---

---

---

---

---

---

---

---

•	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 in Minnesota.

•	RER — The RER recovers the cost of new renewable generation in North Dakota.

•	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 and distribution costs that facilitate grid modernization.

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

---

•	The addition of 800 MW of wind and 400 MW of utility scale solar to the pre-2020 time-frame;

•	The addition of 1000 MW of wind and 1000 MW of utility scale solar between 2020-2030;

•	The retirement of Sherco Unit 2 in 2023 and Sherco Unit 1 in 2026;

•	The addition of a 230 MW natural gas combustion turbine in North Dakota by 2025;

•	Replacement of Sherco coal generation with a 786 MW natural gas combined cycle unit at the Sherco site no later than 2026; and

•	Operation of the Monticello and PI nuclear plants through their current license periods in the early 2030’s.

---

•	Acceleration of NSP-Minnesota’s commitment to locate thermal generation in North Dakota from 2036 to by the end of 2025;

•	Exclusion of select wind and small solar PPAs from the NSP-Minnesota’s North Dakota Fuel Cost Rider;

•	Continued recovery in North Dakota of six existing biomass PPAs, subject, in part, to refund if NSP-Minnesota fails to achieve its generation commitment by the end of 2025;

•	Extension of the current rate moratorium through 2017;

•	NDPSC Staff support for continued use of 12-Coincident Peak system allocator through 2025; and,

•	Development of a framework to address future generation resources to be filed with the NDPSC by Jan. 1, 2017.

•

Hampton, Minn. to Rochester, Minn. to La Crosse, Wis. 161/345 Kilovolt (KV) transmission line — The Wisconsin portion of the project includes a new substation and approximately 50 miles of new 345 KV transmission line, at an estimated cost of $211 million. The final 161 KV segment of the project went into service in January 2016, while the final 345 KV segment of the project is expected to go into service in the fall of 2016;

•	Brookings County, S.D. to Hampton, Minn. 345 KV transmission line — The project was placed in service in March 2015;

•	Bemidji, Minn. to Grand Rapids, Minn. 230 KV transmission line — The project was placed in service in September 2012;

•	Monticello, Minn. to Fargo, N.D. 345 KV transmission line — In April 2015, the final portion of the project was placed in service; and

•	Big Stone South to Brookings County, S.D. 345 KV transmission line — Construction on the line began in September 2015, with completion anticipated in 2017.

---

•	Increased flexibility for utilities to submit a MYP of up to five years;

•	The potential for full capital recovery for all proposed years;

•	O&M cost recovery based on an index;

•	Distribution costs that facilitate grid modernization are eligible for rider recovery;

•	Natural gas extension costs for unserved areas can be socialized and are eligible for rider recovery;

•	Recovery of plant closure costs, should the MPUC order early plant closure, such as in a resource plan; and

•	Allows implementation of interim rates for the first and second years of the MYP.

---

---

---

(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 eight, seven, and eight million net KWh for 2015, 2014, and 2013, respectively.

(a)	Includes refuse-derived fuel and wood.

---

•	Current nuclear fuel supply contracts cover 100 percent of uranium concentrates requirements through 2018 and approximately 59 percent of the requirements for 2019 through 2030;

•	Current contracts for conversion services cover 100 percent of the requirements through 2021 and approximately 54 percent of the requirements for 2022 through 2030; and

•	Current enrichment service contracts cover 100 percent of the requirements through 2026 and approximately 34 percent of the requirements for 2027 through 2030.

•	Renewable energy comprised 23.3 percent and 24.2 percent of the NSP System’s total energy for 2015 and 2014, respectively;

---

•	Wind energy comprised 13.6 percent and 13.7 percent of the total energy for 2015 and 2014, respectively;

•	Hydroelectric energy comprised 7.3 percent and 7.8 percent of the total energy for 2015 and 2014, respectively; and

•	Biomass and solar power comprised approximately 2.4 percent and 2.7 percent of the total energy for 2015 and 2014, respectively.

•	Collectively, the NSP System had approximately 2,210 and 1,860 MWs of wind energy on its system at the end of 2015 and 2014, respectively. In addition to receiving purchased wind energy under these agreements, the NSP System also typically receives wind RECs, which are used to meet state renewable resource requirements.

•

The average cost per MWh of wind energy under the existing contracts was approximately $42 and $41 for 2015 and 2014, respectively.  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 2015 continued to benefit from improvements in technology, excess capacity among manufacturers, and motivation to commence new construction prior to the anticipated expiration of the Federal PTCs. In December 2015, the Federal PTCs were extended through 2019 with a phase down beginning in 2017.

---

---

•	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 on a quarterly basis beginning in January 2015.

•	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 — The CACJA recovers costs associated with implementing its compliance plan under the CACJA.

---

•	The addition of 450 MW of wind generation PPAs became operational in 2015. These additional PPAs bring the installed wind capacity on PSCo’s system in Colorado to 2,560 MW;

•	The addition of 170 MW of utility-scale solar generation PPAs, of which 50 MW became operational in 2015 and the remaining 120 MW of utility-scale solar generation is expected to be operational by mid-2016. PSCo has approximately 80 MW of utility-scale solar and approximately 258 MW of customer-sited solar generation;

•	The addition of 317 MW of natural gas fired generation PPAs 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.

---

•	Two Innovative Clean Technology pilot programs in partnership with leading companies to address electric battery efficiency and reliability including demonstrations to test microgrids and battery technologies for integration of distributed resources;

•	Alignment of PSCo’s pricing in a more fair and equitable manner for Colorado customers;

•	Introduction of Solar*Connect®, a new, cost-based program that will offer customers a choice to sign up for 100 percent solar power and add an incremental 50 MW of solar generation;

•	Investing in natural gas reserves to take advantage of historically low natural gas prices by locking in current costs to provide long-term stable rates for customers;

•	Exploring opportunities for up to 1,000 MW of additional renewable resources to be presented later this year for consideration by the CPUC; and

•	Presenting an intelligent grid proposal later this year focusing on interactive meter technology that will improve customer choice and control of their energy use.

(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 245, 197, and 172 million net KWh for 2015, 2014, and 2013, respectively.

---

•	At Dec. 31, 2015, PSCo’s commitments related to gas supply contracts, which expire in various years from 2016 through 2023, were approximately $750 million and commitments related to gas transportation and storage contracts, which expire in various years from 2016 through 2060, were approximately $684 million.

•	At Dec. 31, 2014, PSCo’s commitments related to gas supply contracts were approximately $902 million and commitments related to gas transportation and storage contracts were approximately $685 million.

---

•	Renewable energy comprised 21.9 percent and 21.4 percent of PSCo’s total energy for 2015 and 2014, respectively;

•	Wind energy comprised 19.4 percent and 18.9 percent of the total energy for 2015 and 2014, respectively; and

•	Hydroelectric, biomass and solar power comprised approximately 2.6 percent and 2.5 percent of the total energy for 2015 and 2014.

•	PSCo had approximately 2,560 MW and 2,340 MW of wind energy on its system at the end of 2015 and 2014, respectively. 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.

•

The average cost per MWh of wind energy under these contracts was approximately $42 and $45 in 2015 and 2014, respectively. 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 2015 continued to benefit from improvements in wind technology, excess capacity among manufacturers, and motivation to commence new construction prior to the anticipated expiration of the Federal PTCs. In December 2015, the Federal PTCs were extended through 2019 with a phase down beginning in 2017.

---

•	DCRF — The DCRF rider recovers certain distribution costs in Texas that are not included in base rates.

•	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 that are not included in base rates.

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

•	TCRF — The TCRF rider recovers certain transmission infrastructure improvement costs and changes in wholesale transmission charges in Texas that are not included in base rates.

---

•	Utilities may include actual and estimated post-test year capital additions up through 30-days before the filing date;

•	A new natural gas generating unit may be included in rate base as long as it is in service before the proposed effective rate date;

•	Rates will go into effect 155 days after filing (previously it was 185 days). If the case is not final by this date, then a utility can go back and surcharge; and

•	Establishes time limits for the PUCT to rule on a new generation plant request for a certificate of convenience and necessity.

---

(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 13, 10, and 11 million net KWh for 2015, 2014, and 2013, respectively.

---

•	SPS had approximately 1,775 MW and 1,500 MW of wind energy on its system at the end of 2015 and 2014, respectively. In addition to receiving purchased wind energy under these agreements, SPS also typically receives wind RECs, which are used to meet state renewable resource requirements.

•

The average cost per MWh of wind energy under the IPP contracts and QF tariffs was approximately $24 and $26 for 2015 and 2014, respectively.  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 2015 continued to benefit from improvements in technology, excess capacity among manufacturers, and motivation to commence new construction prior to the anticipated expiration of the Federal PTCs. In December 2015, the Federal PTCs were extended through 2019 with a phase down beginning in 2017.

---

---

---

(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 266, 222, and 198 million net KWh for 2015, 2014 and 2013, respectively.

---

---

---

•	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 2018.

---

---

---

---

---

---

•	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.

---

---

---

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

•	Limitations on the amounts and types of insurance 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. For example, similar to pensions, interest rate and other assumptions regarding decommissioning costs may change based on economic conditions and changes in the expected life of the asset may cause our funding obligations to change.

---

---

---

---

---

(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.

---

(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.

---

---

---

(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.

(b)	Xcel Energy Inc. withholds stock to satisfy tax withholding obligations on vesting of awards of restricted stock under the Xcel Energy Executive Annual Incentive Award Plan.

---

(a)	Includes capital lease obligations.

(b)	See Exhibit 12.01.

(c)	See Item 7 for reconciliations of ongoing earnings and diluted EPS to GAAP earnings and diluted EPS.

---

•	Improving utility performance;

•	Driving operational excellence;

•	Improving customer experience; and

•	Investing for the future.

•	Close the regulated ROE gap by 50 basis points by 2018 from the 2014 base level; and

•	Derive 75 percent of our revenue from regulated operations via multi-year regulatory plans by 2017.

---

•	Deliver long-term annual EPS growth of four percent to six percent, based on ongoing 2015 EPS of $2.10, which was the mid-point of Xcel Energy’s 2015 ongoing guidance range;

•	Deliver annual dividend increases of five percent to seven percent (prior objective was two to four percent annually);

•	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.

---

(a)	Amounts may not add due to rounding.

---

---

(a)	Amounts may not add due to rounding.

---

(a)	Excluding the impact of negative/positive weather, the Operating Companies and Xcel Energy’s ongoing ROEs equate to 9.07 percent and 10.40 percent, respectively, for 2015 and 9.06 percent and 10.18 percent, respectively, for 2014.

(a)	Amounts may not add due to rounding.

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

---

---

•	PSCo’s residential growth was primarily the result of customer additions, partially offset by lower use per customer. Commercial and industrial (C&I) decline was primarily due to reduced sales to certain large manufacturing customers and/or those that support the fracking industry.

•

NSP-Minnesota’s residential decrease was due to lower use per customer, partially offset by an increase in customer additions. C&I electric sales decreased as a result of lower use by large and small customers (e.g., services, retail trade, finance insurance and real estate industries), partially offset by higher use by certain large customers in the petroleum and food processing industries. The decline was partially reduced by an increase in the number of customers in both the small and large classes.

•	SPS’ residential growth reflects an increased number of customers. C&I also had an increase in customers, primarily in the oil and gas exploration and production industries. However, this was partially offset by reduced activity per customer within these industries, as well as less irrigation by agricultural customers due to wet weather.

•	NSP-Wisconsin’s residential decline was primarily attributable to lower use per customer, partially offset by customer additions. C&I electric sales growth was largely due to strong sales to large customers primarily in the oil and gas industries.

•	Across natural gas service territories, lower natural gas sales reflect a decline in customer use.

---

•	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.

•	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.

---

---

(a)	The retail rate increases included final rates in Texas, Colorado (net of estimated earnings test refund obligations), New Mexico, Wisconsin and North Dakota and interim rates in Minnesota, which were subject to and net of estimated provision for refund.

(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.

---

•	Nuclear expense decreased primarily driven by operational efficiencies and lower amortization of prior outages; and

•	Labor and contract labor increased as a result of various projects and initiatives to improve business processes.

---

•	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.

---

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

---

•	$292 million in 2015;

•	$292 million in 2014; and

•	$275 million in 2013.

---

•	$184 million in 2015;

•	$373 million in 2014; and

•	$517 million in 2013.

---

---

•	$125.0 million in January 2016;

•	$90.1 million in 2015;

---

•	$130.6 million in 2014; and

•	$192.4 million in 2013.

(a)	These costs include the effects of regulation.

•	Xcel Energy contributed $18.3 million, $17.1 million and $17.6 million during 2015, 2014 and 2013, respectively, to the postretirement health care plans.

•	Xcel Energy expects to contribute approximately $12.3 million during 2016.

•	NSP-Minnesota recognizes pension expense in all regulatory jurisdictions 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 Texas and Colorado electric retail jurisdictions, and commencing in 2016, the Colorado gas retail jurisdiction, each 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.

---

•

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.

•

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.

•

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.

---

---

---

---

---

*	Net of dividend and pension funding.

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

---

(a)	Includes interest payments over the terms of the debt. Interest is calculated using the applicable interest rate at Dec. 31, 2015, 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, 2015, the amount that Xcel Energy would have to pay if it chose to terminate these leases was approximately $61.0 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 $217.0 million, $418.7 million, $469.1 million and $2.1 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 and approximate investments in Energy Impact Fund LP, as well as uncertain tax positions.

(f)	Xcel Energy also has outstanding authority under O&M contracts to purchase up to approximately $3.2 billion of goods and services through the year 2053, in addition to the amounts disclosed in this table.

(g)	In January 2016, contributions of $125.0 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 $12.3 million to the postretirement health care plans during 2016. 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.

---

(a)	Excludes nonqualified plan of $42 million and $47 million at Dec. 31, 2015 and 2014, respectively.

•	$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 mature in October 2019.

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

•	Xcel Energy Inc. plans to issue approximately $700 million of senior unsecured bonds;

•	NSP-Minnesota plans to issue approximately $250 million of first mortgage bonds; and

•	SPS plans to issue approximately $350 million of first mortgage bonds.

---

•	PSCo issued $250 million of 2.9 percent first mortgage bonds due May 15, 2025;

•	Xcel Energy Inc. issued $250 million of 1.2 percent senior notes due June 1, 2017 and $250 million of 3.3 percent senior notes due June 1, 2025;

•	NSP-Wisconsin issued $100 million of 3.3 percent first mortgage bonds due June 15, 2024;

•	NSP-Minnesota issued $300 million of 2.2 percent first mortgage bonds due Aug. 15, 2020 and $300 million of 4.0 percent first mortgage bonds due Aug. 15, 2045; and

•	SPS issued $200 million of 3.3 percent first mortgage bonds due June 15, 2024.

•	Constructive outcomes in all rate case and regulatory proceedings.

•	Normal weather patterns are experienced for the year.

•	Weather-normalized retail electric utility sales are projected to increase approximately 0.5 percent to 1.0 percent.

•	Weather normalized retail firm natural gas sales are projected to be relatively flat.

•	Capital rider revenue is projected to increase by $70 million to $80 million over 2015 levels.

•	The change in O&M expenses is projected to be within a range of 0 percent to 2 percent from 2015 levels.

•	Depreciation expense is projected to increase approximately $200 million over 2015 levels.

•	Property taxes are projected to increase approximately $40 million to $50 million over 2015 levels.

•	Interest expense (net of AFUDC — debt) is projected to increase $40 million to $50 million over 2015 levels.

•	AFUDC — equity is projected to decline approximately $10 million to $15 million from 2015 levels.

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

•	Average common stock and equivalents are projected to be approximately 509 million shares.

---

•	Deliver long-term annual EPS growth of 4 percent to 6 percent, based on ongoing 2015 EPS of $2.10, which was the mid-point of Xcel Energy’s 2015 ongoing guidance range;

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

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

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

---

---

---

---

---

---

---

---

---

---

(a)	Pollution control financing.

(b)	Resource recovery financing.

---

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 or OCI, 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.

---

---

---

---

---

---

3.	Selected Balance Sheet Data

---

(a)	PSCo’s Cherokee Unit 3 was retired in August 2015. In 2017, PSCo expects to both early retire Valmont Unit 5 and convert Cherokee Unit 4 from a coal-fueled generating facility to natural gas, as approved by the CPUC. Amounts are presented net of accumulated depreciation.

4.	Borrowings and Other Financing Instruments

---

•	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, 2015 and 2014, 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.

•

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.

•	Xcel Energy Inc. and its subsidiaries were in compliance with all financial covenants in their debt agreements as of Dec. 31, 2015 and 2014.

•	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 mature in October 2019.

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

---

•	PSCo issued $250 million of 2.9 percent first mortgage bonds due May 15, 2025;

•	Xcel Energy Inc. issued $250 million of 1.2 percent senior notes due June 1, 2017 and $250 million of 3.3 percent senior notes due June 1, 2025;

•	NSP-Wisconsin issued $100 million of 3.3 percent first mortgage bonds due June 15, 2024;

•	NSP-Minnesota issued $300 million of 2.2 percent first mortgage bonds due Aug. 15, 2020 and $300 million of 4.0 percent first mortgage bonds due Aug. 15, 2045; and

•	SPS issued $200 million of 3.3 percent first mortgage bonds due June 15, 2024.

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

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

•	SPS issued $150 million of 3.3 percent first mortgage bonds due June 15, 2024; and

•	NSP-Wisconsin issued $100 million of 3.3 percent first mortgage bonds due June 15, 2024.

---

•	PSCo has authorization to issue up to an additional $450 million of long-term debt and up to $800 million of short-term debt.

•	SPS has authorization to issue up to $100 million of long-term debt and $500 million of short-term debt.

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

•	NSP-Minnesota has authorization to issue long-term securities provided the equity-to-total capitalization ratio remains between 46.9 percent and 57.3 percent and to issue short-term debt provided it does not exceed 15 percent of total capitalization. Total capitalization for NSP-Minnesota cannot exceed $10.5 billion.

---

5.	Joint Ownership of Generation, Transmission and Gas Facilities

---

6.	Income Taxes

•	Immediate expensing, or “bonus depreciation,” of 50 percent for property placed in service in 2015, 2016, and 2017; 40 percent for property placed in service in 2018; and 30 percent for property placed in service in 2019. Additionally, some longer production period property placed in service in 2020 will be eligible for bonus depreciation;

•

PTCs at 100 percent of the credit rate ($0.023 per KWh) for wind energy projects that begin construction by the end of 2016; 80 percent of the credit rate for projects that begin construction in 2017; 60 percent of the credit rate for projects that begin construction in 2018; and 40 percent of the credit rate for projects that begin construction in 2019. The wind energy PTC was not extended for projects that begin construction after 2019;

•	ITCs at 30 percent for commercial solar projects that begin construction by the end of 2019; 26 percent for projects that begin construction in 2020; 22 percent for projects that begin construction in 2021; and 10 percent for projects thereafter;

•	R&E credit was permanently extended; and

•	Delay of two years (until 2020) of the excise tax on certain employer-provided health insurance plans.

•	Recognition of additional tax deductions for bonus depreciation of $1.2 billion, and as a result, recognition of $4.9 million benefit related to a carryback claim (see additional discussion below) and $3.5 million expense related to valuation allowances and expirations of charitable contribution carryforwards; and

•	Recognition of $6.8 million benefit for federal R&E credits.

•	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.

---

---

(a)	State tax credit carryforwards are net of federal detriment of $24 million and $10 million as of Dec. 31, 2015 and 2014, respectively.

(b)	Valuation allowances for state tax credit carryforwards were net of federal benefit of $13 million as of Dec. 31, 2015.

---

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.

8.	Share-Based Compensation

---

•	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 were settled in shares in February 2015.

•	The 2013 awards measured on EPS growth, the 2013 environmental awards and the 2013 time-based awards met their targets as of Dec. 31, 2015, and will be settled in shares in February 2016.

---

---

(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, and $7.0 million for the years ended 2014 and 2013, respectively. 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. In August 2015, consistent with a new PSCo bargaining agreement, share-based compensation accounting ceased for the employer 401(k) match for PSCo bargaining employees, which will be paid in cash. As a result, 2015 compensation cost for share-based awards includes no 401(k) matching contributions.

(c)	An allocated amount of the 401(k) match is capitalized.

---

•

NSP-Minnesota had 1,983 and NSP-Wisconsin had 400 bargaining employees covered under a collective-bargaining agreement, which expires at the end of 2016. NSP-Minnesota also had an additional 265 nuclear operation bargaining employees covered under several collective-bargaining agreements. Some of these agreements expired in 2015, but were extended to 2016. The remaining agreements expire in 2016 and 2018.

•	PSCo had 2,024 bargaining employees covered under a collective-bargaining agreement, which expires in May 2017.

•	SPS had 842 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.

---

•	Investment returns in 2015 were below the assumed level of 7.09 percent;

•	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; and

•	In 2016, Xcel Energy’s expected investment return assumption is 6.87 percent.

---

---

(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.

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

---

•	$125.0 million in January 2016;

•	$90.1 million in 2015;

•	$130.6 million in 2014; and

•	$192.4 million in 2013.

---

•	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 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.

---

(a)	Includes restricted cash of $1.0 million at Dec. 31, 2014.

(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.

---

---

---

10.	Other Income, Net

---

---

(a)	Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $130.0 million of equity investments in unconsolidated subsidiaries and $48.9 million of miscellaneous investments.

(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.

---

(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.

---

(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.

---

---

(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, 2015 included $1.1 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, 2015, 2014 and 2013 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.

---

---

(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, 2015. At Dec. 31, 2015, derivative assets and liabilities include no obligations to return cash collateral and rights to reclaim cash collateral of $4.3 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)

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.

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

---

---

•	Intervenors’ direct testimony — June 14, 2016;

•	Rebuttal testimony — Aug. 9, 2016;

•	Surrebuttal testimony — Sept. 16, 2016;

•	Settlement conference — Sept. 26, 2016;

•	Evidentiary hearing — Oct. 4-7, 2016;

•	ALJ report — Feb. 21, 2017; and

•	MPUC order — June 1, 2017.

---

•	In July 2015, the MPUC approved NSP-Minnesota’s 2014 CIP electric and natural gas financial incentives totaling $40.1 million and $5.8 million, respectively.

•	In addition, the MPUC approved NSP-Minnesota’s proposed 2015 to 2016 electric and natural gas CIP riders. NSP-Minnesota estimates 2016 recovery of $21.5 million of electric CIP expenses and $9.2 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.

---

---

•	2014 HTY, with a 13-month average rate base, with the exception of the Cherokee pipeline which is included at a year-end level;

•	Extension of the PSIA rider through 2018 with all O&M expenses transferred to base rates;

•	A ROE of 9.5 percent; and

•	An equity ratio of 56.51 percent.

(a)	The ALJ’s recommendation and the CPUC’s written order also includes approximately $20.0 million of PSIA costs be transferred to base rates, effective Jan. 1, 2016.

(a)	Deferral and amortization impacts relate primarily to recognition of accelerated amortization of prepaid pension assets and deferrals of pension expense in excess of the amount approved in the prior general gas rate case.

---

•	A 2015 DSM electric budget of $81.6 million and a natural gas budget of $13.1 million; and

•	A 2016 DSM electric budget of $78.7 million and a natural gas budget of $13.6 million.

•	Disallowed SPS’ proposed adjustment to jurisdictional allocation factors to reflect Golden Spread Electric Cooperative, Inc.’s (Golden Spread’s) wholesale load reductions from 500 MW to 300 MW, effective June 1, 2015;

•	Disallowed incentive compensation;

•	Approved an equity ratio of 51.00 percent instead of the actual 53.97 percent; and

•	A ROE of 9.70 percent.

---

(a)	SPS anticipates rate case expenses, for this proceeding, to be separated from the request for consideration in a separate docket.

---

•	Settlement conference — Feb. 29, 2016;

•	Staff and intervenor direct testimony — April 1, 2016;

•	Rebuttal testimony — April 18, 2016; and

•	Evidentiary hearing begins — April 28, 2016.

---

---

(a)	Excludes contingent energy payments for renewable energy PPAs.

---

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

(b)	PPA operating leases contractually expire through 2039.

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

---

---

---

(a)	The term of this guarantee expires in 2020, which is the final scheduled repayment date for the loans. As of Dec. 31, 2015, 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 any one of Xcel Energy Inc.’s utility 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.

---

---

---

---

---

---

(a)	The liability recognized relates to the NSP-Minnesota Pleasant Valley and Border Wind Farms which were placed in service during 2015.

(b)	In 2015, AROs were revised for changes in estimated cash flows and the timing of those cash flows. Changes in the asbestos AROs were mainly related to updated cost estimates.

(a)

In 2014, revisions were made to various AROs due to revised estimated cash flows and the timing of those cash flows. Changes to estimated nuclear production decommissioning primarily relate to the triennial filing made to the MPUC in December 2014. See additional information in Note 14. Changes in estimated excavation costs and the timing of future retirement activities resulted in revisions to AROs related to gas transmission and distribution.

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

---

---

---

14.	Nuclear Obligations

---

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

15.	Regulatory Assets and Liabilities

(a)

Includes $257.5 million and $282.4 million for the regulatory recognition of the NSP-Minnesota pension expense of which $21.3 million and $23.8 million is included in the current asset at Dec. 31, 2015 and 2014, respectively. Also included are $12.5 million and $26.1 million of regulatory assets related to the nonqualified pension plan of which $4.0 million and $2.5 million is included in the current asset at Dec. 31, 2015 and 2014, respectively.

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

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

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

---

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

(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)	Revenue subject to refund of $75.0 million and $128.3 million for 2015 and 2014, respectively, is included in other current liabilities.

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 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 wholesale commodity and trading operations.

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

•

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

---

18.	Summarized Quarterly Financial Data (Unaudited)

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

(a)	Recovery of amounts previously written off as related to allowance for bad debts. Accrual of valuation allowance for North Dakota ITC, offset to regulatory liability.

(b)	Deductions related to allowance for bad debts relates primarily to write-offs. Reductions to valuation allowances for North Dakota ITC carryforwards primarily due to a consolidated adjustment to the regulatory liability accrual referenced above. Reductions to valuation allowances for NOL carryforwards primarily due to changes in forecasted taxable income.

---