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•	CIP — The CIP recovers the costs of programs that help customers save energy.  The CIP includes a comprehensive list of programs that benefit all customers including Saver’s Switch®, energy efficiency rebates and energy audits.

•	EIR — The EIR recovers the costs of environmental improvement projects.

•	RDF — The RDF allocates money collected from retail customers to support the research and development of emerging renewable energy projects and technologies.

•	RES — The RES recovers the cost of new renewable generation.

•	SEP — The SEP recovers costs related to various energy policies approved by the Minnesota legislature.

•	TCR — The TCR recovers costs associated with new investments in electric transmission.

•	Infrastructure — The Infrastructure rider recovers costs associated with specific investments in generation and incremental property taxes.

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•	The ALJ’s report focused on meeting a portion of the solar mandate even though the docket was designed to meet our resource need;

•	Solar acquisition to meet the solar mandate should be conducted separately to encourage competition among solar developers;

•	One or more gas fueled plants should be selected because they are large enough to meet the range of reasonably expected need, are least cost, and comply with environmental regulations; and

•	Resource need uncertainty should be addressed through contract options to delay or cancel resources.

•	A 200 MW ownership project for the Pleasant Valley wind farm in Minnesota, which is expected to be operational by October 2015;

•	A 150 MW ownership project for the Border Winds wind farm in North Dakota, which is expected to be operational by 2015;

•	A 200 MW PPA with Geronimo Energy, LLC for the Odell wind farm in Minnesota; and

•	A 200 MW PPA with Geronimo Energy, LLC for the Courtenay wind farm in North Dakota.

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(a)	This category includes wind energy de-bundled from RECs and also includes Windsource RECs.  The NSP System uses RECs to meet or exceed state resource requirements and may sell surplus RECs.

(b)	Includes energy from other sources, including solar, biomass, oil and refuse.  Distributed generation from the Solar*Rewards program is not included, and was approximately 0.008, 0.006, and 0.003 net million KWh for 2013, 2012, and 2011, respectively.

(a)	Includes refuse-derived fuel and wood.

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•	Current nuclear fuel supply contracts cover 100 percent of uranium concentrates requirements through 2018 and approximately 67 percent of the requirements for 2019 through 2026.

•	Current contracts for conversion services cover 100 percent of the requirements through 2021 and approximately 57 percent of the requirements for 2022 through 2026.

•	Current enrichment service contracts cover 100 percent of the requirements through 2024 and approximately 48 percent of the requirements for 2025 through 2026.

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•	ECA — The ECA recovers fuel and purchased power costs.  Short-term sales margins are shared with retail customers through the ECA.  The ECA is revised quarterly.

•	PCCA — The PCCA recovers purchased capacity payments.

•	SCA — The SCA recovers the difference between PSCo’s actual cost of fuel and the amount of these costs recovered under its base steam service rates.  The SCA rate is revised annually in January, as well as on an interim basis to coincide with changes in fuel costs.

•	DSMCA — The DSMCA recovers DSM, interruptible service option credit costs and performance initiatives for achieving various energy savings goals.

•	RESA — The RESA recovers the incremental costs of compliance with the RES and is set at its maximum level of two percent of the customer’s total bill.

•	Wind Energy Service — Wind Energy Service is a premium service for those customers who voluntarily choose to pay an additional charge to increase the level of renewable resource generation used to meet the customer’s load requirements.

•	TCA — The TCA recovers transmission plant revenue requirements and allows for a return on CWIP outside of rate cases.

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•	The addition of 450 MW of wind generation PPAs. This additional wind would bring the installed capacity on PSCo’s system in Colorado to 2,650 MW;

•	The addition of 170 MW of utility-scale solar generation PPAs. PSCo currently has about 80 MW of utility-scale solar and approximately 188 MW of customer-sited solar generation;

•	The addition of 317 MW of natural gas fired generation PPAs, which would come from existing power plants that previously supplied PSCo, but at reduced prices;

•	Accelerated retirement of the 109 MW, coal-fired Unit 4 at the Arapahoe generating station, which occurred at the end of 2013;

•	Confirmation of the retirement of the 45 MW, coal-fired Unit 3 at the Arapahoe generating station, which occurred at the end of 2013; and

•	The continued operation of Cherokee generating station’s Unit 4 as a natural gas facility after 2017.

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(a)	This category includes wind energy de-bundled from RECs and also includes Windsource RECs.  PSCo uses RECs to meet or exceed state resource requirements and may sell surplus RECs.

(b)	Includes energy from other sources, including nuclear, solar, biomass, oil and refuse. Distributed generation from the Solar*Rewards program is not included, and was approximately 0.172, 0.133, and 0.137 net million KWh for 2013, 2012, and 2011, respectively.

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•	DCRF — The DCRF rider recovers distribution costs in Texas.

•	DRC — The DRC rider recovers deferred costs associated with renewable energy programs in New Mexico.

•	EECRF — The EECRF rider recovers costs associated with providing energy efficiency programs in Texas.

•	EE rider — The EE rider recovers costs associated with providing energy efficiency programs in New Mexico.

•	FPPCAC — The FPPCAC adjusts monthly to recover the difference between the actual fuel and purchased power costs and the amount included in base rates of SPS’ New Mexico retail jurisdiction.

•	PCRF — The PCRF rider allows recovery of certain purchased power costs in Texas.

•	TCRF — The TCRF rider recovers transmission infrastructure improvement costs and changes in wholesale transmission charges in Texas.

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(a)	This category includes wind energy de-bundled from RECs and also includes Windsource RECs.  SPS uses RECs to meet or exceed state resource requirements and may sell surplus RECs.

(b)	Includes energy from other sources, including nuclear, hydroelectric, solar, biomass, oil and refuse.  Distributed generation from the Solar*Rewards program is not included, was approximately 0.011, 0.008, and 0.006 net million KWh for 2013, 2012, and 2011, respectively.

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(a)	This category includes wind energy de-bundled from RECs and also includes Windsource RECs.  Xcel Energy uses RECs to meet or exceed state resource requirements and may sell surplus RECs.

(b)	Includes energy from other sources, including solar, biomass, oil and refuse.  Distributed generation from the Solar*Rewards program is not included, and was approximately 0.198, 0.152, and 0.146 net million KWh for 2013, 2012 and 2011, respectively.

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•	GCA — The GCA recovers the actual costs of purchased natural gas and transportation to meet the requirements of its customers and is revised quarterly to allow for changes in natural gas rates.

•	DSMCA — The DSMCA is a low-income energy assistance program.  The costs of this energy conservation and weatherization program are recovered through the gas DSMCA.

•	PSIA — Effective Jan. 1, 2012, the PSIA began to recover costs associated with transmission and distribution pipeline integrity management programs and two projects to replace large transmission pipelines. Although PSCo had proposed to include the PSIA in base rates, instead the rider was extended through Dec. 31, 2015.

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•	Sites of former MGPs operated by our subsidiaries, predecessors, or other entities; and

•	Third party sites, such as landfills, for which we are alleged to be a PRP that sent hazardous materials and wastes.

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•	The risks associated with use of radioactive material in the production of energy, the management, handling, storage and disposal of these radioactive materials and the current lack of a long-term disposal solution for radioactive materials;

•	Limitations on the amounts and types of insurance commercially available to cover losses that might arise in connection with nuclear operations; and

•	Uncertainties with respect to the technological and financial aspects of decommissioning nuclear plants at the end of their licensed lives.

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(a)	Based on NSP-Minnesota’s ownership of 59 percent.

(b)	Refuse-derived fuel is made from municipal solid waste.

(c)	This capacity is only available when wind conditions are sufficiently high enough to support the noted generation values above.  Therefore, the on-demand net dependable capacity is zero.

(a)	Refuse-derived fuel is made from municipal solid waste.

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(a)	Cherokee Unit 2 was taken out of service in October 2011.  Cherokee Unit 1 was taken out of service in May 2012.

(b)	Based on PSCo’s ownership interest of 67 percent of Unit 3.

(c)	Based on PSCo’s ownership interest of 10 percent.

(d)	Based on PSCo’s ownership interest of 76 percent of Unit 1 and 37 percent of Unit 2.

(e)	This capacity is only available when wind conditions are sufficiently high enough to support the noted generation values above.  Therefore, the on-demand net dependable capacity is zero.

(a)	Construction of Jones Unit 3 was completed in 2011 and Jones Unit 4 was completed in May 2013.

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(a)	Xcel Energy Inc. or one of its agents periodically purchases common shares in order to satisfy obligations under the Stock Equivalent Plan for Non-Employee Directors.

(a)	Includes capital lease obligations.

(b)	See Exhibit 12.01.

(c)	See Item 7 for a reconciliation of ongoing earnings to GAAP earnings.

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•	Driving operational excellence;

•	Providing options and solutions to customers;

•	Investing for the future; and

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

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•	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.

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

(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).

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(a)	Extreme weather variations and additional factors such as windchill and cloud cover may not be reflected in weather normalization and growth estimates.

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(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 $8 million in 2013.

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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.

(a)	Decrease is primarily due to the expiration of a long-term wholesale power sales agreement with Black Hills Corp., effective Jan. 1, 2012.

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•	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.

•	Higher employee benefits are mainly due to increased pension expenses.

•	Higher pipeline system integrity costs relate to increased compliance and inspection initiatives, which in Colorado are recovered through the pipeline system integrity rider.

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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.

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

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•	$275 million in 2013;

•	$263 million in 2012; and

•	$265 million in 2011.

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•	$517 million in 2013;

•	$255 million in 2012; and

•	$48 million in 2011.

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•	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.

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•	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.

•	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.

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•

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.

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(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.

•	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.

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(a)	Excludes nonqualified plan of $37 million and $39 million at Dec. 31, 2013 and 2012, respectively.

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•	$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.

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(a)	These credit facilities expire in July 2017.

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

•	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.

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•	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.

•	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.

•	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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•	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.

•	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.

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(a)	Pollution control financing.

(b)	Resource recovery financing.

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1.	Summary of Significant Accounting Policies

•	Certain costs, which would otherwise be charged to expense or OCI, are deferred as regulatory assets based on the expected ability to recover the costs in future rates; and

•	Certain credits, which would otherwise be reflected as income, are deferred as regulatory liabilities based on the expectation the amounts will be returned to customers in future rates, or because the amounts were collected in rates prior to the costs being incurred.

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2.	Accounting Pronouncements

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3.	Selected Balance Sheet Data

(a)

As a result of the CPUC’s 2010 approval of PSCo’s CACJA compliance plan, subsequent CPCNs and the December 2013 approval of PSCo’s preferred plans for applicable generating resources, PSCo has received approval for early retirement of Cherokee Units 1, 2 and 3, Arapahoe Units 3 and 4 and Valmont Unit 5 between 2011 and 2017. In 2011, Cherokee Unit 2 was retired, in 2012, Cherokee Unit 1 was retired, and in 2013, Arapahoe Units 3 and 4 were retired. Amounts are presented net of accumulated depreciation.

4.	Borrowings and Other Financing Instruments

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•	Xcel Energy Inc. may increase its credit facility by up to $200 million, NSP-Minnesota and PSCo may each increase their credit facilities by $100 million and SPS may increase its credit facility by $50 million. The NSP-Wisconsin credit facility cannot be increased.

•	Each credit facility has a financial covenant requiring that the debt-to-total capitalization ratio of each entity be less than or equal to 65 percent. Each entity was in compliance at Dec. 31, 2013 and 2012, respectively, as evidenced by the table below:

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•	If Xcel Energy Inc. or any of its utility subsidiaries do not comply with the covenant, an event of default may be declared, and if not remedied, any outstanding amounts due under the facility can be declared due by the lender.

•

The Xcel Energy Inc. credit facility has a cross-default provision that provides Xcel Energy Inc. will be in default on its borrowings under the facility if it or any of its subsidiaries, except NSP-Wisconsin as long as its total assets do not comprise more than 15 percent of Xcel Energy’s consolidated total assets, default on certain indebtedness in an aggregate principal amount exceeding $75 million.

•	The interest rates under these lines of credit are based on Eurodollar borrowing margins ranging from 87.5 to 175 basis points per year based on the applicable long-term credit ratings.

•	The commitment fees, also based on applicable long-term credit ratings, are calculated on the unused portion of the lines of credit at a range of 7.5 to 27.5 basis points per year.

(a)	These credit facilities expire in July 2017.

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

•	In March 2013, 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.

•	In May 2013, Xcel Energy Inc. issued $450 million of 0.75 percent senior unsecured notes due May 9, 2016.

•	In May 2013, NSP-Minnesota issued $400 million of 2.60 percent first mortgage bonds due May 15, 2023.

•	In August 2013, SPS issued $100 million of 4.50 percent first mortgage bonds due Aug. 15, 2041. Including the $300 million of this series previously issued, total principal outstanding for this series is $400 million.

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•	In June 2012, SPS issued an additional $100 million of its 4.50 percent first mortgage bonds due Aug. 15, 2041.

•	In August 2012, NSP-Minnesota issued $300 million of 2.15 percent first mortgage bonds due Aug. 15, 2022, and $500 million of 3.40 percent first mortgage bonds due Aug. 15, 2042.

•	In September 2012, PSCo issued $300 million of 2.25 percent first mortgage bonds due Sept. 15, 2022, and $500 million of 3.60 percent first mortgage bonds due Sept. 15, 2042.

•	In October 2012, NSP-Wisconsin issued $100 million of 3.70 percent first mortgage bonds due Oct. 1, 2042.

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•	PSCo currently has authorization to issue up to an additional $1 billion of long-term debt and up to $800 million of short-term debt.

•	SPS currently has no authorization to issue any long-term debt in 2014 and up to $400 million of short-term debt.

•	NSP-Wisconsin currently has authorization to issue up to an additional $150 million of long-term debt and up to $150 million of short-term debt.

•	NSP-Minnesota has authorization to issue long-term securities provided the equity-to-total capitalization ratio remains between 46.8 percent and 57.2 percent and to issue short-term debt provided it does not exceed 15 percent of total capitalization.  Total capitalization for NSP-Minnesota cannot exceed $9 billion.

5.	Joint Ownership of Generation, Transmission and Gas Facilities

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6.	Income Taxes

•	The top tax rate for dividends increased from 15 percent to 20 percent.  The 20 percent dividend rate is now consistent with the tax rates for capital gains;

•	The research and experimentation (R&E) credit was extended for 2012 and 2013;

•	PTCs were extended for projects that begin construction before the end of 2013; and

•	50 percent bonus depreciation was extended one year through 2013.  Additionally, some longer production period property placed in service in 2014 is also eligible for 50 percent bonus depreciation.

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(a)	State tax credit carryforwards are net of federal detriment of $9 million as of Dec. 31, 2013 and 2012.

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7.	Earnings Per Share

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•	RSU equity awards subject to a performance condition; included in common shares outstanding when all necessary conditions for settlement have been satisfied by the end of the reporting period.

•	PSP liability awards subject to a performance condition; any portions settled in shares are included in common shares outstanding upon settlement.

8.	Share-Based Compensation

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(a)	Intrinsic value is calculated as market price at exercise date less the option exercise price.

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(a)	Compensation costs for share-based payment arrangements is included in O&M expense in the consolidated statements of income.

(b)	Included in compensation cost for share-based awards are matching contributions related to the Xcel Energy 401(k) plan, which totaled $7.0 million, $22.2 million and $21.6 million for the years ended 2013, 2012 and 2011, respectively.

(c)	In October 2013, Xcel Energy determined that it would settle the 2013 401(k) employer match in cash instead of common stock for all employee groups except PSCo bargaining employees. Share-based compensation accounting for the impacted employee groups ceased in October 2013, and corresponding expense amounts recorded to equity were reclassified to a liability for expected cash settlements.

9.	Benefit Plans and Other Postretirement Benefits

•	NSP-Minnesota had 2,022 and NSP-Wisconsin had 399 bargaining employees covered under a collective-bargaining agreement, which expires at the end of 2016. NSP-Minnesota also had an additional 248 nuclear operation bargaining employees covered under several collective-bargaining agreements, which expire at various dates in 2015 and 2016.

•	PSCo had 2,086 bargaining employees covered under a collective-bargaining agreement, which expires in May 2014.

•	SPS had 832 bargaining employees covered under a collective-bargaining agreement, which expires in October 2014.

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(a)	Transfers out of Level 3 into Level 2 were principally due to diminished use of unobservable inputs that were previously significant to these fair value measurements and were subsequently sold during 2013.

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(a)	Amounts are recognized in noncurrent liabilities on Xcel Energy’s consolidated balance sheets.

•	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;

•	In 2011, contributions of $137.3 million were made across three of Xcel Energy’s pension plans;

•	For future years, Xcel Energy anticipates contributions will be made as necessary.

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•	The former NSP, which includes NSP-Minnesota and NSP-Wisconsin, discontinued contributing toward health care benefits for nonbargaining employees retiring after 1998 and for bargaining employees who retired after 1999.

•	Xcel Energy discontinued contributing toward health care benefits for former NCE, which includes PSCo and SPS, nonbargaining employees retiring after June 30, 2003.

•	Employees of NCE who retired in 2002 continue to receive employer-subsidized health care benefits.

•	Nonbargaining employees of the former NCE who retired after 1998, bargaining employees of the former NCE who retired after 1999 and nonbargaining employees of NCE who retired after June 30, 2003, are eligible to participate in the Xcel Energy health care program with no employer subsidy.

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(a)	Transfers out of Level 3 into Level 2 were principally due to diminished use of unobservable inputs that were previously significant to these fair value measurements and were subsequently sold during 2013.

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10.	Other Income, Net

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(a)	Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $87.1 million of equity investments in unconsolidated subsidiaries and $41.9 million of miscellaneous investments.

(a)	Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $91.2 million of equity investments in unconsolidated subsidiaries and $37.1 million of miscellaneous investments.

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(a)	Transfers out of Level 3 into Level 2 were principally due to diminished use of unobservable inputs that were previously significant to these fair value measurements and were subsequently sold during 2013.

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(a)	Amounts are not reflective of net positions in the underlying commodities.

(b)	Notional amounts for options are included on a gross basis, but are weighted for the probability of exercise.

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(a)	Amounts are recorded to interest charges.

(b)	Amounts are recorded to O&M expenses.

(c)	Amounts are recorded to electric operating revenues.  Portions of these gains and losses are subject to sharing with electric customers through margin-sharing mechanisms and deducted from gross revenue, as appropriate.

(d)	Amounts are recorded to electric fuel and purchased power.  These derivative settlement gains and losses are shared with electric customers through fuel and purchased energy cost-recovery mechanisms, and reclassified out of income as regulatory assets or liabilities, as appropriate.

(e)

Amounts for the years ended Dec. 31, 2012 and 2011 included $5.0 million and $12.7 million, respectively, of settlement losses on derivatives entered to mitigate natural gas price risk for electric generation, recorded to electric fuel and purchased power, subject to cost-recovery mechanisms and reclassified to a regulatory asset, as appropriate.  Such losses for the year ended Dec. 31, 2013 were immaterial.  The remaining settlement losses for the years ended Dec. 31, 2013, 2012 and 2011 relate to natural gas operations and are recorded to cost of natural gas sold and transported.  These losses are subject to cost-recovery mechanisms and reclassified out of income to a regulatory asset, as appropriate.

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(a)

In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, Xcel Energy began recording several long-term PPAs at fair value due to accounting requirements related to underlying price adjustments.  As these purchases are recovered through normal regulatory recovery mechanisms in the respective jurisdictions, the changes in fair value for these contracts were offset by regulatory assets and liabilities.  During 2006, Xcel Energy qualified these contracts under the normal purchase exception.  Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.

(b)

Xcel Energy nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Dec. 31, 2013.  At Dec. 31, 2013, derivative assets and liabilities include obligations to return cash collateral of $0.2 million and rights to reclaim cash collateral of $4.2 million. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

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(a)

In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, Xcel Energy began recording several long-term PPAs at fair value due to accounting requirements related to underlying price adjustments.  As these purchases are recovered through normal regulatory recovery mechanisms in the respective jurisdictions, the changes in fair value for these contracts were offset by regulatory assets and liabilities.  During 2006, Xcel Energy qualified these contracts under the normal purchase exception.  Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.

(b)

Xcel Energy nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Dec. 31, 2012.  At Dec. 31, 2012, derivative assets and liabilities include obligations to return cash collateral of $0.6 million and rights to reclaim cash collateral of $3.0 million. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.

(a)	These amounts relate to commodity derivatives held at the end of the period.

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•	Direct Testimony — June 5, 2014;

•	Rebuttal Testimony — July 7, 2014;

•	Surrebuttal Testimony — Aug. 4, 2014;

•	Evidentiary Hearing — Aug. 11-18, 2014;

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•	Reply Brief — Oct. 14, 2014; and

•	ALJ Report — Dec. 22, 2014.

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•	Direct Testimony — July 2, 2014;

•	Rebuttal Testimony — Aug. 26, 2014;

•	Surrebuttal Testimony — Sept. 19, 2014;

•	Hearing — Sept. 29-Oct. 3, 2014;

•	Reply Brief — Nov. 21, 2014; and

•	ALJ report — Dec. 31, 2014.

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•	An approval of two new rate rider tariff mechanisms to recover transmission and North Dakota renewable costs;

•	An authorized ROE of 9.75, 10.0, 10.0 and 10.25 percent in 2013 through 2016, respectively;

•	A 50 percent earnings sharing mechanism for amounts earned in excess of the authorized ROEs during the term of the settlement;

•	The continued use of a 12 month CP demand allocator for certain rate base and operating expenses;

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A commitment to develop a generation cost allocation mechanism over the next 16 months that reflects North Dakota energy policy; providing for the exclusion of resources deemed inconsistent with North Dakota energy policy beginning in 2016 (such as certain Minnesota wind and biomass purchase power agreements) and reflecting replacement of those costs based on either system average costs or like resource costs (base load for base load generation, etc.) and recognizing the time needed to address complexity among multiple jurisdictions by providing that a plan for this mechanism be filed by June 2015;

•	The commitment to construct up to 400 MW of thermal generation in North Dakota by 2036 subject to least-cost resource planning principles; and

•	The retention of DOE settlement proceeds received in 2012, 2013 and expected in 2014.

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•	Evidentiary hearing — March 3 - March 7, 2014;

•	Initial brief — March 28, 2014; and

•	Reply brief — April 11, 2014.

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•	Intervenor testimony — May 22, 2014;

•	PUCT Staff testimony — May 29, 2014;

•	Cross-rebuttal testimony — June 12, 2014;

•	Rebuttal testimony — June 16, 2014;

•	Evidentiary hearing — June 25, 2014; and

•	A PUCT decision and implementation of final rates are anticipated in the third quarter of 2014.

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•	Intervenor testimony — April 17, 2014;

•	Rebuttal testimony — May 6, 2014; and

•	Evidentiary hearings — May 15 - May 16, 2014.

(a)	Adjustments represent recommended deferrals, extended amortizations and moving costs from rider to fuel in base rates.

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(a)	Excludes contingent energy payments for renewable PPAs.

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(a)	Amounts do not include PPAs accounted for as executory contracts.

(b)	PPA operating leases contractually expire through 2033.

(c)	Future commitments exclude certain amounts related to Xcel Energy’s 50 percent ownership interest in WYCO.

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(a)	The term of this guarantee expires in 2017, which is the final scheduled repayment date for the loans. As of Dec. 31, 2013, no claims had been made by the lender.

(b)	The term of this guarantee expires in 2017 when the associated leases expire.

(c)	The terms of these guarantees expire in 2014 and 2015 when the associated leases expire.

(d)	The surety bonds primarily relate to workers compensation benefits and utility projects.  The workers compensation bonds are renewed annually and the project based bonds expire in conjunction with the completion of the related projects.

(e)	The debtor becomes the subject of bankruptcy or other insolvency proceedings.

(f)	Nonperformance and/or nonpayment.

(g)	Actual fair value of leased assets is less than the guaranteed residual value amount at the end of the lease term.

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

(i)	Due to the magnitude of projects associated with the surety bonds, the total current exposure of this indemnification cannot be determined.  Xcel Energy Inc. believes the exposure to be significantly less than the total amount of the outstanding bonds.

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14.	Nuclear Obligations

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(a)	Decommissioning expense does not include depreciation of the capitalized nuclear asset retirement costs.

15.	Regulatory Assets and Liabilities

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(a)

Includes $303.3 million and $330.3 million for the regulatory recognition of the NSP-Minnesota pension expense of which $23.2 million and $24.3 million is included in the current asset at Dec. 31, 2013 and 2012, respectively. Also included are $17.7 million and $21.5 million of regulatory assets related to the nonqualified pension plan of which $2.2 million is included in the current asset at Dec. 31, 2013 and 2012, respectively.

(b)	Includes the fair value of certain long-term PPAs used to meet energy capacity requirements and valuation adjustments on natural gas commodity purchases.

(c)	Includes amounts recorded for future recovery of AROs, less amounts recovered through nuclear decommissioning accruals and gains from decommissioning investments.

(d)	Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions.

(e)	For the canceled Prairie Island EPU project, NSP-Minnesota plans to address recovery of incurred costs in the pending multi-year rate case.

(a)	Includes the fair value of certain long-term PPAs used to meet energy capacity requirements and valuation adjustments on natural gas commodity purchases.

(b)	Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions.

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16.	Other Comprehensive Income

(a)	Included in interest charges.

(b)	Included in O&M expenses.

(c)	Included in the computation of net periodic pension and post retirement benefit costs.  See Note 9 for details regarding these benefit plans.

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•

Xcel Energy’s regulated electric utility segment generates, transmits and distributes electricity in Minnesota, Wisconsin, Michigan, North Dakota, South Dakota, Colorado, Texas and New Mexico.  In addition, this segment includes sales for resale and provides wholesale transmission service to various entities in the United States.  Regulated electric utility also includes commodity trading operations.

•	Xcel Energy’s regulated natural gas utility segment transports, stores and distributes natural gas primarily in portions of Minnesota, Wisconsin, North Dakota, Michigan and Colorado.

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Revenues from operating segments not included above are below the necessary quantitative thresholds and are therefore included in the all other category.  Those primarily include steam revenue, appliance repair services, nonutility real estate activities, revenues associated with processing solid waste into refuse-derived fuel and investments in rental housing projects that qualify for low-income housing tax credits.

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18.	Summarized Quarterly Financial Data (Unaudited)

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(a)	Recovery of amounts previously written off as related to allowance for bad debts.

(b)	Principally bad debts written off as related to allowance for bad debts.

(c)	Reductions to valuation allowances for NOL and tax credit carryforwards primarily due to changes in tax laws, expirations of certain carryforwards and identification of various tax planning strategies.

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