. In addition, nuclear fuel expense includes fees assessed by the DOE
for NSP-Minnesota’s portion of the cost of decommissioning the DOE’s fuel-enrichment facility.

48 XCEL ENERGY 2005 ANNUAL REPORT

N O T E S T O C O N S O L I D A T E D F I N A N C I A L S T A T E M E N T S

Environmental Costs  Environmental costs are recorded when it is probable Xcel Energy is liable for the costs and the liability can reasonably
be estimated. Costs may be deferred as a regulatory asset if it is probable that the costs will be recovered from customers in future rates.
Otherwise, the costs are expensed. If an environmental expense is related to facilities currently in use, such as emission-control equipment,
the cost is capitalized and depreciated over the life of the plant, assuming the costs are recoverable in future rates or future cash flow.

Estimated remediation costs, excluding inflationary increases, are recorded. The estimates are based on experience, an assessment of the
current situation and the technology currently available for use in the remediation. The recorded costs are regularly adjusted as estimates are
revised and as remediation proceeds. If several designated responsible parties exist, only Xcel Energy’s expected share of the cost is estimated
and recorded. Any future costs of restoring sites where operation may extend indefinitely are treated as a capitalized cost of plant retirement.
The depreciation expense levels recoverable in rates include a provision for removal expenses, which may include final remediation costs.
Removal costs recovered in rates are classified as a regulatory liability.

Legal Costs  Litigation accruals are recorded when it is probable Xcel Energy is liable for the costs and the liability can be reasonably
estimated. Legal accruals are recorded net of insurance recovery. Legal costs related to settlements are not accrued, but expensed as incurred.

Income Taxes  Xcel Energy and its domestic subsidiaries file consolidated federal income tax returns. Xcel Energy and its domestic subsidiaries
file combined and separate state income tax returns. NRG and one or more of its domestic subsidiaries were included in some state returns,
but not all, of these combined returns in 2003. NRG has not been consolidated or combined in any of Xcel Energy’s income tax returns
since 2003.

Federal income taxes paid by Xcel Energy, as parent of the Xcel Energy consolidated group, are allocated to the Xcel Energy subsidiaries
based on separate company computations of tax. A similar allocation is made for state income taxes paid by Xcel Energy in connection with
combined state filings. In accordance with the PUHCA requirements, the holding company also allocates its own net income tax benefits to
its direct subsidiaries based on the positive tax liability of each company.

Xcel Energy defers income taxes for all temporary differences between pretax financial and taxable income, and between the book and tax
bases of assets and liabilities. Xcel Energy uses the tax rates that are scheduled to be in effect when the temporary differences are expected
to turn around, or reverse.

Due to the effects of past regulatory practices, when deferred taxes were not required to be recorded, the reversal of some temporary differences
are accounted for as current income tax expense. Investment tax credits are deferred and their benefits amortized over the estimated lives
of the related property. Utility rate regulation also has created certain regulatory assets and liabilities related to income taxes, which are
summarized in Note 16 to the Consolidated Financial Statements.

Use of Estimates In recording transactions and balances resulting from business operations, Xcel Energy uses estimates based on the
best information available. Estimates are used for such items as plant depreciable lives, asset retirement obligations, decommissioning, tax
provisions, uncollectible amounts, environmental costs, unbilled revenues, jurisdictional fuel and energy cost allocations and actuarially
determined benefit costs. The recorded estimates are revised when better information becomes available or when actual amounts can
be determined. Those revisions can affect operating results. The depreciable lives of certain plant assets are reviewed or revised annually,
if appropriate.

Cash and Cash Equivalents  Xcel Energy considers investments in certain debt instruments with a remaining maturity of three months or
less at the time of purchase to be cash equivalents. Those debt instruments are primarily commercial paper and money market funds.

Inventory  All inventory is recorded at average cost.

Regulatory Accounting  Our regulated utility subsidiaries account for certain income and expense items in accordance with SFAS No. 71 –
“Accounting for the Effects of Certain Types of Regulation.” Under SFAS No. 71:
– Certain costs, which would otherwise be charged to expense, are deferred as regulatory assets based on the expected ability to recover

them in future rates; and

– Certain credits, which would otherwise be reflected as income, are deferred as regulatory liabilities based on the expectation they will be

returned to customers in future rates.

Estimates of recovering deferred costs and returning deferred credits are based on specific ratemaking decisions or precedent for each item.
Regulatory assets and liabilities are amortized consistent with the period of expected regulatory treatment. See more discussion of regulatory
assets and liabilities at Note 16 to the Consolidated Financial Statements.

Stock-Based Employee Compensation  Xcel Energy has several stock-based compensation plans. Those plans are accounted for using the
intrinsic-value method. Compensation expense is not recorded for stock options because there is no difference between the market price and
the purchase price at grant date. Compensation expense is recorded for restricted stock and stock units awarded to certain employees, which
are held until the restriction lapses or the stock is forfeited. For more information on stock compensation impacts, see Note 9 to the
Consolidated Financial Statements.

Deferred Financing Costs  Other assets also included deferred financing costs, net of amortization, of approximately $42 million and
$44 million at Dec. 31, 2005 and 2004, respectively. Xcel Energy is amortizing these financing costs over the remaining maturity periods of
the related debt.

XCEL ENERGY 2005 ANNUAL REPORT 49

N O T E S T O C O N S O L I D A T E D F I N A N C I A L S T A T E M E N T S

Accounts Receivable and Allowance for Uncollectibles  Accounts receivable are stated at the actual billed amount net of write-offs and
allowance for uncollectibles. Xcel Energy establishes an allowance for uncollectibles based on a reserve policy that reflects its expected
exposure to the credit risk of customers.

Reclassifications  Certain items in the statements of operations, balance sheets and the statements of cash flows have been reclassified
from prior-period presentation to conform to the 2005 presentation. These reclassifications had no effect on net income or earnings per
share. The reclassifications were primarily related to the presentation of UE as discontinued operations following the announcement of its
sale in March 2005, as discussed later. In addition, fees collected from customers on behalf of governmental agencies were reclassified to be
presented net of the related payments made to the agencies.

2.  DISCONTINUED  OPERATIONS

Xcel Energy classified and accounted for certain assets as held for sale at Dec. 31, 2005 and 2004. Assets held for sale are valued on an
asset-by-asset basis at the lower of carrying amount or fair value less costs to sell. In applying those provisions, management considered
cash flow analyses, bids and offers related to those assets and businesses. Assets held for sale are not depreciated.

Results of operations for divested businesses and the results of businesses held for sale are reported for all periods presented on a net basis
as discontinued operations. In addition, the assets and liabilities of the businesses divested and held for sale in 2005 and 2004 have been
reclassified to assets and liabilities held for sale in the accompanying Balance Sheet.

R EG U L AT E D U T I L I T Y S EG M E NT

During January 2004, Xcel Energy reached an agreement to sell its regulated electric and natural gas subsidiary, Cheyenne. Black Hills Corp.
purchased all the common stock of Cheyenne, including the assumption of outstanding debt of approximately $25 million, for approximately
$90 million, plus a working capital adjustment finalized in 2005. The sale was completed on Jan. 21, 2005, and resulted in an after-tax loss
of approximately $13 million, or 3 cents per share, which was accrued at Dec. 31, 2004.

During 2003, Xcel Energy completed the sale of two subsidiaries in its regulated natural gas utility segment: Viking and BMG. After-tax disposal
gains of $23.3 million, or 6 cents per share, were recorded for the natural gas utility segment, primarily related to the sale of Viking.

N R G S EG M E NT

Change in Accounting for NRG in 2003  Prior to NRG’s bankruptcy filing in May 2003, Xcel Energy accounted for NRG as a consolidated
subsidiary. However, as a result of NRG’s bankruptcy filing, Xcel Energy no longer had the ability to control the operations of NRG. Accordingly,
effective as of the bankruptcy filing date, Xcel Energy ceased the consolidation of NRG and began accounting for its investment in NRG using
the equity method in accordance with Accounting Principles Board Opinion No. 18 – “The Equity Method of Accounting for Investments in
Common Stock.” After changing to the equity method, Xcel Energy was limited in the amount of NRG’s losses subsequent to the bankruptcy
date that it was required to record. In accordance with these limitations under the equity method, Xcel Energy stopped recognizing equity in
the losses of NRG subsequent to the quarter ended June 30, 2003. These limitations provided for loss recognition by Xcel Energy until its
investment in NRG was written off to zero, with further loss recognition to continue if its financial commitments to NRG existed beyond
amounts already invested.

Prior to NRG entering bankruptcy, Xcel Energy recorded more losses than the limitations provided for as of June 30, 2003. Upon Xcel Energy’s
divestiture of its interest in NRG in December 2003, the NRG losses recorded in excess of Xcel Energy’s investment in and financial commitment
to NRG were reversed. This resulted in an adjustment of the total NRG losses recorded for the year 2003 to $251 million. Xcel Energy’s share
of NRG’s results for all 2003 periods is reported in a single line item, Equity in Losses of NRG, as a component of discontinued operations.
NRG’s 2003 results do reflect some effects of asset impairments, as discussed below.

NRG Asset Impairments  In 2002, NRG experienced credit-rating downgrades, defaults under numerous credit agreements, increased
collateral requirements and reduced liquidity. These events resulted in impairment reviews of a number of NRG assets. NRG completed an
analysis of the recoverability of the asset-carrying values of its projects each period, factoring in the probability weighting of different courses
of action available to NRG, given its financial position and liquidity constraints at the time of each analysis. This approach was applied consistently
to asset groups with similar uncertainties and cash flow streams. As a result, NRG determined that many of its construction projects and its
operational projects became impaired during 2002 and 2003 and required being written down to fair market value. In applying those provisions,
NRG management considered cash flow analyses, bids and offers related to those projects.

N O N R EG U L AT E D S U B S I D I A R I E S – A L L OT H E R S EG M E NT
Utility Engineering In March 2005, Xcel Energy agreed to sell its nonregulated subsidiary Utility Engineering Corp. (UE), to Zachry Group,
Inc. In April 2005, Zachry acquired all of the outstanding shares of UE. Xcel Energy recorded an insignificant loss in the first quarter of 2005
as a result of the transaction. In August 2005, Xcel Energy’s board of directors approved management’s plan to pursue the sale of Quixx
Corp., a former subsidiary of UE that partners in cogeneration projects, and was not included in the sale of UE to Zachry.

Seren  On Sept. 27, 2004, Xcel Energy’s board of directors approved management’s plan to pursue the sale of Seren Innovations, Inc., a
wholly owned broadband subsidiary.

On May 25, 2005, Xcel Energy reached an agreement to sell Seren’s California assets to WaveDivision Holdings, LLC, which was completed
in November 2005. In July 2005, Xcel Energy reached an agreement to sell Seren’s Minnesota assets to Charter Communications, which was
completed in January 2006. An estimated after-tax impairment charge, including disposition costs, of $143 million, or 34 cents per share,

50 XCEL ENERGY 2005 ANNUAL REPORT

N O T E S T O C O N S O L I D A T E D F I N A N C I A L S T A T E M E N T S

was recorded in 2004. Based on the sales agreements entered into in 2005, the estimate was adjusted in 2005 to reflect a total asset impairment
of $140 million.

Xcel Energy International and e prime In December 2003, the board of directors of Xcel Energy approved management’s plan to exit the
businesses conducted by its nonregulated subsidiaries Xcel Energy International and e prime. The exit of all business conducted by e prime
was completed in 2004.

Results of discontinued nonregulated operations in 2004 include the impact of the sale of the Argentina subsidiaries of Xcel Energy International.
The sales took place in a series of three transactions, with a total sales price of approximately $31 million. In addition to the sales price, Xcel
Energy also received approximately $21 million at the closing of one transaction as redemption of its capital investment. The sales resulted
in a gain of approximately $8 million, including the realization of approximately $7 million of income tax benefits realizable upon the sale of
the Xcel Energy International assets.

Results of discontinued nonregulated operations in 2003, other than NRG, include an after-tax loss expected on the disposal of all Xcel Energy
International assets of $59 million, based on the estimated fair value of such assets. The fair value represents a market bid or appraisal received
that is believed to best reflect the assets’ fair value at Dec. 31, 2003. Xcel Energy’s remaining investment in Xcel Energy International at
Dec. 31, 2003, was approximately $39 million. Losses from discontinued nonregulated operations in 2003 also include a charge of $16 million
for costs of settling a Commodity Futures Trading Commission trading investigation of e prime.

Tax Benefits Related to Investment in NRG  With NRG’s emergence from bankruptcy in December 2003, Xcel Energy divested its ownership
interest in NRG. Xcel Energy has recognized tax benefits related to the divestiture. These tax benefits, since related to Xcel Energy’s investment
in discontinued NRG operations, also are reported as discontinued operations. 

During 2002, Xcel Energy recognized an initial estimate of the expected tax benefits of $706 million. Based on the results of a 2003 preliminary
tax basis study of NRG, Xcel Energy recorded $404 million of additional tax benefits in 2003. In 2004, the NRG basis study was updated and
previously recognized tax benefits were reduced by $13 million. In 2005, a $17 million tax benefit was recorded to reflect the final federal income
tax resolution of Xcel Energy’s divested interest in NRG.

XCEL ENERGY 2005 ANNUAL REPORT 51

N O T E S T O C O N S O L I D A T E D F I N A N C I A L S T A T E M E N T S

S U M M A R I Z E D F I N A N C I A L R E S U LT S O F D I S C O NT I N U E D O P E R AT I O N S

(Thousands of dollars)

2005
Operating revenue
Operating and other expenses
Special charges and impairments

Pretax income (loss) from operations of discontinued components

Income tax expense (benefit) 

Income from operations of discontinued components

Estimated pretax gain on disposal of discontinued components
Income tax benefit
Gain on disposal of discontinued components
Net income from discontinued operations

2004
Operating revenue
Operating and other expenses
Special charges and impairments

Pretax loss from operations of discontinued components

Income tax expense (benefit) 

Loss from operations of discontinued components

Estimated pretax gain on disposal of discontinued components
Income tax benefit
Gain on disposal of discontinued components
Net loss from discontinued operations

2003
Operating revenue 
Operating and other expenses
Special charges and impairments (including net disposal losses) 
Equity in NRG losses

Pretax income (loss) from operations of discontinued components

Income tax expense (benefit) 

Income (loss) from operations of discontinued components

Estimated pretax gain on disposal of discontinued components
Income tax expense
Gain on disposal of discontinued components

Net income (loss) from discontinued operations

Utility
Segment

NRG
Segment

All Other
Segment

$ 6,579
6,131
–
448
268
180

–
–
–
180

$

$72,232
68,305
6,574
(2,647)
6,388
(9,035)

–
–
–
$ (9,035)

$51,723
46,539
–
–
5,184
1,667
3,517

40,072
16,780
23,292
$26,809

$

$

$

$

–
–
–
–
–
–

–
–
–
–

–
–
–
–
–
–

–
–
–
–

$

–
–
(1,664)
253,043
(251,379)
–
(251,379)

–
–
–
$(251,379)

$ 63,206
68,669
–
(5,463)
(19,217)
13,754

–
–
–
$ 13,754

$ 179,890
194,605
228,439
(243,154)
(78,021)
(165,133)

961
6,904
7,865
$(157,268)

$ 298,550
330,538
58,700
–
(90,688)
(414,826)
324,138

–
–
–
$ 324,138

Total

$ 69,785
74,800
–
(5,015)
(18,949)
13,934

–
–
–
$ 13,934

$ 252,122
262,910
235,013
(245,801)
(71,633)
(174,168)

961
6,904
7,865
$(166,303)

$ 350,273
377,077
57,036
253,043
(336,883)
(413,159)
76,276

40,072
16,780
23,292
$ 99,568

The major classes of assets and liabilities held for sale and related to discontinued operations as of Dec. 31 are as follows:

(Thousands of dollars)

Cash
Restricted cash
Trade receivables – net
Deferred income tax benefits
Other current assets

Current assets

Property, plant and equipment – net
Deferred income tax benefits
Other noncurrent assets

Noncurrent assets
Accounts payable – trade
Other current liabilities

Current liabilities

Long-term debt
Other noncurrent liabilities

Noncurrent liabilities

52 XCEL ENERGY 2005 ANNUAL REPORT

2005

2004

$ 12,658
–
6,101
157,812
24,240
200,811
29,845
352,171
19,269
401,285
7,657
36,000
43,657
–
6,936
$ 6,936

$ 33,228
15,000
24,364
234,305
60,351
367,248
155,428
338,863
46,293
540,584
29,451
83,480
112,931
24,800
64,442
$ 89,242

N O T E S T O C O N S O L I D A T E D F I N A N C I A L S T A T E M E N T S

3.  SHORT-TERM  BORROWINGS

Notes Payable and Commercial Paper  During 2005, Xcel Energy, PSCo and SPS resumed short-term borrowings in the commercial
paper market. Information regarding notes payable and commercial paper for the years ended Dec. 31, 2005 and 2004, is presented in the
following table:

(Millions of dollars, except interest rates)

Notes payable to banks
Commercial paper
Total short-term debt
Weighted average interest rate at year-end

2005

$

–
746.1
$746.1

2004

$312.3
–
$312.3

4.46%

4.15%

Credit Facilities On Dec. 1, 2005, PSCo entered into an agreement with Wells Fargo Bank, N.A. to provide PSCo a committed five-month,
$50 million seasonal revolving credit facility. The interest rate is based on either Wells Fargo Bank’s prime rate or the applicable London Interbank
Offered Rate (LIBOR), plus a borrowing margin as determined by PSCo’s credit worthiness. PSCo entered into this agreement to ensure adequate
liquidity for rising natural gas prices during the winter months. As of Dec. 31, 2005, PSCo had not borrowed against this facility. 

In addition, on Dec. 12, 2005, PSCo entered into a $25 million good-until-canceled uncommitted credit line with KBC Bank to provide additional
short-term seasonal liquidity as a result of higher natural gas prices. As of Dec. 31, 2005, PSCo had not utilized this credit line.

4.  LONG-TERM  DEBT

Credit Facilities  At Dec. 31, 2005, Xcel Energy and its utility subsidiaries had the following committed credit facilities available:

(Millions of dollars)

NSP-Minnesota
PSCo
SPS
Xcel Energy – holding company

Total

Credit
Facility

$ 450 
$ 600 
$ 250 
$ 700 
$2,000

Available*

Term

Maturity

$190.3 
$258.9 
$164.4 
$356.0 
$969.6

Five year
Five year
Five year
Five year

April 2010
April 2010
April 2010
November 2009

* Net of credit facility borrowings, issued and outstanding letters of credit and commercial paper borrowings.

The lines of credit provide short-term financing in the form of notes payable to banks, letters of credit and backup support for commercial
paper borrowings. Each credit facility has one financial covenant requiring that the debt-to-total-capitalization ratio of each entity be less than
or equal to 65 percent with which all were in compliance. The interest rates under these lines of credit are based on either the agent bank’s
prime rate or the applicable LIBOR, plus a borrowing margin as determined by each entity’s credit worthiness.

Xcel Energy has a $700 million, five-year senior unsecured revolving credit facility that matures in November 2009. Xcel Energy has the
right to request an extension of the final maturity date by one year. The maturity extension is subject to majority bank group approval. As
of Dec. 31, 2005, Xcel Energy had no direct borrowings on this line of credit; however, the credit facility was used to provide backup for
$325.5 million of commercial paper outstanding and $18.5 million of letters of credit. As discussed in Note 13 to the Consolidated Financial
Statements, $35.2 million of letters of credit were outstanding at Dec. 31, 2005, of which $18.5 million were supported by the Xcel Energy
credit facility and are included in the above table.

Xcel Energy’s 2007 and 2008 series convertible senior notes are convertible into shares of Xcel Energy common stock at a conversion price
of $12.33 per share. Conversion is at the option of the holder at any time prior to maturity. In addition, Xcel Energy must make additional
payments of interest, referred to as protection payments, on the notes in an amount equal to any portion of regular quarterly per share
dividends on common stock that exceeds $0.1875 that would have been payable to the holders of the notes if such holders had converted
their notes on the record date for such dividend. On May 25, 2005, the board of directors of Xcel Energy voted to raise the quarterly dividend
on its common stock from $0.2075 to $0.2150. Consequently, as of Dec. 31, 2005, a total of $2.4 million in additional interest expense has
been recorded.

All property of NSP-Minnesota and NSP-Wisconsin and the electric property of PSCo are subject to the liens of their first mortgage indentures. In
addition, certain SPS payments under its pollution-control obligations are pledged to secure obligations of the Red River Authority of Texas. 

Maturities of long-term debt are:

2006
2007
2008
2009
2010

$835.5 million
$338.9 million
$632.4 million
$557.8 million
$1,031.6 million

XCEL ENERGY 2005 ANNUAL REPORT 53

N O T E S T O C O N S O L I D A T E D F I N A N C I A L S T A T E M E N T S

5.  PREFERRED  STOCK

Xcel Energy has authorized 7,000,000 shares of preferred stock with a $100 par value. At Dec. 31, 2005, Xcel Energy had six series of preferred
stock outstanding, redeemable at its option at prices ranging from $102.00 to $103.75 per share plus accrued dividends. Under the PUHCA,
unless there was an order from the SEC, a holding company or any subsidiary could declare and pay dividends only out of retained earnings.
With the repeal of the PUHCA, restrictions on the ability of holding companies or utility subsidiaries to declare dividends set out in that
statute no longer apply.

The holders of the $3.60 series preferred stock are entitled to three votes per each share held. The holders of the other series of preferred
stock are entitled to one vote per share. In the event dividends payable on the preferred stock of any series outstanding is in arrears in an
amount equal to four quarterly dividends, the holders of preferred stocks, voting as a class, are entitled to elect the smallest number of
directors necessary to constitute a majority of the board of directors. The holders of common stock, voting as a class, are entitled to elect the
remaining directors.

The charters of some of Xcel Energy’s subsidiaries also authorize the issuance of preferred stock. However, at Dec. 31, 2005, there are no
preferred shares outstanding.

SPS
PSCo

Preferred Shares
Authorized

10,000,000
10,000,000

Par Value

$1.00
$0.01

Preferred Shares
Outstanding

None
None

6.  MANDATORILY  REDEEMABLE  PREFERRED  SECURITIES  OF  SUBSIDIARY TRUSTS

NSP Financing I, a wholly owned, special-purpose subsidiary trust of NSP-Minnesota, had $200 million of 7.875-percent trust preferred securities
issued and outstanding that were originally scheduled to mature in 2037. The preferred securities were redeemable at NSP Financing I’s
option at $25 per share, beginning in 2002. On July 31, 2003, NSP-Minnesota redeemed the $200 million of trust preferred securities. A certificate
of cancellation was filed to dissolve NSP Financing I on Sept. 15, 2003.

PSCo Capital Trust I, a wholly owned, special-purpose subsidiary trust of PSCo, had $194 million of 7.60-percent trust preferred securities issued
and outstanding that were originally scheduled to mature in 2038. The securities were redeemable at the option of PSCo after May 2003, at
100 percent of the principal amount outstanding plus accrued interest. On June 30, 2003, PSCo redeemed the $194 million of trust preferred
securities. A certificate of cancellation was filed to dissolve PSCo Capital Trust I on Dec. 29, 2003.

Southwestern Public Service Capital I, a wholly owned, special-purpose subsidiary trust of SPS, had $100 million of 7.85-percent trust preferred
securities issued and outstanding that were originally scheduled to mature in 2036. The securities were redeemable at the option of SPS after
October 2001, at 100 percent of the principal amount plus accrued interest. On Oct. 15, 2003, SPS redeemed the $100 million of trust preferred
securities. A certificate of cancellation was filed to dissolve SPS Capital I on Jan. 5, 2004.

Distributions paid to preferred security holders were reflected as a financing cost in the Consolidated Statements of Operations, along with
interest charges.

54 XCEL ENERGY 2005 ANNUAL REPORT

N O T E S T O C O N S O L I D A T E D F I N A N C I A L S T A T E M E N T S

7.  GENERATING  PLANT  OWNERSHIP AND  OPERATION

Joint Plant Ownership  Following are the investments by Xcel Energy’s subsidiaries in jointly owned plants and the related ownership
percentages as of Dec. 31, 2005:

(Thousands of dollars)

NSP-Minnesota
Sherco Unit 3
Sherco Common Facilities Units 1, 2 and 3
Transmission facilities, including substations

Total NSP-Minnesota

PSCo
Hayden Unit 1
Hayden Unit 2
Hayden Common Facilities
Craig Units 1 and 2
Craig Common Facilities Units 1, 2 and 3
Comanche Unit 3 
Transmission and other facilities, including substations

Total PSCo

Plant in Accumulated
Service Depreciation

Construction
Work in

Progress Ownership %

$500,266
102,988
4,832
$608,086

$ 84,357
80,034
28,244
52,848
32,384
–
114,788
$392,655

$282,145
53,552
1,878
$ 337,575

$ 43,579
45,637
5,538
26,318
9,673
–
42,412
$173,157

$

665
1,196
–
$ 1,861

$

635
1,006
–
24
–
54,960
13
$56,638

59.0
65.6
59.0

75.5
37.4
53.1
9.7
6.5–9.7
74.7
11.6–68.1

NSP-Minnesota is part owner of Sherco 3, an 860-megawatt, coal-fueled electric generating unit. NSP-Minnesota is the operating agent under
the joint ownership agreement. NSP-Minnesota’s share of operating expenses and construction expenditures are included in the applicable
utility accounts. PSCo’s current operational assets include approximately 320 megawatts of jointly owned generating capacity. PSCo’s share of
operating expenses and construction expenditures are included in the applicable utility accounts. PSCo began major construction on a new
jointly owned 750-megawatt, coal-fired unit in Pueblo, Colo. in January 2006. Major construction on the new unit, Comanche 3, is expected to
be completed in 2010. PSCo is the operating agent under the joint ownership agreement. Each of the respective owners is responsible for the
issuance of its own securities to finance its portion of the construction costs.

Nuclear Plant Operation The Nuclear Management Company (NMC) is an operating company that manages the operations, maintenance
and physical security of several nuclear generating units on five sites, including three units / two sites owned by NSP-Minnesota. NSP-Minnesota
continues to own the plants, controls all energy produced by the plants and retains responsibility for nuclear property and liability insurance
and decommissioning costs. The Wisconsin Public Service Corporation is no longer participating in NMC after the sale of its Kewaunee nuclear
power plant in July 2005. In January 2006, Florida Power & Light purchased the majority interest in the Duane Arnold plant from Alliant Energy
and announced it will assume management of the plant. As a result, NSP-Minnesota’s ownership interest in NMC has increased to 25 percent.
In accordance with the Nuclear Power Plant Operating Services Agreement, NSP-Minnesota also pays its proportionate share of the operating
expenses and capital improvement costs incurred by NMC. NSP-Minnesota paid NMC $257.1 million in 2005, $314.7 million in 2004 and
$227.0 million in 2003.

8.  INCOME TAXES

Xcel Energy’s federal net operating loss and tax credit carry forwards are estimated to be $1.4 billion and $107.6 million, respectively. A portion of
the net operating loss in the amount of $1.1 billion and a portion of the tax credit carry forwards in the amount of $28.8 million are accounted
for in discontinued operations. The carry forward periods expire in 2023 and 2024. Xcel Energy also has net operating loss and tax credit
carry forwards in some states. The state carry forward periods expire between 2014 and 2024. A valuation allowance was recorded against
deferred tax assets for capital loss carry forwards related to discontinued operations. The valuation allowance was $44 million as of Dec. 31, 2005,
and $46 million as of Dec. 31, 2004. The net reduction in valuation allowance of $2 million was due to capital gains. The capital loss carry forward
period expires in 2009.

Total income tax expense from continuing operations differs from the amount computed by applying the statutory federal income tax rate to
income before income tax expense. The following is a table reconciling such differences for the years ending Dec. 31:

Federal statutory rate
Increases (decreases) in tax from:

State income taxes, net of federal income tax benefit
Life insurance policies
Tax credits recognized
Regulatory differences – utility plant items
Resolution of income tax audits and prior-period adjustments
Other – net

Effective income tax rate from continuing operations

2005

35.0%

2.5
(4.6)
(4.4)
(0.3)
(0.3)
(2.1)
25.8%

2004

35.0%

3.3
(4.0)
(4.4)
(0.1)
(5.3)
(0.8)
23.7%

2003

35.0%

2.3
(3.8)
(3.9)
0.8
(5.1)
(0.7)
24.6%

XCEL ENERGY 2005 ANNUAL REPORT 55

N O T E S T O C O N S O L I D A T E D F I N A N C I A L S T A T E M E N T S

Income taxes comprise the following expense (benefit) items for the years ending Dec. 31:

(Thousands of dollars)

Current federal tax expense
Current state tax expense (benefit)
Current tax credits
Deferred federal tax expense
Deferred state tax expense
Deferred tax credits
Deferred investment tax credits

Total income tax expense from continuing operations

2005

2004

2003

$ (4,122)
(15,733)
(45)
191,900
31,235
(18,077)
(11,619)
$173,539

$ 88,514
32,135
(3,798)
67,716
3,574
(14,017)
(12,189)
$161,935

$ 111,986

(592) 
(3,137)
83,245
3,298
(11,668)
(12,440)
$170,692

The components of Xcel Energy’s net deferred tax liability from continuing operations (current and noncurrent portions) at Dec. 31 were:

(Thousands of dollars)

Deferred tax liabilities:

Differences between book and tax bases of property
Regulatory assets
Employee benefits
Partnership income/loss
Service contracts
Other

Total deferred tax liabilities

Deferred tax assets:

Net operating loss carry forward
Other comprehensive income
Deferred investment tax credits
Tax credit carry forward
Regulatory liabilities
Book reserves and other

Total deferred tax assets

Net deferred tax liability

2005

2004

$2,245,748
257,843
25,711
10,010
8,539
85,810
$2,633,661

$ 119,124
80,356
51,286
86,143
40,835
46,106
$ 423,850
$ 2,209,811

$2,056,951
244,388
33,191
10,310
11,369
31,227
$ 2,387,436

$

88,159
63,469
55,967
51,046
39,415
70,892
$ 368,948
$ 2,018,488

9.  COMMON  STOCK AND  STOCK-BASED  COMPENSATION

Common Stock and Equivalents  Xcel Energy has common stock equivalents consisting of convertible senior notes, restricted stock units
and stock options, as discussed later.

In 2005, 2004 and 2003, Xcel Energy had 13.3 million, 14.3 million and 15.6 million options outstanding, respectively, that were antidilutive
and therefore excluded from the earnings per share calculation. The dilutive impact of common stock equivalents affected earnings per share
as follows for the years ending Dec. 31:

(Shares and dollars in thousands, 
except per share amounts)

Per Share
Income Shares Amount

Per Share
Income Shares Amount

Per Share
Income Shares Amount

2005

2004

2003

Income from continuing operations
Less: Dividend requirements on preferred stock
Basic earnings per share
Income from continuing operations
Effect of dilutive securities:

$230 million convertible debt
$57.5 million convertible debt
Convertible debt option
Restricted stock units
Options

Diluted earnings per share
Income from continuing operations and 

$499,038
(4,241)

$522,264
(4,241)

$522,824
(4,241)

494,797 402,330

$1.23

518,023 399,456

$1.30

518,583 398,765

$1.30

11,498
2,875
–
–
–

18,654
4,663
–
–
24

11,940
2,985
–
–
–

18,654
4,663
–
544
17

11,213
311
–
–
–

18,654
507
508
464
14

assumed conversions

$509,170 425,671

$1.20 $532,948 423,334

$1.26 $530,107 418,912

$1.26

Stock-Based Compensation Xcel Energy has incentive compensation plans under which stock options and other performance incentives are
awarded to key employees. The weighted average number of common and potentially dilutive shares outstanding used to calculate Xcel Energy’s
earnings per share include the dilutive effect of stock options and other stock awards based on the treasury stock method. The options normally
have a term of 10 years and generally become exercisable from three to five years after grant date or upon specified circumstances. The tables
on the following page include awards made by Xcel Energy and some of its predecessor companies, adjusted for the merger stock exchange
ratio, and are presented on an Xcel Energy share basis.

56 XCEL ENERGY 2005 ANNUAL REPORT

N O T E S T O C O N S O L I D A T E D F I N A N C I A L S T A T E M E N T S

Activity in stock options was as follows for the years ended Dec. 31:

(Awards in thousands)

Outstanding beginning of year
Exercised
Forfeited
Expired
Outstanding at end of year
Exercisable at end of year

Options outstanding:

Number outstanding
Weighted average remaining contractual life (years)
Weighted average exercise price

Options exercisable:

Number exercisable
Weighted average exercise price

2005

2004

2003

Awards

14,606
(152)
(213)
(665)
13,576
13,529

Average
Price

$26.67
$17.30
$26.84
$23.71
$26.92
$26.91

Awards 

15,614
(45)
(172)
(791)
14,606
10,096

Average
Price

$26.49
$15.08
$25.10
$24.08
$26.67
$26.58

Awards 

16,981
(190)
(580)
(597)
15,614
9,358

Average
Price

$26.29
$12.21
$28.48
$23.41
$26.49
$25.59

$13.81 to $25.50

Range of Exercise Prices
$25.51 to $27.00

$27.01 to $51.25

2,613,302
2.9
$20.44

2,613,302
$20.44

7,001,694
4.4
$26.28

7,001,694
$26.28

3,960,810
4.4
$32.31

3,913,810
$32.33

Certain employees also may elect to receive shares of common or restricted stock under the Xcel Energy Inc. Executive Annual Incentive
Award Plan. Restricted stock vests in equal annual installments over a three-year period from the date of grant. Xcel Energy reinvests dividends
on the restricted stock it holds while restrictions are in place. Restrictions also apply to the additional shares of restricted stock acquired
through dividend reinvestment. Restricted stock has a value equal to the market-trading price of Xcel Energy’s stock at the grant date.
Xcel Energy granted 28,626 shares of restricted stock in 2005 when the grant-date market price was $17.81. Xcel Energy granted 65,090 shares
of restricted stock in 2004 when the grant-date market price was $17.40. Xcel Energy did not grant any shares of restricted stock in 2003.
Compensation expense related to these awards was not significant.

On March 28, 2003, the governance, compensation and nominating committee of Xcel Energy’s board of directors granted restricted stock
units and performance shares under the Xcel Energy Inc. Omnibus Incentive Plan approved by the shareholders in 2000. Restrictions on the
restricted stock units lapse upon the achievement of a 27-percent total shareholder return (TSR) for 10 consecutive business days and other
criteria relating to Xcel Energy’s common equity ratio. Under no circumstances will the restrictions lapse until one year after the grant date.
TSR is measured using the market price per share of Xcel Energy common stock, which at the grant date was $12.93, plus common dividends
declared after grant date. The TSR was met in the fourth quarter of 2003, and approximately $31 million of compensation expense was recorded
at Dec. 31, 2003. The remaining cost of $10 million related to the 2003 restricted stock units was recorded in the first quarter of 2004. In
January 2004, Xcel Energy’s board of directors approved the repurchase of up to 2.5 million shares of common stock to fulfill the requirements
of the restricted stock unit exercise. On March 29, 2004, the restricted stock units lapsed, and Xcel Energy issued approximately 1.6 million
shares of common stock.

The performance share award is entirely dependent on a single measure, the TSR. Xcel Energy’s TSR will be measured over a three-year period.
Xcel Energy’s TSR is compared to the TSR of other companies in the Edison Electric Institute’s Electrics Index. At the end of the three-year
period, potential payouts of the performance shares range from 0 percent to 200 percent, depending on Xcel Energy’s TSR compared to the
peer group.

On Dec. 9, 2003, the governance, compensation and nominating committee of Xcel Energy’s board of directors approved restricted stock
units and performance shares under the Xcel Energy Inc. Omnibus Incentive Plan. On Jan. 2, 2004, Xcel Energy granted 836,186 restricted
stock units and performance shares. The grant-date market price used to calculate the TSR for this grant is $17.03.

On Dec. 14, 2004, the governance, compensation and nominating committee of Xcel Energy’s board of directors granted restricted stock units
under the Xcel Energy Inc. Omnibus Incentive Plan. Payout of the units and the lapsing of restrictions on the transfer of units are based on two
separate performance criteria. A portion of the awarded units plus associated earned dividend equivalents will be settled, and the restricted
period will lapse after Xcel Energy achieves a specified earnings per share growth (adjusted for corporate-owned life insurance) measured
against year-end earnings per share (adjusted for corporate-owned life insurance). Additionally, Xcel Energy’s annual dividend paid on its
common stock must remain at $0.83 per share or greater. Earnings per share growth will be measured annually at the end of each fiscal year.
However, in no event will the restrictions lapse prior to two years after the date of grant. The remaining awarded units plus associated earned
dividend equivalents will be settled, and the restricted period will lapse after the average of actual performance results (adjusted for actual
megawatt hours) for the three components of an environmental index measured as a percentage of target performance meets or exceeds
100 percent. The environmental index will be measured annually at the end of each fiscal year. However, in no event will the restrictions lapse
prior to two years after the date of grant. If the performance criteria have not been met within four years of the date of grant, all associated
units shall be forfeited. On Jan. 1, 2005, Xcel Energy granted 519,362 restricted stock units.

On Dec. 14, 2004, the governance, compensation and nominating committee of Xcel Energy’s board of directors approved performance shares
under the Xcel Energy Inc. Omnibus Incentive Plan. On Jan. 1, 2005, Xcel Energy granted 323,889 performance shares.

XCEL ENERGY 2005 ANNUAL REPORT 57

N O T E S T O C O N S O L I D A T E D F I N A N C I A L S T A T E M E N T S

On Dec. 13, 2005, the governance, compensation and nominating committee of Xcel Energy’s board of directors approved restricted stock
units and performance shares under the Xcel Energy Inc. Omnibus Incentive Plan. On Jan. 1, 2006, Xcel Energy granted approximately
653,000 restricted stock units and performance shares.

Compensation expense related to restricted stock units and performance shares of approximately $14.9 million, $16.8 million and $35.0 million
was recorded in 2005, 2004 and 2003, respectively.

Xcel Energy applies Accounting Principles Board Opinion No. 25 – “Accounting for Stock Issued to Employees” in accounting for stock-based
compensation and, accordingly, no compensation cost is recognized for the issuance of stock options, as the exercise price of the options equals
the fair-market value of Xcel Energy’s common stock at the date of grant. In December 2002, the FASB issued SFAS No. 148 – “Accounting for
Stock-Based Compensation – Transition and Disclosure,” amending SFAS No. 123 to provide alternative methods of transition for a voluntary
change to the fair-value-based method of accounting for stock-based employee compensation, and requiring disclosure in both annual and
interim Consolidated Financial Statements about the method used and the effect of the method used on results. The pro forma impact of
applying SFAS No. 148 is as follows at Dec. 31:

(Thousands of dollars, except per share amounts)

Net income – as reported
Less: Total stock-based employee compensation expense determined under 
fair-value-based method for stock options, net of related tax effects

Pro forma net income (loss)

Earnings per share:

Basic – as reported
Basic – pro forma
Diluted – as reported
Diluted – pro forma

2005

2004

2003

$512,972

$355,961

$622,392

(1,180)
$511,792

(2,339)
$353,622

(3,897)
$618,495

$
$
$
$

1.26
1.26
1.23
1.23

$
$
$
$

0.88
0.87
0.87
0.86

$
$
$
$

1.55
1.54
1.50
1.49

Common Stock Dividends Per Share  Historically, Xcel Energy has paid quarterly dividends to its shareholders. Dividends on common stock
are paid as declared by the board of directors. Dividends paid per share for the quarters of 2005, 2004 and 2003 are:

2005
First Quarter
Second Quarter
Third Quarter
Fourth Quarter

2004
First Quarter
Second Quarter
Third Quarter
Fourth Quarter

2003
First Quarter
Second Quarter
Third Quarter
Fourth Quarter

Dividends Per Share

$0.2075
0.2150
0.2150
0.2150
$0.8525

$0.1875
0.2075
0.2075
0.2075
$0.8100

$0.1875
0.1875
0.1875
0.1875
$0.7500

Dividend and Other Capital-Related Restrictions  Formerly, under the PUHCA, unless there was an order from the SEC, a holding company
or any subsidiary could declare and pay dividends only out of retained earnings. In May 2003, Xcel Energy received authorization from
the SEC to pay an aggregate amount of $152 million of common and preferred dividends out of capital and unearned surplus. Xcel Energy used
this authorization to declare and pay approximately $150 million for its first- and second-quarter dividends in 2003. At Dec. 31, 2005, Xcel Energy’s
retained earnings were approximately $562.1 million. With the repeal of the PUHCA, restrictions on the ability of holding companies or
utility subsidiaries to declare dividends set out in that statute will no longer apply. However, utility dividends will be subject to the FERC’s
jurisdiction under the Federal Power Act, which prohibits the payment of utility dividends out of capital accounts.

The Articles of Incorporation of Xcel Energy place restrictions on the amount of common stock dividends it can pay when preferred stock is
outstanding. Under the provisions, dividend payments may be restricted if Xcel Energy’s capitalization ratio (on a holding company basis only
and not on a consolidated basis) is less than 25 percent. For these purposes, the capitalization ratio is equal to (i) common stock plus surplus
divided by (ii) the sum of common stock plus surplus plus long-term debt. Based on this definition, the capitalization ratio at Dec. 31, 2005,
was 84 percent. Therefore, the restrictions do not place any effective limit on Xcel Energy’s ability to pay dividends because the restrictions are
only triggered when the capitalization ratio is less than 25 percent or will be reduced to less than 25 percent through dividends (other than
dividends payable in common stock), distributions or acquisitions of Xcel Energy common stock.

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In addition, NSP-Minnesota’s first mortgage indenture places certain restrictions on the amount of cash dividends it can pay to Xcel Energy, the
holder of its common stock. Even with these restrictions, NSP-Minnesota could have paid more than $854 million in additional cash dividends
on common stock at Dec. 31, 2005.

Registered holding companies and certain of their subsidiaries, including Xcel Energy and its utility subsidiaries, were limited, under the PUHCA,
in their ability to issue securities. Such registered holding companies and their subsidiaries could not issue securities unless authorized by an
exemptive rule or order of the SEC. Because Xcel Energy did not qualify for any of the main exemptive rules, it sought and received financing
authority from the SEC under the PUHCA for various financing arrangements. Xcel Energy’s current financing authority permits it, subject to
certain conditions, to issue through June 30, 2008, up to $1.8 billion of new long-term debt, common equity and equity-linked securities
and $1.0 billion of short-term debt securities during the new authorization period, provided that the aggregate amount of long-term debt,
common equity, and equity-linked and short-term debt securities issued during the new authorization period does not exceed $2.0 billion.

Xcel Energy’s ability to issue securities under the financing authority was subject to a number of conditions. One of the conditions of the
financing authority was that Xcel Energy’s ratio of common equity to total capitalization, on a consolidated basis, be at least 30 percent.
As of Dec. 31, 2005, such common equity ratio was approximately 42 percent. Additional conditions require that a security to be issued that
is rated, must be at least rated investment grade by at least one nationally recognized rating agency. Finally, all outstanding securities
that are rated must be rated investment grade by at least one nationally recognized rating agency. On Feb. 10, 2006, Xcel Energy’s senior
unsecured debt was considered investment grade by Standard & Poor’s, Moody’s and Fitch.

Upon the repeal of the PUHCA, these limitations on Xcel Energy’s financings generally will no longer apply, nor will the PUHCA restrictions
generally apply to the financings by the utility subsidiaries. However, utility financings and intra-system financings will become subject to
the jurisdiction of the FERC under the Federal Power Act.  The FERC by rule has granted a blanket authorization under certain intra-system
financings involving holding companies. Requests to the FERC to clarify its rules or grant similar blanket authorizations filed by other entities
are presently pending before the FERC. Xcel Energy and the utility subsidiaries are presently evaluating the specific applications that they
will need to file with the FERC due to the repeal of the PUHCA. It is possible that in lieu of requesting authority from the FERC for intra-company
financings, Xcel Energy and the utility subsidiaries may rely in the interim on a transitional savings clause that would permit such financing
transactions to the extent authorized by the SEC financing order and so long as the conditions in the SEC financing order continue to be satisfied.

Stockholder Protection Rights Agreement  In June 2001, Xcel Energy adopted a Stockholder Protection Rights Agreement. Each share of
Xcel Energy’s common stock includes one shareholder protection right. Under the agreement’s principal provision, if any person or group
acquires 15 percent or more of Xcel Energy’s outstanding common stock, all other shareholders of Xcel Energy would be entitled to buy, for
the exercise price of $95 per right, common stock of Xcel Energy having a market value equal to twice the exercise price, thereby substantially
diluting the acquiring person’s or group’s investment. The rights may cause substantial dilution to a person or group that acquires 15 percent
or more of Xcel Energy’s common stock. The rights should not interfere with a transaction that is in the best interests of Xcel Energy and its
shareholders because the rights can be redeemed prior to a triggering event for $0.01 per right.

10.  BENEFIT  PLANS AND  OTHER  POSTRETIREMENT  BENEFITS

Xcel Energy offers various benefit plans to its benefit employees. Approximately 56 percent of benefiting employees are represented by several
local labor unions under several collective-bargaining agreements. At Dec. 31, 2005, NSP-Minnesota had 2,144 and NSP-Wisconsin had
417 bargaining employees covered under a collective-bargaining agreement, which expires at the end of 2007. PSCo had 2,165 bargaining
employees covered under a collective-bargaining agreement, which expires in May 2006. SPS had 733 bargaining employees covered under
a collective-bargaining agreement, which expires in October 2008.

P E N S I O N B E N E F I T S

Xcel Energy has several noncontributory, defined benefit pension plans that cover almost all employees. Benefits are based on a combination
of years of service, the employee’s average pay and Social Security benefits.

Xcel Energy’s policy is to fully fund into an external trust the actuarially determined pension costs recognized for ratemaking and financial
reporting purposes, subject to the limitations of applicable employee benefit and tax laws.

Pension Plan Assets  Plan assets principally consist of the common stock of public companies, corporate bonds and U.S. government
securities. In 2004, Xcel Energy completed a review of its pension plan asset allocation and adopted revised asset allocation targets. The
target range for our pension asset allocation is 60 percent in equity investments, 20 percent in fixed income investments and 20 percent in
nontraditional investments, such as real estate, timber ventures, private equity and a diversified commodities index.

The actual composition of pension plan assets at Dec. 31 was:

Equity securities
Debt securities
Real estate
Cash
Nontraditional investments

2005

65%
20
4
1
10
100%

2004

69%
19
4
1
7
100%

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Xcel Energy bases its investment-return assumption on expected long-term performance for each of the investment types included in its pension
asset portfolio. Xcel Energy considers the actual historical returns achieved by its asset portfolio over the past 20-year or longer period, as well
as the long-term return levels projected and recommended by investment experts. The historical weighted average annual return for the past
20 years for the Xcel Energy portfolio of pension investments is 12 percent, which is greater than the current assumption level. The pension
cost determinations assume the continued current mix of investment types over the long term. The Xcel Energy portfolio is heavily weighted
toward equity securities and includes nontraditional investments that can provide a higher-than-average return. As is the experience in recent
years, a higher weighting in equity investments can increase the volatility in the return levels actually achieved by pension assets in any year.
Investment returns in 2005, 2004 and 2003 exceeded the assumed level of 8.75, 9.0 and 9.25 percent, respectively. Xcel Energy continually
reviews its pension assumptions. In 2006, Xcel Energy will continue to use an investment-return assumption of 8.75 percent.

Benefit Obligations  A comparison of the actuarially computed pension-benefit obligation and plan assets, on a combined basis, is presented
in the following table:

(Thousands of dollars)

Accumulated Benefit Obligation at Dec. 31

Change in Projected Benefit Obligation
Obligation at Jan. 1
Service cost
Interest cost
Plan amendments
Actuarial loss
Settlements
Benefit payments
Obligation at Dec. 31

Change in Fair Value of Plan Assets
Fair value of plan assets at Jan. 1
Actual return on plan assets
Employer contributions
Settlements
Benefit payments
Fair value of plan assets at Dec. 31

Funded Status of Plans at Dec. 31
Net asset
Unrecognized prior service cost
Unrecognized loss
Net pension amounts recognized on Consolidated Balance Sheets

Prepaid pension asset recorded (a)
Intangible asset recorded – prior service costs
Minimum pension liability recorded
Accumulated other comprehensive income recorded – pretax
Accumulated other comprehensive income recorded – net of tax

2005

2004

$2,642,177

$2,575,317

$2,732,263
60,461
160,985
300
85,558
–
(242,787)
$2,796,780

$2,632,491
58,150
165,361
–
133,552
(27,627)
(229,664)
$2,732,263

$3,062,016
254,307
20,000
–
(242,787)
$3,093,536

$3,024,661
284,600
10,046
(27,627)
(229,664)
$3,062,016

$ 296,756
214,702
281,519
$ 792,977

$ 683,649
3,563
(88,280)
198,542
123,279

$ 329,753
244,437
176,957
$   751,147

$ 642,873
4,689
(63,967)
170,554
106,007

Measurement Date

Dec. 31, 2005 Dec. 31, 2004

Significant Assumptions Used to Measure Benefit Obligations
Discount rate for year-end valuation
Expected average long-term increase in compensation level

5.75%
3.50%

6.00%
3.50%

(a) $22.1 million of the 2005 prepaid pension asset and $23.9 million of the 2004 prepaid pension asset relates to Xcel Energy’s remaining obligation

for companies that are now classified as discontinued operations.

During 2002, one of Xcel Energy’s pension plans became underfunded, and at Dec. 31, 2005, had projected benefit obligations of $739.5 million,
which exceeded plan assets of $609.8 million. All other Xcel Energy plans in the aggregate had plan assets of $2.5 billion and projected benefit
obligations of $2.1 billion on Dec. 31, 2005. A minimum pension liability of $88.3 million was recorded related to the underfunded plan as of
that date. A corresponding reduction in Accumulated Other Comprehensive Income, a component of Stockholders’ Equity, also was recorded,
as previously recorded prepaid pension assets were reduced to record the minimum liability. Net of the related deferred income tax effects
of the adjustments, total Stockholders’ Equity was reduced by $123.3 million at Dec. 31, 2005, due to the minimum pension liability for the
underfunded plan.

Cash Flows Cash funding requirements can be impacted by changes to actuarial assumptions, actual asset levels and other pertinent
calculations prescribed by the funding requirements of income tax and other pension-related regulations. These regulations did not require

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cash funding in the years 2003 through 2005 for Xcel Energy’s pension plans, and are not expected to require cash funding in 2006. PSCo
elected to make voluntary contributions to its pension plan for bargaining employees of $9 million in 2004 and $14.7 million in 2005, Cheyenne
voluntarily contributed $0.9 million to its pension plan for bargaining employees in 2004 and $0.3 million in 2005 and Xcel Energy voluntarily
contributed $5.0 million to the New Century Energies, Inc. (NCE) non-bargaining plans in 2005. PSCo expects to voluntarily contribute between
$15 million and $30 million during 2006 to the pension plan for bargaining employees.

Benefit Costs The components of net periodic pension cost (credit) are:

(Thousands of dollars)

Service cost
Interest cost
Expected return on plan assets
Curtailment gain
Settlement gain
Amortization of transition asset
Amortization of prior service cost
Amortization of net (gain) loss

Net periodic pension cost (credit) under SFAS No. 87 (a)

Credits not recognized due to effects of regulation

Net benefit credit recognized for financial reporting

Significant Assumptions Used to Measure Costs
Discount rate
Expected average long-term increase in compensation level
Expected average long-term rate of return on assets

2005

2004

2003

$ 60,461
160,985
(280,064)
–
–
–
30,035
6,819
(21,764)
19,368
$ (2,396)

$ 58,150
165,361
(302,958)
–
(926)
(7)
30,009
(15,207)
(65,578)
38,967
$(26,611)

$ 67,449
170,731
(322,011)
(17,363)
(1,135)
(1,996)
28,230
(44,825)
(120,920)
51,311
$(69,609)

6.00%
3.50%
8.75%

6.25%
3.50%
9.00%

6.75%
4.00%
9.25%

(a)  Includes pension credits related to discontinued operations of $1.3 million for 2005, $4.7 million for 2004 and $19.0 million for 2003. The 2003 credit

is largely due to a $20.0 million curtailment gain related to termination of NRG employees as a result of the divestiture of NRG in December 2003.

Pension costs include an expected return impact for the current year that may differ from actual investment performance in the plan. The return
assumption used for 2006 pension cost calculations will be 8.75 percent. The cost calculation uses a market-related valuation of pension assets,
which reduces year-to-year volatility by recognizing the differences between assumed and actual investment returns over a five-year period.

Xcel Energy also maintains noncontributory, defined benefit supplemental retirement income plans for certain qualifying executive personnel.
Benefits for these unfunded plans are paid out of Xcel Energy’s operating cash flows.

D E F I N E D C O NT R I B U T I O N P L A N S

Xcel Energy maintains 401(k) and other defined contribution plans that cover substantially all employees. Total contributions to these plans
were approximately $19.6 million in 2005, $21.9 million in 2004 and $15.9 million in 2003.

P O ST R E T I R E M E NT H E A LT H C A R E B E N E F I T S

Xcel Energy has a contributory health and welfare benefit plan that provides health care and death benefits to most Xcel Energy retirees. The
former NSP discontinued contributing toward health care benefits for nonbargaining employees retiring after 1998 and for bargaining
employees of NSP-Minnesota and NSP-Wisconsin who retired after 1999. Xcel Energy discontinued contributing toward health care benefits
for former NCE nonbargaining employees retiring after June 30, 2003. Employees of the former NCE who retired in 2002 continue to receive
employer-subsidized health care benefits. Nonbargaining employees of the former NSP who retired after 1998, bargaining employees of the
former NSP who retired after 1999 and nonbargaining employees of the former NCE who retired after June 30, 2003, are eligible to participate
in the Xcel Energy health care program with no employer subsidy.

In conjunction with the 1993 adoption of SFAS No. 106 – “Employers’ Accounting for Postretirement Benefits Other Than Pension,” Xcel Energy
elected to amortize the unrecognized accumulated postretirement benefit obligation (APBO) on a straight-line basis over 20 years.

Regulatory agencies for nearly all of Xcel Energy’s retail and wholesale utility customers have allowed rate recovery of accrued benefit costs
under SFAS No. 106. The Colorado jurisdictional SFAS No. 106 costs deferred during the transition period are being amortized to expense
on a straight-line basis over the 15-year period from 1998 to 2012. NSP-Minnesota also transitioned to full accrual accounting for SFAS
No. 106 costs, with regulatory differences fully amortized prior to 1997.

Plan Assets  Certain state agencies that regulate Xcel Energy’s utility subsidiaries also have issued guidelines related to the funding of
SFAS No. 106 costs. SPS is required to fund SFAS No. 106 costs for Texas and New Mexico jurisdictional amounts collected in rates, and
PSCo is required to fund SFAS No. 106 costs in irrevocable external trusts that are dedicated to the payment of these postretirement benefits.
In 2004, the investment strategy for the union asset fund was changed to increase the investment mix in equity funds. Also, a portion of the
assets contributed on behalf of nonbargaining retirees has been funded into a sub-account of the Xcel Energy pension plans. These assets
are invested in a manner consistent with the investment strategy for the pension plan.

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The actual composition of postretirement benefit plan assets at Dec. 31 was:

Equity and equity mutual fund securities
Fixed income/debt securities
Cash equivalents
Nontraditional Investments

2005

61%
17
21
1
100%

2004

54%
21
25
–
100%

Xcel Energy bases its investment-return assumption for the postretirement health care fund assets on expected long-term performance for
each of the investment types included in its postretirement health care asset portfolio. Investment-return volatility is not considered to be a
material factor in postretirement health care costs.

Benefit Obligations  A comparison of the actuarially computed benefit obligation and plan assets for Xcel Energy postretirement health
care plans that benefit employees of its utility subsidiaries is presented in the following table:

(Thousands of dollars)

Change in Benefit Obligation
Obligation at Jan. 1
Service cost
Interest cost
Plan amendments
Plan participants’ contributions
Actuarial gain (loss)
Benefit payments
Obligation at Dec. 31

Change in Fair Value of Plan Assets
Fair value of plan assets at Jan. 1
Actual return on plan assets
Plan participants’ contributions
Employer contributions
Benefit payments
Fair value of plan assets at Dec. 31

Funded Status at Dec. 31
Net obligation
Unrecognized transition obligation
Unrecognized prior service cost
Unrecognized loss
Accrued benefit liability recorded (a)

Measurement Date

Significant Assumptions Used to Measure Benefit Obligations
Discount rate for year-end valuation

2005

2004

$929,125
6,684
55,060
–
12,008
(3,175)
(61,530)
$938,172

$318,667
14,507
12,008
68,211
(61,530)
$351,863

$586,309
(103,022)
15,736
(364,745)
$134,278

$775,230
6,100
52,604
(1,600)
9,532
148,341
(61,082)
$929,125

$285,861
21,950
9,532
62,406
(61,082)
$318,667

$610,458
(117,600)
17,914
(383,026)
$ 127,746

Dec. 31, 2005 Dec. 31, 2004

5.75%

6.00%

(a)  $3.1 million of the 2005 accrued benefit liability and $1.7 million of the 2004 accrued benefit liability relate to Xcel Energy’s remaining obligation for

companies that are now classified as discontinued operations.

Effective Dec. 31, 2004, Xcel Energy raised its initial medical trend assumption from 6.5 percent to 9.0 percent and lowered the ultimate trend
assumption from 5.5 percent to 5.0 percent. The period until the ultimate rate is reached also was increased from two years to six years. Xcel
Energy bases its medical trend assumption on the long-term cost inflation expected in the health care market, considering the levels projected
and recommended by industry experts, as well as recent actual medical cost increases experienced by Xcel Energy’s retiree medical plan.

A 1-percent change in the assumed health care cost trend rate would have the following effects:

(Thousands of dollars)

1-percent increase in APBO components at Dec. 31, 2005
1-percent decrease in APBO components at Dec. 31, 2005
1-percent increase in service and interest components of the net periodic cost
1-percent decrease in service and interest components of the net periodic cost

$104,967
$ (87,450)
$ 8,177
$ (6,696)

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The employer subsidy for retiree medical coverage was eliminated for former New Century Energies, Inc. nonbargaining employees who
retire after July 1, 2003.

Xcel Energy’s subsidiary Viking was sold on Jan. 17, 2003. The sale created a one-time curtailment gain of $0.8 million. NRG participants
withdrew from the retiree life plan, resulting in a $1.3 million one-time curtailment gain in 2003.

NRG employees’ participation in the Xcel Energy postretirement health care plan ended when NRG emerged from bankruptcy on Dec. 5, 2003.
A settlement gain of $0.9 million was recognized.

Cash Flows The postretirement health care plans have no funding requirements under income tax and other retirement-related regulations
other than fulfilling benefit payment obligations when claims are presented and approved under the plans. Additional cash funding
requirements are prescribed by certain state and federal rate regulatory authorities, as discussed previously. Xcel Energy expects to contribute
approximately $75 million during 2006.

Benefit Costs The components of net periodic postretirement benefit costs are:

(Thousands of dollars)

Service cost
Interest cost
Expected return on plan assets
Curtailment gain
Settlement gain
Amortization of transition obligation
Amortization of prior service credit
Amortization of net loss

Net periodic postretirement benefit cost under SFAS No. 106 (a)

Additional cost recognized due to effects of regulation

Net cost recognized for financial reporting

Significant assumptions used to measure costs (income)
Discount rate
Expected average long-term rate of return on assets (pretax)

2005

2004

2003

$ 6,684
55,060
(25,700)
–
–
14,578
(2,178)
26,246
74,690
3,891
$78,581

$ 6,100
52,604
(23,066)
–
–
14,578
(2,179)
21,651
69,688
3,891
$73,579

$ 5,893
52,426
(22,185)
(2,128)
(916)
15,426
(1,533)
15,409
62,392
3,883
$66,275

6.00%

6.75%
5.50%–8.50% 5.50%–8.50% 8.00%–9.00%

6.25%

(a)  Includes amounts related to discontinued operations of $1.1 million of cost in 2005, $1.3 million of cost in 2004 and $(1.7) million of cost in 2003.

P R O J E C T E D B E N E F I T PAY M E NT S

The following table lists Xcel Energy’s projected benefit payments for the pension and postretirement benefit plans:

(Thousands of dollars)

2006
2007
2008
2009
2010
2011–2015

Projected
Pension Benefit
Payments

Gross Projected
Postretirement
Health Care Benefit
Payments

Expected
Medicare Part D
Subsidies

Net Projected
Postretirement
Health Care Benefit
Payments

$ 218,093
$ 221,166
$ 228,196
$ 234,663
$ 239,730
$1,216,821

$ 63,966
$ 65,851
$ 67,635
$ 69,303
$ 70,851
$366,454

$ 4,777
$ 5,196
$ 5,582
$ 5,936
$ 6,248
$34,719

$  59,189
$ 60,655
$ 62,053
$ 63,367
$ 64,603
$331,735

11.  DETAIL  OF  INTEREST AND  OTHER  INCOME,  NET  OF  NONOPERATING  EXPENSE

Interest and other income, net of nonoperating expense, for the years ended Dec. 31 consists of the following:

(Thousands of dollars)

Interest income
Equity income (loss) in unconsolidated affiliates
Gain (loss) on disposal of assets
Other nonoperating income
Interest expense on corporate-owned life insurance 

and other employee-related insurance policies

Other nonoperating expense

Total interest and other income (expense)

2005

2004

$14,886
2,511
1,308
7,153

(25,000)
(1)
857

$

$21,534
3,225
4,725
4,441

(24,601)
(8)
$ 9,316

2003

$ 17,653

(1,108) 
(581) 
3,160

(21,320)
(3,038)
$ (5,234) 

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12.  DERIVATIVE  INSTRUMENTS

In the normal course of business, Xcel Energy and its subsidiaries are exposed to a variety of market risks. Market risk is the potential loss
that may occur as a result of changes in the market or fair value of a particular instrument or commodity. Xcel Energy and its subsidiaries
utilize, in accordance with approved risk management policies, a variety of derivative instruments to mitigate market risk and to enhance our
operations. The use of these derivative instruments is discussed in further detail below.

Utility Commodity Price Risk  Xcel Energy’s utility subsidiaries are exposed to commodity price risk in their electric and natural gas
operations. Commodity price risk is managed by entering into both long- and short-term physical purchase and sales contracts for electric
capacity, energy and other energy-related products, and for various fuels used for generation of electricity and in the natural gas utility operations.
Commodity risk also is managed through the use of financial derivative instruments. Xcel Energy’s utility subsidiaries utilize these derivative
instruments to reduce the volatility in the cost of commodities acquired on behalf of our retail customers even though regulatory jurisdiction
may provide for a dollar-for-dollar recovery of actual costs. In these instances, the use of derivative instruments is done consistently with
the state regulatory cost-recovery mechanism. Xcel Energy’s risk-management policy allows it to manage market price risk within each
rate-regulated operation to the extent such exposure exists.

Short-Term Wholesale and Commodity Trading Risk  Xcel Energy’s utility subsidiaries conduct various short-term wholesale and
commodity trading activities, including the purchase and sale of electric capacity, energy and other energy-related instruments. These
activities are primarily focused on specific regions where market knowledge and experience have been obtained and are generally less
than one year in length. Xcel Energy’s risk-management policy allows management to conduct the marketing activity within approved
guidelines and limitations as approved by our risk-management committee, which is made up of management personnel not directly
involved in the activities governed by this policy.

Interest Rate Risk  Xcel Energy and its subsidiaries are subject to the risk of fluctuating interest rates in the normal course of business.
Xcel Energy’s risk-management policy allows interest rate risk to be managed through the use of fixed-rate debt, floating-rate debt and
interest-rate derivatives such as swaps, caps, collars and put or call options.

Foreign Currency Exchange Risk  Due to the discontinuance of NRG and Xcel Energy International’s operations in 2003, as discussed in
Note 2 to the Consolidated Financial Statements, Xcel Energy no longer has material foreign currency exchange risk.

T Y P E S O F A N D AC C O U NT I N G F O R D E R I VAT I V E I N ST R U M E NT S

Xcel Energy and its subsidiaries use a number of different derivative instruments in connection with its utility commodity price, interest rate,
short-term wholesale and commodity trading activities, including forward contracts, futures, swaps and options. All derivative instruments not
qualifying for the normal purchases and normal sales exception, as defined by SFAS No. 133, as amended, are recorded at fair value. The
classification of the fair value for these derivative instruments is dependent on the designation of a qualifying hedging relationship. The fair
values of derivative instruments not designated in a qualifying hedging relationship are reflected in current earnings. This includes certain
instruments used to mitigate market risk for the utility operations and all instruments related to the commodity trading operations. The
designation of a cash flow hedge permits the classification of fair value to be recorded within Other Comprehensive Income, to the extent
effective. The designation of a fair value hedge permits a derivative instrument’s gains or losses to offset the related results of the hedged
item in the Consolidated Statements of Operations, to the extent effective.

SFAS No. 133, as amended, requires that the hedging relationship be highly effective and that a company formally designate a hedging
relationship to apply hedge accounting. Xcel Energy and its subsidiaries formally document hedging relationships, including, among other
factors, the identification of the hedging instrument and the hedged transaction, as well as the risk-management objectives and strategies
for undertaking the hedged transaction. Xcel Energy and its subsidiaries also formally assess, both at inception and on an ongoing basis,
if required, whether the derivative instruments being used are highly effective in offsetting changes in either the fair value or cash flows of
the hedged items.

Gains or losses on hedging transactions for the sales of energy or energy-related products are primarily recorded as a component of revenue;
hedging transactions for fuel used in energy generation are recorded as a component of fuel costs; hedging transactions for natural gas
purchased for resale are recorded as a component of natural gas costs; and interest rate hedging transactions are recorded as a component
of interest expense. Certain utility subsidiaries are allowed to recover in electric or natural gas rates the costs of certain financial instruments
purchased to reduce commodity cost volatility.

Qualifying hedging relationships are designated as either a hedge of a forecasted transaction or future cash flow (cash flow hedge), or a
hedge of a recognized asset, liability or firm commitment (fair value hedge). The types of qualifying hedging transactions that Xcel Energy
and its subsidiaries are currently engaged in are discussed below.

C AS H F LOW H E D G E S

The effective portion of the change in the fair value of a derivative instrument qualifying as a cash flow hedge is recognized in Other
Comprehensive Income, and reclassified into earnings in the same period or periods during which the hedged transaction affects earnings.
The ineffective portion of a derivative instrument’s change in fair value is recognized in current earnings.

Commodity Cash Flow Hedges Xcel Energy’s utility subsidiaries enter into derivative instruments to manage variability of future cash flows
from changes in commodity prices. These derivative instruments are designated as cash flow hedges for accounting purposes. At Dec. 31, 2005,
Xcel Energy had various commodity-related contracts classified as cash flow hedges extending through 2009. The fair value of these cash
flow hedges is recorded in either Other Comprehensive Income or deferred as a regulatory asset or liability. This classification is based on

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the regulatory recovery mechanisms in place.  Amounts deferred in these accounts are recorded in earnings as the hedged purchase or sales
transaction is settled. This could include the purchase or sale of energy or energy-related products, the use of natural gas to generate electric
energy or gas purchased for resale.

As of Dec. 31, 2005, Xcel Energy had no amounts in Accumulated Other Comprehensive Income related to commodity cash flow hedge contracts
that are expected to be recognized in earnings during the next 12 months as the hedged transactions settle.

Xcel Energy had no ineffectiveness related to commodity cash flow hedges during the years ended Dec. 31, 2005 and 2004.

Interest Rate Cash Flow Hedges  Xcel Energy and its subsidiaries enter into interest rate swap instruments that effectively fix the interest
payments on certain floating-rate debt obligations. These derivative instruments are designated as cash flow hedges for accounting purposes.

As of Dec. 31, 2005, Xcel Energy had net losses related to interest rate swaps of approximately $0.8 million in Accumulated Other Comprehensive
Income that it expects to recognize in earnings during the next 12 months.

Xcel Energy and its subsidiaries also enter into interest rate lock agreements, including treasury-rate locks and forward starting swaps, that
effectively fix the yield or price on a specified treasury security for a specific period. These derivative instruments are designated as cash
flow hedges for accounting purposes.

As of Dec. 31, 2005, Xcel Energy had net gains related to settled interest rate lock agreements of approximately $1.4 million in Accumulated
Other Comprehensive Income that it expects to recognize in earnings during the next 12 months.

Xcel Energy had no ineffectiveness related to interest rate cash flow hedges during the years ended Dec. 31, 2005 and 2004.

Financial Impact of Qualifying Cash Flow Hedges The impact of qualifying cash flow hedges on Xcel Energy’s Accumulated Other
Comprehensive Income, included in the Consolidated Statements of Stockholders’ Equity, is detailed in the following table:

(Millions of dollars)

Accumulated other comprehensive income related to hedges at Dec. 31, 2002
After-tax net unrealized gains related to derivatives accounted for as hedges
After-tax net realized gains on derivative transactions reclassified into earnings
Accumulated other comprehensive income related to hedges at Dec. 31, 2003

After-tax net unrealized gains related to derivatives accounted for as hedges
After-tax net realized gains on derivative transactions reclassified into earnings
Accumulated other comprehensive income related to hedges at Dec. 31, 2004

After-tax net unrealized gains related to derivatives accounted for as hedges
After-tax net realized gains on derivative transactions reclassified into earnings
Accumulated other comprehensive loss related to hedges at Dec. 31, 2005

$22.1
24.1
(38.1)
$ 8.1

1.6
(9.6)
$ 0.1

4.5
(13.4)
$ (8.8)

FA I R VA L U E H E D G E S

The effective portion of the change in the fair value of a derivative instrument qualifying as a fair value hedge is offset against the change in
the fair value of the underlying asset, liability or firm commitment being hedged. That is, fair value hedge accounting allows the gains or losses
of the derivative instrument to offset, in the same period, the gains and losses of the hedged item. The ineffective portion of a derivative
instrument’s change in fair value is recognized in current earnings.

Interest Rate Fair Value Hedges  Xcel Energy enters into interest rate swap instruments that effectively hedge the fair value of fixed-rate
debt. The fair market value of Xcel Energy’s interest rate swaps at Dec. 31, 2005, was a liability of approximately $14.1 million.

N O R M A L P U R C H AS E S O R N O R M A L SA L E S C O NT R AC T S

Xcel Energy’s utility subsidiaries enter into contracts for the purchase and sale of various commodities for use in their business operations.
SFAS No. 133, as amended, requires a company to evaluate these contracts to determine whether the contracts are derivatives. Certain
contracts that literally meet the definition of a derivative may be exempted from SFAS No. 133, as amended, as normal purchases or normal
sales. Normal purchases and normal sales are contracts that provide for the purchase or sale of something other than a financial instrument
or derivative instrument that will be delivered in quantities expected to be used or sold over a reasonable period in the normal course of
business. In addition, normal purchases and normal sales contracts must have a price based on an underlying that is clearly and closely
related to the asset being purchased or sold. An underlying is a specified interest rate, security price, commodity price, foreign exchange
rate, index of prices or rates, or other variable, including the occurrence or nonoccurrence of a specified event, such as a scheduled payment
under a contract.

Xcel Energy evaluates all of its contracts when such contracts are entered to determine if they are derivatives and, if so, if they qualify to meet
the normal designation requirements under SFAS No. 133, as amended. None of the contracts entered into within the commodity trading
operations qualify for a normal designation.

Normal purchases and normal sales contracts are accounted for as executory contracts as required under GAAP.

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The following discussion briefly describes the use of derivative commodity and financial instruments at Xcel Energy and its subsidiaries, and
discloses the respective fair values at Dec. 31, 2005 and 2004.

Commodity Trading Instruments  At Dec. 31, 2005 and 2004, the fair value of commodity trading contracts was $3.9 million and $0.0 million,
respectively.

Hedging Contracts  The fair value of qualifying cash flow hedges at Dec. 31, 2005 and 2004 was $4.1 million and $(24.6) million, respectively.

Financial Instruments Xcel Energy and its subsidiaries had interest rate swaps outstanding with a fair value that was a liability of
approximately $44.7 million at Dec. 31, 2005. On Dec. 31, 2004, subsidiaries of Xcel Energy had interest rate swaps outstanding with a fair
value that was a liability of approximately $30 million.

13.  FINANCIAL  INSTRUMENTS

The estimated Dec. 31 fair values of Xcel Energy’s financial instruments, separately identifying amounts that are within continuing operations
and within discontinued operations, are as follows:

(Thousands of dollars)

Continuing Operations
Nuclear decommissioning fund
Other investments
Long-term debt, including current portion

Discontinued Operations
Long-term debt, including current portion

2005

2004

Carrying
Amount

Fair Value

Carrying
Amount

Fair Value

$ 1,047,592
$
24,286
$6,733,284

$1,047,592
$    24,050
$7,245,346

$ 918,442
$
43,141
$6,716,675

$ 918,442
$
43,031
$7,391,616

$             –

$

–

$

24,800

$

26,333

The fair value of cash and cash equivalents, notes and accounts receivable and notes and accounts payable are not materially different from
their carrying amounts because of the short-term nature of these instruments or because the stated rates approximate market rates. The fair
values of Xcel Energy’s debt securities in an external nuclear decommissioning fund and other investments are estimated based on quoted
market prices for those or similar investments. The fair values of Xcel Energy’s long-term debt is estimated based on the quoted market
prices for the same or similar issues, or the current rates for debt of the same remaining maturities and credit quality.

The fair value estimates presented are based on information available to management as of Dec. 31, 2005 and 2004. These fair value
estimates have not been comprehensively revalued for purposes of these Consolidated Financial Statements since that date, and current
estimates of fair values may differ significantly.

The following tables provide the external decommissioning fund’s approximate gains, losses and proceeds from the sale of securities for the
years ended Dec. 31:

(Thousands of dollars)

Realized gains
Realized losses
Proceeds from sale of securities

(Thousands of dollars)

Unrealized gains
Unrealized losses

2003

$ 4,999
$ 6,025
$57,768

2005

2004

8,967
$
$
8,990
$489,697

$ 16,578
$ 20,180
$223,135

2005

2004

$253,991
$  10,558

$240,960
$ 2,703

Xcel Energy provides guarantees and bond indemnities supporting certain of its subsidiaries. The guarantees issued by Xcel Energy guarantee
payment or performance by its subsidiaries under specified agreements or transactions. As a result, Xcel Energy’s exposure under the
guarantees is based upon the net liability of the relevant subsidiary under the specified agreements or transactions. Most of the guarantees
issued by Xcel Energy limit the exposure of Xcel Energy to a maximum amount stated in the guarantee. Unless otherwise indicated on the
following page, the guarantees require no liability to be recorded, contain no recourse provisions and require no collateral.

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On Dec. 31, 2005, Xcel Energy had the following amount of guarantees and exposure under these guarantees, including those related to
Seren and Xcel Energy Argentina, which are components of discontinued operations:

(Millions of dollars)
Nature of Guarantee

Guarantee performance and payment of surety 
bonds for itself and its subsidiaries (d) (h)
Guarantee performance and payment of 
surety bonds 
Guarantee the indemnification obligations of 
Xcel Energy Wholesale Group Inc. under a 
stock purchase agreement
Guarantee the indemnification obligations of 
Xcel Energy Argentina under a stock 
purchase agreement
Guarantee the indemnification obligations of 
Seren under an asset purchase agreement
Guarantee of customer loans to encourage 
business growth and expansion
Guarantee of collection of receivables sold 
to a third party
Combination of guarantees benefiting 
various Xcel Energy subsidiaries

Guarantor

Guarantee
Amount

Current
Exposure

Term or 
Expiration Date

Xcel Energy

$132.9

2006–2008, 2012,
(a) 2014, 2015 and 2022

PSCo

$ 0.50

(a)

2006

Triggering
Event
Requiring

Assets
Held as 
Performance Collateral

(e)

(e)

N/A

N/A

Xcel Energy

$ 17.50

$

–

2010

(c)

N/A

Xcel Energy

$14.70

Xcel Energy

$12.50

$

$

–

–

Continuing

Continuing

NSP-Wisconsin

$ 0.20

$0.20

NSP-Minnesota

$ 0.12

$0.12

2006

2006

Xcel Energy

$ 7.65

$

–

Continuing

(c)

(c)

(f)

(b)

(b)

N/A

N/A

N/A

(g)

N/A

(a) The total exposure of this indemnification cannot be determined. Xcel Energy believes the exposure to be significantly less than the total amount of

the outstanding bonds.

(b) Nonperformance and/or nonpayment.

(c) Losses caused by default in performance of covenants or breach of any warranty or representation in the purchase agreement.

(d) Includes one performance bond with a notional amount of $11.1 million that guarantees the performance of Planergy Housing Inc., a subsidiary of

Xcel Energy that was sold to Ameresco Inc. on Dec. 12, 2003. Ameresco Inc. has agreed to indemnify Xcel Energy for any liability arising out of any
surety bond.

(e) Failure of Xcel Energy or one of its subsidiaries to perform under the agreement that is the subject of the relevant bond. In addition, per the indemnity
agreement between Xcel Energy and the various surety companies, the surety companies have the discretion to demand that collateral be posted.

(f) Non-timely payment of the obligations or at the time the debtor becomes the subject of bankruptcy or other insolvency proceedings.

(g) Security interest in underlying receivable agreements.

(h) Xcel Energy agreed to indemnify an insurance company in connection with surety bonds they may issue or have issued for Utility Engineering up
to $80 million. The Xcel Energy indemnification will be triggered only in the event that Utility Engineering has failed to meet its obligations to the
surety company.

L E T T E R S O F C R E D I T

Xcel Energy and its subsidiaries use letters of credit, generally with terms of one year, to provide financial guarantees for certain operating
obligations. At Dec. 31, 2005, there was $35.2 million of letters of credit outstanding. The contract amounts of these letters of credit approximate
their fair value and are subject to fees determined in the marketplace.

14.  COMMITMENTS AND  CONTINGENCIES

C O M M I T M E NT S

Legislative Resource Commitments  In 1994, NSP-Minnesota received Minnesota legislative approval for on-site temporary spent-fuel
storage facilities at its Prairie Island nuclear power plant, provided NSP-Minnesota satisfies certain requirements. Commitments related to
the 17 dry cask storage containers approved in 1994 have been fulfilled. As a result of legislative amendments in 2003, NSP-Minnesota is
authorized to use as many dry cask storage containers as necessary to operate the plant through 2014. Current estimates indicate that this
will require 29 dry cask storage containers. As of Dec. 31, 2005, NSP-Minnesota had filled and placed 20 dry cask containers in storage at
Prairie Island.

The 2003 legislation transfers the primary authority concerning future spent-fuel storage issues from the Legislature to the MPUC. In
January 2005, NSP-Minnesota filed an application with the MPUC for a certificate of need for up to 30 dry cask storage containers at the
Monticello nuclear plant so that it can continue to operate beyond 2010. Xcel Energy expects a decision from the MPUC later this year.
NSP-Minnesota also filed its request with the NRC on March 24, 2005, for a 20-year extension to Monticello’s operating license. If a certificate
of need is granted, it is stayed until the following June to provide the Minnesota Legislature the opportunity to review the MPUC’s action if
it is determined appropriate. The 2003 legislation also requires NSP-Minnesota to add at least 300 megawatts of additional wind power
by 2010, with an option to own 100 megawatts of this power.

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Furthermore, payments during the remaining operating life of the Prairie Island plant are required. These payments include: $2.25 million per
year to the Prairie Island Tribal Community beginning in 2004; 5 percent of NSP-Minnesota’s conservation program expenditures (estimated at
$2 million per year) to the University of Minnesota for renewable energy research; and an increase in funding commitments to the previously
established Renewable Development Fund to $16 million per year beginning in 2003. All of the cost increases to NSP-Minnesota from these
required payments and funding commitments are expected to be recoverable in Minnesota retail customer rates, mainly through existing cost-
recovery mechanisms. Funding commitments to the Renewable Development Fund would terminate after the Prairie Island plant discontinues
operation unless the MPUC determines that NSP-Minnesota failed to make a good faith effort to store or dispose of the spent fuel out of state,
in which case NSP-Minnesota would have to make payments in the amount of $7.5 million per year.

Capital Commitments The estimated cost as of Dec. 31, 2005, of the capital expenditure programs and other capital requirements of Xcel
Energy and its subsidiaries is approximately $1.6 billion in 2006, $1.6 billion in 2007 and $1.4 billion in 2008.

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, 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.

Leases  Xcel Energy and its subsidiaries lease a variety of equipment and facilities used in the normal course of business. Two of these leases
qualify as capital leases and are accounted for accordingly. The capital leases contractually expire in 2025 and 2029. The assets and liabilities
acquired under capital leases are recorded at the lower of fair market value or the present value of future lease payments, and are depreciated
over their actual contract term in accordance with practices allowed by regulators. Depreciation of assets under capital leases is included in
depreciation expense for 2005 and 2004.

Following is a summary of property held under capital leases:

(Millions of dollars)

Storage, leaseholds and rights
Gas pipeline

Accumulated depreciation

Total property held under capital leases

2005

$40.5
20.7
61.2
(13.6)
$ 47.6

2004

$40.5
20.7
61.2
(12.3) 
$48.9

The remainder of the leases, primarily for office space, railcars, trucks, cars and power-operated equipment, are accounted for as operating
leases. Rental expense under operating lease obligations for continuing operations was approximately $57.2 million, $57.5 million and
$65.0 million for 2005, 2004 and 2003, respectively.

Future commitments under operating and capital leases for continuing operations are:

(Millions of dollars)

Operating Leases

Capital Leases

2006
2007
2008
2009
2010
Thereafter

Total minimum obligation
Interest component of obligation

Present value of minimum obligation

$41
$34
$31
$27
$21
$54

$ 7
6
6
6
6
68
$99
(51)
$48

Technology Agreement  Xcel Energy has a contract that extends through 2015 with International Business Machines Corp. (IBM) for
information technology services. The contract is cancelable at our option, although there are financial penalties for early termination. In 2005,
Xcel Energy paid IBM $137.7 million under the contract and $3.5 million for other project business. The contract also has a committed minimum
payment each year from 2006 through September 2015.

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 2006 and 2027. In total, Xcel Energy is
committed to the minimum purchase of approximately $2.8 billion of coal, $117.6 million of nuclear fuel and $2.7 billion of natural gas,
including $1.0 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.

Purchased Power Agreements  The utility subsidiaries of Xcel Energy have entered into agreements with utilities and other energy suppliers
for purchased power to meet system load and energy requirements, replace generation from company-owned units under maintenance and
during outages, and meet operating reserve obligations. NSP-Minnesota, PSCo and SPS have various pay-for-performance contracts with

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expiration dates through the year 2033. In general, these contracts provide for capacity payments, subject to meeting certain contract obligations,
and energy payments based on actual power taken under the contracts. Certain contractual payment obligations are adjusted based on
indexes. However, the effects of price adjustments are mitigated through cost-of-energy rate adjustment mechanisms.

At Dec. 31, 2005, the estimated future payments for capacity that the utility subsidiaries of Xcel Energy are obligated to purchase, subject to
availability, are as follows:

(Thousands of dollars)

2006
2007
2008
2009
2010
2011 and thereafter

Total

$ 564,669
579,333
592,655
574,145
555,228
3,439,683
$6,305,713

E N V I R O N M E NTA L C O NT I N G E N C I E S

Xcel Energy and its subsidiaries have been, or are currently involved with, the cleanup of contamination from certain hazardous substances
at several sites. In many situations, the subsidiary involved is pursuing or intends to pursue insurance claims and believes it will recover
some portion of these costs through such claims. Additionally, where applicable, the subsidiary involved is pursuing, or intends to pursue,
recovery from other potentially responsible parties and through the rate regulatory process. New and changing federal and state environmental
mandates can also create added financial liabilities for Xcel Energy and its subsidiaries, which are normally recovered through the rate
regulatory process. To the extent any costs are not recovered through the options listed above, Xcel Energy would be required to recognize
an expense for such unrecoverable amounts in its Consolidated Financial Statements.

Site Remediation  Xcel Energy must pay all or a portion of the cost to remediate sites where past activities of its subsidiaries and some other
parties have caused environmental contamination. Environmental contingencies could arise from various situations, including the following
categories of sites:
– The site of a former federal uranium enrichment facility;
– Sites of former manufactured gas plants (MGPs) operated by Xcel Energy subsidiaries or predecessors; and
– Third-party sites, such as landfills, to which Xcel Energy is alleged to be a potentially responsible party (PRP) that sent hazardous materials

and wastes.

Xcel Energy records a liability when enough information is obtained to develop an estimate of the cost of environmental remediation and
revises the estimate as information is received. The estimated remediation cost may vary materially.

To estimate the cost to remediate these sites, assumptions are made when facts are not fully known. For instance, assumptions may be
made about the nature and extent of site contamination, the extent of required cleanup efforts, costs of alternative cleanup methods and
pollution-control technologies, the period over which remediation will be performed and paid for, changes in environmental remediation
and pollution-control requirements, the potential effect of technological improvements, the number and financial strength of other PRPs and
the identification of new environmental cleanup sites.

Estimates are revised as facts become known. At Dec. 31, 2005, the liability for the cost of remediating these sites was estimated to be
$27.8 million, of which $8.8 million was considered to be a current liability. Some of the cost of remediation may be recovered from:
– Insurance coverage;
– Other parties that have contributed to the contamination; and
– Customers.

Neither the total remediation cost nor the final method of cost allocation among all PRPs of the unremediated sites has been determined.
Estimates have been recorded for Xcel Energy’s future costs for these sites.

Federal Uranium Enrichment Facility

Approximately $0.5 million of the long-term liability and $4.8 million of the current liability relate to a DOE assessment to NSP-Minnesota
and PSCo for decommissioning a federal uranium enrichment facility. These environmental liabilities do not include accruals recorded and
collected from customers in rates for future nuclear fuel disposal costs or decommissioning costs related to NSP-Minnesota’s nuclear generating
plants. See Note 15 to the Consolidated Financial Statements for further discussion of nuclear obligations.

Manufactured Gas Plant Sites

Ashland Manufactured Gas Plant Site NSP-Wisconsin was named a PRP for creosote and coal tar contamination at a site in Ashland,
Wis. The Ashland site includes property owned by NSP-Wisconsin, which was previously an MGP facility, and two other properties: an adjacent
city lakeshore park area, on which an unaffiliated third party previously operated a sawmill, and an area of Lake Superior’s Chequemegon
Bay adjoining the park.

As an interim action, NSP-Wisconsin proposed, and the Wisconsin Department of Natural Resources (WDNR) approved, a coal tar removal
and groundwater treatment system for one area of concern at the site for which NSP-Wisconsin has accepted responsibility. The groundwater
treatment system began operating in the fall of 2000. In 2002, NSP-Wisconsin installed additional monitoring wells in the deep aquifer under

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the former MGP site to better characterize the extent and degree of contaminants in that aquifer while the coal tar removal system is operational.
In 2002, a second interim response action was also implemented. As approved by the WDNR, this interim response action involved the
removal and capping of a seep area in a city park. Surface soils in the area of the seep were contaminated with tar residues. The interim
action also included the diversion and ongoing treatment of groundwater that contributed to the formation of the seep.

On Sept. 5, 2002, the Ashland site was placed on the National Priorities List (NPL). The NPL is intended primarily to guide the United States
Environmental Protection Agency (EPA) in determining which sites require further investigation. On Dec. 7, 2004, the EPA approved, with minor
contingencies, NSP-Wisconsin’s proposed work plan to complete the remedial investigation and feasibility study. On Feb. 1, 2005, NSP-Wisconsin
submitted its revised work plan to the EPA addressing all of the contingencies raised with the previous proposal. The final approval results in
specific delineation of the investigative fieldwork and scientific assessments that must be performed. A determination of the scope and cost
of the remediation of the Ashland site is not currently expected until 2007 or 2008. NSP-Wisconsin continues to work with the WDNR to
access state and federal funds to apply to the ultimate remediation cost of the entire site. In 2005, NSP-Wisconsin spent $2.8 million in the
development of the work plan, the interim response action and other matters related to the site.

The WDNR and NSP-Wisconsin have each developed several estimates of the ultimate cost to remediate the Ashland site. The estimates vary
significantly, between $4 million and $93 million, because different methods of remediation and different results are assumed in each. The
EPA and WDNR have not yet selected the method of remediation to use at the site. Until the EPA and the WDNR select a remediation strategy
for the entire site and determine NSP-Wisconsin’s level of responsibility, NSP-Wisconsin’s liability for the cost of remediating the Ashland site
is not determinable. NSP-Wisconsin has recorded a liability of $19.7 million for its potential liability for remediating the Ashland site. Since
NSP-Wisconsin cannot currently estimate the cost of remediating the Ashland site, the recorded liability is based upon the minimum of the
estimated range of remediation costs, using information available to date and reasonably effective remedial methods.

On July 2, 2004, the WDNR sent NSP-Wisconsin an invoice for recovery of past costs incurred at the Ashland site between 1994 and March 2003
in the amount of $1.4 million. On Oct. 19, 2004, the WDNR, represented by the Wisconsin Department of Justice, filed a lawsuit in Wisconsin
state court for reimbursement of the past costs. This lawsuit has been stayed until further action by either party. NSP-Wisconsin is reviewing
the invoice to determine whether all costs charged are appropriate and has recorded an estimate of its potential liability. All appropriate
insurance carriers have been notified of the WDNR’s invoice and the lawsuit, and will be invited to participate in any future efforts to address
the WDNR’s actions. All costs paid to the WDNR are expected to be recoverable in rates.

In addition to potential liability for remediation and WDNR oversight costs, NSP-Wisconsin may have liability for natural resource damages,
including the assessment thereof (collectively NRDA) at the Ashland site. Section 107 of the Comprehensive Environmental Response,
Compensation and Liability Act (CERCLA) as amended, provides that a natural resource damages trustee may recover for injury to, destruction
or loss of natural resources, including the reasonable costs of assessment, resulting from releases of hazardous substances. Similarly, Section
311 of the Federal Water Pollution Control Act (or Clean Water Act) provides the federal and state governments with the ability to recover costs
incurred in the restoration or replacement of natural resources damaged or destroyed as a result of a hazardous substance discharge. In
addition to liability for injuries to or loss of services caused by a release from the Ashland site, NSP-Wisconsin could face exposure for
additional indirect injuries that could result from the implementation of various remedial technologies during the cleanup phase of the
project. NSP-Wisconsin has indicated to the relevant natural resource trustees its intent to pursue a cooperative assessment approach to the
NRDA for the Ashland site whereby the question of natural resource damages is assessed and resolved in tandem with the studies required
for selection of a cleanup remedy or remedies. It is, however, unknown at this time whether a cooperative assessment NRDA approach will
be adopted at the Ashland site. Therefore, NSP-Wisconsin is not able to estimate its potential exposure for natural resource damages at the
site, but has recorded an estimate of its potential liability based upon the minimum of its estimated range of potential exposure.

NSP-Wisconsin has deferred, as a regulatory asset, the costs accrued for the Ashland site based on an expectation that the PSCW will continue
to allow NSP-Wisconsin to recover payments for environmental remediation from its customers. The PSCW has consistently authorized
recovery in NSP-Wisconsin rates of all remediation costs incurred at the Ashland site, and has authorized recovery of similar remediation costs
for other Wisconsin utilities. External MGP remediation costs are subject to deferral in the Wisconsin retail jurisdiction and are reviewed for
prudence as part of the Wisconsin biennial retail rate case process. Once approved by the PSCW, deferred MGP remediation costs, less
carrying costs, are historically amortized over four or six years. Carrying costs vary directly with the balance in the deferred account and for
the period 1995–2005 are estimated to total approximately $1.8 million.

In addition, in 2003, the Wisconsin Supreme Court rendered a ruling that reopens the possibility that NSP-Wisconsin may be able to recover
a portion of the remediation costs from its insurance carriers. Any insurance proceeds received by NSP-Wisconsin will operate as a credit to
ratepayers.

Fort Collins Manufactured Gas Plant Site  Prior to 1926, Poudre Valley Gas Co., a predecessor of PSCo, operated an MGP in Fort Collins,
Colo., not far from the Cache la Poudre River. In 1926, after acquiring the Poudre Valley Gas Co., PSCo shut down the MGP site and has sold
most of the property. An oily substance similar to MGP byproducts was discovered in the Cache la Poudre River. On Nov. 10, 2004, PSCo
entered into an agreement with the EPA, the city of Fort Collins and Schrader Oil Co., under which PSCo performed remediation and monitoring
work. PSCo has substantially completed work at the site, with the exception of ongoing maintenance and monitoring. In May 2005, PSCo
filed a natural gas rate case with the CPUC requesting recovery of cleanup costs at the Fort Collins MGP plant spent through March 2005,
which amounted to $6.2 million to be amortized over four years. Xcel Energy reached a settlement agreement with the parties in the case.
The CPUC approved the settlement agreement on Jan. 19, 2006, and the final order became effective on Feb. 3, 2006.

In April 2005, PSCo brought a contribution action against Schrader Oil Co. and related parties alleging Schrader Oil Co. released hazardous
substances into the environment and these releases increased the migration and environmental impact of the MGP byproducts at the site.
PSCo requested damages, including a portion of the costs PSCo incurred to investigate and remove contaminated sediments from the Cache

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la Poudre River. On Dec. 14, 2005, the court denied Schrader’s request to dismiss the PSCo suit. On Jan. 3, 2006, Schrader filed a response
to the PSCo complaint and a counterclaim against PSCo for its response costs under the CERCLA and under the Resource Conservation and
Recovery Act (RCRA). Schrader has alleged as part of its counterclaim an “imminent and substantial endangerment” of its property as defined
by RCRA. PSCo believes the allegations with respect to PSCo are without merit and will vigorously defend itself.

Third Party and Other Environmental Site Remediation

Asbestos Removal  Some of our facilities contain asbestos. Most asbestos will remain undisturbed until the facilities that contain it are
demolished or renovated. Xcel Energy has recorded an estimate for final removal of the asbestos as an asset retirement obligation. See
additional discussion of asset retirement obligations elsewhere in Note 14. It may be necessary to remove some asbestos to perform maintenance
or make improvements to other equipment. The cost of removing asbestos as part of other work is immaterial and is recorded as incurred
as operating expenses for maintenance projects, capital expenditures for construction projects or removal costs for demolition projects.

Leyden Gas Storage Facility  In February 2001, the CPUC approved PSCo’s plan to abandon the Leyden natural gas storage facility (Leyden)
after 40 years of operation. In July 2001, the CPUC decided that the recovery of all Leyden costs would be addressed in a future rate proceeding
when all costs were known. In 2003, PSCo began flooding the facility with water, as part of an overall plan to convert Leyden into a municipal
water storage facility owned and operated by the city of Arvada, Colo. In August 2003, the Colorado Oil and Gas Conservation Commission
(COGCC) approved the closure plan, the last formal regulatory approval necessary before conversion. On Dec. 31, 2005, PSCo’s leases of the
Leyden properties were terminated and the city of Arvada took custody of the facility. PSCo is obligated to monitor the site for two years
after closure. As of Dec. 31, 2005, PSCo has incurred approximately $5.7 million of costs associated with engineering buffer studies, damage
claims paid to landowners and other initial closure costs. PSCo has accrued an additional $0.2 million of costs expected to be incurred
through 2006 to complete the decommissioning and closure of the facility. PSCo has deferred these costs as a regulatory asset. In May 2005,
PSCo filed a natural gas rate case with the CPUC requesting recovery of the Leyden costs, totaling $4.8 million to be amortized over four years.
Xcel Energy has reached a settlement agreement with the parties in the case. The CPUC approved the settlement agreement on Jan. 19, 2006,
and the final order became effective on Feb. 3, 2006. Xcel Energy believes that the additional $0.9 million of costs incurred may be recovered
in a future case.

In December 2003, a homeowners’ association petitioned the EPA to assess the threat of a natural gas release from the Leyden facility pursuant
to Section 105(d) of the CERCLA. The EPA completed its review in October 2004 and concluded that the risk to nearby residents is relatively
low. The EPA referred the matter to its RCRA program. On Nov. 24, 2004, the EPA sent a letter to the COGCC requesting that the COGCC
contact Xcel Energy and request certain information concerning the closure. To date no formal request has been received by PSCo.

On Aug. 17, 2005, the EPA requested information from PSCo regarding the compliance status of the Leyden facility under the federal Clean
Air Act (CAA). On Sept. 19, 2005, PSCo responded to the requests for information. PSCo believes the Leyden facility is in compliance with the
CAA and other applicable state and federal environmental laws. Xcel Energy cannot predict the ultimate outcome of this inquiry; however,
any consequence is not expected to have a material impact.

Polychlorinated Biphenyl (PCB) Storage and Disposal  In August 2004, SPS received notice from the EPA contending SPS violated PCB
storage and disposal regulations with respect to storage of a drained transformer and related solids. The EPA contends the fine for the alleged
violation is approximately $1.2 million. SPS is contesting the fine and is in discussions with the EPA.

Cunningham Station Groundwater  Cunningham Station is a natural gas-fired power plant constructed in the 1960s by SPS and has 28 water
wells installed on its water rights. The well field provides water for boiler makeup, cooling water and potable water. Following an acid release
in 2002, groundwater samples revealed elevated concentrations of inorganic salt compounds not related to the release. The contamination
was identified in wells located near the plant buildings. The source of contamination is thought to be leakage from ponds that receive blowdown
water from the plant. In response to a request by the New Mexico Environment Department (NMED), SPS prepared a corrective action plan
to address the groundwater contamination. Under the plan submitted to the NMED, SPS agreed to control leakage from the plant blowdown
ponds through construction of a new lined pond, additional irrigation areas to minimize percolation, and installation of additional wells
to monitor groundwater quality. On June 23, 2005, NMED issued a letter approving the corrective action plan. The action plan is subject
to continued compliance with New Mexico regulations and oversight by the NMED. These actions, which are considered future improvements,
are estimated to cost approximately $3.8 million through 2008 and will be capitalized or expensed as incurred.

Other Environmental Requirements

Clean Air Interstate and Mercury Rules  In March 2005, the EPA issued two significant new air quality rules. The Clean Air Interstate Rule
(CAIR) further regulates sulfur dioxide (SO2) and nitrogen oxide (NOx) emissions, and the Clean Air Mercury Rule (CAMR) regulates mercury
emissions from power plants for the first time.

The objective of the CAIR is to cap emissions of SO2 and NOx in the eastern United States, including Minnesota, Texas and Wisconsin, which
are within Xcel Energy’s service territory. Xcel Energy generating facilities in other states are not affected. When fully implemented, CAIR
will reduce SO2 emissions in 28 eastern states and the District of Columbia by over 70 percent, and NOx emissions by over 60 percent from
2003 levels. It is designed to address the transportation of fine particulates, ozone and emission precursors to nonattainment downwind
states. CAIR has a two-phase compliance schedule, beginning in 2009 for NOx and 2010 for SO2, with a final compliance deadline in 2015
for both emissions. Under CAIR, each affected state will be allocated an emissions budget for SO2 and NOx that will result in significant
emission reductions. It will be based on stringent emission controls and forms the basis for a cap-and-trade program. State emission budgets
or caps decline over time. States can choose to implement an emissions reduction program based on the EPA’s proposed model program, or
they can propose another method, which the EPA would need to approve.

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On July 11, 2005, SPS, the City of Amarillo, Texas and Occidental Permian LTD filed a lawsuit against the EPA and a request for reconsideration
with the agency to exclude West Texas from the CAIR. El Paso Electric Co. joined in the request for reconsideration.

Xcel Energy and SPS advocated that West Texas should be excluded from CAIR because it does not contribute significantly to nonattainment
with the fine particulate matter National Ambient Air Quality Standard in any downwind jurisdiction. They argued that:
– Emissions from plants located in the Texas panhandle are more than 1,000 kilometers away from cities like Chicago, St. Louis and

Indianapolis and have no measurable impact on their air quality.

– The EPA should not arbitrarily include the entire state of Texas in the rule. As a result of its size, there are significant differences in the air

quality impact of plants in the different regions of Texas.

– The EPA has precedent for dividing the state into two regions. As part of the Texas Air Quality strategy, the Texas Commission on

Environmental Quality split the state and imposed different requirements on West Texas. The Bush administration adopted a similar
approach in its proposed Clear Skies Act.

– The EPA excluded Oklahoma and Kansas from CAIR, but imposes CAIR’s burdens on plants in West Texas. Emissions from West Texas must

pass through Oklahoma and Kansas – and over power plants in those states that are not subject to the rule – before reaching the
downwind cities the rule is designed to protect.

Under CAIR’s cap-and-trade structure, SPS can comply through capital investments in emission controls or purchase of emission “allowances”
from other utilities making reductions on their systems. Based on the preliminary analysis of various scenarios of capital investment and
allowance purchase, capital investments could range from $30 million to $300 million, and allowance purchases or increased operating
and maintenance expenses could range from $20 million to $30 million per year, beginning in 2011, based on the cost of allowance on
Feb. 15, 2006. This does not include other costs that SPS will have to incur to comply with the EPA’s new mercury emission control regulations,
which will apply to SPS’ plants.

In addition, Minnesota and Wisconsin will be included in CAIR, and Xcel Energy has generating facilities in these states that will be impacted.
Preliminary estimates of capital expenditures associated with compliance with CAIR in Minnesota and Wisconsin range from $30 million to
$40 million. Xcel Energy is not challenging CAIR in these states.

These cost estimates represent one potential scenario on complying with CAIR if West Texas is not excluded. There is uncertainty concerning
implementation of CAIR. States are required to develop implementation plans within 18 months of the issuance of the new rules and have
a significant amount of discretion in the implementation details. Legal challenges to CAIR rules could alter their requirements and/or schedule.
The uncertainty associated with the final CAIR rules makes it difficult to project the ultimate amount and timing of capital expenditures and
operating expenses.

While Xcel Energy expects to comply with the new rules through a combination of additional capital investments in emission controls at various
facilities and purchases of emission allowances, it is continuing to review the alternatives. Xcel Energy believes the cost of any required capital
investment or allowance purchases will be recoverable from customers.

The EPA’s CAMR also uses a national cap-and-trade system and is designed to achieve a 70 percent reduction in mercury emissions. It affects all
coal- and oil-fired generating units across the country that are greater than 25 megawatts. Compliance with this rule also occurs in two phases,
with the first phase beginning in 2010 and the second phase in 2018. States will be allocated mercury allowances based on coal type and their
baseline heat input relative to other states. Each electric generating unit will be allocated mercury allowances based on its percentage of total
coal heat input for the state. Similar to CAIR, states can choose to implement an emissions reduction program based on the EPA’s pro-
posed model program, or they can propose another method, which the EPA would need to approve.

Under CAMR, Xcel Energy can comply through capital investments in emission controls or purchase of emission “allowances” from other
utilities making reductions on their systems. Estimating the cost of compliance with CAMR is difficult because technologies specifically
designed for control of mercury are in the early stages of development and there is no established market on which to base the cost of mercury
allowances. Xcel Energy’s preliminary analysis for phase I compliance suggests capital costs of approximately $20 million and increased
operating and maintenance expenses ranging between $10 million and $20 million, beginning in 2010. Further testing is planned during 2006
to confirm these costs or determine if different measures will be necessary, which could result in higher costs. Additional costs will be
incurred to meet phase II requirements in 2018.

The Minnesota Legislature is expected to consider legislation in the 2006 session that could require up to a 90 percent reduction in mercury
emissions from coal-fueled power plants, provided the MPUC determines that it is technically feasible and economically reasonable to do so.
The cost impact of this potential legislation is unknown. The legislation is expected to allow for cost recovery by the utility.

Regional Haze Rules  On June 15, 2005, the EPA finalized amendments to the July 1999 regional haze rules. These amendments apply to the
provisions of the regional haze rule that require emission controls, known as best available retrofit technology (BART), for industrial facilities
emitting air pollutants that reduce visibility by causing or contributing to regional haze. Xcel Energy generating facilities in several states will
be subject to BART requirements. Some of these facilities are located in regions where CAIR is effective. CAIR has precedence over BART.
Therefore, BART requirements will be deemed to be met through compliance with CAIR requirements. 

States must develop their implementation plans by December 2007. States will identify the facilities that will have to reduce emissions under
BART and then set BART emissions limits for those facilities. Colorado is the first state in Xcel Energy’s region to earnestly begin its BART rule
development as the first step toward the December 2007 deadline. Xcel Energy is actively involved in the stakeholder process in Colorado and
will also be involved as other states begin their process. Due to the uncertainties of the many decisions involved in this process, Xcel Energy
is not able to estimate the cost impact at this time.

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Federal Clean Water Act  The federal Clean Water Act addresses the environmental impact of cooling water intakes. In July 2004, the EPA
published phase II of the rule that applies to existing cooling water intakes at steam-electric power plants. The rule will require Xcel Energy
to perform additional environmental studies at several power plants in Minnesota, Wisconsin and Colorado to determine the impact the facilities
may be having on aquatic organisms vulnerable to injury. If the studies determine the plants are not meeting the new performance standards
established by the phase II rule, physical and/or operational changes may be required at these plants. It is not possible to provide an accurate
estimate of the overall cost of this rulemaking at this time due to the many uncertainties involved, including unresolved third-party legal
challenges to the federal rule. Preliminary cost estimates range from less than $1 million at some plants to more than $10 million at others,
depending on site-specific circumstances. Based on the limited information available, total capital and operating and maintenance costs
to Xcel Energy are estimated at approximately $30 million over the next five to 10 years. Actual costs may be higher or lower depending
on the final resolution of legal challenges to the rule, as well as pending state and federal decisions regarding interpretation of specific
rule requirements.

PSCo Notice of Violation  On July 1, 2002, PSCo received a Notice of Violation (NOV) from the EPA alleging violations of the New Source
Review (NSR) requirements of the CAA at the Comanche and Pawnee plants in Colorado. The NOV specifically alleges that various maintenance,
repair and replacement projects undertaken at the plants in the mid- to late-1990s should have required a permit under the NSR process. PSCo
believes it has acted in full compliance with the CAA and NSR process. It believes that the projects identified in the NOV fit within the routine
maintenance, repair and replacement exemption contained within the NSR regulations or are otherwise not subject to the NSR requirements.
PSCo also believes that the projects would be expressly authorized under the EPA’s NSR equipment replacement rulemaking promulgated in
October 2003. On Dec. 24, 2003, the U.S. Court of Appeals for the District of Columbia circuit stayed this rule while it considers challenges to
it. PSCo disagrees with the assertions contained in the NOV and intends to vigorously defend its position. As required by the CAA, the EPA
met with Xcel Energy in September 2002 to discuss the NOV.

On March 10, 2005, the Rocky Mountain Environmental Labor Coalition (RMELC) provided notice to PSCo of its intent to sue PSCo for alleged
violations of the CAA at the Comanche plant. The notice of intent to sue alleges PSCo has violated the CAA’s Prevention of Significant
Deterioration regulations based on allegations that maintenance, repair and replacement projects undertaken at the plants in the mid- to
late-1990s should have required a permit under the NSR process. The allegations are the same as those presented in the NOV. On June 9, 2005,
Citizens for Clean Air and Water in Pueblo/Southern Colorado (CCAP) and Leslie Glustrom provided notice of intent to sue PSCo for alleged
violations of the CAA at the Comanche Plant. The allegations in the notice of intent to sue by CCAP and Ms. Glustrom are substantially identical
to those of RMELC. PSCo believes the allegations with respect to PSCo are without merit and will vigorously defend itself in any suit which
may be filed. Currently, Xcel Energy is not able to estimate any potential loss.

AS S E T R E T I R E M E NT O B L I G AT I O N S

Xcel Energy adopted Statement of Financial Accounting Standard SFAS No. 143 – “Accounting for Asset Retirement Obligations” (SFAS No. 143)
effective Jan. 1, 2003. Xcel Energy records future plant removal obligations as a liability at fair value with a corresponding increase to the
carrying values of the related long-lived assets. This liability will be increased over time by applying the interest method of accretion to
the liability, and the capitalized costs will be depreciated over the useful life of the related long-lived assets. The recording of the obligation
for regulated operations has no income statement impact due to the deferral of the adjustments through the establishment of a regulatory
asset pursuant to SFAS No. 71.

In March 2005, the Financial Accounting Standards Board (FASB) issued FASB Interpretation No. 47 – “Accounting for Conditional Asset
Retirement Obligations” (FIN No. 47) to clarify the scope and timing of liability recognition for conditional asset retirement obligations
pursuant to SFAS No. 143.  The interpretation requires that a liability be recorded for the fair value of an asset retirement obligation, if the
fair value is estimable, even when the obligation is dependent on a future event. FIN No. 47 further clarified that uncertainty surrounding
the timing and method of settlement of the obligation should be factored into the measurement of the conditional asset retirement obligation
rather than affect whether a liability should be recognized. Xcel Energy implemented FIN No. 47 as of Dec. 31, 2005. Included in these financial
statements is the recognition of a cumulative change in accounting and disclosure of the liability on a pro forma basis.

Recorded Asset Retirement Obligations (ARO)  Asset retirement obligations have been recorded for nuclear production, steam production,
electric transmission and distribution system, natural gas distribution system and office buildings. The steam production obligation includes
asbestos, ash-containment facilities and decommissioning. The asbestos recognition associated with the steam production includes certain
plants at NSP-Minnesota, PSCo and SPS. NSP-Minnesota also recorded asbestos recognition for its general office building. Generally, this
asbestos abatement removal obligation originated in 1973 with the Clean Air Act, which applied to the demolition of buildings or removal of
equipment containing asbestos that can become airborne on removal. Asset retirement obligations also have been recorded for NSP-Minnesota,
PSCo and SPS steam production related to ash-containment facilities such as bottom ash ponds, evaporation ponds and solid waste landfills.
The origination date on the ARO recognition for ash-containment facilities at steam plants was the in-service date of various facilities.

Xcel Energy recognized an ARO for the retirement costs of natural gas mains at NSP-Minnesota, NSP- Wisconsin and PSCo. In addition, an
ARO was recognized for the removal of electric transmission and distribution equipment at NSP-Minnesota, NSP-Wisconsin, PSCo and SPS.
The electric transmission and distribution ARO consists of many small potential obligations associated with PCBs, mineral oil, storage tanks,
treated poles, lithium batteries, mercury and street lighting lamps. These electric and natural gas assets have many in-service dates for which
it is difficult to assign the obligation to a particular year. Therefore, the obligation was measured at Dec. 31, 2005. The asset retirement cost was
set to this recognized obligation and no cumulative effect adjustment was shown.

A liability has also been recorded in previous years for nuclear decommissioning of an NSP-Minnesota steam production plant. This plant
began operating as a nuclear production facility in 1964 before being converted to a steam production peaking facility in 1969. For the nuclear
assets, the asset retirement obligation is associated with the decommissioning of two NSP-Minnesota nuclear generating plants, Monticello

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and Prairie Island, originates with the in-service date of the facility. Monticello began operation in 1971. Prairie Island units 1 and 2 began
operation in 1973 and 1974, respectively. See Note 15 to the Consolidated Financial Statements for further discussion of nuclear obligations.

A reconciliation of the beginning and ending aggregate carrying amounts of Xcel Energy’s asset retirement obligations is shown in the table
below for the 12 months ended Dec. 31, 2005 and 2004:

Liabilities
Recognized

Liabilities
Settled

Accretion 

Revisions
to Prior

Ending
Balance
Estimates  Dec. 31, 2005

(Thousands of dollars) 

Electric Utility Plant
Steam production asbestos
Steam production ash containment
Steam production retirement
Nuclear production decommissioning
Electric transmission and distribution
Gas Utility Plant
Gas transmission and distribution
Common Utility and Other Property
Common general plant asbestos

Total liability

Beginning
Balance
Jan. 1, 2005

$             –
–
3,002
1,088,087
–

$ 5,917
4,916
–
–
2,350

–

43,245

–
$1,091,089

575
$57,003

$ –
–
–
–
–

–

–
$ –

$ 28,406
16,018
150
70,736
–

$

–
–
–
26,145
–

$

34,323
20,934
3,152
1,184,968
2,350

–

–

43,245

2,459
$117,769

–
$26,145

3,034
$1,292,006

(Thousands of dollars) 

Electric Utility Plant
Steam production retirement
Nuclear production decommissioning  

Total liability

Beginning
Balance
Jan. 1, 2004

Liabilities
Recognized

Liabilities
Settled

Accretion 

Revisions
to Prior

Ending
Balance
Estimates  Dec. 31, 2004

$

2,860
1,021,669
$1,024,529

$

$

–
–
–

$

$

–
–
–

$

142
66,418
$ 66,560

$

$

–
–     
–

$

3,002
1,088,087
$1,091,089

The fair value of NSP-Minnesota assets legally restricted for purposes of settling the nuclear asset retirement obligations is $1.1 billion as of
Dec. 31, 2005, including external nuclear decommissioning investment funds and internally funded amounts.

Cumulative Effect of FIN No. 47 In March 2005, the FASB issued FIN No. 47. The interpretation clarified the term “conditional asset retirement
obligation” as used in SFAS No. 143. The recording of the obligation for regulated operations has no income statement impact due to the deferral
of the adjustments through the establishment of a regulatory asset pursuant to SFAS No. 71. If Xcel Energy had implemented FIN No. 47 at
Jan. 1, 2004, the liability for asset retirement obligations would have increased by $52.2 million. The same liability at Dec. 31, 2004, would
have increased by $55.2 million. A summary of the accounting for the initial adoption of FIN No. 47, as of Dec. 31, 2005, is as follows:

(Thousands of dollars)

Reflect retirement obligation when liability incurred
Record accretion of liability to adoption date
Record depreciation of plant to adoption date
Net impact of FASB Interpretation No. 47

Plant
Assets

Regulatory
Assets

Long-Term
Liabilities

$ 57,003
–
(8,283)
$ 48,720

$

–
46,883
8,283
$55,166

$ 57,003
46,883
–
$103,886

Indeterminate Asset Retirement Obligations  PSCo has underground gas storage facilities that have special closure requirements for
which the final removal date cannot be determined. 

Removal Costs  Xcel Energy accrues an obligation for plant removal costs for other generation, transmission and distribution facilities of its
utility subsidiaries. Generally, the accrual of future non-ARO removal obligations is not required. However, long-standing ratemaking practices
approved by applicable state and federal regulatory commissions have allowed provisions for such costs in historical depreciation rates.
These removal costs have accumulated over a number of years based on varying rates as authorized by the appropriate regulatory entities.
Given the long periods over which the amounts were accrued and the changing of rates through time, the utility subsidiaries have estimated the
amount of removal costs accumulated through historic depreciation expense based on current factors used in the existing depreciation rates.

Accordingly, the recorded amounts of estimated future removal costs are considered Regulatory Liabilities under SFAS No. 71. Removal costs
by entity are as follows at Dec. 31:

(Millions of dollars)

NSP-Minnesota
NSP-Wisconsin
PSCo
SPS

Total Xcel Energy

74 XCEL ENERGY 2005 ANNUAL REPORT

2005

$334
86
377
98
$895

2004

$323
81
383
104
$891

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Nuclear Insurance NSP-Minnesota’s public liability for claims resulting from any nuclear incident is limited to $10.8 billion under the 1988
Price-Anderson amendment to the Atomic Energy Act of 1954. NSP-Minnesota has secured $300 million of coverage for its public liability
exposure with a pool of insurance companies. The remaining $10.5 billion of exposure is funded by the Secondary Financial Protection
Program, available from assessments by the federal government in case of a nuclear accident. NSP-Minnesota is subject to assessments of
up to $100.6 million for each of its three licensed reactors, to be applied for public liability arising from a nuclear incident at any licensed
nuclear facility in the United States. The maximum funding requirement is $15 million per reactor during any one year.

NSP-Minnesota purchases insurance for property damage and site decontamination cleanup costs from Nuclear Electric Insurance Ltd. (NEIL).
The coverage limits are $2.1 billion for each of NSP-Minnesota’s two nuclear plant sites. NEIL also provides business interruption insurance
coverage, including the cost of replacement power obtained during certain prolonged accidental outages of nuclear generating units. Premiums
are expensed over the policy term. All companies insured with NEIL are subject to retroactive premium adjustments if losses exceed accumulated
reserve funds. Capital has been accumulated in the reserve funds of NEIL to the extent that NSP-Minnesota would have no exposure for
retroactive premium assessments in case of a single incident under the business interruption and the property damage insurance coverage.
However, in each calendar year, NSP-Minnesota could be subject to maximum assessments of approximately $14.8 million for business
interruption insurance and $26.5 million for property damage insurance if losses exceed accumulated reserve funds.

L EG A L C O NT I N G E N C I E S

In the normal course of business, Xcel Energy is subject to claims and litigation arising from prior and current operations. Xcel Energy is
actively defending these matters and has recorded a reasonable liability related to the probable cost of settlement or other disposition when
it can be reasonably estimated. The ultimate outcome of these matters cannot presently be determined. Accordingly, the ultimate resolution
of these matters could have a material adverse effect on Xcel Energy’s financial position and results of operations.

Bender et al. vs. Xcel Energy On July 2, 2004, five former NRG officers filed a lawsuit against Xcel Energy in the U.S. District Court for the
District of Minnesota. The lawsuit alleges, among other things, that Xcel Energy violated the Employee Retirement Income Security Act of 1974
(ERISA) by refusing to make certain deferred compensation payments to the plaintiffs. The complaint also alleges interference with ERISA
benefits, breach of contract related to the nonpayment of certain stock options and unjust enrichment. The complaint alleges damages of
approximately $6 million. Xcel Energy believes the suit is without merit. On Jan. 19, 2005, Xcel Energy filed a motion for summary judgment.
On July 26, 2005, the court issued an order granting Xcel Energy’s motion for summary judgment in part with respect to claims for interference
with ERISA benefits, breach of contract for nonpayment of stock options and unjust enrichment. The court denied Xcel Energy’s motion in part
with respect to the allegations of nonpayment of deferred compensation benefits. Plaintiffs and Xcel Energy have filed additional cross motions
for summary judgment, with oral arguments presented on Feb. 24, 2006. The court has also ordered this lawsuit to be trial-ready by Feb. 1, 2006.

Carbon Dioxide Emissions Lawsuit  On July 21, 2004, the attorneys general of eight states and New York City, as well as several 
environmental groups, filed lawsuits in U.S. District Court for the Southern District of New York against five utilities, including Xcel Energy,
to force reductions in carbon dioxide (CO2) emissions. The other utilities include American Electric Power Co., Southern Co., Cinergy Corp. and
Tennessee Valley Authority. CO2 is emitted whenever fossil fuel is combusted, such as in automobiles, industrial operations and coal- or
gas-fired power plants. The lawsuits allege that CO2 emitted by each company is a public nuisance as defined under state and federal
common law because it has contributed to global warming. The lawsuits do not demand monetary damages. Instead, the lawsuits ask the
court to order each utility to cap and reduce its CO2 emissions. In October 2004, Xcel Energy and four other utility companies filed a motion
to dismiss the lawsuit, contending, among other reasons, that the lawsuit is an attempt to usurp the policy-setting role of the U.S. Congress
and the president. On Sept. 19, 2005, the judge granted the defendants’ motion to dismiss on constitutional grounds. Plaintiffs have filed a
notice of appeal.

Department of Labor Audit  In 2001, Xcel Energy received notice from the Department of Labor (DOL) Employee Benefit Security
Administration that it intended to audit the Xcel Energy pension plan. After multiple on-site meetings and interviews with Xcel Energy
personnel, the DOL indicated on Sept. 18, 2003, that it is prepared to take the position that Xcel Energy, as plan sponsor and through its
delegate, the Pension Trust Administration Committee, breached its fiduciary duties under ERISA with respect to certain investments made
in limited partnerships and hedge funds in 1997 and 1998. The DOL has offered to conclude the audit if Xcel Energy is willing to contribute
to the plan the full amount of losses from the questioned investments, or approximately $7 million. On July 19, 2004, Xcel Energy formally
responded with a letter to the DOL that asserted no fiduciary violations have occurred and extended an offer to meet to discuss the matter
further. In 2005, the DOL submitted two additional requests for information related to the investigation and has not indicated that they are
prepared to close the file, or in the alternative, to assert charges against Xcel Energy or the pension plan.

Texas-Ohio Energy, Inc. vs. Centerpoint Energy et al.  On Nov. 19, 2003, a class action complaint filed in the U.S. District Court for the
Eastern District of California by Texas-Ohio Energy, Inc. was served on Xcel Energy naming e prime as a defendant. The lawsuit, filed on behalf
of a purported class of large wholesale natural gas purchasers, alleges that e prime falsely reported natural gas trades to market trade
publications in an effort to artificially raise natural gas prices in California. The case has been conditionally transferred by the Multi-District
Litigation (MDL) Panel to U.S. District Judge Pro, in Nevada, who is the judge assigned to western area wholesale natural gas marketing
litigation. In an order entered April 8, 2005, Judge Pro granted the defendants’ motion to dismiss based on the filed rate doctrine. On
May 9, 2005, plaintiffs filed an appeal of this decision to the 9th Circuit Court of Appeals.

Cornerstone Propane Partners, L.P. et al. vs. e prime inc. et al.  On Feb. 2, 2004, a purported class action complaint was filed in the
U.S. District Court for the Southern District of New York against e prime and three other defendants by Cornerstone Propane Partners, L.P.,
Robert Calle Gracey and Dominick Viola on behalf of a class who purchased or sold one or more New York Mercantile Exchange natural gas
futures and/or options contracts during the period from Jan. 1, 2000, to Dec. 31, 2002. The complaint alleges that defendants manipulated the
price of natural gas futures and options and/or the price of natural gas underlying those contracts in violation of the Commodities Exchange
Act. In February 2004, the plaintiff requested that this action be consolidated with a similar suit involving Reliant Energy Services. In February

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2004, defendants, including e prime, filed motions to dismiss. In September 2004, the U.S. District Court denied the motions to dismiss. On
Jan. 25, 2005, plaintiffs filed a motion for class certification, which defendants opposed. On Sept. 30, 2005, the U.S. District Court granted
plaintiffs’ motion for class certification. On Oct. 17, 2005, defendants filed a petition with the U.S. Court of Appeals for the Second Circuit
challenging the class certification. On Dec. 5, 2005, e prime reached a tentative settlement with the plaintiffs that will require court approval.
The settlement will be paid by e prime, and is not expected to have a material financial impact on Xcel Energy.

Fairhaven Power Company vs. Encana Corporation et al.  On Sept. 14, 2004, a class action complaint was filed in the U.S. District Court
for the Eastern District of California by Fairhaven Power Co. and subsequently served on Xcel Energy. The lawsuit, filed on behalf of a
purported class of natural gas purchasers, alleges that Xcel Energy falsely reported natural gas trades to market trade publications in an
effort to artificially raise natural gas prices in California and engaged in a conspiracy with other sellers of natural gas to inflate prices. This
case has been consolidated with Texas-Ohio Energy, Inc. vs. Centerpoint Energy et al. and assigned to U.S. District Court Judge Pro.
Defendants filed a motion to dismiss, which was granted on December 19, 2005. The plaintiffs subsequently appealed.

Utility Savings and Refund Services LLP vs. Reliant Energy Services Inc.  On Nov. 29, 2004, a class action complaint was filed in the
U.S. District Court for the Eastern District of California by Utility Savings and Refund Services LLP and subsequently served on Xcel Energy.
The lawsuit, filed on behalf of a purported class of natural gas purchasers, alleges that Xcel Energy falsely reported natural gas trades to
market trade publications in an effort to artificially raise natural gas prices in California and engaged in a conspiracy with other sellers of
natural gas to inflate prices. This case has been consolidated with Texas-Ohio Energy, Inc. vs. Centerpoint Energy et al and assigned to U.S.
District Court Judge Pro. Defendants filed a motion to dismiss, which was granted on December 19, 2005. Plaintiffs subsequently appealed.

Abelman Art Glass vs. Ercana Corporation et al.  On Dec. 13, 2004, a class action complaint was filed in the U.S. District Court for the
Eastern District of California by Abelman Art Glass and subsequently served on Xcel Energy. The lawsuit, filed on behalf of a purported class
of natural gas purchasers, alleges that Xcel Energy falsely reported natural gas trades to market trade publications in an effort to artificially raise
natural gas prices in California and engaged in a conspiracy with other sellers of natural gas to inflate prices. This case has been consolidated
with Texas-Ohio Energy, Inc. vs. Centerpoint Energy et al. and assigned to U.S. District Court Judge Pro. Defendants filed a motion to dismiss,
which was granted on December 19, 2005.

Sinclair Oil Corporation vs. e prime inc. and Xcel Energy, Inc.  On July 18, 2005, Sinclair Oil Corporation filed a lawsuit against Xcel
Energy and its former subsidiary e prime in the U.S. District Court for the Northern District of Oklahoma, alleging liability and damages for
purported misreporting of price information for natural gas to trade publications in an effort to artificially increase natural gas prices. The
complaint also alleges that e prime and Xcel Energy engaged in a conspiracy with other gas sellers to inflate prices through alleged false
reporting of gas prices. In response, e prime and Xcel Energy filed a motion with the MDL Panel to have this matter transferred to U.S. District
Court Judge Pro and filed a second motion to dismiss the lawsuit. In response to this motion, the matter has been conditionally transferred to
Judge Pro. Sinclair subsequently filed a motion with the MDL Panel to vacate this transfer. The MDL Panel has yet to issue an order. e prime
and Xcel Energy also filed a motion to dismiss with the District Court in Oklahoma based upon the filed rate doctrine. This motion is being
held in abeyance pending a ruling from the MDL Panel.

Ever-Bloom Inc. vs. Xcel Energy Inc. and e prime et al.  On June 21, 2005, a class action complaint was filed in the U.S. District Court
for the Eastern District of California by Ever-Bloom, Inc. The lawsuit names as defendants, among others, Xcel Energy and e prime. The lawsuit,
filed on behalf of a purported class of gas purchasers, alleges that defendants falsely reported natural gas trades to market trade publications
in an effort to artificially raise natural gas prices in California, purportedly in violation of the Sherman Act. Xcel Energy and e prime intend to
vigorously defend themselves against this claim.

Learjet, Inc. vs. e prime and Xcel Energy et al.  On Nov. 4, 2005, a purported class action complaint was filed in state court for Wyandotte
County of Kansas on behalf of all natural gas producers in Kansas. The lawsuit alleges that e prime, Xcel Energy and other named defendants
conspired to raise the market price of natural gas in Kansas by, among other things, inaccurately reporting price and volume information to
market trade publications. On Dec. 7, 2005, the defendants removed this matter to the U.S. District Court in Kansas. This case is in the early
stages; no discovery has been conducted and e prime and Xcel Energy intend to vigorously defend themselves against these claims.

J.P. Morgan Trust Company vs. e prime and Xcel Energy Inc. et al.  On Oct. 17, 2005, J.P. Morgan, in its capacity as the liquidating trustee
for Farmland Industries Liquidating Trust, filed an amended complaint in Kansas state court adding defendants, including Xcel Energy and
e prime, to a previously filed complaint alleging that the defendants inaccurately reported natural gas trades to market trade publications in
an effort to artificially raise natural gas prices. The lawsuit was removed to the U.S. District Court in Kansas and subsequently transferred to
U.S. District Court Judge Pro in Nevada, pursuant to an order from the MDL Panel. A motion to remand to state court has been filed by
plaintiffs and that motion is currently pending. This case is in the early stages, there has been no discovery and e prime and Xcel Energy
intend to vigorously defend themselves against these claims.

Payne et al. vs. PSCo et al.  In late October 2003, there was a wildfire in Boulder County, Colo. There was no loss of life, but there was
property damage associated with this fire. On Oct. 28, 2005, an action against PSCo related to this fire was filed in Boulder County District
Court. There are 28 plaintiffs, including individuals, the City of Jamestown and one private corporation, and three co-defendants, including
PSCo. Plaintiffs have asserted that a tree falling into PSCo distribution lines may have caused the fire. This lawsuit is in the early stages
and PSCo intends to vigorously defend itself against the claim. This lawsuit is not expected to have a material financial impact and PSCo
believes that its insurance coverage will cover any liability in this matter.

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Comanche 3 Permit Litigation  On Aug. 4, 2005, CCAP and Clean Energy Action filed suit against the Air Pollution Control Division, Colorado
Department of Public Health and Environment in state district court in Pueblo, Colo. The suit alleges the issuance of environmental permits
for the proposed Comanche 3 generating station by the Department violates the Colorado Air Pollution Prevention and Control Act. The plaintiffs
have sought judicial review of the issuance of the permits. The plaintiffs have not sought a stay of the permits or an injunction on construction
pending judicial review. On Aug. 19, 2005, the Colorado attorney general, on behalf of the Department, filed an answer in the suit. On the same
date, PSCo filed a motion to intervene and an answer in the suit. On Nov. 20, 2005, the Division submitted the formal record which was entered
by the Court. Plaintiffs’ brief was filed on Feb. 2, 2006, and the government and PSCo will have 60 days to respond.

Fru-Con Construction Corporation vs. Utility Engineering et al.  On March 28, 2005, Fru-Con Construction Corporation (Fru-Con)
commenced a lawsuit in U.S. District Court for the Eastern District of California against UE and the Sacramento Municipal Utility District
(SMUD) for damages allegedly suffered during the construction of a natural gas-fired, combined-cycle power plant in Sacramento County.
Fru-Con’s complaint alleges that it entered into a contract with SMUD to construct the power plant and further alleges that UE was negligent
with regard to the design services it furnished to SMUD. UE denies this claim and intends to vigorously defend itself. Because this lawsuit
was commenced prior to the April 8, 2005, closing of the sale of UE to Zachry Group, Inc., Xcel Energy is obligated to indemnify Zachry up
to $17.5 million. Pursuant to the terms of its professional liability policy, UE is insured up to $35 million. On June 1, 2005, UE filed a motion
to dismiss Fru-Con’s complaint. A hearing concerning this motion was held on July 18, 2005, with the court taking the matter under advisement.
On Aug. 4, 2005, the court granted UE’s motion to dismiss. Because SMUD remains a defendant in this action, the court has not entered a
final judgment subject to an appeal with respect to its order to dismiss UE from the lawsuit.

Metropolitan Airports Commission vs. Northern States Power Company  On Dec. 30, 2004, the Metropolitan Airports Commission
(MAC) filed a complaint in Minnesota state district court asserting that NSP-Minnesota is required to relocate facilities on MAC property at
the expense of NSP-Minnesota. MAC claims that approximately $7.1 million charged by NSP-Minnesota over the past five years for relocation
costs should be repaid. Both parties have asserted cross motions for partial summary judgment concerning legal obligations associated with
rent payments allegedly due and owing by NSP-Minnesota to MAC for the use of its property for a substation that serves the MAC. This
hearing was held in January 2006; the judge has not yet issued his decision. Both sides have scheduled depositions of key witnesses to
take place in February and March of 2006. Trial has been set for May 2006; additional summary judgment motions are likely prior to trial.

Siewert vs. Xcel Energy  Plaintiffs, the owners and operators of a Minnesota dairy farm, brought an action against NSP-Minnesota alleg-
ing negligence in the handling, supplying, distributing and selling of electrical power systems; negligence in the construction and mainte-
nance of distribution systems; and failure to warn or adequately test such systems. Plaintiffs allege decreased milk production, injury, and
damage to a dairy herd as a result of stray voltage resulting from NSP-Minnesota’s distribution system. Plaintiffs’ expert report on the
economic damage to their dairy farm states that the total present value of plaintiffs’ loss is $6.8 million. Trial is scheduled to commence
in March 2007. NSP-Minnesota denies these allegations and will vigorously defend itself in this matter.

OT H E R C O NT I N G E N C I E S

Tax Matters  In April 2004, Xcel Energy filed a lawsuit against the government in the U.S. District Court for the District of Minnesota to
establish its right to deduct the policy loan interest expense that had accrued during tax years 1993 and 1994 on policy loans related to its
company-owned life insurance (COLI) policies that insured certain lives of employees of PSCo. These policies are owned and managed by
PSR Investments, Inc. (PSRI), a wholly owned subsidiary of PSCo.

After Xcel Energy filed this suit, the IRS sent it two statutory notices of proposed deficiency of tax, penalty and interest for taxable years 1995
through 1999. Xcel Energy then filed two Tax Court petitions challenging those notices. Xcel Energy anticipates that the dispute relating to its
claimed interest expense deductions for tax years 1993 and later will be resolved in the refund suit that is pending in the Minnesota federal
district court and that the two Tax Court petitions will be held in abeyance pending the outcome of the refund litigation.

On Oct. 12, 2005, the district court denied Xcel Energy’s motion for summary judgment on the grounds that there were disputed issues of material
fact that required a trial for resolution. At the same time, the district court denied the government’s motion for summary judgment that was
based on its contention that PSCo had lacked an insurable interest in the lives of the employees insured under the COLI policies. However, the
district court granted Xcel Energy’s motion for partial summary judgment on the grounds that PSCo did have the requisite insurable interest.
The case is expected to proceed to trial and the litigation could take another two or more years.

Xcel Energy believes that the tax deduction for interest expense on the COLI policy loans is in full compliance with the tax law. Accordingly,
PSRI has not recorded any provision for income tax or related interest or penalties that may be imposed by the IRS, and has continued to
take deductions for interest expense related to policy loans on its income tax returns for subsequent years. As discussed above, the litigation
could require several years to reach final resolution. Defense of Xcel Energy’s position may require significant cash outlays, which may or
may not be recoverable in a court proceeding. Although the ultimate resolution of this matter is uncertain, it could have a material adverse
effect on Xcel Energy’s financial position, results of operations and cash flows.

Should the IRS ultimately prevail on this issue, tax and interest payable through Dec. 31, 2005, would reduce earnings by an estimated
$361 million. In 2004, Xcel Energy received formal notification that the IRS will seek penalties. If penalties (plus associated interest) also are
included, the total exposure through Dec. 31, 2005, is approximately $428 million. Xcel Energy annual earnings for 2006 would be reduced
by approximately $44 million, after tax, or 10 cents per share, if COLI interest expense deductions were no longer available.

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15.  NUCLEAR  OBLIGATIONS

Fuel Disposal  NSP-Minnesota is responsible for temporarily storing used or spent nuclear fuel from its nuclear plants. The DOE is responsible
for permanently storing spent fuel from NSP-Minnesota’s nuclear plants as well as from other U.S. nuclear plants. NSP-Minnesota has funded
its portion of the DOE’s permanent disposal program since 1981. The fuel disposal fees are based on a charge of 0.1 cent per kilowatt-hour
sold to customers from nuclear generation. Fuel expense includes DOE fuel disposal assessments of approximately $12 million in 2005,
$13 million in 2004 and $13 million in 2003. In total, NSP-Minnesota had paid approximately $346 million to the DOE through Dec. 31, 2005.
However, it is not determinable whether the amount and method of the DOE’s assessments to all utilities will be sufficient to fully fund the
DOE’s permanent storage or disposal facility.

The Nuclear Waste Policy Act required the DOE to begin accepting spent nuclear fuel no later than Jan. 31, 1998. In 1996, the DOE notified
commercial spent-fuel owners of an anticipated delay in accepting spent nuclear fuel by the required date and conceded that a permanent
storage or disposal facility will not be available until at least 2010. NSP-Minnesota and other utilities have commenced lawsuits against the
DOE to recover damages caused by the DOE’s failure to meet its statutory and contractual obligations.

NSP-Minnesota has its own temporary on-site storage facilities for spent fuel at its Monticello and Prairie Island nuclear plants, which consist
of storage pools and a dry cask facility. With the dry cask storage facility licensed by the NRC, approved in 1994 and again in 2003, management
believes it has adequate storage capacity to continue operation of its Prairie Island nuclear plant until at least the end of its license terms in
2013 and 2014. The Monticello nuclear plant has storage capacity in the pool to continue operations until 2010. Storage availability to permit
operation beyond these dates is not known at this time. All of the alternatives for spent fuel storage are being investigated until a DOE facility
is available, including pursuing the establishment of a private facility for interim storage of spent nuclear fuel as part of a consortium of
electric utilities.

Nuclear fuel expense includes payments to the DOE for the decommissioning and decontamination of the DOE’s uranium-enrichment facilities.
In 1993, NSP-Minnesota recorded the DOE’s initial assessment of $46 million, which is payable in annual installments from 1993 to 2008.
NSP-Minnesota is amortizing each installment to expense on a monthly basis. The most recent installment paid in 2005 was $4.7 million;
future installments are subject to inflation adjustments under DOE rules. NSP-Minnesota is obtaining rate recovery of these DOE assessments
through the cost-of-energy adjustment clause as the assessments are amortized. Accordingly, the unamortized assessment of $8.3 million at
Dec. 31, 2005, is deferred as a regulatory asset.

Regulatory Plant Decommissioning Recovery  Decommissioning of NSP-Minnesota’s nuclear facilities, as last approved by the MPUC, is
planned for the period from cessation of operations through 2040, assuming the prompt dismantlement method. NSP-Minnesota is currently
accruing the costs for decommissioning over the MPUC-approved cost-recovery period and including the accruals in Accumulated Depreciation.
Upon implementation of SFAS No. 143, the decommissioning costs in Accumulated Depreciation and ongoing accruals are reclassified to a
regulatory liability account. The total decommissioning cost obligation is recorded as an asset retirement obligation in accordance with
SFAS No. 143.

Monticello began operation in 1971 and is licensed to operate until 2010. Prairie Island units 1 and 2 began operation in 1973 and 1974,
respectively, and are licensed to operate until 2013 and 2014, respectively. In 2003, the Minnesota Legislature changed a law that had limited
expansion of on-site storage. On Aug. 25, 2004, the Xcel Energy board of directors authorized the pursuit of renewal of the operating licenses
for the Monticello and Prairie Island nuclear plants. NSP-Minnesota filed its application for Monticello with the MPUC in January 2005, seeking
a certificate of need for dry spent-fuel storage, and filed an application in March 2005 with the NRC for an operating license extension of up
to 20 years. A decision regarding Monticello relicensing is expected in 2007. Plant assessments and other work for the Prairie Island applications
are planned in the next two or three years. The Prairie Island license renewal process has not yet begun.

Consistent with cost recovery in utility customer rates, NSP-Minnesota records annual decommissioning accruals based on periodic site-specific
cost studies and a presumed level of dedicated funding. Cost studies quantify decommissioning costs in current dollars. Current authorized
funding presumes that costs will escalate in the future at a rate of 4.19 percent per year. The total estimated decommissioning costs that will
ultimately be paid, net of income earned by external trust funds, is currently being accrued using an annuity approach over the approved
plant-recovery period. This annuity approach uses an assumed rate of return on funding, which is currently 5.5 percent, net of tax, for external
funding and approximately 8 percent, net of tax, for internal funding. The net unrealized gain on nuclear decommissioning investments is
deferred as a Regulatory Liability based on the assumed offsetting against decommissioning costs in current ratemaking treatment.

The MPUC last approved NSP-Minnesota’s nuclear decommissioning study request in December 2003, using 2002 cost data. In October 2005,
NSP-Minnesota filed with the MPUC a nuclear decommissioning study using 2005 cost data. Xcel Energy’s recommendation is to reduce the
2006 funding if approved by the MPUC. Xcel Energy expects the MPUC to approve a new funding amount in 2006.

Internal funding for all retail jurisdictions was transferred to the external funds by the end of 2005. Based on the last MPUC approval requiring
the acceleration of the internal fund transfer, there is a step change in the level of the overall decommissioning expense at the expiration of
the transfer beginning Jan. 1, 2006. Expecting to operate Prairie Island through the end of each unit’s licensed life, the approved capital
recovery will allow for the plant to be fully depreciated, including the accrual and recovery of decommissioning costs, in 2014. Xcel Energy
believes future decommissioning cost accruals will continue to be recovered in customer rates.

The total obligation for decommissioning currently is expected to be funded 100 percent by external funds, as approved by the MPUC.
Contributions to the external fund started in 1990 and are expected to continue until plant decommissioning begins. The assets held in trusts
as of Dec. 31, 2005, primarily consisted of investments in fixed income securities, such as tax-exempt municipal bonds and U.S. government
securities that mature in one to 20 years, and common stock of public companies. NSP-Minnesota plans to reinvest matured securities until
decommissioning begins.

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At Dec. 31, 2005, NSP-Minnesota had recorded and recovered in rates cumulative decommissioning accruals of $816 million. The following
table summarizes the funded status of NSP-Minnesota’s decommissioning obligation based on approved regulatory recovery parameters.
These amounts are not those recorded in the financial statements for the asset retirement obligation in accordance with SFAS No. 143.

(Thousands of dollars)

Estimated decommissioning cost obligation from most recently approved study (2002 dollars)
Effect of escalating costs to 2005 and 2004 dollars (at 4.19 percent per year), respectively
Estimated decommissioning cost obligation in current dollars
Effect of escalating costs to payment date (at 4.19 percent per year)
Estimated future decommissioning costs (undiscounted)
Effect of discounting obligation (using risk-free interest rate)
Discounted decommissioning cost obligation
Assets held in external decommissioning trust
Discounted decommissioning obligation in excess of assets currently held in external trust

Decommissioning expenses recognized include the following components:

2005

2004

$1,716,618
224,946
1,941,564
1,851,801
3,793,365
(2,026,003)
1,767,362
1,047,592
$ 719,770

$1,716,618
146,866
1,863,484
1,929,881
3,793,365
(2,139,561)
1,653,804
918,442
$ 735,362

(Thousands of dollars)

2005

2004

2003

Annual decommissioning cost accrual reported as depreciation expense:

Externally funded
Internally funded (including interest costs)

Interest cost on externally funded decommissioning obligation
Earnings from external trust funds
Net decommissioning accruals recorded

$80,582
(57,561)
(24,516)
24,516
$23,021

$80,582
(53,307)
(19,026)
19,026
$ 27,275

$80,582
(35,906)
(14,952)
14,952
$44,676

Decommissioning and interest accruals are included with Regulatory Liabilities on the Consolidated Balance Sheets. Interest costs and trust
earnings associated with externally funded obligations are reported in Other Nonoperating Income on the Consolidated Statements of Operations.

Negative accruals for internally funded portions in 2003, 2004 and 2005 reflect the impact of the 2002 decommissioning study, which
approved an assumption of 100-percent external funding of future costs. The 2005 nuclear decommissioning filing has not been used for
the regulatory presentation because it is effective for 2006. However, the filing and all the updated parameters were used for a new ARO
layer for SFAS No. 143 recognition.

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16.  REGULATORY ASSETS AND  LIABILITIES

Xcel Energy’s regulated businesses prepare their Consolidated Financial Statements in accordance with the provisions of SFAS No. 71, as
discussed in Note 1 to the Consolidated Financial Statements. Under SFAS No. 71, regulatory assets and liabilities can be created for amounts
that regulators may allow to be collected, or may require to be paid back to customers in future electric and natural gas rates. Any portion
of Xcel Energy’s business that is not regulated cannot use SFAS No. 71 accounting. If changes in the utility industry or the business of Xcel
Energy no longer allow for the application of SFAS No. 71 under GAAP, Xcel Energy would be required to recognize the write-off of regulatory
assets and liabilities in its Statements of Operations. The components of unamortized regulatory assets and liabilities of continuing operations
shown on the balance sheet at Dec. 31 were:

(Thousands of dollars)

Regulatory Assets
Net nuclear asset retirement obligations
Contract valuation adjustments (e)
AFDC recorded in plant (a)
Losses on reacquired debt
Conservation programs (a)
Nonnuclear asset retirement obligations
Nuclear decommissioning costs (b)
Employees’ postretirement benefits other than pension
Renewable resource costs
Environmental costs

State commission accounting adjustments (a)
Plant asset recovery (Pawnee II and Metro Ash)
Unrecovered natural gas costs (c)
Unrecovered electric production and transmission costs (d)
Other

Total regulatory assets

Regulatory Liabilities
Plant removal costs
Pension costs – regulatory differences
Contract valuation adjustments (e)
Unrealized gains from decommissioning investments
Investment tax credit deferrals
Deferred income tax adjustments
Interest on income tax refunds
Fuel costs, refunds and other
Total regulatory liabilities

See Note(s)

Remaining
Amortization Period

2005

2004

End of licensed life
Term of related contract
Plant lives
Term of related debt
Various
Plant lives
Up to two years
Seven years
One to two years
Varies, generally 
four to six years
Plant lives
18 months
One to two years
To be determined
Various

1, 15
12

1

14

10

14, 15 

1
1

1, 15 
10
12
15

1

$ 282,195
111,639
170,785
84,290
111,429
32,371
8,317
27,234
50,453

33,957
14,460
7,355
12,998
6,634
9,286
$ 963,403

$ 895,653
397,261
99,734
143,396
84,437
75,171
6,031
9,137
$1,710,820

$ 221,864
102,741
169,352
89,694
88,253
–
20,494
31,125
38,985

28,176
15,945
12,258
14,553
–
17,196
$ 850,636

$ 891,018
377,893
56,874
129,028
92,227
69,780
9,667
4,058
$1,630,545

(a) Earns a return on investment in the ratemaking process. These amounts are amortized consistent with recovery in rates.

(b) These costs do not relate to NSP-Minnesota’s nuclear plants. They relate to DOE assessments, as discussed previously in Note 15. In 2004, these

costs also included unamortized costs for PSCo’s Fort St. Vrain nuclear plant decommissioning.

(c) Excludes current portion expected to be returned to customers within 12 months of $16.3 million and $12.4 million for 2005 and 2004, respectively.

(d) In 2004, excluded the current portion expected to be recovered within the next 12 months of $16.1 million.

(e) Includes the fair value of certain long-term contracts used to meet native energy requirements.

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17.  SEGMENTS AND  RELATED  INFORMATION

Xcel Energy has the following reportable segments: Regulated Electric Utility, Regulated Natural Gas Utility and All Other.
– Xcel Energy’s Regulated Electric Utility segment generates, transmits and distributes electricity in Minnesota, Wisconsin, Michigan,

North Dakota, South Dakota, Colorado, Texas, New Mexico, Kansas and Oklahoma. In addition, this segment includes sales for resale
and provides wholesale transmission service to various entities in the United States. Regulated Electric Utility also includes commodity
trading operations.

– Xcel Energy’s Regulated Natural Gas Utility segment transports, stores and distributes natural gas primarily in portions of Minnesota,

Wisconsin, North Dakota, Michigan and Colorado.

Revenues from operating segments not included above are below the necessary quantitative thresholds and are therefore included in the All
Other category. Those primarily include steam revenue, appliance repair services, nonutility real estate activities, revenues associated with
processing solid waste into refuse-derived fuel and investments in rental housing projects that qualify for low-income housing tax credits.

To report income from continuing operations for Regulated Electric and Regulated Natural Gas Utility segments, Xcel Energy must assign or
allocate all costs and certain other income. In general, costs are:
– directly assigned wherever applicable;
– allocated based on cost causation allocators wherever applicable; and
– allocated based on a general allocator for all other costs not assigned by the above two methods.

The accounting policies of the segments are the same as those described in Note 1 to the Consolidated Financial Statements. These segments
are managed separately because the revenue streams are dependent upon regulated rate recovery, which are separately determined for each
segment. Xcel Energy evaluates performance by each legal entity based on profit or loss generated from the product or service provided.

(Thousands of dollars)

2005
Operating revenues from external customers
Intersegment revenues
Total revenues

Depreciation and amortization
Financing costs, mainly interest expense
Income tax expense (benefit)
Income (loss) from continuing operations

2004
Operating revenues from external customers
Intersegment revenues
Total revenues

Depreciation and amortization
Financing costs, mainly interest expense
Income tax expense (benefit)
Income (loss) from continuing operations

2003
Operating revenues from external customers
Intersegment revenues
Total revenues

Depreciation and amortization
Financing costs, mainly interest expense
Income tax expense (benefit)
Income (loss) from continuing operations

Regulated 
Electric Utility

$ 7,243,637
767
$ 7,244,404
$ 662,236
301,185
258,161
$ 440,578

$6,225,245
1,132
$6,226,377
$ 610,127
299,768
235,743
$ 466,307

$5,919,938
1,123
$5,921,061
$ 625,132
312,432
239,671
$ 461,363

Regulated
Natural 
Gas Utility

$ 2,307,385
17,732
$ 2,325,117
89,174
$
47,145
32,923
71,213

$

$1,915,514
8,735
$1,924,249
82,012
$
48,757
29,286
86,091

$

$1,677,768
10,868
$1,688,636
80,688
$
57,673
31,314
94,056

$

All Other

Reconciling  Consolidated 
Total
Eliminations

$ 74,455
–
$ 74,455
$ 15,911
108,538
(117,545)
$ 35,733

$ 74,802
–
$ 74,802
$ 13,816
100,784
(103,094)
$ 12,173

$133,561
–
$133,561
$ 21,487
103,825
(100,293)
$ 4,984

$

–
(18,499)
$(18,499) 
$

–
(14,242)
–
$(48,486)

$

–
(9,867)
$ (9,867) 
$

–
(14,829)
–

$(42,307) 

$

–
(11,991)
$ (11,991) 
$

–
(22,911)
–

$ (37,579) 

$9,625,477
–
$9,625,477
$ 767,321
442,626
173,539
$ 499,038

$8,215,561
–
$8,215,561
$ 705,955
434,480
161,935
$ 522,264

$ 7,731,267
–
$ 7,731,267
$ 727,307
451,019
170,692
$ 522,824

XCEL ENERGY 2005 ANNUAL REPORT 81

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18.  SUMMARIZED  QUARTERLY  FINANCIAL  DATA  (UNAUDITED)

Summarized quarterly unaudited financial data is as follows:

(Thousands of dollars, except per share amounts)

Revenue
Operating income
Income from continuing operations
Discontinued operations – income (loss)
Net income
Earnings available for common shareholders
Earnings per share from continuing operations – basic
Earnings per share from continuing operations – diluted
Earnings (loss) per share from discontinued operations – basic
Earnings (loss) per share from discontinued operations – diluted
Earnings per share total – basic
Earnings per share total – diluted

(Thousands of dollars, except per share amounts)

Revenue
Operating income
Income from continuing operations
Discontinued operations – income (loss)
Net income
Earnings available for common shareholders
Earnings per share from continuing operations – basic
Earnings per share from continuing operations – diluted
Earnings (loss) per share from discontinued operations – basic
Earnings (loss) per share from discontinued operations – diluted
Earnings per share total – basic
Earnings per share total – diluted

(a) 2005 results include unusual items as follows:

March 31, 2005
(a)

Quarter ended
June 30, 2005 Sept. 30, 2005
(a)

(a)

Dec. 31, 2005
(a)

$2,381,038
279,341
127,643

(6,165) 

121,478
120,418
0.32
0.31
(0.02)
(0.02)
0.30
0.29

$
$
$
$
$
$

$2,073,549
198,098
74,613
8,793
83,406
82,346
0.18
0.18
0.02
0.02
0.20
0.20

$
$
$
$
$
$

$2,288,653
364,725
197,817
(1,798)
196,019
194,959
0.49
0.47
(0.01)
–
0.48
0.47

$
$
$
$
$
$

$2,882,237
250,555
98,964
13,104
112,068
111,008
0.25
0.24
0.03
0.03
0.28
0.27

$
$
$
$
$
$

March 31, 2004
(b)

Quarter ended
June 30, 2004 Sept. 30, 2004
(b)

(b)

Dec. 31, 2004
(b)

$2,248,797
321,438
148,684
1,227
149,911
148,851
0.37
$
0.36
$
$             –
$             –
0.37
$
0.36
$

$1,760,175
198,694
85,420
886
86,306
85,246
0.21
$
0.21
$
$             –
$             –
0.21
$
0.21
$

$1,974,935
338,235
165,952
(119,232) 
46,720
45,660
0.41
0.40

$
$
$       (0.30) 
$       (0.28) 
$
$

0.11
0.12

$2,231,654
217,347
122,208
(49,184)
73,024
71,964
0.30
$
0.30
$
$       (0.12)
$       (0.12)
0.18
$
0.18
$

– Third-quarter results from continuing operations were decreased by the accrual of legal settlements incurred by the holding company in the

amount of $5 million.

– Second-quarter results from discontinued operations were increased by $7.7 million due to a true-up on the estimated impairment expected to

result from the disposal of Seren, as discussed in Note 2 to the Consolidated Financial Statements.

– Fourth-quarter results from discontinued operations include the positive impact of a $17.2 million tax benefit recorded to reflect the final resolution

of Xcel Energy’s divested interest in NRG.

– First-quarter revenue has been reduced by $6.1 million as compared to the amount previously reported in the Quarterly Report filed on Form 10-Q
with the SEC for the first quarter of 2005. This adjustment is a result of fees collected from customers on behalf of governmental agencies that
were reclassified to be presented net of the related payments made to the agencies.

(b) 2004 results include special charges in the fourth quarter and unusual items as follows:

– Fourth-quarter results from continuing operations were decreased by the accrual of legal settlements incurred by the holding company in the

amount of $17.6 million.

– Third-quarter results from discontinued operations were decreased by $112 million, or 27 cents per share, due to the estimated impairment

expected to result from the disposal of Seren, as discussed in Note 2 to the Consolidated Financial Statements. During the fourth quarter, an
adjustment increasing the impairment by $31 million, or 7 cents per share, was recorded.

– Fourth-quarter results from discontinued operations were decreased by $15.7 million, or 4 cents per share, related to a reduction of the NRG tax

benefits previously booked, after completion of an NRG tax basis study.

– Fourth-quarter results from continuing operations were increased by $33.8 million, or 8 cents per share, due to the accrual of income tax benefits

which included $22.3 million related to the successful resolution of various issues and other adjustments to current and deferred taxes.

– Fourth-quarter results from continuing operations were decreased by a $19.7 million accrual recorded to reflect SPS’ best estimate of any potential

liability for the impact of its retail fuel cost-recovery proceeding in Texas.

– First-quarter revenue has been reduced by $10.4 million as compared to the amount previously reported in the Quarterly Report filed on Form
10-Q with the SECfor the first quarter 2005. Revenue for the quarter ended Dec. 31, 2004, has been reduced by $10.3 million as compared to
the amount previously reported in the Annual Report on Form 10-K for 2004. These adjustments are a result of fees collected from customers
on behalf of governmental agencies that were reclassified to be presented net of the related payments made to the agencies.

82 XCEL ENERGY 2005 ANNUAL REPORT

S H A R E H O L D E R I N F O R M A T I O N A N D F I S C A L A G E N T S

SHAREHOLDER  INFORMATION

H E A D QU A RT E R S

414 Nicollet Mall, Minneapolis, Minnesota 55401

I NT E R N E T A D D R E S S

www.xcelenergy.com

I N V E STO R S H OT L I N E

1-877-914-9235

STO C K T R A N S F E R AG E NT

The Bank of New York
101 Barclay Street
New York, New York 10286

1-877-778-6786, toll free
This is an automated phone system to expedite requests. However,
staying on the line to speak with a representative is an option.
Representatives are available from 7 a.m. to 7 p.m. CST.

R E P O RT S AVA I L A B L E O N L I N E

Financial reports, including filings with the Securities and Exchange
Commission and Xcel Energy’s Report to Shareholders, are available
online at www.xcelenergy.com. Click on Investor Information.

STO C K E X C H A N G E L I ST I N G S A N D T I C K E R SY M B O L

Common stock is listed on the New York, Chicago and Pacific
exchanges under the ticker symbol XEL. The New York Stock
Exchange lists some of Xcel Energy’s preferred stock. In newspaper
listings, it appears as XcelEngy.

I N V E STO R R E L AT I O N S

Internet address: www.xcelenergy.com or contact Richard Kolkmann,
Managing Director, Investor Relations, at 612-215-4559 or Paul
Johnson, Director, Investor Relations, at 612-215-4535.

S H A R E H O L D E R S E RV I C E S

Internet address: www.xcelenergy.com or contact Dianne Perry, 
Manager, Shareholder Services, at 612-215-4534 or e-mail
dianne.g.perry@xcelenergy.com.

C O R P O R AT E G OV E R N A N C E

Xcel Energy has filed certifications of its Chief Executive Officer and
Chief Financial Officer pursuant to section 302 of the Sarbanes-Oxley
Act of 2002 as exhibits to its Annual Report on Form 10-K for 2005
that it has filed with the Securities and Exchange Commission. It
has also filed with the New York Stock Exchange the CEO certification
for 2005 required by section 303A.12(a) of the New York Stock
Exchange’s rules relating to compliance with the New York Stock
Exchange’s corporate governance listing standards.

FISCAL AGENTS

X C E L E N E R G Y I N C.
Transfer Agent, Registrar, Dividend Distribution, Common
and Preferred Stocks

The Bank of New York, 101 Barclay Street, New York, New York 10286

Trustee – Bonds

Wells Fargo Bank Minnesota, N.A., Sixth Street and Marquette
Avenue, Minneapolis, Minnesota 55479

Coupon Paying Agents – Bonds

Wells Fargo Bank Minnesota, N.A., Minneapolis, Minnesota 

XCEL ENERGY 2005 ANNUAL REPORT 83

X C E L E N E R G Y D I R E C T O R S A N D P R I N C I P A L O F F I C E R S

XCEL  ENERGY  DIRECTORS

Richard C. Kelly*

Chairman, President and CEO
Xcel Energy Inc.

Richard H. Anderson, 1, 4

Executive Vice President
UnitedHealth Group, Inc. 
CEO
Ingenix

C. Coney Burgess 2, 3

Chairman and President
Burgess-Herring Ranch Company 
Chairman
Herring Bank

Roger R. Hemminghaus 1, 3

Retired Chairman and CEO
Ultramar Diamond Shamrock Corporation

A. Barry Hirschfeld 2, 4

Chairman
National Hirschfeld LLC

Douglas W. Leatherdale 1, 2, 3

Retired Chairman and CEO
The St. Paul Companies, Inc.

Albert F. Moreno 1, 3

Retired Senior Vice President
and General Counsel
Levi Strauss & Co.

Dr. Margaret R. Preska 1, 4

Owner and CEO
Robinson Preska Company
Distinguished Service Professor
Minnesota State Universities
President Emerita
Minnesota State University, Mankato

A. Patricia Sampson 2, 4

President and CEO
The Sampson Group, Inc.

Richard H. Truly 3, 4

Retired U.S. Navy Vice Admiral

Board Committees:
1. Audit
2. Governance, Compensation and 

Nominating

3. Finance
4. Operations, Nuclear and Environmental

*Richard C. Kelly is ex officio member of

all committees

XCEL  ENERGY  PRINCIPAL  OFFICERS

Richard C. Kelly

Chairman, President and CEO 

Paul J. Bonavia

President – Utilities Group

Benjamin G.S. Fowke III

Vice President and Chief Financial Officer

Raymond E. Gogel

Vice President – Customer and Enterprise
Solutions and Chief Administrative Officer

Cathy J. Hart

Vice President – Corporate Services and
Corporate Secretary

Gary R. Johnson

Vice President and General Counsel

Teresa S. Madden

Vice President and Controller

George E. Tyson II

Vice President and Treasurer

David M. Wilks

President – Energy Supply

PRINCIPAL  SUBSIDIARIES  OFFICERS

Gary L. Gibson

Michael L. Swenson

Patricia K. Vincent

President and CEO – Southwestern Public
Service Company

President and CEO – Northern States Power
Company-Wisconsin

President and CEO – Public Service
Company of Colorado

Cynthia L. Lesher

President and CEO – Northern States Power
Company-Minnesota 

84 XCEL ENERGY 2005 ANNUAL REPORT

U.S. Bancorp Center
414 Nicollet Mall
Minneapolis, MN 55401
Xcel Energy investors hotline: 1-877-914-9235
www.xcelenergy.com

© 2006 Xcel Energy Inc.
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