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x
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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¨
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TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
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Minnesota
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41-0448030
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(State or other jurisdiction of incorporation or organization)
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(I.R.S. Employer Identification No.)
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414 Nicollet Mall
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Minneapolis, MN 55401
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(Address of principal executive offices)
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Registrant’s telephone number, including area code:
612-330-5500
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Title of each class
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Name of each exchange on which registered
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Common Stock, $2.50 par value per share
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New York Stock Exchange
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Securities registered pursuant to section 12(g) of the Act:
None
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PART I
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Item 1 —
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Item 1A —
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Item 1B —
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Item 2 —
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Item 3 —
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Item 4 —
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PART II
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Item 5 —
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Item 6 —
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Item 7 —
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Item 7A —
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Item 8 —
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Item 9 —
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Item 9A —
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Item 9B —
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PART III
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Item 10 —
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Item 11 —
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Item 12 —
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Item 13 —
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Item 14 —
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PART IV
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Item 15 —
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Xcel Energy Inc.’s Subsidiaries and Affiliates (current and former)
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Eloigne
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Eloigne Company
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NCE
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New Century Energies, Inc.
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NMC
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Nuclear Management Company, LLC
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NSP-Minnesota
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Northern States Power Company, a Minnesota corporation
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NSP System
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The electric production and transmission system of NSP-Minnesota and NSP-Wisconsin operated on an integrated basis and managed by NSP-Minnesota
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NSP-Wisconsin
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Northern States Power Company, a Wisconsin corporation
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Operating companies
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NSP-Minnesota, NSP-Wisconsin, PSCo and SPS
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PSCo
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Public Service Company of Colorado
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PSRI
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P.S.R. Investments, Inc.
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SPS
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Southwestern Public Service Co.
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Utility subsidiaries
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NSP-Minnesota, NSP-Wisconsin, PSCo and SPS
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WGI
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WestGas InterState, Inc.
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WYCO
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WYCO Development LLC
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Xcel Energy
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Xcel Energy Inc. and its subsidiaries
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XETD
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Xcel Energy Transmission Development Company, LLC
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XEST
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Xcel Energy Southwest Transmission Company, LLC
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XEWT
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Xcel Energy West Transmission Company, LLC
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Federal and State Regulatory Agencies
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ASLB
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Atomic Safety and Licensing Board
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CFTC
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Commodity Futures Trading Commission
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CPUC
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Colorado Public Utilities Commission
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D.C. Circuit
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United States Court of Appeals for the District of Columbia Circuit
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DOC
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Minnesota Department of Commerce
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DOE
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United States Department of Energy
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DOI
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United States Department of the Interior
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DOT
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United States Department of Transportation
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EPA
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United States Environmental Protection Agency
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FERC
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Federal Energy Regulatory Commission
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IRS
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Internal Revenue Service
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MPCA
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Minnesota Pollution Control Agency
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MPSC
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Michigan Public Service Commission
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MPUC
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Minnesota Public Utilities Commission
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NDPSC
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North Dakota Public Service Commission
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NERC
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North American Electric Reliability Corporation
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NMPRC
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New Mexico Public Regulation Commission
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NRC
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Nuclear Regulatory Commission
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PNM
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Public Service Company of New Mexico
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PSCW
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Public Service Commission of Wisconsin
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PUCT
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Public Utility Commission of Texas
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SDPUC
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South Dakota Public Utilities Commission
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SEC
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Securities and Exchange Commission
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CPCN
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Certificate of public convenience and necessity
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CPP
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Clean Power Plan
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CSAPR
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Cross-State Air Pollution Rule
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CWIP
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Construction work in progress
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EEI
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Edison Electric Institute
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EGU
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Electric generating unit
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EPS
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Earnings per share
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ERCOT
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Electric Reliability Council of Texas
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ETR
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Effective tax rate
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FASB
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Financial Accounting Standards Board
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FIP
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Federal implementation plan
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FTR
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Financial transmission right
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GAAP
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Generally accepted accounting principles
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GHG
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Greenhouse gas
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HTY
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Historic test year
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IM
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Integrated market
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ISFSI
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Independent Spent Fuel Storage Installation
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ITC
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Investment Tax Credit
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LCM
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Life cycle management
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LLW
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Low-level radioactive waste
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LNG
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Liquefied natural gas
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MGP
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Manufactured gas plant
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MISO
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Midcontinent Independent System Operator, Inc.
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Moody’s
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Moody’s Investor Services
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MYP
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Multi-year plan
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NAAQS
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National Ambient Air Quality Standard
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Native load
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Customer demand of retail and wholesale customers that a utility has an obligation to serve
under statute or long-term contract
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NOL
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Net operating loss
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NOx
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Nitrogen oxide
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NOV
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Notice of violation
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NTC
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Notifications to construct
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NYISO
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New York Independent System Operator
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O&M
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Operating and maintenance
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OCC
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Office of Consumer Counsel
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OCI
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Other comprehensive income
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PCB
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Polychlorinated biphenyl
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PFS
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Private Fuel Storage, LLC
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PI
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Prairie Island nuclear generating plant
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PJM
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PJM Interconnection, LLC
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PM
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Particulate matter
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PPA
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Purchased power agreement
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PRP
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Potentially responsible party
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PTC
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Production tax credit
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PV
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Photovoltaic
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QF
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Qualifying facilities
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R&E
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Research and experimentation
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REC
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Renewable energy credit
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RFP
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Request for proposal
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ROE
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Return on equity
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RPS
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Renewable portfolio standards
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RTO
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Regional Transmission Organization
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Sharyland
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Sharyland Distribution and Transmission Services, LLC
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SIP
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State implementation plan
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SO
2
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Sulfur dioxide
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SPP
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Southwest Power Pool, Inc.
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S&P
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Standard & Poor’s Ratings Services
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TO
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Transmission owner
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TransCo
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Transmission-only subsidiary
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TSR
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Total shareholder return
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Wexpro
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Wexpro Development Company
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Measurements
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Bcf
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Billion cubic feet
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GWh
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Gigawatt hours
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KV
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Kilovolts
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KWh
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Kilowatt hours
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Mcf
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Thousand cubic feet
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MMBtu
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Million British thermal units
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MW
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Megawatts
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MWh
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Megawatt hours
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•
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CIP
— The CIP recovers the costs of conservation and demand-side management programs that help customers save energy.
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•
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EIR
— The EIR recovers the costs of environmental improvement projects.
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•
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RDF
— The RDF allocates money collected from retail customers to support the research and development of emerging renewable energy projects and technologies.
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•
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RES
— The RES recovers the cost of new renewable generation in Minnesota.
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•
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RER
— The RER recovers the cost of new renewable generation in North Dakota.
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•
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SEP
— The SEP recovers costs related to various energy policies approved by the Minnesota legislature.
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•
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TCR
— The TCR recovers costs associated with new investments in electric transmission and distribution costs that facilitate grid modernization.
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•
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Infrastructure
— The Infrastructure rider recovers costs associated with specific investments in generation and incremental property taxes in South Dakota.
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System Peak Demand (in MW)
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2013
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2014
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2015
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2016 Forecast
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NSP System
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9,524
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8,848
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8,621
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9,327
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•
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The addition of 800 MW of wind and 400 MW of utility scale solar to the pre-2020 time-frame;
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•
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The addition of 1000 MW of wind and 1000 MW of utility scale solar between 2020-2030;
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•
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The retirement of Sherco Unit 2 in 2023 and Sherco Unit 1 in 2026;
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•
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The addition of a 230 MW natural gas combustion turbine in North Dakota by 2025;
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•
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Replacement of Sherco coal generation with a 786 MW natural gas combined cycle unit at the Sherco site no later than 2026; and
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•
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Operation of the Monticello and PI nuclear plants through their current license periods in the early 2030’s.
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•
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Acceleration of NSP-Minnesota’s commitment to locate thermal generation in North Dakota from 2036 to by the end of 2025;
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•
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Exclusion of select wind and small solar PPAs from the NSP-Minnesota’s North Dakota Fuel Cost Rider;
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•
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Continued recovery in North Dakota of six existing biomass PPAs, subject, in part, to refund if NSP-Minnesota fails to achieve its generation commitment by the end of 2025;
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•
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Extension of the current rate moratorium through 2017;
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•
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NDPSC Staff support for continued use of 12-Coincident Peak system allocator through 2025; and,
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•
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Development of a framework to address future generation resources to be filed with the NDPSC by Jan. 1, 2017.
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•
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Hampton, Minn. to Rochester, Minn. to La Crosse, Wis. 161/345 Kilovolt (KV) transmission line
— The Wisconsin portion of the project includes a new substation and approximately 50 miles of new 345 KV transmission line, at an estimated cost of $211 million. The final 161 KV segment of the project went into service in January 2016, while the final 345 KV segment of the project is expected to go into service in the fall of 2016;
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•
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Brookings County, S.D. to Hampton, Minn. 345 KV transmission line
— The project was placed in service in March 2015;
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•
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Bemidji, Minn. to Grand Rapids, Minn. 230 KV transmission line
— The project was placed in service in September 2012;
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•
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Monticello, Minn. to Fargo, N.D. 345 KV transmission line
— In April 2015, the final portion of the project was placed in service; and
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•
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Big Stone South to Brookings County, S.D. 345 KV transmission line
— Construction on the line began in September 2015, with completion anticipated in 2017.
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•
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Increased flexibility for utilities to submit a MYP of up to five years;
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•
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The potential for full capital recovery for all proposed years;
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•
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O&M cost recovery based on an index;
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•
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Distribution costs that facilitate grid modernization are eligible for rider recovery;
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•
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Natural gas extension costs for unserved areas can be socialized and are eligible for rider recovery;
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•
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Recovery of plant closure costs, should the MPUC order early plant closure, such as in a resource plan; and
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•
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Allows implementation of interim rates for the first and second years of the MYP.
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Year Ended Dec. 31
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2015
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2014
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2013
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NSP System
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Millions of
KWh
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Percent of
Generation
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Millions of
KWh
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Percent of
Generation
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Millions of
KWh
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Percent of
Generation
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Coal
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15,961
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|
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35
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%
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18,079
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39
|
%
|
|
15,844
|
|
|
36
|
%
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Nuclear
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12,425
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27
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13,434
|
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29
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12,161
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|
|
28
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Natural Gas
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6,689
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|
|
15
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|
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3,402
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7
|
|
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5,550
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|
|
13
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Wind
(a)
|
6,235
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|
|
14
|
|
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6,243
|
|
|
14
|
|
|
5,481
|
|
|
13
|
|
Hydroelectric
|
3,326
|
|
|
7
|
|
|
3,560
|
|
|
8
|
|
|
3,223
|
|
|
7
|
|
Other
(b)
|
1,083
|
|
|
2
|
|
|
1,417
|
|
|
3
|
|
|
1,323
|
|
|
3
|
|
Total
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45,719
|
|
|
100
|
%
|
|
46,135
|
|
|
100
|
%
|
|
43,582
|
|
|
100
|
%
|
|
|
|
|
|
|
|
|
|
|
|
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||||||
Owned generation
|
33,818
|
|
|
74
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%
|
|
33,641
|
|
|
73
|
%
|
|
29,249
|
|
|
67
|
%
|
Purchased generation
|
11,901
|
|
|
26
|
|
|
12,494
|
|
|
27
|
|
|
14,333
|
|
|
33
|
|
Total
|
45,719
|
|
|
100
|
%
|
|
46,135
|
|
|
100
|
%
|
|
43,582
|
|
|
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 eight, seven, and eight million net KWh for 2015, 2014, and 2013, respectively.
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Coal
(a)
|
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Nuclear
|
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Natural Gas
|
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Weighted
Average Owned Fuel Cost
|
|||||||||||||||||
NSP System Generating Plants
|
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Cost
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Percent
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Cost
|
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Percent
|
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Cost
|
|
Percent
|
|
||||||||||||
2015
|
|
$
|
2.15
|
|
|
47
|
%
|
|
$
|
0.83
|
|
|
40
|
%
|
|
$
|
3.89
|
|
|
13
|
%
|
|
$
|
1.85
|
|
2014
|
|
2.23
|
|
|
52
|
|
|
0.89
|
|
|
42
|
|
|
6.27
|
|
|
6
|
|
|
1.94
|
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||||
2013
|
|
2.20
|
|
|
49
|
|
|
0.95
|
|
|
40
|
|
|
5.08
|
|
|
11
|
|
|
2.03
|
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(a)
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Includes refuse-derived fuel and wood.
|
•
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Current nuclear fuel supply contracts cover 100 percent of uranium concentrates requirements through 2018 and approximately 59 percent of the requirements for 2019 through 2030;
|
•
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Current contracts for conversion services cover 100 percent of the requirements through 2021 and approximately 54 percent of the requirements for 2022 through 2030; and
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•
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Current enrichment service contracts cover 100 percent of the requirements through 2026 and approximately 34 percent of the requirements for 2027 through 2030.
|
•
|
Renewable energy comprised
23.3
percent and 24.2 percent of the NSP System’s total energy for 2015 and 2014, respectively;
|
•
|
Wind energy comprised
13.6
percent and 13.7 percent of the total energy for 2015 and 2014, respectively;
|
•
|
Hydroelectric energy comprised
7.3
percent and 7.8 percent of the total energy for 2015 and 2014, respectively; and
|
•
|
Biomass and solar power comprised approximately
2.4
percent and 2.7 percent of the total energy for 2015 and 2014, respectively.
|
•
|
Collectively, the NSP System had approximately 2,210 and 1,860 MWs of wind energy on its system at the end of 2015 and 2014, respectively. In addition to receiving purchased wind energy under these agreements, the NSP System also typically receives wind RECs, which are used to meet state renewable resource requirements.
|
•
|
The average cost per MWh of wind energy under the existing contracts was approximately $42 and $41 for 2015 and 2014, respectively. The cost per MWh of wind energy varies by contract and may be influenced by a number of factors including regulation, state-specific renewable resource requirements, and the year of contract execution. Generally, contracts executed in 2015 continued to benefit from improvements in technology, excess capacity among manufacturers, and motivation to commence new construction prior to the anticipated expiration of the Federal PTCs. In December 2015, the Federal PTCs were extended through 2019 with a phase down beginning in 2017.
|
•
|
ECA
— The ECA recovers fuel and purchased energy costs. Short-term sales margins are shared with retail customers through the ECA. The ECA is revised quarterly.
|
•
|
PCCA
— The PCCA recovers purchased capacity payments.
|
•
|
SCA
— The SCA recovers the difference between PSCo’s actual cost of fuel and the amount of these costs recovered under its base steam service rates. The SCA rate is revised on a quarterly basis beginning in January 2015.
|
•
|
DSMCA
— The DSMCA recovers DSM, interruptible service option credit costs and performance initiatives for achieving various energy savings goals.
|
•
|
RESA
— The RESA recovers the incremental costs of compliance with the RES with a maximum of two percent of the customer’s total bill.
|
•
|
Wind Energy Service
— Wind Energy Service is a premium service for customers who voluntarily choose to pay an additional charge for renewable resources.
|
•
|
TCA
— The TCA recovers costs associated with transmission investment outside of rate cases.
|
•
|
CACJA
— The CACJA recovers costs associated with implementing its compliance plan under the CACJA.
|
|
System Peak Demand (in MW)
|
||||||||||
|
2013
|
|
2014
|
|
2015
|
|
2016 Forecast
|
||||
PSCo
|
6,678
|
|
|
6,152
|
|
|
6,284
|
|
|
6,493
|
|
•
|
The addition of 450 MW of wind generation PPAs became operational in 2015. These additional PPAs bring the installed wind capacity on PSCo’s system in Colorado to 2,560 MW;
|
•
|
The addition of 170 MW of utility-scale solar generation PPAs, of which 50 MW became operational in 2015 and the remaining 120 MW of utility-scale solar generation is expected to be operational by mid-2016. PSCo has approximately 80 MW of utility-scale solar and approximately 258 MW of customer-sited solar generation;
|
•
|
The addition of 317 MW of natural gas fired generation PPAs come from existing power plants;
|
•
|
The accelerated retirements of the coal-fired Arapahoe Unit 3 (45 MW) and Unit 4 (109 MW), which occurred in 2013; and
|
•
|
The continued operation of Cherokee generating station’s Unit 4 as a natural gas facility after 2017.
|
•
|
Two Innovative Clean Technology pilot programs in partnership with leading companies to address electric battery efficiency and reliability including demonstrations to test microgrids and battery technologies for integration of distributed resources;
|
•
|
Alignment of PSCo’s pricing in a more fair and equitable manner for Colorado customers;
|
•
|
Introduction of Solar*Connect®, a new, cost-based program that will offer customers a choice to sign up for 100 percent solar power and add an incremental 50 MW of solar generation;
|
•
|
Investing in natural gas reserves to take advantage of historically low natural gas prices by locking in current costs to provide long-term stable rates for customers;
|
•
|
Exploring opportunities for up to 1,000 MW of additional renewable resources to be presented later this year for consideration by the CPUC; and
|
•
|
Presenting an intelligent grid proposal later this year focusing on interactive meter technology that will improve customer choice and control of their energy use.
|
|
Year Ended Dec. 31
|
||||||||||||||||
|
2015
|
|
2014
|
|
2013
|
||||||||||||
PSCo
|
Millions of
KWh
|
|
Percent of
Generation
|
|
Millions of
KWh
|
|
Percent of
Generation
|
|
Millions of
KWh
|
|
Percent of
Generation
|
||||||
Coal
|
18,601
|
|
|
54
|
%
|
|
18,274
|
|
|
53
|
%
|
|
19,647
|
|
|
56
|
%
|
Natural Gas
|
7,948
|
|
|
23
|
|
|
8,601
|
|
|
25
|
|
|
7,565
|
|
|
22
|
|
Wind
(a)
|
6,699
|
|
|
19
|
|
|
6,472
|
|
|
19
|
|
|
6,750
|
|
|
19
|
|
Hydroelectric
|
662
|
|
|
2
|
|
|
617
|
|
|
2
|
|
|
655
|
|
|
2
|
|
Other
(b)
|
705
|
|
|
2
|
|
|
294
|
|
|
1
|
|
|
250
|
|
|
1
|
|
Total
|
34,615
|
|
|
100
|
%
|
|
34,258
|
|
|
100
|
%
|
|
34,867
|
|
|
100
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Owned generation
|
22,981
|
|
|
66
|
%
|
|
23,023
|
|
|
67
|
%
|
|
22,873
|
|
|
66
|
%
|
Purchased generation
|
11,634
|
|
|
34
|
|
|
11,235
|
|
|
33
|
|
|
11,994
|
|
|
34
|
|
Total
|
34,615
|
|
|
100
|
%
|
|
34,258
|
|
|
100
|
%
|
|
34,867
|
|
|
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 245, 197, and 172 million net KWh for 2015, 2014, and 2013, respectively.
|
|
|
Coal
|
|
Natural Gas
|
|
Weighted Average Owned Fuel Cost
|
||||||||||||
PSCo Generating Plants
|
|
Cost
|
|
Percent
|
|
Cost
|
|
Percent
|
|
|||||||||
2015
|
|
$
|
1.75
|
|
|
75
|
%
|
|
$
|
3.89
|
|
|
25
|
%
|
|
$
|
2.29
|
|
2014
|
|
1.82
|
|
|
75
|
|
|
5.32
|
|
|
25
|
|
|
2.68
|
|
|||
2013
|
|
1.84
|
|
|
80
|
|
|
4.86
|
|
|
20
|
|
|
2.45
|
|
•
|
At Dec. 31, 2015, PSCo’s commitments related to gas supply contracts, which expire in various years from 2016 through 2023, were approximately $750 million and commitments related to gas transportation and storage contracts, which expire in various years from 2016 through 2060, were approximately $684 million.
|
•
|
At Dec. 31, 2014, PSCo’s commitments related to gas supply contracts were approximately $902 million and commitments related to gas transportation and storage contracts were approximately $685 million.
|
•
|
Renewable energy comprised
21.9
percent and 21.4 percent of PSCo’s total energy for 2015 and 2014, respectively;
|
•
|
Wind energy comprised
19.4
percent and 18.9 percent of the total energy for 2015 and 2014, respectively; and
|
•
|
Hydroelectric, biomass and solar power comprised approximately
2.6
percent and 2.5 percent of the total energy for 2015 and 2014.
|
•
|
PSCo had approximately 2,560 MW and 2,340 MW of wind energy on its system at the end of 2015 and 2014, respectively. In addition to receiving purchased wind energy under these agreements, PSCo also typically receives wind RECs which are used to meet state renewable resource requirements.
|
•
|
The average cost per MWh of wind energy under these contracts was approximately $42 and $45 in 2015 and 2014, respectively. The cost per MWh of wind energy varies by contract and may be influenced by a number of factors including regulation, state-specific renewable resource requirements, and the year of contract execution. Generally, contracts executed in 2015 continued to benefit from improvements in wind technology, excess capacity among manufacturers, and motivation to commence new construction prior to the anticipated expiration of the Federal PTCs. In December 2015, the Federal PTCs were extended through 2019 with a phase down beginning in 2017.
|
•
|
DCRF
— The DCRF rider recovers certain distribution costs in Texas that are not included in base rates.
|
•
|
EECRF
— The EECRF rider recovers costs associated with providing energy efficiency programs in Texas.
|
•
|
EE rider
— The EE rider recovers costs associated with providing energy efficiency programs in New Mexico.
|
•
|
FPPCAC
— The FPPCAC adjusts monthly to recover the difference between the actual fuel and purchased power costs and the amount included in base rates of SPS’ New Mexico retail jurisdiction.
|
•
|
PCRF
— The PCRF rider allows recovery of certain purchased power costs in Texas that are not included in base rates.
|
•
|
RPS
— The RPS rider recovers deferred costs associated with renewable energy programs in New Mexico.
|
•
|
TCRF
— The TCRF rider recovers certain transmission infrastructure improvement costs and changes in wholesale transmission charges in Texas that are not included in base rates.
|
|
System Peak Demand (in MW)
|
||||||||||
|
2013
|
|
2014
|
|
2015
|
|
2016 Forecast
|
||||
SPS
|
5,056
|
|
|
4,871
|
|
|
4,678
|
|
|
4,886
|
|
•
|
Utilities may include actual and estimated post-test year capital additions up through 30-days before the filing date;
|
•
|
A new natural gas generating unit may be included in rate base as long as it is in service before the proposed effective rate date;
|
•
|
Rates will go into effect 155 days after filing (previously it was 185 days). If the case is not final by this date, then a utility can go back and surcharge; and
|
•
|
Establishes time limits for the PUCT to rule on a new generation plant request for a certificate of convenience and necessity.
|
|
Year Ended Dec. 31
|
||||||||||||||||
|
2015
|
|
2014
|
|
2013
|
||||||||||||
SPS
|
Millions of
KWh
|
|
Percent of
Generation
|
|
Millions of
KWh
|
|
Percent of
Generation
|
|
Millions of
KWh
|
|
Percent of
Generation
|
||||||
Coal
|
12,441
|
|
|
44
|
%
|
|
12,770
|
|
|
48
|
%
|
|
14,184
|
|
|
49
|
%
|
Natural Gas
|
10,514
|
|
|
36
|
|
|
10,068
|
|
|
37
|
|
|
11,235
|
|
|
38
|
|
Wind
(a)
|
5,252
|
|
|
19
|
|
|
3,762
|
|
|
14
|
|
|
3,507
|
|
|
12
|
|
Other
(b)
|
150
|
|
|
1
|
|
|
180
|
|
|
1
|
|
|
167
|
|
|
1
|
|
Total
|
28,357
|
|
|
100
|
%
|
|
26,780
|
|
|
100
|
%
|
|
29,093
|
|
|
100
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Owned generation
|
16,480
|
|
|
58
|
%
|
|
16,956
|
|
|
63
|
%
|
|
18,814
|
|
|
65
|
%
|
Purchased generation
|
11,877
|
|
|
42
|
|
|
9,824
|
|
|
37
|
|
|
10,279
|
|
|
35
|
|
Total
|
28,357
|
|
|
100
|
%
|
|
26,780
|
|
|
100
|
%
|
|
29,093
|
|
|
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 13, 10, and 11 million net KWh for 2015, 2014, and 2013, respectively.
|
|
|
Coal
|
|
Natural Gas
|
|
Weighted
Average Owned Fuel Cost
|
||||||||||||
SPS Generating Plants
|
|
Cost
|
|
Percent
|
|
Cost
|
|
Percent
|
|
|||||||||
2015
|
|
$
|
2.12
|
|
|
73
|
%
|
|
$
|
3.11
|
|
|
27
|
%
|
|
$
|
2.39
|
|
2014
|
|
2.07
|
|
|
71
|
|
|
4.76
|
|
|
29
|
|
|
2.85
|
|
|||
2013
|
|
2.14
|
|
|
71
|
|
|
3.97
|
|
|
29
|
|
|
2.68
|
|
•
|
SPS had approximately 1,775 MW and 1,500 MW of wind energy on its system at the end of 2015 and 2014, respectively. In addition to receiving purchased wind energy under these agreements, SPS also typically receives wind RECs, which are used to meet state renewable resource requirements.
|
•
|
The average cost per MWh of wind energy under the IPP contracts and QF tariffs was approximately $24 and $26 for 2015 and 2014, respectively. The cost per MWh of wind energy varies by contract and may be influenced by a number of factors including regulation, state-specific renewable resource requirements and the year of contract execution. Generally, contracts executed in 2015 continued to benefit from improvements in technology, excess capacity among manufacturers, and motivation to commence new construction prior to the anticipated expiration of the Federal PTCs. In December 2015, the Federal PTCs were extended through 2019 with a phase down beginning in 2017.
|
|
Year Ended Dec. 31
|
||||||||||
|
2015
|
|
2014
|
|
2013
|
||||||
Electric sales (Millions of KWh)
|
|
|
|
|
|
||||||
Residential
|
24,498
|
|
|
24,857
|
|
|
25,306
|
|
|||
Large C&I
|
27,719
|
|
|
27,657
|
|
|
27,206
|
|
|||
Small C&I
|
35,806
|
|
|
36,022
|
|
|
35,873
|
|
|||
Public authorities and other
|
1,071
|
|
|
1,104
|
|
|
1,098
|
|
|||
Total retail
|
89,094
|
|
|
89,640
|
|
|
89,483
|
|
|||
Sales for resale
|
15,283
|
|
|
14,931
|
|
|
15,065
|
|
|||
Total energy sold
|
104,377
|
|
|
104,571
|
|
|
104,548
|
|
|||
|
|
|
|
|
|
||||||
Number of customers at end of period
|
|
|
|
|
|
||||||
Residential
|
3,023,494
|
|
|
2,994,075
|
|
|
2,965,717
|
|
|||
Large C&I
|
1,229
|
|
|
1,128
|
|
|
1,132
|
|
|||
Small C&I
|
429,617
|
|
|
426,289
|
|
|
422,553
|
|
|||
Public authorities and other
|
68,595
|
|
|
68,306
|
|
|
67,998
|
|
|||
Total retail
|
3,522,935
|
|
|
3,489,798
|
|
|
3,457,400
|
|
|||
Wholesale
|
47
|
|
|
44
|
|
|
65
|
|
|||
Total customers
|
3,522,982
|
|
|
3,489,842
|
|
|
3,457,465
|
|
|||
|
|
|
|
|
|
||||||
Electric revenues (Thousands of Dollars)
|
|
|
|
|
|
||||||
Residential
|
$
|
2,891,371
|
|
|
$
|
2,956,576
|
|
|
$
|
2,906,208
|
|
Large C&I
|
1,689,695
|
|
|
1,789,742
|
|
|
1,694,720
|
|
|||
Small C&I
|
3,303,838
|
|
|
3,382,750
|
|
|
3,248,586
|
|
|||
Public authorities and other
|
136,730
|
|
|
143,442
|
|
|
138,126
|
|
|||
Total retail
|
8,021,634
|
|
|
8,272,510
|
|
|
7,987,640
|
|
|||
Wholesale
|
660,590
|
|
|
795,425
|
|
|
691,204
|
|
|||
Other electric revenues
|
593,762
|
|
|
397,955
|
|
|
355,201
|
|
|||
Total electric revenues
|
$
|
9,275,986
|
|
|
$
|
9,465,890
|
|
|
$
|
9,034,045
|
|
|
|
|
|
|
|
||||||
KWh sales per retail customer
|
25,290
|
|
|
25,686
|
|
|
25,882
|
|
|||
Revenue per retail customer
|
$
|
2,277
|
|
|
$
|
2,370
|
|
|
$
|
2,310
|
|
Residential revenue per KWh
|
|
11.80
|
¢
|
|
|
11.89
|
¢
|
|
|
11.48
|
¢
|
Large C&I revenue per KWh
|
6.10
|
|
|
6.47
|
|
|
6.23
|
|
|||
Small C&I revenue per KWh
|
9.23
|
|
|
9.39
|
|
|
9.06
|
|
|||
Total retail revenue per KWh
|
9.00
|
|
|
9.23
|
|
|
8.93
|
|
|||
Wholesale revenue per KWh
|
4.32
|
|
|
5.33
|
|
|
4.59
|
|
|
Year Ended Dec. 31
|
||||||||||||||||
|
2015
|
|
2014
|
|
2013
|
||||||||||||
Xcel Energy
|
Millions of
KWh
|
|
Percent of
Generation
|
|
Millions of
KWh
|
|
Percent of
Generation
|
|
Millions of
KWh
|
|
Percent of
Generation
|
||||||
Coal
|
47,003
|
|
|
43
|
%
|
|
49,123
|
|
|
46
|
%
|
|
49,675
|
|
|
46
|
%
|
Natural Gas
|
25,151
|
|
|
23
|
|
|
22,071
|
|
|
21
|
|
|
24,350
|
|
|
23
|
|
Wind
(a)
|
18,186
|
|
|
17
|
|
|
16,478
|
|
|
15
|
|
|
15,738
|
|
|
14
|
|
Nuclear
|
12,895
|
|
|
12
|
|
|
13,503
|
|
|
12
|
|
|
12,177
|
|
|
11
|
|
Hydroelectric
|
4,001
|
|
|
4
|
|
|
4,203
|
|
|
4
|
|
|
3,900
|
|
|
4
|
|
Other
(b)
|
1,456
|
|
|
1
|
|
|
1,795
|
|
|
2
|
|
|
1,704
|
|
|
2
|
|
Total
|
108,692
|
|
|
100
|
%
|
|
107,173
|
|
|
100
|
%
|
|
107,544
|
|
|
100
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Owned generation
|
73,279
|
|
|
67
|
%
|
|
73,620
|
|
|
69
|
%
|
|
70,936
|
|
|
66
|
%
|
Purchased generation
|
35,413
|
|
|
33
|
|
|
33,553
|
|
|
31
|
|
|
36,608
|
|
|
34
|
|
Total
|
108,692
|
|
|
100
|
%
|
|
107,173
|
|
|
100
|
%
|
|
107,544
|
|
|
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 266, 222, and 198 million net KWh for 2015, 2014 and 2013, respectively.
|
2015
|
$
|
4.07
|
|
2014
|
6.17
|
|
|
2013
|
4.53
|
|
2015
|
$
|
4.11
|
|
2014
|
6.52
|
|
|
2013
|
4.51
|
|
•
|
GCA
— The GCA recovers the actual costs of purchased natural gas and transportation to meet the requirements of its customers and is revised quarterly to allow for changes in natural gas rates.
|
•
|
DSMCA
— The DSMCA recovers costs of DSM and performance initiatives to achieve various energy savings goals.
|
•
|
PSIA
— The PSIA recovers costs associated with transmission and distribution pipeline integrity management programs and two projects to replace large transmission pipelines. The rider was extended through 2018.
|
2015
|
$
|
3.92
|
|
2014
|
4.91
|
|
|
2013
|
4.20
|
|
|
Year Ended Dec. 31
|
||||||||||
|
2015
|
|
2014
|
|
2013
|
||||||
Natural gas deliveries (Thousands of MMBtu)
|
|
|
|
|
|
||||||
Residential
|
135,394
|
|
|
152,269
|
|
|
150,280
|
|
|||
C&I
|
86,093
|
|
|
95,879
|
|
|
92,849
|
|
|||
Total retail
|
221,487
|
|
|
248,148
|
|
|
243,129
|
|
|||
Transportation and other
|
125,263
|
|
|
124,000
|
|
|
125,057
|
|
|||
Total deliveries
|
346,750
|
|
|
372,148
|
|
|
368,186
|
|
|||
|
|
|
|
|
|
||||||
Number of customers at end of period
|
|
|
|
|
|
||||||
Residential
|
1,814,321
|
|
|
1,795,190
|
|
|
1,776,849
|
|
|||
C&I
|
156,306
|
|
|
155,515
|
|
|
154,646
|
|
|||
Total retail
|
1,970,627
|
|
|
1,950,705
|
|
|
1,931,495
|
|
|||
Transportation and other
|
6,981
|
|
|
6,594
|
|
|
6,320
|
|
|||
Total customers
|
1,977,608
|
|
|
1,957,299
|
|
|
1,937,815
|
|
|||
|
|
|
|
|
|
||||||
Natural gas revenues (Thousands of Dollars)
|
|
|
|
|
|
||||||
Residential
|
$
|
1,042,884
|
|
|
$
|
1,320,207
|
|
|
$
|
1,126,859
|
|
C&I
|
547,165
|
|
|
727,071
|
|
|
586,548
|
|
|||
Total retail
|
1,590,049
|
|
|
2,047,278
|
|
|
1,713,407
|
|
|||
Transportation and other
|
82,032
|
|
|
95,460
|
|
|
91,272
|
|
|||
Total natural gas revenues
|
$
|
1,672,081
|
|
|
$
|
2,142,738
|
|
|
$
|
1,804,679
|
|
|
|
|
|
|
|
||||||
MMBtu sales per retail customer
|
112.39
|
|
|
127.21
|
|
|
125.88
|
|
|||
Revenue per retail customer
|
$
|
807
|
|
|
$
|
1,050
|
|
|
$
|
887
|
|
Residential revenue per MMBtu
|
7.70
|
|
|
8.67
|
|
|
7.50
|
|
|||
C&I revenue per MMBtu
|
6.36
|
|
|
7.58
|
|
|
6.32
|
|
|||
Transportation and other revenue per MMBtu
|
0.65
|
|
|
0.77
|
|
|
0.73
|
|
•
|
Sites of former MGPs operated by our subsidiaries, predecessors or other entities; and
|
•
|
Third party sites, such as landfills, for which we are alleged to be a PRP that sent hazardous materials and wastes.
|
•
|
The risks associated with use of radioactive material in the production of energy, the management, handling, storage and disposal and the current lack of a long-term disposal solution for radioactive materials;
|
•
|
Limitations on the amounts and types of insurance available to cover losses that might arise in connection with nuclear operations; and
|
•
|
Uncertainties with respect to the technological and financial aspects of decommissioning nuclear plants at the end of their licensed lives. For example, similar to pensions, interest rate and other assumptions regarding decommissioning costs may change based on economic conditions and changes in the expected life of the asset may cause our funding obligations to change.
|
NSP-Minnesota
Station, Location and Unit
|
|
Fuel
|
|
Installed
|
|
Summer 2015
Net Dependable
Capability (MW)
|
|
|
Steam:
|
|
|
|
|
|
|
|
|
A.S. King-Bayport, Minn., 1 Unit
|
|
Coal
|
|
1968
|
|
511
|
|
|
Sherco-Becker, Minn.
|
|
|
|
|
|
|
|
|
Unit 1
|
|
Coal
|
|
1976
|
|
680
|
|
|
Unit 2
|
|
Coal
|
|
1977
|
|
682
|
|
|
Unit 3
|
|
Coal
|
|
1987
|
|
517
|
|
(a)
|
Monticello-Monticello, Minn., 1 Unit
|
|
Nuclear
|
|
1971
|
|
607
|
|
|
PI-Welch, Minn.
|
|
|
|
|
|
|
|
|
Unit 1
|
|
Nuclear
|
|
1973
|
|
521
|
|
|
Unit 2
|
|
Nuclear
|
|
1974
|
|
519
|
|
|
Various locations, 4 Units
|
|
Wood/Refuse-derived fuel
|
|
Various
|
|
36
|
|
(b)
|
Combustion Turbine:
|
|
|
|
|
|
|
|
|
Angus Anson-Sioux Falls, S.D., 3 Units
|
|
Natural Gas
|
|
1994-2005
|
|
327
|
|
|
Black Dog-Burnsville, Minn., 2 Units
|
|
Natural Gas
|
|
1987-2002
|
|
282
|
|
|
Blue Lake-Shakopee, Minn., 6 Units
|
|
Natural Gas
|
|
1974-2005
|
|
453
|
|
|
High Bridge-St. Paul, Minn., 3 Units
|
|
Natural Gas
|
|
2008
|
|
538
|
|
|
Inver Hills-Inver Grove Heights, Minn., 6 Units
|
|
Natural Gas
|
|
1972
|
|
282
|
|
|
Riverside-Minneapolis, Minn., 3 Units
|
|
Natural Gas
|
|
2009
|
|
470
|
|
|
Various locations, 14 Units
|
|
Natural Gas
|
|
Various
|
|
67
|
|
|
Wind:
|
|
|
|
|
|
|
|
|
Grand Meadow-Mower County, Minn., 67 Units
|
|
Wind
|
|
2008
|
|
101
|
|
(c)
|
Nobles-Nobles County, Minn., 134 Units
|
|
Wind
|
|
2010
|
|
201
|
|
(c)
|
Pleasant Valley-Mower County, Minn., 100 Units
|
|
Wind
|
|
2015
|
|
200
|
|
(c)
|
Border-Rolette County, N.D., 75 Units
|
|
Wind
|
|
2015
|
|
150
|
|
(c)
|
|
|
|
|
Total
|
|
7,144
|
|
|
(a)
|
Based on NSP-Minnesota’s ownership of
59 percent
.
|
(b)
|
Refuse-derived fuel is made from municipal solid waste.
|
(c)
|
This capacity is only available when wind conditions are sufficiently high enough to support the noted generation values above. Therefore, the on-demand net dependable capacity is zero.
|
NSP-Wisconsin
Station, Location and Unit
|
|
Fuel
|
|
Installed
|
|
Summer 2015
Net Dependable
Capability (MW)
|
|
|
Steam:
|
|
|
|
|
|
|
|
|
Bay Front-Ashland, Wis., 3 Units
|
|
Coal/Wood/Natural Gas
|
|
1948-1956
|
|
56
|
|
|
French Island-La Crosse, Wis., 2 Units
|
|
Wood/Refuse-derived fuel
|
|
1940-1948
|
|
16
|
|
(a)
|
Combustion Turbine:
|
|
|
|
|
|
|
|
|
Flambeau Station-Park Falls, Wis., 1 Unit
|
|
Natural Gas
|
|
1969
|
|
12
|
|
|
French Island-La Crosse, Wis., 2 Units
|
|
Natural Gas
|
|
1974
|
|
122
|
|
|
Wheaton-Eau Claire, Wis., 4 Units
|
|
Natural Gas
|
|
1973
|
|
183
|
|
|
Hydro:
|
|
|
|
|
|
|
|
|
Various locations, 63 Units
|
|
Hydro
|
|
Various
|
|
135
|
|
|
|
|
|
|
Total
|
|
524
|
|
|
(a)
|
Refuse-derived fuel is made from municipal solid waste.
|
PSCo
Station, Location and Unit
|
|
Fuel
|
|
Installed
|
|
Summer 2015
Net Dependable
Capability (MW)
|
|
|
Steam:
|
|
|
|
|
|
|
|
|
Cherokee-Denver, Colo., 1 Unit
|
|
Coal
|
|
1968
|
|
352
|
|
|
Comanche-Pueblo, Colo.
|
|
|
|
|
|
|
|
|
Unit 1
|
|
Coal
|
|
1973
|
|
325
|
|
|
Unit 2
|
|
Coal
|
|
1975
|
|
335
|
|
|
Unit 3
|
|
Coal
|
|
2010
|
|
500
|
|
(a)
|
Craig-Craig, Colo., 2 Units
|
|
Coal
|
|
1979-1980
|
|
83
|
|
(b)
|
Hayden-Hayden, Colo., 2 Units
|
|
Coal
|
|
1965-1976
|
|
237
|
|
(c)
|
Pawnee-Brush, Colo., 1 Unit
|
|
Coal
|
|
1981
|
|
505
|
|
|
Valmont-Boulder, Colo., 1 Unit
|
|
Coal
|
|
1964
|
|
184
|
|
|
Combustion Turbine:
|
|
|
|
|
|
|
|
|
Cherokee-Denver, Colo., 3 Units
|
|
Natural Gas
|
|
2015
|
|
576
|
|
|
Blue Spruce-Aurora, Colo., 2 Units
|
|
Natural Gas
|
|
2003
|
|
264
|
|
|
Fort St. Vrain-Platteville, Colo., 6 Units
|
|
Natural Gas
|
|
1972-2009
|
|
969
|
|
|
Rocky Mountain-Keenesburg, Colo., 3 Units
|
|
Natural Gas
|
|
2004
|
|
580
|
|
|
Various locations, 6 Units
|
|
Natural Gas
|
|
Various
|
|
173
|
|
|
Hydro:
|
|
|
|
|
|
|
|
|
Cabin Creek-Georgetown, Colo.
|
|
|
|
|
|
|
|
|
Pumped Storage, 2 Units
|
|
Hydro
|
|
1967
|
|
210
|
|
|
Various locations, 9 Units
|
|
Hydro
|
|
Various
|
|
26
|
|
|
|
|
|
|
Total
|
|
5,319
|
|
|
(a)
|
Based on PSCo’s ownership interest of
67 percent
of Unit 3.
|
(b)
|
Based on PSCo’s ownership interest of
10 percent
.
|
(c)
|
Based on PSCo’s ownership interest of
76 percent
of Unit 1 and
37 percent
of Unit 2.
|
SPS
Station, Location and Unit
|
|
Fuel
|
|
Installed
|
|
Summer 2015
Net Dependable
Capability (MW)
|
|
Steam:
|
|
|
|
|
|
|
|
Harrington-Amarillo, Texas, 3 Units
|
|
Coal
|
|
1976-1980
|
|
1,018
|
|
Tolk-Muleshoe, Texas, 2 Units
|
|
Coal
|
|
1982-1985
|
|
1,067
|
|
Cunningham-Hobbs, N.M., 2 Units
|
|
Natural Gas
|
|
1957-1965
|
|
254
|
|
Jones-Lubbock, Texas, 2 Units
|
|
Natural Gas
|
|
1971-1974
|
|
486
|
|
Maddox-Hobbs, N.M., 1 Unit
|
|
Natural Gas
|
|
1967
|
|
112
|
|
Nichols-Amarillo, Texas, 3 Units
|
|
Natural Gas
|
|
1960-1968
|
|
457
|
|
Plant X-Earth, Texas, 4 Units
|
|
Natural Gas
|
|
1952-1964
|
|
411
|
|
Combustion Turbine:
|
|
|
|
|
|
|
|
Carlsbad-Carlsbad, N.M., 1 Unit
|
|
Natural Gas
|
|
1968
|
|
10
|
|
Cunningham-Hobbs, N.M., 2 Units
|
|
Natural Gas
|
|
1998
|
|
212
|
|
Jones-Lubbock, Texas, 2 Units
|
|
Natural Gas
|
|
2011-2013
|
|
338
|
|
Maddox-Hobbs, N.M., 1 Unit
|
|
Natural Gas
|
|
1963-1976
|
|
61
|
|
|
|
|
|
Total
|
|
4,426
|
|
Conductor Miles
|
|
NSP-Minnesota
|
|
NSP-Wisconsin
|
|
PSCo
|
|
SPS
|
||||
500 KV
|
|
2,917
|
|
|
—
|
|
|
—
|
|
|
—
|
|
345 KV
|
|
8,425
|
|
|
1,152
|
|
|
2,630
|
|
|
8,108
|
|
230 KV
|
|
2,157
|
|
|
—
|
|
|
12,553
|
|
|
9,302
|
|
161 KV
|
|
395
|
|
|
1,577
|
|
|
—
|
|
|
—
|
|
138 KV
|
|
—
|
|
|
—
|
|
|
92
|
|
|
—
|
|
115 KV
|
|
7,502
|
|
|
1,810
|
|
|
4,925
|
|
|
12,427
|
|
Less than 115 KV
|
|
84,074
|
|
|
32,355
|
|
|
75,155
|
|
|
23,299
|
|
|
|
NSP-Minnesota
|
|
NSP-Wisconsin
|
|
PSCo
|
|
SPS
|
||||
Quantity
|
|
349
|
|
|
204
|
|
|
229
|
|
|
444
|
|
Miles
|
|
NSP-Minnesota
|
|
NSP-Wisconsin
|
|
PSCo
|
|
WGI
|
||||
Transmission
|
|
136
|
|
|
—
|
|
|
2,278
|
|
|
11
|
|
Distribution
|
|
10,084
|
|
|
2,342
|
|
|
22,045
|
|
|
—
|
|
2015
|
|
High
|
|
Low
|
|
Dividends
|
||||||
First quarter
|
|
$
|
38.35
|
|
|
$
|
33.41
|
|
|
$
|
0.3200
|
|
Second quarter
|
|
35.35
|
|
|
31.76
|
|
|
0.3200
|
|
|||
Third quarter
|
|
36.48
|
|
|
32.12
|
|
|
0.3200
|
|
|||
Fourth quarter
|
|
37.25
|
|
|
34.33
|
|
|
0.3200
|
|
2014
|
|
High
|
|
Low
|
|
Dividends
|
||||||
First quarter
|
|
$
|
30.77
|
|
|
$
|
27.27
|
|
|
$
|
0.3000
|
|
Second quarter
|
|
32.37
|
|
|
29.83
|
|
|
0.3000
|
|
|||
Third quarter
|
|
32.48
|
|
|
29.60
|
|
|
0.3000
|
|
|||
Fourth quarter
|
|
37.58
|
|
|
30.18
|
|
|
0.3000
|
|
|
2010
|
|
2011
|
|
2012
|
|
2013
|
|
2014
|
|
2015
|
||||||||||||
Xcel Energy Inc.
|
$
|
100
|
|
|
$
|
122
|
|
|
$
|
123
|
|
|
$
|
134
|
|
|
$
|
178
|
|
|
$
|
185
|
|
EEI Investor-Owned Electrics
|
100
|
|
|
120
|
|
|
122
|
|
|
138
|
|
|
178
|
|
|
171
|
|
||||||
S&P 500
|
100
|
|
|
102
|
|
|
118
|
|
|
157
|
|
|
178
|
|
|
181
|
|
|
|
Issuer Purchases of Equity Securities
|
|||||||||||
Period
|
|
Total Number
of Shares
Purchased
|
|
Average Price
Paid per Share
|
|
Total Number of
Shares Purchased as Part of Publicly Announced Plans or
Programs
|
|
Maximum Number (or Approximate Dollar Value) of Shares That May Yet Be Purchased Under the Plans or Programs
|
|||||
Jan. 1, 2015 — Jan. 31, 2015
(a)
|
|
12,051
|
|
|
$
|
37.85
|
|
|
—
|
|
|
—
|
|
Feb. 1, 2015 — Feb. 28, 2015
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
March 1, 2015 — March 31, 2015
(b)
|
|
19,441
|
|
|
$
|
34.75
|
|
|
—
|
|
|
—
|
|
April 1, 2015 — Dec. 31, 2015
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Total
|
|
31,492
|
|
|
|
|
|
—
|
|
|
—
|
|
(a)
|
Xcel Energy Inc. or one of its agents periodically purchases common shares in order to satisfy obligations under the Stock Equivalent Plan for Non-Employee Directors.
|
(b)
|
Xcel Energy Inc. withholds stock to satisfy tax withholding obligations on vesting of awards of restricted stock under the Xcel Energy Executive Annual Incentive Award Plan.
|
(Millions of Dollars, Thousands of Shares, Except Per Share Data)
|
|
2015
|
|
2014
|
|
2013
|
|
2012
|
|
2011
|
||||||||||
Operating revenues
|
|
$
|
11,025
|
|
|
$
|
11,686
|
|
|
$
|
10,915
|
|
|
$
|
10,128
|
|
|
$
|
10,655
|
|
Operating expenses
|
|
9,024
|
|
|
9,738
|
|
|
9,067
|
|
|
8,306
|
|
|
8,873
|
|
|||||
Net income
|
|
984
|
|
|
1,021
|
|
|
948
|
|
|
905
|
|
|
841
|
|
|||||
Earnings available to common shareholders
|
|
984
|
|
|
1,021
|
|
|
948
|
|
|
905
|
|
|
834
|
|
|||||
Weighted average common shares outstanding:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Basic
|
|
507,768
|
|
|
503,847
|
|
|
496,073
|
|
|
487,899
|
|
|
485,039
|
|
|||||
Diluted
|
|
508,168
|
|
|
504,117
|
|
|
496,532
|
|
|
488,434
|
|
|
485,615
|
|
|||||
EPS:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Basic
|
|
$
|
1.94
|
|
|
$
|
2.03
|
|
|
$
|
1.91
|
|
|
$
|
1.86
|
|
|
$
|
1.72
|
|
Diluted
|
|
1.94
|
|
|
2.03
|
|
|
1.91
|
|
|
1.85
|
|
|
1.72
|
|
|||||
Dividends declared per common share
|
|
1.28
|
|
|
1.20
|
|
|
1.11
|
|
|
1.07
|
|
|
1.03
|
|
|||||
Total assets
|
|
39,054
|
|
|
36,958
|
|
|
33,907
|
|
|
31,141
|
|
|
29,497
|
|
|||||
Long-term debt
(a)
|
|
12,491
|
|
|
11,500
|
|
|
10,911
|
|
|
10,144
|
|
|
8,849
|
|
|||||
Book value per share
|
|
20.89
|
|
|
20.20
|
|
|
19.21
|
|
|
18.19
|
|
|
17.44
|
|
|||||
Return on average common equity
|
|
9.5
|
%
|
|
10.3
|
%
|
|
10.3
|
%
|
|
10.4
|
%
|
|
10.1
|
%
|
|||||
Ratio of earnings to fixed charges
(b)
|
|
3.2
|
|
|
3.3
|
|
|
3.1
|
|
|
2.8
|
|
|
2.8
|
|
|||||
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Non-GAAP:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Ongoing earnings
(c)
|
|
$
|
1,064
|
|
|
$
|
1,021
|
|
|
$
|
968
|
|
|
$
|
888
|
|
|
$
|
841
|
|
Ongoing diluted EPS
(c)
|
|
2.09
|
|
|
2.03
|
|
|
1.95
|
|
|
1.82
|
|
|
1.72
|
|
(a)
|
Includes capital lease obligations.
|
(b)
|
See Exhibit 12.01.
|
(c)
|
See Item 7 for reconciliations of ongoing earnings and diluted EPS to GAAP earnings and diluted EPS.
|
•
|
Improving utility performance;
|
•
|
Driving operational excellence;
|
•
|
Improving customer experience; and
|
•
|
Investing for the future.
|
•
|
Close the regulated ROE gap by 50 basis points by 2018 from the 2014 base level; and
|
•
|
Derive 75 percent of our revenue from regulated operations via multi-year regulatory plans by 2017.
|
•
|
Deliver long-term annual EPS growth of four percent to six percent, based on ongoing 2015 EPS of $2.10, which was the mid-point of Xcel Energy’s 2015 ongoing guidance range;
|
•
|
Deliver annual dividend increases of five percent to seven percent (prior objective was two to four percent annually);
|
•
|
Target a dividend payout ratio of 60 to 70 percent of annual ongoing EPS; and
|
•
|
Maintain senior unsecured debt credit ratings in the BBB+ to A range.
|
Diluted Earnings (Loss) Per Share
|
|
2015
|
|
2014
|
|
2013
|
||||||
PSCo
|
|
$
|
0.92
|
|
|
$
|
0.90
|
|
|
$
|
0.91
|
|
NSP-Minnesota
|
|
0.85
|
|
|
0.80
|
|
|
0.79
|
|
|||
SPS
|
|
0.25
|
|
|
0.26
|
|
|
0.23
|
|
|||
NSP-Wisconsin
|
|
0.15
|
|
|
0.14
|
|
|
0.12
|
|
|||
Equity earnings of unconsolidated subsidiaries
|
|
0.04
|
|
|
0.04
|
|
|
0.04
|
|
|||
Regulated utility
|
|
2.21
|
|
|
2.14
|
|
|
2.09
|
|
|||
Xcel Energy Inc. and other
|
|
(0.11
|
)
|
|
(0.11
|
)
|
|
(0.14
|
)
|
|||
Ongoing diluted EPS
(a)
|
|
2.09
|
|
|
2.03
|
|
|
1.95
|
|
|||
Loss on Monticello LCM/EPU project
|
|
(0.16
|
)
|
|
—
|
|
|
—
|
|
|||
SPS FERC complaint case orders
|
|
—
|
|
|
—
|
|
|
(0.04
|
)
|
|||
GAAP diluted EPS
(a)
|
|
$
|
1.94
|
|
|
$
|
2.03
|
|
|
$
|
1.91
|
|
(a)
|
Amounts may not add due to rounding.
|
Diluted Earnings (Loss) Per Share
|
|
Dec. 31
|
||
2014 GAAP and ongoing diluted EPS
|
|
$
|
2.03
|
|
|
|
|
||
Components of change — 2015 vs. 2014
|
|
|
||
Higher electric margins
|
|
0.31
|
|
|
Lower conservation and DSM program expenses
|
|
0.09
|
|
|
Lower O&M expenses
|
|
0.01
|
|
|
Higher depreciation and amortization
|
|
(0.13
|
)
|
|
Lower AFUDC — equity
|
|
(0.07
|
)
|
|
Higher ETR
|
|
(0.06
|
)
|
|
Higher taxes (other than income taxes)
|
|
(0.06
|
)
|
|
Higher interest charges
|
|
(0.03
|
)
|
|
Other, net
|
|
0.01
|
|
|
2015 ongoing diluted EPS
(a)
|
|
2.09
|
|
|
Loss on Monticello LCM/EPU project
|
|
(0.16
|
)
|
|
2015 GAAP diluted EPS
(a)
|
|
$
|
1.94
|
|
(a)
|
Amounts may not add due to rounding.
|
Diluted Earnings (Loss) Per Share
|
|
Dec. 31
|
||
2013 GAAP diluted EPS
|
|
$
|
1.91
|
|
SPS FERC complaint case orders
|
|
0.04
|
|
|
2013 ongoing diluted EPS
|
|
1.95
|
|
|
|
|
|
||
Components of change — 2014 vs. 2013
|
|
|
|
|
Higher electric margins (excludes impact of SPS FERC complaint case orders)
|
|
0.26
|
|
|
Higher natural gas margins
|
|
0.06
|
|
|
Lower interest charges (excludes 2013 impact of SPS FERC complaint case orders)
|
|
0.01
|
|
|
Higher O&M expenses
|
|
(0.07
|
)
|
|
Higher taxes (other than income taxes)
|
|
(0.06
|
)
|
|
Higher depreciation and amortization
|
|
(0.05
|
)
|
|
Higher conservation and DSM program expenses
|
|
(0.05
|
)
|
|
Dilution from at-the-market program, direct stock purchase plan and benefit plans
|
|
(0.03
|
)
|
|
Other, net
|
|
0.01
|
|
|
2014 ongoing and GAAP diluted EPS
|
|
$
|
2.03
|
|
ROE — 2015
|
|
PSCo
|
|
NSP-Minnesota
|
|
SPS
|
|
NSP-Wisconsin
|
|
Operating
Companies
(a)
|
|
Xcel Energy
(a)
|
||||||
2015 ongoing ROE
|
|
9.33
|
%
|
|
8.72
|
%
|
|
7.56
|
%
|
|
10.45
|
%
|
|
8.91
|
%
|
|
10.22
|
%
|
Loss on Monticello LCM/ EPU
project
|
|
—
|
|
|
(1.49
|
)
|
|
—
|
|
|
(0.42
|
)
|
|
(0.62
|
)
|
|
(0.76
|
)
|
2015 GAAP ROE
|
|
9.33
|
%
|
|
7.23
|
%
|
|
7.56
|
%
|
|
10.03
|
%
|
|
8.29
|
%
|
|
9.46
|
%
|
ROE — 2014
|
|
PSCo
|
|
NSP-Minnesota
|
|
SPS
|
|
NSP-Wisconsin
|
|
Operating
Companies
(a)
|
|
Xcel Energy
(a)
|
||||||
2014 ongoing and GAAP ROE
|
|
9.40
|
%
|
|
8.82
|
%
|
|
8.88
|
%
|
|
10.85
|
%
|
|
9.18
|
%
|
|
10.33
|
%
|
(a)
|
Excluding the impact of negative/positive weather, the Operating Companies and Xcel Energy’s ongoing ROEs equate to 9.07 percent and 10.40 percent, respectively, for 2015 and 9.06 percent and 10.18 percent, respectively, for 2014.
|
(Millions of Dollars)
|
|
2015
|
|
2014
|
|
2013
|
||||||
Ongoing earnings
|
|
$
|
1,063.7
|
|
|
$
|
1,021.3
|
|
|
$
|
968.4
|
|
Loss on Monticello LCM/EPU project (2015) and SPS FERC complaint
case orders (2013)
|
|
(79.2
|
)
|
|
—
|
|
|
(20.2
|
)
|
|||
GAAP earnings
|
|
$
|
984.5
|
|
|
$
|
1,021.3
|
|
|
$
|
948.2
|
|
Diluted Earnings (Loss) Per Share
|
|
2015
|
|
2014
|
|
2013
|
||||||
Ongoing diluted EPS
(a)
|
|
$
|
2.09
|
|
|
$
|
2.03
|
|
|
$
|
1.95
|
|
Loss on Monticello LCM/EPU project (2015) and SPS FERC complaint
case orders (2013)
|
|
(0.16
|
)
|
|
—
|
|
|
(0.04
|
)
|
|||
GAAP diluted EPS
(a)
|
|
$
|
1.94
|
|
|
$
|
2.03
|
|
|
$
|
1.91
|
|
(a)
|
Amounts may not add due to rounding.
|
(Millions of Dollars)
|
|
2015
|
|
2014
|
|
2013
|
||||||
GAAP income (loss) by segment
|
|
|
|
|
|
|
||||||
Regulated electric income
|
|
$
|
921.4
|
|
|
$
|
890.5
|
|
|
$
|
850.7
|
|
Regulated natural gas income
|
|
106.0
|
|
|
128.6
|
|
|
123.7
|
|
|||
Other income
(a)
|
|
15.8
|
|
|
59.5
|
|
|
44.6
|
|
|||
Xcel Energy Inc. and other costs
(a)
|
|
(58.7
|
)
|
|
(57.3
|
)
|
|
(70.8
|
)
|
|||
Total net income
|
|
$
|
984.5
|
|
|
$
|
1,021.3
|
|
|
$
|
948.2
|
|
Contributions to Diluted Earnings (Loss) Per Share
|
|
2015
|
|
2014
|
|
2013
|
||||||
GAAP earnings (loss) by segment
|
|
|
|
|
|
|
||||||
Regulated electric
|
|
$
|
1.81
|
|
|
$
|
1.77
|
|
|
$
|
1.71
|
|
Regulated natural gas
|
|
0.21
|
|
|
0.25
|
|
|
0.25
|
|
|||
Other
(a)
|
|
0.03
|
|
|
0.12
|
|
|
0.09
|
|
|||
Xcel Energy Inc. and other costs
(a)
|
|
(0.11
|
)
|
|
(0.11
|
)
|
|
(0.14
|
)
|
|||
Total diluted EPS
|
|
$
|
1.94
|
|
|
$
|
2.03
|
|
|
$
|
1.91
|
|
(a)
|
Not a reportable segment. Included in all other segment results in Note 17 to the consolidated financial statements.
|
|
2015 vs.
Normal |
|
2014 vs.
Normal |
|
2015 vs.
2014 |
|
2013 vs.
Normal |
|
2014 vs.
2013 |
|||||
HDD
|
(7.9
|
)%
|
|
7.8
|
%
|
|
(14.8
|
)%
|
|
6.5
|
%
|
|
0.4
|
%
|
CDD
|
6.2
|
|
|
(2.6
|
)
|
|
10.3
|
|
|
24.7
|
|
|
(20.3
|
)
|
THI
|
(2.3
|
)
|
|
(11.9
|
)
|
|
14.1
|
|
|
21.8
|
|
|
(24.2
|
)
|
|
2015 vs.
Normal |
|
2014 vs.
Normal |
|
2015 vs.
2014 |
|
2013 vs.
Normal
|
|
2014 vs.
2013
|
||||||||||
Retail electric
|
$
|
(0.020
|
)
|
|
$
|
0.010
|
|
|
$
|
(0.030
|
)
|
|
$
|
0.088
|
|
|
$
|
(0.078
|
)
|
Firm natural gas
|
(0.018
|
)
|
|
0.019
|
|
|
(0.037
|
)
|
|
0.021
|
|
|
(0.002
|
)
|
|||||
Total
|
$
|
(0.038
|
)
|
|
$
|
0.029
|
|
|
$
|
(0.067
|
)
|
|
$
|
0.109
|
|
|
$
|
(0.080
|
)
|
|
|
2015 vs. 2014
|
|||||||||||||
|
|
PSCo
|
|
NSP-Minnesota
|
|
SPS
|
|
NSP-Wisconsin
|
|
Xcel Energy
|
|||||
Actual
|
|
|
|
|
|
|
|
|
|
|
|||||
Electric residential
(a)
|
|
1.1
|
%
|
|
(3.2
|
)%
|
|
(0.4
|
)%
|
|
(6.1
|
)%
|
|
(1.4
|
)%
|
Electric C&I
|
|
(0.4
|
)
|
|
(0.6
|
)
|
|
0.3
|
|
|
0.4
|
|
|
(0.2
|
)
|
Total retail electric sales
|
|
0.1
|
|
|
(1.4
|
)
|
|
0.1
|
|
|
(1.5
|
)
|
|
(0.6
|
)
|
Firm natural gas sales
|
|
(6.6
|
)
|
|
(16.6
|
)
|
|
N/A
|
|
|
(16.4
|
)
|
|
(10.5
|
)
|
|
|
2015 vs. 2014
|
|||||||||||||
|
|
PSCo
|
|
NSP-Minnesota
|
|
SPS
|
|
NSP-Wisconsin
|
|
Xcel Energy
|
|||||
Weather-normalized
|
|
|
|
|
|
|
|
|
|
|
|||||
Electric residential
(a)
|
|
0.4
|
%
|
|
(0.7
|
)%
|
|
0.6
|
%
|
|
(2.8
|
)%
|
|
(0.3
|
)%
|
Electric C&I
|
|
(0.9
|
)
|
|
(0.2
|
)
|
|
0.7
|
|
|
0.8
|
|
|
(0.1
|
)
|
Total retail electric sales
|
|
(0.5
|
)
|
|
(0.4
|
)
|
|
0.5
|
|
|
(0.3
|
)
|
|
(0.2
|
)
|
Firm natural gas sales
|
|
(2.0
|
)
|
|
(1.1
|
)
|
|
N/A
|
|
|
(1.7
|
)
|
|
(1.7
|
)
|
•
|
PSCo’s residential growth was primarily the result of customer additions, partially offset by lower use per customer. Commercial and industrial (C&I) decline was primarily due to reduced sales to certain large manufacturing customers and/or those that support the fracking industry.
|
•
|
NSP-Minnesota’s residential decrease was due to lower use per customer, partially offset by an increase in customer additions. C&I electric sales decreased as a result of lower use by large and small customers (e.g., services, retail trade, finance insurance and real estate industries), partially offset by higher use by certain large customers in the petroleum and food processing industries. The decline was partially reduced by an increase in the number of customers in both the small and large classes.
|
•
|
SPS’ residential growth reflects an increased number of customers. C&I also had an increase in customers, primarily in the oil and gas exploration and production industries. However, this was partially offset by reduced activity per customer within these industries, as well as less irrigation by agricultural customers due to wet weather.
|
•
|
NSP-Wisconsin’s residential decline was primarily attributable to lower use per customer, partially offset by customer additions. C&I electric sales growth was largely due to strong sales to large customers primarily in the oil and gas industries.
|
•
|
Across natural gas service territories, lower natural gas sales reflect a decline in customer use.
|
|
|
2014 v. 2013
|
|||||||||||||
|
|
PSCo
|
|
NSP-Minnesota
|
|
SPS
|
|
NSP-Wisconsin
|
|
Xcel Energy
|
|||||
Actual
|
|
|
|
|
|
|
|
|
|
|
|||||
Electric residential
(a)
|
|
(2.8
|
)%
|
|
(1.6
|
)%
|
|
(0.4
|
)%
|
|
(0.3
|
)%
|
|
(1.8
|
)%
|
Electric C&I
|
|
0.3
|
|
|
—
|
|
|
2.5
|
|
|
4.2
|
|
|
1.0
|
|
Total retail electric sales
|
|
(0.7
|
)
|
|
(0.5
|
)
|
|
1.8
|
|
|
2.8
|
|
|
0.2
|
|
Firm natural gas sales
|
|
(0.7
|
)
|
|
7.3
|
|
|
N/A
|
|
|
7.4
|
|
|
2.3
|
|
|
|
2014 vs. 2013
|
|||||||||||||
|
|
PSCo
|
|
NSP-Minnesota
|
|
SPS
|
|
NSP-Wisconsin
|
|
Xcel Energy
|
|||||
Weather-normalized
|
|
|
|
|
|
|
|
|
|
|
|||||
Electric residential
(a)
|
|
0.3
|
%
|
|
0.7
|
%
|
|
0.4
|
%
|
|
0.5
|
%
|
|
0.5
|
%
|
Electric C&I
|
|
1.6
|
|
|
0.6
|
|
|
2.8
|
|
|
4.4
|
|
|
1.7
|
|
Total retail electric sales
|
|
1.2
|
|
|
0.6
|
|
|
2.3
|
|
|
3.3
|
|
|
1.3
|
|
Firm natural gas sales
|
|
5.2
|
|
|
3.6
|
|
|
N/A
|
|
|
3.8
|
|
|
4.6
|
|
•
|
NSP-Wisconsin’s electric sales growth was largely due to strong sales to large C&I customers primarily in the oil, gas and sand mining industries.
|
•
|
SPS’ C&I growth was driven by continued expansion from oil and gas exploration and production in the Southeastern New Mexico, Permian Basin area.
|
•
|
PSCo’s electric sales growth was primarily due to customers in the food manufacturing, fracking and mining industries.
|
•
|
NSP-Minnesota’s electric sales growth was led by an increased number of customers for both residential and small C&I, as well as higher use per customer in small C&I.
|
•
|
Across our natural gas service territories, strong sales were experienced in 2014, which continued the trend that began in the last half of 2013.
|
(Millions of Dollars)
|
|
2015
|
|
2014
|
|
2013
|
||||||
Electric revenues
|
|
$
|
9,276
|
|
|
$
|
9,466
|
|
|
$
|
9,034
|
|
Electric fuel and purchased power
|
|
(3,763
|
)
|
|
(4,210
|
)
|
|
(4,019
|
)
|
|||
Electric margin
|
|
$
|
5,513
|
|
|
$
|
5,256
|
|
|
$
|
5,015
|
|
(Millions of Dollars)
|
|
2015 vs. 2014
|
||
Fuel and purchased power cost recovery
|
|
$
|
(469
|
)
|
Conservation and DSM program revenues (offset by expenses)
|
|
(62
|
)
|
|
Estimated impact of weather
|
|
(23
|
)
|
|
Trading
|
|
(14
|
)
|
|
Retail rate increases
(a)
|
|
101
|
|
|
Colorado CACJA non-fuel rider
|
|
94
|
|
|
Transmission revenue
|
|
91
|
|
|
PSCo earnings test refund
|
|
74
|
|
|
Non-fuel riders
(b)
|
|
20
|
|
|
Other, net
|
|
(2
|
)
|
|
Total decrease in electric revenues
|
|
$
|
(190
|
)
|
(Millions of Dollars)
|
|
2015 vs. 2014
|
||
Retail rate increases
(a)
|
|
$
|
101
|
|
Colorado CACJA non-fuel rider
|
|
94
|
|
|
PSCo earnings test refunds
|
|
74
|
|
|
Transmission revenue, net of costs
|
|
47
|
|
|
Non-fuel riders
(b)
|
|
20
|
|
|
Conservation and DSM program revenues (offset by expenses)
|
|
(62
|
)
|
|
Estimated impact of weather
|
|
(23
|
)
|
|
Other, net
|
|
6
|
|
|
Total increase in electric margin
|
|
$
|
257
|
|
(Millions of Dollars)
|
|
2014 vs. 2013
|
||
Retail rate increases
(a)
|
|
$
|
129
|
|
Trading
|
|
100
|
|
|
Fuel and purchased power cost recovery
|
|
78
|
|
|
Non-fuel riders
|
|
57
|
|
|
Transmission revenue
|
|
48
|
|
|
Conservation and DSM program revenues (offset by expenses)
|
|
44
|
|
|
Retail sales growth, excluding weather impact
|
|
24
|
|
|
Estimated impact of weather
|
|
(60
|
)
|
|
Other, net
|
|
(14
|
)
|
|
Total increase in ongoing electric revenues
|
|
406
|
|
|
SPS FERC complaint case orders
(b)
|
|
26
|
|
|
Total increase in GAAP electric revenues
|
|
$
|
432
|
|
(Millions of Dollars)
|
|
2014 vs. 2013
|
||
Retail rate increases
(a)
|
|
$
|
129
|
|
Non-fuel riders
|
|
57
|
|
|
Conservation and DSM program revenues (offset by expenses)
|
|
44
|
|
|
Transmission revenue, net of costs
|
|
31
|
|
|
Retail sales growth, excluding weather impact
|
|
24
|
|
|
NSP-Wisconsin fuel recovery
|
|
11
|
|
|
Estimated impact of weather
|
|
(60
|
)
|
|
Firm wholesale
|
|
(6
|
)
|
|
Other, net
|
|
(15
|
)
|
|
Total increase in ongoing electric margin
|
|
215
|
|
|
SPS FERC complaint case orders
(b)
|
|
26
|
|
|
Total increase in GAAP electric margin
|
|
$
|
241
|
|
(a)
|
The retail rate increases included final rates in Texas, Colorado (net of estimated earnings test refund obligations), New Mexico, Wisconsin and North Dakota and interim rates in Minnesota, which were subject to and net of estimated provision for refund.
|
(b)
|
As a result of two orders issued by the FERC in August 2013, a pretax charge of approximately $36 million ($32 million in electric revenues, of which $6 million relates to 2013 and $26 million relates to periods prior to 2013, and $4 million in interest charges) was recorded in 2013.
|
(Millions of Dollars)
|
|
2015
|
|
2014
|
|
2013
|
||||||
Natural gas revenues
|
|
$
|
1,672
|
|
|
$
|
2,143
|
|
|
$
|
1,805
|
|
Cost of natural gas sold and transported
|
|
(905
|
)
|
|
(1,372
|
)
|
|
(1,083
|
)
|
|||
Natural gas margin
|
|
$
|
767
|
|
|
$
|
771
|
|
|
$
|
722
|
|
(Millions of Dollars)
|
|
2015 vs. 2014
|
||
Purchased natural gas adjustment clause recovery
|
|
$
|
(462
|
)
|
Estimated impact of weather
|
|
(30
|
)
|
|
Conservation and DSM program revenues (offset by expenses)
|
|
(13
|
)
|
|
Infrastructure and integrity riders, partially offset in O&M expenses
|
|
30
|
|
|
Purchased gas adjustment
|
|
5
|
|
|
Retail rate increases (Colorado, interim, subject to refund)
|
|
4
|
|
|
Other, net
|
|
(5
|
)
|
|
Total decrease in natural gas revenues
|
|
$
|
(471
|
)
|
(Millions of Dollars)
|
|
2015 vs. 2014
|
||
Estimated impact of weather
|
|
$
|
(30
|
)
|
Conservation and DSM program revenues (offset by expenses)
|
|
(13
|
)
|
|
Infrastructure and integrity riders, partially offset in O&M expenses
|
|
30
|
|
|
Purchased gas adjustment
|
|
5
|
|
|
Retail rate increases (Colorado, interim, subject to refund)
|
|
4
|
|
|
Total decrease in natural gas margin
|
|
$
|
(4
|
)
|
(Millions of Dollars)
|
|
2014 vs. 2013
|
||
Purchased natural gas adjustment clause recovery
|
|
$
|
293
|
|
Retail rate increases (Colorado)
|
|
19
|
|
|
PSIA rider (Colorado)
|
|
14
|
|
|
Retail sales growth, excluding weather impact
|
|
10
|
|
|
Estimated impact of weather
|
|
(1
|
)
|
|
Other, net
|
|
3
|
|
|
Total increase in natural gas revenues
|
|
$
|
338
|
|
(Millions of Dollars)
|
|
2014 vs. 2013
|
||
Retail rate increases (Colorado)
|
|
$
|
19
|
|
PSIA rider (Colorado), partially offset in O&M expenses
|
|
14
|
|
|
Retail sales growth, excluding weather impact
|
|
10
|
|
|
Estimated impact of weather
|
|
(1
|
)
|
|
Other, net
|
|
7
|
|
|
Total increase in natural gas margin
|
|
$
|
49
|
|
(Millions of Dollars)
|
|
2015 vs. 2014
|
||
Nuclear plant operations
|
|
$
|
(22
|
)
|
Transmission costs
|
|
(4
|
)
|
|
Labor and contract labor
|
|
14
|
|
|
Plant generation costs
|
|
1
|
|
|
Other, net
|
|
6
|
|
|
Total decrease in O&M expenses
|
|
$
|
(5
|
)
|
•
|
Nuclear expense decreased primarily driven by operational efficiencies and lower amortization of prior outages; and
|
•
|
Labor and contract labor increased as a result of various projects and initiatives to improve business processes.
|
(Millions of Dollars)
|
|
2014 vs. 2013
|
||
Nuclear plant operations and amortization
|
|
$
|
36
|
|
2013 gain on sale of transmission assets
|
|
14
|
|
|
Transmission costs
|
|
4
|
|
|
Electric and natural gas distribution expenses
|
|
1
|
|
|
Employee benefits
|
|
(6
|
)
|
|
Plant generation costs
|
|
(3
|
)
|
|
Other, net
|
|
15
|
|
|
Total increase in O&M expenses
|
|
$
|
61
|
|
•
|
Nuclear cost increases are related to the amortization of prior outages and initiatives designed to improve the operational efficiencies of the plants; and
|
•
|
Gain on sale of transmission assets relates to the 2013 gain associated with the sale of certain SPS’ transmission assets to Sharyland.
|
|
|
Contribution to Xcel Energy’s Earnings
|
||||||||||
(Millions of Dollars)
|
|
2015
|
|
2014
|
|
2013
|
||||||
Xcel Energy Inc. financing costs
|
|
$
|
(56.1
|
)
|
|
$
|
(51.8
|
)
|
|
$
|
(62.9
|
)
|
Eloigne
(a)
|
|
0.1
|
|
|
(0.5
|
)
|
|
(0.8
|
)
|
|||
Xcel Energy Inc. taxes and other results
|
|
(2.7
|
)
|
|
(5.0
|
)
|
|
(7.1
|
)
|
|||
Total Xcel Energy Inc. and other costs
|
|
$
|
(58.7
|
)
|
|
$
|
(57.3
|
)
|
|
$
|
(70.8
|
)
|
|
|
Contribution to Xcel Energy’s EPS
|
||||||||||
(Earnings per Share)
|
|
2015
|
|
2014
|
|
2013
|
||||||
Xcel Energy Inc. financing costs
|
|
$
|
(0.11
|
)
|
|
$
|
(0.10
|
)
|
|
$
|
(0.13
|
)
|
Eloigne
(a)
|
|
—
|
|
|
—
|
|
|
—
|
|
|||
Xcel Energy Inc. taxes and other results
|
|
—
|
|
|
(0.01
|
)
|
|
(0.01
|
)
|
|||
Total Xcel Energy Inc. and other costs
|
|
$
|
(0.11
|
)
|
|
$
|
(0.11
|
)
|
|
$
|
(0.14
|
)
|
(a)
|
Amounts include gains or losses associated with sales of properties held by Eloigne.
|
•
|
$292 million in 2015;
|
•
|
$292 million in 2014; and
|
•
|
$275 million in 2013.
|
•
|
$184 million in 2015;
|
•
|
$373 million in 2014; and
|
•
|
$517 million in 2013.
|
•
|
$125.0 million
in January 2016;
|
•
|
$90.1 million
in 2015;
|
•
|
$130.6 million
in 2014; and
|
•
|
$192.4 million
in 2013.
|
|
|
Pension Costs
|
||||||
(Millions of Dollars)
|
|
+1%
|
|
-1%
|
||||
Rate of return
|
|
$
|
(20.5
|
)
|
|
$
|
20.9
|
|
Discount rate
(a)
|
|
(8.6
|
)
|
|
10.9
|
|
(a)
|
These costs include the effects of regulation.
|
•
|
Xcel Energy contributed
$18.3 million
,
$17.1 million
and
$17.6 million
during
2015
,
2014
and
2013
, respectively, to the postretirement health care plans.
|
•
|
Xcel Energy expects to contribute approximately
$12.3 million
during 2016.
|
•
|
NSP-Minnesota recognizes pension expense in all regulatory jurisdictions as calculated using the aggregate normal cost actuarial method. Differences between aggregate normal cost and expense as calculated by pension accounting standards are deferred as a regulatory liability.
|
•
|
Colorado, Texas, New Mexico and FERC jurisdictions allow the recovery of other postretirement benefit costs only to the extent that recognized expense is matched by cash contributions to an irrevocable trust. Xcel Energy has consistently funded at a level to allow full recovery of costs in these jurisdictions.
|
•
|
PSCo and SPS recognize pension expense in all regulatory jurisdictions based on expense consistent with accounting guidance. The Texas and Colorado electric retail jurisdictions, and commencing in 2016, the Colorado gas retail jurisdiction, each record the difference between annual recognized pension expense and the annual amount of pension expense approved in their last respective general rate case as a deferral to a regulatory asset.
|
•
|
Timing
— Decommissioning cost estimates are impacted by each facility’s retirement date and the expected timing of the actual decommissioning activities. Currently, the estimated retirement dates coincide with each unit’s operating license with the NRC (i.e., 2030 for Monticello and 2033 and 2034 for PI’s Unit 1 and 2, respectively). The estimated timing of the decommissioning activities is based upon the DECON method, which is required by the MPUC. By utilizing this method, which assumes prompt removal and dismantlement, these activities are expected to begin at the end of the license date and be completed for both facilities by 2091.
|
•
|
Technology and Regulation
— There is limited experience with actual decommissioning of large nuclear facilities. Changes in technology and experience as well as changes in regulations regarding nuclear decommissioning could cause cost estimates to change significantly. NSP-Minnesota’s 2014 nuclear decommissioning filing assumed current technology and regulations.
|
•
|
Escalation Rates
— Escalation rates represent projected cost increases over time due to both general inflation and increases in the cost of specific decommissioning activities. NSP-Minnesota used an escalation rate of 4.36 percent in calculating the AROs related to nuclear decommissioning for the remaining operational period through the radiological decommissioning period. An escalation rate of 3.36 percent was utilized for the period of operating costs related to interim dry cask storage of spent nuclear fuel and site restoration.
|
•
|
Discount Rates
— Changes in timing or estimated expected cash flows that result in upward revisions to the ARO are calculated using the then-current credit-adjusted risk-free interest rate. The credit-adjusted risk-free rate in effect when the change occurs is used to discount the revised estimate of the incremental expected cash flows of the retirement activity. If the change in timing or estimated expected cash flows results in a downward revision of the ARO, the undiscounted revised estimate of expected cash flows is discounted using the credit-adjusted risk-free rate in effect at the date of initial measurement and recognition of the original ARO. Discount rates ranging from approximately four and seven percent have been used to calculate the net present value of the expected future cash flows over time.
|
|
|
Futures / Forwards
|
|||||||||||||||||||||
(Thousands of Dollars)
|
|
Source of
Fair Value
|
|
Maturity
Less Than
1 Year
|
|
Maturity
1 to 3 Years
|
|
Maturity
4 to 5 Years
|
|
Maturity
Greater Than
5 Years
|
|
Total Futures /
Forwards
Fair Value
|
|||||||||||
NSP-Minnesota
|
|
1
|
|
|
$
|
2,699
|
|
|
$
|
5,959
|
|
|
$
|
1,575
|
|
|
$
|
—
|
|
|
$
|
10,233
|
|
NSP-Minnesota
|
|
2
|
|
|
695
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
695
|
|
|||||
PSCo
|
|
1
|
|
|
128
|
|
|
(16
|
)
|
|
—
|
|
|
—
|
|
|
112
|
|
|||||
|
|
|
|
$
|
3,522
|
|
|
$
|
5,943
|
|
|
$
|
1,575
|
|
|
$
|
—
|
|
|
$
|
11,040
|
|
(Thousands of Dollars)
|
|
2015
|
|
2014
|
||||
Fair value of commodity trading net contract assets outstanding at Jan. 1
|
|
$
|
21,811
|
|
|
$
|
30,514
|
|
Contracts realized or settled during the period
|
|
(3,578
|
)
|
|
(12,698
|
)
|
||
Commodity trading contract additions and changes during the period
|
|
(7,193
|
)
|
|
3,995
|
|
||
Fair value of commodity trading net contract assets outstanding at Dec. 31
|
|
$
|
11,040
|
|
|
$
|
21,811
|
|
(Millions of Dollars)
|
|
Year Ended
Dec. 31
|
|
VaR Limit
|
|
Average
|
|
High
|
|
Low
|
||||||||||
2015
|
|
$
|
0.10
|
|
|
$
|
3.00
|
|
|
$
|
0.28
|
|
|
$
|
1.34
|
|
|
$
|
0.06
|
|
2014
|
|
0.57
|
|
|
3.00
|
|
|
0.61
|
|
|
4.06
|
|
|
|
0.13
|
|
(Millions of Dollars)
|
|
2015
|
|
2014
|
|
2013
|
||||||
Net cash provided by operating activities
|
|
$
|
3,026
|
|
|
$
|
2,648
|
|
|
$
|
2,584
|
|
(Millions of Dollars)
|
|
2015
|
|
2014
|
|
2013
|
||||||
Net cash used in investing activities
|
|
$
|
(3,623
|
)
|
|
$
|
(3,117
|
)
|
|
$
|
(3,213
|
)
|
(Millions of Dollars)
|
|
2015
|
|
2014
|
|
2013
|
||||||
Net cash provided by financing activities
|
|
$
|
602
|
|
|
$
|
442
|
|
|
$
|
654
|
|
|
|
Actual
|
|
Base Capital Forecast
|
||||||||||||||||||||||||
(Millions of Dollars)
|
|
2015
|
|
2016
|
|
2017
|
|
2018
|
|
2019
|
|
2020
|
|
2016 - 2020 Total
|
||||||||||||||
By Subsidiary
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
NSP-Minnesota
|
|
$
|
1,753
|
|
|
$
|
1,290
|
|
|
$
|
1,050
|
|
|
$
|
1,215
|
|
|
$
|
1,245
|
|
|
$
|
1,125
|
|
|
$
|
5,925
|
|
PSCo
|
|
944
|
|
|
975
|
|
|
940
|
|
|
960
|
|
|
1,030
|
|
|
1,070
|
|
|
4,975
|
|
|||||||
SPS
|
|
602
|
|
|
560
|
|
|
725
|
|
|
640
|
|
|
520
|
|
|
450
|
|
|
2,895
|
|
|||||||
NSP-Wisconsin
|
|
230
|
|
|
225
|
|
|
250
|
|
|
295
|
|
|
265
|
|
|
285
|
|
|
1,320
|
|
|||||||
Other
|
|
—
|
|
|
10
|
|
|
10
|
|
|
10
|
|
|
10
|
|
|
10
|
|
|
50
|
|
|||||||
Total capital expenditures
|
|
$
|
3,529
|
|
|
$
|
3,060
|
|
|
$
|
2,975
|
|
|
$
|
3,120
|
|
|
$
|
3,070
|
|
|
$
|
2,940
|
|
|
$
|
15,165
|
|
|
|
Actual
|
|
Base Capital Forecast
|
||||||||||||||||||||||||
(Millions of Dollars)
|
|
2015
|
|
2016
|
|
2017
|
|
2018
|
|
2019
|
|
2020
|
|
2016 - 2020 Total
|
||||||||||||||
By Function
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||
Electric transmission
|
|
$
|
889
|
|
|
$
|
700
|
|
|
$
|
825
|
|
|
$
|
875
|
|
|
$
|
855
|
|
|
$
|
870
|
|
|
$
|
4,125
|
|
Electric distribution
|
|
639
|
|
|
645
|
|
|
775
|
|
|
790
|
|
|
915
|
|
|
940
|
|
|
4,065
|
|
|||||||
Electric generation
|
|
1,230
|
|
|
835
|
|
|
510
|
|
|
565
|
|
|
470
|
|
|
465
|
|
|
2,845
|
|
|||||||
Natural gas
|
|
368
|
|
|
390
|
|
|
335
|
|
|
395
|
|
|
390
|
|
|
400
|
|
|
1,910
|
|
|||||||
Nuclear fuel
|
|
90
|
|
|
120
|
|
|
120
|
|
|
60
|
|
|
145
|
|
|
85
|
|
|
530
|
|
|||||||
Minnesota Integrated Resource Plan
renewables
|
|
—
|
|
|
—
|
|
|
120
|
|
|
250
|
|
|
110
|
|
|
—
|
|
|
480
|
|
|||||||
Other
|
|
313
|
|
|
370
|
|
|
290
|
|
|
185
|
|
|
185
|
|
|
180
|
|
|
1,210
|
|
|||||||
Total capital expenditures
|
|
$
|
3,529
|
|
|
$
|
3,060
|
|
|
$
|
2,975
|
|
|
$
|
3,120
|
|
|
$
|
3,070
|
|
|
$
|
2,940
|
|
|
$
|
15,165
|
|
*
|
Net of dividend and pension funding.
|
**
|
Reflects a combination of short and long-term debt.
|
|
|
Payments Due by Period
|
||||||||||||||||||
(Thousands of Dollars)
|
|
Total
|
|
Less than 1 Year
|
|
1 to 3 Years
|
|
3 to 5 Years
|
|
After 5 Years
|
||||||||||
Long-term debt, principal and interest payments
(a)
|
$
|
21,797,721
|
|
|
$
|
1,227,067
|
|
|
$
|
2,897,756
|
|
|
$
|
2,547,661
|
|
|
$
|
15,125,237
|
|
|
Capital lease obligations
|
334,461
|
|
|
17,135
|
|
|
29,722
|
|
|
28,842
|
|
|
258,762
|
|
||||||
Operating leases
(b)(c)
|
3,529,682
|
|
|
241,572
|
|
|
462,152
|
|
|
515,767
|
|
|
2,310,191
|
|
||||||
Unconditional purchase obligations
(d)
|
8,523,291
|
|
|
1,801,881
|
|
|
2,088,242
|
|
|
1,220,206
|
|
|
3,412,962
|
|
||||||
Other long-term obligations, including current portion
(e)
|
322,687
|
|
|
93,698
|
|
|
153,719
|
|
|
75,270
|
|
|
—
|
|
||||||
Payments to vendors in process
|
32,547
|
|
|
32,547
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Short-term debt
|
846,000
|
|
|
846,000
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Total contractual cash obligations
(f)(g)(h)
|
$
|
35,386,389
|
|
|
$
|
4,259,900
|
|
|
$
|
5,631,591
|
|
|
$
|
4,387,746
|
|
|
$
|
21,107,152
|
|
(a)
|
Includes interest payments over the terms of the debt. Interest is calculated using the applicable interest rate at Dec. 31,
2015
, and outstanding principal for each investment with the terms ending at each instrument’s maturity.
|
(b)
|
Under some leases, Xcel Energy would have to sell or purchase the property that it leases if it chose to terminate before the scheduled lease expiration date. Most of Xcel Energy’s railcar, vehicle and equipment and aircraft leases have these terms. At Dec. 31,
2015
, the amount that Xcel Energy would have to pay if it chose to terminate these leases was approximately $61.0 million. In addition, at the end of the equipment lease terms, each lease must be extended, equipment purchased for the greater of the fair value or unamortized value of equipment sold to a third party with Xcel Energy making up any deficiency between the sales price and the unamortized value.
|
(c)
|
Included in operating lease payments are
$217.0 million
,
$418.7 million
,
$469.1 million
and
$2.1 billion
, for the less than 1 year, 1-3 years, 3-5 years and after 5 years categories, respectively, pertaining to PPAs that were accounted for as operating leases.
|
(d)
|
Xcel Energy Inc. and its subsidiaries have contracts providing for the purchase and delivery of a significant portion of its current coal, nuclear fuel and natural gas requirements. Additionally, the utility subsidiaries of Xcel Energy Inc. have entered into agreements with utilities and other energy suppliers for purchased power to meet system load and energy requirements, replace generation from company-owned units under maintenance and during outages, and meet operating reserve obligations. Certain contractual purchase obligations are adjusted on indices. The effects of price changes are mitigated through cost of energy adjustment mechanisms.
|
(e)
|
Other long-term obligations relate primarily to amounts associated with technology agreements and approximate investments in Energy Impact Fund LP, as well as uncertain tax positions.
|
(f)
|
Xcel Energy also has outstanding authority under O&M contracts to purchase up to approximately $3.2 billion of goods and services through the year 2053, in addition to the amounts disclosed in this table.
|
(g)
|
In January
2016
, contributions of
$125.0 million
were made across four of Xcel Energy’s pension plans. Obligations of this type are dependent on several factors, including management discretion, and therefore, they are not included in the table.
|
(h)
|
Xcel Energy expects to contribute approximately
$12.3 million
to the postretirement health care plans during
2016
. Obligations of this type are dependent on several factors, including management discretion, and therefore, they are not included in the table.
|
•
|
Projected cash generation;
|
•
|
Projected capital investment;
|
•
|
A reasonable rate of return on shareholder investment; and
|
•
|
The impact on Xcel Energy’s capital structure and credit ratings.
|
(Millions of Dollars)
|
|
Dec. 31, 2015
|
|
Dec. 31, 2014
|
||||
Fair value of pension assets
|
|
$
|
2,884
|
|
|
$
|
3,084
|
|
Projected pension obligation
(a)
|
|
3,568
|
|
|
3,747
|
|
||
Funded status
|
|
$
|
(684
|
)
|
|
$
|
(663
|
)
|
(a)
|
Excludes nonqualified plan of
$42 million
and
$47 million
at Dec. 31,
2015
and
2014
, respectively.
|
Pension Assumptions
|
|
2015
|
|
2014
|
||
Discount rate
|
|
4.66
|
%
|
|
4.11
|
%
|
Expected long-term rate of return
|
|
6.87
|
|
|
7.09
|
|
•
|
$1 billion
for Xcel Energy Inc.;
|
•
|
$700 million
for PSCo;
|
•
|
$500 million
for NSP-Minnesota;
|
•
|
$400 million
for SPS; and
|
•
|
$150 million
for NSP-Wisconsin.
|
(Amounts in Millions, Except Interest Rates)
|
|
Three Months Ended Dec. 31, 2015
|
||
Borrowing limit
|
|
$
|
2,750
|
|
Amount outstanding at period end
|
|
846
|
|
|
Average amount outstanding
|
|
290
|
|
|
Maximum amount outstanding
|
|
846
|
|
|
Weighted average interest rate, computed on a daily basis
|
|
0.56
|
%
|
|
Weighted average interest rate at end of period
|
|
0.82
|
|
(Amounts in Millions, Except Interest Rates)
|
|
Year Ended Dec. 31, 2015
|
|
Year Ended Dec. 31, 2014
|
|
Year Ended Dec. 31, 2013
|
||||||
Borrowing limit
|
|
$
|
2,750
|
|
|
$
|
2,750
|
|
|
$
|
2,450
|
|
Amount outstanding at period end
|
|
846
|
|
|
1,020
|
|
|
759
|
|
|||
Average amount outstanding
|
|
601
|
|
|
841
|
|
|
481
|
|
|||
Maximum amount outstanding
|
|
1,360
|
|
|
1,200
|
|
|
1,160
|
|
|||
Weighted average interest rate, computed on a daily basis
|
|
0.48
|
%
|
|
0.33
|
%
|
|
0.31
|
%
|
|||
Weighted average interest rate at end of period
|
|
0.82
|
|
|
0.56
|
|
|
0.25
|
|
(Millions of Dollars)
|
|
Facility
(a)
|
|
Drawn
(b)
|
|
Available
|
|
Cash
|
|
Liquidity
|
||||||||||
Xcel Energy Inc.
|
|
$
|
1,000
|
|
|
$
|
616
|
|
|
$
|
384
|
|
|
$
|
—
|
|
|
$
|
384
|
|
PSCo
|
|
700
|
|
|
4
|
|
|
696
|
|
|
1
|
|
|
697
|
|
|||||
NSP-Minnesota
|
|
500
|
|
|
250
|
|
|
250
|
|
|
1
|
|
|
251
|
|
|||||
SPS
|
|
400
|
|
|
65
|
|
|
335
|
|
|
1
|
|
|
336
|
|
|||||
NSP-Wisconsin
|
|
150
|
|
|
—
|
|
|
150
|
|
|
3
|
|
|
153
|
|
|||||
Total
|
|
$
|
2,750
|
|
|
$
|
935
|
|
|
$
|
1,815
|
|
|
$
|
6
|
|
|
$
|
1,821
|
|
(a)
|
These credit facilities mature in October 2019.
|
(b)
|
Includes outstanding commercial paper and letters of credit.
|
•
|
Xcel Energy Inc. plans to issue approximately $700 million of senior unsecured bonds;
|
•
|
NSP-Minnesota plans to issue approximately $250 million of first mortgage bonds; and
|
•
|
SPS plans to issue approximately $350 million of first mortgage bonds.
|
•
|
PSCo issued $250 million of 2.9 percent first mortgage bonds due May 15, 2025;
|
•
|
Xcel Energy Inc. issued $250 million of 1.2 percent senior notes due June 1, 2017 and $250 million of 3.3 percent senior notes due June 1, 2025;
|
•
|
NSP-Wisconsin issued $100 million of 3.3 percent first mortgage bonds due June 15, 2024;
|
•
|
NSP-Minnesota issued $300 million of 2.2 percent first mortgage bonds due Aug. 15, 2020 and $300 million of 4.0 percent first mortgage bonds due Aug. 15, 2045; and
|
•
|
SPS issued $200 million of 3.3 percent first mortgage bonds due June 15, 2024.
|
•
|
Constructive outcomes in all rate case and regulatory proceedings.
|
•
|
Normal weather patterns are experienced for the year.
|
•
|
Weather-normalized retail electric utility sales are projected to increase approximately 0.5 percent to 1.0 percent.
|
•
|
Weather normalized retail firm natural gas sales are projected to be relatively flat.
|
•
|
Capital rider revenue is projected to increase by $70 million to $80 million over 2015 levels.
|
•
|
The change in O&M expenses is projected to be within a range of 0 percent to 2 percent from 2015 levels.
|
•
|
Depreciation expense is projected to increase approximately $200 million over 2015 levels.
|
•
|
Property taxes are projected to increase approximately $40 million to $50 million over 2015 levels.
|
•
|
Interest expense (net of AFUDC — debt) is projected to increase $40 million to $50 million over 2015 levels.
|
•
|
AFUDC — equity is projected to decline approximately $10 million to $15 million from 2015 levels.
|
•
|
The ETR is projected to be approximately 34 percent to 36 percent.
|
•
|
Average common stock and equivalents are projected to be approximately 509 million shares.
|
•
|
Deliver long-term annual EPS growth of 4 percent to 6 percent, based on ongoing 2015 EPS of $2.10, which was the mid-point of Xcel Energy’s 2015 ongoing guidance range;
|
•
|
Deliver annual dividend increases of 5 percent to 7 percent;
|
•
|
Target a dividend payout ratio of 60 percent to 70 percent; and
|
•
|
Maintain senior unsecured debt credit ratings in the BBB+ to A range.
|
/s/ BEN FOWKE
|
|
/s/ TERESA S. MADDEN
|
Ben Fowke
|
|
Teresa S. Madden
|
Chairman, President and Chief Executive Officer
|
|
Executive Vice President, Chief Financial Officer
|
Feb. 19, 2016
|
|
Feb. 19, 2016
|
XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CAPITALIZATION
(amounts in thousands, except share and per share data)
|
||||||||
|
|
Dec. 31
|
||||||
|
|
2015
|
|
2014
|
||||
Long-Term Debt
|
|
|
|
|
||||
NSP-Minnesota
|
|
|
|
|
||||
First Mortgage Bonds, Series due:
|
|
|
|
|
||||
Aug. 15, 2015, 1.95%
|
|
$
|
—
|
|
|
$
|
250,000
|
|
March 1, 2018, 5.25%
|
|
500,000
|
|
|
500,000
|
|
||
Aug. 15, 2020, 2.2%
|
|
300,000
|
|
|
—
|
|
||
Aug. 15, 2022, 2.15%
|
|
300,000
|
|
|
300,000
|
|
||
May 15, 2023, 2.6%
|
|
400,000
|
|
|
400,000
|
|
||
July 1, 2025, 7.125%
|
|
250,000
|
|
|
250,000
|
|
||
March 1, 2028, 6.5%
|
|
150,000
|
|
|
150,000
|
|
||
July 15, 2035, 5.25%
|
|
250,000
|
|
|
250,000
|
|
||
June 1, 2036, 6.25%
|
|
400,000
|
|
|
400,000
|
|
||
July 1, 2037, 6.2%
|
|
350,000
|
|
|
350,000
|
|
||
Nov. 1, 2039, 5.35%
|
|
300,000
|
|
|
300,000
|
|
||
Aug. 15, 2040, 4.85%
|
|
250,000
|
|
|
250,000
|
|
||
Aug. 15, 2042, 3.4%
|
|
500,000
|
|
|
500,000
|
|
||
May 15, 2044, 4.125%
|
|
300,000
|
|
|
300,000
|
|
||
Aug. 15, 2045, 4.0%
|
|
300,000
|
|
|
—
|
|
||
Other
|
|
33
|
|
|
47
|
|
||
Unamortized discount
|
|
(15,911
|
)
|
|
(11,365
|
)
|
||
Total
|
|
4,534,122
|
|
|
4,188,682
|
|
||
Less current maturities
|
|
11
|
|
|
250,013
|
|
||
Total NSP-Minnesota long-term debt
|
|
$
|
4,534,111
|
|
|
$
|
3,938,669
|
|
|
|
|
|
|
||||
PSCo
|
|
|
|
|
|
|
||
First Mortgage Bonds, Series due:
|
|
|
|
|
|
|
||
Sept. 1, 2017, 4.375%
(a)
|
|
$
|
129,500
|
|
|
$
|
129,500
|
|
Aug. 1, 2018, 5.8%
|
|
300,000
|
|
|
300,000
|
|
||
June 1, 2019, 5.125%
|
|
400,000
|
|
|
400,000
|
|
||
Nov. 15, 2020, 3.2%
|
|
400,000
|
|
|
400,000
|
|
||
Sept. 15, 2022, 2.25%
|
|
300,000
|
|
|
300,000
|
|
||
March 15, 2023, 2.5%
|
|
250,000
|
|
|
250,000
|
|
||
May 15, 2025, 2.9%
|
|
250,000
|
|
|
—
|
|
||
Sept. 1, 2037, 6.25%
|
|
350,000
|
|
|
350,000
|
|
||
Aug. 1, 2038, 6.5%
|
|
300,000
|
|
|
300,000
|
|
||
Aug. 15, 2041, 4.75%
|
|
250,000
|
|
|
250,000
|
|
||
Sept. 15, 2042, 3.6%
|
|
500,000
|
|
|
500,000
|
|
||
March 15, 2043, 3.95%
|
|
250,000
|
|
|
250,000
|
|
||
March 15, 2044, 4.30%
|
|
300,000
|
|
|
300,000
|
|
||
Capital lease obligations, through 2060, 11.2% — 14.3%
|
|
164,031
|
|
|
172,209
|
|
||
Unamortized discount
|
|
(11,340
|
)
|
|
(11,480
|
)
|
||
Total
|
|
4,132,191
|
|
|
3,890,229
|
|
||
Less current maturities
|
|
8,103
|
|
|
8,178
|
|
||
Total PSCo long-term debt
|
|
$
|
4,124,088
|
|
|
$
|
3,882,051
|
|
|
|
|
|
|
||||
SPS
|
|
|
|
|
|
|
||
First Mortgage Bonds, Series due:
|
|
|
|
|
||||
June 15, 2024, 3.3%
|
|
$
|
350,000
|
|
|
$
|
150,000
|
|
Aug. 15, 2041, 4.5%
|
|
400,000
|
|
|
400,000
|
|
||
Unsecured Senior E Notes, due Oct. 1, 2016, 5.6%
|
|
200,000
|
|
|
200,000
|
|
||
Unsecured Senior G Notes, due Dec. 1, 2018, 8.75%
|
|
250,000
|
|
|
250,000
|
|
||
Unsecured Senior C and D Notes, due Oct. 1, 2033, 6%
|
|
100,000
|
|
|
100,000
|
|
||
Unsecured Senior F Notes, due Oct. 1, 2036, 6%
|
|
250,000
|
|
|
250,000
|
|
||
Unamortized premium (discount)
|
|
605
|
|
|
(309
|
)
|
||
Total
|
|
1,550,605
|
|
|
1,349,691
|
|
||
Less current maturities
|
|
200,000
|
|
|
—
|
|
||
Total SPS long-term debt
|
|
$
|
1,350,605
|
|
|
$
|
1,349,691
|
|
|
|
|
|
|
XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CAPITALIZATION
—
(Continued)
(amounts in thousands, except share and per share data)
|
||||||||
|
|
Dec. 31
|
||||||
|
|
2015
|
|
2014
|
||||
NSP-Wisconsin
|
|
|
|
|
||||
First Mortgage Bonds, Series due:
|
|
|
|
|
||||
Oct. 1, 2018, 5.25%
|
|
$
|
150,000
|
|
|
$
|
150,000
|
|
June 15, 2024, 3.3%
|
|
200,000
|
|
|
100,000
|
|
||
Sept. 1, 2038, 6.375%
|
|
200,000
|
|
|
200,000
|
|
||
Oct. 1, 2042, 3.7%
|
|
100,000
|
|
|
100,000
|
|
||
City of La Crosse Resource Recovery Bond, Series due Nov. 1, 2021, 6%
(b)
|
|
18,600
|
|
|
18,600
|
|
||
Fort McCoy System Acquisition, due Oct. 15, 2030, 7%
|
|
490
|
|
|
523
|
|
||
Other
|
|
1,634
|
|
|
1,687
|
|
||
Unamortized discount
|
|
(3,131
|
)
|
|
(2,519
|
)
|
||
Total
|
|
667,593
|
|
|
568,291
|
|
||
Less current maturities
|
|
1,131
|
|
|
1,235
|
|
||
Total NSP-Wisconsin long-term debt
|
|
$
|
666,462
|
|
|
$
|
567,056
|
|
|
|
|
|
|
||||
Other Subsidiaries
|
|
|
|
|
||||
Various Eloigne Co. Affordable Housing Project Notes, due 2016-2052, 0% — 8%
|
|
$
|
31,255
|
|
|
$
|
32,037
|
|
Total
|
|
31,255
|
|
|
32,037
|
|
||
Less current maturities
|
|
709
|
|
|
1,316
|
|
||
Total other subsidiaries long-term debt
|
|
$
|
30,546
|
|
|
$
|
30,721
|
|
|
|
|
|
|
||||
Xcel Energy Inc.
|
|
|
|
|
||||
Unsecured Senior Notes, Series due:
|
|
|
|
|
||||
May 9, 2016, 0.75%
|
|
$
|
450,000
|
|
|
$
|
450,000
|
|
April 1, 2017, 5.613%
|
|
253,979
|
|
|
253,979
|
|
||
June 1, 2017, 1.2%
|
|
250,000
|
|
|
—
|
|
||
May 15, 2020, 4.7%
|
|
550,000
|
|
|
550,000
|
|
||
June 1, 2025, 3.3%
|
|
250,000
|
|
|
—
|
|
||
July 1, 2036, 6.5%
|
|
300,000
|
|
|
300,000
|
|
||
Sept. 15, 2041, 4.8%
|
|
250,000
|
|
|
250,000
|
|
||
Elimination of PSCo capital lease obligation with affiliates
|
|
(66,454
|
)
|
|
(69,470
|
)
|
||
Unamortized discount
|
|
(5,551
|
)
|
|
(6,078
|
)
|
||
Total
|
|
2,231,974
|
|
|
1,728,431
|
|
||
Less current maturities (including elimination of PSCo capital lease obligation)
|
|
447,067
|
|
|
(3,015
|
)
|
||
Total Xcel Energy Inc. long-term debt
|
|
$
|
1,784,907
|
|
|
$
|
1,731,446
|
|
Total long-term debt
|
|
$
|
12,490,719
|
|
|
$
|
11,499,634
|
|
|
|
|
|
|
||||
Common Stockholders’ Equity
|
|
|
|
|
||||
Common stock — 1,000,000,000 shares authorized of $2.50 par value; 507,535,523 and
505,733,267 shares outstanding at Dec. 31, 2015 and Dec. 31, 2014, respectively
|
|
$
|
1,268,839
|
|
|
$
|
1,264,333
|
|
Additional paid in capital
|
|
5,889,106
|
|
|
5,837,330
|
|
||
Retained earnings
|
|
3,552,728
|
|
|
3,220,958
|
|
||
Accumulated other comprehensive loss
|
|
(109,753
|
)
|
|
(108,139
|
)
|
||
Total common stockholders’ equity
|
|
$
|
10,600,920
|
|
|
$
|
10,214,482
|
|
(a)
|
Pollution control financing.
|
(b)
|
Resource recovery financing.
|
1.
|
Summary of Significant Accounting Policies
|
•
|
Certain costs, which would otherwise be charged to expense or OCI, are deferred as regulatory assets based on the expected ability to recover the costs in future rates; and
|
•
|
Certain credits, which would otherwise be reflected as income or OCI, are deferred as regulatory liabilities based on the expectation the amounts will be returned to customers in future rates, or because the amounts were collected in rates prior to the costs being incurred.
|
3.
|
Selected Balance Sheet Data
|
(Thousands of Dollars)
|
|
Dec. 31, 2015
|
|
Dec. 31, 2014
|
||||
Accounts receivable, net
|
|
|
|
|
||||
Accounts receivable
|
|
$
|
776,494
|
|
|
$
|
884,225
|
|
Less allowance for bad debts
|
|
(51,888
|
)
|
|
(57,719
|
)
|
||
|
|
$
|
724,606
|
|
|
$
|
826,506
|
|
(Thousands of Dollars)
|
|
Dec. 31, 2015
|
|
Dec. 31, 2014
|
||||
Inventories
|
|
|
|
|
||||
Materials and supplies
|
|
$
|
290,690
|
|
|
$
|
244,099
|
|
Fuel
|
|
202,271
|
|
|
183,249
|
|
||
Natural gas
|
|
115,623
|
|
|
169,835
|
|
||
|
|
$
|
608,584
|
|
|
$
|
597,183
|
|
(Thousands of Dollars)
|
|
Dec. 31, 2015
|
|
Dec. 31, 2014
|
||||
Property, plant and equipment, net
|
|
|
|
|
||||
Electric plant
|
|
$
|
36,464,050
|
|
|
$
|
33,203,139
|
|
Natural gas plant
|
|
4,944,757
|
|
|
4,643,452
|
|
||
Common and other property
|
|
1,709,508
|
|
|
1,611,486
|
|
||
Plant to be retired
(a)
|
|
38,249
|
|
|
71,534
|
|
||
CWIP
|
|
1,256,949
|
|
|
2,005,531
|
|
||
Total property, plant and equipment
|
|
44,413,513
|
|
|
41,535,142
|
|
||
Less accumulated depreciation
|
|
(13,591,259
|
)
|
|
(13,168,418
|
)
|
||
Nuclear fuel
|
|
2,447,251
|
|
|
2,347,422
|
|
||
Less accumulated amortization
|
|
(2,063,654
|
)
|
|
(1,957,230
|
)
|
||
|
|
$
|
31,205,851
|
|
|
$
|
28,756,916
|
|
(a)
|
PSCo’s Cherokee Unit 3 was retired in August 2015. In 2017, PSCo expects to both early retire Valmont Unit 5 and convert Cherokee Unit 4 from a coal-fueled generating facility to natural gas, as approved by the CPUC. Amounts are presented net of accumulated depreciation.
|
4.
|
Borrowings and Other Financing Instruments
|
(Amounts in Millions, Except Interest Rates)
|
|
Three Months Ended Dec. 31, 2015
|
||
Borrowing limit
|
|
$
|
2,750
|
|
Amount outstanding at period end
|
|
846
|
|
|
Average amount outstanding
|
|
290
|
|
|
Maximum amount outstanding
|
|
846
|
|
|
Weighted average interest rate, computed on a daily basis
|
|
0.56
|
%
|
|
Weighted average interest rate at period end
|
|
0.82
|
|
|
|
Year Ended Dec. 31
|
||||||||||
(Amounts in Millions, Except Interest Rates)
|
|
2015
|
|
2014
|
|
2013
|
||||||
Borrowing limit
|
|
$
|
2,750
|
|
|
$
|
2,750
|
|
|
$
|
2,450
|
|
Amount outstanding at period end
|
|
846
|
|
|
1,020
|
|
|
759
|
|
|||
Average amount outstanding
|
|
601
|
|
|
841
|
|
|
481
|
|
|||
Maximum amount outstanding
|
|
1,360
|
|
|
1,200
|
|
|
1,160
|
|
|||
Weighted average interest rate, computed on a daily basis
|
|
0.48
|
%
|
|
0.33
|
%
|
|
0.31
|
%
|
|||
Weighted average interest rate at end of period
|
|
0.82
|
|
|
0.56
|
|
|
0.25
|
|
•
|
Xcel Energy Inc. may increase its credit facility by up to
$200 million
, NSP-Minnesota and PSCo may each increase their credit facilities by
$100 million
and SPS may increase its credit facility by
$50 million
. The NSP-Wisconsin credit facility cannot be increased.
|
•
|
Each credit facility has a financial covenant requiring that the debt-to-total capitalization ratio of each entity be less than or equal to
65 percent
. Each entity was in compliance at Dec. 31,
2015
and
2014
, respectively, as evidenced by the table below:
|
•
|
If Xcel Energy Inc. or any of its utility subsidiaries do not comply with the covenant, an event of default may be declared, and if not remedied, any outstanding amounts due under the facility can be declared due by the lender.
|
•
|
The Xcel Energy Inc. credit facility has a cross-default provision that provides Xcel Energy Inc. will be in default on its borrowings under the facility if it or any of its subsidiaries, except NSP-Wisconsin as long as its total assets do not comprise more than
15 percent
of Xcel Energy’s consolidated total assets, default on certain indebtedness in an aggregate principal amount exceeding
$75 million
.
|
•
|
Xcel Energy Inc. and its subsidiaries were in compliance with all financial covenants in their debt agreements as of Dec. 31, 2015 and 2014.
|
•
|
The interest rates under these lines of credit are based on Eurodollar borrowing margins ranging from 87.5 to 175 basis points per year based on the applicable long-term credit ratings.
|
•
|
The commitment fees, also based on applicable long-term credit ratings, are calculated on the unused portion of the lines of credit at a range of 7.5 to 27.5 basis points per year.
|
(Millions of Dollars)
|
|
Credit Facility
(a)
|
|
Drawn
(b)
|
|
Available
|
||||||
Xcel Energy Inc.
|
|
$
|
1,000
|
|
|
$
|
584
|
|
|
$
|
416
|
|
PSCo
|
|
700
|
|
|
18
|
|
|
682
|
|
|||
NSP-Minnesota
|
|
500
|
|
|
241
|
|
|
259
|
|
|||
SPS
|
|
400
|
|
|
22
|
|
|
378
|
|
|||
NSP-Wisconsin
|
|
150
|
|
|
10
|
|
|
140
|
|
|||
Total
|
|
$
|
2,750
|
|
|
$
|
875
|
|
|
$
|
1,875
|
|
(a)
|
These credit facilities mature in October 2019.
|
(b)
|
Includes outstanding commercial paper and letters of credit.
|
•
|
PSCo issued
$250 million
of
2.9 percent
first mortgage bonds due
May 15, 2025
;
|
•
|
Xcel Energy Inc. issued
$250 million
of
1.2 percent
senior notes due
June 1, 2017
and
$250 million
of
3.3 percent
senior notes due
June 1, 2025
;
|
•
|
NSP-Wisconsin issued
$100 million
of
3.3 percent
first mortgage bonds due
June 15, 2024
;
|
•
|
NSP-Minnesota issued
$300 million
of
2.2 percent
first mortgage bonds due
Aug. 15, 2020
and
$300 million
of
4.0 percent
first mortgage bonds due
Aug. 15, 2045
; and
|
•
|
SPS issued
$200 million
of
3.3 percent
first mortgage bonds due
June 15, 2024
.
|
•
|
PSCo issued
$300 million
of
4.3 percent
first mortgage bonds due
March 15, 2044
;
|
•
|
NSP-Minnesota issued
$300 million
of
4.125 percent
first mortgage bonds due
May 15, 2044
;
|
•
|
SPS issued
$150 million
of
3.3 percent
first mortgage bonds due
June 15, 2024
; and
|
•
|
NSP-Wisconsin issued
$100 million
of
3.3 percent
first mortgage bonds due
June 15, 2024
.
|
•
|
PSCo has authorization to issue up to an additional
$450 million
of long-term debt and up to
$800 million
of short-term debt.
|
•
|
SPS has authorization to issue up to
$100 million
of long-term debt and
$500 million
of short-term debt.
|
•
|
NSP-Wisconsin has authorization to issue up to
$150 million
of short-term debt and NSPW will file for additional long-term debt authorization.
|
•
|
NSP-Minnesota has authorization to issue long-term securities provided the equity-to-total capitalization ratio remains between
46.9 percent
and
57.3 percent
and to issue short-term debt provided it does not exceed
15 percent
of total capitalization. Total capitalization for NSP-Minnesota cannot exceed
$10.5 billion
.
|
5.
|
Joint Ownership of Generation, Transmission and Gas Facilities
|
(Thousands of Dollars)
|
|
Plant in
Service
|
|
Accumulated
Depreciation
|
|
CWIP
|
|
Ownership %
|
|||||||
NSP-Minnesota
|
|
|
|
|
|
|
|
|
|||||||
Electric Generation:
|
|
|
|
|
|
|
|
|
|||||||
Sherco Unit 3
|
|
$
|
590,048
|
|
|
$
|
386,675
|
|
|
$
|
4,984
|
|
|
59
|
%
|
Sherco Common Facilities Units 1, 2 and 3
|
|
145,825
|
|
|
93,583
|
|
|
47
|
|
|
80
|
|
|||
Sherco Substation
|
|
4,790
|
|
|
3,054
|
|
|
—
|
|
|
59
|
|
|||
Electric Transmission:
|
|
|
|
|
|
|
|
|
|||||||
Grand Meadow Line and Substation
|
|
9,248
|
|
|
1,451
|
|
|
—
|
|
|
50
|
|
|||
CapX2020 Transmission
|
|
947,674
|
|
|
107,985
|
|
|
68,834
|
|
|
51
|
|
|||
Total NSP-Minnesota
|
|
$
|
1,697,585
|
|
|
$
|
592,748
|
|
|
$
|
73,865
|
|
|
|
(Thousands of Dollars)
|
|
Plant in
Service
|
|
Accumulated
Depreciation
|
|
CWIP
|
|
Ownership %
|
|||||||
NSP-Wisconsin
|
|
|
|
|
|
|
|
|
|||||||
Electric Transmission:
|
|
|
|
|
|
|
|
|
|||||||
CapX2020 Transmission
|
|
$
|
154,394
|
|
|
$
|
6,863
|
|
|
$
|
1,633
|
|
|
80
|
%
|
La Crosse, Wis. to Madison, Wis.
|
|
—
|
|
|
—
|
|
|
18,894
|
|
|
37
|
|
|||
Total NSP-Wisconsin
|
|
$
|
154,394
|
|
|
$
|
6,863
|
|
|
$
|
20,527
|
|
|
|
(Thousands of Dollars)
|
|
Plant in
Service
|
|
Accumulated
Depreciation
|
|
CWIP
|
|
Ownership %
|
|||||||
PSCo
|
|
|
|
|
|
|
|
|
|||||||
Electric Generation:
|
|
|
|
|
|
|
|
|
|||||||
Hayden Unit 1
|
|
$
|
155,159
|
|
|
$
|
69,679
|
|
|
$
|
147
|
|
|
76
|
%
|
Hayden Unit 2
|
|
121,486
|
|
|
61,780
|
|
|
20,840
|
|
|
37
|
|
|||
Hayden Common Facilities
|
|
37,756
|
|
|
17,910
|
|
|
321
|
|
|
53
|
|
|||
Craig Units 1 and 2
|
|
60,158
|
|
|
36,570
|
|
|
8,518
|
|
|
10
|
|
|||
Craig Common Facilities 1, 2 and 3
|
|
37,418
|
|
|
18,520
|
|
|
505
|
|
|
7
|
|
|||
Comanche Unit 3
|
|
892,340
|
|
|
95,029
|
|
|
452
|
|
|
67
|
|
|||
Comanche Common Facilities
|
|
23,826
|
|
|
1,430
|
|
|
894
|
|
|
82
|
|
|||
Electric Transmission:
|
|
|
|
|
|
|
|
|
|||||||
Transmission and other facilities, including substations
|
|
152,460
|
|
|
62,324
|
|
|
5,378
|
|
|
Various
|
|
|||
Gas Transportation:
|
|
|
|
|
|
|
|
|
|||||||
Rifle, Colo. to Avon, Colo.
|
|
19,928
|
|
|
7,165
|
|
|
—
|
|
|
60
|
|
|||
Gas Transportation Compressor
|
|
8,353
|
|
|
124
|
|
|
127
|
|
|
50
|
|
|||
Total PSCo
|
|
$
|
1,508,884
|
|
|
$
|
370,531
|
|
|
$
|
37,182
|
|
|
|
6.
|
Income Taxes
|
•
|
Immediate expensing, or “bonus depreciation,” of
50 percent
for property placed in service in 2015, 2016, and 2017;
40 percent
for property placed in service in 2018; and
30 percent
for property placed in service in 2019. Additionally, some longer production period property placed in service in 2020 will be eligible for bonus depreciation;
|
•
|
PTCs at
100 percent
of the credit rate (
$0.023
per KWh) for wind energy projects that begin construction by the end of 2016;
80 percent
of the credit rate for projects that begin construction in 2017;
60 percent
of the credit rate for projects that begin construction in 2018; and
40 percent
of the credit rate for projects that begin construction in 2019. The wind energy PTC was not extended for projects that begin construction after 2019;
|
•
|
ITCs at
30 percent
for commercial solar projects that begin construction by the end of 2019;
26 percent
for projects that begin construction in 2020;
22 percent
for projects that begin construction in 2021; and
10 percent
for projects thereafter;
|
•
|
R&E credit was permanently extended; and
|
•
|
Delay of
two
years (until 2020) of the excise tax on certain employer-provided health insurance plans.
|
•
|
Recognition of additional tax deductions for bonus depreciation of
$1.2 billion
, and as a result, recognition of
$4.9 million
benefit related to a carryback claim (see additional discussion below) and
$3.5 million
expense related to valuation allowances and expirations of charitable contribution carryforwards; and
|
•
|
Recognition of
$6.8 million
benefit for federal R&E credits.
|
•
|
The R&E credit was extended for 2014;
|
•
|
PTCs were extended for projects that began construction before the end of 2014 with certain projects qualifying into future years; and
|
•
|
50 percent
bonus depreciation was extended
one
year through 2014. Additionally, some longer production period property placed in service in 2015 is also eligible for
50 percent
bonus depreciation.
|
•
|
The top tax rate for dividends increased from
15 percent
to
20 percent
. The
20 percent
dividend rate is now consistent with the tax rates for capital gains;
|
•
|
The R&E credit was extended for 2012 and 2013;
|
•
|
PTCs were extended for projects that began construction before the end of 2013 with certain projects qualifying into future years; and
|
•
|
50 percent
bonus depreciation was extended
one
year through 2013. Additionally, some longer production period property placed in service in 2014 is also eligible for
50 percent
bonus depreciation.
|
State
|
|
Year
|
Colorado
|
|
2009
|
Minnesota
|
|
2009
|
Texas
|
|
2009
|
Wisconsin
|
|
2011
|
(Millions of Dollars)
|
|
Dec. 31, 2015
|
|
Dec. 31, 2014
|
||||
Unrecognized tax benefit — Permanent tax positions
|
|
$
|
25.8
|
|
|
$
|
16.2
|
|
Unrecognized tax benefit — Temporary tax positions
|
|
94.9
|
|
|
50.3
|
|
||
Total unrecognized tax benefit
|
|
$
|
120.7
|
|
|
$
|
66.5
|
|
(Millions of Dollars)
|
|
2015
|
|
2014
|
|
2013
|
||||||
Balance at Jan. 1
|
|
$
|
66.5
|
|
|
$
|
41.2
|
|
|
$
|
34.5
|
|
Additions based on tax positions related to the current year
|
|
27.1
|
|
|
28.7
|
|
|
15.1
|
|
|||
Reductions based on tax positions related to the current year
|
|
(4.5
|
)
|
|
(2.0
|
)
|
|
(0.4
|
)
|
|||
Additions for tax positions of prior years
|
|
34.8
|
|
|
16.0
|
|
|
21.6
|
|
|||
Reductions for tax positions of prior years
|
|
(2.9
|
)
|
|
(6.0
|
)
|
|
(4.8
|
)
|
|||
Settlements with taxing authorities
|
|
(0.3
|
)
|
|
(9.6
|
)
|
|
(24.8
|
)
|
|||
Lapse of applicable statutes of limitations
|
|
—
|
|
|
(1.8
|
)
|
|
—
|
|
|||
Balance at Dec. 31
|
|
$
|
120.7
|
|
|
$
|
66.5
|
|
|
$
|
41.2
|
|
(Millions of Dollars)
|
|
Dec. 31, 2015
|
|
Dec. 31, 2014
|
||||
NOL and tax credit carryforwards
|
|
$
|
(36.7
|
)
|
|
$
|
(28.5
|
)
|
(Millions of Dollars)
|
|
2015
|
|
2014
|
||||
Federal NOL carryforward
|
|
$
|
2,153
|
|
|
$
|
1,349
|
|
Federal tax credit carryforwards
|
|
360
|
|
|
327
|
|
||
State NOL carryforwards
|
|
2,124
|
|
|
1,722
|
|
||
Valuation allowances for state NOL carryforwards
|
|
(65
|
)
|
|
(53
|
)
|
||
State tax credit carryforwards, net of federal detriment
(a)
|
|
45
|
|
|
19
|
|
||
Valuation allowances for state credit carryforwards, net of federal benefit
(b)
|
|
(24
|
)
|
|
—
|
|
(a)
|
State tax credit carryforwards are net of federal detriment of
$24 million
and
$10 million
as of Dec. 31, 2015 and 2014, respectively.
|
(b)
|
Valuation allowances for state tax credit carryforwards were net of federal benefit of
$13 million
as of Dec. 31, 2015.
|
(Thousands of Dollars)
|
|
2015
|
|
2014
|
|
2013
|
||||||
Current federal tax (benefit)
|
|
$
|
(36,129
|
)
|
|
$
|
(73,160
|
)
|
|
$
|
(46,173
|
)
|
Current state tax expense
|
|
2,324
|
|
|
9,225
|
|
|
7,678
|
|
|||
Current change in unrecognized tax expense
|
|
45,933
|
|
|
23,915
|
|
|
13,162
|
|
|||
Deferred federal tax expense
|
|
480,078
|
|
|
505,236
|
|
|
439,085
|
|
|||
Deferred state tax expense
|
|
92,132
|
|
|
84,787
|
|
|
80,907
|
|
|||
Deferred change in unrecognized tax (benefit)
|
|
(36,342
|
)
|
|
(20,645
|
)
|
|
(4,930
|
)
|
|||
Deferred investment tax credits
|
|
(5,277
|
)
|
|
(5,543
|
)
|
|
(5,753
|
)
|
|||
Total income tax expense
|
|
$
|
542,719
|
|
|
$
|
523,815
|
|
|
$
|
483,976
|
|
(Thousands of Dollars)
|
|
2015
|
|
2014
|
|
2013
|
||||||
Deferred tax expense excluding items below
|
|
$
|
546,664
|
|
|
$
|
616,934
|
|
|
$
|
588,053
|
|
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities
|
|
(11,810
|
)
|
|
(48,674
|
)
|
|
(64,420
|
)
|
|||
Tax benefit (expense) allocated to OCI
|
|
1,013
|
|
|
1,117
|
|
|
(8,572
|
)
|
|||
Other
|
|
1
|
|
|
1
|
|
|
1
|
|
|||
Deferred tax expense
|
|
$
|
535,868
|
|
|
$
|
569,378
|
|
|
$
|
515,062
|
|
(Thousands of Dollars)
|
|
2015
|
|
2014
|
||||
Deferred tax liabilities:
|
|
|
|
|
|
|
||
Differences between book and tax bases of property
|
|
$
|
7,119,023
|
|
|
$
|
6,257,191
|
|
Regulatory assets
|
|
313,414
|
|
|
300,762
|
|
||
Other
|
|
243,690
|
|
|
300,251
|
|
||
Total deferred tax liabilities
|
|
$
|
7,676,127
|
|
|
$
|
6,858,204
|
|
|
|
|
|
|
||||
Deferred tax assets:
|
|
|
|
|
|
|
||
NOL carryforward
|
|
$
|
851,242
|
|
|
$
|
552,274
|
|
Tax credit carryforward
|
|
404,738
|
|
|
346,064
|
|
||
Unbilled revenue - fuel costs
|
|
57,220
|
|
|
55,021
|
|
||
Rate refund
|
|
50,441
|
|
|
93,956
|
|
||
Regulatory liabilities
|
|
41,541
|
|
|
49,712
|
|
||
Environmental remediation
|
|
38,663
|
|
|
42,716
|
|
||
Deferred investment tax credits
|
|
29,650
|
|
|
31,886
|
|
||
NOL and tax credit valuation allowances
|
|
(27,679
|
)
|
|
(3,402
|
)
|
||
Other
|
|
76,869
|
|
|
83,199
|
|
||
Total deferred tax assets
|
|
$
|
1,522,685
|
|
|
$
|
1,251,426
|
|
Net deferred tax liability
|
|
$
|
6,153,442
|
|
|
$
|
5,606,778
|
|
7.
|
Earnings Per Share
|
•
|
Equity awards subject to a performance condition; included in common shares outstanding when all necessary conditions for settlement have been satisfied by the end of the reporting period.
|
•
|
Liability awards subject to a performance condition; any portions settled in shares are included in common shares outstanding upon settlement.
|
|
|
2015
|
|
2014
|
|
2013
|
|||||||||||||||||||||||||||
(Amounts in thousands, except per share data)
|
|
Income
|
|
Shares
|
|
Per
Share
Amount
|
|
Income
|
|
Shares
|
|
Per
Share
Amount
|
|
Income
|
|
Shares
|
|
Per
Share
Amount
|
|||||||||||||||
Net income
|
|
$
|
984,485
|
|
|
|
|
|
|
$
|
1,021,306
|
|
|
|
|
|
|
$
|
948,234
|
|
|
|
|
|
|||||||||
Basic EPS:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||
Earnings available to common shareholders
|
|
984,485
|
|
|
507,768
|
|
|
$
|
1.94
|
|
|
1,021,306
|
|
|
503,847
|
|
|
$
|
2.03
|
|
|
948,234
|
|
|
496,073
|
|
|
$
|
1.91
|
|
|||
Effect of dilutive securities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||
Equity awards
|
|
—
|
|
|
400
|
|
|
|
|
—
|
|
|
270
|
|
|
|
|
—
|
|
|
459
|
|
|
|
|||||||||
Diluted EPS:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||
Earnings available to common shareholders
|
|
$
|
984,485
|
|
|
508,168
|
|
|
$
|
1.94
|
|
|
$
|
1,021,306
|
|
|
504,117
|
|
|
$
|
2.03
|
|
|
$
|
948,234
|
|
|
496,532
|
|
|
$
|
1.91
|
|
8.
|
Share-Based Compensation
|
(Shares in Thousands)
|
|
2015
|
|
2014
|
|
2013
|
||||||
Granted shares
|
|
42
|
|
|
46
|
|
|
33
|
|
|||
Grant date fair value
|
|
$
|
35.00
|
|
|
$
|
29.69
|
|
|
$
|
28.30
|
|
(Shares in Thousands)
|
|
Shares
|
|
Weighted Average
Grant Date Fair Value |
|||
Nonvested restricted stock at Jan. 1, 2015
|
|
82
|
|
|
$
|
29.00
|
|
Granted
|
|
42
|
|
|
35.00
|
|
|
Forfeited
|
|
(9
|
)
|
|
28.24
|
|
|
Vested
|
|
(35
|
)
|
|
28.30
|
|
|
Dividend equivalents
|
|
3
|
|
|
35.19
|
|
|
Nonvested restricted stock at Dec. 31, 2015
|
|
83
|
|
|
32.62
|
|
•
|
The 2010 environmental awards met their targets as of Dec. 31, 2012 and were settled in shares in February 2013.
|
•
|
The 2011 awards measured on EPS growth and the 2011 environmental awards met their targets as of Dec. 31, 2013 and were settled in shares in February 2014.
|
•
|
The 2012 awards measured on EPS growth and the 2012 environmental awards met their targets as of Dec. 31, 2014, and were settled in shares in February 2015.
|
•
|
The 2013 awards measured on EPS growth, the 2013 environmental awards and the 2013 time-based awards met their targets as of Dec. 31, 2015, and will be settled in shares in February 2016.
|
(Units in Thousands)
|
|
2015
|
|
2014
|
|
2013
|
||||||
Granted units
|
|
496
|
|
|
588
|
|
|
774
|
|
|||
Weighted average grant date fair value
|
|
$
|
36.09
|
|
|
$
|
29.90
|
|
|
$
|
27.65
|
|
(Units in Thousands)
|
|
Units
|
|
Weighted Average
Grant Date Fair Value |
|||
Nonvested Units at Jan. 1, 2015
|
|
1,322
|
|
|
$
|
28.63
|
|
Granted
|
|
496
|
|
|
36.09
|
|
|
Forfeited
|
|
(99
|
)
|
|
30.97
|
|
|
Vested
|
|
(756
|
)
|
|
27.67
|
|
|
Dividend equivalents
|
|
62
|
|
|
30.25
|
|
|
Nonvested Units at Dec. 31, 2015
|
|
1,025
|
|
|
32.81
|
|
(Units in Thousands)
|
|
2015
|
|
2014
|
|
2013
|
||||||
Granted units
|
|
60
|
|
|
62
|
|
|
69
|
|
|||
Grant date fair value
|
|
$
|
34.58
|
|
|
$
|
30.57
|
|
|
$
|
29.52
|
|
(Units in Thousands)
|
|
Units
|
|
Weighted Average
Grant Date Fair Value |
|||
Stock equivalent units at Jan. 1, 2015
|
|
690
|
|
|
$
|
24.03
|
|
Granted
|
|
60
|
|
|
34.58
|
|
|
Units distributed
|
|
(29
|
)
|
|
20.71
|
|
|
Dividend equivalents
|
|
25
|
|
|
35.26
|
|
|
Stock equivalent units at Dec. 31, 2015
|
|
746
|
|
|
25.38
|
|
(In Thousands)
|
|
2015
|
|
2014
|
|
2013
|
|||
Awards granted
|
|
224
|
|
|
270
|
|
|
215
|
|
(In Thousands)
|
|
2015
|
|
2014
|
|
2013
|
||||||
Awards settled
|
|
—
|
|
|
—
|
|
|
108
|
|
|||
Settlement amount (cash and common stock)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
3,057
|
|
(Thousands of Dollars)
|
|
2015
|
|
2014
|
|
2013
|
||||||
Compensation cost for share-based awards
(a) (b)
|
|
$
|
44,928
|
|
|
$
|
32,189
|
|
|
$
|
24,613
|
|
Tax benefit recognized in income
|
|
17,570
|
|
|
12,557
|
|
|
9,571
|
|
|||
Capitalized compensation cost for share-based awards
(c)
|
|
—
|
|
|
1,887
|
|
|
1,698
|
|
(a)
|
Compensation costs for share-based payment arrangements are included in O&M expense in the consolidated statements of income.
|
(b)
|
Included in compensation cost for share-based awards are matching contributions related to the Xcel Energy 401(k) plan, which totaled $
7.4 million
, and $
7.0 million
for the years ended 2014 and 2013, respectively. In October 2013, Xcel Energy determined that it would settle the 401(k) employer match in cash instead of common stock going forward for all employee groups except PSCo bargaining employees. Share-based compensation accounting for the impacted employee groups ceased in October 2013, and corresponding expense amounts recorded to equity were reclassified to a liability for expected cash settlements. In August 2015, consistent with a new PSCo bargaining agreement, share-based compensation accounting ceased for the employer 401(k) match for PSCo bargaining employees, which will be paid in cash. As a result, 2015 compensation cost for share-based awards includes no 401(k) matching contributions.
|
(c)
|
An allocated amount of the 401(k) match is capitalized.
|
•
|
NSP-Minnesota had
1,983
and NSP-Wisconsin had
400
bargaining employees covered under a collective-bargaining agreement, which expires at the end of 2016. NSP-Minnesota also had an additional
265
nuclear operation bargaining employees covered under several collective-bargaining agreements. Some of these agreements expired in 2015, but were extended to 2016. The remaining agreements expire in 2016 and 2018.
|
•
|
PSCo had
2,024
bargaining employees covered under a collective-bargaining agreement, which expires in May 2017.
|
•
|
SPS had
842
bargaining employees covered under a collective-bargaining agreement, which expired in October 2014. While collective bargaining is ongoing, the terms and conditions of the expired agreement are automatically extended until the parties reach an agreement or a decision is rendered by an arbitrator.
|
•
|
Investment returns in 2015 were below the assumed level of
7.09 percent
;
|
•
|
Investment returns in 2014 were above the assumed level of
7.05 percent
;
|
•
|
Investment returns in 2013 were below the assumed level of
6.88 percent
; and
|
•
|
In
2016
, Xcel Energy’s expected investment return assumption is
6.87 percent
.
|
|
|
2015
|
|
2014
|
||
Domestic and international equity securities
|
|
39
|
%
|
|
37
|
%
|
Long-duration fixed income and interest rate swap securities
|
|
27
|
|
|
27
|
|
Short-to-intermediate fixed income securities
|
|
13
|
|
|
13
|
|
Alternative investments
|
|
19
|
|
|
21
|
|
Cash
|
|
2
|
|
|
2
|
|
Total
|
|
100
|
%
|
|
100
|
%
|
|
|
Dec. 31, 2015
|
||||||||||||||
(Thousands of Dollars)
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
||||||||
Cash equivalents
|
|
$
|
178,884
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
178,884
|
|
Derivatives
|
|
—
|
|
|
2,850
|
|
|
—
|
|
|
2,850
|
|
||||
Government securities
|
|
—
|
|
|
412,932
|
|
|
—
|
|
|
412,932
|
|
||||
Corporate bonds
|
|
—
|
|
|
248,439
|
|
|
—
|
|
|
248,439
|
|
||||
Asset-backed securities
|
|
—
|
|
|
2,446
|
|
|
—
|
|
|
2,446
|
|
||||
Common stock
|
|
93,831
|
|
|
—
|
|
|
—
|
|
|
93,831
|
|
||||
Private equity investments
|
|
—
|
|
|
—
|
|
|
126,396
|
|
|
126,396
|
|
||||
Commingled funds
|
|
—
|
|
|
1,759,066
|
|
|
—
|
|
|
1,759,066
|
|
||||
Real estate
|
|
—
|
|
|
—
|
|
|
55,935
|
|
|
55,935
|
|
||||
Other
|
|
—
|
|
|
3,001
|
|
|
—
|
|
|
3,001
|
|
||||
Total
|
|
$
|
272,715
|
|
|
$
|
2,428,734
|
|
|
$
|
182,331
|
|
|
$
|
2,883,780
|
|
|
|
Dec. 31, 2014
|
||||||||||||||
(Thousands of Dollars)
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
||||||||
Cash equivalents
|
|
$
|
193,141
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
193,141
|
|
Derivatives
|
|
—
|
|
|
1,590
|
|
|
—
|
|
|
1,590
|
|
||||
Government securities
|
|
—
|
|
|
439,186
|
|
|
—
|
|
|
439,186
|
|
||||
Corporate bonds
|
|
—
|
|
|
318,161
|
|
|
—
|
|
|
318,161
|
|
||||
Asset-backed securities
|
|
—
|
|
|
3,759
|
|
|
—
|
|
|
3,759
|
|
||||
Mortgage-backed securities
|
|
—
|
|
|
11,047
|
|
|
—
|
|
|
11,047
|
|
||||
Common stock
|
|
102,667
|
|
|
—
|
|
|
—
|
|
|
102,667
|
|
||||
Private equity investments
|
|
—
|
|
|
—
|
|
|
151,871
|
|
|
151,871
|
|
||||
Commingled funds
|
|
—
|
|
|
1,826,420
|
|
|
—
|
|
|
1,826,420
|
|
||||
Real estate
|
|
—
|
|
|
—
|
|
|
54,657
|
|
|
54,657
|
|
||||
Securities lending collateral obligation and other
|
|
—
|
|
|
(18,728
|
)
|
|
—
|
|
|
(18,728
|
)
|
||||
Total
|
|
$
|
295,808
|
|
|
$
|
2,581,435
|
|
|
$
|
206,528
|
|
|
$
|
3,083,771
|
|
(Thousands of Dollars)
|
|
Jan. 1, 2015
|
|
Net Realized
Gains (Losses) |
|
Net Unrealized
Gains (Losses) |
|
Purchases,
Issuances and Settlements, Net |
|
Transfers Out of Level 3
|
|
Dec. 31, 2015
|
||||||||||||
Private equity investments
|
|
$
|
151,871
|
|
|
$
|
28,094
|
|
|
$
|
(40,848
|
)
|
|
$
|
(12,721
|
)
|
|
$
|
—
|
|
|
$
|
126,396
|
|
Real estate
|
|
54,657
|
|
|
7,083
|
|
|
(8,443
|
)
|
|
2,638
|
|
|
—
|
|
|
55,935
|
|
||||||
Total
|
|
$
|
206,528
|
|
|
$
|
35,177
|
|
|
$
|
(49,291
|
)
|
|
$
|
(10,083
|
)
|
|
$
|
—
|
|
|
$
|
182,331
|
|
(Thousands of Dollars)
|
|
Jan. 1, 2014
|
|
Net Realized
Gains (Losses) |
|
Net Unrealized
Gains (Losses) |
|
Purchases,
Issuances and Settlements, Net |
|
Transfers Out of Level 3
|
|
Dec. 31, 2014
|
||||||||||||
Private equity investments
|
|
$
|
152,849
|
|
|
$
|
25,694
|
|
|
$
|
(17,573
|
)
|
|
$
|
(9,099
|
)
|
|
$
|
—
|
|
|
$
|
151,871
|
|
Real estate
|
|
47,553
|
|
|
3,569
|
|
|
(2,443
|
)
|
|
5,978
|
|
|
—
|
|
|
54,657
|
|
||||||
Total
|
|
$
|
200,402
|
|
|
$
|
29,263
|
|
|
$
|
(20,016
|
)
|
|
$
|
(3,121
|
)
|
|
$
|
—
|
|
|
$
|
206,528
|
|
(Thousands of Dollars)
|
|
Jan. 1, 2013
|
|
Net Realized
Gains (Losses) |
|
Net Unrealized
Gains (Losses) |
|
Purchases,
Issuances and Settlements, Net |
|
Transfers Out of Level 3
(a)
|
|
Dec. 31, 2013
|
||||||||||||
Asset-backed securities
|
|
$
|
14,639
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(14,639
|
)
|
|
$
|
—
|
|
Mortgage-backed securities
|
|
39,904
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(39,904
|
)
|
|
—
|
|
||||||
Private equity investments
|
|
158,498
|
|
|
22,058
|
|
|
(24,335
|
)
|
|
(3,372
|
)
|
|
—
|
|
|
152,849
|
|
||||||
Real estate
|
|
64,597
|
|
|
(2,659
|
)
|
|
8,690
|
|
|
9,317
|
|
|
(32,392
|
)
|
|
47,553
|
|
||||||
Total
|
|
$
|
277,638
|
|
|
$
|
19,399
|
|
|
$
|
(15,645
|
)
|
|
$
|
5,945
|
|
|
$
|
(86,935
|
)
|
|
$
|
200,402
|
|
(a)
|
Transfers out of Level 3 into Level 2 were principally due to diminished use of unobservable inputs that were previously significant to these fair value measurements and were subsequently sold during 2013.
|
(Thousands of Dollars)
|
|
2015
|
|
2014
|
||||
Accumulated Benefit Obligation at Dec. 31
|
|
$
|
3,368,239
|
|
|
$
|
3,545,928
|
|
|
|
|
|
|
||||
Change in Projected Benefit Obligation:
|
|
|
|
|
|
|
||
Obligation at Jan. 1
|
|
$
|
3,746,752
|
|
|
$
|
3,440,704
|
|
Service cost
|
|
99,311
|
|
|
88,342
|
|
||
Interest cost
|
|
148,524
|
|
|
156,619
|
|
||
Actuarial (gain) loss
|
|
(169,678
|
)
|
|
342,826
|
|
||
Benefit payments
|
|
(256,982
|
)
|
|
(281,739
|
)
|
||
Obligation at Dec. 31
|
|
$
|
3,567,927
|
|
|
$
|
3,746,752
|
|
(Thousands of Dollars)
|
|
2015
|
|
2014
|
||||
Change in Fair Value of Plan Assets:
|
|
|
|
|
||||
Fair value of plan assets at Jan. 1
|
|
$
|
3,083,771
|
|
|
$
|
3,010,140
|
|
Actual (loss) return on plan assets
|
|
(33,102
|
)
|
|
224,808
|
|
||
Employer contributions
|
|
90,093
|
|
|
130,562
|
|
||
Benefit payments
|
|
(256,982
|
)
|
|
(281,739
|
)
|
||
Fair value of plan assets at Dec. 31
|
|
$
|
2,883,780
|
|
|
$
|
3,083,771
|
|
(Thousands of Dollars)
|
|
2015
|
|
2014
|
||||
Funded Status of Plans at Dec. 31:
|
|
|
|
|
||||
Funded status
(a)
|
|
$
|
(684,147
|
)
|
|
$
|
(662,981
|
)
|
(a)
|
Amounts are recognized in noncurrent liabilities on Xcel Energy’s consolidated balance sheets.
|
(Thousands of Dollars)
|
|
2015
|
|
2014
|
||||
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:
|
|
|
|
|
||||
Net loss
|
|
$
|
1,710,097
|
|
|
$
|
1,757,935
|
|
Prior service credit
|
|
(9,073
|
)
|
|
(10,878
|
)
|
||
Total
|
|
$
|
1,701,024
|
|
|
$
|
1,747,057
|
|
(Thousands of Dollars)
|
|
2015
|
|
2014
|
||||
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery in Rates:
|
|
|
|
|
||||
Current regulatory assets
|
|
$
|
105,426
|
|
|
$
|
113,432
|
|
Noncurrent regulatory assets
|
|
1,520,975
|
|
|
1,558,649
|
|
||
Deferred income taxes
|
|
29,002
|
|
|
29,143
|
|
||
Net-of-tax accumulated OCI
|
|
45,621
|
|
|
45,833
|
|
||
Total
|
|
$
|
1,701,024
|
|
|
$
|
1,747,057
|
|
Measurement date
|
|
Dec. 31, 2015
|
|
Dec. 31, 2014
|
|
|
2015
|
|
2014
|
||
Significant Assumptions Used to Measure Benefit Obligations:
|
|
|
|
|
||
Discount rate for year-end valuation
|
|
4.66
|
%
|
|
4.11
|
%
|
Expected average long-term increase in compensation level
|
|
4.00
|
|
|
3.75
|
|
Mortality table
|
|
RP 2014
|
|
|
RP 2014
|
|
•
|
$125.0 million
in January 2016;
|
•
|
$90.1 million
in 2015;
|
•
|
$130.6 million
in 2014; and
|
•
|
$192.4 million
in 2013.
|
(Thousands of Dollars)
|
|
2015
|
|
2014
|
|
2013
|
||||||
Service cost
|
|
$
|
99,311
|
|
|
$
|
88,342
|
|
|
$
|
96,282
|
|
Interest cost
|
|
148,524
|
|
|
156,619
|
|
|
140,690
|
|
|||
Expected return on plan assets
|
|
(213,890
|
)
|
|
(207,205
|
)
|
|
(198,452
|
)
|
|||
Amortization of prior service (credit) cost
|
|
(1,805
|
)
|
|
(1,746
|
)
|
|
5,871
|
|
|||
Amortization of net loss
|
|
125,152
|
|
|
116,762
|
|
|
144,151
|
|
|||
Net periodic pension cost
|
|
157,292
|
|
|
152,772
|
|
|
188,542
|
|
|||
Costs not recognized due to effects of regulation
|
|
(29,633
|
)
|
|
(26,315
|
)
|
|
(36,724
|
)
|
|||
Net benefit cost recognized for financial reporting
|
|
$
|
127,659
|
|
|
$
|
126,457
|
|
|
$
|
151,818
|
|
|
|
2015
|
|
2014
|
|
2013
|
|||
Significant Assumptions Used to Measure Costs:
|
|
|
|
|
|
|
|||
Discount rate
|
|
4.11
|
%
|
|
4.75
|
%
|
|
4.00
|
%
|
Expected average long-term increase in compensation level
|
|
3.75
|
|
|
3.75
|
|
|
3.75
|
|
Expected average long-term rate of return on assets
|
|
7.09
|
|
|
7.05
|
|
|
6.88
|
|
•
|
NSP-Minnesota and NSP-Wisconsin discontinued contributing toward health care benefits for nonbargaining employees retiring after 1998 and for bargaining employees who retired after 1999.
|
•
|
Xcel Energy discontinued contributing toward health care benefits for PSCo and SPS, nonbargaining employees retiring after June 30, 2003.
|
•
|
Employees of NCE who retired in 2002 continue to receive employer-subsidized health care benefits.
|
•
|
Nonbargaining employees of the former NCE who retired after 1998, bargaining employees of the former NCE who retired after 1999 and nonbargaining employees of NCE who retired after June 30, 2003, are eligible to participate in the Xcel Energy health care program with no employer subsidy.
|
|
|
2015
|
|
2014
|
||
Domestic and international equity securities
|
|
25
|
%
|
|
25
|
%
|
Short-to-intermediate fixed income securities
|
|
57
|
|
|
57
|
|
Alternative investments
|
|
13
|
|
|
13
|
|
Cash
|
|
5
|
|
|
5
|
|
Total
|
|
100
|
%
|
|
100
|
%
|
|
|
Dec. 31, 2015
|
||||||||||||||
(Thousands of Dollars)
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
||||||||
Cash equivalents
|
|
$
|
19,638
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
19,638
|
|
Government securities
|
|
—
|
|
|
39,241
|
|
|
—
|
|
|
39,241
|
|
||||
Insurance contracts
|
|
—
|
|
|
47,205
|
|
|
—
|
|
|
47,205
|
|
||||
Corporate bonds
|
|
—
|
|
|
72,876
|
|
|
—
|
|
|
72,876
|
|
||||
Asset-backed securities
|
|
—
|
|
|
28,691
|
|
|
—
|
|
|
28,691
|
|
||||
Mortgage-backed securities
|
|
—
|
|
|
35,612
|
|
|
—
|
|
|
35,612
|
|
||||
Commingled funds
|
|
—
|
|
|
204,782
|
|
|
—
|
|
|
204,782
|
|
||||
Other
|
|
—
|
|
|
(412
|
)
|
|
—
|
|
|
(412
|
)
|
||||
Total
|
|
$
|
19,638
|
|
|
$
|
427,995
|
|
|
$
|
—
|
|
|
$
|
447,633
|
|
|
|
Dec. 31, 2014
|
||||||||||||||
(Thousands of Dollars)
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
||||||||
Cash equivalents
(a)
|
|
$
|
26,324
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
26,324
|
|
Derivatives
|
|
—
|
|
|
186
|
|
|
—
|
|
|
186
|
|
||||
Government securities
|
|
—
|
|
|
48,584
|
|
|
—
|
|
|
48,584
|
|
||||
Insurance contracts
|
|
—
|
|
|
50,351
|
|
|
—
|
|
|
50,351
|
|
||||
Corporate bonds
|
|
—
|
|
|
54,207
|
|
|
—
|
|
|
54,207
|
|
||||
Asset-backed securities
|
|
—
|
|
|
3,619
|
|
|
—
|
|
|
3,619
|
|
||||
Mortgage-backed securities
|
|
—
|
|
|
11,250
|
|
|
—
|
|
|
11,250
|
|
||||
Commingled funds
|
|
—
|
|
|
282,378
|
|
|
—
|
|
|
282,378
|
|
||||
Other
|
|
—
|
|
|
(1,841
|
)
|
|
—
|
|
|
(1,841
|
)
|
||||
Total
|
|
$
|
26,324
|
|
|
$
|
448,734
|
|
|
$
|
—
|
|
|
$
|
475,058
|
|
(a)
|
Includes restricted cash of
$1.0 million
at Dec. 31, 2014.
|
(Thousands of Dollars)
|
|
Jan. 1, 2013
|
|
Net Realized
Gains (Losses) |
|
Net Unrealized
Gains (Losses) |
|
Purchases,
Issuances and Settlements, Net |
|
Transfers Out of Level 3
(a)
|
|
Dec. 31, 2013
|
||||||||||||
Private equity investments
|
|
$
|
757
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(757
|
)
|
|
$
|
—
|
|
Real estate
|
|
39,958
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(39,958
|
)
|
|
—
|
|
||||||
Total
|
|
$
|
40,715
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(40,715
|
)
|
|
$
|
—
|
|
(a)
|
Transfers out of Level 3 into Level 2 were principally due to diminished use of unobservable inputs that were previously significant to these fair value measurements and were subsequently sold during 2013.
|
(Thousands of Dollars)
|
|
2015
|
|
2014
|
||||
Change in Fair Value of Plan Assets:
|
|
|
|
|
||||
Fair value of plan assets at Jan. 1
|
|
$
|
475,058
|
|
|
$
|
492,036
|
|
Actual (loss) return on plan assets
|
|
(3,570
|
)
|
|
12,083
|
|
||
Plan participants’ contributions
|
|
6,718
|
|
|
7,148
|
|
||
Employer contributions
|
|
18,325
|
|
|
17,145
|
|
||
Benefit payments
|
|
(48,898
|
)
|
|
(53,354
|
)
|
||
Fair value of plan assets at Dec. 31
|
|
$
|
447,633
|
|
|
$
|
475,058
|
|
(Thousands of Dollars)
|
|
2015
|
|
2014
|
||||
Funded Status of Plans at Dec. 31:
|
|
|
|
|
||||
Funded status
|
|
$
|
(136,634
|
)
|
|
$
|
(167,811
|
)
|
Noncurrent assets
|
|
1,820
|
|
|
1,014
|
|
||
Current liabilities
|
|
(7,495
|
)
|
|
(9,110
|
)
|
||
Noncurrent liabilities
|
|
(130,959
|
)
|
|
(159,715
|
)
|
||
Net postretirement amounts recognized on consolidated balance sheets
|
|
$
|
(136,634
|
)
|
|
$
|
(167,811
|
)
|
(Thousands of Dollars)
|
|
2015
|
|
2014
|
||||
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:
|
|
|
|
|
||||
Net loss
|
|
$
|
103,039
|
|
|
$
|
124,064
|
|
Prior service credit
|
|
(64,925
|
)
|
|
(75,610
|
)
|
||
Total
|
|
$
|
38,114
|
|
|
$
|
48,454
|
|
(Thousands of Dollars)
|
|
2015
|
|
2014
|
||||
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost Have Been Recorded as Follows Based Upon Expected Recovery in Rates:
|
|
|
|
|
||||
Current regulatory assets
|
|
$
|
352
|
|
|
$
|
285
|
|
Noncurrent regulatory assets
|
|
50,135
|
|
|
59,697
|
|
||
Current regulatory liabilities
|
|
(985
|
)
|
|
(892
|
)
|
||
Noncurrent regulatory liabilities
|
|
(16,916
|
)
|
|
(17,216
|
)
|
||
Deferred income taxes
|
|
2,148
|
|
|
2,559
|
|
||
Net-of-tax accumulated OCI
|
|
3,380
|
|
|
4,021
|
|
||
Total
|
|
$
|
38,114
|
|
|
$
|
48,454
|
|
Measurement date
|
|
Dec. 31, 2015
|
|
Dec. 31, 2014
|
|
|
2015
|
|
2014
|
||
Significant Assumptions Used to Measure Benefit Obligations:
|
|
|
|
|
||
Discount rate for year-end valuation
|
|
4.65
|
%
|
|
4.08
|
%
|
Mortality table
|
|
RP 2014
|
|
|
RP 2014
|
|
Health care costs trend rate — initial
|
|
6.00
|
%
|
|
6.50
|
%
|
|
|
One-Percentage Point
|
||||||
(Thousands of Dollars)
|
|
Increase
|
|
Decrease
|
||||
APBO
|
|
$
|
56,383
|
|
|
$
|
(47,972
|
)
|
Service and interest components
|
|
3,113
|
|
|
(2,594
|
)
|
(Thousands of Dollars)
|
|
2015
|
|
2014
|
|
2013
|
||||||
Service cost
|
|
$
|
2,116
|
|
|
$
|
3,457
|
|
|
$
|
4,079
|
|
Interest cost
|
|
25,297
|
|
|
34,028
|
|
|
32,141
|
|
|||
Expected return on plan assets
|
|
(26,600
|
)
|
|
(33,954
|
)
|
|
(33,011
|
)
|
|||
Amortization of transition obligation
|
|
—
|
|
|
—
|
|
|
825
|
|
|||
Amortization of prior service credit
|
|
(10,686
|
)
|
|
(10,688
|
)
|
|
(12,501
|
)
|
|||
Amortization of net loss
|
|
5,404
|
|
|
11,740
|
|
|
22,325
|
|
|||
Net periodic postretirement benefit cost
|
|
$
|
(4,469
|
)
|
|
$
|
4,583
|
|
|
$
|
13,858
|
|
|
|
2015
|
|
2014
|
|
2013
|
|||
Significant Assumptions Used to Measure Costs:
|
|
|
|
|
|
|
|||
Discount rate
|
|
4.08
|
%
|
|
4.82
|
%
|
|
4.10
|
%
|
Expected average long-term rate of return on assets
|
|
5.80
|
|
|
7.17
|
|
|
7.11
|
|
(Thousands of Dollars)
|
|
Projected
Pension Benefit Payments |
|
Gross Projected
Postretirement Health Care Benefit Payments |
|
Expected
Medicare Part D Subsidies |
|
Net Projected
Postretirement Health Care Benefit Payments |
||||||||
2016
|
|
$
|
260,240
|
|
|
$
|
48,047
|
|
|
$
|
2,355
|
|
|
$
|
45,692
|
|
2017
|
|
255,206
|
|
|
47,460
|
|
|
2,493
|
|
|
44,967
|
|
||||
2018
|
|
263,689
|
|
|
47,039
|
|
|
2,637
|
|
|
44,402
|
|
||||
2019
|
|
268,975
|
|
|
46,522
|
|
|
2,761
|
|
|
43,761
|
|
||||
2020
|
|
271,853
|
|
|
46,819
|
|
|
2,869
|
|
|
43,950
|
|
||||
2021-2025
|
|
1,353,351
|
|
|
220,122
|
|
|
16,053
|
|
|
204,069
|
|
(Thousands of Dollars)
|
|
2015
|
|
2014
|
|
2013
|
||||||
Multiemployer pension contributions:
|
|
|
|
|
|
|
||||||
NSP-Minnesota
|
|
$
|
17,223
|
|
|
$
|
20,254
|
|
|
$
|
23,515
|
|
NSP-Wisconsin
|
|
944
|
|
|
156
|
|
|
130
|
|
|||
Total
|
|
$
|
18,167
|
|
|
$
|
20,410
|
|
|
$
|
23,645
|
|
Multiemployer other postretirement benefit contributions:
|
|
|
|
|
|
|
||||||
NSP-Minnesota
|
|
$
|
135
|
|
|
$
|
273
|
|
|
$
|
390
|
|
Total
|
|
$
|
135
|
|
|
$
|
273
|
|
|
$
|
390
|
|
10.
|
Other Income, Net
|
(Thousands of Dollars)
|
|
2015
|
|
2014
|
|
2013
|
||||||
Interest income
|
|
$
|
5,737
|
|
|
$
|
7,353
|
|
|
$
|
8,343
|
|
Other nonoperating income
|
|
3,514
|
|
|
4,866
|
|
|
3,025
|
|
|||
Insurance policy expense
|
|
(3,851
|
)
|
|
(6,923
|
)
|
|
(8,292
|
)
|
|||
Other nonoperating expense
|
|
—
|
|
|
—
|
|
|
(104
|
)
|
|||
Other income, net
|
|
$
|
5,400
|
|
|
$
|
5,296
|
|
|
$
|
2,972
|
|
|
|
Dec. 31, 2015
|
||||||||||||||||||
|
|
|
|
Fair Value
|
||||||||||||||||
(Thousands of Dollars)
|
|
Cost
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
||||||||||
Nuclear decommissioning fund
(a)
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Cash equivalents
|
|
$
|
27,484
|
|
|
$
|
27,484
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
27,484
|
|
Commingled funds
|
|
392,838
|
|
|
—
|
|
|
410,634
|
|
|
—
|
|
|
410,634
|
|
|||||
International equity funds
|
|
259,114
|
|
|
—
|
|
|
231,122
|
|
|
—
|
|
|
231,122
|
|
|||||
Private equity investments
|
|
105,965
|
|
|
—
|
|
|
—
|
|
|
157,528
|
|
|
157,528
|
|
|||||
Real estate
|
|
61,816
|
|
|
—
|
|
|
—
|
|
|
84,750
|
|
|
84,750
|
|
|||||
Debt securities:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Government securities
|
|
24,444
|
|
|
—
|
|
|
21,356
|
|
|
—
|
|
|
21,356
|
|
|||||
U.S. corporate bonds
|
|
73,061
|
|
|
—
|
|
|
65,276
|
|
|
—
|
|
|
65,276
|
|
|||||
International corporate bonds
|
|
13,726
|
|
|
—
|
|
|
12,801
|
|
|
—
|
|
|
12,801
|
|
|||||
Municipal bonds
|
|
49,255
|
|
|
—
|
|
|
51,589
|
|
|
—
|
|
|
51,589
|
|
|||||
Asset-backed securities
|
|
2,837
|
|
|
—
|
|
|
2,830
|
|
|
—
|
|
|
2,830
|
|
|||||
Mortgage-backed securities
|
|
11,444
|
|
|
—
|
|
|
11,621
|
|
|
—
|
|
|
11,621
|
|
|||||
Equity securities:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Common stock
|
|
473,615
|
|
|
647,159
|
|
|
—
|
|
|
—
|
|
|
647,159
|
|
|||||
Total
|
|
$
|
1,495,599
|
|
|
$
|
674,643
|
|
|
$
|
807,229
|
|
|
$
|
242,278
|
|
|
$
|
1,724,150
|
|
(a)
|
Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes
$130.0 million
of equity investments in unconsolidated subsidiaries and
$48.9 million
of miscellaneous investments.
|
|
|
Dec. 31, 2014
|
||||||||||||||||||
|
|
|
|
Fair Value
|
||||||||||||||||
(Thousands of Dollars)
|
|
Cost
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
||||||||||
Nuclear decommissioning fund
(a)
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Cash equivalents
|
|
$
|
24,184
|
|
|
$
|
24,184
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
24,184
|
|
Commingled funds
|
|
470,013
|
|
|
—
|
|
|
465,615
|
|
|
—
|
|
|
465,615
|
|
|||||
International equity funds
|
|
80,454
|
|
|
—
|
|
|
78,721
|
|
|
—
|
|
|
78,721
|
|
|||||
Private equity investments
|
|
73,936
|
|
|
—
|
|
|
—
|
|
|
101,237
|
|
|
101,237
|
|
|||||
Real estate
|
|
43,859
|
|
|
—
|
|
|
—
|
|
|
64,249
|
|
|
64,249
|
|
|||||
Debt securities:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Government securities
|
|
30,674
|
|
|
—
|
|
|
28,808
|
|
|
—
|
|
|
28,808
|
|
|||||
U.S. corporate bonds
|
|
81,463
|
|
|
—
|
|
|
77,562
|
|
|
—
|
|
|
77,562
|
|
|||||
International corporate bonds
|
|
16,950
|
|
|
—
|
|
|
16,341
|
|
|
—
|
|
|
16,341
|
|
|||||
Municipal bonds
|
|
242,282
|
|
|
—
|
|
|
249,201
|
|
|
—
|
|
|
249,201
|
|
|||||
Asset-backed securities
|
|
9,131
|
|
|
—
|
|
|
9,250
|
|
|
—
|
|
|
9,250
|
|
|||||
Mortgage-backed securities
|
|
23,225
|
|
|
—
|
|
|
23,895
|
|
|
—
|
|
|
23,895
|
|
|||||
Equity securities:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Common stock
|
|
369,751
|
|
|
564,858
|
|
|
—
|
|
|
—
|
|
|
564,858
|
|
|||||
Total
|
|
$
|
1,465,922
|
|
|
$
|
589,042
|
|
|
$
|
949,393
|
|
|
$
|
165,486
|
|
|
$
|
1,703,921
|
|
(a)
|
Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes
$83.1 million
of equity investments in unconsolidated subsidiaries and
$45.6 million
of miscellaneous investments.
|
(Thousands of Dollars)
|
|
Jan. 1, 2015
|
|
Purchases
|
|
Settlements
|
|
Gains
Recognized as Regulatory Assets (a) |
|
Transfers Out of Level 3
|
|
Dec. 31, 2015
|
||||||||||||
Private equity investments
|
|
$
|
101,237
|
|
|
$
|
32,029
|
|
|
$
|
—
|
|
|
$
|
24,262
|
|
|
$
|
—
|
|
|
$
|
157,528
|
|
Real estate
|
|
64,249
|
|
|
27,568
|
|
|
(9,611
|
)
|
|
2,544
|
|
|
—
|
|
|
84,750
|
|
||||||
Total
|
|
$
|
165,486
|
|
|
$
|
59,597
|
|
|
$
|
(9,611
|
)
|
|
$
|
26,806
|
|
|
$
|
—
|
|
|
$
|
242,278
|
|
(Thousands of Dollars)
|
|
Jan. 1, 2014
|
|
Purchases
|
|
Settlements
|
|
Gains
Recognized as
Regulatory Assets (a) |
|
Transfers Out of Level 3
|
|
Dec. 31, 2014
|
||||||||||||
Private equity investments
|
|
$
|
62,696
|
|
|
$
|
22,078
|
|
|
$
|
(286
|
)
|
|
$
|
16,749
|
|
|
$
|
—
|
|
|
$
|
101,237
|
|
Real estate
|
|
57,368
|
|
|
8,088
|
|
|
(9,794
|
)
|
|
8,587
|
|
|
—
|
|
|
64,249
|
|
||||||
Total
|
|
$
|
120,064
|
|
|
$
|
30,166
|
|
|
$
|
(10,080
|
)
|
|
$
|
25,336
|
|
|
$
|
—
|
|
|
$
|
165,486
|
|
(Thousands of Dollars)
|
|
Jan. 1, 2013
|
|
Purchases
|
|
Settlements
|
|
Gains
Recognized as Regulatory Assets (a) |
|
Transfers Out of Level 3
(b)
|
|
Dec. 31, 2013
|
||||||||||||
Private equity investments
|
|
$
|
33,250
|
|
|
$
|
24,201
|
|
|
$
|
—
|
|
|
$
|
5,245
|
|
|
$
|
—
|
|
|
$
|
62,696
|
|
Real estate
|
|
39,074
|
|
|
31,626
|
|
|
(18,622
|
)
|
|
5,290
|
|
|
—
|
|
|
57,368
|
|
||||||
Asset-backed securities
|
|
2,067
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(2,067
|
)
|
|
—
|
|
||||||
Mortgage-backed securities
|
|
30,209
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(30,209
|
)
|
|
—
|
|
||||||
Total
|
|
$
|
104,600
|
|
|
$
|
55,827
|
|
|
$
|
(18,622
|
)
|
|
$
|
10,535
|
|
|
$
|
(32,276
|
)
|
|
$
|
120,064
|
|
(a)
|
Gains and losses are deferred as a component of the regulatory asset for nuclear decommissioning.
|
(b)
|
Transfers out of Level 3 into Level 2 were principally due to diminished use of unobservable inputs that were previously significant to these fair value measurements and were subsequently sold during 2013.
|
|
|
Final Contractual Maturity
|
||||||||||||||||||
(Thousands of Dollars)
|
|
Due in 1 Year
or Less
|
|
Due in 1 to 5
Years
|
|
Due in 5 to 10
Years
|
|
Due after 10
Years
|
|
Total
|
||||||||||
Government securities
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
21,356
|
|
|
$
|
21,356
|
|
U.S. corporate bonds
|
|
—
|
|
|
16,005
|
|
|
51,384
|
|
|
(2,113
|
)
|
|
65,276
|
|
|||||
International corporate bonds
|
|
—
|
|
|
2,787
|
|
|
9,382
|
|
|
632
|
|
|
12,801
|
|
|||||
Municipal bonds
|
|
153
|
|
|
264
|
|
|
17,814
|
|
|
33,358
|
|
|
51,589
|
|
|||||
Asset-backed securities
|
|
—
|
|
|
—
|
|
|
2,830
|
|
|
—
|
|
|
2,830
|
|
|||||
Mortgage-backed securities
|
|
—
|
|
|
—
|
|
|
—
|
|
|
11,621
|
|
|
11,621
|
|
|||||
Debt securities
|
|
$
|
153
|
|
|
$
|
19,056
|
|
|
$
|
81,410
|
|
|
$
|
64,854
|
|
|
$
|
165,473
|
|
(Amounts in Thousands)
(a)(b)
|
|
2015
|
|
2014
|
||
MWh of electricity
|
|
50,487
|
|
|
56,361
|
|
MMBtu of natural gas
|
|
20,874
|
|
|
927
|
|
Gallons of vehicle fuel
|
|
141
|
|
|
282
|
|
(a)
|
Amounts are not reflective of net positions in the underlying commodities.
|
(b)
|
Notional amounts for options are included on a gross basis, but are weighted for the probability of exercise.
|
(Thousands of Dollars)
|
|
2015
|
|
2014
|
|
2013
|
||||||
Accumulated other comprehensive loss related to cash flow hedges at Jan. 1
|
|
$
|
(57,628
|
)
|
|
$
|
(59,753
|
)
|
|
$
|
(61,241
|
)
|
After-tax net unrealized (losses) gains related to derivatives accounted for as hedges
|
|
(70
|
)
|
|
(163
|
)
|
|
12
|
|
|||
After-tax net realized losses on derivative transactions reclassified into earnings
|
|
2,836
|
|
|
2,288
|
|
|
1,476
|
|
|||
Accumulated other comprehensive loss related to cash flow hedges at Dec. 31
|
|
$
|
(54,862
|
)
|
|
$
|
(57,628
|
)
|
|
$
|
(59,753
|
)
|
|
|
Year Ended Dec. 31, 2015
|
|
||||||||||||||||||
|
|
Pre-Tax Fair Value
Losses Recognized
During the Period in:
|
|
Pre-Tax Losses
Reclassified into Income
During the Period from:
|
|
Pre-Tax Losses
Recognized
During the Period in Income |
|
||||||||||||||
(Thousands of Dollars)
|
|
Accumulated
Other Comprehensive Loss |
|
Regulatory
(Assets) and Liabilities |
|
Accumulated
Other Comprehensive Loss |
|
Regulatory
Assets and (Liabilities) |
|
|
|||||||||||
Derivatives designated as cash flow hedges
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Interest rate
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
4,515
|
|
(a)
|
$
|
—
|
|
|
$
|
—
|
|
|
Vehicle fuel and other commodity
|
|
(116
|
)
|
|
—
|
|
|
131
|
|
(b)
|
—
|
|
|
—
|
|
|
|||||
Total
|
|
$
|
(116
|
)
|
|
$
|
—
|
|
|
$
|
4,646
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
Other derivative instruments
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Commodity trading
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(7,286
|
)
|
(c)
|
Electric commodity
|
|
—
|
|
|
(18,543
|
)
|
|
—
|
|
|
16,338
|
|
(d)
|
—
|
|
|
|||||
Natural gas commodity
|
|
—
|
|
|
(16,163
|
)
|
|
—
|
|
|
15,694
|
|
(e)
|
(11,840
|
)
|
(e)
|
|||||
Total
|
|
$
|
—
|
|
|
$
|
(34,706
|
)
|
|
$
|
—
|
|
|
$
|
32,032
|
|
|
$
|
(19,126
|
)
|
|
|
|
Year Ended Dec. 31, 2014
|
|
||||||||||||||||||
|
|
Pre-Tax Fair Value
Gains (Losses) Recognized
During the Period in:
|
|
Pre-Tax (Gains) Losses
Reclassified into Income
During the Period from:
|
|
Pre-Tax Gains
(Losses) Recognized During the Period in Income |
|
||||||||||||||
(Thousands of Dollars)
|
|
Accumulated
Other Comprehensive Loss |
|
Regulatory
(Assets) and Liabilities |
|
Accumulated
Other Comprehensive Loss |
|
Regulatory
Assets and (Liabilities) |
|
|
|||||||||||
Derivatives designated as cash flow hedges
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Interest rate
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
3,836
|
|
(a)
|
$
|
—
|
|
|
$
|
—
|
|
|
Vehicle fuel and other commodity
|
|
(266
|
)
|
|
—
|
|
|
(55
|
)
|
(b)
|
—
|
|
|
—
|
|
|
|||||
Total
|
|
$
|
(266
|
)
|
|
$
|
—
|
|
|
$
|
3,781
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
Other derivative instruments
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Commodity trading
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
881
|
|
(c)
|
Electric commodity
|
|
—
|
|
|
(8,306
|
)
|
|
—
|
|
|
(9,036
|
)
|
(d)
|
—
|
|
|
|||||
Natural gas commodity
|
|
—
|
|
|
5,166
|
|
|
—
|
|
|
(13,997
|
)
|
(e)
|
(13,220
|
)
|
(e)
|
|||||
Other commodity
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
643
|
|
(c)
|
|||||
Total
|
|
$
|
—
|
|
|
$
|
(3,140
|
)
|
|
$
|
—
|
|
|
$
|
(23,033
|
)
|
|
$
|
(11,696
|
)
|
|
|
|
Year Ended Dec. 31, 2013
|
|
||||||||||||||||||
|
|
Pre-Tax Fair Value
Gains (Losses) Recognized
During the Period in:
|
|
Pre-Tax (Gains) Losses
Reclassified into Income
During the Period from:
|
|
Pre-Tax Gains
(Losses) Recognized During the Period in Income |
|
||||||||||||||
(Thousands of Dollars)
|
|
Accumulated
Other Comprehensive Loss |
|
Regulatory
(Assets) and Liabilities |
|
Accumulated
Other Comprehensive Loss |
|
Regulatory
Assets and(Liabilities) |
|
|
|||||||||||
Derivatives designated as cash flow hedges
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Interest rate
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
4,107
|
|
(a)
|
$
|
—
|
|
|
$
|
—
|
|
|
Vehicle fuel and other commodity
|
|
29
|
|
|
—
|
|
|
(90
|
)
|
(b)
|
—
|
|
|
—
|
|
|
|||||
Total
|
|
$
|
29
|
|
|
$
|
—
|
|
|
$
|
4,017
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
Other derivative instruments
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Commodity trading
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
11,221
|
|
(c)
|
Electric commodity
|
|
—
|
|
|
75,817
|
|
|
—
|
|
|
(52,796
|
)
|
(d)
|
—
|
|
|
|||||
Natural gas commodity
|
|
—
|
|
|
(3,088
|
)
|
|
—
|
|
|
5,019
|
|
(e)
|
(6,589
|
)
|
(d)
|
|||||
Total
|
|
$
|
—
|
|
|
$
|
72,729
|
|
|
$
|
—
|
|
|
$
|
(47,777
|
)
|
|
$
|
4,632
|
|
|
(a)
|
Amounts are recorded to interest charges.
|
(b)
|
Amounts are recorded to O&M expenses.
|
(c)
|
Amounts are recorded to electric operating revenues. Portions of these gains and losses are subject to sharing with electric customers through margin-sharing mechanisms and deducted from gross revenue, as appropriate.
|
(d)
|
Amounts are recorded to electric fuel and purchased power. These derivative settlement gains and losses are shared with electric customers through fuel and purchased energy cost-recovery mechanisms, and reclassified out of income as regulatory assets or liabilities, as appropriate.
|
(e)
|
Amounts for the year ended Dec. 31, 2015 included
$1.1 million
of settlement losses on derivatives entered to mitigate natural gas price risk for electric generation, recorded to electric fuel and purchased power, subject to cost-recovery mechanisms and reclassified to a regulatory asset, as appropriate. Such losses for the years ended Dec. 31, 2014 and 2013 were immaterial. The remaining settlement losses for the years ended Dec. 31, 2015, 2014 and 2013 relate to natural gas operations and are recorded to cost of natural gas sold and transported. These losses are subject to cost-recovery mechanisms and reclassified out of income to a regulatory asset, as appropriate.
|
|
|
Dec. 31, 2015
|
||||||||||||||||||||||
|
|
Fair Value
|
|
Fair Value Total
|
|
Counterparty
Netting
(b)
|
|
|
||||||||||||||||
(Thousands of Dollars)
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
|
|
Total
|
||||||||||||||
Current derivative assets
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Other derivative instruments:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Commodity trading
|
|
$
|
225
|
|
|
$
|
10,620
|
|
|
$
|
1,250
|
|
|
$
|
12,095
|
|
|
$
|
(5,865
|
)
|
|
$
|
6,230
|
|
Electric commodity
|
|
—
|
|
|
—
|
|
|
21,421
|
|
|
21,421
|
|
|
(4,088
|
)
|
|
17,333
|
|
||||||
Natural gas commodity
|
|
—
|
|
|
496
|
|
|
—
|
|
|
496
|
|
|
(303
|
)
|
|
193
|
|
||||||
Total current derivative assets
|
|
$
|
225
|
|
|
$
|
11,116
|
|
|
$
|
22,671
|
|
|
$
|
34,012
|
|
|
$
|
(10,256
|
)
|
|
23,756
|
|
|
PPAs
(a)
|
|
|
|
|
|
|
|
|
|
|
|
10,086
|
|
|||||||||||
Current derivative instruments
|
|
|
|
|
|
|
|
|
|
|
|
$
|
33,842
|
|
||||||||||
Noncurrent derivative assets
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Other derivative instruments:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Commodity trading
|
|
$
|
—
|
|
|
$
|
27,416
|
|
|
$
|
—
|
|
|
$
|
27,416
|
|
|
$
|
(6,555
|
)
|
|
$
|
20,861
|
|
Total noncurrent derivative assets
|
|
$
|
—
|
|
|
$
|
27,416
|
|
|
$
|
—
|
|
|
$
|
27,416
|
|
|
$
|
(6,555
|
)
|
|
20,861
|
|
|
PPAs
(a)
|
|
|
|
|
|
|
|
|
|
|
|
30,222
|
|
|||||||||||
Noncurrent derivative instruments
|
|
|
|
|
|
|
|
|
|
|
|
$
|
51,083
|
|
|
|
Dec. 31, 2015
|
||||||||||||||||||||||
|
|
Fair Value
|
|
Fair Value Total
|
|
Counterparty
Netting
(b)
|
|
|
||||||||||||||||
(Thousands of Dollars)
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
|
|
Total
|
||||||||||||||
Current derivative liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Derivatives designated as cash flow hedges:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Vehicle fuel and other commodity
|
|
$
|
—
|
|
|
$
|
205
|
|
|
$
|
—
|
|
|
$
|
205
|
|
|
$
|
—
|
|
|
$
|
205
|
|
Other derivative instruments:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Commodity trading
|
|
152
|
|
|
7,866
|
|
|
555
|
|
|
8,573
|
|
|
(6,904
|
)
|
|
1,669
|
|
||||||
Electric commodity
|
|
—
|
|
|
—
|
|
|
4,088
|
|
|
4,088
|
|
|
(4,088
|
)
|
|
—
|
|
||||||
Natural gas commodity
|
|
—
|
|
|
5,407
|
|
|
—
|
|
|
5,407
|
|
|
(303
|
)
|
|
5,104
|
|
||||||
Total current derivative liabilities
|
|
$
|
152
|
|
|
$
|
13,478
|
|
|
$
|
4,643
|
|
|
$
|
18,273
|
|
|
$
|
(11,295
|
)
|
|
6,978
|
|
|
PPAs
(a)
|
|
|
|
|
|
|
|
|
|
|
|
22,861
|
|
|||||||||||
Current derivative instruments
|
|
|
|
|
|
|
|
|
|
|
|
$
|
29,839
|
|
||||||||||
Noncurrent derivative liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Derivatives designated as cash flow hedges:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Commodity trading
|
|
$
|
—
|
|
|
$
|
19,898
|
|
|
$
|
—
|
|
|
$
|
19,898
|
|
|
$
|
(9,780
|
)
|
|
$
|
10,118
|
|
Total noncurrent derivative liabilities
|
|
$
|
—
|
|
|
$
|
19,898
|
|
|
$
|
—
|
|
|
$
|
19,898
|
|
|
$
|
(9,780
|
)
|
|
10,118
|
|
|
PPAs
(a)
|
|
|
|
|
|
|
|
|
|
|
|
158,193
|
|
|||||||||||
Noncurrent derivative instruments
|
|
|
|
|
|
|
|
|
|
|
|
$
|
168,311
|
|
(a)
|
In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, Xcel Energy began recording several long-term PPAs at fair value due to accounting requirements related to underlying price adjustments. As these purchases are recovered through normal regulatory recovery mechanisms in the respective jurisdictions, the changes in fair value for these contracts were offset by regulatory assets and liabilities. During 2006, Xcel Energy qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.
|
(b)
|
Xcel Energy nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Dec. 31, 2015. At Dec. 31, 2015, derivative assets and liabilities include
no
obligations to return cash collateral and rights to reclaim cash collateral of
$4.3 million
. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.
|
|
|
Dec. 31, 2014
|
||||||||||||||||||||||
|
|
Fair Value
|
|
Fair Value Total
|
|
Counterparty
Netting
(b)
|
|
|
||||||||||||||||
(Thousands of Dollars)
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
|
|
Total
|
||||||||||||||
Current derivative assets
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Other derivative instruments:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Commodity trading
|
|
$
|
—
|
|
|
$
|
14,326
|
|
|
$
|
4,732
|
|
|
$
|
19,058
|
|
|
$
|
(3,240
|
)
|
|
$
|
15,818
|
|
Electric commodity
|
|
—
|
|
|
—
|
|
|
62,825
|
|
|
62,825
|
|
|
(11,402
|
)
|
|
51,423
|
|
||||||
Natural gas commodity
|
|
—
|
|
|
381
|
|
|
—
|
|
|
381
|
|
|
(22
|
)
|
|
359
|
|
||||||
Total current derivative assets
|
$
|
—
|
|
|
$
|
14,707
|
|
|
$
|
67,557
|
|
|
$
|
82,264
|
|
|
$
|
(14,664
|
)
|
|
67,600
|
|
||
PPAs
(a)
|
|
|
|
|
|
|
|
|
|
|
|
18,123
|
|
|||||||||||
Current derivative instruments
|
|
|
|
|
|
|
|
|
|
|
|
$
|
85,723
|
|
||||||||||
Noncurrent derivative assets
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Other derivative instruments:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Commodity trading
|
|
$
|
—
|
|
|
$
|
17,617
|
|
|
$
|
—
|
|
|
$
|
17,617
|
|
|
$
|
(4,151
|
)
|
|
$
|
13,466
|
|
Total noncurrent derivative assets
|
$
|
—
|
|
|
$
|
17,617
|
|
|
$
|
—
|
|
|
$
|
17,617
|
|
|
$
|
(4,151
|
)
|
|
13,466
|
|
||
PPAs
(a)
|
|
|
|
|
|
|
|
|
|
|
|
40,309
|
|
|||||||||||
Noncurrent derivative instruments
|
|
|
|
|
|
|
|
|
|
|
|
$
|
53,775
|
|
|
|
Dec. 31, 2014
|
||||||||||||||||||||||
|
|
Fair Value
|
|
Fair Value Total
|
|
Counterparty
Netting
(b)
|
|
|
||||||||||||||||
(Thousands of Dollars)
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
|
|
Total
|
||||||||||||||
Current derivative liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Derivatives designated as cash flow hedges:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Vehicle fuel and other commodity
|
|
$
|
—
|
|
|
$
|
118
|
|
|
$
|
—
|
|
|
$
|
118
|
|
|
$
|
—
|
|
|
$
|
118
|
|
Other derivative instruments:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Commodity trading
|
|
—
|
|
|
7,974
|
|
|
—
|
|
|
7,974
|
|
|
(7,974
|
)
|
|
—
|
|
||||||
Electric commodity
|
|
—
|
|
|
—
|
|
|
11,402
|
|
|
11,402
|
|
|
(11,402
|
)
|
|
—
|
|
||||||
Natural gas commodity
|
|
—
|
|
|
548
|
|
|
—
|
|
|
548
|
|
|
(21
|
)
|
|
527
|
|
||||||
Total current derivative liabilities
|
|
$
|
—
|
|
|
$
|
8,640
|
|
|
$
|
11,402
|
|
|
$
|
20,042
|
|
|
$
|
(19,397
|
)
|
|
645
|
|
|
PPAs
(a)
|
|
|
|
|
|
|
|
|
|
|
|
20,987
|
|
|||||||||||
Current derivative instruments
|
|
|
|
|
|
|
|
|
|
|
|
$
|
21,632
|
|
||||||||||
Noncurrent derivative liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Derivatives designated as cash flow hedges:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Vehicle fuel and other commodity
|
|
$
|
—
|
|
|
$
|
102
|
|
|
$
|
—
|
|
|
$
|
102
|
|
|
$
|
—
|
|
|
$
|
102
|
|
Other derivative instruments:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Commodity trading
|
|
—
|
|
|
6,890
|
|
|
—
|
|
|
6,890
|
|
|
(6,033
|
)
|
|
857
|
|
||||||
Natural gas commodity
|
|
—
|
|
|
35
|
|
|
—
|
|
|
35
|
|
|
—
|
|
|
35
|
|
||||||
Total noncurrent derivative liabilities
|
|
$
|
—
|
|
|
$
|
7,027
|
|
|
$
|
—
|
|
|
$
|
7,027
|
|
|
$
|
(6,033
|
)
|
|
994
|
|
|
PPAs
(a)
|
|
|
|
|
|
|
|
|
|
|
|
182,942
|
|
|||||||||||
Noncurrent derivative instruments
|
|
|
|
|
|
|
|
|
|
|
|
$
|
183,936
|
|
(a)
|
In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, Xcel Energy began recording several long-term PPAs at fair value due to accounting requirements related to underlying price adjustments. As these purchases are recovered through normal regulatory recovery mechanisms in the respective jurisdictions, the changes in fair value for these contracts were offset by regulatory assets and liabilities. During 2006, Xcel Energy qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.
|
(b)
|
Xcel Energy nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Dec. 31, 2014. At Dec. 31, 2014, derivative assets and liabilities include
no
obligations to return cash collateral and rights to reclaim cash collateral of
$6.6 million
. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.
|
|
|
Year Ended Dec. 31
|
||||||||||
(Thousands of Dollars)
|
|
2015
|
|
2014
|
|
2013
|
||||||
Balance at Jan. 1
|
|
$
|
56,155
|
|
|
$
|
41,660
|
|
|
$
|
16,649
|
|
Purchases
|
|
63,712
|
|
|
135,008
|
|
|
61,474
|
|
|||
Settlements
|
|
(69,754
|
)
|
|
(145,974
|
)
|
|
(45,199
|
)
|
|||
Transfers out of Level 3
|
|
—
|
|
|
(1,093
|
)
|
|
—
|
|
|||
Net transactions recorded during the period:
|
|
|
|
|
|
|
||||||
Gains recognized in earnings
(a)
|
|
1,533
|
|
|
10,692
|
|
|
3,947
|
|
|||
(Losses) gains recognized as regulatory assets and liabilities
|
|
(33,618
|
)
|
|
15,862
|
|
|
4,789
|
|
|||
Balance at Dec. 31
|
|
$
|
18,028
|
|
|
$
|
56,155
|
|
|
$
|
41,660
|
|
(a)
|
These amounts relate to commodity derivatives held at the end of the period.
|
|
|
2015
|
|
2014
|
||||||||||||
(Thousands of Dollars)
|
|
Carrying Amount
|
|
Fair Value
|
|
Carrying Amount
|
|
Fair Value
|
||||||||
Long-term debt, including current portion
|
|
$
|
13,147,740
|
|
|
$
|
14,094,744
|
|
|
$
|
11,757,360
|
|
|
$
|
13,360,236
|
|
(Millions of Dollars)
|
|
MPUC July Decision
|
||
2014 and 2015 step increase - based on MPUC May order
|
|
$
|
166.1
|
|
Reconsideration/clarification adjustments:
|
|
|
||
2015 Monticello EPU used-and-useful adjustment
|
|
(13.8
|
)
|
|
2014 property tax final true-up
|
|
(3.1
|
)
|
|
Other, net
|
|
0.2
|
|
|
Total 2014 and 2015 step increase
|
|
$
|
149.4
|
|
Impact of interim rate effective March 3, 2015
|
|
(3.6
|
)
|
|
Estimated revenue impact
|
|
$
|
145.8
|
|
Request (Millions of Dollars)
|
|
2016
|
|
2017
|
|
2018
|
||||||
Rate request
|
|
$
|
194.6
|
|
|
$
|
52.1
|
|
|
$
|
50.4
|
|
Increase percentage
|
|
6.4
|
%
|
|
1.7
|
%
|
|
1.7
|
%
|
|||
Interim request
|
|
$
|
163.7
|
|
|
$
|
44.9
|
|
|
N/A
|
|
|
Rate base
|
|
$
|
7,800
|
|
|
$
|
7,700
|
|
|
$
|
7,700
|
|
•
|
Intervenors’ direct testimony — June 14, 2016;
|
•
|
Rebuttal testimony — Aug. 9, 2016;
|
•
|
Surrebuttal testimony — Sept. 16, 2016;
|
•
|
Settlement conference — Sept. 26, 2016;
|
•
|
Evidentiary hearing — Oct. 4-7, 2016;
|
•
|
ALJ report — Feb. 21, 2017; and
|
•
|
MPUC order — June 1, 2017.
|
•
|
In July 2015, the MPUC approved NSP-Minnesota’s 2014 CIP electric and natural gas financial incentives totaling
$40.1 million
and
$5.8 million
, respectively.
|
•
|
In addition, the MPUC approved NSP-Minnesota’s proposed 2015 to 2016 electric and natural gas CIP riders. NSP-Minnesota estimates 2016 recovery of
$21.5 million
of electric CIP expenses and
$9.2 million
of natural gas CIP expenses.
|
•
|
This proposed recovery through the riders is in addition to an estimated
$86.9 million
and
$3.7 million
through electric and gas base rates, respectively.
|
Electric Rate Request (Millions of Dollars)
|
|
NSP-Wisconsin Request
|
|
PSCW Approval
|
||||
Capital investments
|
|
$
|
23.0
|
|
|
$
|
13.9
|
|
ROE & other capital structure adjustments
|
|
—
|
|
|
(3.8
|
)
|
||
Generation and transmission expenses (excluding fuel and purchased power)
|
|
37.2
|
|
|
42.7
|
|
||
O&M expenses
|
|
11.1
|
|
|
3.2
|
|
||
Sales forecast
|
|
(27.0
|
)
|
|
(27.0
|
)
|
||
Rate increase - non-fuel and purchased power
|
|
44.3
|
|
|
29.0
|
|
||
Rate reduction - fuel and purchased power
|
|
(16.9
|
)
|
|
(21.4
|
)
|
||
Total electric rate increase
|
|
$
|
27.4
|
|
|
$
|
7.6
|
|
Natural Gas Rate Request (Millions of Dollars)
|
|
NSP-Wisconsin Request
|
|
PSCW Approval
|
||||
Capital investments
|
|
$
|
3.7
|
|
|
$
|
3.7
|
|
ROE & other capital structure adjustments
|
|
—
|
|
|
(0.4
|
)
|
||
O&M expenses
|
|
3.2
|
|
|
1.9
|
|
||
Environmental remediation expenses
|
|
2.9
|
|
|
2.9
|
|
||
Sales forecast
|
|
(3.9
|
)
|
|
(3.9
|
)
|
||
Total natural gas rate increase
|
|
$
|
5.9
|
|
|
$
|
4.2
|
|
(Millions of Dollars)
|
|
2015
|
|
2016 Step
|
|
2017 Step
|
||||||
PSCo’s filed base rate request
|
|
$
|
40.5
|
|
|
$
|
7.6
|
|
|
$
|
18.1
|
|
Shift O&M expenses between PSIA and base rates
|
|
—
|
|
|
7.0
|
|
|
6.4
|
|
|||
Rebuttal corrections and adjustments
|
|
—
|
|
|
—
|
|
|
(7.7
|
)
|
|||
Total base rate increase
|
|
$
|
40.5
|
|
|
$
|
14.6
|
|
|
$
|
16.8
|
|
Incremental PSIA rider revenues
|
|
(0.1
|
)
|
|
14.7
|
|
|
21.7
|
|
|||
Total revenue impact from rebuttal
|
|
$
|
40.4
|
|
|
$
|
29.3
|
|
|
$
|
38.5
|
|
Requested ROE
|
|
10.1
|
%
|
|
10.1
|
%
|
|
10.3
|
%
|
|||
Rate base
|
|
$
|
1,260
|
|
|
$
|
1,310
|
|
|
$
|
1,360
|
|
•
|
2014 HTY, with a
13
-month average rate base, with the exception of the Cherokee pipeline which is included at a year-end level;
|
•
|
Extension of the PSIA rider through 2018 with all O&M expenses transferred to base rates;
|
•
|
A ROE of
9.5 percent
; and
|
•
|
An equity ratio of
56.51 percent
.
|
(Millions of Dollars)
|
|
ALJ
|
|
CPUC
’
s Written Order
|
||||
PSCo’s filed 2015 base rate request
(a)
|
|
$
|
40.5
|
|
|
$
|
40.5
|
|
ROE
|
|
(7.8
|
)
|
|
(7.8
|
)
|
||
Capital structure and cost of debt
|
|
(0.5
|
)
|
|
(0.5
|
)
|
||
Cherokee pipeline adjustment
|
|
4.1
|
|
|
4.1
|
|
||
Move to 2014 HTY
|
|
(14.1
|
)
|
|
(14.1
|
)
|
||
O&M expenses
|
|
(3.0
|
)
|
|
(2.4
|
)
|
||
Other, net
|
|
(1.1
|
)
|
|
(1.1
|
)
|
||
Overall recommended rate increase
|
|
$
|
18.1
|
|
|
$
|
18.7
|
|
(a)
|
The ALJ’s recommendation and the CPUC’s written order also includes approximately
$20.0 million
of PSIA costs be transferred to base rates, effective Jan. 1, 2016.
|
|
|
ALJ
|
|
CPUC
’
s Written Order
|
||||||||||||
(Millions of Dollars)
|
|
2016
|
|
2017
|
|
2016
|
|
2017
|
||||||||
PSCo’s filed incremental PSIA request
|
|
$
|
21.7
|
|
|
$
|
21.2
|
|
|
$
|
21.7
|
|
|
$
|
21.2
|
|
Transfer PSIA costs to base rates
|
|
(20.5
|
)
|
|
—
|
|
|
(20.5
|
)
|
|
—
|
|
||||
PSIA cost recovery remaining in base
|
|
(4.3
|
)
|
|
—
|
|
|
(4.3
|
)
|
|
—
|
|
||||
Projects not recovered through the PSIA
|
|
(3.6
|
)
|
|
(2.0
|
)
|
|
(3.3
|
)
|
|
(0.8
|
)
|
||||
ROE and capital structure
|
|
(0.3
|
)
|
|
(1.6
|
)
|
|
(0.3
|
)
|
|
(1.6
|
)
|
||||
Total
|
|
$
|
(7.0
|
)
|
|
$
|
17.6
|
|
|
$
|
(6.7
|
)
|
|
$
|
18.8
|
|
(Millions of Dollars)
|
|
2015
|
|
2016
|
|
2017
|
||||||
Base rate increase
|
|
$
|
18.7
|
|
|
$
|
19.7
|
|
|
$
|
—
|
|
Incremental PSIA rider revenues
|
|
(0.2
|
)
|
|
(6.7
|
)
|
|
18.8
|
|
|||
Expense deferrals, net amortization
(a)
|
|
(3.6
|
)
|
|
1.5
|
|
|
5.2
|
|
|||
Estimated pre-tax impact
|
|
$
|
14.9
|
|
|
$
|
14.5
|
|
|
$
|
24.0
|
|
(a)
|
Deferral and amortization impacts relate primarily to recognition of accelerated amortization of prepaid pension assets and deferrals of pension expense in excess of the amount approved in the prior general gas rate case.
|
•
|
A 2015 DSM electric budget of
$81.6 million
and a natural gas budget of
$13.1 million
; and
|
•
|
A 2016 DSM electric budget of
$78.7 million
and a natural gas budget of
$13.6 million
.
|
•
|
Disallowed SPS’ proposed adjustment to jurisdictional allocation factors to reflect Golden Spread Electric Cooperative, Inc.’s (Golden Spread’s) wholesale load reductions from
500
MW to
300
MW, effective June 1, 2015;
|
•
|
Disallowed incentive compensation;
|
•
|
Approved an equity ratio of
51.00 percent
instead of the actual
53.97 percent
; and
|
•
|
A ROE of
9.70 percent
.
|
|
|
ALJs’ Proposal
|
|
PUCT
|
||||
(Millions of Dollars)
|
|
for Decision
|
|
Decision
|
||||
SPS’ revised rate request
|
|
$
|
42.1
|
|
|
$
|
42.1
|
|
Investment for capital expenditures — post-test year adjustments
|
|
(8.9
|
)
|
|
(8.9
|
)
|
||
Lower ROE
|
|
(6.3
|
)
|
|
(6.3
|
)
|
||
Lower capital structure
|
|
—
|
|
|
(3.7
|
)
|
||
Annual incentive compensation
|
|
(0.2
|
)
|
|
(0.3
|
)
|
||
O&M expense adjustments
|
|
(4.6
|
)
|
|
(4.6
|
)
|
||
Depreciation expense
|
|
(2.7
|
)
|
|
(2.7
|
)
|
||
Property taxes
|
|
(0.9
|
)
|
|
(0.9
|
)
|
||
Revenue adjustments
|
|
(1.1
|
)
|
|
(1.6
|
)
|
||
Wholesale load reductions
|
|
—
|
|
|
(11.5
|
)
|
||
SPP transmission expansion plan
|
|
(4.2
|
)
|
|
(4.2
|
)
|
||
Other, net
|
|
1.4
|
|
|
(1.2
|
)
|
||
Total, gross of rate case expenses
|
|
$
|
14.6
|
|
|
$
|
(3.8
|
)
|
Adjustment to move rate case expenses to a separate docket
|
|
(0.2
|
)
|
|
(0.2
|
)
|
||
Total, net of rate case expenses
|
|
$
|
14.4
|
|
|
$
|
(4.0
|
)
|
New depreciation rates
|
|
(11.2
|
)
|
|
(11.2
|
)
|
||
Earnings impact
|
|
$
|
3.2
|
|
|
$
|
(15.2
|
)
|
(Millions of Dollars)
|
|
Request
|
||
Capital expenditure investments
|
|
$
|
38.6
|
|
Change in jurisdictional allocation factors
|
|
10.9
|
|
|
Changes in ROE and capital structure
|
|
11.7
|
|
|
Estimated rate case expenses
(a)
|
|
4.5
|
|
|
Other, net
|
|
6.2
|
|
|
Total
|
|
$
|
71.9
|
|
(a)
|
SPS anticipates rate case expenses, for this proceeding, to be separated from the request for consideration in a separate docket.
|
(Millions of Dollars)
|
|
Request
|
||
2015 base period deficiency
|
|
$
|
19.7
|
|
Capital expenditures
—
post-test year adjustments
|
|
12.3
|
|
|
Depreciation, higher rates reflecting changes in depreciable lives, interim retirements and net salvage
|
|
3.7
|
|
|
Transmission revenue and expense, including charges paid to SPP for construction of regionally shared transmission projects
|
|
2.0
|
|
|
ROE, reflecting an increase from 9.96 percent to 10.25 percent
|
|
1.6
|
|
|
Rider revenue adjustments - gross receipts tax
|
|
1.3
|
|
|
Other, net
|
|
4.8
|
|
|
Requested rate increase
|
|
$
|
45.4
|
|
•
|
Settlement conference — Feb. 29, 2016;
|
•
|
Staff and intervenor direct testimony — April 1, 2016;
|
•
|
Rebuttal testimony — April 18, 2016; and
|
•
|
Evidentiary hearing begins — April 28, 2016.
|
(Millions of Dollars)
|
|
Coal
|
|
Nuclear fuel
|
|
Natural gas supply
|
|
Natural gas
storage and
transportation
|
||||||||
2016
|
|
$
|
824.4
|
|
|
$
|
112.2
|
|
|
$
|
285.4
|
|
|
$
|
282.0
|
|
2017
|
|
483.0
|
|
|
112.3
|
|
|
132.2
|
|
|
254.9
|
|
||||
2018
|
|
227.8
|
|
|
62.7
|
|
|
181.0
|
|
|
154.5
|
|
||||
2019
|
|
42.7
|
|
|
124.1
|
|
|
187.6
|
|
|
113.8
|
|
||||
2020
|
|
44.4
|
|
|
46.9
|
|
|
203.4
|
|
|
101.6
|
|
||||
Thereafter
|
|
334.9
|
|
|
599.2
|
|
|
409.5
|
|
|
1,044.2
|
|
||||
Total
|
|
$
|
1,957.2
|
|
|
$
|
1,057.4
|
|
|
$
|
1,399.1
|
|
|
$
|
1,951.0
|
|
(a)
|
Excludes contingent energy payments for renewable energy PPAs.
|
(Millions of Dollars)
|
|
Dec. 31, 2015
|
|
Dec. 31, 2014
|
||||
Gas storage facilities
|
|
$
|
200.5
|
|
|
$
|
200.5
|
|
Gas pipeline
|
|
20.7
|
|
|
20.7
|
|
||
Property held under capital leases
|
|
221.2
|
|
|
221.2
|
|
||
Accumulated depreciation
|
|
(57.2
|
)
|
|
(49.0
|
)
|
||
Total property held under capital leases, net
|
|
$
|
164.0
|
|
|
$
|
172.2
|
|
(Millions of Dollars)
|
|
Operating
Leases
|
|
PPA
(a) (b)
Operating
Leases
|
|
Total
Operating
Leases
|
|
Capital Leases
|
|
||||||||
2016
|
|
$
|
24.6
|
|
|
$
|
217.0
|
|
|
$
|
241.6
|
|
|
$
|
17.1
|
|
|
2017
|
|
22.0
|
|
|
208.7
|
|
|
230.7
|
|
|
15.1
|
|
|
||||
2018
|
|
21.5
|
|
|
210.0
|
|
|
231.5
|
|
|
14.7
|
|
|
||||
2019
|
|
25.9
|
|
|
227.8
|
|
|
253.7
|
|
|
14.5
|
|
|
||||
2020
|
|
20.8
|
|
|
241.3
|
|
|
262.1
|
|
|
14.3
|
|
|
||||
Thereafter
|
|
175.0
|
|
|
2,135.2
|
|
|
2,310.2
|
|
|
258.8
|
|
|
||||
Total minimum obligation
|
|
|
|
|
|
|
|
334.5
|
|
|
|||||||
Interest component of obligation
|
|
|
|
|
|
|
|
(236.9
|
)
|
|
|||||||
Present value of minimum obligation
|
|
|
|
|
|
|
|
$
|
97.6
|
|
(c)
|
(a)
|
Amounts do not include PPAs accounted for as executory contracts.
|
(b)
|
PPA operating leases contractually expire through
2039
.
|
(c)
|
Future commitments exclude certain amounts related to Xcel Energy’s
50 percent
ownership interest in WYCO.
|
(Thousands of Dollars)
|
|
Dec. 31, 2015
|
|
Dec. 31, 2014
|
||||
Current assets
|
|
$
|
6,274
|
|
|
$
|
6,609
|
|
Property, plant and equipment, net
|
|
51,480
|
|
|
53,047
|
|
||
Other noncurrent assets
|
|
1,394
|
|
|
1,503
|
|
||
Total assets
|
|
$
|
59,148
|
|
|
$
|
61,159
|
|
|
|
|
|
|
||||
Current liabilities
|
|
$
|
7,540
|
|
|
$
|
7,774
|
|
Mortgages and other long-term debt payable
|
|
31,082
|
|
|
31,207
|
|
||
Other noncurrent liabilities
|
|
644
|
|
|
619
|
|
||
Total liabilities
|
|
$
|
39,266
|
|
|
$
|
39,600
|
|
(Millions of Dollars)
|
|
IBM
Agreement
|
|
Accenture
Agreement
|
||||
2016
|
|
$
|
34.4
|
|
|
$
|
10.0
|
|
2017
|
|
34.4
|
|
|
10.5
|
|
||
2018
|
|
33.5
|
|
|
10.7
|
|
||
2019
|
|
33.5
|
|
|
10.8
|
|
||
2020
|
|
—
|
|
|
11.0
|
|
||
Thereafter
|
|
—
|
|
|
—
|
|
(Millions of Dollars)
|
|
Guarantor
|
|
Guarantee
Amount
|
|
Current
Exposure
|
|
Triggering
Event
|
||||
Guarantee of customer loans for the Farm Rewiring Program
(a)
|
|
NSP-Wisconsin
|
|
$
|
1.0
|
|
|
$
|
0.1
|
|
|
(e)
|
Guarantee of the indemnification obligations of Xcel Energy Services Inc. under the aircraft leases
(b)
|
|
Xcel Energy Inc.
|
|
6.7
|
|
|
—
|
|
|
(f)
|
||
Guarantee of residual value of assets under the Bank of Tokyo-Mitsubishi Capital Corporation Equipment Leasing Agreement
(c)
|
|
NSP-Minnesota
|
|
4.8
|
|
|
—
|
|
|
(g)
|
||
Total guarantees issued
|
|
|
|
$
|
12.5
|
|
|
$
|
0.1
|
|
|
|
Guarantee performance and payment of surety bonds for Xcel Energy Inc.’s utility subsidiaries
(d)
|
|
Xcel Energy Inc.
|
|
$
|
41.3
|
|
|
(i)
|
|
(h)
|
(a)
|
The term of this guarantee expires in
2020
, which is the final scheduled repayment date for the loans. As of Dec. 31, 2015,
no
claims had been made by the lender.
|
(b)
|
The term of this guarantee expires in
2017
when the associated leases expire.
|
(c)
|
The terms of this guarantee expires in
2019
when the associated lease expires.
|
(d)
|
The surety bonds primarily relate to workers compensation benefits and utility projects. The workers compensation bonds are renewed annually and the project based bonds expire in conjunction with the completion of the related projects.
|
(e)
|
The debtor becomes the subject of bankruptcy or other insolvency proceedings.
|
(f)
|
Nonperformance and/or nonpayment.
|
(g)
|
Actual fair value of leased assets is less than the guaranteed residual value amount at the end of the lease term.
|
(h)
|
Failure of any one of Xcel Energy Inc.’s utility subsidiaries to perform under the agreement that is the subject of the relevant bond. In addition, per the indemnity agreement between Xcel Energy Inc. and the various surety companies, the surety companies have the discretion to demand that collateral be posted.
|
(i)
|
Due to the magnitude of projects associated with the surety bonds, the total current exposure of this indemnification cannot be determined. Xcel Energy Inc. believes the exposure to be significantly less than the total amount of the outstanding bonds.
|
(Thousands of Dollars)
|
|
Beginning
Balance
Jan. 1, 2015
|
|
Liabilities
Recognized
|
|
Liabilities
Settled
|
|
Accretion
|
|
Cash Flow Revisions
(b)
|
|
Ending
Balance
Dec. 31, 2015
|
||||||||||||
Electric plant
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Nuclear production decommissioning
|
|
$
|
2,037,947
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
103,077
|
|
|
$
|
—
|
|
|
$
|
2,141,024
|
|
Steam and other production ash containment
|
|
127,600
|
|
|
—
|
|
|
—
|
|
|
4,746
|
|
|
(759
|
)
|
|
131,587
|
|
||||||
Steam and other production asbestos
|
|
69,698
|
|
|
3,875
|
|
|
—
|
|
|
3,670
|
|
|
7,248
|
|
|
84,491
|
|
||||||
Wind production
|
|
38,260
|
|
|
31,085
|
|
(a)
|
—
|
|
|
1,778
|
|
|
523
|
|
|
71,646
|
|
||||||
Electric distribution
|
|
12,593
|
|
|
—
|
|
|
—
|
|
|
463
|
|
|
131
|
|
|
13,187
|
|
||||||
Other
|
|
4,605
|
|
|
127
|
|
|
(273
|
)
|
|
178
|
|
|
(94
|
)
|
|
4,543
|
|
||||||
Natural gas plant
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Gas transmission and distribution
|
|
149,964
|
|
|
—
|
|
|
—
|
|
|
5,969
|
|
|
—
|
|
|
155,933
|
|
||||||
Other
|
|
3,925
|
|
|
—
|
|
|
—
|
|
|
155
|
|
|
(114
|
)
|
|
3,966
|
|
||||||
Common and other property
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Common general plant asbestos
|
|
505
|
|
|
—
|
|
|
—
|
|
|
27
|
|
|
19
|
|
|
551
|
|
||||||
Common miscellaneous
|
|
1,534
|
|
|
—
|
|
|
—
|
|
|
56
|
|
|
44
|
|
|
1,634
|
|
||||||
Total liability
|
|
$
|
2,446,631
|
|
|
$
|
35,087
|
|
|
$
|
(273
|
)
|
|
$
|
120,119
|
|
|
$
|
6,998
|
|
|
$
|
2,608,562
|
|
(a)
|
The liability recognized relates to the NSP-Minnesota Pleasant Valley and Border Wind Farms which were placed in service during 2015.
|
(b)
|
In 2015, AROs were revised for changes in estimated cash flows and the timing of those cash flows. Changes in the asbestos AROs were mainly related to updated cost estimates.
|
(Thousands of Dollars)
|
|
Beginning
Balance
Jan. 1, 2014
|
|
Liabilities
Recognized
|
|
Accretion
|
|
Cash Flow Revisions
(a)
|
|
Ending
Balance
Dec. 31, 2014
(b)
|
||||||||||
Electric plant
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Nuclear production decommissioning
|
|
$
|
1,628,298
|
|
|
$
|
—
|
|
|
$
|
86,284
|
|
|
$
|
323,365
|
|
|
$
|
2,037,947
|
|
Steam and other production ash containment
|
|
79,353
|
|
|
—
|
|
|
3,354
|
|
|
44,893
|
|
|
127,600
|
|
|||||
Steam and other production asbestos
|
|
50,827
|
|
|
747
|
|
|
2,972
|
|
|
15,152
|
|
|
69,698
|
|
|||||
Wind production
|
|
37,464
|
|
|
—
|
|
|
1,676
|
|
|
(880
|
)
|
|
38,260
|
|
|||||
Electric distribution
|
|
12,186
|
|
|
—
|
|
|
444
|
|
|
(37
|
)
|
|
12,593
|
|
|||||
Other
|
|
3,551
|
|
|
705
|
|
|
137
|
|
|
212
|
|
|
4,605
|
|
|||||
Natural gas plant
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Gas transmission and distribution
|
|
1,198
|
|
|
20,935
|
|
|
76
|
|
|
127,755
|
|
|
149,964
|
|
|||||
Other
|
|
575
|
|
|
2,865
|
|
|
24
|
|
|
461
|
|
|
3,925
|
|
|||||
Common and other property
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Common general plant asbestos
|
|
480
|
|
|
—
|
|
|
25
|
|
|
—
|
|
|
505
|
|
|||||
Common miscellaneous
|
|
1,458
|
|
|
—
|
|
|
53
|
|
|
23
|
|
|
1,534
|
|
|||||
Total liability
|
|
$
|
1,815,390
|
|
|
$
|
25,252
|
|
|
$
|
95,045
|
|
|
$
|
510,944
|
|
|
$
|
2,446,631
|
|
(a)
|
In 2014, revisions were made to various AROs due to revised estimated cash flows and the timing of those cash flows. Changes to estimated nuclear production decommissioning primarily relate to the triennial filing made to the MPUC in December 2014. See additional information in Note 14. Changes in estimated excavation costs and the timing of future retirement activities resulted in revisions to AROs related to gas transmission and distribution.
|
(b)
|
There were
no
ARO liabilities settled during the year ended Dec. 31, 2014.
|
(Millions of Dollars)
|
|
2015
|
|
2014
|
||||
NSP-Minnesota
|
|
$
|
430
|
|
|
$
|
396
|
|
PSCo
|
|
364
|
|
|
366
|
|
||
SPS
|
|
204
|
|
|
68
|
|
||
NSP-Wisconsin
|
|
132
|
|
|
123
|
|
||
Total Xcel Energy
|
|
$
|
1,130
|
|
|
$
|
953
|
|
14.
|
Nuclear Obligations
|
|
|
Regulatory Basis
|
||||||
(Thousands of Dollars)
|
|
2015
|
|
2014
|
||||
Estimated decommissioning cost obligation from most recently approved study (in 2014 and 2011 dollars, respectively)
|
|
$
|
3,012,342
|
|
|
$
|
2,694,079
|
|
Effect of escalating costs (to 2015 and 2014 dollars, respectively, at 4.36/3.36 percent and 3.63/2.63 percent, respectively)
|
|
126,464
|
|
|
289,907
|
|
||
Estimated decommissioning cost obligation (in current dollars)
|
|
3,138,806
|
|
|
2,983,986
|
|
||
Effect of escalating costs to payment date (4.36/3.36 percent and 3.63/2.63 percent, respectively)
|
|
8,066,688
|
|
|
5,597,302
|
|
||
Estimated future decommissioning costs (undiscounted)
|
|
11,205,494
|
|
|
8,581,288
|
|
||
Effect of discounting obligation (using average risk-free interest rate of 3.01 percent and 2.82 percent for 2015 and 2014, respectively)
|
|
(6,891,392
|
)
|
|
(5,044,470
|
)
|
||
Discounted decommissioning cost obligation
|
|
$
|
4,314,102
|
|
|
$
|
3,536,818
|
|
|
|
|
|
|
||||
Assets held in external decommissioning trust
|
|
$
|
1,724,150
|
|
|
$
|
1,703,921
|
|
Underfunding of external decommissioning fund compared to the discounted decommissioning obligation
|
|
2,589,952
|
|
|
1,832,897
|
|
(Thousands of Dollars)
|
|
2015
|
|
2014
|
||||
Discounted decommissioning cost obligation - regulated basis
|
|
$
|
4,314,102
|
|
|
$
|
3,536,818
|
|
Differences in discount rate and market risk premium
|
|
(1,275,438
|
)
|
|
(1,275,101
|
)
|
||
Operating and maintenance costs not included for GAAP
|
|
(897,640
|
)
|
|
(547,135
|
)
|
||
Differences in cost studies (2011 versus 2014, no change in 2015)
|
|
—
|
|
|
323,365
|
|
||
Nuclear production decommissioning ARO - GAAP
|
|
$
|
2,141,024
|
|
|
$
|
2,037,947
|
|
(Thousands of Dollars)
|
|
2015
|
|
2014
|
|
2013
|
||||||
Annual decommissioning recorded as depreciation expense:
(a)
|
|
$
|
6,862
|
|
|
$
|
7,138
|
|
|
$
|
6,402
|
|
(a)
|
Decommissioning expense does not include depreciation of the capitalized nuclear asset retirement costs.
|
15.
|
Regulatory Assets and Liabilities
|
(Thousands of Dollars)
|
|
See Note(s)
|
|
Remaining
Amortization Period |
|
Dec. 31, 2015
|
|
Dec. 31, 2014
|
|||||||||||||
Regulatory Assets
|
|
|
|
|
|
Current
|
|
Noncurrent
|
|
Current
|
|
Noncurrent
|
|||||||||
Pension and retiree medical obligations
(a)
|
|
9
|
|
|
Various
|
|
$
|
90,249
|
|
|
$
|
1,368,115
|
|
|
$
|
95,054
|
|
|
$
|
1,402,360
|
|
Recoverable deferred taxes on AFUDC recorded in plant
|
|
1
|
|
|
Plant lives
|
|
—
|
|
|
408,994
|
|
|
—
|
|
|
395,329
|
|
||||
Net AROs
(b)
|
|
1, 13, 14
|
|
|
Plant lives
|
|
—
|
|
|
306,671
|
|
|
—
|
|
|
189,056
|
|
||||
Environmental remediation costs
|
|
1, 13
|
|
|
Various
|
|
6,702
|
|
|
166,883
|
|
|
4,594
|
|
|
149,812
|
|
||||
Contract valuation adjustments
(c)
|
|
1, 11
|
|
|
Term of related contract
|
|
26,379
|
|
|
128,780
|
|
|
17,730
|
|
|
144,273
|
|
||||
Depreciation differences
|
|
1
|
|
|
One to sixteen years
|
|
14,221
|
|
|
99,835
|
|
|
10,700
|
|
|
104,743
|
|
||||
Purchased power contract costs
|
|
13
|
|
|
Term of related contract
|
|
1,587
|
|
|
70,411
|
|
|
858
|
|
|
69,908
|
|
||||
PI EPU
|
|
12
|
|
|
Nineteen years
|
|
2,967
|
|
|
65,060
|
|
|
8,743
|
|
|
67,379
|
|
||||
Conservation programs
(d)
|
|
1
|
|
|
One to five years
|
|
31,793
|
|
|
50,047
|
|
|
61,866
|
|
|
58,174
|
|
||||
Nuclear refueling outage costs
|
|
1
|
|
|
One to two years
|
|
67,545
|
|
|
28,913
|
|
|
62,499
|
|
|
19,745
|
|
||||
State commission adjustments
|
|
1
|
|
|
Plant lives
|
|
988
|
|
|
26,708
|
|
|
571
|
|
|
26,092
|
|
||||
Losses on reacquired debt
|
|
4
|
|
|
Term of related debt
|
|
5,008
|
|
|
26,268
|
|
|
5,258
|
|
|
31,276
|
|
||||
Renewable resources and environmental initiatives
|
|
13
|
|
|
One to two years
|
|
33,014
|
|
|
23,565
|
|
|
24,891
|
|
|
29,902
|
|
||||
Property tax
|
|
|
|
One to six years
|
|
21,757
|
|
|
14,428
|
|
|
28,024
|
|
|
31,429
|
|
|||||
Gas pipeline inspection and remediation costs
|
|
12
|
|
|
One to four years
|
|
6,858
|
|
|
13,662
|
|
|
9,981
|
|
|
21,869
|
|
||||
Recoverable purchased natural gas and electric energy costs
|
|
1
|
|
|
One to two years
|
|
11,783
|
|
|
12,762
|
|
|
68,841
|
|
|
4,745
|
|
||||
Other
|
|
|
|
Various
|
|
23,779
|
|
|
47,639
|
|
|
44,448
|
|
|
28,124
|
|
|||||
Total regulatory assets
|
|
|
|
|
|
$
|
344,630
|
|
|
$
|
2,858,741
|
|
|
$
|
444,058
|
|
|
$
|
2,774,216
|
|
(a)
|
Includes
$257.5 million
and
$282.4 million
for the regulatory recognition of the NSP-Minnesota pension expense of which
$21.3 million
and
$23.8 million
is included in the current asset at
Dec. 31, 2015
and
2014
, respectively. Also included are
$12.5 million
and
$26.1 million
of regulatory assets related to the nonqualified pension plan of which
$4.0 million
and
$2.5 million
is included in the current asset at
Dec. 31, 2015
and
2014
, respectively.
|
(b)
|
Includes amounts recorded for future recovery of AROs, less amounts recovered through nuclear decommissioning accruals and gains from decommissioning investments.
|
(c)
|
Includes the fair value of certain long-term PPAs used to meet energy capacity requirements and valuation adjustments on natural gas commodity purchases.
|
(d)
|
Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions.
|
(Thousands of Dollars)
|
|
See Note(s)
|
|
Remaining
Amortization Period |
|
Dec. 31, 2015
|
|
Dec. 31, 2014
|
||||||||||||
Regulatory Liabilities
|
|
|
|
|
|
Current
|
|
Noncurrent
|
|
Current
|
|
Noncurrent
|
||||||||
Plant removal costs
|
|
1, 13
|
|
Plant lives
|
|
$
|
—
|
|
|
$
|
1,131,023
|
|
|
$
|
—
|
|
|
$
|
953,660
|
|
Investment tax credit deferrals
|
|
1, 6
|
|
Various
|
|
—
|
|
|
48,985
|
|
|
—
|
|
|
52,666
|
|
||||
Deferred income tax adjustment
|
|
1, 6
|
|
Various
|
|
—
|
|
|
46,737
|
|
|
—
|
|
|
48,622
|
|
||||
Renewable resources and environmental initiatives
|
|
12, 13
|
|
Various
|
|
6,271
|
|
|
41,869
|
|
|
10,427
|
|
|
10,376
|
|
||||
PSCo earnings test
|
|
12
|
|
One to two years
|
|
42,868
|
|
|
9,472
|
|
|
57,127
|
|
|
42,819
|
|
||||
Gas pipeline inspection costs
|
|
|
|
Various
|
|
1,140
|
|
|
4,273
|
|
|
13,970
|
|
|
642
|
|
||||
Gain from asset sales
|
|
12
|
|
Various
|
|
2,640
|
|
|
2,584
|
|
|
2,893
|
|
|
4,472
|
|
||||
Deferred electric and steam production and natural gas costs
|
|
1
|
|
Less than one year
|
|
146,235
|
|
|
—
|
|
|
88,527
|
|
|
—
|
|
||||
Conservation programs
(a)
|
|
1, 12
|
|
Less than one year
|
|
34,444
|
|
|
—
|
|
|
103,351
|
|
|
—
|
|
||||
Contract valuation adjustments
(b)
|
|
1, 11
|
|
Term of related contract
|
|
21,661
|
|
|
—
|
|
|
55,751
|
|
|
2,521
|
|
||||
DOE settlement
|
|
12
|
|
One to two years
|
|
16,139
|
|
|
—
|
|
|
49,492
|
|
|
—
|
|
||||
Low income discount program
|
|
|
|
Less than one year
|
|
2,475
|
|
|
—
|
|
|
3,355
|
|
|
—
|
|
||||
Excess depreciation reserve
|
|
|
|
Less than one year
|
|
60
|
|
|
—
|
|
|
10,999
|
|
|
—
|
|
||||
Other
|
|
|
|
Various
|
|
32,897
|
|
|
47,946
|
|
|
14,837
|
|
|
47,651
|
|
||||
Total regulatory liabilities
(c)
|
|
|
|
|
|
$
|
306,830
|
|
|
$
|
1,332,889
|
|
|
$
|
410,729
|
|
|
$
|
1,163,429
|
|
(a)
|
Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions.
|
(b)
|
Includes the fair value of certain long-term PPAs used to meet energy capacity requirements and valuation adjustments on natural gas commodity purchases.
|
(c)
|
Revenue subject to refund of
$75.0 million
and
$128.3 million
for 2015 and 2014, respectively, is included in other current liabilities.
|
16.
|
Other Comprehensive Income
|
|
|
Year Ended Dec. 31, 2015
|
||||||||||||||
(Thousands of Dollars)
|
|
Gains and
Losses on Cash Flow Hedges
|
|
Unrealized
Gains and Losses
on
Marketable
Securities
|
|
Defined Benefit
Pension and
Postretirement
Items
|
|
Total
|
||||||||
Accumulated other comprehensive (loss) income at Jan. 1
|
|
$
|
(57,628
|
)
|
|
$
|
110
|
|
|
$
|
(50,621
|
)
|
|
$
|
(108,139
|
)
|
Other comprehensive loss before reclassifications
|
|
(70
|
)
|
|
—
|
|
|
(7,906
|
)
|
|
(7,976
|
)
|
||||
Losses reclassified from net accumulated other comprehensive loss
|
|
2,836
|
|
|
—
|
|
|
3,526
|
|
|
6,362
|
|
||||
Net current period other comprehensive income (loss)
|
|
2,766
|
|
|
—
|
|
|
(4,380
|
)
|
|
(1,614
|
)
|
||||
Accumulated other comprehensive (loss) income at Dec. 31
|
|
$
|
(54,862
|
)
|
|
$
|
110
|
|
|
$
|
(55,001
|
)
|
|
$
|
(109,753
|
)
|
|
|
Year Ended Dec. 31, 2014
|
||||||||||||||
(Thousands of Dollars)
|
|
Gains and
Losses on Cash Flow Hedges |
|
Unrealized
Gains and Losses on Marketable Securities |
|
Defined Benefit
Pension and Postretirement Items |
|
Total
|
||||||||
Accumulated other comprehensive (loss) income at Jan. 1
|
|
$
|
(59,753
|
)
|
|
$
|
77
|
|
|
$
|
(46,599
|
)
|
|
$
|
(106,275
|
)
|
Other comprehensive (loss) income before reclassifications
|
|
(163
|
)
|
|
33
|
|
|
(7,517
|
)
|
|
(7,647
|
)
|
||||
Losses reclassified from net accumulated other comprehensive loss
|
|
2,288
|
|
|
—
|
|
|
3,495
|
|
|
5,783
|
|
||||
Net current period other comprehensive income (loss)
|
|
2,125
|
|
|
33
|
|
|
(4,022
|
)
|
|
(1,864
|
)
|
||||
Accumulated other comprehensive (loss) income at Dec. 31
|
|
$
|
(57,628
|
)
|
|
$
|
110
|
|
|
$
|
(50,621
|
)
|
|
$
|
(108,139
|
)
|
|
|
Amounts Reclassified
from Accumulated
Other Comprehensive
Loss
|
|
||||||
(Thousands of Dollars)
|
|
Year Ended
Dec. 31, 2015
|
|
Year Ended
Dec. 31, 2014
|
|
||||
(Gains) losses on cash flow hedges:
|
|
|
|
|
|
||||
Interest rate derivatives
|
|
$
|
4,515
|
|
(a)
|
$
|
3,836
|
|
(a)
|
Vehicle fuel derivatives
|
|
131
|
|
(b)
|
(55
|
)
|
(b)
|
||
Total, pre-tax
|
|
4,646
|
|
|
3,781
|
|
|
||
Tax benefit
|
|
(1,810
|
)
|
|
(1,493
|
)
|
|
||
Total, net of tax
|
|
2,836
|
|
|
2,288
|
|
|
||
Defined benefit pension and postretirement (gains) losses:
|
|
|
|
|
|
||||
Amortization of net loss
|
|
6,132
|
|
(c)
|
5,998
|
|
(c)
|
||
Prior service (credit) cost
|
|
(357
|
)
|
(c)
|
(344
|
)
|
(c)
|
||
Total, pre-tax
|
|
5,775
|
|
|
5,654
|
|
|
||
Tax benefit
|
|
(2,249
|
)
|
|
(2,159
|
)
|
|
||
Total, net of tax
|
|
3,526
|
|
|
3,495
|
|
|
||
Total amounts reclassified, net of tax
|
|
$
|
6,362
|
|
|
$
|
5,783
|
|
|
(a)
|
Included in interest charges.
|
(b)
|
Included in O&M expenses.
|
(c)
|
Included in the computation of net periodic pension and postretirement benefit costs. See Note 9 for details regarding these benefit plans.
|
•
|
Xcel Energy’s regulated electric utility segment generates, transmits and distributes electricity in Minnesota, Wisconsin, Michigan, North Dakota, South Dakota, Colorado, Texas and New Mexico. In addition, this segment includes sales for resale and provides wholesale transmission service to various entities in the United States. Regulated electric utility also includes wholesale commodity and trading operations.
|
•
|
Xcel Energy’s regulated natural gas utility segment transports, stores and distributes natural gas primarily in portions of Minnesota, Wisconsin, North Dakota, Michigan and Colorado.
|
•
|
Revenues from operating segments not included above are below the necessary quantitative thresholds and are therefore included in the all other category. Those primarily include steam revenue, appliance repair services, nonutility real estate activities, revenues associated with processing solid waste into refuse-derived fuel and investments in rental housing projects that qualify for low-income housing tax credits.
|
(Thousands of Dollars)
|
|
Regulated
Electric
|
|
Regulated
Natural Gas
|
|
All Other
|
|
Reconciling
Eliminations
|
|
Consolidated
Total
|
||||||||||
2015
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Operating revenues from external customers
|
|
$
|
9,275,986
|
|
|
$
|
1,672,081
|
|
|
$
|
76,419
|
|
|
$
|
—
|
|
|
$
|
11,024,486
|
|
Intersegment revenues
|
|
1,511
|
|
|
1,251
|
|
|
—
|
|
|
(2,762
|
)
|
|
—
|
|
|||||
Total revenues
|
|
$
|
9,277,497
|
|
|
$
|
1,673,332
|
|
|
$
|
76,419
|
|
|
$
|
(2,762
|
)
|
|
$
|
11,024,486
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Depreciation and amortization
|
|
$
|
962,565
|
|
|
$
|
154,892
|
|
|
$
|
7,067
|
|
|
$
|
—
|
|
|
$
|
1,124,524
|
|
Interest charges and financing costs
|
|
425,999
|
|
|
49,763
|
|
|
93,272
|
|
|
—
|
|
|
569,034
|
|
|||||
Income tax expense (benefit)
|
|
508,568
|
|
|
60,545
|
|
|
(26,394
|
)
|
|
—
|
|
|
542,719
|
|
|||||
Net income
|
|
921,403
|
|
|
106,023
|
|
|
(42,941
|
)
|
|
—
|
|
|
984,485
|
|
(Thousands of Dollars)
|
|
Regulated
Electric
|
|
Regulated
Natural Gas
|
|
All Other
|
|
Reconciling
Eliminations
|
|
Consolidated
Total
|
||||||||||
2014
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Operating revenues from external customers
|
|
$
|
9,465,890
|
|
|
$
|
2,142,738
|
|
|
$
|
77,507
|
|
|
$
|
—
|
|
|
$
|
11,686,135
|
|
Intersegment revenues
|
|
1,774
|
|
|
5,893
|
|
|
—
|
|
|
(7,667
|
)
|
|
—
|
|
|||||
Total revenues
|
|
$
|
9,467,664
|
|
|
$
|
2,148,631
|
|
|
$
|
77,507
|
|
|
$
|
(7,667
|
)
|
|
$
|
11,686,135
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Depreciation and amortization
|
|
$
|
866,746
|
|
|
$
|
144,661
|
|
|
$
|
7,638
|
|
|
$
|
—
|
|
|
$
|
1,019,045
|
|
Interest charges and financing costs
|
|
397,824
|
|
|
43,940
|
|
|
86,442
|
|
|
—
|
|
|
528,206
|
|
|||||
Income tax expense (benefit)
|
|
512,551
|
|
|
76,418
|
|
|
(65,154
|
)
|
|
—
|
|
|
523,815
|
|
|||||
Net income (loss)
|
|
890,535
|
|
|
128,559
|
|
|
2,212
|
|
|
—
|
|
|
1,021,306
|
|
(Thousands of Dollars)
|
|
Regulated
Electric
|
|
Regulated
Natural Gas
|
|
All Other
|
|
Reconciling
Eliminations
|
|
Consolidated
Total
|
||||||||||
2013
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Operating revenues from external customers
|
|
$
|
9,034,045
|
|
|
$
|
1,804,679
|
|
|
$
|
76,198
|
|
|
$
|
—
|
|
|
$
|
10,914,922
|
|
Intersegment revenues
|
|
1,332
|
|
|
2,717
|
|
|
—
|
|
|
(4,049
|
)
|
|
—
|
|
|||||
Total revenues
|
|
$
|
9,035,377
|
|
|
$
|
1,807,396
|
|
|
$
|
76,198
|
|
|
$
|
(4,049
|
)
|
|
$
|
10,914,922
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Depreciation and amortization
|
|
$
|
840,833
|
|
|
$
|
128,186
|
|
|
$
|
8,844
|
|
|
$
|
—
|
|
|
$
|
977,863
|
|
Interest charges and financing costs
|
|
386,198
|
|
|
44,927
|
|
|
104,895
|
|
|
—
|
|
|
536,020
|
|
|||||
Income tax expense (benefit)
|
|
495,044
|
|
|
25,543
|
|
|
(36,611
|
)
|
|
—
|
|
|
483,976
|
|
|||||
Net income (loss)
|
|
850,572
|
|
|
123,702
|
|
|
(26,040
|
)
|
|
—
|
|
|
948,234
|
|
18.
|
Summarized Quarterly Financial Data (Unaudited)
|
|
|
Quarter Ended
|
||||||||||||||
(Amounts in thousands, except per share data)
|
|
March 31, 2015
|
|
June 30, 2015
|
|
Sept. 30, 2015
|
|
Dec. 31, 2015
|
||||||||
Operating revenues
|
|
$
|
2,962,219
|
|
|
$
|
2,515,134
|
|
|
$
|
2,901,312
|
|
|
$
|
2,645,821
|
|
Operating income
|
|
350,845
|
|
|
422,845
|
|
|
785,812
|
|
|
441,010
|
|
||||
Net income
|
|
152,066
|
|
|
196,931
|
|
|
426,463
|
|
|
209,025
|
|
||||
EPS total — basic
|
|
$
|
0.30
|
|
|
$
|
0.39
|
|
|
$
|
0.84
|
|
|
$
|
0.41
|
|
EPS total — diluted
|
|
0.30
|
|
|
0.39
|
|
|
0.84
|
|
|
0.41
|
|
||||
Cash dividends declared per common share
|
|
0.32
|
|
|
0.32
|
|
|
0.32
|
|
|
0.32
|
|
|
|
Quarter Ended
|
||||||||||||||
(Amounts in thousands, except per share data)
|
|
March 31, 2014
|
|
June 30, 2014
|
|
Sept. 30, 2014
|
|
Dec. 31, 2014
|
||||||||
Operating revenues
|
|
$
|
3,202,604
|
|
|
$
|
2,685,096
|
|
|
$
|
2,869,807
|
|
|
$
|
2,928,628
|
|
Operating income
|
|
493,992
|
|
|
397,208
|
|
|
665,680
|
|
|
391,250
|
|
||||
Net income
|
|
261,221
|
|
|
195,164
|
|
|
368,582
|
|
|
196,339
|
|
||||
EPS total — basic
|
|
$
|
0.52
|
|
|
$
|
0.39
|
|
|
$
|
0.73
|
|
|
$
|
0.39
|
|
EPS total — diluted
|
|
0.52
|
|
|
0.39
|
|
|
0.73
|
|
|
0.39
|
|
||||
Cash dividends declared per common share
|
|
0.30
|
|
|
0.30
|
|
|
0.30
|
|
|
0.30
|
|
1.02*
|
Equity Distribution Agreement, dated March 5, 2013, between Xcel Energy Inc. and Merrill Lynch, Pierce, Fenner & Smith Incorporated (Exhibit 1.2 to Form 8-K dated March 5, 2013 (file no. 001-03034)).
|
|||||||||||
1.03*
|
Equity Distribution Agreement, dated March 5, 2013, between Xcel Energy Inc. and Morgan Stanley & Co. LLC (Exhibit 1.3 to Form 8-K dated March 5, 2013 (file no. 001-03034)).
|
|||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
PSCo
|
|
|
|
|
|
|
|
|
|
|
|
|
2.01*
t
|
Purchase and Sale Agreement by and between Riverside Energy Center, LLC and Calpine Development Holdings, Inc., as Sellers, and PSCo, as Purchaser, dated as of April 2, 2010 (excluding certain schedules and exhibits referred to in the agreement, as amended, which the Registrant agrees to furnish supplemental to the SEC upon request) (Exhibit 2.01 to Form 10-Q for the quarter ended June 30, 2010 (file no. 001-03034)).
|
|||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
Xcel Energy Inc.
|
||||||||||||
3.01*
|
Amended and Restated Articles of Incorporation of Xcel Energy Inc., as filed on May 17, 2012 (Exhibit 3.01 to Form 8-K dated May 16, 2012 (file no. 001-03034)).
|
|||||||||||
3.02*
|
Xcel Energy Inc. Bylaws, as amended on Feb. 17, 2016 (Exhibit 3.01 to Form 8-K dated Feb. 17, 2016 (file no. 001-03034)).
|
|||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
Xcel Energy Inc.
|
||||||||||||
4.01*
|
Indenture dated Dec. 1, 2000, between Xcel Energy Inc. and Wells Fargo Bank Minnesota, National Association, as Trustee. (Exhibit 4.01 to Form 8-K (file no. 001-03034) dated Dec. 14, 2000).
|
|||||||||||
4.02*
|
Supplemental Indenture No. 3 dated June 1, 2006 between Xcel Energy Inc. and Wells Fargo Bank, National Association, as Trustee, creating $300 million principal amount of 6.5 percent Senior Notes, Series due 2036 (Exhibit 4.01 to Current Report on Form 8-K (file no. 001-03034) dated June 6, 2006).
|
|||||||||||
4.03*
|
Supplemental Indenture No. 4 dated March 30, 2007 between Xcel Energy Inc. and Wells Fargo Bank, National Association, as Trustee, creating $253.979 million aggregate principal amount of 5.613 percent Senior Notes, Series due 2017 (Exhibit 4.01 to Form 8-K (file no. 001-03034) dated March 30, 2007).
|
|||||||||||
4.04*
|
Junior Subordinated Indenture, dated as of Jan. 1, 2008, by and between Xcel Energy Inc. and Wells Fargo Bank, National Association, as Trustee (Exhibit 4.01 to Form 8-K (file no. 001-03034) dated Jan. 16, 2008).
|
|||||||||||
4.05*
|
Supplemental Indenture No. 1, dated Jan. 16, 2008, by and between Xcel Energy Inc. and Wells Fargo Bank, National Association, as Trustee, creating $400 million principal amount of 7.6 percent Junior Subordinated Notes, Series due 2068 (Exhibit 4.02 to Form 8-K (file no. 001-03034) dated Jan. 16, 2008).
|
|||||||||||
4.06*
|
Replacement Capital Covenant, dated Jan. 16, 2008 (Exhibit 4.03 to Form 8-K (file no. 001-03034) dated Jan. 16, 2008).
|
|||||||||||
4.07*
|
Supplemental Indenture No. 5 dated as of May 1, 2010 between Xcel Energy Inc. and Wells Fargo Bank, National Association, as Trustee, creating $550 million principal amount of 4.70 percent Senior Notes, Series due May 15, 2020 (Exhibit 4.01 to Form 8-K (file no. 001-03034) dated May 10, 2010).
|
|||||||||||
4.08*
|
Supplemental Indenture No. 6 dated as of Sept. 1, 2011 between Xcel Energy Inc. and Wells Fargo Bank, National Association, as Trustee, creating $250 million principal amount of 4.80 percent Senior Notes, Series due Sept. 15, 2041 (Exhibit 4.01 to Form 8-K dated Sept. 12, 2011 (file no. 001-03034)).
|
|||||||||||
4.09*
|
Supplemental Indenture No. 7 dated as of May 1, 2013 between Xcel Energy and Wells Fargo Bank, NA, as Trustee, creating $450 million principal amount of 0.75 percent Senior Notes, Series due May 9, 2016 (Exhibit 4.01 to Form 8-K dated May 9, 2013 (file no. 001-03034)).
|
|||||||||||
4.10*
|
Supplemental Indenture No. 8 dated as of June 1, 2015 between Xcel Energy Inc. and Wells Fargo Bank, National Association, as Trustee, creating $250,000,000 aggregate principal amount of 1.20 percent Senior Notes, Series due June 1, 2017 and $250,000,000 aggregate principal amount of 3.30 percent Senior Notes, Series due June 1, 2025. (Exhibit 4.01 to Form 8-K dated June 1, 2015 (file no. 001-03034)).
|
|||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
NSP-Minnesota
|
||||||||||||
4.11*
|
Supplemental and Restated Trust Indenture, dated May 1, 1988, from NSP-Minnesota to Harris Trust and Savings Bank, as Trustee, providing for the issuance of First Mortgage Bonds (Exhibit 4.02 to Form 10-K of NSP-Minnesota for the year ended Dec. 31, 1988 (file no. 001-03034)). Supplemental Indentures between NSP-Minnesota and said Trustee, dated as follows:
|
|||||||||||
|
Supplemental Trust Indenture dated June 1, 1995, creating $250 million principal amount of 7.125 percent First Mortgage Bonds, Series due July 1, 2025 (Exhibit 4.01 to Form 8-K (file no. 001-03034) dated June 28, 1995).
|
|||||||||||
|
Supplemental Trust Indenture dated April 1, 1997, creating $100 million principal amount of 8.5 percent First Mortgage Bonds, Series due Sept. 1, 2019 and $27.9 million principal amount of 8.5 percent First Mortgage Bonds, Series due March 1, 2019 (Exhibit 4.47 to Form 10-K (file no. 001-03034) dated Dec. 31, 1997).
|
|
Supplemental Trust Indenture dated March 1, 1998, creating $150 million principal amount of 6.5 percent First Mortgage Bonds, Series due March 1, 2028 (Exhibit 4.01 to Form 8-K (file no. 001-03034) dated March 11, 1998).
|
|||||||||||
4.12*
|
Supplemental Trust Indenture dated Aug. 1, 2000 (Assignment and Assumption of Trust Indenture) (Exhibit 4.51 to NSP-Minnesota Form 10-12G (file no. 000-31709) dated Oct. 5, 2000).
|
|||||||||||
4.13*
|
Indenture, dated July 1, 1999, between NSP-Minnesota and Norwest Bank Minnesota, NA, as Trustee, providing for the issuance of Sr. Debt Securities. (Exhibit 4.01 to NSP-Minnesota Form 8-K (file no. 001-03034) dated July 21, 1999).
|
|||||||||||
4.14*
|
Supplemental Indenture, dated Aug. 18, 2000, supplemental to the Indenture dated July 1, 1999, among Xcel Energy, NSP-Minnesota and Wells Fargo Bank Minnesota, NA, as Trustee (Assignment and Assumption of Indenture) (Exhibit 4.63 to NSP-Minnesota Form 10-12G (file no. 000-31709) dated Oct. 5, 2000).
|
|||||||||||
4.15*
|
Supplemental Trust Indenture dated July 1, 2002 between NSP-Minnesota and BNY Midwest Trust Company, as successor Trustee, creating $69 million principal amount of 8.5 percent First Mortgage Bonds, Series due April 1, 2030 (Exhibit 4.06 to NSP-Minnesota Quarterly Report on Form 10-Q (file no. 001-31387) dated Sept. 30, 2002).
|
|||||||||||
4.16*
|
Supplemental Trust Indenture dated July 1, 2005 between NSP-Minnesota and BNY Midwest Trust Company, as successor Trustee, creating $250 million principal amount of 5.25 percent First Mortgage Bonds, Series due July 15, 2035 (Exhibit 4.01 to NSP-Minnesota Current Report on Form 8-K (file no. 001-31387) dated July 14, 2005).
|
|||||||||||
4.17*
|
Supplemental Trust Indenture dated May 1, 2006 between NSP-Minnesota and BNY Midwest Trust Company, as successor Trustee, creating $400 million principal amount of 6.25 percent First Mortgage Bonds, Series due June 1, 2036 (Exhibit 4.01 to NSP-Minnesota Current Report on Form 8-K (file no. 001-31387) dated May 18, 2006).
|
|||||||||||
4.18*
|
Supplemental Trust Indenture, dated June 1, 2007, between NSP-Minnesota and BNY Midwest Trust Company, as successor Trustee (Exhibit 4.01 to NSP-Minnesota Form 8-K (file no. 001-31387) dated June 19, 2007).
|
|||||||||||
4.19*
|
Supplemental Trust Indenture dated March 1, 2008 between NSP-Minnesota and The Bank of New York Trust Company, NA, as successor Trustee (Exhibit 4.01 to NSP-Minnesota Form 8-K (file no. 001-31387) dated March 11, 2008).
|
|||||||||||
4.20*
|
Supplemental Trust Indenture dated as of Nov. 1, 2009 between NSP-Minnesota and The Bank of New York Mellon Trust Co., NA, as successor Trustee, creating $300 million principal amount of 5.35 percent First Mortgage Bonds, Series due Nov. 1, 2039 (Exhibit 4.01 to NSP-Minnesota Form 8-K (file no. 001-31387) dated Nov. 16, 2009).
|
|||||||||||
4.21*
|
Supplemental Trust Indenture dated as of Aug. 1, 2010 between NSP-Minnesota and The Bank of New York Mellon Trust Company, NA, as successor Trustee, creating $250 million principal amount of 1.950 percent First Mortgage Bonds, Series due Aug. 15, 2015 and $250 million principal amount of 4.850 percent First Mortgage Bonds, Series due Aug. 15, 2040 (Exhibit 4.01 to NSP-Minnesota Form 8-K dated Aug. 4, 2010 (file no. 001-31387)).
|
|||||||||||
4.22*
|
Supplemental Trust Indenture dated as of Aug. 1, 2012 between NSP-Minnesota and The Bank of New York Mellon Trust Company, NA, as successor Trustee, creating $300 million principal amount of 2.15 percent First Mortgage Bonds, Series due Aug. 15, 2022 and $500 million principal amount of 3.40 percent First Mortgage Bonds, Series due Aug. 15, 2042 (Exhibit 4.01 to NSP-Minnesota Form 8-K dated Aug. 13, 2012 (file no. 001-31387)).
|
|||||||||||
4.23*
|
Supplemental Trust Indenture dated as of May 1, 2013 between NSP-Minnesota and The Bank of New York Mellon Trust Company, N.A., as successor Trustee, creating $400 million principal amount of 2.60 percent First Mortgage Bonds, Series due May 15, 2023 (Exhibit 4.01 to NSP-Minnesota Form 8-K dated May 20, 2013 (file no. 001-31387)).
|
|||||||||||
4.24*
|
Supplemental Trust Indenture dated as of May 1, 2014 between NSP-Minnesota and The Bank of New York Mellon Trust Company, N.A., as successor Trustee, creating $300 million principal amount of 4.125 percent First Mortgage Bonds, Series due May 15, 2044. (Exhibit 4.01 to NSP-Minnesota Form 8-K dated May 13, 2014 (file no. 001-31387)).
|
|||||||||||
4.25*
|
Supplemental Indenture dated as of Aug. 1, 2015 between NSP-Minnesota and The Bank of New York Mellon Trust Company, N.A., as successor Trustee, creating $300,000,000 principal amount of 2.20 percent First Mortgage Bonds, Series due Aug. 15, 2020 and $300,000,000 principal amount of 4.00 percent First Mortgage Bonds, Series due Aug. 15, 2045 (Exhibit 4.01 to Form 8-K of NSP-Minnesota dated Aug. 11, 2015 (file no. 001-31387)).
|
|||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
NSP-Wisconsin
|
||||||||||||
4.26*
|
Supplemental and Restated Trust Indenture, dated March 1, 1991, between NSP-Wisconsin and First Wisconsin Trust company, providing for the issuance of First Mortgage Bonds (Exhibit 4.01 to Registration Statement 33-39831).
|
|||||||||||
4.27*
|
Supplemental Trust Indenture, dated April 1, 1991 (Exhibit 4.01 to Form 10-Q (file no. 001-03140) for the quarter ended March 31, 1991).
|
|||||||||||
4.28*
|
Supplemental Trust Indenture, dated Dec. 1, 1996, between NSP-Wisconsin and Firstar Trust Company, as Trustee (Exhibit 4.01 to Form 8-K (file no. 001-03140) dated Dec. 12, 1996).
|
|||||||||||
4.29*
|
Trust Indenture dated Sept. 1, 2000, between NSP-Wisconsin and Firstar Bank, NA as Trustee (Exhibit 4.01 to Form 8-K (file no. 001-03140) dated Sept. 25, 2000).
|
|||||||||||
4.30*
|
Supplemental Trust Indenture dated Sept. 1, 2003 between NSP-Wisconsin and U.S. Bank National Association, supplementing indentures dated April 1, 1947 and March 1, 1991 (Exhibit 4.05 to Xcel Energy Form 10-Q (file no. 001-03034) for the quarter ended Sept. 30, 2003).
|
4.31*
|
Supplemental Trust Indenture dated as of Sept. 1, 2008 between NSP-Wisconsin and U.S. Bank National Association, as successor Trustee, creating $200 million principal amount of 6.375 percent First Mortgage Bonds, Series due Sept. 1, 2038 (Exhibit 4.01 of Form 8-K of NSP-Wisconsin dated Sept. 3, 2008 (file no. 001-03140)).
|
|||||||||||
4.32*
|
Supplemental Trust Indenture dated as of Oct. 1, 2012 between NSP-Wisconsin and U.S. Bank National Association, as successor Trustee, creating $100 million principal amount of 3.700 percent First Mortgage Bonds, Series due Oct. 1, 2042 (Exhibit 4.01 of Form 8-K of NSP-Wisconsin dated Oct. 10, 2012 (file no. 001-03140)).
|
|||||||||||
4.33*
|
Supplemental Trust Indenture dated as of June 1, 2014 between NSP-Wisconsin and U.S. Bank National Association, as successor Trustee, creating $100 million principal amount of 3.30 percent First Mortgage Bonds, Series due June 15, 2024. (Exhibit 4.01 of Form 8-K of NSP-Wisconsin dated June 23, 2014 (file no. 001-03140)).
|
|||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
PSCo
|
||||||||||||
4.34*
|
Indenture, dated as of Oct. 1, 1993, between PSCo and Morgan Guaranty Trust Company of New York, as trustee,
providing for the issuance of First Collateral Trust Bonds (Form 10-Q, Sept. 30, 1993 — Exhibit 4(a)).
|
|||||||||||
4.35*
|
Indentures supplemental to Indenture dated as of Oct. 1, 1993, between PSCo and Morgan Guaranty Trust Company of New York, as trustee:
|
|||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dated as of
|
|
Previous Filing: Form; Date or file no.
|
|
Exhibit
No.
|
|||||||
|
Nov. 1, 1993
|
|
S-3, (33-51167)
|
|
4(b)(2)
|
|
||||||
|
Jan. 1, 1994
|
|
10-K, 1993
|
|
4(b)(3)
|
|
||||||
|
Sept. 2, 1994
|
|
8-K, September 1994
|
|
4(b)
|
|
||||||
|
Nov. 1, 1996
|
|
10-K, 1996 (001-03280)
|
|
4(b)(3)
|
|
||||||
|
Feb. 1, 1997
|
|
10-Q, March 31, 1997 (001-03280)
|
|
4(a)
|
|
||||||
|
April 1, 1998
|
|
10-Q, March 31,1998 (001-03280)
|
|
4(b)
|
|
||||||
|
Aug. 15, 2002
|
|
10-Q, Sept. 30, 2002 (001-03280)
|
|
4.03
|
|
||||||
|
Aug. 1, 2005
|
|
8-K, Aug. 18, 2005 (001-03280)
|
|
4.02
|
|
||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
4.36*
|
Indenture dated July 1, 1999, between PSCo and The Bank of New York, providing for the issuance of Senior Debt Securities and First Supplemental Indenture dated July 15, 1999, between PSCo and The Bank of New York (Exhibits 4.1 and 4.2 to Form 8-K (file no. 001-03280) dated July 13, 1999).
|
|||||||||||
4.37*
|
Financing Agreement between Adams County, Colorado and PSCo, dated as of Aug. 1, 2005 relating to $129.5 million Adams County, Colorado Pollution Control Refunding Revenue Bonds, 2005 Series A (Exhibit 4.01 to PSCo Current Report on Form 8-K, dated Aug. 18, 2005, file no. 001-03280).
|
|||||||||||
4.38*
|
Supplemental Indenture, dated Aug. 1, 2007, between PSCo and U.S. Bank Trust National Association, as successor Trustee (Exhibit 4.01 to PSCo Form 8-K (file no. 001-03280) dated Aug. 8, 2007).
|
|||||||||||
4.39*
|
Supplemental Indenture dated as of Aug. 1, 2008, between PSCo and U.S. Bank Trust National Association, as successor Trustee, creating $300 million principal amount of 5.80 percent First Mortgage Bonds, Series No. 18 due 2018 and $300 million principal amount of 6.50 percent First Mortgage Bonds, Series No. 19 due 2038 (Exhibit 4.01 of Form 8-K of PSCo dated Aug. 6, 2008 (file no. 001-03280)).
|
|||||||||||
4.40*
|
Supplemental Indenture dated as of May 1, 2009 between PSCo and U.S. Bank Trust National Association, as successor Trustee, creating $400 million principal amount of 5.125 percent First Mortgage Bonds, Series No. 20 due 2019 (Exhibit 4.01 of Form 8-K of PSCo dated May 28, 2009 (file no. 001-03280)).
|
|||||||||||
4.41*
|
Supplemental Indenture dated as of Nov. 1, 2010 between PSCo and U.S. Bank National Association, as successor Trustee, creating $400 million principal amount of 3.200 percent First Mortgage Bonds, Series No. 21 due 2020 (Exhibit 4.01 of Form 8-K of PSCo dated Nov. 8, 2010 (file no. 001-03280)).
|
|||||||||||
4.42*
|
Supplemental Indenture dated as of Aug. 1, 2011 between PSCo and U.S. Bank National Association, as successor Trustee, creating $250 million principal amount of 4.75 percent First Mortgage Bonds, Series No. 22 due 2041 (Exhibit 4.01 to Form 8-K of PSCo dated Aug. 9, 2011 (file no. 001-03280)).
|
|||||||||||
4.43*
|
Supplemental Indenture dated as of Sept. 1, 2012 between PSCo and U.S. Bank National Association, as successor Trustee, creating $300 million principal amount of 2.25 percent First Mortgage Bonds, Series No. 23 due 2022 and $500 million principal amount of 3.60 percent First Mortgage Bonds, Series No. 24 due 2042 (Exhibit 4.01 to PSCo’s Form 8-K dated Sept. 11, 2012 (file no. 001-03280)).
|
|||||||||||
4.44*
|
Supplemental Indenture dated as of March 1, 2013 between PSCo and U.S. Bank National Association, as successor Trustee, creating $250 million principal amount of 2.50 percent First Mortgage Bonds, Series No. 25 due 2023 and $250 million principal amount of 3.95 percent First Mortgage Bonds, Series No. 26 due 2043 (Exhibit 4.01 to Form 8-K of PSCo dated March 26, 2013 (file no. 001-03280)).
|
Statement pursuant to Private Securities Litigation Reform Act of 1995.
|
||||||||||||
101
|
The following materials from Xcel Energy Inc.’s Annual Report on Form 10-K for the year ended Dec. 31, 2015 are formatted in XBRL (eXtensible Business Reporting Language): (i) the Consolidated Statements of Income, (ii) the Consolidated Statements of Comprehensive Income, (iii) the Consolidated Statements of Cash Flows, (iv) the Consolidated Balance Sheets, (v) the Consolidated Statements of Common Stockholders’ Equity, (vi) Consolidated Statements of Capitalization, (vii) Notes to Consolidated Financial Statements, (viii) document and entity information, (ix) Schedule I, and (x) Schedule II.
|
XCEL ENERGY INC.
CONDENSED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME
(amounts in thousands, except per share data)
|
|||||||||||
|
Year Ended Dec. 31
|
||||||||||
|
2015
|
|
2014
|
|
2013
|
||||||
Income
|
|
|
|
|
|
||||||
Equity earnings of subsidiaries
|
$
|
1,045,788
|
|
|
$
|
1,077,714
|
|
|
$
|
1,018,783
|
|
Total income
|
1,045,788
|
|
|
1,077,714
|
|
|
1,018,783
|
|
|||
Expenses and other deductions
|
|
|
|
|
|
||||||
Operating expenses
|
19,865
|
|
|
19,756
|
|
|
18,513
|
|
|||
Other income
|
(1,242
|
)
|
|
(537
|
)
|
|
(206
|
)
|
|||
Interest charges and financing costs
|
91,801
|
|
|
84,830
|
|
|
102,914
|
|
|||
Total expenses and other deductions
|
110,424
|
|
|
104,049
|
|
|
121,221
|
|
|||
Income before income taxes
|
935,364
|
|
|
973,665
|
|
|
897,562
|
|
|||
Income tax benefit
|
(49,121
|
)
|
|
(47,641
|
)
|
|
(50,672
|
)
|
|||
Net income
|
$
|
984,485
|
|
|
$
|
1,021,306
|
|
|
$
|
948,234
|
|
|
|
|
|
|
|
||||||
Other Comprehensive Income
|
|
|
|
|
|
||||||
Pension and retiree medical benefits, net of tax of $(2,777), $(2,528) and $5,897, respectively
|
$
|
(4,380
|
)
|
|
$
|
(4,022
|
)
|
|
$
|
4,714
|
|
Derivative instruments, net of tax of $1,764, $1,390 and $2,558, respectively
|
2,766
|
|
|
2,125
|
|
|
1,488
|
|
|||
Other, net of tax of $0, $21 and $117, respectively
|
—
|
|
|
33
|
|
|
176
|
|
|||
Other comprehensive (loss) income
|
(1,614
|
)
|
|
(1,864
|
)
|
|
6,378
|
|
|||
Comprehensive income
|
$
|
982,871
|
|
|
$
|
1,019,442
|
|
|
$
|
954,612
|
|
|
|
|
|
|
|
||||||
Weighted average common shares outstanding:
|
|
|
|
|
|
||||||
Basic
|
507,768
|
|
|
503,847
|
|
|
496,073
|
|
|||
Diluted
|
508,168
|
|
|
504,117
|
|
|
496,532
|
|
|||
Earnings per average common share:
|
|
|
|
|
|
||||||
Basic
|
$
|
1.94
|
|
|
$
|
2.03
|
|
|
$
|
1.91
|
|
Diluted
|
1.94
|
|
|
2.03
|
|
|
1.91
|
|
|||
|
|
|
|
|
|
||||||
Cash dividends declared per common share
|
1.28
|
|
|
1.20
|
|
|
1.11
|
|
|||
|
|
|
|
|
|
||||||
See Notes to Condensed Financial Statements
|
|
|
2015
|
|
2014
|
||||||||||||
(Thousands of Dollars)
|
|
Accounts Receivable
|
|
Accounts Payable
|
|
Accounts Receivable
|
|
Accounts Payable
|
||||||||
NSP-Minnesota
|
|
$
|
58,952
|
|
|
$
|
—
|
|
|
$
|
79,390
|
|
|
$
|
—
|
|
NSP-Wisconsin
|
|
17,391
|
|
|
—
|
|
|
20,117
|
|
|
—
|
|
||||
PSCo
|
|
114,524
|
|
|
—
|
|
|
38,646
|
|
|
—
|
|
||||
SPS
|
|
21,357
|
|
|
—
|
|
|
28,062
|
|
|
—
|
|
||||
Xcel Energy Services Inc.
|
|
73,054
|
|
|
—
|
|
|
75,954
|
|
|
—
|
|
||||
Xcel Energy Ventures Inc.
|
|
20,003
|
|
|
—
|
|
|
20,082
|
|
|
—
|
|
||||
Other subsidiaries of Xcel Energy Inc.
|
|
10,585
|
|
|
—
|
|
|
8,670
|
|
|
—
|
|
||||
|
|
$
|
315,866
|
|
|
$
|
—
|
|
|
$
|
270,921
|
|
|
$
|
—
|
|
(Amounts in Millions, Except Interest Rates)
|
|
Three Months Ended Dec. 31, 2015
|
||
Lending limit
|
|
$
|
250
|
|
Loan outstanding at period end
|
|
—
|
|
|
Average loan outstanding
|
|
38
|
|
|
Maximum loan outstanding
|
|
99
|
|
|
Weighted average interest rate, computed on a daily basis
|
|
0.38
|
%
|
|
Weighted average interest rate at end of period
|
|
N/A
|
|
|
Money pool interest income
|
|
$
|
—
|
|
(Amounts in Millions, Except Interest Rates)
|
|
Year Ended
Dec. 31, 2015
|
|
Year Ended
Dec. 31, 2014
|
|
Year Ended
Dec. 31, 2013
|
||||||
Lending limit
|
|
$
|
250
|
|
|
$
|
250
|
|
|
$
|
250
|
|
Loan outstanding at period end
|
|
—
|
|
|
16
|
|
|
72
|
|
|||
Average loan outstanding
|
|
27
|
|
|
25
|
|
|
88
|
|
|||
Maximum loan outstanding
|
|
141
|
|
|
250
|
|
|
243
|
|
|||
Weighted average interest rate, computed on a daily basis
|
|
0.42
|
%
|
|
0.22
|
%
|
|
0.30
|
%
|
|||
Weighted average interest rate at end of period
|
|
N/A
|
|
|
0.45
|
|
|
0.25
|
|
|||
Money pool interest income
|
|
$
|
0.1
|
|
|
$
|
0.1
|
|
|
$
|
0.3
|
|
XCEL ENERGY INC. AND SUBSIDIARIES
VALUATION AND QUALIFYING ACCOUNTS
YEARS ENDED DEC. 31, 2015, 2014 AND 2013
(amounts in thousands)
|
|||||||||||||||||||
|
|
|
Additions
|
|
|
|
|
||||||||||||
|
Balance at
Jan. 1
|
|
Charged to
Costs and
Expenses
|
|
Charged to
Other
Accounts
(a)
|
|
Deductions from
Reserves
(b)
|
|
Balance at
Dec. 31
|
||||||||||
Allowance for bad debts:
|
|
|
|
|
|
|
|
|
|
||||||||||
2015
|
$
|
57,719
|
|
|
$
|
36,074
|
|
|
$
|
11,784
|
|
|
$
|
53,689
|
|
|
$
|
51,888
|
|
2014
|
53,107
|
|
|
42,765
|
|
|
14,067
|
|
|
52,220
|
|
|
57,719
|
|
|||||
2013
|
51,394
|
|
|
37,627
|
|
|
14,469
|
|
|
50,383
|
|
|
53,107
|
|
|||||
NOL and tax credit valuation allowances:
|
|
|
|
|
|
|
|
|
|
||||||||||
2015
|
$
|
3,402
|
|
|
$
|
2,064
|
|
|
$
|
24,784
|
|
|
$
|
2,571
|
|
|
$
|
27,679
|
|
2014
|
3,263
|
|
|
139
|
|
|
—
|
|
|
—
|
|
|
3,402
|
|
|||||
2013
|
3,314
|
|
|
—
|
|
|
—
|
|
|
51
|
|
|
3,263
|
|
(a)
|
Recovery of amounts previously written off as related to allowance for bad debts. Accrual of valuation allowance for North Dakota ITC, offset to regulatory liability.
|
(b)
|
Deductions related to allowance for bad debts relates primarily to write-offs. Reductions to valuation allowances for North Dakota ITC carryforwards primarily due to a consolidated adjustment to the regulatory liability accrual referenced above. Reductions to valuation allowances for NOL carryforwards primarily due to changes in forecasted taxable income.
|
|
|
XCEL ENERGY INC.
|
|
|
|
Feb. 19, 2016
|
By:
|
/s/ TERESA S. MADDEN
|
|
|
Teresa S. Madden
|
|
|
Executive Vice President, Chief Financial Officer
|
|
|
(Principal Financial Officer)
|
Grant Date
|
Period of Restriction
|
Restricted Stock Units
|
[DATE]
|
[Period of Restriction]
|
[#]
|
Grant Date
|
Period of Restriction
|
Performance Period
|
Performance Share Units
(at Target)
|
[DATE]
|
[Period of Restriction]
|
[Performance Period]
|
[#]
|
(a)
|
The term “Committee” shall also include those persons to whom authority has been delegated under the Plan.
|
ARTICLE 7.
|
TERMINATION OF SERVICE
|
ARTICLE 10.
|
CHANGE IN CONTROL
|
|
Year Ended Dec. 31
|
||||||||||||||||||
|
2015
|
|
2014
|
|
2013
|
|
2012
|
|
2011
|
||||||||||
Earnings, as defined:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Pretax income from continuing operations
|
$
|
1,527,204
|
|
|
$
|
1,545,121
|
|
|
$
|
1,432,210
|
|
|
$
|
1,355,402
|
|
|
$
|
1,309,690
|
|
Add: Fixed charges
|
700,512
|
|
|
677,390
|
|
|
686,258
|
|
|
734,564
|
|
|
725,375
|
|
|||||
Add: Dividends from unconsolidated subsidiaries
|
40,128
|
|
|
36,707
|
|
|
36,416
|
|
|
33,470
|
|
|
34,034
|
|
|||||
Deduct: Equity earnings of unconsolidated subsidiaries
|
34,390
|
|
|
30,151
|
|
|
30,020
|
|
|
29,971
|
|
|
30,527
|
|
|||||
Total earnings, as defined
|
$
|
2,233,454
|
|
|
$
|
2,229,067
|
|
|
$
|
2,124,864
|
|
|
$
|
2,093,465
|
|
|
$
|
2,038,572
|
|
Fixed charges, as defined:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Interest charges
|
$
|
595,282
|
|
|
$
|
566,608
|
|
|
$
|
575,199
|
|
|
$
|
601,582
|
|
|
$
|
591,098
|
|
Interest charges on life insurance policy borrowings
|
233
|
|
|
214
|
|
|
245
|
|
|
310
|
|
|
332
|
|
|||||
Interest component of leases
|
104,997
|
|
|
110,568
|
|
|
110,814
|
|
|
132,672
|
|
|
133,945
|
|
|||||
Total fixed charges, as defined
|
$
|
700,512
|
|
|
$
|
677,390
|
|
|
$
|
686,258
|
|
|
$
|
734,564
|
|
|
$
|
725,375
|
|
Ratio of earnings to fixed charges
|
3.2
|
|
|
3.3
|
|
|
3.1
|
|
|
2.8
|
|
|
2.8
|
|
SUBSIDIARY
(a)
|
|
STATE OF INCORPORATION
|
|
PURPOSE
|
Northern States Power Company (a Minnesota corporation)
|
|
Minnesota
|
|
Electric and gas utility
|
Northern States Power Company (a Wisconsin corporation)
|
|
Wisconsin
|
|
Electric and gas utility
|
Public Service Company of Colorado
|
|
Colorado
|
|
Electric and gas utility
|
Southwestern Public Service Company
|
|
New Mexico
|
|
Electric utility
|
WestGas InterState, Inc.
|
|
Colorado
|
|
Natural gas transmission company
|
Xcel Energy Wholesale Group Inc.
|
|
Minnesota
|
|
Intermediate holding company for subsidiaries providing wholesale energy
|
Xcel Energy Markets Holdings Inc.
|
|
Minnesota
|
|
Intermediate holding company for subsidiaries providing energy marketing services
|
Xcel Energy International Inc.
|
|
Delaware
|
|
Intermediate holding company for international subsidiaries
|
Xcel Energy Ventures Inc.
|
|
Minnesota
|
|
Intermediate holding company for subsidiaries developing new businesses
|
Xcel Energy Retail Holdings Inc.
|
|
Minnesota
|
|
Intermediate holding company for subsidiaries providing services to retail customers
|
Xcel Energy Communications Group Inc.
|
|
Minnesota
|
|
Intermediate holding company for subsidiaries providing telecommunications and related services
|
Xcel Energy WYCO Inc.
|
|
Colorado
|
|
Intermediate holding company holding investment in WYCO
|
Xcel Energy Services Inc.
|
|
Delaware
|
|
Service company for Xcel Energy system
|
Xcel Energy Transmission Holding Company, LLC
|
|
Delaware
|
|
Intermediate holding company for subsidiaries developing and providing energy transmission services
|
Xcel Energy Venture Holdings, Inc.
|
|
Minnesota
|
|
Intermediate holding company holding investment in Energy Impact Fund
|
(a)
|
Certain insignificant subsidiaries are omitted.
|
•
|
No. 333-185610 (relating to the Nuclear Management Company, LLC NMC Savings and Retirement Plan)
|
•
|
No. 333-182136 (relating to the Xcel Energy Inc. Nonqualified Deferred Compensation Plan)
|
•
|
No. 333-172407 and 333-186856 (relating to the Xcel Energy 401(k) Savings Plan; and New Century Energies, Inc. Employees’ Savings and Stock Ownership plan for Bargaining Unit Employees and Former Non-Bargaining Unit Employees; and New Century Energies, Inc. Employee Investment Plan for Bargaining Unit Employees and Former Non-Bargaining Unit Employees)
|
•
|
No. 333-127218 (relating to the Xcel Energy Inc. Executive Annual Incentive Award Plan)
|
•
|
No. 333-48610 (relating to New Century Energies, Inc. Omnibus Incentive Plan; Public Service Company of Colorado Omnibus Incentive Plan; Southwestern Public Service Company 1989 Stock Incentive Plan; Southwestern Public Service Company Employee Investment Plan; and Southwestern Public Service Company Directors’ Deferred Compensation Plan)
|
•
|
No. 333-127217 (relating to the Xcel Energy 2005 Long-Term Incentive Plan)
|
•
|
No. 333-115754 and 333-175189 (relating to Stock Equivalent Plan for Non-Employee Directors)
|
•
|
No. 333-204325 (relating to the Xcel Energy 2015 Omnibus Incentive Plan)
|
•
|
No. 333-191673 (relating to the Xcel Energy Dividend Reinvestment and Cash Payment Plan)
|
•
|
No. 333-203664 (relating to senior debt securities, junior subordinated debt securities and common stock)
|
/s/ DELOITTE & TOUCHE LLP
|
|
Minneapolis, Minnesota
|
|
February 19, 2016
|
|
|
/s/ BEN FOWKE
|
|
|
Ben Fowke
|
|
|
Chairman, President, Chief Executive Officer and Director
|
|
/s/ Gail Koziara Boudreaux
|
|
|
Gail Koziara Boudreaux
|
|
|
Director
|
|
/s/ Richard K. Davis
|
|
|
Richard K. Davis
|
|
|
Director
|
|
/s/ Albert F. Moreno
|
|
|
Albert F. Moreno
|
|
|
Director
|
|
/s/ Richard T. O’Brien
|
|
|
Richard T. O’Brien
|
|
|
Director
|
|
/s/ Christopher J. Policinski
|
|
|
Christopher J. Policinski
|
|
|
Director
|
|
/s/ James Prokopanko
|
|
|
James Prokopanko
|
|
|
Director
|
|
/s/ A. Patricia Sampson
|
|
|
A. Patricia Sampson
|
|
|
Director
|
|
/s/ James J. Sheppard
|
|
|
James J. Sheppard
|
|
|
Director
|
|
/s/ David A. Westerlund
|
|
|
David A. Westerlund
|
|
|
Director
|
|
/s/ Kim Williams
|
|
|
Kim Williams
|
|
|
Director
|
|
/s/ Timothy V. Wolf
|
|
|
Timothy V. Wolf
|
|
|
Director
|
1.
|
I have reviewed this report on Form 10-K of Xcel Energy Inc. (a Minnesota corporation);
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
|
4.
|
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
|
a.
|
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
|
b.
|
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
|
c.
|
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
|
d.
|
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
|
5.
|
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
|
a.
|
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
|
b.
|
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
|
|
/s/ BEN FOWKE
|
|
Ben Fowke
|
|
Chairman, President, Chief Executive Officer and Director
|
1.
|
I have reviewed this report on Form 10-K of Xcel Energy Inc. (a Minnesota corporation);
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
|
4.
|
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
|
a.
|
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
|
b.
|
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
|
c.
|
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
|
d.
|
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
|
5.
|
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
|
a.
|
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
|
b.
|
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
|
|
/s/ TERESA S. MADDEN
|
|
Teresa S. Madden
|
|
Executive Vice President, Chief Financial Officer
|
(1)
|
The Form 10-K fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
|
(2)
|
The information contained in the Form 10-K fairly presents, in all material respects, the financial condition and results of operations of Xcel Energy as of the dates and for the periods expressed in the Form 10-K.
|
|
/s/ BEN FOWKE
|
|
Ben Fowke
|
|
Chairman, President, Chief Executive Officer and Director
|
|
|
|
/s/ TERESA S. MADDEN
|
|
Teresa S. Madden
|
|
Executive Vice President, Chief Financial Officer
|
•
|
Economic conditions, including inflation rates, monetary fluctuations and their impact on capital expenditures;
|
•
|
The risk of a significant slowdown in growth or decline in the U.S. economy, the risk of delay in growth recovery in the U.S. economy or the risk of increased cost for insurance premiums, security and other items as a consequence of past or future terrorist attacks;
|
•
|
Trade, monetary, fiscal, taxation and environmental policies of governments, agencies and similar organizations in geographic areas where Xcel Energy has a financial interest;
|
•
|
Customer business conditions, including demand for their products or services and supply of labor and materials used in creating their products and services;
|
•
|
Financial or regulatory accounting principles or policies imposed by the FASB, the SEC, the FERC and similar entities with regulatory oversight;
|
•
|
Availability or cost of capital such as changes in: interest rates; market perceptions of the utility industry, Xcel Energy Inc. or any of its subsidiaries; or security ratings;
|
•
|
Factors affecting utility and nonutility operations such as unusual weather conditions; catastrophic weather-related damage; unscheduled generation outages, maintenance or repairs; unanticipated changes to fossil fuel, nuclear fuel or natural gas supply costs or availability due to higher demand, shortages, transportation problems or other developments; nuclear or environmental incidents; cyber incidents; or electric transmission or natural gas pipeline constraints;
|
•
|
Employee workforce factors, including loss or retirement of key executives, collective-bargaining agreements with union employees, or work stoppages;
|
•
|
Increased competition in the utility industry or additional competition in the markets served by Xcel Energy Inc. and its subsidiaries;
|
•
|
State, federal and foreign legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rate structures and affect the speed and degree to which competition enters the electric and natural gas markets; industry restructuring initiatives; transmission system operation and/or administration initiatives; recovery of investments made under traditional regulation; nature of competitors entering the industry; retail wheeling; a new pricing structure; and former customers entering the generation market;
|
•
|
Environmental laws and regulations, including legislation and regulations relating to climate change, and the associated cost of compliance;
|
•
|
Rate-setting policies or procedures of regulatory entities, including environmental externalities, which are values established by regulators assigning environmental costs to each method of electricity generation when evaluating generation resource options;
|
•
|
Nuclear regulatory policies and procedures, including operating regulations and spent nuclear fuel storage;
|
•
|
Social attitudes regarding the utility and power industries;
|
•
|
Cost and other effects of legal and administrative proceedings, settlements, investigations and claims;
|
•
|
Technological developments that result in competitive disadvantages and create the potential for impairment of existing assets;
|
•
|
Risks associated with implementations of new technologies; and
|
•
|
Other business or investment considerations that may be disclosed from time to time in Xcel Energy Inc.’s SEC filings, including “Risk Factors” in Item 1A of this Form 10-K, or in other publicly disseminated written documents.
|