News Column

XCEL ENERGY INC - 10-K - Management's Discussion and Analysis of Financial Condition and Results of Operations

February 21, 2014

Business Segments and Organizational Overview

Xcel Energy Inc. is a public utility holding company. In 2013, Xcel Energy's operations included the activity of four utility subsidiaries that serve electric and natural gas customers in eight states. These utility subsidiaries are NSP-Minnesota, NSP-Wisconsin, PSCo and SPS. These utilities serve customers in portions of Colorado, Michigan, Minnesota, New Mexico, North Dakota, South Dakota, Texas and Wisconsin. Along with WYCO, a joint venture formed with CIG to develop and lease natural gas pipelines, storage and compression facilities, and WGI, an interstate natural gas pipeline company, these companies comprise the regulated utility operations.



Xcel Energy Inc.'s nonregulated subsidiary is Eloigne, which invests in rental housing projects that qualify for low-income housing tax credits.

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, including the 2014 EPS guidance and assumptions, 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. Forward-looking statements speak only as of the date they are made, and we do not undertake any obligation to update them to reflect changes that occur after that date. Factors that could cause actual results to differ materially include, but are not limited to: general economic conditions, including inflation rates, monetary fluctuations and their impact on capital expenditures and the ability of Xcel Energy Inc. and its subsidiaries to obtain financing on favorable terms; business conditions in the energy industry, including the risk of a slow down in the U.S. economy or delay in growth recovery; trade, fiscal, taxation and environmental policies in areas where Xcel Energy has a financial interest; customer business conditions; 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 Inc. 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 or impose environmental compliance conditions; structures that affect the speed and degree to which competition enters the electric and natural gas markets; costs and other effects of legal and administrative proceedings, settlements, investigations and claims; actions by regulatory bodies impacting our nuclear operations, including those affecting costs, operations or the approval of requests pending before the NRC; financial or regulatory accounting policies imposed by regulatory bodies; availability or cost of capital; employee work force factors; the items described under Factors Affecting Results of Operations; and the other risk factors listed from time to time by Xcel Energy Inc. in reports filed with the SEC, including "Risk Factors" in Item 1A of this Annual Report on Form 10-K and Exhibit 99.01 hereto.



Management's Strategic Plans

Xcel Energy's corporate strategy focuses on the following primary objectives:

Driving operational excellence;

Providing options and solutions to customers;

Investing for the future; and

Enhancing engagement with employees, customers, shareholders, communities

and policy makers.



These objectives are designed to provide our investors an attractive total return and our customers with clean, safe, reliable energy at a competitive price. Below is a discussion of these objectives and how they support our overall strategy.

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Driving operational excellence

Managing our operational performance and satisfying our customers has and will continue to be a fundamental priority. However, operational excellence also includes managing costs. By building on past success, leveraging technology, managing risks and continuously striving to improve our processes, we can bend the cost curve downward. Over the next five years, Xcel Energy is planning to implement cost saving measures which are intended to align increases in O&M expense more closely to sales growth. Our financial objective is to slow our annual O&M expense growth to approximately zero percent to two percent. However, we will not sacrifice reliability or safety to meet this initiative.



Providing options and solutions to customers

Adapting to a changing environment is critical to our success. Our customers expect to be offered choices and we are committed to providing options and solutions that are fair and satisfy their needs. Environmental leadership is a core priority and is designed to meet customer and policy maker expectations for clean energy at a competitive price while creating shareholder value. We will continue to offer and expand our production of renewable energy, including wind and solar alternatives, and further develop DSM, conservation and renewable programs.



Investing for the future

Sound investments today are necessary for tomorrow's success. From 2014 through 2018, we anticipate investing approximately $14.1 billion in our utility businesses, which will grow rate base at a compounded average annual rate of approximately 5.4 percent. Our capital investment plan is primarily intended to take advantage of opportunities to grow the business, refresh our infrastructure, reduce emissions and improve reliability. Xcel Energy has a proven record for making sound investments, including proactive and forward-looking decisions to balance its generation portfolio and expand alternative energy production. Our customers, stakeholders and the environment are currently benefiting from these decisions and will continue to do so in the future. Organic growth will remain a priority, but ventures such as transmission related projects outside our established footprint are also being considered.



Enhancing engagement with employees, customers, shareholders, communities and policy makers

Engagement starts with our employees and creating a productive place to work. Providing the right tools and opportunities to our employees is important not only for their future development, but the future of Xcel Energy. Communicating with customers, shareholders, communities and policymakers is also crucial to enhancing our business relationships and overall engagement. Maintaining a constructive regulatory environment is a key part of our overall strategy. We plan to further improve the regulatory compact by proposing additional rate mitigation methodologies, rider mechanisms and continuing to negotiate multi-year rate agreements.



Provide an attractive total return

Successful execution of our strategic plan should allow Xcel Energy to deliver an attractive total return to our shareholders. Through a combination of earnings growth and dividend yield, we plan to:

Deliver long-term annual EPS growth of four percent to six percent, based

on a normalized 2013 EPS of $1.90 per share;

Deliver annual dividend increases of four percent to six percent; and

Maintain senior unsecured debt credit ratings in the BBB+ to A range.

We have successfully achieved our prior financial objectives and believe we are positioned to continue to achieve our value proposition. Our ongoing earnings have grown approximately 6.8 percent and our dividend has grown approximately 3.4 percent annually since 2005. In addition, our current senior unsecured debt credit ratings for Xcel Energy and it utility subsidiaries are in the BBB+ to A range. 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 the related notes to consolidated financial statements. 55



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The only common equity securities that are publicly traded are common shares of Xcel Energy Inc. The earnings and EPS as well as the ROE of each subsidiary discussed below do not represent a direct legal interest in the assets and liabilities allocated to such subsidiary but rather represent a direct interest in our assets and liabilities as a whole. Ongoing diluted EPS and ongoing ROE for Xcel Energy and by subsidiary are financial measures not recognized under GAAP. Ongoing diluted EPS is calculated by dividing the net income or loss attributable to the controlling interest of each subsidiary, adjusted for certain nonrecurring items, by the weighted average fully diluted Xcel Energy Inc. common shares outstanding for the period. Ongoing ROE is calculated by dividing the net income or loss attributable to the controlling interest of Xcel Energy or each subsidiary, adjusted for certain nonrecurring items, by each entity's average common stockholders' or stockholder's equity. We use these non-GAAP financial measures to evaluate and provide details of earnings results. We believe that these measurements are useful to investors to evaluate the actual and projected financial performance and contribution of our subsidiaries. These non-GAAP financial measures should not be considered as alternatives to measures calculated and reported in accordance with GAAP.



Results of Operations

The following table summarizes the diluted EPS for Xcel Energy and subsidiaries: Diluted Earnings (Loss) Per Share

2013 2012 2011 PSCo $ 0.91$ 0.90$ 0.82 NSP-Minnesota 0.79 0.70 0.73 SPS 0.23 0.22 0.18 NSP-Wisconsin 0.12 0.10 0.10



Equity earnings of unconsolidated subsidiaries 0.04 0.04 0.04 Regulated utility

2.09 1.96



1.87

Xcel Energy Inc. and other costs (0.14 ) (0.14 ) (0.15 ) Ongoing diluted earnings per share 1.95 1.82



1.72

SPS 2004 FERC complaint case orders (0.04 ) - - Prescription drug tax benefit - 0.03 - GAAP diluted earnings per share $ 1.91$ 1.85 $



1.72

Ongoing earnings exclude adjustments for certain items. For 2013, the adjustment is related to the SPS 2004 FERC complaint case orders. For 2012, the adjustment is related to the Patient Protection and Affordable Care Act. See below under Adjustments to GAAP Earnings and Note 12 and Note 6 to the consolidated financial statements for further discussion, respectively, for the 2013 and 2012 adjustments. Xcel Energy's management believes that ongoing earnings reflects management's performance in operating the company and provides a meaningful representation of the performance of Xcel Energy's core business. In addition, Xcel Energy's management uses ongoing earnings internally for financial planning and analysis, for reporting of results to the Board of Directors and when communicating its earnings outlook to analysts and investors.



2013 Adjustment to GAAP Earnings

SPS FERC Orders - As a result of the two orders issued in August 2013 by the FERC for a potential SPS customer refund, a pre-tax charge of $36 million was recorded in 2013. Of this amount, approximately $30 million ($26 million revenue reduction and $4 million of interest) was attributable to periods prior to 2013 and not representative of ongoing earnings. As such, GAAP earnings include the total after tax amount of $24.4 million and ongoing earnings exclude $20.2 million. See Note 12 to the consolidated financial statements for further discussion.



2012 Adjustment to GAAP Earnings

Prescription drug tax benefit - In the third quarter of 2012, Xcel Energy implemented a tax strategy related to the allocation of funding of Xcel Energy's retiree prescription drug plan. This strategy restored a portion of the tax benefit associated with federal subsidies for prescription drug plans that had been accrued since 2004 and was expensed in 2010. As a result, Xcel Energy recognized approximately $17 million, or $0.03 per share, of income tax benefit. See Note 6 to the consolidated financial statements for further discussion. 56



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Earnings Adjusted for Certain Items (Ongoing EPS)

2013 Comparison with 2012

Xcel Energy - Overall, ongoing earnings increased $0.13 per share for 2013. Ongoing earnings increased as a result of higher electric and gas margins due to rate increases in various states, the impact of favorable colder weather on the natural gas business and reduced interest charges. These positive factors were partially offset by planned increases in O&M expenses and depreciation. PSCo - PSCo's ongoing earnings increased $0.01 per share for 2013. Ongoing earnings increased as a result of higher gas and electric margins primarily due to rate increases, the impact of cooler weather on natural gas margins and lower interest charges, partially offset by higher depreciation, O&M expenses and customer refunds related to the 2013 electric earnings test refund obligation. NSP-Minnesota - NSP-Minnesota's ongoing earnings increased $0.09 per share for 2013. Ongoing earnings were positively impacted by electric rate increases in Minnesota and South Dakota, interim rates subject to refund in North Dakota, the impact of cooler winter weather and lower interest charges. These items were partially offset by higher O&M expenses. SPS - SPS' ongoing earnings increased $0.01 per share for 2013. Electric rate increases in Texas and the gain associated with the sale of certain transmission assets to Sharyland were partially offset by higher depreciation. NSP-Wisconsin - NSP-Wisconsin's ongoing earnings increased $0.02 per share for 2013. Higher ongoing earnings from electric and natural gas rates and cooler winter weather were partially offset by higher O&M expenses and depreciation.



2012 Comparison with 2011

Xcel Energy - Overall, ongoing earnings increased $0.10 per share for 2012. Ongoing earnings increased largely due to increases in electric margins driven by the conclusion of various rate cases, which reflect our continued investment in our utility business and a lower ETR. Partially offsetting these positive factors were warmer than normal winter weather, increases in depreciation expense, O&M expenses and property taxes. PSCo - PSCo's ongoing earnings increased $0.08 per share for 2012. The increase is primarily due to an electric rate increase, effective May 2012, and the impact of warmer summer weather. The increase was partially offset by decreased wholesale revenue due to the expiration of a long-term power sales agreement with Black Hills Corp, higher depreciation expense and O&M expenses. NSP-Minnesota - NSP-Minnesota's 2012 ongoing earnings decreased $0.03 per share. The decrease is primarily due to the unfavorable impact of warmer than normal winter weather during the first quarter, electric sales decline and higher property taxes, O&M expenses and depreciation expense. These decreases were partially offset by the 2012 rate increase and a lower ETR. SPS - SPS' ongoing earnings increased $0.04 per share for 2012. The increase is the result of rate increases in New Mexico and Texas, effective January 2012, partially offset by the impact of milder weather during the second half of the year, higher depreciation expense and property taxes. NSP-Wisconsin - NSP-Wisconsin's ongoing earnings were flat for 2012. Ongoing earnings were positively impacted by rate increases, effective January 2012, offset by higher O&M expenses. 57



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Changes in Diluted EPS

The following table summarizes significant components contributing to the changes in 2013 EPS compared with the same period in 2012. See further discussion below. Diluted Earnings (Loss) Per Share

Dec. 31 2012 GAAP diluted earnings per share $ 1.85 Prescription drug tax benefit (0.03 ) 2012 ongoing diluted earnings per share



1.82

Components of change - 2013 vs. 2012 Higher electric margins (excludes impact of SPS 2004 FERC complaint case orders) 0.18 Higher natural gas margins 0.08 Higher AFUDC - equity 0.05



Lower interest charges (excludes impact of SPS 2004 FERC complaint case orders)

0.04

Gain on sale of transmission assets (included in O&M expenses)



0.02

Higher O&M expenses (excludes gain on sale of transmission assets)

(0.14 ) Higher depreciation and amortization



(0.06 ) Dilution from at-the-market program, direct stock purchase plan and benefit plans

(0.03 ) Higher taxes (other than income taxes) (0.01 ) 2013 ongoing diluted earnings per share



1.95

SPS 2004 FERC complaint case orders (0.04 ) 2013 GAAP diluted earnings per share



$ 1.91

Diluted Earnings (Loss) Per Share Dec. 31 2011 GAAP and ongoing diluted earnings per share



$ 1.72

Components of change - 2012 vs. 2011 Higher electric margins



0.15

Lower ETR



0.04

Lower conservation and DSM expenses (generally offset in revenues)

0.03 Higher AFUDC - equity 0.02 Higher natural gas margins 0.01 Higher O&M expenses (0.05 ) Higher depreciation and amortization (0.04 ) Higher taxes (other than income taxes) (0.04 ) Higher interest charges (0.01 ) Other, net (including interest and premium on redemption of preferred stock) (0.01 ) 2012 ongoing diluted earnings per share



1.82

Prescription drug tax benefit



0.03

2012 GAAP diluted earnings per share



$ 1.85

The following table summarizes the ROE for Xcel Energy and subsidiaries: ROE - 2013

PSCo NSP-Minnesota SPS NSP-Wisconsin Xcel Energy 2013 ongoing ROE 9.66 % 9.24 % 9.03 % 10.61 % 10.50 % SPS 2004 FERC complaint case orders - - (1.54 ) - (0.22 ) 2013 GAAP ROE 9.66 % 9.24 % 7.49 % 10.61 % 10.28 % ROE - 2012 PSCo NSP-Minnesota SPS NSP-Wisconsin Xcel Energy 2012 ongoing ROE 9.92 % 8.77 % 9.44 % 9.62 % 10.24 % Prescription drug tax benefit 0.38 - - - 0.19 2012 GAAP ROE 10.30 % 8.77 % 9.44 % 9.62 % 10.43 % 58



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The following tables provide reconciliations of ongoing to GAAP earnings (net income) and ongoing to GAAP diluted earnings per share for the years ended Dec. 31: (Millions of Dollars) 2013 2012 2011 Ongoing earnings $ 968.4$ 888.3$ 840.7 SPS 2004 FERC complaint case orders (2013), prescription drug tax benefit (2012) and COLI settlement (2011) (20.2 ) 16.9 0.5 GAAP earnings $ 948.2$ 905.2$ 841.2 Diluted Earnings (Loss) Per Share 2013 2012 2011 Ongoing diluted earnings per share (a) $ 1.95$ 1.82$ 1.72 SPS 2004 FERC complaint case orders (2013), prescription drug tax benefit (2012) and COLI settlement (2011) (0.04 ) 0.03 - GAAP diluted earnings per share (a) $ 1.91 $



1.85 $ 1.72

(a) Includes the dividend requirements on preferred stock in 2011.

The following tables summarize the earnings contributions of Xcel Energy's business segments. (Millions of Dollars)

2013 2012 2011 GAAP income (loss) by segment Regulated electric income $ 850.7$ 851.9$ 789.0 Regulated natural gas income 123.7 98.1 101.8 Other income (a) 44.6 22.1 17.9



Xcel Energy Inc. and other costs (a) (70.8 ) (66.9 ) (67.5 ) Total net income

$ 948.2$ 905.2$ 841.2



Contributions to Diluted Earnings (Loss) Per Share 2013 2012

2011

GAAP earnings (loss) by segment Regulated electric $ 1.71$ 1.74$ 1.62 Regulated natural gas 0.25 0.20 0.21 Other (a) 0.09 0.05 0.04 Xcel Energy Inc. and other costs (a) (b) (0.14 ) (0.14 ) (0.15 ) Total diluted earnings per share (b) $ 1.91$ 1.85



$ 1.72

(a) Not a reportable segment. Included in all other segment results in Note 17

to the consolidated financial statements.

(b) Includes the dividend requirements on preferred stock (2011).

Statement of Income Analysis

The following discussion summarizes the items that affected the individual revenue and expense items reported in the consolidated statements of income.

Estimated Impact of Temperature Changes on Regulated Earnings - Unusually hot summers or cold winters increase electric and natural gas sales while, conversely, mild weather reduces electric and natural gas sales. The estimated 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 uses per degree of temperature. Accordingly, deviations in weather from normal levels can affect Xcel Energy's financial performance, from both an energy and demand perspective. 59



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Degree-day or Temperature-Humidity Index (THI) data is used to estimate amounts of energy required to maintain comfortable indoor temperature levels based on each day's average temperature and humidity. Heating degree-days (HDD) is the measure of the variation in the weather based on the extent to which the average daily temperature falls below 65 Fahrenheit, and cooling degree-days (CDD) is the measure of the variation in the weather based on the extent to which the average daily temperature rises above 65 Fahrenheit. Each degree of temperature above 65 Fahrenheit is counted as one cooling degree-day, and each degree of temperature below 65 Fahrenheit is counted as one heating degree-day. In Xcel Energy's more humid service territories, a THI is used in place of CDD, which adds a humidity factor to CDD. HDD, CDD and THI are most likely to impact the usage of Xcel Energy's residential and commercial customers. Industrial customers are less sensitive to weather. Normal weather conditions are defined as either the 20-year or 30-year average of actual historical weather conditions. The historical period of time used in the calculation of normal weather differs by jurisdiction based on the time period used by the regulator in establishing estimated volumes in the rate setting process. To calculate the impact of weather on demand, a demand factor is applied to the weather impact on sales as defined above to derive the amount of demand associated with the weather impact.



The percentage increase (decrease) in normal and actual HDD, CDD and THI are provided in the following table:

2013 vs. 2012 vs. 2013 vs. 2011 vs. 2012 vs. Normal Normal 2012 Normal 2011 HDD 6.5 % (15.9 )% 25.8 % (1.0 )% (14.8 )% CDD 24.7 46.1 (13.6 ) 38.1 5.7 THI 21.8 36.1 (9.7 ) 37.9 (0.2 )



Weather - The following table summarizes the estimated impact of temperature variations on EPS compared with sales under normal weather conditions:

2013 vs. 2012 vs. 2013 vs. 2011 vs. 2012 vs. Normal Normal 2012 Normal 2011 Retail electric $ 0.088$ 0.081$ 0.007$ 0.080$ 0.001 Firm natural gas 0.021 (0.033 ) 0.054 0.002 (0.035 ) Total $ 0.109$ 0.048$ 0.061$ 0.082$ (0.034 )



Sales Growth (Decline) - The following tables summarize Xcel Energy's sales growth (decline) for actual and weather-normalized sales for the years ended Dec. 31, compared with the previous year:

Dec. 31, 2013 Dec. 31, 2013 (Without 2012 Leap Day) Weather Weather Actual Normalized Actual Normalized Electric residential 1.1 % 0.2 % 1.4 % 0.5 % Electric commercial and industrial - 0.1 0.3 0.4 Total retail electric sales 0.3 0.1 0.6 0.4 Firm natural gas sales (a) 21.3 3.3 21.9 3.8 Dec. 31, 2012 Dec. 31, 2012 (Without Leap Day) Weather Weather Actual Normalized Actual Normalized Electric residential (1.0 )% (0.1 )% (1.2 )% (0.4 )% Electric commercial and industrial 0.1 - (0.2 ) (0.2 ) Total retail electric sales (0.3 ) - (0.5 ) (0.3 ) Firm natural gas sales (a) (10.6 ) (0.3 ) (11.0 ) (0.8 )



(a) Extreme weather variations and additional factors such as windchill and

cloud cover may not be reflected in weather normalization and growth estimates.



Weather-normalized sales for 2014 are projected to increase by approximately 0.5 percent for retail electric customers and to decline by approximately 0.0 percent to 2.0 percent for retail firm natural gas customers.

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Electric Revenues and Margin

Electric revenues and fuel and purchased power expenses are largely impacted by the fluctuation in the price of natural gas, coal and uranium used in the generation of electricity, but as a result of the design of fuel recovery mechanisms to recover current expenses, these price fluctuations have little impact on electric margin. The following table details the electric revenues and margin: (Millions of Dollars) 2013 2012 2011 Electric revenues $ 9,034$ 8,517$ 8,767



Electric fuel and purchased power (4,019 ) (3,624 ) (3,992 ) Electric margin

$ 5,015$ 4,893$ 4,775



The following tables summarize the components of the changes in electric revenues and electric margin for the years ended Dec. 31:

Electric Revenues (Millions of Dollars) 2013 vs. 2012



Fuel and purchased power cost recovery $ 360 Retail rate increases (a)

229 Transmission revenue 68 Non-fuel riders 18 Estimated impact of weather 7 PSCo earnings test refund obligation (43 ) Firm wholesale (36 ) Conservation and DSM program incentives (24 ) Trading (19 ) SPS 2004 FERC complaint case orders (b) (6 ) Other, net (11 ) Total increase in ongoing electric revenues 543 SPS 2004 FERC complaint case orders (b) (26 )



Total increase in GAAP electric revenues $ 517

2013 Comparison with 2012 - Electric revenues increased primarily due to higher fuel and purchased power cost recovery, which is offset in operating expense, and various rate increases across all of the utility subsidiaries. Electric Margin (Millions of Dollars) 2013 vs. 2012 Retail rate increases (a) $ 229 Transmission revenue, net of costs 36 Non-fuel riders 18 Estimated impact of weather 7 PSCo earnings test refund obligation (43 ) Conservation and DSM program incentives (24 ) Firm wholesale (24 ) Trading margin (12 ) SPS 2004 FERC complaint case orders (b) (6 ) Other, net (33 ) Total increase in ongoing electric margin 148 SPS 2004 FERC complaint case orders (b) (26 )



Total increase in GAAP electric margin $ 122

(a) The retail rate increases include final rates in Minnesota, Colorado,

Wisconsin, South Dakota and Texas and interim rates, subject to refund, in

North Dakota. The Minnesota rate increase is net of a provision for customer

refunds of $131 million for the twelve months ended Dec. 31, 2013 based on

the final rate order received for the 2013 electric rate case. Due to the order, there was a reduction in revenues and expenses of approximately $40



million, primarily related to depreciation of $32 million and O&M expense of

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(b) As a result of two orders issued by the FERC in August 2013, a pretax charge

of approximately $36 million ($32 million in electric revenues, of which $6

million relates to 2013 and $26 million relates to periods prior to 2013,

and $4 million in interest charges) was recorded in 2013. See Note 12 to the

consolidated financial statements.

2013 Comparison to 2012 - The increase in electric margin was primarily due to the various rate increases across all of the utility subsidiaries.

Electric Revenues (Millions of Dollars) 2012 vs. 2011 Fuel and purchased power cost recovery $ (394 ) Firm wholesale (a) (58 ) Retail sales decrease, excluding weather impact (6 ) Conservation and DSM revenue (offset by expenses) (5 ) Retail rate increases (Colorado, Texas, New Mexico, Wisconsin, South Dakota, North Dakota, Michigan and Minnesota) 125 Transmission revenue 44 Demand revenue 13 Conservation and DSM incentive 12 Estimated impact of weather 1 Other, net 18 Total decrease in electric revenue $



(250 )

2012 Comparison with 2011 - Electric revenues decreased primarily due to lower fuel and purchased power cost recovery, which is offset in operating expense. This decrease was partially offset by the various rate increases across all of the utility subsidiaries. Electric Margin (Millions of Dollars) 2012 vs. 2011 Retail rate increases (Colorado, Texas, New Mexico, Wisconsin, South Dakota, North Dakota, Michigan and Minnesota) $



125

Demand revenue



13

Transmission revenue, net of costs



13

Conservation and DSM incentive 12 Estimated impact of weather 1 Firm wholesale (a) (48 ) Retail sales decrease, excluding weather impact (6 ) Conservation and DSM revenue (offset by expenses) (5 ) Other, net



13

Total increase in electric margin $



118

(a) Decrease is primarily due to the expiration of a long-term wholesale power

sales agreement with Black Hills Corp., effective Jan. 1, 2012.

2012 Comparison to 2011 - The increase in electric margin was primarily due to the various rate increases across all of the utility subsidiaries.

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Natural Gas Revenues and Margin

The cost of natural gas tends to vary with changing sales requirements and the cost of natural gas purchases. However, due to the design of purchased natural gas cost recovery mechanisms to recover current expenses for sales to retail customers, fluctuations in the cost of natural gas have little effect on natural gas margin. The following table details natural gas revenues and margin: (Millions of Dollars) 2013 2012 2011 Natural gas revenues $ 1,805$ 1,537$ 1,812



Cost of natural gas sold and transported (1,083 ) (881 ) (1,164 ) Natural gas margin

$ 722$ 656$ 648



The following tables summarize the components of the changes in natural gas revenues and natural gas margin for the years ended Dec. 31:

Natural Gas Revenues (Millions of Dollars) 2013 vs. 2012 Purchased natural gas adjustment clause recovery $ 198 Estimated impact of weather 42 Retail rate increases (Colorado and Wisconsin) 15 Retail sales growth 9 Conservation and DSM program incentives 5 Conservation and DSM program revenues (offset by expenses) 4 Other, net (5 ) Total increase in natural gas revenues $ 268 2013 Comparison to 2012 - Natural gas revenues increased primarily due to the purchased natural gas adjustment clause recovery, which is offset in operating expense. Natural Gas Margin (Millions of Dollars) 2013 vs. 2012 Estimated impact of weather $ 42 Retail rate increases (Colorado and Wisconsin) 15 Retail sales growth 9 Conservation and DSM program incentive 5 Conservation and DSM program revenues (offset by expenses) 4 Other, net (9 ) Total increase in natural gas margin $ 66



2013 Comparison to 2012 - Natural gas margins increased primarily due to cooler winter weather and rate increases in Colorado and Wisconsin.

Natural Gas Revenues (Millions of Dollars) 2012 vs. 2011



Purchased natural gas adjustment clause recovery $ (282 ) Estimated impact of weather

(26 ) Conservation and DSM revenue (offset by expenses) (17 ) PSIA rider (Colorado), offset by expenses 29 Retail rate increase (Colorado, Wisconsin) 16 Other, net 5 Total decrease in natural gas revenues $ (275 ) 63



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2012 Comparison to 2011 - Natural gas revenues decreased primarily due to the purchased natural gas adjustment clause recovery, which is offset in operating expense. Natural Gas Margin (Millions of Dollars) 2012 vs. 2011 PSIA rider (Colorado) offset by expenses $ 29 Retail rate increase (Colorado, Wisconsin) 16 Estimated impact of weather (26 ) Conservation and DSM revenue (offset by expenses) (17 ) Other, net 6 Total increase in natural gas margin $ 8



2012 Comparison to 2011 - Natural gas margins increased primarily due to the PSIA rider, which is offset in operating expense.

Non-Fuel Operating Expenses and Other Items

O&M Expenses - O&M expenses increased $97.4 million, or 4.5 percent, for 2013 compared with 2012, and by $35.8 million, or 1.7 percent, for 2012 compared with 2011. The following tables summarize the changes in O&M expenses: (Millions of Dollars) 2013 vs. 2012



Electric and gas distribution expenses $ 44 Nuclear plant operations and amortization

33 Transmission costs 13 Employee benefits 7 Gain on sale of transmission assets (14 ) Other, net 14 Total increase in O&M expenses $ 97



2013 Comparison to 2012 - The increase in O&M expenses for 2013 was largely driven by the following:

Electric and gas distribution expenses were primarily driven by increased

maintenance activities due to vegetation management, storms and outages;

Nuclear cost increases are related to the amortization of prior outages

and initiatives designed to improve the operational efficiencies of the plants;



Increased transmission costs were related to higher substation maintenance

expenditures and reliability costs;

Higher employee benefits related primarily to increased pension expense; and

See Note 12 to the consolidated financial statements for further discussion of the gain on sale of transmission assets. (Millions of Dollars) 2012 vs. 2011 Employee benefits $ 36 Pipeline system integrity costs 20 SmartGridCity 11 Prairie Island EPU 10 Plant generation costs (17 ) Bad debt expense (10 ) Labor and contract labor (2 ) Other, net (12 )



Total increase in O&M expenses $ 36

2012 Comparison to 2011 - The increase in O&M expenses for 2012 was largely driven by the following:

Higher employee benefits are mainly due to increased pension expenses.

Higher pipeline system integrity costs relate to increased compliance and

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See Note 12 to the consolidated financial statements for further discussion of SmartGridCity and Prairie Island EPU. Lower plant generation costs are primarily attributable to fewer plant overhauls in 2012. Conservation and DSM Program Expenses - Conservation and DSM program expenses decreased $20.9 million, or 7.4 percent, for 2012 compared with 2011. The lower expenses are primarily attributable to lower gas rider rates, as well as the timing of recovery of electric CIP expenses at NSP-Minnesota. Conservation and DSM program expenses are generally recovered in our major jurisdictions concurrently through riders and base rates. Overall, the programs are designed to encourage the operating companies and their retail customers to conserve energy or change energy usage patterns in order to reduce peak demand on the gas or electric system. This, in turn, reduces the need for additional plant capacity, reduces emissions, serves to achieve other environmental goals as well as reduces energy costs to participating customers. Depreciation and Amortization - Depreciation and amortization increased $51.8 million, or 5.6 percent, for 2013 compared with 2012. The increase is primarily attributable to normal system expansion, which was partially offset by reductions related to the final rate order received for the 2013 Minnesota electric rate case that reduced depreciation expense by approximately $32 million for 2013. Depreciation and amortization increased $35.4 million, or 4.0 percent, for 2012 compared with 2011. The increase is primarily due to a portion of the Monticello EPU going into service in May 2011 at NSP-Minnesota, the Jones Unit 3 going into service in June 2011 at SPS and normal system expansion across Xcel Energy's service territories.



Taxes (Other Than Income Taxes) - Taxes (other than income taxes) increased $11.6 million, or 2.8 percent, for 2013 compared with 2012. The annual increase is due to higher property taxes primarily in Colorado and Texas.

Taxes (other than income taxes) increased $34.1 million, or 9.1 percent, for 2012 compared with 2011. The increases are due to an increase in property taxes primarily in Minnesota. Higher property taxes in Colorado related to the electric retail business are being deferred, based on the multi-year rate settlement approved by the CPUC in May 2012. AFUDC, Equity and Debt - AFUDC increased $28.7 million for 2013 compared with 2012. The increase is primarily due to construction related to the CACJA and the expansion of transmission facilities.



AFUDC increased $18.8 million for 2012, compared with 2011. The increase is primarily due to the expansion of PSCo's transmission facilities, additional construction related to the Colorado CACJA and life extension work at the Prairie Island nuclear generating plant.

Interest Charges - Interest charges decreased $26.4 million, or 4.4 percent, for 2013 compared with 2012. The decrease is primarily due to refinancings at lower interest rates. This was partially offset by higher long-term debt levels, $4 million of interest associated with the customer refund at SPS based on the August 2013 FERC orders, $5 million of interest associated with customer refunds in Minnesota for the 2013 electric rate case and the write off of $6.3 million of unamortized debt expense related to the junior subordinated notes called in May 2013. Interest charges increased $10.5 million, or 1.8 percent for 2012 compared with 2011. The increase is due to higher long-term debt levels to fund investment in utility operations, partially offset by lower interest rates. Income Taxes - Income tax expense increased $33.8 million for 2013 compared with 2012. The increase in income tax expense was primarily due to higher pretax earnings in 2013, a tax benefit for a carryback in 2012 and for the restoration in 2012 of a portion of the tax benefit associated with federal subsidies for prescription drug plans that was previously written off in 2010. These were partially offset in 2013 by a tax benefit for a carryback claim related to 2013, research and experimentation credits and increased permanent plant-related reductions. The ETR was 33.8 percent for 2013 compared with 33.2 percent for 2012. The higher ETR for 2013 was primarily due to the adjustments referenced above. See Note 6 to the consolidated financial statements for further discussion. Income tax expense decreased $18.1 million for 2012 compared with 2011. The decrease in income tax expense was primarily due to a tax benefit associated with a carryback and a tax benefit related to the restoration of a portion of the tax benefit written off in 2010 associated with federal subsidies for prescription drug plans. As a result, Xcel Energy recognized tax benefits of approximately $14.9 million for the carryback and $17 million for the tax benefit associated with the federal subsidies. These were partially offset by higher pretax income in 2012. The ETR was 33.2 percent for 2012, compared with 35.8 percent for 2011. The lower ETR for 2012 was primarily due to the adjustments referenced above. The ETR would have been 35.6 percent for 2012 without these tax benefits. 65



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Premium on Redemption of Preferred Stock - Xcel Energy Inc. redeemed all series of its preferred stock on Oct. 31, 2011, at an aggregate purchase price of $108 million, plus accrued dividends. As such, the redemption premium of $3.3 million and accrued dividends are reflected as reductions to earnings available to common shareholders for 2011.



Xcel Energy Inc. and Other Results

The following tables summarize the net income and EPS contributions of Xcel Energy Inc. and its nonregulated businesses:

Contribution to Xcel Energy's Earnings (Millions of Dollars) 2013 2012 2011 Xcel Energy Inc. financing costs $ (62.9 )$ (71.5 )$ (63.8 ) Eloigne (a) (0.8 ) 3.8 (2.9 ) Xcel Energy Inc. taxes and other results (7.1 ) 0.8 (0.6 ) Total Xcel Energy Inc. and other costs (70.8 ) (66.9 ) (67.3 ) Preferred dividends - - (6.8 ) Total Xcel Energy Inc. and other costs, available to common shareholders $ (70.8 )$ (66.9 )$ (74.1 ) Contribution to Xcel Energy's Earnings per Share (Earnings per Share) 2013 2012 2011 Xcel Energy Inc. financing costs $ (0.13 ) $ (0.15 ) $ (0.13 ) Eloigne (a) - 0.01 (0.01 ) Xcel Energy Inc. taxes and other results (0.01 ) - - Preferred dividends - - (0.01 ) Total Xcel Energy Inc. and other costs $ (0.14 )



$ (0.14 ) $ (0.15 )

(a) Amounts include gains or losses associated with sales of properties held by

Eloigne.



Xcel Energy Inc.'s results include interest charges and the EPS impact of preferred dividends, which are incurred at Xcel Energy Inc. and are not directly assigned to individual subsidiaries.

Factors Affecting Results of Operations

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 those listed below.



General Economic Conditions

Economic conditions may have a material impact on Xcel Energy's operating results. Management cannot predict the impact of a prolonged economic recession, fluctuating energy prices, terrorist activity, war or the threat of war. However, Xcel Energy could experience a material impact to its results of operations, future growth or ability to raise capital resulting from a sustained general slowdown in economic growth or a significant increase in interest rates.



Fuel Supply and Costs

Xcel Energy Inc.'s operating utilities have varying dependence on coal, natural gas and uranium. Changes in commodity prices are generally recovered through fuel recovery mechanisms and have very little impact on earnings. However, availability of supply, the potential implementation of a carbon tax and unanticipated changes in regulatory recovery mechanisms could impact our operations. See Item 1 for further discussion of fuel supply and costs. 66



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Pension Plan Costs and Assumptions

Xcel Energy has significant net pension and postretirement benefit costs that are measured using actuarial valuations. Inherent in these valuations are key assumptions including discount rates and expected return on plan assets. Xcel Energy evaluates these key assumptions at least annually by analyzing current market conditions, which include changes in interest rates and market returns. Changes in the related net pension and postretirement benefits costs and funding requirements may occur in the future due to changes in assumptions. The payout of a significant percentage of pension plan liabilities in a single year due to high retirements or employees leaving the company would trigger settlement accounting and could require the company to recognize material incremental pension expense related to unrecognized plan losses in the year these liabilities are paid. For further discussion and a sensitivity analysis on these assumptions, see "Employee Benefits" under Critical Accounting Policies and Estimates.



Regulation

FERC and State Regulation - The FERC and various state and local regulatory commissions regulate Xcel Energy Inc.'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 Inc.'s utility subsidiaries are approved by the FERC or the regulatory commissions in the states in which they operate. The rates are 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. Changes in operating costs can affect Xcel Energy's financial results, depending on the timing of filing general rate cases and the implementation of final rates. In addition to changes in operating costs, other factors affecting rate filings are new investments, sales, which are affected by overall economic conditions, conservation and DSM efforts, and the cost of capital. In addition, the regulatory commissions authorize the ROE, capital structure and depreciation rates in rate proceedings. Wholesale Energy Market Regulation - Wholesale energy markets in the Midwest and South Central U.S. are operated by MISO and SPP, respectively, to centrally dispatch all regional electric generation and apply a regional transmission congestion management system. NSP-Minnesota and NSP-Wisconsin are members of MISO and SPS is a member of SPP. NSP-Minnesota, NSP-Wisconsin and SPS expect to recover energy charges through either base rates or various recovery mechanisms. See Note 12 to the consolidated financial statements for further discussion. Capital Expenditure Regulation - Xcel Energy Inc.'s utility subsidiaries make substantial investments in plant additions to build and upgrade power plants, and expand and maintain the reliability of the energy transmission and distribution systems. In addition to filings for increases in base rates charged to customers to recover the costs associated with such investments, the CPUC, MPUC, SDPUC, NDPSC and PUCT in certain instances have approved proposals to recover, through a rate rider, costs to upgrade generation plants and lower emissions, increase transmission investment cost, and/or increase distribution investment cost, and increase purchased power capacity cost. These non-fuel rate riders are expected to provide significant cash flows to enable recovery of costs incurred on a timely basis. For wholesale electric transmission and production services, Xcel Energy has, consistent with FERC policy, implemented formula rates for each of the utility subsidiaries that will provide annual rate changes as transmission or production investments increase in a manner similar to the retail rate riders. NSP-Minnesota and NSP-Wisconsin have no cost-based wholesale production customers and therefore have not implemented a production formula rate. Environmental Matters Environmental costs include accruals for nuclear plant decommissioning and payments for storage of spent nuclear fuel, disposal of hazardous materials and waste, remediation of contaminated sites, monitoring of discharges to the environment and compliance with laws and permits with respect to emissions. A trend of greater environmental awareness and increasingly stringent regulation 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:



$275 million in 2013;

$263 million in 2012; and

$265 million in 2011. 67



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Xcel Energy estimates an average annual expense of approximately $320 million from 2014 through 2018 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 may fluctuate. Capital expenditures for environmental improvements at regulated facilities were approximately: $517 million in 2013; $255 million in 2012; and $48 million in 2011.



See Item 7 - Capital Requirements for further discussion.

Xcel Energy's operations are subject to federal and state laws and regulations related to air emissions, water discharges and waste management. These laws and regulations regulate air emissions from various sources, including electrical generating units, and impose certain monitoring and reporting requirements. Such laws and regulations may require Xcel Energy to obtain pre-approval for the construction or modification of certain projects that increase air emissions, obtain and strictly comply with air permits that contain emission and operational limitations, or install or operate pollution control equipment at facilities. Xcel Energy will likely be required to incur capital expenditures in the future to comply with these requirements for remediation plans of MGP sites and various regulations for air emissions and water intake. Actual expenditures could be higher or lower than the estimates presented and the scope and timing of these expenditures cannot be fully determined until any new or revised regulations become final. In 2011, the EPA issued the CSAPR to address long range transport of PM and ozone by requiring reductions in SO2 and NOx from utilities in the eastern half of the United States. In August 2012, the D.C. Circuit vacated the CSAPR and remanded it back to the EPA. The D.C. Circuit stated that the EPA must continue administering the CAIR pending adoption of a valid replacement. In December 2013, the U.S. Supreme Court heard oral arguments on the D.C. Circuit's 2012 decision to vacate the CSAPR. A decision is anticipated by June 2014. It is not yet known whether the D.C. Circuit's decision will be upheld, or how the EPA might approach a replacement rule. Therefore, it is not known what requirements may be imposed in the future.



In addition, there are emission controls, known as BART, for industrial facilities releasing emissions that reduce visibility in certain national parks and wilderness areas. Xcel Energy generating facilities in Minnesota and Colorado are subject to BART requirements.

Further, generating facilities throughout the Xcel Energy territory are subject to state and federal mercury reduction requirements.

See Note 13 to the consolidated financial statements for further discussion of Xcel Energy's environmental contingencies.

Inflation

Inflation at its current level is not expected to materially affect Xcel Energy's prices or returns to shareholders. However, potential future inflation could result from economic conditions or the economic and monetary policies of the U.S. Government and the Federal Reserve. This could lead to future price increases for materials and services required to deliver electric and natural gas services to customers. These potential cost increases could in turn lead to increased prices to customers.



CRITICAL ACCOUNTING POLICIES AND ESTIMATES

Preparation of the consolidated financial statements and related disclosures in compliance with GAAP requires the application of accounting rules and guidance, as well as the use of estimates. The application of these policies involves judgments regarding future events, including the likelihood of success of particular projects, legal and regulatory challenges and anticipated recovery of costs. These judgments could materially impact the consolidated financial statements and disclosures, based on varying assumptions. In addition, the financial and operating environment also may have a significant effect on the operation of the business and on the results reported even if the nature of the accounting policies applied have not changed. The following is a list of accounting policies and estimates 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 likelihood of resulting in materially different reported amounts under different conditions or using different assumptions. Each critical accounting policy has been reviewed and discussed with the Audit Committee of Xcel Energy Inc.'s Board of Directors on a quarterly basis. 68



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Regulatory Accounting

Xcel Energy Inc. is a holding company with rate-regulated subsidiaries that are subject to the accounting for Regulated Operations, which provides that rate-regulated entities account for and report assets and liabilities consistent with the recovery of those incurred costs in rates, if the rates established are designed to recover the costs of providing the regulated service and if the competitive environment makes it probable that such rates will be charged and collected. Xcel Energy's rates are derived through the ratemaking process, which results in the recording of regulatory assets and liabilities based on the probability of future cash flows. Regulatory assets generally represent incurred or accrued costs that have been deferred because they are probable of future recovery from customers. Regulatory liabilities generally represent amounts that are expected to be refunded to customers in future rates or amounts collected in current rates for future costs. In other businesses or industries, regulatory assets and regulatory liabilities would generally be charged to net income or OCI. Each reporting period Xcel Energy assesses the probability of future recoveries and obligations associated with regulatory assets and liabilities. Factors such as the current regulatory environment, recently issued rate orders and historical precedents are considered. Decisions made by regulatory agencies can directly impact the amount and timing of cost recovery as well as the rate of return on invested capital and may materially impact Xcel Energy's results of operations, financial condition, or cash flows. As of Dec. 31, 2013 and 2012, Xcel Energy has recorded regulatory assets of $2.9 billion and $3.1 billion and regulatory liabilities of $1.3 billion and $1.2 billion, respectively. Each subsidiary is subject to regulation that varies from jurisdiction to jurisdiction. If future recovery of costs, in any such jurisdiction, ceases to be probable, Xcel Energy would be required to charge these assets to current net income or OCI. There are no current or expected proposals or changes in the regulatory environment that impact the probability of future recovery of these assets. However, if the SEC should mandate the use of IFRS and the lack of an accounting standard for rate-regulated entities under IFRS could require us to charge certain regulatory assets and regulatory liabilities to net income or OCI. See Note 15 to the consolidated financial statements for further discussion of regulatory assets and liabilities and Note 12 to the consolidated financial statements for further discussion of rate matters.



Income Tax Accruals

Judgment, uncertainty, and estimates are a significant aspect of the income tax accrual process that accounts for the effects of current and deferred income taxes. Uncertainty associated with the application of tax statutes and regulations and the outcomes of tax audits and appeals require that judgment and estimates be made in the accrual process and in the calculation of the ETR. Changes in tax laws and rates may affect recorded deferred tax assets and liabilities and our ETR in the future. ETRs are also highly impacted by assumptions. ETR calculations are revised every quarter based on best available year end tax assumptions (income levels, deductions, credits, etc.); adjusted in the following year after returns are filed, with the tax accrual estimates being trued-up to the actual amounts claimed on the tax returns; and further adjusted after examinations by taxing authorities have been completed.



In accordance with the interim period reporting guidance, income tax expense for the first three quarters in a year is based on the forecasted ETR.

Accounting for income taxes also requires that only tax benefits that meet the more likely than not recognition threshold can be recognized or continue to be recognized. The change in the unrecognized tax benefits needs to be reasonably estimated based on evaluation of the nature of uncertainty, the nature of event that could cause the change and an estimated range of reasonably possible changes. At any period end, and as new developments occur, management will use prudent business judgment to derecognize appropriate amounts of tax benefits. Unrecognized tax benefits can be recognized as issues are favorably resolved and loss exposures decline. As disputes with the IRS and state tax authorities are resolved over time, we may adjust our unrecognized tax benefits and interest accruals to the updated estimates needed to satisfy tax and interest obligations for the related issues. These adjustments may increase or decrease earnings. See Note 6 to the consolidated financial statements for further discussion. 69



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Employee Benefits

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 and postretirement health care investment assets will earn in the future and the interest rate used to discount future pension benefit payments to a present value obligation. In addition, the pension cost calculation uses an asset-smoothing methodology to reduce the volatility of varying investment performance over time. See Note 9 to the consolidated financial statements for further discussion on the rate of return and discount rate used in the calculation of pension costs and obligations. Pension costs are expected to decrease in 2014 and continue to decline in the following few years. Funding requirements are also expected to decline in 2014 and then be flat in the following years. While investment returns exceeded the assumed levels from 2009 through 2012, investment returns were slightly below the assumed levels in 2013. The pension cost calculation uses a market-related valuation of pension assets. Xcel Energy uses a calculated value method to determine the market-related value of the plan assets. The market-related value is determined by adjusting the fair market value of assets at the beginning of the year to reflect the investment gains and losses (the difference between the actual investment return and the expected investment return on the market-related value) during each of the previous five years at the rate of 20 percent per year. As these differences between the actual investment returns and the expected investment returns are incorporated into the market-related value, the differences are recognized in pension cost over the expected average remaining years of service for active employees. Based on current assumptions and the recognition of past investment gains and losses, Xcel Energy currently projects the pension costs recognized for financial reporting purposes will decrease from an expense of $151.8 million in 2013 and $127.1 million in 2012 to an expense of $126.8 million in 2014 and $109.0 million in 2015. The expected decrease in the 2014 expense is due primarily to an increase in the discount rate along with the reduced amortization of prior service costs and other historic loss amounts, including the 2008 market loss. Further, future year expenses are expected to decrease primarily as a result of reductions in loss amortizations and an increase in expected return on assets as a result of increases in assets via planned contributions and the subsequent expected return of current assets. At Dec. 31, 2013, Xcel Energy set the rate of return on assets used to measure pension costs at 7.05 percent, which is a 17 basis point increase from Dec. 31, 2012. The rate of return used to measure postretirement health care costs is 7.17 percent at Dec. 31, 2013 and is a six basis point increase from Dec. 31, 2012. Xcel Energy set the discount rates used to value the Dec. 31, 2013 pension and postretirement health care obligations at 4.75 percent and 4.82 percent, which represent a 75 basis point and 72 basis point increase from Dec. 31, 2012, respectively. Xcel Energy uses a bond matching study as its primary basis for determining the discount rate used to value pension and postretirement health care obligations. The bond matching study utilizes a portfolio of high grade (Aa or higher) bonds that matches the expected cash flows of Xcel Energy's benefit plans in amount and duration. The effective yield on this cash flow matched bond portfolio determines the discount rate for the individual plans. The bond matching study is validated for reasonableness against the Citigroup Pension Liability Discount Curve and the Citigroup Above Median Curve. At Dec. 31, 2013, these reference points supported the selected rate. In addition to these reference points, Xcel Energy also reviews general actuarial survey data to assess the reasonableness of the discount rate selected.



The following are the pension funding contributions, both voluntary and required, made by Xcel Energy for 2011 through 2014:

In January 2014, contributions of $130.0 million were made across three of

Xcel Energy's pension plans;

In 2013, contributions of $192.4 million were made across four of Xcel

Energy's pension plans;

In 2012, contributions of $198.1 million were made across four of Xcel

Energy's pension plans; and

In 2011, contributions of $137.3 million were made across three of Xcel

Energy's pension plans.

For future years, we anticipate contributions will be made as necessary. These contributions are summarized in Note 9 to the consolidated financial statements. Future year amounts are estimates and may change based on actual market performance, changes in interest rates and any changes in governmental regulations. Therefore, additional contributions could be required in the future. 70



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If Xcel Energy were to use alternative assumptions at Dec. 31, 2013, a one-percent change would result in the following impact on 2014 pension expense: Pension Costs (Millions of Dollars) +1% -1% Rate of return $ (25.1 )$ 25.5 Discount rate (11.2 ) 14.1



Effective Jan. 1, 2014, the initial medical trend assumption was decreased from 7.5 percent to 7.0 percent. The ultimate trend assumption remained at 4.5 percent. The period until the ultimate rate is reached is five 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 experienced by Xcel Energy's retiree medical plan.

Xcel Energy contributed $17.6 million, $47.1 million and $49.0 million

during 2013, 2012 and 2011, respectively, to the postretirement health

care plans.

Xcel Energy expects to contribute approximately $13.3 million during 2014.

Xcel Energy recovers employee benefits costs in its regulated utility operations consistent with accounting guidance with the exception of the areas noted below.

NSP-Minnesota recognizes pension expense in all regulatory jurisdictions

based on expense as calculated using the aggregate normal cost actuarial

method. Differences between aggregate normal cost and expense as

calculated by pension accounting standards are deferred as a regulatory

liability.

Colorado, Texas, New Mexico and FERC jurisdictions allow the recovery of

other post retirement benefit costs only to the extent that recognized

expense is matched by cash contributions to an irrevocable trust. Xcel

Energy has consistently funded at a level to allow full recovery of costs

in these jurisdictions.

SPS recognizes pension expense in all regulatory jurisdictions based on

expense consistent with accounting guidance. The Texas jurisdiction

records the difference between annual recognized pension expense and the

annual amount of pension expense approved in the last general rate case as

a deferral to a regulatory asset.

See Note 9 to the consolidated financial statements for further discussion.

Nuclear Decommissioning

Xcel Energy recognizes liabilities for the expected cost of retiring tangible long-lived assets for which a legal obligation exists. These AROs are recognized at fair value as incurred and are capitalized as part of the cost of the related long-lived assets. In the absence of quoted market prices, Xcel Energy estimates the fair value of its AROs using present value techniques, in which it makes various assumptions including estimates of the amounts and timing of future cash flows associated with retirement activities, credit-adjusted risk free rates and cost escalation rates. When Xcel Energy revises any assumptions used to estimate AROs, it adjusts the carrying amount of both the ARO liability and the related long-lived asset. Xcel Energy accretes ARO liabilities to reflect the passage of time using the interest method. A significant portion of Xcel Energy's AROs relates to the future decommissioning of NSP-Minnesota's nuclear facilities. The total obligation for nuclear decommissioning currently is expected to be funded 100 percent by the external decommissioning trust fund. The difference between regulatory funding (including depreciation expense less returns from the external trust fund) and amounts recorded under current accounting guidance are deferred as a regulatory asset. The amounts recorded for AROs related to future nuclear decommissioning were $1,627 million and $1,490 million as of Dec. 31, 2013 and 2012, respectively. Based on their significance, the following discussion relates specifically to the AROs associated with nuclear decommissioning. NSP-Minnesota obtains periodic cost studies in order to estimate the cost and timing of planned nuclear decommissioning activities. These independent cost studies are based on relevant information available at the time performed. Estimates of future cash flows for extended periods of time are by nature highly uncertain and may vary significantly from actual results. 71



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In November 2012, the MPUC approved NSP-Minnesota's most recent nuclear decommissioning study. The decommissioning study, which covered all expenses over the decommissioning period of the nuclear plants, including decontamination and removal of radioactive material. The estimated future costs were initially determined in nominal amounts (2011 dollars) prior to escalation adjustments, then future periods' costs were escalated using decommissioning-specific cost escalators and finally discounted using risk-free, credit adjusted interest rates. The MPUC approved the use of a 60-year decommissioning scenario. This resulted in an approved annual accrual of $14.2 million for Minnesota retail customers, to be held in our external escrow fund.



The following key assumptions have a significant effect on these estimates:

Timing - Decommissioning cost estimates are impacted by each facility's

retirement date, as well as the expected timing of the actual decommissioning activities. Currently, the estimated retirement dates coincide with each unit's operating license with the NRC (i.e., 2030 for Monticello and 2033 and 2034 for Prairie Island's Unit 1 and 2, respectively). The estimated timing of the decommissioning activities is



based upon the DECON method, which is required by the MPUC. By utilizing

this method, which assumes prompt removal and dismantlement, these activities are expected to begin at the end of the license date and be completed for both facilities by 2091. Technology and Regulation - There is limited experience with actual decommissioning of large nuclear facilities. Changes in technology and experience as well as changes in regulations regarding nuclear decommissioning could cause cost estimates to change



significantly. NSP-Minnesota's 2011 nuclear decommissioning filing assumed

current technology and regulations.



Escalation Rates - Escalation rates represent projected cost increases over

time due to both general inflation and increases in the cost of specific

decommissioning activities. NSP-Minnesota used an escalation rate of 3.63

percent in calculating the AROs related to nuclear decommissioning for the

remaining operational period through the radiological decommissioning

period. An escalation rate of 2.63 percent was utilized for the period of

operating costs related to interim dry cask storage of spent nuclear fuel

and site restoration.



Discount Rates - Changes in timing or estimated expected cash flows that

result in upward revisions to the ARO are calculated using the then-current

credit-adjusted risk-free interest rate. The credit-adjusted risk-free rate

in effect when the change occurs is used to discount the revised estimate of

the incremental expected cash flows of the retirement activity. If the

change in timing or estimated expected cash flows results in a downward

revision of the ARO, the undiscounted revised estimate of expected cash

flows is discounted using the credit-adjusted risk-free rate in effect at

the date of initial measurement and recognition of the original ARO. The

estimated expected cash flows that changed in 2012 due to the change to a 60

year decommissioning assumption resulted in an immaterial revision to the

ARO. Discount rates ranging from approximately four and seven percent have

been used to calculate the net present value of the expected future cash

flows over time. Significant uncertainties exist in estimating the future cost of nuclear decommissioning including the method to be utilized, the ultimate costs to decommission, and the planned method of disposing spent fuel. If different cost estimates, life assumptions or cost escalation rates were utilized, the AROs could change materially. However, changes in estimates have minimal impact on results of operations as NSP-Minnesota expects to continue to recover all costs in future rates. Xcel Energy continually makes judgments and estimates related to these critical accounting policy areas, based on an evaluation of the varying assumptions and uncertainties for each area. 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, 2013. 72



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Derivatives, Risk Management and Market Risk

In the normal course of business, Xcel Energy Inc. and its subsidiaries are exposed to a variety of market risks. Market risk is the potential loss that may occur as a result of adverse 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. See Note 11 to the consolidated financial statements for further discussion of market risks associated with derivatives. Xcel Energy is exposed to the impact of adverse changes in price for energy and energy-related products, which is partially mitigated by the use of commodity derivatives. In addition to ongoing monitoring and maintaining credit policies intended to minimize overall credit risk, when necessary, management takes steps to mitigate changes in credit and concentration risks associated with its derivatives and other contracts, including parental guarantees and requests of collateral. While Xcel Energy expects that the counterparties will perform under the contracts underlying its derivatives, the contracts expose Xcel Energy to some credit and non-performance risk. Though no material non-performance risk currently exists with the counterparties to Xcel Energy's commodity derivative contracts, distress in the financial markets may in the future impact that risk to the extent it impacts those counterparties. Distress in the financial markets may also impact the fair value of the securities in the nuclear decommissioning fund and master pension trust, as well as Xcel Energy's ability to earn a return on short-term investments of excess cash. Commodity Price Risk - Xcel Energy Inc.'s utility subsidiaries are exposed to commodity price risk in their electric and natural gas operations. Commodity price risk is managed by entering into 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. Wholesale and Commodity Trading Risk - Xcel Energy Inc.'s utility subsidiaries conduct various wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy and energy-related instruments. Xcel Energy's risk management policy allows management to conduct these activities within guidelines and limitations as approved by its risk management committee, which is made up of management personnel not directly involved in the activities governed by this policy. At Dec. 31, 2013, the fair values by source for net commodity trading contract assets were as follows: Futures / Forwards Maturity Maturity Total Futures / Source of Less Than Maturity Maturity Greater Than Forwards (Thousands of Dollars) Fair Value 1 Year 1 to 3 Years 4 to 5 Years 5 Years Fair Value NSP-Minnesota 1 $ 9,746$ 16,918$ 2,516$ 1,049$ 30,229 NSP-Minnesota 2 (646 ) - - 604 (42 ) PSCo 1 318 - - - 318 $ 9,418$ 16,918$ 2,516$ 1,653$ 30,505 Options Maturity Maturity Source of Less Than Maturity Maturity Greater Than Total Options (Thousands of Dollars) Fair Value 1 Year 1 to 3 Years 4 to 5 Years 5 Years Fair Value NSP-Minnesota 2 $ 9 $ - $ - $ - $ 9



1 - Prices actively quoted or based on actively quoted prices. 2 - Prices based on models and other valuation methods.

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Changes in the fair value of commodity trading contracts before the impacts of margin-sharing mechanisms for the years ended Dec. 31, were as follows: (Thousands of Dollars)

2013



2012

Fair value of commodity trading net contract assets outstanding at Jan. 1

$ 28,314$ 20,424 Contracts realized or settled during the period (6,665 )



(12,185 ) Commodity trading contract additions and changes during the period

8,865



20,075

Fair value of commodity trading net contract assets outstanding at Dec. 31 $ 30,514$ 28,314 At Dec. 31, 2013, a 10 percent increase in market prices for commodity trading contracts would decrease pretax income by approximately $0.6 million, whereas a 10 percent decrease would increase pretax income by approximately $0.6 million. At Dec. 31, 2012, a 10 percent increase in market prices for commodity trading contracts would increase pretax income by approximately $0.5 million, whereas a 10 percent decrease would decrease pretax income by approximately $0.5 million. Xcel Energy Inc.'s utility subsidiaries' 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, including transactions that are not recorded at fair value, 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 under normal market conditions.



The VaRs for the NSP-Minnesota and PSCo commodity trading operations, calculated on a consolidated basis using a Monte Carlo simulation with a 95 percent confidence level and a one-day holding period, were as follows:

Year Ended



(Millions of Dollars) Dec. 31 VaR Limit Average High

Low 2013 $ 0.29$ 3.00$ 0.41$ 1.65 $ <0.01 2012 0.45 3.00 0.36 1.56 0.06 Interest Rate Risk - Xcel Energy is 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. In conjunction with the NSP-Minnesota debt issuance in August 2012, NSP-Minnesota settled interest rate hedging instruments with a notional amount of $225 million with cash payments of $45.0 million. In conjunction with the PSCo debt issuance in September 2012, PSCo settled interest rate hedging instruments with a notional amount of $250 million with cash payments of $44.7 million. These losses are classified as a component of accumulated other comprehensive loss on the consolidated balance sheet, net of tax, and are being reclassified to earnings over the term of the hedged interest payments. See Note 4 to the consolidated financial statements for further discussion of long-term borrowings. At Dec. 31, 2013 and 2012, a 100 basis point change in the benchmark rate on Xcel Energy's variable rate debt would impact pretax interest expense annually by approximately $8.3 million and $6.0 million, respectively. See Note 11 to the consolidated financial statements for a discussion of Xcel Energy Inc. and its subsidiaries' interest rate derivatives. NSP-Minnesota also maintains a nuclear decommissioning fund, as required by the NRC. The nuclear decommissioning fund is subject to interest rate risk and equity price risk. At Dec. 31, 2013, the fund was invested in a diversified portfolio of cash equivalents, debt securities, equity securities, and other investments. These investments may be used only for activities related to nuclear decommissioning. Given the purpose and legal restrictions on the use of nuclear decommissioning fund assets, realized and unrealized gains on fund investments over the life of the fund are deferred as an offset of NSP-Minnesota's regulatory asset for nuclear decommissioning costs. Consequently, any realized and unrealized gains and losses on securities in the nuclear decommissioning fund, including any other-than-temporary impairments, are deferred as a component of the regulatory asset for nuclear decommissioning. Since the accounting for nuclear decommissioning recognizes that costs are recovered through rates, fluctuations in equity prices or interest rates do not have an impact on earnings. Credit Risk - Xcel Energy Inc. and its subsidiaries are also exposed to credit risk. Credit risk relates to the risk of loss resulting from counterparties' nonperformance on their contractual obligations. Xcel Energy Inc. and its subsidiaries maintain credit policies intended to minimize overall credit risk and actively monitor these policies to reflect changes and scope of operations. 74



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At Dec. 31, 2013, a 10 percent increase in commodity prices would have resulted in an increase in credit exposure of $15.2 million, while a decrease in prices of 10 percent would have resulted in an increase in credit exposure of $2.6 million. At Dec. 31, 2012, a 10 percent increase in commodity prices would have resulted in a decrease in credit exposure of $11.6 million, while a decrease in prices of 10 percent would have resulted in an increase in credit exposure of $12.6 million. Xcel Energy Inc. 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. Credit exposure is monitored and, when necessary, the activity with a specific counterparty is limited until credit enhancement is provided. Distress in the financial markets could increase Xcel Energy's credit risk. Fair Value Measurements Xcel Energy follows accounting and disclosure guidance on fair value measurements that contains a hierarchy for inputs used in measuring fair value and requires disclosure of the observability of the inputs used in these measurements. See Note 11 to the consolidated financial statements for further discussion of the fair value hierarchy and the amounts of assets and liabilities measured at fair value that have been assigned to Level 3. Commodity Derivatives - Xcel Energy continuously monitors the creditworthiness of the counterparties to its commodity derivative contracts and assesses each counterparty's ability to perform on the transactions set forth in the contracts. Given this assessment and the typically short duration of these contracts, the impact of discounting commodity derivative assets for counterparty credit risk was not material to the fair value of commodity derivative assets at Dec. 31, 2013. Adjustments to fair value for credit risk of commodity trading instruments are recorded in electric revenues. Credit risk adjustments for other commodity derivative instruments are deferred as OCI or regulatory assets and liabilities. The classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms. Xcel Energy also assesses the impact of its own credit risk when determining the fair value of commodity derivative liabilities. The impact of discounting commodity derivative liabilities for credit risk was immaterial to the fair value of commodity derivative liabilities at Dec. 31, 2013.



Commodity derivative assets and liabilities assigned to Level 3 typically consist of FTRs, as well as forwards and options that are long-term in nature. Level 3 commodity derivative assets and liabilities represent 3.0 percent and 28.7 percent of gross assets and liabilities, respectively, measured at fair value at Dec. 31, 2013.

Determining the fair value of FTRs requires numerous management forecasts that vary in observability, including various forward commodity prices, retail and wholesale demand, generation and resulting transmission system congestion. Given the limited observability of management's forecasts for several of these inputs, these instruments have been assigned a Level 3. Level 3 commodity derivatives assets and liabilities included $48.3 million and $10.0 million of estimated fair values, respectively, for FTRs held at Dec. 31, 2013. Determining the fair value of certain commodity forwards and options can require management to make use of subjective price and volatility forecasts which extend to periods beyond those readily observable on active exchanges or quoted by brokers. When less observable forward price and volatility forecasts are significant to determining the value of commodity forwards and options, these instruments are assigned to Level 3. Level 3 commodity derivative assets and liabilities included $3.4 million and zero of estimated fair values, respectively, for forwards held at Dec. 31, 2013. There were no Level 3 options held at Dec. 31, 2013. Nuclear Decommissioning Fund - Nuclear decommissioning fund assets assigned to Level 3 consist of private equity investments and real estate investments. Based on an evaluation of NSP-Minnesota's ability to redeem private equity investments and real estate investment funds measured at net asset value, estimated fair values for these investments totaling $120.1 million in the nuclear decommissioning fund at Dec. 31, 2013 (approximately 6.9 percent of total assets measured at fair value) are assigned to Level 3. Realized and unrealized gains and losses on nuclear decommissioning fund investments are deferred as a regulatory asset. 75



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Liquidity and Capital Resources

Cash Flows (Millions of Dollars) 2013 2012 2011



Net cash provided by operating activities $ 2,584$ 2,005$ 2,406

Net cash provided by operating activities increased by $579 million for 2013 as compared to 2012. The increase was primarily the result of higher net income, changes in working capital due to the timing of payments and receipts, net changes in regulatory assets and liabilities, and payments mainly related to interest rate swap settlements in 2012. Net cash provided by operating activities decreased by $401 million for 2012 as compared to 2011. The decrease was the result of changes in working capital due to the timing of payments and receipts, higher pension contributions, interest rate swap settlements and the effect of income taxes paid in 2012 compared to a refund received in 2011, partially offset by higher net income. (Millions of Dollars) 2013 2012 2011



Net cash used in investing activities $ (3,213 )$ (2,333 )$ (2,248 )

Net cash used in investing activities increased by $880 million for 2013 as compared to 2012. The increase was primarily the result of higher capital expenditures for several major construction projects including the Monticello nuclear EPU project as well as the Prairie Island steam generator replacement and certain other transmission line projects. Other differences mainly related to changes in restricted cash. Net cash used in investing activities increased by $85 million for 2012 as compared to 2011. The increase was the result of higher capital expenditures, partially offset by the change in restricted cash due to customer refunds associated with the nuclear waste disposal settlement with the DOE and insurance proceeds related to Sherco Unit 3 received in 2012. (Millions of Dollars) 2013 2012



2011

Net cash provided by (used in) financing activities $ 654$ 350$ (205 )

Net cash provided by financing activities increased by $304 million for 2013 as compared to 2012. The increase was primarily due to the issuance of more common stock during 2013, lower repayments of previously existing long-term debt, which was partially offset by reductions in long-term and short-term borrowing. Net cash provided by financing activities increased by $555 million for 2012 as compared to 2011. The increase was primarily due to higher proceeds from short-term borrowings and the issuance of long-term debt, partially offset by repayments of previously existing long-term debt, repurchases of common stock and higher dividend payments.



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

Capital Requirements

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

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Capital Expenditures - The current estimated capital expenditure programs of Xcel Energy Inc. and its subsidiaries for the years 2014 through 2018 are shown in the table below. Actual Forecast (Millions of Dollars) 2013 2014 2015 2016 2017 2018 By Subsidiary NSP-Minnesota $ 1,505$ 1,090$ 1,620$ 955$ 885$ 805 PSCo 1,074 985 845 795 770 815 SPS 555 525 520 610 770 790 NSP-Wisconsin 217 290 210 265 275 275 WYCO 8 - - - - - Total capital expenditures $ 3,359$ 2,890$ 3,195$ 2,625$ 2,700$ 2,685 By Function 2013 2014 2015 2016 2017 2018 Electric transmission $ 1,073$ 950$ 770$ 790$ 945$ 1,035 Electric generation 1,116 715 1,235 560 550 470 Electric distribution 551 510 560 595 605 610 Natural gas 316 365 340 345 300 320 Nuclear fuel 90 140 100 135 135 75 Other 213 210 190 200 165 175 Total capital expenditures $ 3,359$ 2,890$ 3,195$ 2,625$ 2,700$ 2,685 By Project 2013 2014 2015 2016 2017 2018 Other major transmission projects $ 335$ 370$ 265$ 330$ 420$ 385 CapX2020 transmission project 330 255 125 5 - - PSCo CACJA 350 250 85 10 - - Natural gas pipeline replacement 115 160 180 145 125 125 Nuclear fuel 90 140 100 135 135 75 NSP-Minnesota wind projects - 35 610 - - - Southwest infrastructure expansion - 5 70 170 290 385 NSP-Minnesota Black Dog - 5 50 40 5 - Other capital expenditures 2,139 1,670 1,710 1,790 1,725 1,715 Total capital expenditures $ 3,359$ 2,890$ 3,195$ 2,625$ 2,700$ 2,685 The capital expenditure programs of Xcel Energy are subject to continuing review and modification. Actual utility capital expenditures may vary from the estimates due to changes in electric and natural gas projected load growth, regulatory decisions, legislative initiatives, reserve margin requirements, the availability of purchased power, alternative plans for meeting long-term energy needs, compliance with environmental requirements, RPS and merger, acquisition and divestiture opportunities. 77



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Contractual Obligations and Other Commitments - In addition to its capital expenditure programs, Xcel Energy has contractual obligations and other commitments that will need to be funded in the future. The following is a summarized table of contractual obligations and other commercial commitments at Dec. 31, 2013. See the statements of capitalization and additional discussion in Notes 4 and 13 to the consolidated financial statements. Payments Due by Period Less than 1 (Thousands of Dollars) Total Year 1 to 3 Years 4 to 5 Years After 5 Years Long-term debt, principal and interest payments (a) $ 18,532,746$ 758,294$ 1,846,741$ 2,438,796$ 13,488,915 Capital lease obligations 371,697 17,966 34,896 29,686 289,149 Operating leases (b)(c) 3,028,807 240,669 452,213 420,423 1,915,502 Unconditional purchase obligations (d) 12,087,474 2,217,694 3,103,409 1,776,893 4,989,478 Other long-term obligations, including current portion (e) 218,718 55,416 85,089 62,743 15,470 Payments to vendors in process 28,955 28,955 - - - Short-term debt 759,000 759,000 - - - Total contractual cash obligations (f)(g)(h) $ 35,027,397$ 4,077,994$ 5,522,348$ 4,728,541$ 20,698,514



(a) Includes interest payments over the terms of the debt. Interest is

calculated using the applicable interest rate at Dec. 31, 2013, and

outstanding principal for each investment with the terms ending at each

instrument's maturity.

(b) 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, 2013, the amount that Xcel

Energy would have to pay if it chose to terminate these leases was

approximately $73.4 million. In addition, at the end of the equipment lease

terms, each lease must be extended, equipment purchased for the greater of

the fair value or unamortized value of equipment sold to a third party with

Xcel Energy making up any deficiency between the sales price and the

unamortized value.

(c) Included in operating lease payments are $214.2 million, $404.4 million,

$387.1 million and $1.8 billion, for the less than 1 year, 1-3 years, 4-5

years and after 5 years categories, respectively, pertaining to PPAs that

were accounted for as operating leases.

(d) Xcel Energy Inc. 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. Additionally, the utility subsidiaries of

Xcel Energy Inc. 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. Certain

contractual purchase obligations are adjusted on indices. The effects of

price changes are mitigated through cost of energy adjustment mechanisms.

(e) Other long-term obligations relate primarily to amounts associated with

technology agreements as well as uncertain tax positions.

(f) Xcel Energy also has outstanding authority under O&M contracts to purchase

up to approximately $3.1 billion of goods and services through the year

2050, in addition to the amounts disclosed in this table.

(g) In January 2014, contributions of $130.0 million were made across three of

Xcel Energy's pension plans. Obligations of this type are dependent on several factors, including management discretion, and therefore, they are not included in the table. (h) Xcel Energy expects to contribute approximately $13.3 million to the postretirement health care plans during 2014. Obligations of this type are dependent on several factors, including management discretion, and therefore, they are not included in the table. Common Stock Dividends - Future dividend levels will be dependent on Xcel Energy's results of operations, financial position, cash flows, reinvestment opportunities and other factors, and will be evaluated by the Xcel Energy Inc. Board of Directors. Xcel Energy's general objective is to continue to grow annual EPS four percent to six percent and to grow the annual dividend four percent to six percent. On Feb. 19, 2014, Xcel Energy announced dividends of $0.30 per share. Xcel Energy's dividend policy balances:



Projected cash generation;

Projected capital investment;

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. Federal law places certain limits on 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 utility subsidiaries' dividends may be limited directly or indirectly by state regulatory commissions or bond indenture covenants. See Note 4 to the consolidated financial statements for further discussion of restrictions on dividend payments.

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Regulation of Derivatives - In July 2010, financial reform legislation was passed that provides for the regulation of derivative transactions amongst other provisions. Provisions within the bill provide the CFTC and the SEC with expanded regulatory authority over derivative and swap transactions. Regulations effected under this legislation could preclude or impede some types of over-the-counter energy commodity transactions and/or require clearing through regulated central counterparties, which could negatively impact the market for these transactions or result in extensive margin and fee requirements. As a result of this legislation there will be material increased reporting requirements for certain volumes of derivative and swap activity. In April 2012, the CFTC ruled that swap dealing activity conducted by entities under a notional limit, initially set at $8 billion with further potential reduction to $3 billion after five years, will fall under the de minimis exemption level and will not subject an entity to registering as a swap dealer. Xcel Energy's current and projected swap activity is well below this de minimis level. The CFTC has set an $800 million de minimis volume exemption for swaps with "Utility Special Entities," defined by the CFTC as primarily entities owning or operating electric or natural gas facilities and government entities, after which the entity would have to register as a swap dealer. The bill also contains provisions that should exempt certain derivatives end users from much of the clearing and margin requirements. Xcel Energy does not expect to be materially impacted by the margining provisions. Xcel Energy has completed its review of the additional reporting obligations for "trade options," which are physical electric and gas contracts that contain embedded volumetric and/or price optionality. At this time, none of the contracts reviewed qualify as a "trade option." However, this determination is subject to change as additional Dodd-Frank Act rules continue to be finalized and implemented and subsequent transactions are executed. Xcel Energy is currently meeting all other reporting requirements. SPP FTR Margining Requirements - The SPP conducted its initial auction for FTRs in 2013. The full process for transmission owners involves the receipt of Auction Revenue Rights (ARRs), and if elected by the transmission owner, conversion of those ARRs to firm FTRs. At Dec. 31, 2013, SPS had a $26 million letter of credit posted as collateral for its SPP FTRs. In early January 2014, this letter of credit was reduced to $17 million.



Pension Fund - Xcel Energy's pension assets are invested in a diversified portfolio of domestic and international equity securities, short-term to long-duration fixed income securities, and alternative investments, including, private equity, real estate, hedge funds and commodity investments.

The funded status and pension assumptions are summarized in the following tables: (Millions of Dollars)

Dec. 31, 2013Dec. 31, 2012



Fair value of pension assets $ 3,010$ 2,944 Projected pension obligation (a)

3,441 3,640 Funded status $ (431 )$ (696 ) (a) Excludes nonqualified plan of $37 million and $39 million at Dec. 31, 2013 and 2012, respectively. Pension Assumptions 2013 2012 Discount rate 4.75 % 4.00 %



Expected long-term rate of return 7.05 6.88

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Capital Sources

Short-Term Funding Sources - Xcel Energy uses 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, working capital and dividend payments. Short-Term Investments - Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS maintain cash operating and short-term investment accounts. At Dec. 31, 2013, approximately $21.7 million of cash was held in these accounts. Commercial Paper - Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS each have individual commercial paper programs. The authorized levels for these commercial paper programs are:



$800 million for Xcel Energy Inc.;

$700 million for PSCo;

$500 million for NSP-Minnesota;

$300 million for SPS; and

$150 million for NSP-Wisconsin.

Commercial paper outstanding for Xcel Energy was as follows:

Three Months



Ended

(Amounts in Millions, Except Interest Rates) Dec. 31,



2013

Borrowing limit $



2,450

Amount outstanding at period end 759 Average amount outstanding 515 Maximum amount outstanding 759 Weighted average interest rate, computed on a daily basis 0.29 % Weighted average interest rate at end of period



0.25

(Amounts in Millions, Except Interest Twelve Months Ended Twelve Months Ended Twelve Months Ended Rates)

Dec. 31, 2013 Dec. 31, 2012 Dec. 31, 2011 Borrowing limit $ 2,450 $ 2,450 $ 2,450 Amount outstanding at period end 759 602 219 Average amount outstanding 481 403 430 Maximum amount outstanding 1,160 634 824 Weighted average interest rate, computed on a daily basis 0.31 % 0.35 % 0.36 % Weighted average interest rate at end of period 0.25 0.36 0.40 Credit Facilities - NSP-Minnesota, NSP-Wisconsin, PSCo, SPS and Xcel Energy Inc. each have five-year credit agreements with a syndicate of banks. The total size of the credit facilities is $2.45 billion and each credit facility terminates in July 2017. NSP-Minnesota, PSCo, SPS and Xcel Energy Inc. each have the right to request an extension of the revolving termination date for two additional one-year periods. NSP-Wisconsin has the right to request an extension of the revolving termination date for an additional one-year period. All extension requests are subject to majority bank group approval. 80



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As of Feb. 18, 2014, Xcel Energy Inc. and its utility subsidiaries had the following committed credit facilities available to meet liquidity needs: (Millions of Dollars) Facility (a) Drawn (b) Available Cash Liquidity Xcel Energy Inc. $ 800.0$ 582.0$ 218.0$ 0.2$ 218.2 PSCo 700.0 6.4 693.6 0.5 694.1 NSP-Minnesota 500.0 305.9 194.1 0.4 194.5 SPS 300.0 102.0 198.0 0.9 198.9 NSP-Wisconsin 150.0 48.0 102.0 0.5 102.5 Total $ 2,450.0$ 1,044.3$ 1,405.7$ 2.5$ 1,408.2



(a) These credit facilities expire in July 2017.

(b) Includes outstanding commercial paper and letters of credit.

Money Pool - Xcel Energy received FERC approval to establish a utility money pool arrangement with the utility subsidiaries, subject to receipt of required state regulatory approvals. The utility money pool allows for short-term investments in and borrowings between the utility subsidiaries. Xcel Energy Inc. may make investments in the utility subsidiaries at market-based interest rates; however, the money pool arrangement does not allow the utility subsidiaries to make investments in Xcel Energy Inc. The money pool balances are eliminated in consolidation.



NSP-Minnesota, PSCo and SPS participate in the money pool pursuant to approval from their respective state regulatory commissions. NSP-Wisconsin does not participate in the money pool.

Registration Statements - Xcel Energy Inc.'s Articles of Incorporation authorize the issuance of one billion shares of $2.50 par value common stock. As of Dec. 31, 2013 and 2012, Xcel Energy Inc. had approximately 498 million shares and 488 million shares of common stock outstanding, respectively. In addition, Xcel Energy Inc.'s Articles of Incorporation authorize the issuance of seven million shares of $100 par value preferred stock. Xcel Energy Inc. had no shares of preferred stock outstanding on Dec. 31, 2013 and 2012. Xcel Energy Inc. and its subsidiaries have the following registration statements on file with the SEC, pursuant to which they may sell, from time to time, securities:



Xcel Energy Inc. has an effective automatic shelf registration statement

filed in August 2012, which does not contain a limit on issuance capacity.

However, Xcel Energy Inc.'s ability to issue securities is limited by

authority granted by the Board of Directors, which currently authorizes

the issuance of up to an additional $900 million of debt and common equity

securities. NSP-Minnesota has an automatic shelf registration statement filed in December 2013, which does not contain a limit on issuance capacity. However, NSP-Minnesota's ability to issue securities is limited by



authority granted by its Board of Directors, which currently authorizes

the issuance of up to an additional $600 million of debt securities. NSP-Wisconsin has $200 million of debt securities remaining under its currently effective shelf registration statement, which was filed in December 2013.



PSCo has an automatic shelf registration statement filed in October 2013,

which does not contain a limit on issuance capacity. However, PSCo's ability to issue securities is limited by authority granted by its Board of Directors, which currently authorizes the issuance of up to an additional $1.0 billion of debt securities.



SPS has $300 million of debt securities remaining under its currently

effective shelf registration statement, which was filed in April 2013. 81



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Long-Term Borrowings and Other Financing Instruments - See the consolidated statements of capitalization and a discussion of the long-term borrowings in Note 4 to the consolidated financial statements.

During 2013, Xcel Energy Inc. and its utility subsidiaries completed the following financings:

PSCo issued $250 million of 2.50 percent first mortgage bonds due March 15, 2023 and $250 million of 3.95 percent first mortgage bonds due March 15, 2043. PSCo used a portion of the net proceeds from the sale of the first mortgage bonds to repay short-term borrowings incurred to fund daily operational needs;



Xcel Energy Inc. issued $450 million of 0.75 percent senior unsecured

notes due May 9, 2016. Xcel Energy Inc. used a portion of the proceeds

from the sale of the notes to repay short-term borrowings and for other

general corporate purposes;

NSP-Minnesota issued $400 million of 2.60 percent first mortgage bonds due

May 15, 2023. NSP-Minnesota used a portion of the net proceeds from the

sale of the first mortgage bonds to repay short-term borrowings and for

other general corporate purposes; and

SPS issued $100 million of 4.50 percent first mortgage bonds due Aug. 15,

2041. SPS used a portion of the net proceeds from the sale of the first

mortgage bonds to repay short-term borrowings incurred to fund daily

operational needs. Including the $300 million of this series previously

issued in August 2011 and June 2012, total principal outstanding for this series is $400 million. In March 2013, Xcel Energy Inc. filed a prospectus supplement under which it may sell up to $400 million of its common stock through an at-the-market offering program. No shares of common stock have been issued through this program since April 2013. As of Dec. 31, 2013, Xcel Energy Inc. sold 7.7 million shares of common stock with net proceeds of $223 million. On May 31, 2013, Xcel Energy Inc. redeemed the entire $400 million principal amount of its 7.60 percent junior subordinated notes. Upon redemption, Xcel Energy Inc. recognized $6.3 million of related unamortized debt issuance costs as interest charges. Financing Plans - Xcel Energy issues debt and equity securities to refinance retiring maturities, reduce short-term debt, fund construction programs, infuse equity in subsidiaries, fund asset acquisitions and for other general corporate purposes.



During the first half of 2014, Xcel Energy Inc. and its utility subsidiaries anticipate issuing the following:

PSCo may issue approximately $300 million of first mortgage bonds;

NSP-Minnesota may issue approximately $300 million of first mortgage bonds;

SPS may issue approximately $150 million of first mortgage bonds; and

NSP-Wisconsin may issue approximately $100 million of first mortgage bonds.

Financing plans are subject to change, depending on capital expenditures, internal cash generation, market conditions and other factors.

Credit Ratings - Access to reasonably priced capital markets is dependent in part on credit and ratings. On Feb. 14, 2013, Standard and Poor's upgraded SPS senior secured debt by one notch. On Nov. 14, 2013, Fitch Ratings upgraded both PSCo senior unsecured debt and PSCo senior secured debt by one notch.



On Jan. 31, 2014, Moody's upgraded each of the following ratings by one notch:

Xcel Energy Inc. senior unsecured debt;

NSP-Minnesota senior unsecured debt;

NSP-Minnesota commercial paper;

NSP-Wisconsin senior unsecured debt;

NSP-Wisconsin commercial paper;

PSCo senior unsecured debt; and

SPS senior unsecured debt.

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Off-Balance-Sheet Arrangements

Xcel Energy does not have any off-balance-sheet arrangements, other than those currently disclosed, 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.



Earnings Guidance

Xcel Energy's 2014 ongoing earnings guidance is $1.90 to $2.05 per share. Key assumptions related to 2014 earnings are detailed below:

Constructive outcomes in all rate case and regulatory proceedings.

Normal weather patterns are experienced for the remainder of the year.

Weather-adjusted retail electric utility sales are projected to increase

by approximately 0.5 percent.

Weather-adjusted retail firm natural gas sales are projected to decline by

approximately 0.0 percent to 2.0 percent. Capital rider revenue is projected to increase by $50 million to $60 million over 2013 levels. O&M expenses are projected to increase approximately 2 percent to 3 percent over 2013 levels.



Depreciation expense is projected to increase $30 million to $40 million

over 2013 levels, reflecting the proposed acceleration of the depreciation

reserve as part of NSP-Minnesota's moderation plan in the Minnesota

electric rate case. The moderation plan, if approved by the MPUC, would

reduce depreciation expense by approximately $81 million in 2014.



Property taxes are projected to increase approximately $50 million to $55

million over 2013 levels.

Interest expense (net of AFUDC - debt) is projected to decrease $0 to $10

million from 2013 levels.

AFUDC - equity is projected to increase approximately $5 million to $10

million over 2013 levels.

The ETR is projected to be approximately 34 percent to 36 percent.

Average common stock and equivalents are projected to be approximately 507

million shares.



Long-Term EPS and Dividend Growth Rate Objectives

Xcel Energy expects to deliver an attractive total return to our shareholders through a combination of earnings growth and dividend yield, based on the following long-term objectives:

Deliver long-term annual EPS growth of 4 percent to 6 percent, based on a

normalized 2013 EPS of $1.90 per share;

Deliver annual dividend increases of 4 percent to 6 percent; and

Maintain senior unsecured debt credit ratings in the BBB+ to A range.

Item 7A - Quantitative and Qualitative Disclosures About Market Risk

See Item 7, incorporated by reference.


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