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•	CIP — The CIP recovers the costs of conservation and demand-side management programs that help customers save energy.

•	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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•	Leading the effort to reduce carbon emissions 40 percent by 2030 from 2005 levels;

•	Advancing distribution grid modernization;

•	Providing our customers with a platform of innovative services and product offerings; and

•	Implementing a new regulatory framework that provides both predictable rates for customers and a more timely and nimble review while retaining key benefits of the existing process, thus freeing time for regulatory agencies, stakeholders and utilities to focus on achieving policy objectives.

•	Adding 600 MW of wind by 2020 and 1,200 MW by 2027, bringing total wind power on the NSP System to over 3,600 MW;

•	Adding 187 MW of large-scale solar energy by 2016 and an additional 1,700 MW of large-scale solar and 500 MW of customer-driven small-scale solar; bringing total solar power on the NSP System to approximately 2,400 MW;

•	Operating the Monticello and PI nuclear plants through their current licenses; and

•	Continuing to run Sherco Units 1 and 2 with gradually decreasing reliance through 2030.

•	Enter into an agreement for 100 MW of distributed solar with Geronimo Energy LLC;

•	Enter into an agreement with Calpine Corporation for a 345 MW expansion at its Mankato Energy Center; and

•	Construct a 215 MW Black Dog Unit 6 combustion turbine.

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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 seven, eight, and six net million KWh for 2014, 2013, and 2012, 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 72 percent of the requirements for 2019 through 2027.

•	Current contracts for conversion services cover 100 percent of the requirements through 2021 and approximately 62 percent of the requirements for 2022 through 2027.

•	Current enrichment service contracts cover 100 percent of the requirements through 2021 and approximately 68 percent of the requirements for 2025 through 2027.

•	Renewable energy comprised 24.2 percent and 22.9 percent of the NSP System’s total owned and purchased energy for 2014 and 2013, respectively.

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•	Wind energy comprised 13.7 percent and 12.6 percent of the total owned and purchased energy on the NSP System for 2014 and 2013, respectively.

•	Hydroelectric energy comprised 7.8 percent and 7.4 percent of the total owned and purchased energy on the NSP System for 2014 and 2013, respectively.

•	Biomass and solar power comprised approximately 2.7 percent and 3.0 percent of the total owned and purchased energy on the NSP System for 2014 and 2013, respectively.

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•	ECA — The ECA recovers fuel and purchased energy 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.

•	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 with a maximum of two percent of the customer’s total bill.

•	Wind Energy Service — Wind Energy Service is a premium service for customers who voluntarily choose to pay an additional charge for renewable resources.

•	TCA — The TCA recovers costs associated with transmission investment outside of rate cases.

•	CACJA — As part of its pending electric rate case, PSCo proposed to establish a CACJA rider, retroactive to Jan. 1, 2015, to recover costs associated with implementing its compliance plan under the CACJA.

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•	The addition of 450 MW of wind generation PPAs, which are expected to be operational in 2015. These additional PPAs will bring the installed wind capacity on PSCo’s system in Colorado to 2,650 MW;

•	The addition of 170 MW of utility-scale solar generation PPAs, which are expected to be operational in 2016. PSCo has approximately 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 will come from existing power plants;

•	The accelerated retirements of the coal-fired Arapahoe Unit 3 (45 MW) and Unit 4 (109 MW), which occurred in 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)	Distributed generation from the Solar*Rewards program is not included, and was approximately 197, 172, and 133 net million KWh for 2014, 2013, and 2012, respectively.

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•	At Dec. 31, 2014, PSCo’s commitments related to gas supply contracts, which expire in various years from 2015 through 2023, were approximately $902 million and commitments related to gas transportation and storage contracts, which expire in various years from 2015 through 2060, were approximately $685 million.

•	At Dec. 31, 2013, PSCo’s commitments related to gas supply contracts were approximately $1.1 billion and commitments related to gas transportation and storage contracts were approximately $723 million.

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•	Renewable energy comprised 21.4 percent and 21.9 percent of PSCo’s total owned and purchased energy for 2014 and 2013, respectively.

•	Wind energy comprised 18.9 percent and 19.3 percent of PSCo’s total owned and purchased energy for 2014 and 2013, respectively.

•	Hydroelectric, biomass and solar power comprised approximately 2.5 percent and 2.6 percent of PSCo’s total owned and purchased energy for 2014 and 2013.

•	PSCo had approximately 2,340 MW and 2,170 MW of wind energy on its system at the end of 2014 and 2013, respectively.

•	In October 2013, the CPUC approved the addition of 450 MW of Colorado wind generation PPA’s.

•	With the new projects, PSCo is anticipated to have approximately 2,592 MW of wind power by 2016. In addition to receiving purchased wind energy under these agreements, PSCo also typically receives wind RECs, which are used to meet state renewable resource requirements.

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The average cost per MWh of wind energy under these contracts was approximately $45 in both 2014 and 2013. The cost per MWh of wind energy varies by contract and may be influenced by a number of factors including regulation, state-specific renewable resource requirements, and the year of contract execution. Generally, contracts executed in 2014 continued to benefit from improvements in technology, excess capacity among manufacturers, and motivation to commence new construction prior to the expiration of the Federal PTCs in 2014, with certain projects qualifying into future years.

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

•	DRC — The DRC rider previously recovered 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.

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

•	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)	Distributed generation from the Solar*Rewards program is not included, was approximately 10, 11, and eight net million KWh for 2014, 2013, and 2012, respectively.

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•	Renewable energy comprised 14.7 percent and 12.7 percent of SPS’ energy for 2014 and 2013, respectively.

•	Wind energy comprised 14.0 percent and 12.1 percent of SPS’ energy for 2014 and 2013, respectively.

•	Solar power comprised approximately 0.4 percent of SPS’ energy for both 2014 and 2013.

•	The development of tariffs that provide for joint regional transmission planning and cost allocation for all FERC-jurisdictional utilities within a region;

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•	The coordination between regions for the development of interregional plans for transmission planning and cost allocation;

•	Each public utility transmission provider to amend its Open Access Transmission Tariff to describe procedures that provide for the consideration of transmission needs driven by public policy requirements in the local and regional transmission planning processes; and

•	The removal of ROFR provisions from FERC-jurisdictional wholesale transmission contracts and tariffs that presently grant the incumbent transmission owner a federal ROFR to build certain types of transmission projects in its service area.

•	A capital structure based on 55 percent equity and 45 percent debt for both TransCos;

•	Deferral of start-up costs for future recovery in rates, subject to a future filing prior to actual recovery;

•	XETD’s request for a base ROE using the currently applicable MISO regional rate of 12.38 percent, subject to any potential modifications resulting from a pending ROE complaint against the MISO transmission owners; and

•	XEST’s base ROE of 10.64 percent. However, the FERC suspended the proposed ROE and the ROE will be subject to refund and potential modifications resulting from settlement judge or hearing procedures set for 2015. Also, the FERC granted XEST’s request for a 50 basis point adder for membership in SPP.

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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 222, 198, and 152 net million KWh for 2014, 2013 and 2012, 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 recovers costs of DSM and performance initiatives to achieve various energy savings goals.

•	PSIA — The PSIA recovers costs associated with transmission and distribution pipeline integrity management programs and two projects to replace large transmission pipelines. The rider was extended through 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)	Based on PSCo’s ownership interest of 67 percent of Unit 3.

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

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

(d)	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.

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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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•	Improving utility performance;

•	Driving operational excellence;

•	Providing options and solutions to customers; and

•	Investing for the future.

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•	Close the ROE gap by 50 basis points by 2018; and

•	Derive 75 percent of our revenue from multi-year plans by 2017.

•	Deliver long-term annual EPS growth of four percent to six percent, based on a weather-normalized 2014 EPS of $2.00;

•	Deliver annual dividend increases of five percent to seven percent;

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•	Target a dividend payout ratio of 60 to 70 percent of annual ongoing EPS; and

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

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(a)	Not a reportable segment. Included in all other segment results in Note 17 to the consolidated financial statements.

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•	NSP-Wisconsin’s electric sales growth was largely due to strong sales to large C&I customers primarily in the oil, gas and sand mining industries.

•	SPS’ C&I growth was driven by continued expansion from oil and gas exploration and production in the Southeastern New Mexico, Permian Basin area.

•	PSCo’s electric sales growth was primarily due to customers in the food manufacturing, fracking and mining industries.

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•	NSP-Minnesota’s electric sales growth was led by an increased number of customers for both residential and small C&I, as well as higher use per customer in small C&I.

•	Across our natural gas service territories, strong sales were experienced in 2014, which continued the trend that began in the last half of 2013.

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(a)	The retail rate increases include final rates in Texas, Colorado (net of estimated earnings test refund obligations), New Mexico, Wisconsin and North Dakota and interim rates in Minnesota, subject to and net of estimated provision for refund. See Note 12 to the consolidated financial statements.

(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.

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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.

(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.

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•	Nuclear cost increases are related to the amortization of prior outages and initiatives designed to improve the operational efficiencies of the plants; and

•	Gain on sale of transmission assets relates to the 2013 gain associated with the sale of certain SPS’ transmission assets to Sharyland.

•	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.

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

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•	$292 million in 2014;

•	$275 million in 2013; and

•	$263 million in 2012.

•	$373 million in 2014;

•	$517 million in 2013; and

•	$255 million in 2012.

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•	$90.0 million in January 2015;

•	$130.6 million in 2014;

•	$192.4 million in 2013; and

•	$198.1 million in 2012.

(a)	These costs include the effects of regulation.

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•	Xcel Energy contributed $17.1 million, $17.6 million and $47.1 million during 2014, 2013 and 2012, respectively, to the postretirement health care plans.

•	Xcel Energy expects to contribute approximately $12.8 million during 2015.

•	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 postretirement 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.

•	PSCo and SPS recognize pension expense in all regulatory jurisdictions based on expense consistent with accounting guidance. The Colorado electric retail and Texas jurisdictions record the difference between annual recognized pension expense and the annual amount of pension expense approved in their last respective general rate case as a deferral to a regulatory asset.

•	Beginning in 2015, the Colorado electric retail jurisdiction expects to recognize additional expense associated with a pending order to accelerate amortization of the qualified prepaid pension asset. A regulatory liability would be recorded to account for any resulting regulatory obligation.

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•

Timing — Decommissioning cost estimates are impacted by each facility’s retirement date and 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 PI’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 2014 nuclear decommissioning filing assumed current technology and regulations.

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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 4.36 percent in calculating the AROs related to nuclear decommissioning for the remaining operational period through the radiological decommissioning period. An escalation rate of 3.36 percent was utilized for the period of operating costs related to interim dry cask storage of spent nuclear fuel and site restoration.

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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. 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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*	Cash from operations, net of dividend and pension funding.

**	Reflects a combination of short and long-term debt.

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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, 2014, 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, 2014, the amount that Xcel Energy would have to pay if it chose to terminate these leases was approximately $62.2 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 $228.3 million, $425.4 million, $424.6 million and $1.8 billion, for the less than 1 year, 1-3 years, 3-5 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 $3.6 billion of goods and services through the year 2050, in addition to the amounts disclosed in this table.

(g)	In January 2015, contributions of $90.0 million were made across four 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 $12.8 million to the postretirement health care plans during 2015. 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 $47 million and $37 million at Dec. 31, 2014 and 2013, respectively.

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•	$1 billion for Xcel Energy Inc.;

•	$700 million for PSCo;

•	$500 million for NSP-Minnesota;

•	$400 million for SPS; and

•	$150 million for NSP-Wisconsin.

(a)	These credit facilities have been amended to extend the maturity to October 2019.

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

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•	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 $750 million of debt securities.

•	NSP-Wisconsin has $100 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 $700 million of debt securities.

•	SPS has $150 million of debt securities remaining under its currently effective shelf registration statement, which was filed in April 2013. SPS intends to register additional debt securities in 2015.

•	In March, PSCo issued $300 million of 4.30 percent first mortgage bonds due March 15, 2044;

•	In May, NSP-Minnesota issued $300 million of 4.125 percent first mortgage bonds due May 15, 2044;

•	In June, SPS issued $150 million of 3.30 percent first mortgage bonds due June 15, 2024; and

•	In June, NSP-Wisconsin issued $100 million of 3.30 percent first mortgage bonds due June 15, 2024.

•	Xcel Energy Inc. plans to issue approximately $500 million of senior unsecured bonds;

•	PSCo plans to issue approximately $250 million of first mortgage bonds;

•	NSP-Minnesota plans to issue approximately $600 million of first mortgage bonds;

•	SPS plans to issue approximately $250 million of first mortgage bonds; and

•	NSP-Wisconsin plans to issue approximately $100 million of first mortgage bonds.

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•	Constructive outcomes in all rate case and regulatory proceedings.

•	If the MPUC orders a disallowance in the Monticello prudence review, Xcel Energy would exclude the associated charge from ongoing earnings.

•	Normal weather patterns are experienced for the year.

•	Weather-normalized retail electric utility sales are projected to increase approximately 1.0 percent.

•	Weather-normalized retail firm natural gas sales are projected to decline approximately 2.0 percent.

•	Capital rider revenue is projected to increase by $160 million to $170 million over 2014 levels. The projected capital rider revenue reflects the transfer of the CACJA project from base rates to the rider per the settlement in the Colorado electric rate case. The settlement is pending CPUC approval.

•	The change in O&M expenses is projected to be within a range of 0 percent to 2 percent from 2014 levels.

•	Depreciation expense is projected to increase $160 million to $180 million over 2014 levels, reflecting the originally proposed acceleration of the amortization of the excess depreciation reserve as part of NSP-Minnesota’s moderation plan in the Minnesota electric rate case.

•	Property taxes are projected to increase approximately $60 million to $70 million over 2014 levels.

•	Interest expense (net of AFUDC — debt) is projected to increase $40 million to $50 million over 2014 levels.

•	AFUDC — equity is projected to decline approximately $35 million to $45 million from 2014 levels.

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

•	Average common stock and equivalents are projected to be approximately 508 million shares.

•	Deliver long-term annual EPS growth of 4 percent to 6 percent, based on weather-normalized, ongoing 2014 EPS of $2.00;

•	Deliver annual dividend increases of 5 percent to 7 percent;

•	Target a dividend payout ratio of 60 percent to 70 percent of annual ongoing EPS; 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 and the December 2013 approval of PSCo’s preferred plans for applicable generating resources, PSCo has received approval for early retirement of Cherokee Unit 3 and Valmont Unit 5 between 2015 and 2017. 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, 2014 and 2013, respectively, as evidenced by the table below:

•	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.

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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.

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•	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 have been amended to extend the maturity to October 2019.

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

•	In March 2014, PSCo issued $300 million of 4.3 percent first mortgage bonds due March 15, 2044;

•	In May 2014, NSP-Minnesota issued $300 million of 4.125 percent first mortgage bonds due May 15, 2044;

•	In June 2014, SPS issued $150 million of 3.30 percent first mortgage bonds due June 15, 2024; and

•	In June 2014, NSP-Wisconsin issued $100 million of 3.30 percent first mortgage bonds due June 15, 2024.

•	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.

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•	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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•	PSCo has authorization to issue up to an additional $700 million of long-term debt and up to $800 million of short-term debt.

•	SPS has authorization to issue up to $500 million of short-term debt and plans to file for additional long-term authorization.

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

•	NSP-Minnesota has authorization to issue long-term securities provided the equity-to-total capitalization ratio remains between 47.1 percent and 57.5 percent and to issue short-term debt provided it does not exceed 15 percent of total capitalization. Total capitalization for NSP-Minnesota cannot exceed $9.5 billion.

5.	Joint Ownership of Generation, Transmission and Gas Facilities

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6.	Income Taxes

•	The R&E credit was extended for 2014;

•	PTCs were extended for projects that began construction before the end of 2014 with certain projects qualifying into future years; and

•	50 percent bonus depreciation was extended one year through 2014. Additionally, some longer production period property placed in service in 2015 is also eligible for 50 percent bonus depreciation.

•	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 R&E credit was extended for 2012 and 2013;

•	PTCs were extended for projects that began construction before the end of 2013 with certain projects qualifying into future years; 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 $10 million and $9 million as of Dec. 31, 2014 and 2013.

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7.	Earnings Per Share

•	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.

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

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8.	Share-Based Compensation

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•	The 2010 awards measured on EPS growth met their targets as of Dec. 31, 2011, and were settled in shares in February 2012.

•	The 2010 environmental awards met their targets as of Dec. 31, 2012 and were settled in shares in February 2013.

•	The 2011 awards measured on EPS growth and the 2011 environmental awards met their targets as of Dec. 31, 2013 and were settled in shares in February 2014.

•	The 2012 awards measured on EPS growth and the 2012 environmental awards met their targets as of Dec. 31, 2014, and will be settled in shares in February 2015.

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(a)	Compensation costs for share-based payment arrangements are 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 $7.4 million, $7.0 million, and $22.2 million for the years ended 2014, 2013 and 2012, respectively.

(c)

In October 2013, Xcel Energy determined that it would settle the 401(k) employer match in cash instead of common stock going forward 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 2,011 and NSP-Wisconsin had 402 bargaining employees covered under a collective-bargaining agreement, which expires at the end of 2016. NSP-Minnesota also had an additional 272 nuclear operation bargaining employees covered under several collective-bargaining agreements, which expire at various dates in 2015 and 2016.

•	PSCo had 2,063 bargaining employees covered under a collective-bargaining agreement, which expired in May 2014. While collective bargaining is ongoing, the terms and conditions of the expired agreement are automatically extended until the parties reach an agreement or a decision is rendered by an arbitrator.

•	SPS had 840 bargaining employees covered under a collective-bargaining agreement, which expired in October 2014. While collective bargaining is ongoing, the terms and conditions of the expired agreement are automatically extended until the parties reach an agreement or a decision is rendered by an arbitrator.

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•	Investment returns in 2014 were above the assumed level of 7.05 percent;

•	Investment returns in 2013 were below the assumed level of 6.88 percent;

•	Investment returns in 2012 were above the assumed level of 7.10 percent; and

•	In 2015, Xcel Energy’s expected investment return assumption is 7.09 percent.

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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.

•	$90.0 million in January 2015;

•	$130.6 million in 2014;

•	$192.4 million in 2013; and

•	$198.1 million in 2012.

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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)	Includes restricted cash of $1.0 million and $0.7 million at Dec. 31, 2014 and 2013, respectively.

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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 $83.1 million of equity investments in unconsolidated subsidiaries and $45.6 million of miscellaneous investments.

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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)	Gains and losses are deferred as a component of the regulatory asset for nuclear decommissioning.

(b)	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 year ended Dec. 31, 2012 included $5.0 million 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 years ended Dec. 31, 2014 and 2013 were immaterial. The remaining settlement losses for the years ended Dec. 31, 2014, 2013 and 2012 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, 2014. At Dec. 31, 2014, derivative assets and liabilities include no obligations to return cash collateral and rights to reclaim cash collateral of $6.6 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, 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)	These amounts relate to commodity derivatives held at the end of the period.

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(a)	The true-up adjustment for the sales forecast reflects weather-normalized sales through December 2014.

(b)	The true-up adjustment for property taxes reflects NSP-Minnesota’s 2014 year end property tax accruals.

(c)	In July 2014, the DOC recommended a cost disallowance of approximately $71.5 million on a Minnesota jurisdictional basis which equates to a total NSP System disallowance of approximately $94 million. This would reduce NSP-Minnesota’s revenue requirement by approximately $10.2 million in 2015.

(d)	Adjustment is due to timing differences and/or methodology of accelerating amortization of the excess depreciation reserve over three years.

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•	In December 2014, the MPUC approved NSP-Minnesota’s 2013 CIP electric and natural gas financial incentives totaling $42.7 million and $5.4 million, respectively.

•	In addition, the MPUC approved NSP-Minnesota’s proposed 2014 to 2015 electric and natural gas CIP riders. NSP-Minnesota estimates 2015 recovery of $15.5 million of electric CIP expenses and $6.0 million of natural gas CIP expenses.

•	This proposed recovery through the riders is in addition to an estimated $86.9 million and $3.7 million through electric and gas base rates, respectively.

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•	The settlement is based on a 2013 HTY, an ROE of 9.83 percent and an equity ratio of 56 percent;

•	It includes the implementation of a forward-looking CACJA rider, effective Jan. 1, 2015, a forward-looking TCA rider, effective Feb. 13, 2015 and tracking mechanisms for pension expense and property taxes; and

•	The agreement also includes an earnings test for 2015 through 2017, under which PSCo and customers would share in any earnings on a 50/50 basis if the ROE recognized falls between 9.84 percent and 10.48 percent. The earnings test principles are based primarily on those established in the previous rate case.

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•	Intervenor Direct Testimony — April 1, 2015;

•	Staff Direct Testimony — April 8, 2015;

•	Staff and Intervenor Cross-Rebuttal Testimony — April 22, 2015;

•	Rebuttal Testimony — April 24, 2015; and

•	Evidentiary Hearing — May 11, 2015.

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(a)	Excludes contingent energy payments for renewable energy 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 2018, which is the final scheduled repayment date for the loans. As of Dec. 31, 2014, 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 this guarantee expires in 2019 when the associated lease expires.

(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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(a)	There were no ARO liabilities settled during the year ended Dec. 31, 2014.

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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.

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15.	Regulatory Assets and Liabilities

(a)

Includes $282.4 million and $303.3 million for the regulatory recognition of the NSP-Minnesota pension expense of which $23.8 million and $23.2 million is included in the current asset at Dec. 31, 2014 and 2013, respectively. Also included are $26.1 million and $17.7 million of regulatory assets related to the nonqualified pension plan of which $2.5 million and $2.2 million is included in the current asset at Dec. 31, 2014 and 2013, 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 PI EPU project, NSP-Minnesota has addressed recovery of incurred costs in the pending multi-year rate case.

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(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.

16.	Other Comprehensive Income

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(a)	Included in interest charges.

(b)	Included in O&M expenses.

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

•

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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