Item 1 — Business

DEFINITION OF ABBREVIATIONS AND INDUSTRY TERMS

Xcel Energy Inc.’s Subsidiaries and Affiliates (current and former)
Cheyenne	Cheyenne Light, Fuel and Power Company
Eloigne	Eloigne Company
NCE	New Century Energies, Inc.
NMC	Nuclear Management Company, LLC
NSP-Minnesota	Northern States Power Company, a Minnesota corporation
NSP System	The electric production and transmission system of NSP-Minnesota and NSP-Wisconsin operated on an integrated basis and managed by NSP-Minnesota
NSP-Wisconsin	Northern States Power Company, a Wisconsin corporation
PSCo	Public Service Company of Colorado
PSRI	P.S.R. Investments, Inc.
SPS	Southwestern Public Service Co.
Utility subsidiaries	NSP-Minnesota, NSP-Wisconsin, PSCo and SPS
WGI	WestGas InterState, Inc.
WYCO	WYCO Development LLC
Xcel Energy	Xcel Energy Inc. and its subsidiaries
XETD	Xcel Energy Transmission Development Company, LLC
XEST	Xcel Energy Southwest Transmission Company, LLC
XEWT	Xcel Energy West Transmission Company, LLC

Federal and State Regulatory Agencies
ASLB	Atomic Safety and Licensing Board
CFTC	Commodity Futures Trading Commission
CPUC	Colorado Public Utilities Commission
D.C. Circuit	United States Court of Appeals for the District of Columbia Circuit
DOC	Minnesota Department of Commerce
DOE	United States Department of Energy
DOI	United States Department of the Interior
DOT	United States Department of Transportation
EPA	United States Environmental Protection Agency
FERC	Federal Energy Regulatory Commission
IRS	Internal Revenue Service
MPCA	Minnesota Pollution Control Agency
MPSC	Michigan Public Service Commission
MPUC	Minnesota Public Utilities Commission
NDPSC	North Dakota Public Service Commission
NERC	North American Electric Reliability Corporation
NMAG	New Mexico Attorney General
NMPRC	New Mexico Public Regulation Commission
NRC	Nuclear Regulatory Commission
PNM	Public Service Company of New Mexico
PSCW	Public Service Commission of Wisconsin
PUCT	Public Utility Commission of Texas
SDPUC	South Dakota Public Utilities Commission
SEC	Securities and Exchange Commission
WDNR	Wisconsin Department of Natural Resources

Electric, Purchased Gas and Resource Adjustment Clauses
CIP	Conservation improvement program
DCRF	Distribution cost recovery factor
DRC	Deferred renewable cost rider
DSM	Demand side management
DSMCA	Demand side management cost adjustment
ECA	Retail electric commodity adjustment
EE	Energy efficiency
EECRF	Energy efficiency cost recovery factor
EIR	Environmental improvement rider (recovers the costs associated with investments in environmental improvements to fossil fuel generation plants)
EPU	Extended power uprate
ERP	Electric resource plan
FCA	Fuel clause adjustment
FPPCAC	Fuel and purchased power cost adjustment clause
GAP	Gas affordability program
GCA	Gas cost adjustment
OATT	Open access transmission tariff
PCCA	Purchased capacity cost adjustment
PCRF	Power cost recovery factor (recovers the costs of certain purchased power costs)
PGA	Purchased gas adjustment
PSIA	Pipeline system integrity adjustment
QSP	Quality of service plan
RDF	Renewable development fund
RES	Renewable energy standard (recovers the costs of new renewable generation)
RESA	Renewable energy standard adjustment
SCA	Steam cost adjustment
SEP	State energy policy
TCA	Transmission cost adjustment
TCR	Transmission cost recovery adjustment
TCRF	Transmission cost recovery factor (recovers transmission infrastructure improvement costs and changes in wholesale transmission charges)

Other Terms and Abbreviations
AFUDC	Allowance for funds used during construction
ATM	At-the-market
ALJ	Administrative law judge
APBO	Accumulated postretirement benefit obligation
ARO	Asset retirement obligation
ASU	FASB Accounting Standards Update
BART	Best available retrofit technology
C&I	Commercial and Industrial
CAA	Clean Air Act
CACJA	Clean Air Clean Jobs Act
CAIR	Clean Air Interstate Rule
CapX2020	Alliance of electric cooperatives, municipals and investor-owned utilities in the upper Midwest involved in a joint transmission line planning and construction effort
CCN	Certificate of convenience and necessity
CIG	Colorado Interstate Gas Company, LLC
CO₂	Carbon dioxide
CON	Certificate of need

CP	Coincident peak
CPCN	Certificate of public convenience and necessity
CSAPR	Cross-State Air Pollution Rule
CWIP	Construction work in progress
EEI	Edison Electric Institute
EGU	Electric generating unit
EPS	Earnings per share
ERCOT	Electric Reliability Council of Texas
ETR	Effective tax rate
FASB	Financial Accounting Standards Board
FTR	Financial transmission right
FTY	Forecast test year
GAAP	Generally accepted accounting principles
GHG	Greenhouse gas
HTY	Historic test year
IFRS	International Financial Reporting Standards
LCM	Life cycle management
LLW	Low-level radioactive waste
LNG	Liquefied natural gas
MACT	Maximum achievable control technology
MGP	Manufactured gas plant
MISO	Midcontinent Independent System Operator, Inc.
Moody’s	Moody’s Investor Services
MVP	Multi-value project
Native load	Customer demand of retail and wholesale customers that a utility has an obligation to serve under statute or long-term contract
NEI	Nuclear Energy Institute
NOL	Net operating loss
NOx	Nitrogen oxide
NOV	Notice of violation
NSPS	New source performance standard
NTC	Notifications to construct
NYISO	New York Independent System Operator
O&M	Operating and maintenance
OCC	Office of Consumer Counsel
OCI	Other comprehensive income
PCB	Polychlorinated biphenyl
PFS	Private Fuel Storage, LLC
PI	Prairie Island nuclear generating plant
PJM	PJM Interconnection, LLC
PM	Particulate matter
PPA	Purchased power agreement
PRP	Potentially responsible party
PTC	Production tax credit
PV	Photovoltaic
QF	Qualifying facilities
R&E	Research and experimentation
REC	Renewable energy credit
RFP	Request for proposal
ROE	Return on equity

ROFR	Right of first refusal
RPS	Renewable portfolio standards
RSG	Revenue sufficiency guarantee
RTO	Regional Transmission Organization
SCR	Selective catalytic reduction
Sharyland	Sharyland Distribution and Transmission Services, LLC
SIP	State implementation plan
SO₂	Sulfur dioxide
SPP	Southwest Power Pool, Inc.
S&P	Standard & Poor’s Ratings Services
TransCo	Transmission-only subsidiary
TSR	Total shareholder return
Measurements
Bcf	Billion cubic feet
GWh	Gigawatt hours
KV	Kilovolts
KWh	Kilowatt hours
Mcf	Thousand cubic feet
MMBtu	Million British thermal units
MW	Megawatts
MWh	Megawatt hours

COMPANY OVERVIEW

Xcel Energy Inc. is a holding company with subsidiaries engaged primarily in the utility business. In 2014, Xcel Energy Inc.’s continuing operations included the activity of four wholly owned utility subsidiaries that serve electric and natural gas customers in eight states. These utility subsidiaries are NSP-Minnesota, NSP-Wisconsin, PSCo and SPS, and serve customers in portions of Colorado, Michigan, Minnesota, New Mexico, North Dakota, South Dakota, Texas and Wisconsin. Along with WYCO, a joint venture formed with CIG to develop and lease natural gas pipelines, storage, and compression facilities, and WGI, an interstate natural gas pipeline company, these companies comprise the regulated utility operations.

Xcel Energy Inc. was incorporated under the laws of Minnesota in 1909. Xcel Energy’s executive offices are located at 414 Nicollet Mall, Minneapolis, Minn. 55401. Its website address is www.xcelenergy.com. Xcel Energy makes available, free of charge through its website, its annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable after the reports are electronically filed with or furnished to the SEC. The public may read and copy any materials that Xcel Energy files with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC also maintains an internet site that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC at http://www.sec.gov.

Xcel Energy’s corporate strategy focuses on four core objectives: improving utility performance; driving operational excellence; providing options and solutions to customers; and investing for the future. These core objectives are designed to provide an attractive total return to our investors, including long-term annual ongoing EPS growth of four to six percent and annual dividend increases of five to seven percent.

NSP-Minnesota

NSP-Minnesota is a utility primarily engaged in the generation, purchase, transmission, distribution and sale of electricity in Minnesota, North Dakota and South Dakota. The wholesale customers served by NSP-Minnesota comprised approximately seven percent of its total KWh sold in 2014. NSP-Minnesota also purchases, transports, distributes and sells natural gas to retail customers and transports customer-owned natural gas in Minnesota and North Dakota. NSP-Minnesota provides electric utility service to approximately 1.4 million customers and natural gas utility service to approximately 0.5 million customers. Approximately 88 percent of NSP-Minnesota’s retail electric operating revenues were derived from operations in Minnesota during 2014. Although NSP-Minnesota’s large C&I electric retail customers are comprised of many diversified industries, a significant portion of NSP-Minnesota’s large C&I electric sales include the following industries: petroleum, coal and food products. For small C&I customers, significant electric retail sales include the following industries: real estate and educational services. Generally, NSP-Minnesota’s earnings contribute approximately 35 percent to 45 percent of Xcel Energy’s consolidated net income.

The electric production and transmission costs of the entire NSP System are shared by NSP-Minnesota and NSP-Wisconsin. A FERC-approved Interchange Agreement between the two companies provides for the sharing of all generation and transmission costs of the NSP System.

NSP-Minnesota owns the following direct subsidiaries: United Power and Land Company, which holds real estate; and NSP Nuclear Corporation, which owns NMC, an inactive company.

NSP-Wisconsin

NSP-Wisconsin is a utility primarily engaged in the generation, transmission, distribution and sale of electricity in portions of northwestern Wisconsin and in the western portion of the Upper Peninsula of Michigan. NSP-Wisconsin purchases, transports, distributes and sells natural gas to retail customers and transports customer-owned natural gas in this service territory. NSP-Wisconsin provides electric utility service to approximately 255,000 customers and natural gas utility service to approximately 111,000 customers. Approximately 98 percent of NSP-Wisconsin’s retail electric operating revenues were derived from operations in Wisconsin during 2014. Although NSP-Wisconsin’s large C&I electric retail customers are comprised of many diversified industries, a significant portion of NSP-Wisconsin’s large C&I electric sales include the following industries: food products, paper, allied products and sand mining for oil and gas extraction. For small C&I customers, significant electric retail sales include the following industries: grocery and dining establishments, educational services and health services. Generally, NSP-Wisconsin’s earnings contribute approximately five percent to 10 percent of Xcel Energy’s consolidated net income.

The management of the electric production and transmission system of NSP-Wisconsin is integrated with NSP-Minnesota.

NSP-Wisconsin owns the following direct subsidiaries: Chippewa and Flambeau Improvement Co., which operates hydro reservoirs; Clearwater Investments Inc., which owns interests in affordable housing; and NSP Lands, Inc., which holds real estate.

PSCo

PSCo is a utility engaged primarily in the generation, purchase, transmission, distribution and sale of electricity in Colorado. The wholesale customers served by PSCo comprised approximately 11 percent of its total KWh sold in 2014. PSCo also purchases, transports, distributes and sells natural gas to retail customers and transports customer-owned natural gas. PSCo provides electric utility service to approximately 1.4 million customers and natural gas utility service to approximately 1.3 million customers. All of PSCo’s retail electric operating revenues were derived from operations in Colorado during 2014. Although PSCo’s large C&I electric retail customers are comprised of many diversified industries, a significant portion of PSCo’s large C&I electric sales include the following industries: fabricated metal products, communications and oil and gas extraction. For small C&I customers, significant electric retail sales include the following industries: real estate and dining establishments. Generally, PSCo’s earnings contribute approximately 45 percent to 55 percent of Xcel Energy’s consolidated net income.

PSCo owns the following direct subsidiaries: 1480 Welton, Inc. and United Water Company, both of which own certain real estate interests; and Green and Clear Lakes Company, which owns water rights and certain real estate interests. PSCo also owns PSRI, which held certain former employees’ life insurance policies. PSCo also holds a controlling interest in several other relatively small ditch and water companies.

SPS

SPS is a utility engaged primarily in the generation, purchase, transmission, distribution and sale of electricity in portions of Texas and New Mexico. The wholesale customers served by SPS comprised approximately 31 percent of its total KWh sold in 2014. SPS provides electric utility service to approximately 386,000 retail customers in Texas and New Mexico. Approximately 72 percent of SPS’ retail electric operating revenues were derived from operations in Texas during 2014. Although SPS’ large C&I electric retail customers are comprised of many diversified industries, a significant portion of SPS’ large C&I electric sales include the following industries: oil and gas extraction, as well as petroleum and coal products. For small C&I customers, significant electric retail sales include the following industries: oil and gas extraction and crop related agricultural industries. Generally, SPS’ earnings contribute approximately five percent to 15 percent of Xcel Energy’s consolidated net income.

Other Subsidiaries

WGI is a small interstate natural gas pipeline company engaged in transporting natural gas from the PSCo system near Chalk Bluffs, Colo., to Cheyenne, Wyo.

WYCO was formed as a joint venture with CIG to develop and lease natural gas pipeline, storage, and compression facilities. Xcel Energy has a 50 percent ownership interest in WYCO. The gas pipeline and storage facilities are leased under a FERC-approved agreement to CIG.

Xcel Energy Services Inc. is the service company for Xcel Energy Inc.

XETD and XEST are transmission-only subsidiaries that will participate in MISO and SPP competitive bidding processes for transmission projects. XEWT is a transmission-only subsidiary that will competitively bid on transmission projects in the western United States.

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

Xcel Energy conducts its utility business in the following reportable segments: regulated electric utility, regulated natural gas utility and all other. See Note 17 to the consolidated financial statements for further discussion relating to comparative segment revenues, income from operations and related financial information.

ELECTRIC UTILITY OPERATIONS

NSP-Minnesota

Public Utility Regulation

Summary of Regulatory Agencies and Areas of Jurisdiction — Retail rates, services and other aspects of NSP-Minnesota’s operations are regulated by the MPUC, the NDPSC and the SDPUC within their respective states. The MPUC also has regulatory authority over security issuances, property transfers, mergers, dispositions of assets and transactions between NSP-Minnesota and its affiliates. In addition, the MPUC reviews and approves NSP-Minnesota’s ERPs for meeting customers’ future energy needs. The MPUC also certifies the need and siting for generating plants greater than 50 MW and transmission lines greater than 100 KV that will be located within the state. No large power plant or transmission line may be constructed in Minnesota except on a site or route designated by the MPUC. The NDPSC and SDPUC have regulatory authority over generation and transmission facilities, along with the siting and routing of new generation and transmission facilities in North Dakota and South Dakota, respectively.

NSP-Minnesota is subject to the jurisdiction of the FERC with respect to its wholesale electric operations, hydroelectric licensing, accounting practices, wholesale sales for resale, transmission of electricity in interstate commerce, compliance with NERC electric reliability standards, asset transfers and mergers, and natural gas transactions in interstate commerce. NSP-Minnesota has been granted continued authorization from the FERC to make wholesale electric sales at market-based prices. NSP-Minnesota is a transmission owning member of the MISO RTO.

Fuel, Purchased Energy and Conservation Cost-Recovery Mechanisms — NSP-Minnesota has several retail adjustment clauses that recover fuel, purchased energy and other resource costs:

• 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.

NSP-Minnesota’s retail electric rates in Minnesota, North Dakota and South Dakota include a FCA for monthly billing adjustments for changes in prudently incurred costs of fuel, fuel related items and purchased energy. NSP-Minnesota is permitted to recover these costs through FCA mechanisms approved by the regulators in each jurisdiction. In general, capacity costs are not recovered through the FCA. In addition, costs associated with MISO are generally recovered through either the FCA or base rates.

Minnesota state law requires NSP-Minnesota to invest two percent of its state electric revenues in CIP. NSP-Minnesota was in compliance with this standard in 2014 and expects to be in compliance in 2015. These costs are recovered through an annual cost-recovery mechanism for electric conservation and energy management program expenditures.

CIP Triennial Plan — In 2012, the DOC approved NSP-Minnesota’s 2013 through 2015 CIP Triennial Plan, which increases the savings goals and budgets over the previous plan. The plan sets an electric goal of annually saving the equivalent of 1.5 percent of sales (calculated on a historical three-year average, excluding opt-out customers) and an annual natural gas goal of saving 1.0 percent of sales.

Capacity and Demand

Uninterrupted system peak demand for the NSP System’s electric utility for each of the last three years and the forecast for 2015, assuming normal weather, is listed below.

	System Peak Demand (in MW)
	2012	2013	2014	2015 Forecast
NSP System	9,475	9,524	8,848	9,301

The peak demand for the NSP System typically occurs in the summer. The 2014 uninterrupted system peak demand for the NSP System occurred on July 21, 2014. The 2014 system peak demand was lower due to cooler summer weather. The 2015 forecast assumes normal peak day weather.

Energy Sources and Related Transmission Initiatives

NSP-Minnesota expects to use existing power plants, power purchases, CIP options, new generation facilities and expansion of existing power plants to meet its system capacity requirements.

Purchased Power — NSP-Minnesota has contracts to purchase power from other utilities and independent power producers. Long-term purchased power contracts typically require a periodic payment to secure the capacity and a charge for the associated energy actually purchased. NSP-Minnesota also makes short-term purchases to meet system load and energy requirements, to replace generation from company-owned units under maintenance or during outages, to meet operating reserve obligations, or to obtain energy at a lower cost.

Purchased Transmission Services — In addition to using their integrated transmission system, NSP-Minnesota and NSP-Wisconsin have contracts with MISO and regional transmission service providers to deliver power and energy to the NSP System.

NSP-Minnesota’s Filing in Support of e21 Initiative — In December 2014, a collaborative report was issued in Minnesota by a diverse stakeholder group known as the e21 Initiative. The e21 report released a set of recommendations that are intended to act as a blueprint for a new customer-centric, performance-based regulatory approach.

Following the e21 report, NSP-Minnesota filed with the MPUC a plan for supporting the e21 Initiative, which includes the following key objectives:

• 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.

NSP-Minnesota plans to work with the MPUC and various stakeholders during 2015 to continue the dialogue and implementation of the e21 Initiative and proposals presented by NSP-Minnesota.

NSP System Resource Plans — In January 2015, NSP-Minnesota filed its 2016-2030 Resource Plan with the MPUC, proposing to achieve a 40 percent reduction in carbon emissions by 2030 from 2005 levels through the significant addition of renewables, continued commitment to specific CIP annual achievements, and the continued operation of its existing cost-effective thermal generation. The plan positions NSP-Minnesota to be responsive to future environmental requirements and market trends, builds on the significant investments already made in the NSP System, and acknowledges the divergence in state energy policies within the NSP System. Key points of the resource plan include:

• 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.

In February 2015, the MPUC approved the Competitive Acquisition Plan (CAP), in which NSP-Minnesota is required to add capacity to its system to meet a resource need as follows:

• 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.

NSP-Minnesota also proposed use of a collaborative stakeholder process to guide its five-year action plan, and to facilitate the necessary update of its resource analysis to incorporate the CAP outcomes and significantly higher than expected response to its Community Solar Gardens program.

CapX2020 — The estimated cost of the five major CapX2020 transmission projects listed below is $2.0 billion. NSP-Minnesota and NSP-Wisconsin are responsible for approximately $1.1 billion of the total investment. As of Dec. 31, 2014, Xcel Energy has invested $882.3 million of its $1.1 billion share of the five CapX2020 transmission projects.

Hampton, Minn. to Rochester, Minn. to La Crosse, Wis. 345 KV transmission line

Construction on the project started in Minnesota in January 2013 and the project is expected to go into service in 2016, although segments are being placed in service as they are completed.

Monticello, Minn. to Fargo, N.D. 345 KV transmission line

In December 2011, the Monticello, Minn. to St. Cloud, Minn. portion of the Monticello, Minn. to Fargo, N.D. project was placed in service. In April 2014, the St. Cloud, Minn. to Alexandria, Minn. portion of the project was placed in service. In January 2013, construction started on the project in North Dakota. The final phase of the project, Alexandria, Minn. to Fargo, N.D. is expected to go into service in 2015.

Brookings County, S.D. to Hampton, Minn. 345 KV transmission line

In December 2011, MISO granted the final approval of the project as a MVP. Construction started on the project in Minnesota in May 2012. The project is expected to go fully into service in 2015, although segments are being placed in service as they are completed.

Bemidji, Minn. to Grand Rapids, Minn. 230 KV transmission line

The Bemidji, Minn. to Grand Rapids, Minn. line was placed in service in September 2012.

Big Stone South to Brookings County, S.D. 345 KV transmission line

In December 2011, MISO granted final approval of the project as a MVP. In March 2014, the SDPUC approved a permit for construction of the project’s southern portion. Construction is anticipated to begin in late 2015, with completion in 2017.

Minnesota Solar — Minnesota legislation requires 1.5 percent of a public utility’s total electric retail sales to retail customers be generated using solar energy by 2020. Of the 1.5 percent, 10 percent must come from systems sized less than 20 kilowatts. There are two customer-facing solar programs authorized by the legislature: a community solar garden program that provides bill credits to participating subscribers, and a solar production incentive program for systems equal to or less than 20 kilowatts with authorized payments of $5.0 million per year over five years. NSP-Minnesota launched its Solar*Rewards Community program in December 2014.

The legislation also provides for an alternative tariff based on a distributed solar value or Value of Solar (VOS) methodology. In March 2014, a VOS methodology was approved by the MPUC. However, in September 2014 the MPUC determined that the VOS is not in the public interest for use with community solar gardens. The MPUC instead approved a retail rate based credit ranging from 9.5 to 15 cents per kilowatt hour. The actual bill credit amount is dependent on customer class as well as customers’ willingness to transfer the RECs to NSP-Minnesota.

Annual Automatic Adjustment (AAA) of Charges — In June 2013, the DOC proposed that the MPUC adopt a fuel clause incentive that would normalize FCA recovery using monthly patterns derived from averages of the prior three-year period, setting and fixing this level during a rate case with no adjustment between rate cases. NSP-Minnesota and other utilities opposed this proposal. The DOC proposal is pending MPUC action.

Additionally, the DOC has indicated it will review prudence of replacement power costs associated with the Sherco Unit 3 outage event within the 2013 AAA docket. The 2013 and 2012 AAA dockets remain pending.

Minneapolis, Minn. Franchise Agreement — In October 2014, the City of Minneapolis and Xcel Energy signed a 10 year franchise agreement. The City of Minneapolis has the option to end the agreement any time after the first five years and the option to extend it to a maximum of 20 years if both parties agree. A separate clean energy partnership agreement with the City of Minneapolis was also signed, which establishes a board comprised of city and utility officials tasked with creating a work plan to promote energy efficiency, the use of renewable energy, and the reduction of carbon emissions.

Nuclear Power Operations and Waste Disposal

NSP-Minnesota owns two nuclear generating plants: the Monticello plant and the PI plant. Nuclear power plant operations produce gaseous, liquid and solid radioactive wastes which are controlled by federal regulation. High-level radioactive wastes primarily include used nuclear fuel. LLW consists primarily of demineralizer resins, paper, protective clothing, rags, tools and equipment that have become contaminated through use in a plant.

NRC Regulation — The NRC regulates the nuclear operations of NSP-Minnesota. Decisions by the NRC can significantly impact the operations of the nuclear generating plants.

The NRC imposed new requirements after events at the nuclear generating plant in Fukushima, Japan. In 2012, the NRC issued orders which included requirements for mitigation strategies for beyond-design-basis external events, requirements with regard to reliable spent fuel instrumentation and requirements with regard to reliable hardened containment vents, which are applicable to boiling water reactor containments at the Monticello plant. The NRC also requested additional information including requirements to perform walkdowns of seismic and flood protection, to evaluate seismic and flood hazards and to assess the emergency preparedness staffing and communications capabilities at each plant. Based on current refueling outage plans, the dates of the required compliance are expected to begin in 2015 with all units expected to be fully compliant by December 2016.

In 2013, the NRC issued a revised order with regard to reliable hardened containment vents. Phase 1 addresses severe accident conditions under which the existing hardened vent which comes off of the wet portion of the containment needs to operate. Phase 2 addresses a second hardened vent off of the dry portion of the containment, or a containment venting strategy that makes it unlikely that a licensee would need to vent from the dry portion of the containment. Compliance with the revised order will be completed during refueling outages in 2017-2019.

NSP-Minnesota expects that complying with these external event requirements will cost approximately $90 to $100 million at the Monticello and PI plants. The majority of these costs are expected to be capital in nature. NSP-Minnesota believes the costs associated with compliance would be recoverable from customers through regulatory mechanisms and does not expect a material impact on its results of operations, financial position, or cash flows.

The NRC continues to review its requirements for mitigating the risks of external events on nuclear plants. In 2014, the NRC issued a draft of proposed regulatory guidance for risk mitigation of tornado missiles (projectiles impacting the plant). NSP-Minnesota expects the costs associated with compliance with new NRC regulatory guidance for missile protection to be capital in nature and recoverable from customers. NSP-Minnesota is still evaluating the proposed new requirements and has not yet estimated their financial impact.

Nuclear Regulatory Performance — Since 2000, the NRC has had in place a Reactor Oversight Process (ROP) that classifies U.S. nuclear reactors into various categories (referred to as Columns, from 1 to 5) based on the significance of issues identified in performance indicators or inspection findings. Such issues are evaluated as either green, white, yellow, or red based on their safety significance, with green representing the least safety concern and red representing the most concern. At Dec. 31, 2014, PI Units 1 and 2 were in Column 1 (Licensee Response) with all green performance indicators and no greater than green findings or violations. Monticello was in Column 3 (Degraded Cornerstone) with all green performance indicators and a yellow finding related to flood control. The NRC has completed their inspection that will allow the yellow finding to be closed out. The NRC has notified Monticello that it has a potentially greater than green finding related to plant security which was immediately remedied. Xcel Energy expects to be formally notified of the closeout of the yellow finding, a final determination of the significance of the security finding, and Monticello’s overall column status under the NRC’s ROP in the first half of 2015. Until the NRC makes its determination, we are unable to estimate the cost or impact of any responsive actions required.

LLW Disposal — LLW from NSP-Minnesota’s Monticello and PI nuclear plants is currently disposed at the Clive facility located in Utah and Waste Control Specialists facility located in Texas. If off-site LLW disposal facilities become unavailable, NSP-Minnesota has storage capacity available on-site at PI and Monticello that would allow both plants to continue to operate until the end of their current licensed lives.

High-Level Radioactive Waste Disposal — The federal government has the responsibility to permanently dispose of domestic spent nuclear fuel and other high-level radioactive wastes. The Nuclear Waste Policy Act requires the DOE to implement a program for nuclear high-level waste management. This includes the siting, licensing, construction and operation of a repository for spent nuclear fuel from civilian nuclear power reactors and other high-level radioactive wastes at a permanent federal storage or disposal facility.

Nuclear Geologic Repository - Yucca Mountain Project

In 2002, the U.S. Congress designated Yucca Mountain, Nevada as the first deep geologic repository. In 2008, the DOE submitted an application to construct a deep geologic repository at this site to the NRC. In 2010, the DOE announced its intention to stop the Yucca Mountain project and requested the NRC approve the withdrawal of the application. In 2010, the ASLB issued a ruling that the DOE could not withdraw the Yucca Mountain application.

The DOE’s decision and the resulting stoppage of the NRC’s review has prompted multiple legal challenges, including the DOE’s authority to stop the project and withdraw the application, the DOE’s authority to continue to collect the nuclear waste fund fee and the NRC’s authority to stop their review of the DOE’s application.

In August 2013, the D.C. Court of Appeals ordered the NRC to complete their review of the DOE’s application to construct the Yucca Mountain repository. In November 2013, the NRC complied by issuing an order to the NRC Staff to complete and publish a safety evaluation report on the proposed Yucca Mountain nuclear spent fuel and waste repository. The NRC also requested that the DOE prepare a supplemental environmental impact statement (EIS) so the NRC Staff can complete its review.

In November 2013, the U.S. Court of Appeals ordered the DOE to suspend the collection of the nuclear waste fund fee from nuclear utilities and to recommend to Congress that the nuclear waste fund fee be set to zero. In January 2014, the DOE sent its court mandated proposal to adjust the current fee to zero, which Congress approved in May 2014.

At the time that the DOE decided to stop the Yucca Mountain project and withdraw the application, the Secretary of Energy convened a Blue Ribbon Commission to recommend alternatives to Yucca Mountain for disposal of used nuclear fuel. In January 2012, the Blue Ribbon Commission report was issued. In January 2013, the DOE provided its report to Congress relative to their plans to implement the Blue Ribbon Commission’s recommendations including the required legislative changes and authorizations. The report also announced the Obama Administration’s intent to make a pilot consolidated interim storage facility available in 2021, a larger consolidated interim storage facility available in 2025 and a deep geologic repository available in 2048. See Note 13 and Note 14 to the consolidated financial statements for further discussion.

Nuclear Spent Fuel Storage

NSP-Minnesota has interim on-site storage for spent nuclear fuel at its Monticello and PI nuclear generating plants. As of Dec. 31, 2014, there were 38 casks loaded and stored at the PI plant and 15 canisters loaded and stored at the Monticello plant. An additional 26 casks for PI and 15 canisters for Monticello have been authorized by the State of Minnesota. This currently authorized storage capacity is sufficient to allow NSP-Minnesota to operate until the end of the operating licenses in 2030 for Monticello, 2033 for PI Unit 1, and 2034 for PI Unit 2. Authorizations for additional spent fuel storage capacity may be required at each site to support either continued operation or decommissioning if the federal government does not begin operation of a consolidated interim storage installation by the time frames established in the DOE’s Strategy for the Management and Disposal of Used Nuclear Fuel and High-Level Radioactive Waste issued in January 2013.

PFS — The eight partners of PFS, including NSP-Minnesota, have withdrawn their license termination request from the NRC and have stopped activities to dissolve the LLC. This action was taken when the NRC changed its fee rules to no longer require certain licensees like PFS to pay annual fees until their facility becomes operational. PFS is currently reviewing its plans for the future.

NRC Waste Confidence Decision (WCD) — In June 2012, the D.C. Circuit issued a ruling to vacate and remand the NRC’s WCD. The WCD assesses how long temporary on-site storage can remain safe and when facilities for the disposal of nuclear waste will become available. The D.C. Circuit remanded the WCD to the NRC and directed it to prepare an EIS if there are significant impacts or an environmental assessment to support a finding of no significant impact. In September 2014, the NRC published a Generic Environmental Impact Statement (GEIS) and revised WCD rule, now called the Continued Storage Rule (CSR) on the temporary on-site storage of spent nuclear fuel. Issuance of the CSR now allows the NRC to proceed with final license decisions regarding the new and renewal of plant and Independent Spent Fuel Storage Installation (ISFSI) operating licenses without the need to litigate contentions related to the continued storage of spent nuclear fuel on-site. This may facilitate potential future licensing needs for NSP-Minnesota.

See Notes 13 and 14 to the consolidated financial statements for further discussion regarding nuclear related items.

Nuclear Plant Power Uprates and Life Extension

PI ISFSI License Renewal — The current license to operate an ISFSI at PI expired in October 2013. An application to renew the ISFSI license for an additional 40 years until 2053 was submitted by NSP-Minnesota to the NRC in October 2011. As PI met the NRC’s criteria for timely renewal, it will be allowed to continue to operate under the current license until the NRC has rendered a decision on the license renewal application. The NRC’s ASLB will establish a schedule for the hearing which should be completed by the second half of 2015.

Monticello Nuclear Uprate Project — NSP-Minnesota has received all federal and state approvals that are necessary and has completed all of the plant modifications to achieve the 71 MW capacity Monticello Nuclear Uprate Project and is in the process of completing the power ascension testing required by the NRC. Operation at the full increased power level is expected in the first half of 2015. As of Dec. 31, 2014, Monticello was operating at 656 MW, which includes approximately 56 MW of the extended uprate capacity. See Note 12 to the consolidated financial statements for further discussion.

Energy Source Statistics

	Year Ended Dec. 31
	2014			2013			2012
NSP System	Millions of KWh	Percent of Generation		Millions of KWh	Percent of Generation		Millions of KWh	Percent of Generation
Coal	18,079	39	%	15,844	36	%	16,023	35	%
Nuclear	13,434	29		12,161	28		13,231	29
Natural Gas	3,402	7		5,550	13		6,200	13
Wind ^(a)	6,243	14		5,481	13		5,443	12
Hydroelectric	3,560	8		3,223	7		3,193	7
Other ^(b)	1,417	3		1,323	3		1,617	4
Total	46,135	100	%	43,582	100	%	45,707	100	%

Owned generation	33,641	73	%	29,249	67	%	31,365	69	%
Purchased generation	12,494	27		14,333	33		14,342	31
Total	46,135	100	%	43,582	100	%	45,707	100	%

(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.

Fuel Supply and Costs

The following table shows the delivered cost per MMBtu of each significant category of fuel consumed for owned electric generation, the percentage of total fuel requirements represented by each category of fuel and the total weighted average cost of all fuels.

	Coal ^(a)				Nuclear				Natural Gas				Weighted Average Owned Fuel Cost
NSP System Generating Plants	Cost		Percent		Cost		Percent		Cost		Percent		Weighted Average Owned Fuel Cost
2014	$	2.23	52	%	$	0.89	42	%	$	6.27	6	%	$	1.94
2013	2.20		49		0.95		40		5.08		11		2.03
2012	2.13		47		0.90		42		4.21		11		1.88

(a) Includes refuse-derived fuel and wood.

The higher cost of natural gas was primarily due to higher market prices from increased demand because of cold weather in early 2014.

See Items 1A and 7 for further discussion of fuel supply and costs.

Fuel Sources

Coal — The NSP System normally maintains approximately 41 days of coal inventory. Coal supply inventories at Dec. 31, 2014 and 2013 were approximately 27 and 34 days usage, respectively. At Dec. 31, 2014, coal inventories were below optimal levels due to railcar congestion. NSP-Minnesota’s generation stations use low-sulfur western coal purchased primarily under contracts with suppliers operating in Wyoming and Montana. During 2014 and 2013, coal requirements for the NSP System’s major coal-fired generating plants were approximately 9.3 million tons and 7.3 million tons, respectively. Coal requirements for 2014 were higher as Sherco Unit 3 was placed back in service. The estimated coal requirements for 2015 are approximately 8.7 million tons, which reflects the retirement of Black Dog Units 3 and 4.

NSP-Minnesota and NSP-Wisconsin have contracted for coal supplies to provide 88 percent of their estimated coal requirements in 2015, and a declining percentage of the requirements in subsequent years. The NSP System’s general coal purchasing objective is to contract for approximately 100 percent of requirements for the first year, 67 percent of requirements in year two, and 33 percent of requirements in year three. Remaining requirements will be filled through the procurement process or over-the-counter transactions.

NSP-Minnesota and NSP-Wisconsin have a number of coal transportation contracts that provide for delivery of 100 percent of their coal requirements in 2015 and 2016. Coal delivery may be subject to interruptions or reductions due to operation of the mines, transportation problems, weather and availability of equipment.

Nuclear — NSP-Minnesota secures contracts for uranium concentrates, uranium conversion, uranium enrichment and fuel fabrication to operate its’ nuclear plants. The contract strategy involves a portfolio of spot purchases and medium and long-term contracts for uranium concentrates, conversion services and enrichment services with multiple producers and with a focus on diversification to minimize potential impacts caused by supply interruptions due to geographical and world political issues.

• 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.

Fabrication services for Monticello and PI are 100 percent committed through 2030 and 2019, respectively.

NSP-Minnesota expects sufficient uranium concentrates, conversion services and enrichment services to be available for the total fuel requirements of its nuclear generating plants. Some exposure to spot market price volatility will remain due to index-based pricing structures contained in certain supply contracts.

Natural gas — The NSP System uses both firm and interruptible natural gas supply and standby oil in combustion turbines and certain boilers. Natural gas supplies, transportation and storage services for power plants are procured under contracts to provide an adequate supply of fuel. However, as natural gas primarily serves intermediate and peak demand, remaining forecasted requirements are able to be procured through a liquid spot market. Generally, natural gas supply contracts have variable pricing that is tied to various natural gas indices. Most transportation contract pricing is based on FERC approved transportation tariff rates. Certain natural gas supply and transportation agreements include obligations for the purchase and/or delivery of specified volumes of natural gas or to make payments in lieu of delivery. At Dec. 31, 2014 and 2013, the NSP System did not have any commitments related to gas supply contracts; however commitments related to gas transportation and storage contracts were approximately $349 million and $389 million, respectively. Commitments related to gas transportation and storage contracts expire in various years from 2015 to 2028.

The NSP System also has limited on-site fuel oil storage facilities and primarily relies on the spot market for incremental supplies.

Renewable Energy Sources

The NSP System’s renewable energy portfolio includes wind, hydroelectric, biomass and solar power from both owned generating facilities and PPAs. As of Dec. 31, 2014, the NSP System was in compliance with mandated RPS, which require generation from renewable resources of 18 percent and 12.9 percent of NSP-Minnesota and NSP-Wisconsin electric retail sales, respectively.

• 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.

• 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.

The NSP System also offers customer-focused renewable energy initiatives. Windsource® allows customers in Minnesota, Wisconsin, and Michigan to purchase a portion or all of their electricity from renewable sources. In 2014, the number of customers utilizing Windsource increased to approximately 43,000 from 37,000 in 2013. Windsource MWh sales increased from approximately 181,000 MWh in 2013 to 186,000 MWh in 2014.

Additionally, to encourage the growth of solar energy on the system, customers are offered incentives to install solar panels on their homes and businesses under the Solar*Rewards® program. Over 915 PV systems with approximately 11.1 MW of aggregate capacity and over 679 PV systems with approximately 7.3 MW of aggregate capacity have been installed in Minnesota under this program as of Dec. 31, 2014 and 2013, respectively.

As part of NSP-Minnesota’s North Dakota 2013 electric rate case settlement, NSP-Minnesota is required to file a system restack proposal in 2015 to ensure that additional costs for compliance with Minnesota renewable initiatives are not paid for by North Dakota customers.

Wind — The NSP System acquires the majority of its wind energy from PPAs with wind farm owners, primarily located in Southwestern Minnesota. Currently, the NSP System has more than 100 of these agreements in place, with facilities ranging in size from under one MW to more than 200 MW. The NSP System owns and operates two wind farms which have the capacity to generate 302 MWs. Collectively, the NSP System had approximately 1,860 MWs of wind energy on its system at the end of 2014 and 2013. In October 2013, the MPUC approved four new projects, which are anticipated to provide up to 750 MW of capacity, including two projects totaling 350 MW that will be owned by NSP-Minnesota. One additional 20 MW project was approved in 2014. All five projects are targeted to be operational in late 2015. With the new projects, the NSP System is anticipated to have approximately 2,630 MWs of wind power. 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 $41 for 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.

Hydroelectric — The NSP System acquires its hydroelectric energy from both owned generation and PPAs. The NSP System owns 20 hydroelectric plants throughout Wisconsin and Minnesota which provide 268 MW of capacity. For 2014, PPAs provided approximately 38 MW of hydroelectric capacity. Additionally, the NSP System purchases approximately 850 MW of generation from Manitoba Hydro which is sourced primarily from its fleet of hydroelectric facilities.

Wholesale Commodity Marketing Operations

NSP-Minnesota conducts various wholesale marketing operations, including the purchase and sale of electric capacity, energy and energy-related products. See Item 7 for further discussion.

NSP-Wisconsin

Public Utility Regulation

Summary of Regulatory Agencies and Areas of Jurisdiction — Retail rates, services and other aspects of NSP-Wisconsin’s operations are regulated by the PSCW and the MPSC, within their respective states. In addition, each of the state commissions certifies the need for new generating plants and electric transmission lines before the facilities may be sited and built. NSP-Wisconsin is subject to the jurisdiction of the FERC with respect to its wholesale electric operations, hydroelectric generation licensing, accounting practices, wholesale sales for resale, the transmission of electricity in interstate commerce, compliance with the NERC electric reliability standards, asset transactions and mergers, and natural gas transactions in interstate commerce. NSP-Wisconsin and NSP-Minnesota have been granted continued joint authorization from the FERC to make wholesale electric sales at market-based prices. NSP-Wisconsin is a transmission owning member of the MISO RTO.

The PSCW has a biennial base rate filing requirement. By June of each odd numbered year, NSP-Wisconsin must submit a rate filing for the test year beginning the following January. In recent years, NSP-Wisconsin has been submitting rate filings each year.

Fuel and Purchased Energy Cost Recovery Mechanisms — NSP-Wisconsin does not have an automatic electric fuel adjustment clause for Wisconsin retail customers. Instead, under Wisconsin rules, utilities submit a forward-looking annual fuel cost plan to the PSCW for approval. Once the PSCW approves the fuel cost plan, utilities defer the amount of any fuel cost under-collection or over-collection in excess of a two percent annual tolerance band, for future rate recovery or refund. Approval of a fuel cost plan and any rate adjustment for refund or recovery of deferred costs is determined by the PSCW after an opportunity for a hearing. Rate recovery of deferred fuel cost is subject to an earnings test based on the utility’s most recently authorized ROE. Fuel cost under-collections that exceed the two percent annual tolerance band for a calendar year may not be recovered if the utility earnings for that year exceed the authorized ROE.

NSP-Wisconsin’s retail electric rate schedules for Michigan customers include power supply cost recovery factors, which are based on 12-month projections. After each 12-month period, a reconciliation is submitted whereby over-collections are refunded and any under-collections are collected from the customers over the subsequent 12-month period.

Wisconsin Energy Efficiency Program — In Wisconsin, the primary energy efficiency program is funded by the state’s utilities, but operated by independent contractors subject to oversight by the PSCW and the utilities. NSP-Wisconsin recovers these costs in rates charged to Wisconsin retail customers.

Capacity and Demand

NSP-Wisconsin operates an integrated system with NSP-Minnesota. See NSP-Minnesota Capacity and Demand.

Energy Sources and Related Transmission Initiatives

NSP-Wisconsin operates an integrated system with NSP-Minnesota. See NSP-Minnesota Energy Sources and Related Transmission Initiatives.

NSP-Wisconsin CapX2020 CPCN — The PSCW issued a CPCN for the Wisconsin portion of the Hampton, Minn. to La Crosse, Wis. project in May 2012. The Wisconsin route is approximately 50 miles of new transmission line with an estimated cost of $211 million. The line is expected to go into service in the fall of 2015.

NSP-Wisconsin / American Transmission Company, LLC (ATC) - La Crosse, Wis. to Madison, Wis. Transmission Line — In October 2013, NSP-Wisconsin and ATC jointly filed an application with the PSCW for a CPCN for a new 345 KV transmission line that would extend from La Crosse, Wis. to Madison, Wis. The proposed line, known as the Badger Coulee line, would run between 154 and 187 miles based on the permitted route, which includes an estimated project cost, including AFUDC, of between $540 and $580 million. NSP-Wisconsin’s half of the project is shared with two partners, Dairyland Power Cooperative and WPPI Energy. NSP-Wisconsin’s portion of the investment is estimated to be between $190 and $207 million. In 2011, MISO determined the line to be a MVP project, and as such, eligible for cost sharing under MISO’s MVP tariff. The PSCW held hearings on the application in January 2015, and a decision is expected by April 2015. If approved, NSP-Wisconsin and ATC anticipate beginning construction on the line in late 2016, with completion by late 2018.

Fuel Supply and Costs

NSP-Wisconsin operates an integrated system with NSP-Minnesota. See NSP-Minnesota Fuel Supply and Costs.

PSCo

Public Utility Regulation

Summary of Regulatory Agencies and Areas of Jurisdiction — PSCo is regulated by the CPUC with respect to its facilities, rates, accounts, services and issuance of securities. PSCo is regulated by the FERC with respect to its wholesale electric operations, accounting practices, hydroelectric licensing, wholesale sales for resale, the transmission of electricity in interstate commerce, compliance with the NERC electric reliability standards, asset transactions and mergers and natural gas transactions in interstate commerce.

Fuel, Purchased Energy and Conservation Cost-Recovery Mechanisms — PSCo has several retail adjustment clauses that recover fuel, purchased energy and other resource costs:

• 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.

PSCo recovers fuel and purchased energy costs from its wholesale electric customers through a fuel cost adjustment clause approved by the FERC. PSCo’s wholesale customers have agreed to pay the full cost of certain renewable energy purchase and generation costs through a fuel clause and in exchange receive RECs associated with those resources. The wholesale customers pay their jurisdictional allocation of production costs through a fully forecasted formula rate with true-up.

QSP Requirements — The CPUC established an electric QSP that provides for bill credits to customers if PSCo does not achieve certain performance targets relating to electric reliability and customer service. PSCo monitors and records, as necessary, an estimated customer refund obligation under the QSP. The CPUC extended the terms of the current QSP through 2015.

Capacity and Demand

Uninterrupted system peak demand for PSCo’s electric utility for each of the last three years and the forecast for 2015, assuming normal weather, is listed below.

	System Peak Demand (in MW)
	2012	2013	2014	2015 Forecast
PSCo	6,689	6,678	6,152	6,475

The peak demand for PSCo’s system typically occurs in the summer. The 2014 uninterrupted system peak demand for PSCo occurred on July 7, 2014. The 2014 system peak demand was lower due to reduced wholesale loads and cooler summer weather. In 2013 Comanche Unit 3 was off-line, which increased PSCo’s system load by approximately 250 MW for the backup power provided by PSCo to the joint owners. The forecast of 2015 system peak assumes normal weather conditions.

Energy Sources and Related Transmission Initiatives

PSCo expects to meet its system capacity requirements through existing electric generating stations, power purchases, new generation facilities, DSM options and phased expansion of existing generation at select power plants.

Purchased Power — PSCo has contracts to purchase power from other utilities and independent power producers. Long-term purchased power contracts typically require a periodic payment to secure the capacity and a charge for the associated energy actually purchased. PSCo also makes short-term purchases to meet system load and energy requirements, to replace generation from company-owned units under maintenance or during outages, to meet operating reserve obligations, or to obtain energy at a lower cost.

Purchased Transmission Services — In addition to using its own transmission system, PSCo has contracts with regional transmission service providers to deliver energy to PSCo’s customers.

Colorado ERP and All-Source Solicitation — In 2013, PSCo issued an All-Source RFP for 250 MW of generation by the end of 2018. PSCo also issued a separate wind RFP for PPAs only.

The CPUC provided final approval to PSCo’s plan in December 2013, which includes the following:

• 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.

In addition, PSCo continues to execute on the remaining aspects of CACJA compliance including the construction of a new natural gas fired combined cycle unit at Cherokee generating station and the addition of emissions controls at the Pawnee and Hayden stations. PSCo also expects to retire the Cherokee Unit 3 and Valmont Unit 5 coal-fired power plants by the end of 2015 and 2017, respectively.

Brush, Colo. to Castle Pines, Colo. 345 KV Transmission Line — In March 2014, PSCo filed with the CPUC for a CPCN to construct a new 345 KV transmission line originating from Pawnee Station, near Brush, Colo. and terminating at the Daniels Park substation, near Castle Pines, Colo. The estimated cost of the project is $178 million. In September 2014, PSCo entered into a partial settlement agreement with the CPUC Staff supporting the grant of a CPCN for the line. The OCC has opposed the CPCN. In November 2014, the ALJ issued a recommended decision approving the CPCN, but delaying construction until May 2020. PSCo filed exceptions to the recommended decision, requesting clarification and reconsideration to commence certain portions of the project in 2015. A CPUC decision is anticipated in the first quarter of 2015.

Thornton, Colo. Substation Project — In October 2014, PSCo filed with the CPUC for a CPCN to construct a new substation to serve growing load in and around Thornton, Colo. to be placed into service in July 2016. The estimated cost of the project is approximately $34 million. The OCC and the City of Thornton have intervened in the CPCN proceeding. In November 2014, the matter was referred to an ALJ for hearing procedures. In January 2015, PSCo and the OCC filed a settlement agreement with the CPUC requesting approval of the CPCN. The City of Thornton did not oppose the settlement. An evidentiary hearing was held in February 2015 and a CPUC decision is anticipated in the first quarter of 2015.

Boulder, Colo. Municipalization — PSCo’s franchise agreement with the City of Boulder (Boulder) expired in December 2010. In November 2011, a ballot measure was passed which authorized the formation and operation of a municipal utility and the issuance of enterprise revenue bonds, subject to certain restrictions, including the level of initial rates and debt service coverage. In May 2014, the Boulder City Council passed an ordinance to establish an electric utility.

In 2013, the CPUC ruled that it has jurisdiction under Colorado law to determine the utility that will serve customers outside Boulder’s city limits, and will determine certain system separation matters as well as what facilities need to be constructed to ensure reliable service. The CPUC has declared that it should make its determinations prior to any eminent domain actions. In January 2014, Boulder appealed this ruling to the Boulder District Court. In January 2015, the Boulder District Court affirmed the CPUC decision.

Boulder sent PSCo an offer of $128 million for certain portions of PSCo’s transmission and distribution business. PSCo has notified Boulder that its offer was deficient. Under Colorado law, a condemning entity must pay the owner fair market value for the taking of and damages to the remainder of the property.

In July 2014, Boulder filed a petition for condemnation in the Boulder District Court. PSCo filed a motion to dismiss the petition based upon the CPUC’s ruling that it must determine the appropriate system separations prior to Boulder filing its condemnation case. PSCo’s motion to dismiss was granted in February 2015. This decision does not prevent Boulder from filing another condemnation petition if it obtains CPUC approval of a separation plan.

In August 2014, PSCo filed a petition with the FERC requesting an order requiring that Boulder’s attempt to acquire PSCo’s transmission and distribution facilities by condemnation requires prior FERC approval under the Federal Power Act. In December 2014, the FERC issued an order granting PSCo’s petition.

If Boulder proceeds with another condemnation petition and were to succeed in the eminent domain proceeding, PSCo would seek to obtain full compensation for the business and its associated property taken by Boulder, as well as for all damages resulting to PSCo and its system. PSCo would also seek appropriate compensation for stranded costs with the FERC.

RES Compliance Plan — Colorado law mandates that at least 30 percent of PSCo’s energy sales are supplied by renewable energy by 2020 and includes a distributed generation standard. In July 2013, PSCo filed its 2014 RES compliance plan. In July 2014, the ALJ issued a recommended decision accepting PSCo’s compliance plan with modifications. The CPUC approved the recommended decision with modifications in December 2014. PSCo subsequently requested additional adjustments to the CPUC’s decision, which were granted through an order issued in February 2015.

Net Metering Standard — In a filing, PSCo proposed to track and quantify the system costs that are not avoided by distributed solar generation, which PSCo has defined as a “net metering incentive,” for purposes of equitably recovering costs between customers. The CPUC assigned the net metering issue to its own docket. A CPUC decision is anticipated in the third quarter of 2015.

Steam System Package Boilers and Regulatory Plan — In December 2014, PSCo filed the results of a steam survey along with both a short-term plan and a long-term plan for the steam system consisting of a request for a conditional CPCN to construct either one or two boilers for its steam utility, dependent on the next two seasons of winter peaking capacity. A decision is anticipated in the third quarter of 2015.

Energy Source Statistics

	Year Ended Dec. 31
	2014			2013			2012
PSCo	Millions of KWh	Percent of Generation		Millions of KWh	Percent of Generation		Millions of KWh	Percent of Generation
Coal	18,274	53	%	19,647	56	%	21,367	59	%
Natural Gas	8,601	25		7,565	22		7,930	22
Wind ^(a)	6,472	19		6,750	19		5,752	16
Hydroelectric	617	2		655	2		590	2
Other ^(b)	294	1		250	1		263	1
Total	34,258	100	%	34,867	100	%	35,902	100	%

Owned generation	23,023	67	%	22,873	66	%	23,766	66	%
Purchased generation	11,235	33		11,994	34		12,136	34
Total	34,258	100	%	34,867	100	%	35,902	100	%

(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.

Fuel Supply and Costs

The following table shows the delivered cost per MMBtu of each significant category of fuel consumed for owned electric generation, the percentage of total fuel requirements represented by each category of fuel and the total weighted average cost of all fuels.

	Coal				Natural Gas				Weighted Average Owned Fuel Cost
PSCo Generating Plants	Cost		Percent		Cost		Percent		Weighted Average Owned Fuel Cost
2014	$	1.82	75	%	$	5.32	25	%	$	2.68
2013	1.84		80		4.86		20		2.45
2012	1.77		78		4.25		22		2.31

The higher cost of natural gas was primarily due to higher market prices from increased demand because of cold weather in early 2014.

See Items 1A and 7 for further discussion of fuel supply and costs.

Fuel Sources

Coal — PSCo normally maintains approximately 41 days of coal inventory. Coal supply inventories at Dec. 31, 2014 and 2013 were approximately 36 and 41 days usage, respectively. At Dec. 31, 2014, coal inventories were below optimal levels due to railcar congestion. PSCo’s generation stations use low-sulfur western coal purchased primarily under contracts with suppliers operating in Colorado and Wyoming. During 2014 and 2013, PSCo’s coal requirements for existing plants were approximately 10.3 million tons and 11.3 million tons, respectively. The estimated coal requirements for 2015 are approximately 11.0 million tons.

PSCo has contracted for coal supply to provide 96 percent of its estimated coal requirements in 2015, and a declining percentage of requirements in subsequent years. PSCo’s general coal purchasing objective is to contract for approximately 100 percent of requirements for the first year, 67 percent of requirements in year two, and 33 percent of requirements in year three. Remaining requirements will be filled through the procurement process or over-the-counter transactions.

PSCo has coal transportation contracts that provide for delivery of 100 percent of its coal requirements in 2015 and 2016. Coal delivery may be subject to interruptions or reductions due to operation of the mines, transportation problems, weather and availability of equipment.

Natural gas — PSCo uses both firm and interruptible natural gas supply and standby oil in combustion turbines and certain boilers. Natural gas supplies for PSCo’s power plants are procured under contracts to provide an adequate supply of fuel. However, as natural gas primarily serves intermediate and peak demand, any remaining forecasted requirements are able to be procured through a liquid spot market. The majority of natural gas supply under contract is covered by a long-term agreement with Anadarko Energy Services Company, the balance of natural gas supply contracts have variable pricing features tied to changes in various natural gas indices. PSCo hedges a portion of that risk through financial instruments. See Note 11 to the consolidated financial statements for further discussion.

Most transportation contract pricing is based on FERC approved transportation tariff rates. Certain natural gas supply and transportation agreements include obligations for the purchase and/or delivery of specified volumes of natural gas or to make payments in lieu of delivery.

• 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.

PSCo has limited on-site fuel oil storage facilities and primarily relies on the spot market for incremental supplies.

Renewable Energy Sources

PSCo’s renewable energy portfolio includes wind, hydroelectric, biomass and solar power from both owned generating facilities and PPAs. As of Dec. 31, 2014, PSCo was in compliance with mandated RPS, which require generation from renewable resources of 12 percent of electric retail sales.

• 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 also offers customer-focused renewable energy initiatives. Windsource allows customers to purchase a portion or all of their electricity from renewable sources. In 2014, the number of customers utilizing Windsource increased to approximately 41,000 from 37,000 in 2013. Windsource MWh sales declined slightly, due in part to loss of certain commercial customers, from approximately 197,000 MWh in 2013 to 188,000 MWh in 2014.

Additionally, to encourage the growth of solar energy on the system, customers are offered incentives to install solar panels on their homes and businesses under the Solar*Rewards program. Over 24,000 PV systems with approximately 221 MW of aggregate capacity and over 18,250 PV systems with approximately 188 MW of aggregate capacity have been installed in Colorado under this program as of Dec. 31, 2014 and 2013, respectively. In 2014, the first community solar gardens were interconnected in Colorado. As of Dec. 31, 2014, 14 gardens have been completed with 9.6 MW of capacity.

Wind — PSCo acquires the majority of its wind energy from PPAs with wind farm owners, primarily located in Colorado. Currently, PSCo has 18 of these agreements in place, with facilities ranging in size from two MW to over 300 MW. PSCo owns and operates the 26 MW Ponnequin Wind Farm in northern Colorado, which has been in service since 1999.

• 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.

• 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.

Wholesale Commodity Marketing Operations

PSCo conducts various wholesale marketing operations, including the purchase and sale of electric capacity, energy and energy related products. See Item 7 for further discussion.

SPS

Public Utility Regulation

Summary of Regulatory Agencies and Areas of Jurisdiction — The PUCT and NMPRC regulate SPS’ retail electric operations and have jurisdiction over its retail rates and services and the construction of transmission or generation in their respective states. The municipalities in which SPS operates in Texas have original jurisdiction over SPS’ rates in those communities. Each municipality can deny SPS’ rate increases. SPS can then appeal municipal rate decisions to the PUCT, which hears all municipal rate denials in one hearing. The NMPRC also has jurisdiction over the issuance of securities. SPS is regulated by the FERC with respect to its wholesale electric operations, accounting practices, wholesale sales for resale, the transmission of electricity in interstate commerce, compliance with NERC electric reliability standards, asset transactions and mergers, and natural gas transactions in interstate commerce. SPS has received authorization from the FERC to make wholesale electric sales at market-based prices.

Fuel, Purchased Energy and Conservation Cost-Recovery Mechanisms — SPS has several retail adjustment clauses that recover fuel, purchased energy and other resource costs:

• 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.

Fuel and purchased energy costs are recovered in Texas through a fixed fuel and purchased energy recovery factor, which is part of SPS’ retail electric tariff. SO and NOx allowance revenues and costs are also recovered through the fixed fuel and purchased energy recovery factor. The regulations allow retail fuel factors to change up to three times per year.

The fixed fuel and purchased energy recovery factor provides for the over- or under-recovery of fuel and purchased energy expenses. Regulations also require refunding or surcharging over- or under- recovery amounts, including interest, when they exceed four percent of the utility’s annual fuel and purchased energy costs on a rolling 12-month basis, if this condition is expected to continue.

PUCT regulations require periodic examination of SPS’ fuel and purchased energy costs, the efficient use of fuel and purchased energy, fuel acquisition and management policies and purchased energy commitments. SPS is required to file an application for the PUCT to retrospectively review fuel and purchased energy costs at least every three years.

NMPRC regulations require SPS to request authority to continue collecting its fuel and purchased power costs through a fuel adjustment clause every four years. The NMPRC previously granted SPS authority to use a fuel adjustment clause through November 2014, and allows its continued use while a new application is pending. In November 2014, SPS filed an application with the NMPRC to continue use of the fuel adjustment clause for an additional four years. Hearings are scheduled for May 2015.

SPS recovers fuel and purchased energy costs from its wholesale customers through a monthly wholesale fuel and purchased economic energy cost adjustment clause accepted for filing by the FERC.

Capacity and Demand

Uninterrupted system peak demand for SPS for each of the last three years and the forecast for 2015, assuming normal weather, is listed below.

	System Peak Demand (in MW)
	2012	2013	2014	2015 Forecast
SPS	5,265	5,056	4,871	4,982

The peak demand for the SPS system typically occurs in the summer. The 2014 uninterrupted system peak demand for SPS occurred on Aug. 7, 2014. The 2014 peak demand decreased due to cooler summer weather.

Energy Sources and Related Transmission Initiatives

SPS expects to use existing electric generating stations, power purchases, DSM and new generation options to meet its net dependable system capacity requirements.

Purchased Power — SPS has contracts to purchase power from other utilities and independent power producers. Long-term purchased power contracts typically require a periodic payment to secure the capacity and a charge for the associated energy actually purchased. SPS also makes short-term purchases to meet system load and energy requirements, to replace generation from company-owned units under maintenance or during outages, to meet operating reserve obligations or to obtain energy at a lower cost.

Purchased Transmission Services — SPS has contractual arrangements with SPP and regional transmission service providers, including PSCo, to deliver power and energy to its native load customers, which are retail and wholesale load obligations with terms of more than one year.

SPP Integrated Market (IM) — In February 2014, the FERC granted SPS approval to make sales to the SPP IM at market-based rates. Further, In February and March, respectively, SPS was granted interim approval for revised QF tariff pricing in Texas and New Mexico to be consistent with the new market and to coincide with the start of the IM. The SPP IM began operations in March 2014 and operates in the day ahead and real time energy and ancillary services market. In April 2014, the FERC approved SPS’ filings to modify its wholesale power sales contracts to allow recovery of SPP IM charges and revenues through the SPP wholesale FCA.

SPS Transmission NTCs — As a member of SPP, SPS accepts NTCs for electric transmission line and substation projects to be built within the SPP footprint. SPS has accepted NTCs for projects with an estimated capital cost of approximately $1.9 billion and will continue to review new NTCs for acceptance as they are issued. These projects generally span several years to plan, site, procure and develop. The NMPRC and the PUCT must approve the siting and routing of any SPP identified transmission line NTC projects that require permitting approval. Projects identified through SPP NTCs may have costs allocated to other SPP members in accordance with the SPP OATT. Costs allocated to SPS are permissible for recovery through the NMPRC, the PUCT and the FERC processes.

High Priority Incremental Load Study Report

In April 2014, the SPP Board of Directors approved the High Priority Incremental Load Study Report, a reliability assessment that evaluated the anticipated transmission needs of certain parts of the SPP resulting from expected load growth in the area. As a result of this study, SPS has received NTCs and conditional NTCs for 44 new transmission projects to be placed into service by 2020. SPS is developing plans for these projects in preparation of submitting CCNs to the PUCT and the NMPRC. These projects are intended to provide regional reliability benefits as well as the ability to serve the increase in load in southeastern New Mexico.

TUCO substation to Woodward, Okla. 345 KV transmission line

The TUCO to Woodward District extra high voltage interchange is a 345 KV transmission line. SPS constructed the line to just inside the Oklahoma state line, and Oklahoma Gas and Electric Company (OGE) built from there to Woodward, Okla. SPS’ investment in the TUCO to Woodward line and substation is approximately $206 million and is expected to be recovered from SPP members, including SPS, in accordance with the SPP tariff. The line was placed into service in September 2014.

Hitchland substation to Woodward, Okla. 345 KV transmission line

The Hitchland substation to Woodward, Okla. line is a 345 KV double circuit transmission line and associated substation facilities in the Oklahoma and Texas Panhandle. SPS built the first 30 miles to Beaver County, Okla. and OGE completed the line from there to Woodward, Okla. SPS’ investment for the Hitchland to Woodward line and substation is approximately $58 million and is expected to be recovered from SPP members in accordance with the SPP tariff. The line was placed into service in May 2014.

Potash Junction substation to Roadrunner substation 345 KV transmission line

In April 2014, SPS filed a CCN with the NMPRC for a new 345 KV transmission line from the Potash Junction substation to the Roadrunner substation, both near Carlsbad, N.M. The proposed line would run 40 miles and cost an estimated $54 million. The NMPRC approved the CCN in December 2014. The line is anticipated to be placed into service in the fourth quarter of 2015.

SPS Resource Plans — SPS is required to develop and implement a renewable portfolio plan in which 15 percent of its energy to serve its New Mexico retail customers is produced by renewable resources in 2015. SPS primarily fulfills its renewable portfolio requirements through PPAs.

Energy Source Statistics

	Year Ended Dec. 31
	2014			2013			2012
SPS	Millions of KWh	Percent of Generation		Millions of KWh	Percent of Generation		Millions of KWh	Percent of Generation
Coal	12,770	48	%	14,184	49	%	14,005	49	%
Natural Gas	10,068	37		11,235	38		12,088	43
Wind ^(a)	3,762	14		3,507	12		2,103	7
Other ^(b)	180	1		167	1		177	1
Total	26,780	100	%	29,093	100	%	28,373	100	%

Owned generation	16,956	63	%	18,814	65	%	19,940	70	%
Purchased generation	9,824	37		10,279	35		8,433	30
Total	26,780	100	%	29,093	100	%	28,373	100	%

(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.

Fuel Supply and Costs

The following table shows the delivered cost per MMBtu of each significant category of fuel consumed for owned electric generation, the percentage of total fuel requirements represented by each category of fuel and the total weighted average cost of all fuels.

	Coal				Natural Gas				Weighted Average Owned Fuel Cost
SPS Generating Plants	Cost		Percent		Cost		Percent		Weighted Average Owned Fuel Cost
2014	$	2.07	71	%	$	4.76	29	%	$	2.85
2013	2.14		71		3.97		29		2.68
2012	1.87		67		2.99		33		2.24

See Items 1A and 7 for further discussion of fuel supply and costs.

Fuel Sources

Coal — SPS purchases all of the coal requirements for its two coal facilities, Harrington and Tolk electric generating stations, from TUCO. TUCO arranges for the purchase, receiving, transporting, unloading, handling, crushing, weighing and delivery of coal to meet SPS’ requirements. TUCO is responsible for negotiating and administering contracts with coal suppliers, transporters and handlers. The coal supply contract with TUCO expires in 2016 for Harrington and Tolk. SPS normally maintains approximately 43 days of coal inventory. As of Dec. 31, 2014 and 2013, coal inventories at SPS were approximately 17 and 42 days supply, respectively. At Dec. 31, 2014, coal inventories were below optimal levels due to railcar congestion. TUCO has coal agreements to supply 87 percent of SPS’ estimated coal requirements in 2015, and a declining percentage of the requirements in subsequent years. SPS’ general coal purchasing objective is to contract for approximately 100 percent of requirements for the first year, 67 percent of requirements in year two, and 33 percent of requirements in year three.

Natural gas — SPS uses both firm and interruptible natural gas supply and standby oil in combustion turbines and certain boilers. Natural gas for SPS’ power plants is procured under contracts to provide an adequate supply of fuel; which typically is purchased with terms of one year or less. The transportation and storage contracts expire in various years from 2015 to 2033. All of the natural gas supply contracts have variable pricing that is tied to various natural gas indices.

Most transportation contract pricing is based on FERC and Railroad Commission of Texas approved transportation tariff rates. Certain natural gas supply and transportation agreements include obligations for the purchase and/or delivery of specified volumes of natural gas or to make payments in lieu of delivery. SPS’ commitments related to gas supply contracts were approximately $3 million and $21 million and commitments related to gas transportation and storage contracts were approximately $222 million and $201 million at Dec. 31, 2014 and 2013, respectively.

SPS has limited on-site fuel oil storage facilities and primarily relies on the spot market for incremental supplies.

Renewable Energy Sources

SPS’ renewable energy portfolio includes wind and solar power from both owned generating facilities and PPAs. As of Dec. 31, 2014, SPS is in compliance with mandated RPS, which require generation from renewable resources of approximately four percent and 10 percent of Texas and New Mexico electric retail sales, respectively.

• 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.

SPS also offers customer-focused renewable energy initiatives. Windsource allows customers in New Mexico to purchase a portion or all of their electricity from renewable sources. The number of Windsource participants remained consistent at approximately 900 in 2013 and 2014. Windsource sales were approximately 4,400 MWh in 2013 and 3,900 MWh in 2014.

Additionally, to encourage the growth of solar energy on the system in New Mexico, customers are offered incentives to install solar panels on their homes and businesses under the Solar*Rewards program. Over 315 PV systems with approximately 20.8 MW of aggregate capacity and over 115 PV systems with approximately 7.6 MW of aggregate capacity have been installed in New Mexico under this program as of Dec. 31, 2014 and 2013, respectively.

Wind — SPS acquires its wind energy from independent power producers (IPP) and qualified facilities (QF) contracts with wind farm owners, primarily located in the Texas Panhandle area of Texas and New Mexico. SPS currently has 37 of these agreements in place, with facilities ranging in size from under two MW to 250 MW for a total capacity greater than 1,800 MW. SPS had approximately 1,500 MW and 1,000 MW of wind energy on its system at the end of 2014 and 2013, 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 contracts was approximately $26 for 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.

Wholesale Commodity Marketing Operations

SPS conducts various wholesale marketing operations, including the purchase and sale of electric capacity, energy and energy related products. SPS uses physical and financial instruments to minimize commodity price and credit risk and hedge sales and purchases. See Item 7 for further discussion.

Summary of Recent Federal Regulatory Developments

The FERC has jurisdiction over rates for electric transmission service in interstate commerce and electricity sold at wholesale, hydro facility licensing, natural gas transportation, asset transactions and mergers, accounting practices and certain other activities of Xcel Energy Inc.’s utility subsidiaries and transmission-only subsidiaries, including enforcement of NERC mandatory electric reliability standards. State and local agencies have jurisdiction over many of Xcel Energy Inc.’s utility subsidiaries’ activities, including regulation of retail rates and environmental matters. In addition to the matters discussed below, see Note 12 to the accompanying consolidated financial statements for a discussion of other regulatory matters.

FERC Order, New ROE Policy — In June 2014, the FERC adopted a new two-step ROE methodology for electric utilities. In October 2014, the FERC upheld the determination of the long-term growth rate to be used in its new ROE methodology. Several parties sought rehearing of the June 2014 order and therefore the new FERC policy may be subject to additional changes.

FERC Order 1000, Transmission Planning and Cost Allocation (Order 1000) — In 2011, the FERC issued a final ruling, Order 1000, adopting new requirements for transmission planning, cost allocation and development to be effective prospectively. Order 1000 requires:

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

• 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.

MISO, SPP and the jurisdictional WestConnect utilities, including PSCo, have submitted multiple compliance filings with the FERC to implement the Order 1000 requirements. Some of the new compliance provisions that were filed have already been approved but others remain under review by the FERC.

In August 2014, the D.C. Circuit denied all appeals and upheld Order 1000 in its entirety and indicated that challenges to the removal of federal ROFR provisions from individual contracts or tariffs could be considered in individual compliance filings. The FERC’s decisions to remove federal ROFR provisions in certain MISO and SPP agreements were appealed to federal courts of appeal in 2014, and those appeals are pending. The removal of a federal ROFR would eliminate rights that NSP-Minnesota, NSP-Wisconsin and SPS currently have under the MISO and SPP tariffs, respectively, to build certain transmission projects within their footprints.

In 2014, MISO and SPP both filed compliance plans that would allow the RTOs to recognize state law ROFRs in any selection process for Order 1000 transmission projects. The commissions granted these requests in 2014. In 2015, the FERC issued orders on rehearing on the compliance filing that would continue to allow MISO and SPP the authority to recognize state ROFRs. Xcel Energy has state ROFRs in Minnesota, North Dakota, South Dakota and believes it has a state ROFR in Texas.

Order 1000 could create opportunities for third parties to build and own certain regional transmission projects that had previously been reserved for the MISO and SPP transmission owners, potentially reducing NSP-Minnesota’s, NSP-Wisconsin’s and SPS’s financial return on new investments in electric transmission facilities. Xcel Energy formed its TransCo entities to pursue opportunities for new investments in electric transmission facilities that may be possible under Order 1000. The ultimate impact of Order 1000 on future Xcel Energy transmission investment is not known at this time.

TransCos — In 2014, Xcel Energy formed the Xcel Energy Transmission Holding Company, LLC and two of its TransCo subsidiaries that will participate in the MISO and SPP competitive bidding processes. Transmission assets held by these entities will be subject to FERC jurisdiction. Xcel Energy has also formed an additional TransCo subsidiary to pursue transmission projects in the western United States.

MISO

XETD was approved as a non-transmission owning member in MISO in April 2014, and a qualified transmission developer (QTD) in December 2014. This allows XETD to competitively bid for MISO transmission projects starting in 2015 or 2016.

SPP

In September 2014, SPP determined that XEST’s participant application was complete. This allows XEST to competitively bid for SPP transmission projects starting in 2015. The number of projects made available for competitive bidding in SPP in 2015, as the RTO establishes its rules and processes, is not expected to be significant.

In November 2014, the FERC approved XETD and XEST’s forward-looking transmission formula rates that will apply in their respective jurisdictions with an effective date retroactive to Nov. 1, 2014. The FERC approved the following items requested in the TransCo rate filings:

• 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.

In January 2015, XETD and XEST submitted compliance filings to the orders. Golden Spread Electric Cooperative, Inc. (Golden Spread) filed a protest to the XEST compliance filing in February 2015. The first settlement conference for the XEST ROE issue was held Jan. 6, 2015. The next settlement conference is scheduled for March 10, 2015.

WestConnect

XEWT executed the WestConnect planning participation agreement in January 2015, and is participating in the WestConnect regional planning process as an independent transmission developer or owner.

NERC Critical Infrastructure Protection Requirements — The FERC has approved version 5 of NERC’s critical infrastructure protection standards. Requirements must be applied to high and medium impact assets by April 1, 2016 and to low impact assets by April 1, 2017. Xcel Energy is currently in the process of evaluating the new requirements and identifying initiatives needed to meet the compliance deadlines.

NERC Physical Security Requirements — In November 2014, the FERC approved NERC’s proposed critical infrastructure protection standard related to physical security for bulk electric system facilities. The new standard will become enforceable in October 2015 with staggered milestone deliverable dates through 2016. Xcel Energy is currently in the process of developing and performing the initial risk assessment in accordance with the requirements of the standard, which will provide a basis to estimate the cost of protections necessary to meet the standard. The additional cost for compliance is anticipated to be recoverable through rates.

SPP and MISO Complaints Regarding RTO Joint Operating Agreement (JOA) — SPP and MISO have a longstanding dispute regarding the interpretation of their JOA, which is intended to coordinate RTO operations along the MISO/SPP system boundary. SPP and MISO disagree over MISO’s authority to transmit power over SPP transmission facilities between the traditional MISO region in the Midwest and the Entergy system. Several cases have been filed with the FERC by MISO and SPP. In June 2014, the FERC accepted a proposed tariff change by MISO to recover transmission charges imposed by SPP retroactive to January 2014, and set the issues for settlement judge and hearing procedures. If SPP is successful in charging MISO for use of the SPP system, the NSP System would experience higher costs from MISO, which could be material, but SPS would collect revenues from SPP. The outcome of the JOA disputes, and the potential impact on Xcel Energy, are uncertain at this time.

Xcel Energy Services Inc. and NSP-Wisconsin vs. ATC (La Crosse, Wis. to Madison, Wis. Transmission Line) — In February 2012, Xcel Energy Services Inc. and NSP-Wisconsin filed a complaint with the FERC concerning ownership of the proposed La Crosse, Wis. to Madison, Wis. 345 KV transmission line. In July 2012, the FERC ruled favorably on Xcel Energy Services Inc.’s and NSP-Wisconsin’s complaint, ruling that the responsibilities to construct the La Crosse, Wis. to Madison, Wis. transmission line, also known as the Badger Coulee line, belong equally to NSP-Wisconsin and ATC. In August 2012, ATC requested rehearing and requested that the FERC grant a stay of the ruling. ATC and NSP-Wisconsin jointly filed a CPCN application with the PSCW for the project in October 2013. In May 2014, the FERC issued an order denying the ATC request for rehearing and motion for stay. The 60 day period for ATC to appeal the FERC order lapsed, making the FERC ruling final.

MISO Transmission Pricing — The MISO Tariff presently provides for different allocation methods for the costs of new transmission investments depending on whether the project is primarily local or regional in nature. If a project qualifies as a MVP, the costs would be fully allocated to all loads in the MISO region. MVP eligibility is generally obtained for higher voltage (345 KV and higher) projects expected to serve multiple purposes, such as improved reliability, reduced congestion, transmission for renewable energy, and load serving.

Electric Operating Statistics

Electric Sales Statistics

	Year Ended Dec. 31
	2014			2013			2012
Electric sales (Millions of KWh)
Residential	24,857			25,306			25,033
Large C&I	27,657			27,206			27,396
Small C&I	36,022			35,873			35,660
Public authorities and other	1,104			1,098			1,109
Total retail	89,640			89,483			89,198
Sales for resale	14,931			15,065			15,781
Total energy sold	104,571			104,548			104,979

Number of customers at end of period
Residential	2,994,075			2,965,717			2,940,024
Large C&I	1,128			1,132			1,147
Small C&I	426,289			422,553			419,618
Public authorities and other	68,306			67,998			68,510
Total retail	3,489,798			3,457,400			3,429,299
Wholesale	44			65			75
Total customers	3,489,842			3,457,465			3,429,374

Electric revenues (Thousands of Dollars)
Residential	$	2,956,576		$	2,906,208		$	2,713,575
Large C&I	1,789,742			1,694,720			1,534,728
Small C&I	3,382,750			3,248,586			3,023,154
Public authorities and other	143,442			138,126			130,538
Total retail	8,272,510			7,987,640			7,401,995
Wholesale	796,766			693,728			687,912
Other electric revenues	396,614			352,677			427,389
Total electric revenues	$	9,465,890		$	9,034,045		$	8,517,296

KWh sales per retail customer	25,686			25,882			26,011
Revenue per retail customer	$	2,370		$	2,310		$	2,158
Residential revenue per KWh		11.89	¢		11.48	¢		10.84	¢
Large C&I revenue per KWh	6.47			6.23			5.60
Small C&I revenue per KWh	9.39			9.06			8.48
Total retail revenue per KWh	9.23			8.93			8.30
Wholesale revenue per KWh	5.34			4.60			4.36

Energy Source Statistics

	Year Ended Dec. 31
	2014			2013			2012
Xcel Energy	Millions of KWh	Percent of Generation		Millions of KWh	Percent of Generation		Millions of KWh	Percent of Generation
Coal	49,123	46	%	49,675	46	%	51,395	47	%
Natural Gas	22,071	21		24,350	23		26,218	24
Wind ^(a)	16,478	15		15,738	14		13,298	12
Nuclear	13,503	12		12,177	11		13,249	12
Hydroelectric	4,203	4		3,900	4		3,800	3
Other ^(b)	1,795	2		1,704	2		2,022	2
Total	107,173	100	%	107,544	100	%	109,982	100	%

Owned generation	73,620	69	%	70,936	66	%	75,071	68	%
Purchased generation	33,553	31		36,608	34		34,911	32
Total	107,173	100	%	107,544	100	%	109,982	100	%

(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.

NATURAL GAS UTILITY OPERATIONS

Overview

The most significant developments in the natural gas operations of the utility subsidiaries are continued volatility in natural gas market prices, uncertainty regarding political and regulatory developments that impact hydraulic fracturing, safety requirements for natural gas pipelines and the continued trend of declining use per residential and small C&I customer, as a result of improved building construction technologies, higher appliance efficiencies and conservation. From 2000 to 2014, average annual sales to the typical residential customer declined 14 percent, while sales to the typical small C&I customer declined 6 percent, each on a weather-normalized basis. Although wholesale price increases do not directly affect earnings because of natural gas cost-recovery mechanisms, high prices can encourage further efficiency efforts by customers.

The Pipeline and Hazardous Materials Safety Administration

Pipeline Safety Act — The Pipeline Safety, Regulatory Certainty, and Job Creation Act, signed into law in January 2012 (Pipeline Safety Act) requires additional verification of pipeline infrastructure records by pipeline owners and operators to confirm the maximum allowable operating pressure of lines located in high consequence areas or more-densely populated areas. The DOT Pipeline and Hazardous Materials Safety Administration (PHMSA) will require operators to re-confirm the maximum allowable operating pressure if records are inadequate. This process could cause temporary or permanent limitations on throughput for affected pipelines.

In addition, the Pipeline Safety Act requires PHMSA to issue reports and develop new regulations including: requiring use of automatic or remote-controlled shut-off valves; requiring testing of certain previously untested transmission lines; and expanding integrity management requirements. The Pipeline Safety Act also raises the maximum penalty for violating pipeline safety rules to $2 million per day for related violations. While Xcel Energy cannot predict the ultimate impact Pipeline Safety Act will have on its costs, operations or financial results, it is taking actions that are intended to comply with the Pipeline Safety Act and any related PHMSA regulations as they become effective. PSCo and NSP-Minnesota can generally recover costs to comply with the transmission and distribution integrity management programs through the PSIA and GUIC riders, respectively.

NSP-Minnesota

Public Utility Regulation

Summary of Regulatory Agencies and Areas of Jurisdiction — Retail rates, services and other aspects of NSP-Minnesota’s retail natural gas operations are regulated by the MPUC and the NDPSC within their respective states. The MPUC has regulatory authority over security issuances, certain property transfers, mergers with other utilities and transactions between NSP-Minnesota and its affiliates. In addition, the MPUC reviews and approves NSP-Minnesota’s natural gas supply plans for meeting customers’ future energy needs. NSP-Minnesota is subject to the jurisdiction of the FERC with respect to certain natural gas transactions in interstate commerce. NSP-Minnesota is subject to the DOT, the Minnesota Office of Pipeline Safety, the NDPSC and the SDPUC for pipeline safety compliance, including pipeline facilities used in electric utility operations for fuel deliveries.

Purchased Gas and Conservation Cost-Recovery Mechanisms — NSP-Minnesota’s retail natural gas rates for Minnesota and North Dakota include a PGA clause that provides for prospective monthly rate adjustments to reflect the forecasted cost of purchased natural gas, transportation service and storage service. The annual difference between the natural gas cost revenues collected through PGA rates and the actual natural gas costs is collected or refunded over the subsequent 12-month period.

NSP-Minnesota also recovers costs associated with transmission and distribution pipeline integrity management programs through its GUIC rider. Costs recoverable under the GUIC rider include funding for pipeline assessments as well as deferred costs from NSP-Minnesota’s existing sewer separation and pipeline integrity management programs. The MPUC and NDPSC have the authority to disallow recovery of certain costs if they find the utility was not prudent in its procurement activities.

Minnesota state law requires utilities to invest 0.5 percent of their state natural gas revenues in CIP. These costs are recovered through customer base rates and an annual cost-recovery mechanism for the CIP expenditures.

Capability and Demand

Natural gas supply requirements are categorized as firm or interruptible (customers with an alternate energy supply). The maximum daily send-out (firm and interruptible) for NSP-Minnesota was 752,931 MMBtu, which occurred on Jan. 2, 2014 and 767,636 MMBtu, which occurred on Jan. 21, 2013.

NSP-Minnesota purchases natural gas from independent suppliers, generally based on market indices that reflect current prices. The natural gas is delivered under transportation agreements with interstate pipelines. These agreements provide for firm deliverable pipeline capacity of 610,048 MMBtu per day. In addition, NSP-Minnesota contracts with providers of underground natural gas storage services. These agreements provide storage for approximately 26 percent of winter natural gas requirements and 30 percent of peak day firm requirements of NSP-Minnesota.

NSP-Minnesota also owns and operates one LNG plant with a storage capacity of 2.0 Bcf equivalent and three propane-air plants with a storage capacity of 1.3 Bcf equivalent to help meet its peak requirements. These peak-shaving facilities have production capacity equivalent to 246,000 MMBtu of natural gas per day, or approximately 30 percent of peak day firm requirements. LNG and propane-air plants provide a cost-effective alternative to annual fixed pipeline transportation charges to meet the peaks caused by firm space heating demand on extremely cold winter days.

NSP-Minnesota is required to file for a change in natural gas supply contract levels to meet peak demand, to redistribute demand costs among classes, or to exchange one form of demand for another. In August 2014, the MPUC approved NSP-Minnesota’s contract demand levels for the years 2007 through 2013. Demand levels filed with the MPUC in 2014 are awaiting approval.

Natural Gas Supply and Costs

NSP-Minnesota actively seeks natural gas supply, transportation and storage alternatives to yield a diversified portfolio that provides increased flexibility, decreased interruption and financial risk and economical rates. In addition, NSP-Minnesota conducts natural gas price hedging activity that has been approved by the MPUC.

The following table summarizes the average delivered cost per MMBtu of natural gas purchased for resale by NSP-Minnesota’s regulated retail natural gas distribution business:

2014	$	6.17
2013	4.53
2012	4.41

The higher cost of natural gas was primarily due to higher at market prices from increased demand because of cold weather in early 2014.

NSP-Minnesota has firm natural gas transportation contracts with several pipelines, which expire in various years from 2015 through 2033.

NSP-Minnesota has certain natural gas supply, transportation and storage agreements that include obligations for the purchase and/or delivery of specified volumes of natural gas or to make payments in lieu of delivery. At Dec. 31, 2014, NSP-Minnesota was committed to approximately $294 million in such obligations under these contracts.

NSP-Minnesota purchases firm natural gas supply utilizing long-term and short-term agreements from approximately 31 domestic and Canadian suppliers. This diversity of suppliers and contract lengths allows NSP-Minnesota to maintain competition from suppliers and minimize supply costs.

See Items 1A and 7 for further discussion of natural gas supply and costs.

NSP-Wisconsin

Public Utility Regulation

Summary of Regulatory Agencies and Areas of Jurisdiction — NSP-Wisconsin is regulated by the PSCW and the MPSC. The PSCW has a biennial base-rate filing requirement. By June of each odd-numbered year, NSP-Wisconsin must submit a rate filing for the test year period beginning the following January. NSP-Wisconsin is subject to the jurisdiction of the FERC with respect to certain natural gas transactions in interstate commerce. NSP-Wisconsin is subject to the DOT, the PSCW and the MPSC for pipeline safety compliance.

Natural Gas Cost-Recovery Mechanisms — NSP-Wisconsin has a retail PGA cost-recovery mechanism for Wisconsin operations to recover the actual cost of natural gas and transportation and storage services. The PSCW has the authority to disallow certain costs if it finds NSP-Wisconsin was not prudent in its procurement activities.

NSP-Wisconsin’s natural gas rate schedules for Michigan customers include a natural gas cost-recovery factor, which is based on 12-month projections.

Capability and Demand

Natural gas supply requirements are categorized as firm or interruptible (customers with an alternate energy supply). The maximum daily send-out (firm and interruptible) for NSP-Wisconsin was 163,520 MMBtu, which occurred on Jan. 6, 2014, and 155,087 MMBtu, which occurred on Jan. 21, 2013.

NSP-Wisconsin purchases natural gas from independent suppliers, generally based on market indices that reflect current prices. The natural gas is delivered under transportation agreements with interstate pipelines. These agreements provide for firm deliverable pipeline capacity of approximately 131,857 MMBtu per day. In addition, NSP-Wisconsin contracts with providers of underground natural gas storage services. These agreements provide storage for approximately 31 percent of winter natural gas requirements and 34 percent of peak day firm requirements of NSP-Wisconsin.

NSP-Wisconsin also owns and operates one LNG plant with a storage capacity of 270,000 Mcf equivalent and one propane-air plant with a storage capacity of 2,700 Mcf equivalent to help meet its peak requirements. These peak-shaving facilities have production capacity equivalent to 18,408 MMBtu of natural gas per day, or approximately 13 percent of peak day firm requirements. LNG and propane-air plants provide a cost-effective alternative to annual fixed pipeline transportation charges to meet the peaks caused by firm space heating demand on extremely cold winter days.

NSP-Wisconsin is required to file a natural gas supply plan with the PSCW annually to change natural gas supply contract levels to meet peak demand. NSP-Wisconsin’s winter 2014-2015 supply plan was approved by the PSCW in October 2014.

Natural Gas Supply and Costs

NSP-Wisconsin actively seeks natural gas supply, transportation and storage alternatives to yield a diversified portfolio that provides increased flexibility, decreased interruption and financial risk and economical rates. In addition, NSP-Wisconsin conducts natural gas price hedging activity that has been approved by the PSCW.

The following table summarizes the average delivered cost per MMBtu of natural gas purchased for resale by NSP-Wisconsin’s regulated retail natural gas distribution business:

2014	$	6.52
2013	4.51
2012	4.36

The higher cost of natural gas was primarily due to higher at market prices from increased demand because of cold weather in early 2014.

The cost of natural gas supply, transportation service and storage service is recovered through various cost-recovery adjustment mechanisms. NSP-Wisconsin has firm natural gas transportation contracts with several pipelines, which expire in various years from 2015 through 2029.

NSP-Wisconsin has certain natural gas supply, transportation and storage agreements that include obligations for the purchase and/or delivery of specified volumes of natural gas or to make payments in lieu of delivery. At Dec. 31, 2014, NSP-Wisconsin was committed to approximately $71 million in such obligations under these contracts.

NSP-Wisconsin purchased firm natural gas supply utilizing long-term and short-term agreements from approximately 8 domestic and Canadian suppliers. This diversity of suppliers and contract lengths allows NSP-Wisconsin to maintain competition from suppliers and minimize supply costs.

See Items 1A and 7 for further discussion of natural gas supply and costs.

PSCo

Public Utility Regulation

Summary of Regulatory Agencies and Areas of Jurisdiction — PSCo is regulated by the CPUC with respect to its facilities, rates, accounts, services and issuance of securities. PSCo holds a FERC certificate that allows it to transport natural gas in interstate commerce without PSCo becoming subject to full FERC jurisdiction under the Federal Natural Gas Act. PSCo is subject to the DOT and the CPUC with regards to pipeline safety compliance.

Purchased Natural Gas and Conservation Cost-Recovery Mechanisms — PSCo has retail adjustment clauses that recover purchased natural gas and other resource costs:

• 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.

QSP Requirements — The CPUC established a natural gas QSP that provides for bill credits to customers if PSCo does not achieve certain performance targets relating to natural gas leak repair time and customer service. The CPUC has extended the terms of the QSP through 2015.

Capability and Demand

PSCo projects peak day natural gas supply requirements for firm sales and backup transportation to be 1,983,672 MMBtu. In addition, firm transportation customers hold 771,112 MMBtu of capacity for PSCo without supply backup. Total firm delivery obligation for PSCo is 2,754,784 MMBtu per day. The maximum daily deliveries for PSCo for firm and interruptible services were 2,116,747 MMBtu on Dec. 30, 2014 and 1,865,207 MMBtu on Dec. 5, 2013.

PSCo purchases natural gas from independent suppliers, generally based on market indices that reflect current prices. The natural gas is delivered under transportation agreements with interstate pipelines. These agreements provide for firm deliverable pipeline capacity of approximately 1,814,265 MMBtu per day, which includes 850,840 MMBtu of natural gas held under third-party underground storage agreements. In addition, PSCo operates three company-owned underground storage facilities, which provide approximately 41,000 MMBtu of natural gas supplies on a peak day. The balance of the quantities required to meet firm peak day sales obligations are primarily purchased at PSCo’s city gate meter stations.

PSCo is required by CPUC regulations to file a natural gas purchase plan each year projecting and describing the quantities of natural gas supplies, upstream services and the costs of those supplies and services for the 12-month period of the following year. PSCo is also required to file a natural gas purchase report by October of each year reporting actual quantities and costs incurred for natural gas supplies and upstream services for the previous 12-month period.

Natural Gas Supply and Costs

PSCo actively seeks natural gas supply, transportation and storage alternatives to yield a diversified portfolio that provides increased flexibility, decreased interruption and financial risk and economical rates. In addition, PSCo conducts natural gas price hedging activities that have been approved by the CPUC.

The following table summarizes the average delivered cost per MMBtu of natural gas purchased for resale by PSCo’s regulated retail natural gas distribution business:

2014	$	4.91
2013	4.20
2012	4.28

The higher cost of natural gas was primarily due to higher at market prices from increased demand because of cold weather in early 2014.

PSCo has natural gas supply, transportation and storage agreements that include obligations for the purchase and/or delivery of specified volumes of natural gas or to make payments in lieu of delivery. At Dec. 31, 2014, PSCo was committed to approximately $1.4 billion in such obligations under these contracts, which expire in various years from 2015 through 2029.

PSCo purchases natural gas by optimizing a balance of long-term and short-term natural gas purchases, firm transportation and natural gas storage contracts. During 2014, PSCo purchased natural gas from approximately 34 suppliers.

See Items 1A and 7 for further discussion of natural gas supply and costs.

SPS

Natural Gas Facilities Used for Electric Generation

SPS does not provide retail natural gas service, but purchases and transports natural gas for certain of its generation facilities and operates natural gas pipeline facilities connecting the generation facilities to interstate natural gas pipelines. SPS is subject to the jurisdiction of the FERC with respect to certain natural gas transactions in interstate commerce; and to the jurisdiction of the DOT and the PUCT for pipeline safety compliance.

See Items 1A and 7 for further discussion of natural gas supply and costs.

Natural Gas Operating Statistics

	Year Ended Dec. 31
	2014		2013		2012
Natural gas deliveries (Thousands of MMBtu)
Residential	152,269		150,280		123,835
C&I	95,879		92,849		77,848
Total retail	248,148		243,129		201,683
Transportation and other	124,000		125,057		116,611
Total deliveries	372,148		368,186		318,294

Number of customers at end of period
Residential	1,795,190		1,776,849		1,760,364
C&I	155,515		154,646		154,158
Total retail	1,950,705		1,931,495		1,914,522
Transportation and other	6,594		6,320		5,789
Total customers	1,957,299		1,937,815		1,920,311

Natural gas revenues (Thousands of Dollars)
Residential	$	1,320,207	$	1,126,859	$	964,642
C&I	727,071		586,548		488,644
Total retail	2,047,278		1,713,407		1,453,286
Transportation and other	95,460		91,272		84,088
Total natural gas revenues	$	2,142,738	$	1,804,679	$	1,537,374

MMBtu sales per retail customer	127.21		125.88		105.34
Revenue per retail customer	$	1,050	$	887	$	759
Residential revenue per MMBtu	8.67		7.50		7.79
C&I revenue per MMBtu	7.58		6.32		6.28
Transportation and other revenue per MMBtu	0.77		0.73		0.72

GENERAL

Seasonality

The demand for electric power and natural gas is affected by seasonal differences in the weather. In general, peak sales of electricity occur in the summer months, and peak sales of natural gas occur in the winter months. As a result, the overall operating results may fluctuate substantially on a seasonal basis. Additionally, Xcel Energy’s operations have historically generated less revenues and income when weather conditions are milder in the winter and cooler in the summer. See Item 7 for further discussion.

Competition

Xcel Energy is a vertically integrated utility in all of its jurisdictions, subject to traditional cost-of-service regulation by state public utilities commissions. However, Xcel Energy is subject to different public policies that promote competition and the development of energy markets. Xcel Energy’s industrial and large commercial customers have the ability to own or operate facilities to generate their own electricity. In addition, customers may have the option of substituting other fuels, such as natural gas, steam or chilled water for heating, cooling and manufacturing purposes, or the option of relocating their facilities to a lower cost region. Customers also have the opportunity to supply their own power with on-site solar generation (typically rooftop solar) and in most jurisdictions can currently avoid paying for most of the fixed production, transmission and distribution costs incurred to serve them. Finally, in some of our states, customers can elect to subscribe to a community solar garden at pricing that affords them the same opportunity to avoid fixed charges as if they had rooftop installations.

The FERC has continued to promote competitive wholesale markets through open access transmission and other means. As a result, Xcel Energy Inc.’s utility subsidiaries and their wholesale customers can purchase the output from generation resources of competing wholesale suppliers and use the transmission systems of the utility subsidiaries on a comparable basis to serve their native load. State public utilities commissions have created resource planning programs that promote competition in the acquisition of electricity generation resources used to provide service to retail customers. In addition, FERC Order 1000 seeks to establish competition for construction and operation of certain new electric transmission facilities. Xcel Energy Inc.’s utility subsidiaries also have franchise agreements with certain cities subject to periodic renewal. If a city elected not to renew the franchise agreement, it could seek alternative means for its citizens to access electric power or gas, such as municipalization. Several states have policies designed to promote the development of solar and other distributed energy resources through significant incentive policies; with these incentives and federal tax subsidies, distributed generating resources are potential competitors to Xcel Energy’s electric service business. While each of Xcel Energy Inc.’s utility subsidiaries faces these challenges, Xcel Energy believes their rates and services are competitive with currently available alternatives.

ENVIRONMENTAL MATTERS

Xcel Energy’s facilities are regulated by federal and state environmental agencies. These agencies have jurisdiction over air emissions, water quality, wastewater discharges, solid wastes and hazardous substances. Various company activities require registrations, permits, licenses, inspections and approvals from these agencies. Xcel Energy has received all necessary authorizations for the construction and continued operation of its generation, transmission and distribution systems. Xcel Energy’s facilities have been designed and constructed to operate in compliance with applicable environmental standards. However, it is not possible to determine when or to what extent additional facilities or modifications of existing or planned facilities will be required as a result of changes to environmental regulations, interpretations or enforcement policies or what effect future laws or regulations may have upon Xcel Energy’s operations. See Item 7 and Notes 12 and 13 to the consolidated financial statements for further discussion.

There are significant future environmental regulations under consideration to encourage the use of clean energy technologies and regulate emissions of GHGs to address climate change. Xcel Energy has undertaken a number of initiatives to meet current requirements and prepare for potential future regulations, reduce GHG emissions and respond to state renewable and energy efficiency goals. If these future environmental regulations do not provide credit for the investments we have already made to reduce GHG emissions, or if they require additional initiatives or emission reductions, then their requirements would potentially impose additional substantial costs. We believe, based on prior state commission practice, we would recover the cost of these initiatives through rates.

Xcel Energy is committed to addressing climate change and potential climate change regulation through efforts to reduce its GHG emissions in a balanced, cost-effective manner. Xcel Energy adopted a methodology for calculating CO emissions based on the reporting protocols of The Climate Registry, a nonprofit organization that provides and compiles GHG emissions data from reporting entities. Starting in 2011, Xcel Energy began reporting GHG emissions to the EPA under the EPA’s mandatory GHG Reporting Program.

Based on The Climate Registry’s current reporting protocol, Xcel Energy estimated that its current electric generating portfolio emitted approximately 57.6 million and 57.2 million tons of CO in 2014 and 2013, respectively. Xcel Energy also estimated emissions associated with electricity purchased for resale to Xcel Energy customers from generation facilities owned by third parties. Xcel Energy estimates these non-owned facilities emitted approximately 11.4 million and 14.7 million tons of CO in 2014 and 2013, respectively. Estimated total CO emissions associated with service to Xcel Energy electric customers decreased by 3.0 million tons in 2014 compared to 2013. The decrease in emissions was associated with a decrease of 5.4 million net MWh of generation since 2011. The average annual decrease in CO emissions since 2011 is approximately 3.1 million tons of CO per year.

CAPITAL SPENDING AND FINANCING

See Item 7 for a discussion of expected capital expenditures and funding sources.

EMPLOYEES

As of Dec. 31, 2014, Xcel Energy had 11,589 full-time employees and 102 part-time employees, of which 5,588 were covered under collective-bargaining agreements. See Note 9 to the consolidated financial statements for further discussion.

EXECUTIVE OFFICERS

Ben Fowke, 56, Chairman of the Board, President and Chief Executive Officer and Director, Xcel Energy Inc., August 2011 to present. Chief Executive Officer, NSP-Minnesota, NSP-Wisconsin, PSCo, and SPS January 2015 to present. Previously, President and Chief Operating Officer, Xcel Energy Inc., August 2009 to August 2011; Executive Vice President and Chief Financial Officer, Xcel Energy Inc., December 2008 to August 2009.

Christopher B. Clark, 48, President and Director, NSP-Minnesota, January 2015 to present. Previously, Regional Vice President, Rates and Regulatory Affairs, NSP-Minnesota, October 2012 to December 2014; Managing Attorney and Director, Government and Regulatory Affairs, NSP-Minnesota, November 2007 to October 2012.

David L. Eves, 56, President and Director, PSCo, January 2015 to present. Previously, President, Director and Chief Executive Officer, PSCo, December 2009 to December 2014; President, Director and Chief Operating Officer, PSCo, November 2009 to December 2009; President and Director, SPS, December 2006 to November 2009; Chief Executive Officer, SPS, August 2006 to November 2009.

David T. Hudson, 54, President and Director, SPS, January 2015 to present. Previously, President, Director and Chief Executive Officer, SPS, January 2014 to December 2014; Director, Community Service & Economic Development, SPS, April 2011 to January 2014; Director, Strategic Planning, SPS, May 2008 to April 2011.

Kent T. Larson, 55, Executive Vice President and Group President Operations, Xcel Energy Inc., January 2015 to present. Previously, Senior Vice President, Group President Operations, Xcel Energy Services Inc., August 2014 to December 2014; Senior Vice President Operations, Xcel Energy Services Inc., September 2011 to August 2014; Chief Energy Supply Officer, Xcel Energy Services Inc., March 2010 to September 2011; Vice President, Transmission, Xcel Energy Services Inc., August 2008 to March 2010.

Teresa S. Madden, 59, Executive Vice President, Chief Financial Officer, Xcel Energy Inc., January 2015 to present. Previously, Senior Vice President, Chief Financial Officer, Xcel Energy Inc., September 2011 to December 2014; Vice President and Controller, Xcel Energy Inc., January 2004 to September 2011.

Marvin E. McDaniel, Jr., 55, Executive Vice President, Group President, Utilities, and Chief Administrative Officer, Xcel Energy Inc., January 2015 to present. Previously, Senior Vice President, Chief Administrative Officer, Xcel Energy Inc., August 2012 to December 2014; Senior Vice President and Chief Administrative Officer, Xcel Energy Services Inc., September 2011 to August 2012; Vice President and Chief Administrative Officer, Xcel Energy Services Inc., August 2009 to September 2011 and Vice President, Talent and Technology Business Areas, Xcel Energy Services Inc., August 2009 to September 2011; Vice President, Human Resources, Xcel Energy Services Inc., July 2007 to August 2009.

Timothy O’Connor, 55, Senior Vice President, Chief Nuclear Officer, Xcel Energy Services Inc., February 2013 to present. Previously, Acting Chief Nuclear Officer, NSP-Minnesota, September 2012 to February 2013; Vice President, Engineering and Nuclear Regulatory Compliance and Licensing July 2012 to September 2012; Monticello Site Vice President in May 2007 to July 2012.

Judy M. Poferl, 55, Senior Vice President, Corporate Secretary and Executive Services, Xcel Energy Inc., January 2015 to present. Previously, Vice President, Corporate Secretary, Xcel Energy Inc., May 2013 to December 2014; President, Director and Chief Executive Officer, NSP-Minnesota, August 2009 to May 2013; Regional Vice President, NSP-Minnesota, September 2008 to August 2009; Managing Director, Government and Regulatory Affairs, Xcel Energy Services Inc., November 2007 to September 2008.

Jeffrey S. Savage, 43, Senior Vice President, Controller, Xcel Energy Inc., January 2015 to present. Previously, Vice President, Controller, Xcel Energy Inc., September 2011 to December 2014; Senior Director, Financial Reporting, Corporate and Technical Accounting, Xcel Energy Services Inc., December 2009 to September 2011; Director, Financial Reporting and Technical Accounting, Xcel Energy Services Inc., March 2007 to December 2009.

Mark E. Stoering, 54, President and Director, NSP-Wisconsin, January 2015 to present. Previously, President, Director and Chief Executive Officer, NSP-Wisconsin, January 2012 to December 2014; Vice President, Portfolio Strategy and Business Development, Xcel Energy Services Inc., August 2000 to December 2011.

George E. Tyson, II, 49, Senior Vice President, Treasurer, Xcel Energy Inc., January 2015 to present. Previously, Vice President, Treasurer, Xcel Energy Inc., May 2004 to December 2014.

Scott M. Wilensky, 58, Executive Vice President, General Counsel, Xcel Energy Inc., January 2015 to present. Previously, Senior Vice President, General Counsel, Xcel Energy Inc., September 2011 to December 2014; Vice President, Regulatory and Resource Planning, Xcel Energy Services Inc., September 2009 to September 2011; Vice President, Government and Regulatory Affairs, Xcel Energy Services Inc., August 2008 to September 2009.

No family relationships exist between any of the executive officers or directors.

XEL - Xcel Energy Inc.