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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)
|
|
Cheyenne
|
Cheyenne Light, Fuel and Power Company
|
Eloigne
|
Eloigne Company
|
NCE
|
New Century Energies, Inc.
|
NMC
|
Nuclear Management Company, LLC
|
NSP-Minnesota
|
Northern States Power Company, a Minnesota corporation
|
NSP System
|
The electric production and transmission system of NSP-Minnesota and NSP-Wisconsin operated on an integrated basis and managed by NSP-Minnesota
|
NSP-Wisconsin
|
Northern States Power Company, a Wisconsin corporation
|
PSCo
|
Public Service Company of Colorado
|
PSRI
|
P.S.R. Investments, Inc.
|
SPS
|
Southwestern Public Service Co.
|
Utility subsidiaries
|
NSP-Minnesota, NSP-Wisconsin, PSCo and SPS
|
WGI
|
WestGas InterState, Inc.
|
WYCO
|
WYCO Development LLC
|
Xcel Energy
|
Xcel Energy Inc. and its subsidiaries
|
|
|
Federal and State Regulatory Agencies
|
|
ASLB
|
Atomic Safety and Licensing Board
|
CFTC
|
Commodity Futures Trading Commission
|
CPUC
|
Colorado Public Utilities Commission
|
D.C. Circuit
|
United States Court of Appeals for the District of Columbia Circuit
|
DOC
|
Minnesota Department of Commerce
|
DOE
|
United States Department of Energy
|
DOI
|
United States Department of the Interior
|
DOT
|
United States Department of Transportation
|
EPA
|
United States Environmental Protection Agency
|
FERC
|
Federal Energy Regulatory Commission
|
IRS
|
Internal Revenue Service
|
MPCA
|
Minnesota Pollution Control Agency
|
MPSC
|
Michigan Public Service Commission
|
MPUC
|
Minnesota Public Utilities Commission
|
NDPSC
|
North Dakota Public Service Commission
|
NERC
|
North American Electric Reliability Corporation
|
NMAG
|
New Mexico Attorney General
|
NMPRC
|
New Mexico Public Regulation Commission
|
NRC
|
Nuclear Regulatory Commission
|
PNM
|
Public Service Company of New Mexico
|
PSCW
|
Public Service Commission of Wisconsin
|
PUCT
|
Public Utility Commission of Texas
|
SDPUC
|
South Dakota Public Utilities Commission
|
SEC
|
Securities and Exchange Commission
|
WDNR
|
Wisconsin Department of Natural Resources
|
|
|
CWIP
|
Construction work in progress
|
EEI
|
Edison Electric Institute
|
EGU
|
Electric generating unit
|
EPS
|
Earnings per share
|
ERCOT
|
Electric Reliability Council of Texas
|
ETR
|
Effective tax rate
|
FASB
|
Financial Accounting Standards Board
|
FTR
|
Financial transmission right
|
FTY
|
Forecast test year
|
GAAP
|
Generally accepted accounting principles
|
GHG
|
Greenhouse gas
|
HTY
|
Historic test year
|
IFRS
|
International Financial Reporting Standards
|
LCM
|
Life cycle management
|
LLW
|
Low-level radioactive waste
|
LNG
|
Liquefied natural gas
|
MACT
|
Maximum achievable control technology
|
MGP
|
Manufactured gas plant
|
MISO
|
Midcontinent Independent Transmission System Operator, Inc.
|
Moody’s
|
Moody’s Investor Services
|
MVP
|
Multi-value project
|
Native load
|
Customer demand of retail and wholesale customers that a utility has an obligation to serve
under statute or long-term contract
|
NEI
|
Nuclear Energy Institute
|
NOL
|
Net operating loss
|
NOx
|
Nitrogen oxide
|
NOV
|
Notice of violation
|
NSPS
|
New source performance standard
|
NTC
|
Notifications to construct
|
NYISO
|
New York Independent System Operator
|
O&M
|
Operating and maintenance
|
OCC
|
Office of Consumer Counsel
|
OCI
|
Other comprehensive income
|
PCB
|
Polychlorinated biphenyl
|
PFS
|
Private Fuel Storage, LLC
|
PJM
|
PJM Interconnection, LLC
|
PM
|
Particulate matter
|
PPA
|
Purchased power agreement
|
PRP
|
Potentially responsible party
|
PSP
|
Performance share plan
|
PTC
|
Production tax credit
|
PV
|
Photovoltaic
|
QF
|
Qualifying facilities
|
REC
|
Renewable energy credit
|
RFP
|
Request for proposal
|
ROE
|
Return on equity
|
RPS
|
Renewable portfolio standards
|
RSG
|
Revenue sufficiency guarantee
|
RSU
|
Restricted stock unit
|
RTO
|
Regional Transmission Organization
|
ROFR
|
Right of first refusal
|
SCR
|
Selective catalytic reduction
|
Sharyland
|
Sharyland Distribution and Transmission Services, LLC
|
SIP
|
State implementation plan
|
SO
2
|
Sulfur dioxide
|
SPP
|
Southwest Power Pool, Inc.
|
Standard & Poor’s
|
Standard & Poor’s Ratings Services
|
TSR
|
Total shareholder return
|
|
|
Measurements
|
|
Bcf
|
Billion cubic feet
|
GWh
|
Gigawatt hours
|
KV
|
Kilovolts
|
KWh
|
Kilowatt hours
|
Mcf
|
Thousand cubic feet
|
MMBtu
|
Million British thermal units
|
MW
|
Megawatts
|
MWh
|
Megawatt hours
|
•
|
CIP
— The CIP recovers the costs of programs that help customers save energy. The CIP includes a comprehensive list of programs that benefit all customers including Saver’s Switch
®
, energy efficiency rebates and energy audits.
|
•
|
EIR
— The EIR recovers the costs of environmental improvement projects.
|
•
|
RDF
— The RDF allocates money collected from retail customers to support the research and development of emerging renewable energy projects and technologies.
|
•
|
RES
— The RES recovers the cost of new renewable generation.
|
•
|
SEP
— The SEP recovers costs related to various energy policies approved by the Minnesota legislature.
|
•
|
TCR
— The TCR recovers costs associated with new investments in electric transmission.
|
•
|
Infrastructure
— The Infrastructure rider recovers costs associated with specific investments in generation and incremental property taxes.
|
|
System Peak Demand (in MW)
|
||||||||||
|
2011
|
|
2012
|
|
2013
|
|
2014 Forecast
|
||||
NSP System
|
9,792
|
|
|
9,475
|
|
|
9,524
|
|
|
9,212
|
|
•
|
The ALJ’s report focused on meeting a portion of the solar mandate even though the docket was designed to meet our resource need;
|
•
|
Solar acquisition to meet the solar mandate should be conducted separately to encourage competition among solar developers;
|
•
|
One or more gas fueled plants should be selected because they are large enough to meet the range of reasonably expected need, are least cost, and comply with environmental regulations; and
|
•
|
Resource need uncertainty should be addressed through contract options to delay or cancel resources.
|
•
|
A 200 MW ownership project for the Pleasant Valley wind farm in Minnesota, which is expected to be operational by October 2015;
|
•
|
A 150 MW ownership project for the Border Winds wind farm in North Dakota, which is expected to be operational by 2015;
|
•
|
A 200 MW PPA with Geronimo Energy, LLC for the Odell wind farm in Minnesota; and
|
•
|
A 200 MW PPA with Geronimo Energy, LLC for the Courtenay wind farm in North Dakota.
|
|
Year Ended Dec. 31
|
||||||||||||||||
|
2013
|
|
2012
|
|
2011
|
||||||||||||
NSP System
|
Millions of
KWh
|
|
Percent of
Generation
|
|
Millions of
KWh
|
|
Percent of
Generation
|
|
Millions of
KWh
|
|
Percent of
Generation
|
||||||
Coal
|
15,844
|
|
|
36
|
%
|
|
16,023
|
|
|
35
|
%
|
|
20,131
|
|
|
44
|
%
|
Nuclear
|
12,161
|
|
|
28
|
|
|
13,231
|
|
|
29
|
|
|
13,332
|
|
|
29
|
|
Natural Gas
|
5,550
|
|
|
13
|
|
|
6,200
|
|
|
13
|
|
|
3,016
|
|
|
7
|
|
Wind
(a)
|
5,481
|
|
|
13
|
|
|
5,443
|
|
|
12
|
|
|
4,312
|
|
|
9
|
|
Hydroelectric
|
3,223
|
|
|
7
|
|
|
3,193
|
|
|
7
|
|
|
3,444
|
|
|
8
|
|
Other
(b)
|
1,323
|
|
|
3
|
|
|
1,617
|
|
|
4
|
|
|
1,453
|
|
|
3
|
|
Total
|
43,582
|
|
|
100
|
%
|
|
45,707
|
|
|
100
|
%
|
|
45,688
|
|
|
100
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Owned generation
|
29,249
|
|
|
67
|
%
|
|
31,365
|
|
|
69
|
%
|
|
31,668
|
|
|
69
|
%
|
Purchased generation
|
14,333
|
|
|
33
|
|
|
14,342
|
|
|
31
|
|
|
14,020
|
|
|
31
|
|
Total
|
43,582
|
|
|
100
|
%
|
|
45,707
|
|
|
100
|
%
|
|
45,688
|
|
|
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 0.008, 0.006, and 0.003 net million KWh for 2013, 2012, and 2011, respectively.
|
|
|
Coal
(a)
|
|
Nuclear
|
|
Natural Gas
|
|
Weighted
Average Owned Fuel Cost
|
|||||||||||||||||
NSP System Generating Plants
|
|
Cost
|
|
Percent
|
|
Cost
|
|
Percent
|
|
Cost
|
|
Percent
|
|
||||||||||||
2013
|
|
$
|
2.20
|
|
|
49
|
%
|
|
$
|
0.95
|
|
|
40
|
%
|
|
$
|
5.08
|
|
|
11
|
%
|
|
$
|
2.03
|
|
2012
|
|
2.13
|
|
|
47
|
|
|
0.90
|
|
|
42
|
|
|
4.21
|
|
|
11
|
|
|
1.88
|
|
||||
2011
|
|
2.06
|
|
|
55
|
|
|
0.89
|
|
|
40
|
|
|
6.56
|
|
|
5
|
|
|
1.82
|
|
(a)
|
Includes refuse-derived fuel and wood.
|
•
|
Current nuclear fuel supply contracts cover 100 percent of uranium concentrates requirements through 2018 and approximately 67 percent of the requirements for 2019 through 2026.
|
•
|
Current contracts for conversion services cover 100 percent of the requirements through 2021 and approximately 57 percent of the requirements for 2022 through 2026.
|
•
|
Current enrichment service contracts cover 100 percent of the requirements through 2024 and approximately 48 percent of the requirements for 2025 through 2026.
|
•
|
ECA
— The ECA recovers fuel and purchased power costs. Short-term sales margins are shared with retail customers through the ECA. The ECA is revised quarterly.
|
•
|
PCCA
— The PCCA recovers purchased capacity payments.
|
•
|
SCA
— The SCA recovers the difference between PSCo’s actual cost of fuel and the amount of these costs recovered under its base steam service rates. The SCA rate is revised annually in January, as well as on an interim basis to coincide with changes in fuel costs.
|
•
|
DSMCA
— The DSMCA recovers DSM, interruptible service option credit costs and performance initiatives for achieving various energy savings goals.
|
•
|
RESA
— The RESA recovers the incremental costs of compliance with the RES and is set at its maximum level of two percent of the customer’s total bill.
|
•
|
Wind Energy Service
— Wind Energy Service is a premium service for those customers who voluntarily choose to pay an additional charge to increase the level of renewable resource generation used to meet the customer’s load requirements.
|
•
|
TCA
— The TCA recovers transmission plant revenue requirements and allows for a return on CWIP outside of rate cases.
|
|
System Peak Demand (in MW)
|
||||||||||
|
2011
|
|
2012
|
|
2013
|
|
2014 Forecast
|
||||
PSCo
|
6,896
|
|
|
6,689
|
|
|
6,678
|
|
|
6,459
|
|
•
|
The addition of 450 MW of wind generation PPAs. This additional wind would bring the installed capacity on PSCo’s system in Colorado to 2,650 MW;
|
•
|
The addition of 170 MW of utility-scale solar generation PPAs. PSCo currently has about 80 MW of utility-scale solar and approximately 188 MW of customer-sited solar generation;
|
•
|
The addition of 317 MW of natural gas fired generation PPAs, which would come from existing power plants that previously supplied PSCo, but at reduced prices;
|
•
|
Accelerated retirement of the 109 MW, coal-fired Unit 4 at the Arapahoe generating station, which occurred at the end of 2013;
|
•
|
Confirmation of the retirement of the 45 MW, coal-fired Unit 3 at the Arapahoe generating station, which occurred at the end of 2013; and
|
•
|
The continued operation of Cherokee generating station’s Unit 4 as a natural gas facility after 2017.
|
|
Year Ended Dec. 31
|
||||||||||||||||
|
2013
|
|
2012
|
|
2011
|
||||||||||||
PSCo
|
Millions of
KWh
|
|
Percent of
Generation
|
|
Millions of
KWh
|
|
Percent of
Generation
|
|
Millions of
KWh
|
|
Percent of
Generation
|
||||||
Coal
|
19,647
|
|
|
56
|
%
|
|
21,367
|
|
|
59
|
%
|
|
22,065
|
|
|
61
|
%
|
Natural Gas
|
7,565
|
|
|
22
|
|
|
7,930
|
|
|
22
|
|
|
8,896
|
|
|
24
|
|
Wind
(a)
|
6,750
|
|
|
19
|
|
|
5,752
|
|
|
16
|
|
|
4,518
|
|
|
12
|
|
Hydroelectric
|
655
|
|
|
2
|
|
|
590
|
|
|
2
|
|
|
681
|
|
|
2
|
|
Other
(b)
|
250
|
|
|
1
|
|
|
263
|
|
|
1
|
|
|
324
|
|
|
1
|
|
Total
|
34,867
|
|
|
100
|
%
|
|
35,902
|
|
|
100
|
%
|
|
36,484
|
|
|
100
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Owned generation
|
22,873
|
|
|
66
|
%
|
|
23,766
|
|
|
66
|
%
|
|
23,743
|
|
|
65
|
%
|
Purchased generation
|
11,994
|
|
|
34
|
|
|
12,136
|
|
|
34
|
|
|
12,741
|
|
|
35
|
|
Total
|
34,867
|
|
|
100
|
%
|
|
35,902
|
|
|
100
|
%
|
|
36,484
|
|
|
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)
|
Includes energy from other sources, including nuclear, solar, biomass, oil and refuse. Distributed generation from the Solar*Rewards program is not included, and
was approximately 0.172, 0.133, and 0.137 net million KWh for 2013, 2012, and 2011, respectively.
|
|
|
Coal
|
|
Natural Gas
|
|
Weighted Average Owned Fuel Cost
|
||||||||||||
PSCo Generating Plants
|
|
Cost
|
|
Percent
|
|
Cost
|
|
Percent
|
|
|||||||||
2013
|
|
$
|
1.84
|
|
|
80
|
%
|
|
$
|
4.86
|
|
|
20
|
%
|
|
$
|
2.45
|
|
2012
|
|
1.77
|
|
|
78
|
|
|
4.25
|
|
|
22
|
|
|
2.31
|
|
|||
2011
|
|
1.77
|
|
|
76
|
|
|
4.98
|
|
|
24
|
|
|
2.54
|
|
•
|
DCRF
— The DCRF rider recovers distribution costs in Texas.
|
•
|
DRC
— The DRC rider recovers deferred costs associated with renewable energy programs in New Mexico.
|
•
|
EECRF
— The EECRF rider recovers costs associated with providing energy efficiency programs in Texas.
|
•
|
EE rider
— The EE rider recovers costs associated with providing energy efficiency programs in New Mexico.
|
•
|
FPPCAC
— The FPPCAC adjusts monthly to recover the difference between the actual fuel and purchased power costs and the amount included in base rates of SPS’ New Mexico retail jurisdiction.
|
•
|
PCRF
— The PCRF rider allows recovery of certain purchased power costs in Texas.
|
•
|
TCRF
— The TCRF rider recovers transmission infrastructure improvement costs and changes in wholesale transmission charges in Texas.
|
|
System Peak Demand (in MW)
|
||||||||||
|
2011
|
|
2012
|
|
2013
|
|
2014 Forecast
|
||||
SPS
|
5,210
|
|
|
5,265
|
|
|
5,056
|
|
|
5,119
|
|
|
Year Ended Dec. 31
|
||||||||||||||||
|
2013
|
|
2012
|
|
2011
|
||||||||||||
SPS
|
Millions of
KWh
|
|
Percent of
Generation
|
|
Millions of
KWh
|
|
Percent of
Generation
|
|
Millions of
KWh
|
|
Percent of
Generation
|
||||||
Coal
|
14,184
|
|
|
49
|
%
|
|
14,005
|
|
|
49
|
%
|
|
14,818
|
|
|
48
|
%
|
Natural Gas
|
11,235
|
|
|
38
|
|
|
12,088
|
|
|
43
|
|
|
13,167
|
|
|
43
|
|
Wind
(a)
|
3,507
|
|
|
12
|
|
|
2,103
|
|
|
7
|
|
|
2,386
|
|
|
8
|
|
Other
(b)
|
167
|
|
|
1
|
|
|
177
|
|
|
1
|
|
|
409
|
|
|
1
|
|
Total
|
29,093
|
|
|
100
|
%
|
|
28,373
|
|
|
100
|
%
|
|
30,780
|
|
|
100
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Owned generation
|
18,814
|
|
|
65
|
%
|
|
19,940
|
|
|
70
|
%
|
|
19,310
|
|
|
63
|
%
|
Purchased generation
|
10,279
|
|
|
35
|
|
|
8,433
|
|
|
30
|
|
|
11,470
|
|
|
37
|
|
Total
|
29,093
|
|
|
100
|
%
|
|
28,373
|
|
|
100
|
%
|
|
30,780
|
|
|
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)
|
Includes energy from other sources, including nuclear, hydroelectric, solar, biomass, oil and refuse. Distributed generation from the Solar*Rewards program is not included, was approximately 0.011, 0.008, and 0.006 net million KWh for 2013, 2012, and 2011, respectively.
|
|
|
Coal
|
|
Natural Gas
|
|
Weighted
Average Owned Fuel Cost
|
||||||||||||
SPS Generating Plants
|
|
Cost
|
|
Percent
|
|
Cost
|
|
Percent
|
|
|||||||||
2013
|
|
$
|
2.14
|
|
|
71
|
%
|
|
$
|
3.97
|
|
|
29
|
%
|
|
$
|
2.68
|
|
2012
|
|
1.87
|
|
|
67
|
|
|
2.99
|
|
|
33
|
|
|
2.24
|
|
|||
2011
|
|
1.89
|
|
|
67
|
|
|
4.37
|
|
|
33
|
|
|
2.71
|
|
|
Year Ended Dec. 31
|
||||||||||
|
2013
|
|
2012
|
|
2011
|
||||||
Electric sales (Millions of KWh)
|
|
|
|
|
|
||||||
Residential
|
25,306
|
|
|
25,033
|
|
|
25,278
|
|
|||
Large commercial and industrial
|
27,206
|
|
|
27,396
|
|
|
27,419
|
|
|||
Small commercial and industrial
|
35,873
|
|
|
35,660
|
|
|
35,597
|
|
|||
Public authorities and other
|
1,098
|
|
|
1,109
|
|
|
1,135
|
|
|||
Total retail
|
89,483
|
|
|
89,198
|
|
|
89,429
|
|
|||
Sales for resale
|
15,065
|
|
|
15,781
|
|
|
20,177
|
|
|||
Total energy sold
|
104,548
|
|
|
104,979
|
|
|
109,606
|
|
|||
|
|
|
|
|
|
||||||
Number of customers at end of period
|
|
|
|
|
|
||||||
Residential
|
2,965,717
|
|
|
2,940,024
|
|
|
2,919,660
|
|
|||
Large commercial and industrial
|
1,132
|
|
|
1,147
|
|
|
1,129
|
|
|||
Small commercial and industrial
|
422,553
|
|
|
419,618
|
|
|
415,755
|
|
|||
Public authorities and other
|
67,998
|
|
|
68,510
|
|
|
69,350
|
|
|||
Total retail
|
3,457,400
|
|
|
3,429,299
|
|
|
3,405,894
|
|
|||
Wholesale
|
65
|
|
|
75
|
|
|
78
|
|
|||
Total customers
|
3,457,465
|
|
|
3,429,374
|
|
|
3,405,972
|
|
|||
|
|
|
|
|
|
||||||
Electric revenues (Thousands of Dollars)
|
|
|
|
|
|
||||||
Residential
|
$
|
2,906,208
|
|
|
$
|
2,713,575
|
|
|
$
|
2,712,340
|
|
Large commercial and industrial
|
1,694,720
|
|
|
1,534,728
|
|
|
1,616,596
|
|
|||
Small commercial and industrial
|
3,248,586
|
|
|
3,023,154
|
|
|
3,025,416
|
|
|||
Public authorities and other
|
138,126
|
|
|
130,538
|
|
|
129,826
|
|
|||
Total retail
|
7,987,640
|
|
|
7,401,995
|
|
|
7,484,178
|
|
|||
Wholesale
|
693,728
|
|
|
687,912
|
|
|
936,875
|
|
|||
Other electric revenues
|
352,677
|
|
|
427,389
|
|
|
345,540
|
|
|||
Total electric revenues
|
$
|
9,034,045
|
|
|
$
|
8,517,296
|
|
|
$
|
8,766,593
|
|
|
|
|
|
|
|
||||||
KWh sales per retail customer
|
25,882
|
|
|
26,011
|
|
|
26,257
|
|
|||
Revenue per retail customer
|
$
|
2,310
|
|
|
$
|
2,158
|
|
|
$
|
2,197
|
|
Residential revenue per KWh
|
|
11.48
|
¢
|
|
|
10.84
|
¢
|
|
|
10.73
|
¢
|
Large commercial and industrial revenue per KWh
|
6.23
|
|
|
5.60
|
|
|
5.90
|
|
|||
Small commercial and industrial revenue per KWh
|
9.06
|
|
|
8.48
|
|
|
8.50
|
|
|||
Total retail revenue per KWh
|
8.93
|
|
|
8.30
|
|
|
8.37
|
|
|||
Wholesale revenue per KWh
|
4.60
|
|
|
4.36
|
|
|
4.64
|
|
|
Year Ended Dec. 31
|
||||||||||||||||
|
2013
|
|
2012
|
|
2011
|
||||||||||||
Xcel Energy
|
Millions of
KWh
|
|
Percent of
Generation
|
|
Millions of
KWh
|
|
Percent of
Generation
|
|
Millions of
KWh
|
|
Percent of
Generation
|
||||||
Coal
|
49,675
|
|
|
46
|
%
|
|
51,395
|
|
|
47
|
%
|
|
57,014
|
|
|
50
|
%
|
Natural Gas
|
24,350
|
|
|
23
|
|
|
26,218
|
|
|
24
|
|
|
25,080
|
|
|
22
|
|
Wind
(a)
|
15,738
|
|
|
14
|
|
|
13,298
|
|
|
12
|
|
|
11,216
|
|
|
10
|
|
Nuclear
|
12,177
|
|
|
11
|
|
|
13,249
|
|
|
12
|
|
|
13,781
|
|
|
12
|
|
Hydroelectric
|
3,900
|
|
|
4
|
|
|
3,800
|
|
|
3
|
|
|
4,203
|
|
|
4
|
|
Other
(b)
|
1,704
|
|
|
2
|
|
|
2,022
|
|
|
2
|
|
|
1,659
|
|
|
2
|
|
Total
|
107,544
|
|
|
100
|
%
|
|
109,982
|
|
|
100
|
%
|
|
112,953
|
|
|
100
|
%
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Owned generation
|
70,936
|
|
|
66
|
%
|
|
75,071
|
|
|
68
|
%
|
|
74,722
|
|
|
66
|
%
|
Purchased generation
|
36,608
|
|
|
34
|
|
|
34,911
|
|
|
32
|
|
|
38,231
|
|
|
34
|
|
Total
|
107,544
|
|
|
100
|
%
|
|
109,982
|
|
|
100
|
%
|
|
112,953
|
|
|
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 0.198, 0.152, and 0.146 net million KWh for 2013, 2012 and 2011, respectively.
|
2013
|
$
|
4.53
|
|
2012
|
4.41
|
|
|
2011
|
5.25
|
|
2013
|
$
|
4.51
|
|
2012
|
4.36
|
|
|
2011
|
5.18
|
|
•
|
GCA
— The GCA recovers the actual costs of purchased natural gas and transportation to meet the requirements of its customers and is revised quarterly to allow for changes in natural gas rates.
|
•
|
DSMCA
— The DSMCA is a low-income energy assistance program. The costs of this energy conservation and weatherization program are recovered through the gas DSMCA.
|
•
|
PSIA
— Effective Jan. 1, 2012, the PSIA began to recover costs associated with transmission and distribution pipeline integrity management programs and two projects to replace large transmission pipelines. Although PSCo had proposed to include the PSIA in base rates, instead the rider was extended through Dec. 31, 2015.
|
2013
|
$
|
4.20
|
|
2012
|
4.28
|
|
|
2011
|
4.99
|
|
|
Year Ended Dec. 31
|
||||||||||
|
2013
|
|
2012
|
|
2011
|
||||||
Natural gas deliveries (Thousands of MMBtu)
|
|
|
|
|
|
||||||
Residential
|
150,280
|
|
|
123,835
|
|
|
139,200
|
|
|||
Commercial and industrial
|
92,849
|
|
|
77,848
|
|
|
86,788
|
|
|||
Total retail
|
243,129
|
|
|
201,683
|
|
|
225,988
|
|
|||
Transportation and other
|
125,057
|
|
|
116,611
|
|
|
117,654
|
|
|||
Total deliveries
|
368,186
|
|
|
318,294
|
|
|
343,642
|
|
|||
|
|
|
|
|
|
||||||
Number of customers at end of period
|
|
|
|
|
|
||||||
Residential
|
1,776,849
|
|
|
1,760,364
|
|
|
1,747,153
|
|
|||
Commercial and industrial
|
154,646
|
|
|
154,158
|
|
|
153,911
|
|
|||
Total retail
|
1,931,495
|
|
|
1,914,522
|
|
|
1,901,064
|
|
|||
Transportation and other
|
6,320
|
|
|
5,789
|
|
|
5,395
|
|
|||
Total customers
|
1,937,815
|
|
|
1,920,311
|
|
|
1,906,459
|
|
|||
|
|
|
|
|
|
||||||
Natural gas revenues (Thousands of Dollars)
|
|
|
|
|
|
||||||
Residential
|
$
|
1,126,859
|
|
|
$
|
964,642
|
|
|
$
|
1,133,888
|
|
Commercial and industrial
|
586,548
|
|
|
488,644
|
|
|
601,298
|
|
|||
Total retail
|
1,713,407
|
|
|
1,453,286
|
|
|
1,735,186
|
|
|||
Transportation and other
|
91,272
|
|
|
84,088
|
|
|
76,740
|
|
|||
Total natural gas revenues
|
$
|
1,804,679
|
|
|
$
|
1,537,374
|
|
|
$
|
1,811,926
|
|
|
|
|
|
|
|
||||||
MMBtu sales per retail customer
|
125.88
|
|
|
105.34
|
|
|
118.87
|
|
|||
Revenue per retail customer
|
$
|
887
|
|
|
$
|
759
|
|
|
$
|
913
|
|
Residential revenue per MMBtu
|
7.50
|
|
|
7.79
|
|
|
8.15
|
|
|||
Commercial and industrial revenue per MMBtu
|
6.32
|
|
|
6.28
|
|
|
6.93
|
|
|||
Transportation and other revenue per MMBtu
|
0.73
|
|
|
0.72
|
|
|
0.65
|
|
•
|
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 of these radioactive materials and the current lack of a long-term disposal solution for radioactive materials;
|
•
|
Limitations on the amounts and types of insurance commercially available to cover losses that might arise in connection with nuclear operations; and
|
•
|
Uncertainties with respect to the technological and financial aspects of decommissioning nuclear plants at the end of their licensed lives.
|
NSP-Minnesota
Station, Location and Unit
|
|
Fuel
|
|
Installed
|
|
Summer 2013
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
|
|
507
|
|
(a)
|
Monticello-Monticello, Minn., 1 Unit
|
|
Nuclear
|
|
1971
|
|
554
|
|
|
Prairie Island-Welch, Minn.
|
|
|
|
|
|
|
|
|
Unit 1
|
|
Nuclear
|
|
1973
|
|
521
|
|
|
Unit 2
|
|
Nuclear
|
|
1974
|
|
519
|
|
|
Black Dog-Burnsville, Minn., 2 Units
|
|
Coal/Natural Gas
|
|
1955-1960
|
|
232
|
|
|
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
|
|
271
|
|
|
Blue Lake-Shakopee, Minn., 6 Units
|
|
Natural Gas
|
|
1974-2005
|
|
453
|
|
|
High Bridge-St. Paul, Minn., 3 Units
|
|
Natural Gas
|
|
2008
|
|
534
|
|
|
Inver Hills-Inver Grove Heights, Minn., 6 Units
|
|
Natural Gas
|
|
1972
|
|
282
|
|
|
Riverside-Minneapolis, Minn., 3 Units
|
|
Natural Gas
|
|
2009
|
|
470
|
|
|
Various locations, 17 Units
|
|
Natural Gas
|
|
Various
|
|
101
|
|
|
Wind:
|
|
|
|
|
|
|
|
|
Grand Meadow-Mower County, Minn., 67 Units
|
|
Wind
|
|
2008
|
|
101
|
|
(c)
|
Nobles-Nobles County, Minn., 134 Units
|
|
Wind
|
|
2010
|
|
201
|
|
(c)
|
|
|
|
|
Total
|
|
6,982
|
|
|
(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 2013
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., 6 Units
|
|
Natural Gas
|
|
1973
|
|
290
|
|
|
Hydro:
|
|
|
|
|
|
|
|
|
Various locations, 63 Units
|
|
Hydro
|
|
Various
|
|
135
|
|
|
|
|
|
|
Total
|
|
631
|
|
|
(a)
|
Refuse-derived fuel is made from municipal solid waste.
|
PSCo
Station, Location and Unit
|
|
Fuel
|
|
Installed
|
|
Summer 2013
Net Dependable
Capability (MW)
|
|
|
Steam:
|
|
|
|
|
|
|
|
|
Cherokee-Denver, Colo., 2 Units
|
|
Coal
|
|
1957-1968
|
|
504
|
|
(a)
|
Comanche-Pueblo, Colo.
|
|
|
|
|
|
|
|
|
Unit 1
|
|
Coal
|
|
1973
|
|
325
|
|
|
Unit 2
|
|
Coal
|
|
1975
|
|
335
|
|
|
Unit 3
|
|
Coal
|
|
2010
|
|
500
|
|
(b)
|
Craig-Craig, Colo., 2 Units
|
|
Coal
|
|
1979-1980
|
|
83
|
|
(c)
|
Hayden-Hayden, Colo., 2 Units
|
|
Coal
|
|
1965-1976
|
|
237
|
|
(d)
|
Pawnee-Brush, Colo., 1 Unit
|
|
Coal
|
|
1981
|
|
505
|
|
|
Valmont-Boulder, Colo., 1 Unit
|
|
Coal
|
|
1964
|
|
184
|
|
|
Zuni-Denver, Colo., 1 Unit
|
|
Coal
|
|
1948-1954
|
|
59
|
|
|
Combustion Turbine:
|
|
|
|
|
|
|
|
|
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
|
|
172
|
|
|
Hydro:
|
|
|
|
|
|
|
|
|
Cabin Creek-Georgetown, Colo.
|
|
|
|
|
|
|
|
|
Pumped Storage, 2 Units
|
|
Hydro
|
|
1967
|
|
210
|
|
|
Various locations, 9 Units
|
|
Hydro
|
|
Various
|
|
26
|
|
|
Wind:
|
|
|
|
|
|
|
|
|
Ponnequin-Weld County, Colo., 37 Units
|
|
Wind
|
|
1999-2001
|
|
25
|
|
(e)
|
|
|
|
|
Total
|
|
4,978
|
|
|
(a)
|
Cherokee Unit 2 was taken out of service in October 2011. Cherokee Unit 1 was taken out of service in May 2012.
|
(b)
|
Based on PSCo’s ownership interest of 67 percent of Unit 3.
|
(c)
|
Based on PSCo’s ownership interest of 10 percent.
|
(d)
|
Based on PSCo’s ownership interest of 76 percent of Unit 1 and 37 percent of Unit 2.
|
(e)
|
This capacity is only available when wind conditions are sufficiently high enough to support the noted generation values above. Therefore, the on-demand net dependable capacity is zero.
|
SPS
Station, Location and Unit
|
|
Fuel
|
|
Installed
|
|
Summer 2013
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
|
|
339
|
|
(a)
|
Maddox-Hobbs, N.M., 1 Unit
|
|
Natural Gas
|
|
1963-1976
|
|
61
|
|
|
|
|
|
|
Total
|
|
4,427
|
|
|
(a)
|
Construction of Jones Unit 3 was completed in 2011 and Jones Unit 4 was completed in May 2013.
|
Conductor Miles
|
|
NSP-Minnesota
|
|
NSP-Wisconsin
|
|
PSCo
|
|
SPS
|
||||
500 KV
|
|
2,917
|
|
|
—
|
|
|
—
|
|
|
—
|
|
345 KV
|
|
6,392
|
|
|
1,152
|
|
|
2,157
|
|
|
6,806
|
|
230 KV
|
|
1,802
|
|
|
—
|
|
|
12,153
|
|
|
9,310
|
|
161 KV
|
|
353
|
|
|
1,572
|
|
|
—
|
|
|
—
|
|
138 KV
|
|
—
|
|
|
—
|
|
|
92
|
|
|
—
|
|
115 KV
|
|
7,552
|
|
|
1,739
|
|
|
4,893
|
|
|
12,380
|
|
Less than 115 KV
|
|
83,469
|
|
|
32,204
|
|
|
74,610
|
|
|
22,782
|
|
|
|
NSP-Minnesota
|
|
NSP-Wisconsin
|
|
PSCo
|
|
SPS
|
||||
Quantity
|
|
351
|
|
|
203
|
|
|
230
|
|
|
429
|
|
Miles
|
|
NSP-Minnesota
|
|
NSP-Wisconsin
|
|
PSCo
|
|
WGI
|
||||
Transmission
|
|
137
|
|
|
—
|
|
|
2,252
|
|
|
11
|
|
Distribution
|
|
9,855
|
|
|
2,295
|
|
|
21,718
|
|
|
—
|
|
2013
|
|
High
|
|
Low
|
|
Dividends
|
||||||
First quarter
|
|
$
|
29.74
|
|
|
$
|
26.77
|
|
|
$
|
0.2700
|
|
Second quarter
|
|
31.79
|
|
|
27.38
|
|
|
0.2800
|
|
|||
Third quarter
|
|
30.41
|
|
|
26.90
|
|
|
0.2800
|
|
|||
Fourth quarter
|
|
29.40
|
|
|
27.14
|
|
|
0.2800
|
|
2012
|
|
High
|
|
Low
|
|
Dividends
|
||||||
First quarter
|
|
$
|
27.93
|
|
|
$
|
25.92
|
|
|
$
|
0.2600
|
|
Second quarter
|
|
29.12
|
|
|
25.89
|
|
|
0.2700
|
|
|||
Third quarter
|
|
29.92
|
|
|
27.25
|
|
|
0.2700
|
|
|||
Fourth quarter
|
|
28.34
|
|
|
25.84
|
|
|
0.2700
|
|
|
2008
|
|
2009
|
|
2010
|
|
2011
|
|
2012
|
|
2013
|
||||||||||||
Xcel Energy Inc.
|
$
|
100
|
|
|
$
|
120
|
|
|
$
|
140
|
|
|
$
|
171
|
|
|
$
|
172
|
|
|
$
|
187
|
|
EEI Investor-Owned Electrics
|
100
|
|
|
111
|
|
|
118
|
|
|
142
|
|
|
145
|
|
|
164
|
|
||||||
S&P 500
|
100
|
|
|
126
|
|
|
146
|
|
|
149
|
|
|
172
|
|
|
228
|
|
|
|
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, 2013 — Jan. 31, 2013
(a)
|
|
18,175
|
|
|
$
|
27.43
|
|
|
—
|
|
|
—
|
|
Feb. 1, 2013 — Dec. 31, 2013
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
Total
|
|
18,175
|
|
|
|
|
|
—
|
|
|
—
|
|
(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.
|
(Millions of Dollars, Thousands of Shares, Except Per Share Data)
|
|
2013
|
|
2012
|
|
2011
|
|
2010
|
|
2009
|
||||||||||
Operating revenues
|
|
$
|
10,915
|
|
|
$
|
10,128
|
|
|
$
|
10,655
|
|
|
$
|
10,311
|
|
|
$
|
9,644
|
|
Operating expenses
|
|
9,067
|
|
|
8,306
|
|
|
8,873
|
|
|
8,691
|
|
|
8,176
|
|
|||||
Net income
|
|
948
|
|
|
905
|
|
|
841
|
|
|
756
|
|
|
681
|
|
|||||
Earnings available to common shareholders
|
|
948
|
|
|
905
|
|
|
834
|
|
|
752
|
|
|
677
|
|
|||||
Weighted average common shares outstanding:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Basic
|
|
496,073
|
|
|
487,899
|
|
|
485,039
|
|
|
462,052
|
|
|
456,433
|
|
|||||
Diluted
|
|
496,532
|
|
|
488,434
|
|
|
485,615
|
|
|
463,391
|
|
|
457,139
|
|
|||||
Earnings per share:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Basic
|
|
$
|
1.91
|
|
|
$
|
1.86
|
|
|
$
|
1.72
|
|
|
$
|
1.63
|
|
|
$
|
1.48
|
|
Diluted
|
|
1.91
|
|
|
1.85
|
|
|
1.72
|
|
|
1.62
|
|
|
1.48
|
|
|||||
Dividends declared per common share
|
|
1.11
|
|
|
1.07
|
|
|
1.03
|
|
|
1.00
|
|
|
0.97
|
|
|||||
Total assets
|
|
33,907
|
|
|
31,141
|
|
|
29,497
|
|
|
27,388
|
|
|
25,306
|
|
|||||
Long-term debt
(a)
|
|
10,911
|
|
|
10,144
|
|
|
8,849
|
|
|
9,263
|
|
|
7,889
|
|
|||||
Book value per share
|
|
19.21
|
|
|
18.19
|
|
|
17.44
|
|
|
16.76
|
|
|
15.92
|
|
|||||
Return on average common equity
|
|
10.3
|
%
|
|
10.4
|
%
|
|
10.1
|
%
|
|
9.8
|
%
|
|
9.5
|
%
|
|||||
Ratio of earnings to fixed charges
(b)
|
|
3.1
|
|
|
2.8
|
|
|
2.8
|
|
|
2.7
|
|
|
2.5
|
|
|||||
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Non-GAAP:
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Ongoing earnings
(c)
|
|
$
|
968
|
|
|
$
|
888
|
|
|
$
|
841
|
|
|
$
|
756
|
|
|
$
|
690
|
|
(a)
|
Includes capital lease obligations.
|
(b)
|
See Exhibit 12.01.
|
(c)
|
See Item 7 for a reconciliation of ongoing earnings to GAAP earnings.
|
•
|
Driving operational excellence;
|
•
|
Providing options and solutions to customers;
|
•
|
Investing for the future; and
|
•
|
Enhancing engagement with employees, customers, shareholders, communities and policy makers.
|
•
|
Deliver long-term annual EPS growth of four percent to six percent, based on a normalized 2013 EPS of $1.90 per share;
|
•
|
Deliver annual dividend increases of four percent to six percent; and
|
•
|
Maintain senior unsecured debt credit ratings in the BBB+ to A range.
|
Diluted Earnings (Loss) Per Share
|
|
2013
|
|
2012
|
|
2011
|
||||||
PSCo
|
|
$
|
0.91
|
|
|
$
|
0.90
|
|
|
$
|
0.82
|
|
NSP-Minnesota
|
|
0.79
|
|
|
0.70
|
|
|
0.73
|
|
|||
SPS
|
|
0.23
|
|
|
0.22
|
|
|
0.18
|
|
|||
NSP-Wisconsin
|
|
0.12
|
|
|
0.10
|
|
|
0.10
|
|
|||
Equity earnings of unconsolidated subsidiaries
|
|
0.04
|
|
|
0.04
|
|
|
0.04
|
|
|||
Regulated utility
|
|
2.09
|
|
|
1.96
|
|
|
1.87
|
|
|||
Xcel Energy Inc. and other costs
|
|
(0.14
|
)
|
|
(0.14
|
)
|
|
(0.15
|
)
|
|||
Ongoing diluted earnings per share
|
|
1.95
|
|
|
1.82
|
|
|
1.72
|
|
|||
SPS 2004 FERC complaint case orders
|
|
(0.04
|
)
|
|
—
|
|
|
—
|
|
|||
Prescription drug tax benefit
|
|
—
|
|
|
0.03
|
|
|
—
|
|
|||
GAAP diluted earnings per share
|
|
$
|
1.91
|
|
|
$
|
1.85
|
|
|
$
|
1.72
|
|
Diluted Earnings (Loss) Per Share
|
|
Dec. 31
|
||
2012 GAAP diluted earnings per share
|
|
$
|
1.85
|
|
Prescription drug tax benefit
|
|
(0.03
|
)
|
|
2012 ongoing diluted earnings per share
|
|
1.82
|
|
|
|
|
|
||
Components of change — 2013 vs. 2012
|
|
|
||
Higher electric margins (excludes impact of SPS 2004 FERC complaint case orders)
|
|
0.18
|
|
|
Higher natural gas margins
|
|
0.08
|
|
|
Higher AFUDC — equity
|
|
0.05
|
|
|
Lower interest charges (excludes impact of SPS 2004 FERC complaint case orders)
|
|
0.04
|
|
|
Gain on sale of transmission assets
(included in O&M expenses)
|
|
0.02
|
|
|
Higher O&M expenses (excludes gain on sale of transmission assets)
|
|
(0.14
|
)
|
|
Higher depreciation and amortization
|
|
(0.06
|
)
|
|
Dilution from at-the-market program, direct stock purchase plan and benefit plans
|
|
(0.03
|
)
|
|
Higher taxes (other than income taxes)
|
|
(0.01
|
)
|
|
2013 ongoing diluted earnings per share
|
|
1.95
|
|
|
SPS 2004 FERC complaint case orders
|
|
(0.04
|
)
|
|
2013 GAAP diluted earnings per share
|
|
$
|
1.91
|
|
Diluted Earnings (Loss) Per Share
|
|
Dec. 31
|
||
2011 GAAP and ongoing diluted earnings per share
|
|
$
|
1.72
|
|
|
|
|
||
Components of change — 2012 vs. 2011
|
|
|
|
|
Higher electric margins
|
|
0.15
|
|
|
Lower ETR
|
|
0.04
|
|
|
Lower conservation and DSM expenses (generally offset in revenues)
|
|
0.03
|
|
|
Higher AFUDC — equity
|
|
0.02
|
|
|
Higher natural gas margins
|
|
0.01
|
|
|
Higher O&M expenses
|
|
(0.05
|
)
|
|
Higher depreciation and amortization
|
|
(0.04
|
)
|
|
Higher taxes (other than income taxes)
|
|
(0.04
|
)
|
|
Higher interest charges
|
|
(0.01
|
)
|
|
Other, net (including interest and premium on redemption of preferred stock)
|
|
(0.01
|
)
|
|
2012 ongoing diluted earnings per share
|
|
1.82
|
|
|
Prescription drug tax benefit
|
|
0.03
|
|
|
2012 GAAP diluted earnings per share
|
|
$
|
1.85
|
|
ROE - 2013
|
|
PSCo
|
|
NSP-Minnesota
|
|
SPS
|
|
NSP-Wisconsin
|
|
Xcel Energy
|
|||||
2013 ongoing ROE
|
|
9.66
|
%
|
|
9.24
|
%
|
|
9.03
|
%
|
|
10.61
|
%
|
|
10.50
|
%
|
SPS 2004 FERC complaint case orders
|
|
—
|
|
|
—
|
|
|
(1.54
|
)
|
|
—
|
|
|
(0.22
|
)
|
2013 GAAP ROE
|
|
9.66
|
%
|
|
9.24
|
%
|
|
7.49
|
%
|
|
10.61
|
%
|
|
10.28
|
%
|
ROE - 2012
|
|
PSCo
|
|
NSP-Minnesota
|
|
SPS
|
|
NSP-Wisconsin
|
|
Xcel Energy
|
|||||
2012 ongoing ROE
|
|
9.92
|
%
|
|
8.77
|
%
|
|
9.44
|
%
|
|
9.62
|
%
|
|
10.24
|
%
|
Prescription drug tax benefit
|
|
0.38
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
0.19
|
|
2012 GAAP ROE
|
|
10.30
|
%
|
|
8.77
|
%
|
|
9.44
|
%
|
|
9.62
|
%
|
|
10.43
|
%
|
(Millions of Dollars)
|
|
2013
|
|
2012
|
|
2011
|
||||||
Ongoing earnings
|
|
$
|
968.4
|
|
|
$
|
888.3
|
|
|
$
|
840.7
|
|
SPS 2004 FERC complaint case orders (2013), prescription drug tax benefit (2012) and COLI settlement (2011)
|
|
(20.2
|
)
|
|
16.9
|
|
|
0.5
|
|
|||
GAAP earnings
|
|
$
|
948.2
|
|
|
$
|
905.2
|
|
|
$
|
841.2
|
|
Diluted Earnings (Loss) Per Share
|
|
2013
|
|
2012
|
|
2011
|
||||||
Ongoing diluted earnings per share
(a)
|
|
$
|
1.95
|
|
|
$
|
1.82
|
|
|
$
|
1.72
|
|
SPS 2004 FERC complaint case orders (2013), prescription drug tax benefit (2012) and COLI settlement (2011)
|
|
(0.04
|
)
|
|
0.03
|
|
|
—
|
|
|||
GAAP diluted earnings per share
(a)
|
|
$
|
1.91
|
|
|
$
|
1.85
|
|
|
$
|
1.72
|
|
(a)
|
Includes the dividend requirements on preferred stock in 2011.
|
(Millions of Dollars)
|
|
2013
|
|
2012
|
|
2011
|
||||||
GAAP income (loss) by segment
|
|
|
|
|
|
|
||||||
Regulated electric income
|
|
$
|
850.7
|
|
|
$
|
851.9
|
|
|
$
|
789.0
|
|
Regulated natural gas income
|
|
123.7
|
|
|
98.1
|
|
|
101.8
|
|
|||
Other income
(a)
|
|
44.6
|
|
|
22.1
|
|
|
17.9
|
|
|||
Xcel Energy Inc. and other costs
(a)
|
|
(70.8
|
)
|
|
(66.9
|
)
|
|
(67.5
|
)
|
|||
Total net income
|
|
$
|
948.2
|
|
|
$
|
905.2
|
|
|
$
|
841.2
|
|
Contributions to Diluted Earnings (Loss) Per Share
|
|
2013
|
|
2012
|
|
2011
|
||||||
GAAP earnings (loss) by segment
|
|
|
|
|
|
|
||||||
Regulated electric
|
|
$
|
1.71
|
|
|
$
|
1.74
|
|
|
$
|
1.62
|
|
Regulated natural gas
|
|
0.25
|
|
|
0.20
|
|
|
0.21
|
|
|||
Other
(a)
|
|
0.09
|
|
|
0.05
|
|
|
0.04
|
|
|||
Xcel Energy Inc. and other costs
(a) (b)
|
|
(0.14
|
)
|
|
(0.14
|
)
|
|
(0.15
|
)
|
|||
Total diluted earnings per share
(b)
|
|
$
|
1.91
|
|
|
$
|
1.85
|
|
|
$
|
1.72
|
|
(a)
|
Not a reportable segment. Included in all other segment results in Note 17 to the consolidated financial statements.
|
(b)
|
Includes the dividend requirements on preferred stock (2011).
|
|
2013 vs.
Normal
|
|
2012 vs.
Normal
|
|
2013 vs.
2012
|
|
2011 vs.
Normal
|
|
2012 vs.
2011
|
|||||
HDD
|
6.5
|
%
|
|
(15.9
|
)%
|
|
25.8
|
%
|
|
(1.0
|
)%
|
|
(14.8
|
)%
|
CDD
|
24.7
|
|
|
46.1
|
|
|
(13.6
|
)
|
|
38.1
|
|
|
5.7
|
|
THI
|
21.8
|
|
|
36.1
|
|
|
(9.7
|
)
|
|
37.9
|
|
|
(0.2
|
)
|
|
2013 vs.
Normal
|
|
2012 vs.
Normal
|
|
2013 vs.
2012
|
|
2011 vs.
Normal
|
|
2012 vs.
2011
|
||||||||||
Retail electric
|
$
|
0.088
|
|
|
$
|
0.081
|
|
|
$
|
0.007
|
|
|
$
|
0.080
|
|
|
$
|
0.001
|
|
Firm natural gas
|
0.021
|
|
|
(0.033
|
)
|
|
0.054
|
|
|
0.002
|
|
|
(0.035
|
)
|
|||||
Total
|
$
|
0.109
|
|
|
$
|
0.048
|
|
|
$
|
0.061
|
|
|
$
|
0.082
|
|
|
$
|
(0.034
|
)
|
|
|
Dec. 31, 2013
|
|
Dec. 31, 2013
(Without 2012 Leap Day) |
||||||||
|
|
Actual
|
|
Weather
Normalized |
|
Actual
|
|
Weather
Normalized |
||||
Electric residential
|
|
1.1
|
%
|
|
0.2
|
%
|
|
1.4
|
%
|
|
0.5
|
%
|
Electric commercial and industrial
|
|
—
|
|
|
0.1
|
|
|
0.3
|
|
|
0.4
|
|
Total retail electric sales
|
|
0.3
|
|
|
0.1
|
|
|
0.6
|
|
|
0.4
|
|
Firm natural gas sales
(a)
|
|
21.3
|
|
|
3.3
|
|
|
21.9
|
|
|
3.8
|
|
|
|
Dec. 31, 2012
|
|
Dec. 31, 2012
(Without Leap Day)
|
||||||||
|
|
Actual
|
|
Weather
Normalized
|
|
Actual
|
|
Weather
Normalized
|
||||
Electric residential
|
|
(1.0
|
)%
|
|
(0.1
|
)%
|
|
(1.2
|
)%
|
|
(0.4
|
)%
|
Electric commercial and industrial
|
|
0.1
|
|
|
—
|
|
|
(0.2
|
)
|
|
(0.2
|
)
|
Total retail electric sales
|
|
(0.3
|
)
|
|
—
|
|
|
(0.5
|
)
|
|
(0.3
|
)
|
Firm natural gas sales
(a)
|
|
(10.6
|
)
|
|
(0.3
|
)
|
|
(11.0
|
)
|
|
(0.8
|
)
|
(a)
|
Extreme weather variations and additional factors such as windchill and cloud cover may not be reflected in weather normalization and growth estimates.
|
(Millions of Dollars)
|
|
2013
|
|
2012
|
|
2011
|
||||||
Electric revenues
|
|
$
|
9,034
|
|
|
$
|
8,517
|
|
|
$
|
8,767
|
|
Electric fuel and purchased power
|
|
(4,019
|
)
|
|
(3,624
|
)
|
|
(3,992
|
)
|
|||
Electric margin
|
|
$
|
5,015
|
|
|
$
|
4,893
|
|
|
$
|
4,775
|
|
(Millions of Dollars)
|
|
2013 vs. 2012
|
||
Fuel and purchased power cost recovery
|
|
$
|
360
|
|
Retail rate increases
(a)
|
|
229
|
|
|
Transmission revenue
|
|
68
|
|
|
Non-fuel riders
|
|
18
|
|
|
Estimated impact of weather
|
|
7
|
|
|
PSCo earnings test refund obligation
|
|
(43
|
)
|
|
Firm wholesale
|
|
(36
|
)
|
|
Conservation and DSM program incentives
|
|
(24
|
)
|
|
Trading
|
|
(19
|
)
|
|
SPS 2004 FERC complaint case orders
(b)
|
|
(6
|
)
|
|
Other, net
|
|
(11
|
)
|
|
Total increase in ongoing electric revenues
|
|
543
|
|
|
SPS 2004 FERC complaint case orders
(b)
|
|
(26
|
)
|
|
Total increase in GAAP electric revenues
|
|
$
|
517
|
|
(Millions of Dollars)
|
|
2013 vs. 2012
|
||
Retail rate increases
(a)
|
|
$
|
229
|
|
Transmission revenue, net of costs
|
|
36
|
|
|
Non-fuel riders
|
|
18
|
|
|
Estimated impact of weather
|
|
7
|
|
|
PSCo earnings test refund obligation
|
|
(43
|
)
|
|
Conservation and DSM program incentives
|
|
(24
|
)
|
|
Firm wholesale
|
|
(24
|
)
|
|
Trading margin
|
|
(12
|
)
|
|
SPS 2004 FERC complaint case orders
(b)
|
|
(6
|
)
|
|
Other, net
|
|
(33
|
)
|
|
Total increase in ongoing electric margin
|
|
148
|
|
|
SPS 2004 FERC complaint case orders
(b)
|
|
(26
|
)
|
|
Total increase in GAAP electric margin
|
|
$
|
122
|
|
(a)
|
The retail rate increases include final rates in Minnesota, Colorado, Wisconsin, South Dakota and Texas and interim rates, subject to refund, in North Dakota. The Minnesota rate increase is net of a provision for customer refunds of $131 million for the twelve months ended Dec. 31, 2013 based on the final rate order received for the 2013 electric rate case. Due to the order, there was a reduction in revenues and expenses of approximately $40 million, primarily related to depreciation of $32 million and O&M expense of $8 million in 2013.
|
(b)
|
As a result of two orders issued by the FERC in August 2013, a pretax charge of approximately $36 million ($32 million in electric revenues, of which $6 million relates to 2013 and $26 million relates to periods prior to 2013, and $4 million in interest charges) was recorded in 2013. See Note 12 to the consolidated financial statements.
|
(Millions of Dollars)
|
|
2012 vs. 2011
|
||
Fuel and purchased power cost recovery
|
|
$
|
(394
|
)
|
Firm wholesale
(a)
|
|
(58
|
)
|
|
Retail sales decrease, excluding weather impact
|
|
(6
|
)
|
|
Conservation and DSM revenue (offset by expenses)
|
|
(5
|
)
|
|
Retail rate increases (Colorado, Texas, New Mexico, Wisconsin, South Dakota,
North Dakota, Michigan and Minnesota)
|
|
125
|
|
|
Transmission revenue
|
|
44
|
|
|
Demand revenue
|
|
13
|
|
|
Conservation and DSM incentive
|
|
12
|
|
|
Estimated impact of weather
|
|
1
|
|
|
Other, net
|
|
18
|
|
|
Total decrease in electric revenue
|
|
$
|
(250
|
)
|
(Millions of Dollars)
|
|
2012 vs. 2011
|
||
Retail rate increases (Colorado, Texas, New Mexico, Wisconsin, South Dakota,
North Dakota, Michigan and Minnesota)
|
|
$
|
125
|
|
Demand revenue
|
|
13
|
|
|
Transmission revenue, net of costs
|
|
13
|
|
|
Conservation and DSM incentive
|
|
12
|
|
|
Estimated impact of weather
|
|
1
|
|
|
Firm wholesale
(a)
|
|
(48
|
)
|
|
Retail sales decrease, excluding weather impact
|
|
(6
|
)
|
|
Conservation and DSM revenue (offset by expenses)
|
|
(5
|
)
|
|
Other, net
|
|
13
|
|
|
Total increase in electric margin
|
|
$
|
118
|
|
(a)
|
Decrease is primarily due to the expiration of a long-term wholesale power sales agreement with Black Hills Corp., effective Jan. 1, 2012.
|
(Millions of Dollars)
|
|
2013
|
|
2012
|
|
2011
|
||||||
Natural gas revenues
|
|
$
|
1,805
|
|
|
$
|
1,537
|
|
|
$
|
1,812
|
|
Cost of natural gas sold and transported
|
|
(1,083
|
)
|
|
(881
|
)
|
|
(1,164
|
)
|
|||
Natural gas margin
|
|
$
|
722
|
|
|
$
|
656
|
|
|
$
|
648
|
|
(Millions of Dollars)
|
|
2013 vs. 2012
|
||
Purchased natural gas adjustment clause recovery
|
|
$
|
198
|
|
Estimated impact of weather
|
|
42
|
|
|
Retail rate increases (Colorado and Wisconsin)
|
|
15
|
|
|
Retail sales growth
|
|
9
|
|
|
Conservation and DSM program incentives
|
|
5
|
|
|
Conservation and DSM program revenues (offset by expenses)
|
|
4
|
|
|
Other, net
|
|
(5
|
)
|
|
Total increase in natural gas revenues
|
|
$
|
268
|
|
(Millions of Dollars)
|
|
2013 vs. 2012
|
||
Estimated impact of weather
|
|
$
|
42
|
|
Retail rate increases (Colorado and Wisconsin)
|
|
15
|
|
|
Retail sales growth
|
|
9
|
|
|
Conservation and DSM program incentive
|
|
5
|
|
|
Conservation and DSM program revenues (offset by expenses)
|
|
4
|
|
|
Other, net
|
|
(9
|
)
|
|
Total increase in natural gas margin
|
|
$
|
66
|
|
(Millions of Dollars)
|
|
2012 vs. 2011
|
||
Purchased natural gas adjustment clause recovery
|
|
$
|
(282
|
)
|
Estimated impact of weather
|
|
(26
|
)
|
|
Conservation and DSM revenue (offset by expenses)
|
|
(17
|
)
|
|
PSIA rider (Colorado), offset by expenses
|
|
29
|
|
|
Retail rate increase (Colorado, Wisconsin)
|
|
16
|
|
|
Other, net
|
|
5
|
|
|
Total decrease in natural gas revenues
|
|
$
|
(275
|
)
|
(Millions of Dollars)
|
|
2012 vs. 2011
|
||
PSIA rider (Colorado) offset by expenses
|
|
$
|
29
|
|
Retail rate increase (Colorado, Wisconsin)
|
|
16
|
|
|
Estimated impact of weather
|
|
(26
|
)
|
|
Conservation and DSM revenue (offset by expenses)
|
|
(17
|
)
|
|
Other, net
|
|
6
|
|
|
Total increase in natural gas margin
|
|
$
|
8
|
|
(Millions of Dollars)
|
|
2013 vs. 2012
|
||
Electric and gas distribution expenses
|
|
$
|
44
|
|
Nuclear plant operations and amortization
|
|
33
|
|
|
Transmission costs
|
|
13
|
|
|
Employee benefits
|
|
7
|
|
|
Gain on sale of transmission assets
|
|
(14
|
)
|
|
Other, net
|
|
14
|
|
|
Total increase in O&M expenses
|
|
$
|
97
|
|
•
|
Electric and gas distribution expenses were primarily driven by increased maintenance activities due to vegetation management, storms and outages;
|
•
|
Nuclear cost increases are related to the amortization of prior outages and initiatives designed to improve the operational efficiencies of the plants;
|
•
|
Increased transmission costs were related to higher substation maintenance expenditures and reliability costs;
|
•
|
Higher employee benefits related primarily to increased pension expense; and
|
•
|
See Note 12 to the consolidated financial statements for further discussion of the gain on sale of transmission assets.
|
(Millions of Dollars)
|
|
2012 vs. 2011
|
||
Employee benefits
|
|
$
|
36
|
|
Pipeline system integrity costs
|
|
20
|
|
|
SmartGridCity
|
|
11
|
|
|
Prairie Island EPU
|
|
10
|
|
|
Plant generation costs
|
|
(17
|
)
|
|
Bad debt expense
|
|
(10
|
)
|
|
Labor and contract labor
|
|
(2
|
)
|
|
Other, net
|
|
(12
|
)
|
|
Total increase in O&M expenses
|
|
$
|
36
|
|
•
|
Higher employee benefits are mainly due to increased pension expenses.
|
•
|
Higher pipeline system integrity costs relate to increased compliance and inspection initiatives, which in Colorado are recovered through the pipeline system integrity rider.
|
•
|
See Note 12 to the consolidated financial statements for further discussion of SmartGridCity and Prairie Island EPU.
|
•
|
Lower plant generation costs are primarily attributable to fewer plant overhauls in 2012.
|
|
|
Contribution to Xcel Energy’s Earnings
|
||||||||||
(Millions of Dollars)
|
|
2013
|
|
2012
|
|
2011
|
||||||
Xcel Energy Inc. financing costs
|
|
$
|
(62.9
|
)
|
|
$
|
(71.5
|
)
|
|
$
|
(63.8
|
)
|
Eloigne
(a)
|
|
(0.8
|
)
|
|
3.8
|
|
|
(2.9
|
)
|
|||
Xcel Energy Inc. taxes and other results
|
|
(7.1
|
)
|
|
0.8
|
|
|
(0.6
|
)
|
|||
Total Xcel Energy Inc. and other costs
|
|
(70.8
|
)
|
|
(66.9
|
)
|
|
(67.3
|
)
|
|||
Preferred dividends
|
|
—
|
|
|
—
|
|
|
(6.8
|
)
|
|||
Total Xcel Energy Inc. and other costs, available to common shareholders
|
|
$
|
(70.8
|
)
|
|
$
|
(66.9
|
)
|
|
$
|
(74.1
|
)
|
|
|
Contribution to Xcel Energy’s Earnings per Share
|
||||||||||
(Earnings per Share)
|
|
2013
|
|
2012
|
|
2011
|
||||||
Xcel Energy Inc. financing costs
|
|
$
|
(0.13
|
)
|
|
$
|
(0.15
|
)
|
|
$
|
(0.13
|
)
|
Eloigne
(a)
|
|
—
|
|
|
0.01
|
|
|
(0.01
|
)
|
|||
Xcel Energy Inc. taxes and other results
|
|
(0.01
|
)
|
|
—
|
|
|
—
|
|
|||
Preferred dividends
|
|
—
|
|
|
—
|
|
|
(0.01
|
)
|
|||
Total Xcel Energy Inc. and other costs
|
|
$
|
(0.14
|
)
|
|
$
|
(0.14
|
)
|
|
$
|
(0.15
|
)
|
(a)
|
Amounts include gains or losses associated with sales of properties held by Eloigne.
|
•
|
$275 million in 2013;
|
•
|
$263 million in 2012; and
|
•
|
$265 million in 2011.
|
•
|
$517 million in 2013;
|
•
|
$255 million in 2012; and
|
•
|
$48 million in 2011.
|
•
|
In January 2014, contributions of $130.0 million were made across three of Xcel Energy’s pension plans;
|
•
|
In 2013, contributions of $192.4 million were made across four of Xcel Energy’s pension plans;
|
•
|
In 2012, contributions of $198.1 million were made across four of Xcel Energy’s pension plans; and
|
•
|
In 2011, contributions of $137.3 million were made across three of Xcel Energy’s pension plans.
|
|
|
Pension Costs
|
||||||
(Millions of Dollars)
|
|
+1%
|
|
-1%
|
||||
Rate of return
|
|
$
|
(25.1
|
)
|
|
$
|
25.5
|
|
Discount rate
|
|
(11.2
|
)
|
|
14.1
|
|
•
|
Xcel Energy contributed $17.6 million, $47.1 million and $49.0 million during 2013, 2012 and 2011, respectively, to the postretirement health care plans.
|
•
|
Xcel Energy expects to contribute approximately $13.3 million during 2014.
|
•
|
NSP-Minnesota recognizes pension expense in all regulatory jurisdictions based on expense as calculated using the aggregate normal cost actuarial method. Differences between aggregate normal cost and expense as calculated by pension accounting standards are deferred as a regulatory liability.
|
•
|
Colorado, Texas, New Mexico and FERC jurisdictions allow the recovery of other post retirement benefit costs only to the extent that recognized expense is matched by cash contributions to an irrevocable trust. Xcel Energy has consistently funded at a level to allow full recovery of costs in these jurisdictions.
|
•
|
SPS recognizes pension expense in all regulatory jurisdictions based on expense consistent with accounting guidance. The Texas jurisdiction records the difference between annual recognized pension expense and the annual amount of pension expense approved in the last general rate case as a deferral to a regulatory asset.
|
•
|
Timing
— Decommissioning cost estimates are impacted by each facility’s retirement date, as well as the expected timing of the actual decommissioning activities. Currently, the estimated retirement dates coincide with each unit’s operating license with the NRC (i.e., 2030 for Monticello and 2033 and 2034 for Prairie Island’s Unit 1 and 2, respectively). The estimated timing of the decommissioning activities is based upon the DECON method, which is required by the MPUC. By utilizing this method, which assumes prompt removal and dismantlement, these activities are expected to begin at the end of the license date and be completed for both facilities by 2091.
|
•
|
Technology and Regulation
— There is limited experience with actual decommissioning of large nuclear facilities. Changes in technology and experience as well as changes in regulations regarding nuclear decommissioning could cause cost estimates to change significantly. NSP-Minnesota’s 2011 nuclear decommissioning filing assumed current technology and regulations.
|
•
|
Escalation Rates
— Escalation rates represent projected cost increases over time due to both general inflation and increases in the cost of specific decommissioning activities. NSP-Minnesota used an escalation rate of
3.63 percent
in calculating the AROs related to nuclear decommissioning for the remaining operational period through the radiological decommissioning period. An escalation rate of
2.63 percent
was utilized for the period of operating costs related to interim dry cask storage of spent nuclear fuel and site restoration.
|
•
|
Discount Rates
— Changes in timing or estimated expected cash flows that result in upward revisions to the ARO are calculated using the then-current credit-adjusted risk-free interest rate. The credit-adjusted risk-free rate in effect when the change occurs is used to discount the revised estimate of the incremental expected cash flows of the retirement activity. If the change in timing or estimated expected cash flows results in a downward revision of the ARO, the undiscounted revised estimate of expected cash flows is discounted using the credit-adjusted risk-free rate in effect at the date of initial measurement and recognition of the original ARO. The estimated expected cash flows that changed in 2012 due to the change to a 60 year decommissioning assumption resulted in an immaterial revision to the ARO. Discount rates ranging from approximately four and seven percent have been used to calculate the net present value of the expected future cash flows over time.
|
|
|
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
|
|
|
$
|
9,746
|
|
|
$
|
16,918
|
|
|
$
|
2,516
|
|
|
$
|
1,049
|
|
|
$
|
30,229
|
|
NSP-Minnesota
|
|
2
|
|
|
(646
|
)
|
|
—
|
|
|
—
|
|
|
604
|
|
|
(42
|
)
|
|||||
PSCo
|
|
1
|
|
|
318
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
318
|
|
|||||
|
|
|
|
$
|
9,418
|
|
|
$
|
16,918
|
|
|
$
|
2,516
|
|
|
$
|
1,653
|
|
|
$
|
30,505
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
|
|
Options
|
|||||||||||||||||||||
(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 Options
Fair Value
|
|||||||||||
NSP-Minnesota
|
|
2
|
|
|
$
|
9
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
9
|
|
(Thousands of Dollars)
|
|
2013
|
|
2012
|
||||
Fair value of commodity trading net contract assets outstanding at Jan. 1
|
|
$
|
28,314
|
|
|
$
|
20,424
|
|
Contracts realized or settled during the period
|
|
(6,665
|
)
|
|
(12,185
|
)
|
||
Commodity trading contract additions and changes during the period
|
|
8,865
|
|
|
20,075
|
|
||
Fair value of commodity trading net contract assets outstanding at Dec. 31
|
|
$
|
30,514
|
|
|
$
|
28,314
|
|
(Millions of Dollars)
|
|
Year Ended
Dec. 31
|
|
VaR Limit
|
|
Average
|
|
High
|
|
Low
|
||||||||||
2013
|
|
$
|
0.29
|
|
|
$
|
3.00
|
|
|
$
|
0.41
|
|
|
$
|
1.65
|
|
|
$
|
<0.01
|
|
2012
|
|
0.45
|
|
|
3.00
|
|
|
0.36
|
|
|
1.56
|
|
|
|
0.06
|
|
(Millions of Dollars)
|
|
2013
|
|
2012
|
|
2011
|
||||||
Net cash provided by operating activities
|
|
$
|
2,584
|
|
|
$
|
2,005
|
|
|
$
|
2,406
|
|
(Millions of Dollars)
|
|
2013
|
|
2012
|
|
2011
|
||||||
Net cash used in investing activities
|
|
$
|
(3,213
|
)
|
|
$
|
(2,333
|
)
|
|
$
|
(2,248
|
)
|
(Millions of Dollars)
|
|
2013
|
|
2012
|
|
2011
|
||||||
Net cash provided by (used in) financing activities
|
|
$
|
654
|
|
|
$
|
350
|
|
|
$
|
(205
|
)
|
|
|
Actual
|
|
Forecast
|
||||||||||||||||||||
(Millions of Dollars)
|
|
2013
|
|
2014
|
|
2015
|
|
2016
|
|
2017
|
|
2018
|
||||||||||||
By Subsidiary
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
NSP-Minnesota
|
|
$
|
1,505
|
|
|
$
|
1,090
|
|
|
$
|
1,620
|
|
|
$
|
955
|
|
|
$
|
885
|
|
|
$
|
805
|
|
PSCo
|
|
1,074
|
|
|
985
|
|
|
845
|
|
|
795
|
|
|
770
|
|
|
815
|
|
||||||
SPS
|
|
555
|
|
|
525
|
|
|
520
|
|
|
610
|
|
|
770
|
|
|
790
|
|
||||||
NSP-Wisconsin
|
|
217
|
|
|
290
|
|
|
210
|
|
|
265
|
|
|
275
|
|
|
275
|
|
||||||
WYCO
|
|
8
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Total capital expenditures
|
|
$
|
3,359
|
|
|
$
|
2,890
|
|
|
$
|
3,195
|
|
|
$
|
2,625
|
|
|
$
|
2,700
|
|
|
$
|
2,685
|
|
By Function
|
|
2013
|
|
2014
|
|
2015
|
|
2016
|
|
2017
|
|
2018
|
||||||||||||
Electric transmission
|
|
$
|
1,073
|
|
|
$
|
950
|
|
|
$
|
770
|
|
|
$
|
790
|
|
|
$
|
945
|
|
|
$
|
1,035
|
|
Electric generation
|
|
1,116
|
|
|
715
|
|
|
1,235
|
|
|
560
|
|
|
550
|
|
|
470
|
|
||||||
Electric distribution
|
|
551
|
|
|
510
|
|
|
560
|
|
|
595
|
|
|
605
|
|
|
610
|
|
||||||
Natural gas
|
|
316
|
|
|
365
|
|
|
340
|
|
|
345
|
|
|
300
|
|
|
320
|
|
||||||
Nuclear fuel
|
|
90
|
|
|
140
|
|
|
100
|
|
|
135
|
|
|
135
|
|
|
75
|
|
||||||
Other
|
|
213
|
|
|
210
|
|
|
190
|
|
|
200
|
|
|
165
|
|
|
175
|
|
||||||
Total capital expenditures
|
|
$
|
3,359
|
|
|
$
|
2,890
|
|
|
$
|
3,195
|
|
|
$
|
2,625
|
|
|
$
|
2,700
|
|
|
$
|
2,685
|
|
By Project
|
|
2013
|
|
2014
|
|
2015
|
|
2016
|
|
2017
|
|
2018
|
||||||||||||
Other major transmission projects
|
|
$
|
335
|
|
|
$
|
370
|
|
|
$
|
265
|
|
|
$
|
330
|
|
|
$
|
420
|
|
|
$
|
385
|
|
CapX2020 transmission project
|
|
330
|
|
|
255
|
|
|
125
|
|
|
5
|
|
|
—
|
|
|
—
|
|
||||||
PSCo CACJA
|
|
350
|
|
|
250
|
|
|
85
|
|
|
10
|
|
|
—
|
|
|
—
|
|
||||||
Natural gas pipeline replacement
|
|
115
|
|
|
160
|
|
|
180
|
|
|
145
|
|
|
125
|
|
|
125
|
|
||||||
Nuclear fuel
|
|
90
|
|
|
140
|
|
|
100
|
|
|
135
|
|
|
135
|
|
|
75
|
|
||||||
NSP-Minnesota wind projects
|
|
—
|
|
|
35
|
|
|
610
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Southwest infrastructure expansion
|
|
—
|
|
|
5
|
|
|
70
|
|
|
170
|
|
|
290
|
|
|
385
|
|
||||||
NSP-Minnesota Black Dog
|
|
—
|
|
|
5
|
|
|
50
|
|
|
40
|
|
|
5
|
|
|
—
|
|
||||||
Other capital expenditures
|
|
2,139
|
|
|
1,670
|
|
|
1,710
|
|
|
1,790
|
|
|
1,725
|
|
|
1,715
|
|
||||||
Total capital expenditures
|
|
$
|
3,359
|
|
|
$
|
2,890
|
|
|
$
|
3,195
|
|
|
$
|
2,625
|
|
|
$
|
2,700
|
|
|
$
|
2,685
|
|
|
|
Payments Due by Period
|
||||||||||||||||||
(Thousands of Dollars)
|
|
Total
|
|
Less than 1 Year
|
|
1 to 3 Years
|
|
4 to 5 Years
|
|
After 5 Years
|
||||||||||
Long-term debt, principal and interest payments
(a)
|
$
|
18,532,746
|
|
|
$
|
758,294
|
|
|
$
|
1,846,741
|
|
|
$
|
2,438,796
|
|
|
$
|
13,488,915
|
|
|
Capital lease obligations
|
371,697
|
|
|
17,966
|
|
|
34,896
|
|
|
29,686
|
|
|
289,149
|
|
||||||
Operating leases
(b)(c)
|
3,028,807
|
|
|
240,669
|
|
|
452,213
|
|
|
420,423
|
|
|
1,915,502
|
|
||||||
Unconditional purchase obligations
(d)
|
12,087,474
|
|
|
2,217,694
|
|
|
3,103,409
|
|
|
1,776,893
|
|
|
4,989,478
|
|
||||||
Other long-term obligations, including current portion
(e)
|
218,718
|
|
|
55,416
|
|
|
85,089
|
|
|
62,743
|
|
|
15,470
|
|
||||||
Payments to vendors in process
|
28,955
|
|
|
28,955
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Short-term debt
|
759,000
|
|
|
759,000
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Total contractual cash obligations
(f)(g)(h)
|
$
|
35,027,397
|
|
|
$
|
4,077,994
|
|
|
$
|
5,522,348
|
|
|
$
|
4,728,541
|
|
|
$
|
20,698,514
|
|
(a)
|
Includes interest payments over the terms of the debt. Interest is calculated using the applicable interest rate at Dec. 31, 2013, and outstanding principal for each investment with the terms ending at each instrument’s maturity.
|
(b)
|
Under some leases, Xcel Energy would have to sell or purchase the property that it leases if it chose to terminate before the scheduled lease expiration date. Most of Xcel Energy’s railcar, vehicle and equipment and aircraft leases have these terms. At Dec. 31, 2013, the amount that Xcel Energy would have to pay if it chose to terminate these leases was approximately $73.4 million. In addition, at the end of the equipment lease terms, each lease must be extended, equipment purchased for the greater of the fair value or unamortized value of equipment sold to a third party with Xcel Energy making up any deficiency between the sales price and the unamortized value.
|
(c)
|
Included in operating lease payments are
$214.2 million
,
$404.4 million
,
$387.1 million
and
$1.8 billion
, for the less than 1 year, 1-3 years, 4-5 years and after 5 years categories, respectively, pertaining to PPAs that were accounted for as operating leases.
|
(d)
|
Xcel Energy Inc. and its subsidiaries have contracts providing for the purchase and delivery of a significant portion of its current coal, nuclear fuel and natural gas requirements. Additionally, the utility subsidiaries of Xcel Energy Inc. have entered into agreements with utilities and other energy suppliers for purchased power to meet system load and energy requirements, replace generation from company-owned units under maintenance and during outages, and meet operating reserve obligations. Certain contractual purchase obligations are adjusted on indices. The effects of price changes are mitigated through cost of energy adjustment mechanisms.
|
(e)
|
Other long-term obligations relate primarily to amounts associated with technology agreements as well as uncertain tax positions.
|
(f)
|
Xcel Energy also has outstanding authority under O&M contracts to purchase up to approximately $3.1 billion of goods and services through the year 2050, in addition to the amounts disclosed in this table.
|
(g)
|
In January 2014, contributions of $130.0 million were made across three of Xcel Energy’s pension plans. Obligations of this type are dependent on several factors, including management discretion, and therefore, they are not included in the table.
|
(h)
|
Xcel Energy expects to contribute approximately $13.3 million to the postretirement health care plans during 2014. Obligations of this type are dependent on several factors, including management discretion, and therefore, they are not included in the table.
|
•
|
Projected cash generation;
|
•
|
Projected capital investment;
|
•
|
A reasonable rate of return on shareholder investment; and
|
•
|
The impact on Xcel Energy’s capital structure and credit ratings.
|
(Millions of Dollars)
|
|
Dec. 31, 2013
|
|
Dec. 31, 2012
|
||||
Fair value of pension assets
|
|
$
|
3,010
|
|
|
$
|
2,944
|
|
Projected pension obligation
(a)
|
|
3,441
|
|
|
3,640
|
|
||
Funded status
|
|
$
|
(431
|
)
|
|
$
|
(696
|
)
|
(a)
|
Excludes nonqualified plan of $37 million and $39 million at Dec. 31, 2013 and 2012, respectively.
|
Pension Assumptions
|
|
2013
|
|
2012
|
||
Discount rate
|
|
4.75
|
%
|
|
4.00
|
%
|
Expected long-term rate of return
|
|
7.05
|
|
|
6.88
|
|
•
|
$800 million for Xcel Energy Inc.;
|
•
|
$700 million for PSCo;
|
•
|
$500 million for NSP-Minnesota;
|
•
|
$300 million for SPS; and
|
•
|
$150 million for NSP-Wisconsin.
|
(Amounts in Millions, Except Interest Rates)
|
|
Three Months Ended
Dec. 31, 2013
|
||
Borrowing limit
|
|
$
|
2,450
|
|
Amount outstanding at period end
|
|
759
|
|
|
Average amount outstanding
|
|
515
|
|
|
Maximum amount outstanding
|
|
759
|
|
|
Weighted average interest rate, computed on a daily basis
|
|
0.29
|
%
|
|
Weighted average interest rate at end of period
|
|
0.25
|
|
(Amounts in Millions, Except Interest Rates)
|
|
Twelve Months Ended
Dec. 31, 2013
|
|
Twelve Months Ended
Dec. 31, 2012
|
|
Twelve Months Ended
Dec. 31, 2011
|
||||||
Borrowing limit
|
|
$
|
2,450
|
|
|
$
|
2,450
|
|
|
$
|
2,450
|
|
Amount outstanding at period end
|
|
759
|
|
|
602
|
|
|
219
|
|
|||
Average amount outstanding
|
|
481
|
|
|
403
|
|
|
430
|
|
|||
Maximum amount outstanding
|
|
1,160
|
|
|
634
|
|
|
824
|
|
|||
Weighted average interest rate, computed on a daily basis
|
|
0.31
|
%
|
|
0.35
|
%
|
|
0.36
|
%
|
|||
Weighted average interest rate at end of period
|
|
0.25
|
|
|
0.36
|
|
|
0.40
|
|
(Millions of Dollars)
|
|
Facility
(a)
|
|
Drawn
(b)
|
|
Available
|
|
Cash
|
|
Liquidity
|
||||||||||
Xcel Energy Inc.
|
|
$
|
800.0
|
|
|
$
|
582.0
|
|
|
$
|
218.0
|
|
|
$
|
0.2
|
|
|
$
|
218.2
|
|
PSCo
|
|
700.0
|
|
|
6.4
|
|
|
693.6
|
|
|
0.5
|
|
|
694.1
|
|
|||||
NSP-Minnesota
|
|
500.0
|
|
|
305.9
|
|
|
194.1
|
|
|
0.4
|
|
|
194.5
|
|
|||||
SPS
|
|
300.0
|
|
|
102.0
|
|
|
198.0
|
|
|
0.9
|
|
|
198.9
|
|
|||||
NSP-Wisconsin
|
|
150.0
|
|
|
48.0
|
|
|
102.0
|
|
|
0.5
|
|
|
102.5
|
|
|||||
Total
|
|
$
|
2,450.0
|
|
|
$
|
1,044.3
|
|
|
$
|
1,405.7
|
|
|
$
|
2.5
|
|
|
$
|
1,408.2
|
|
(a)
|
These credit facilities expire in July 2017.
|
(b)
|
Includes outstanding commercial paper and letters of credit.
|
•
|
Xcel Energy Inc. has an effective automatic shelf registration statement filed in August 2012, which does not contain a limit on issuance capacity. However, Xcel Energy Inc.’s ability to issue securities is limited by authority granted by the Board of Directors, which currently authorizes the issuance of up to an additional $900 million of debt and common equity securities.
|
•
|
NSP-Minnesota has an automatic shelf registration statement filed in December 2013, which does not contain a limit on issuance capacity. However, NSP-Minnesota’s ability to issue securities is limited by authority granted by its Board of Directors, which currently authorizes the issuance of up to an additional $600 million of debt securities.
|
•
|
NSP-Wisconsin has $200 million of debt securities remaining under its currently effective shelf registration statement, which was filed in December 2013.
|
•
|
PSCo has an automatic shelf registration statement filed in October 2013, which does not contain a limit on issuance capacity. However, PSCo’s ability to issue securities is limited by authority granted by its Board of Directors, which currently authorizes the issuance of up to an additional $1.0 billion of debt securities.
|
•
|
SPS has $300 million of debt securities remaining under its currently effective shelf registration statement, which was filed in April 2013.
|
•
|
PSCo issued $250 million of 2.50 percent first mortgage bonds due March 15, 2023 and $250 million of 3.95 percent first mortgage bonds due March 15, 2043. PSCo used a portion of the net proceeds from the sale of the first mortgage bonds to repay short-term borrowings incurred to fund daily operational needs;
|
•
|
Xcel Energy Inc. issued $450 million of 0.75 percent senior unsecured notes due May 9, 2016. Xcel Energy Inc. used a portion of the proceeds from the sale of the notes to repay short-term borrowings and for other general corporate purposes;
|
•
|
NSP-Minnesota issued $400 million of 2.60 percent first mortgage bonds due May 15, 2023. NSP-Minnesota used a portion of the net proceeds from the sale of the first mortgage bonds to repay short-term borrowings and for other general corporate purposes; and
|
•
|
SPS issued $100 million of 4.50 percent first mortgage bonds due Aug. 15, 2041. SPS used a portion of the net proceeds from the sale of the first mortgage bonds to repay short-term borrowings incurred to fund daily operational needs. Including the $300 million of this series previously issued in August 2011 and June 2012, total principal outstanding for this series is $400 million.
|
•
|
PSCo may issue approximately $300 million of first mortgage bonds;
|
•
|
NSP-Minnesota may issue approximately $300 million of first mortgage bonds;
|
•
|
SPS may issue approximately $150 million of first mortgage bonds; and
|
•
|
NSP-Wisconsin may issue approximately $100 million of first mortgage bonds.
|
•
|
Xcel Energy Inc. senior unsecured debt;
|
•
|
NSP-Minnesota senior unsecured debt;
|
•
|
NSP-Minnesota commercial paper;
|
•
|
NSP-Wisconsin senior unsecured debt;
|
•
|
NSP-Wisconsin commercial paper;
|
•
|
PSCo senior unsecured debt; and
|
•
|
SPS senior unsecured debt.
|
•
|
Constructive outcomes in all rate case and regulatory proceedings.
|
•
|
Normal weather patterns are experienced for the remainder of the year.
|
•
|
Weather-adjusted retail electric utility sales are projected to increase by approximately 0.5 percent.
|
•
|
Weather-adjusted retail firm natural gas sales are projected to decline by approximately 0.0 percent to 2.0 percent.
|
•
|
Capital rider revenue is projected to increase by $50 million to $60 million over 2013 levels.
|
•
|
O&M expenses are projected to increase approximately 2 percent to 3 percent over 2013 levels.
|
•
|
Depreciation expense is projected to increase $30 million to $40 million over 2013 levels, reflecting the proposed acceleration of the depreciation reserve as part of NSP-Minnesota’s moderation plan in the Minnesota electric rate case. The moderation plan, if approved by the MPUC, would reduce depreciation expense by approximately $81 million in 2014.
|
•
|
Property taxes are projected to increase approximately $50 million to $55 million over 2013 levels.
|
•
|
Interest expense (net of AFUDC
—
debt) is projected to decrease $0 to $10 million from 2013 levels.
|
•
|
AFUDC
—
equity is projected to increase approximately $5 million to $10 million over 2013 levels.
|
•
|
The ETR is projected to be approximately 34 percent to 36 percent.
|
•
|
Average common stock and equivalents are projected to be approximately 507 million shares.
|
•
|
Deliver long-term annual EPS growth of 4 percent to 6 percent, based on a normalized 2013 EPS of $1.90 per share;
|
•
|
Deliver annual dividend increases of 4 percent to 6 percent; and
|
•
|
Maintain senior unsecured debt credit ratings in the BBB+ to A range.
|
/s/ BENJAMIN G.S. FOWKE III
|
|
/s/ TERESA S. MADDEN
|
Benjamin G.S. Fowke III
|
|
Teresa S. Madden
|
Chairman, President and Chief Executive Officer
|
|
Senior Vice President and Chief Financial Officer
|
Feb. 21, 2014
|
|
Feb. 21, 2014
|
XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CAPITALIZATION
(amounts in thousands, except share and per share data)
|
||||||||
|
|
Dec. 31
|
||||||
|
|
2013
|
|
2012
|
||||
Long-Term Debt
|
|
|
|
|
||||
NSP-Minnesota
|
|
|
|
|
||||
First Mortgage Bonds, Series due:
|
|
|
|
|
||||
Aug. 15, 2015, 1.95%
|
|
$
|
250,000
|
|
|
$
|
250,000
|
|
March 1, 2018, 5.25%
|
|
500,000
|
|
|
500,000
|
|
||
Aug. 15, 2022, 2.15%
|
|
300,000
|
|
|
300,000
|
|
||
May 15, 2023, 2.6%
|
|
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
|
|
||
Other
|
|
48
|
|
|
2
|
|
||
Unamortized discount
|
|
(11,316
|
)
|
|
(11,362
|
)
|
||
Total
|
|
3,888,732
|
|
|
3,488,640
|
|
||
Less current maturities
|
|
2
|
|
|
2
|
|
||
Total NSP-Minnesota long-term debt
|
|
$
|
3,888,730
|
|
|
$
|
3,488,638
|
|
|
|
|
|
|
||||
PSCo
|
|
|
|
|
|
|
||
First Mortgage Bonds, Series due:
|
|
|
|
|
|
|
||
March 1, 2013, 4.875%
|
|
$
|
—
|
|
|
$
|
250,000
|
|
April 1, 2014, 5.5%
|
|
275,000
|
|
|
275,000
|
|
||
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
|
|
|
—
|
|
||
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
|
|
|
—
|
|
||
Capital lease obligations, through 2060, 11.2% — 14.3%
|
|
179,444
|
|
|
185,741
|
|
||
Unamortized discount
|
|
(11,301
|
)
|
|
(9,468
|
)
|
||
Total
|
|
3,872,643
|
|
|
3,630,773
|
|
||
Less current maturities
|
|
282,143
|
|
|
256,297
|
|
||
Total PSCo long-term debt
|
|
$
|
3,590,500
|
|
|
$
|
3,374,476
|
|
|
|
|
|
|
||||
SPS
|
|
|
|
|
|
|
||
First Mortgage Bonds, Series due Aug. 15, 2041, 4.5%
|
|
$
|
400,000
|
|
|
$
|
300,000
|
|
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 (discount) premium
|
|
(135
|
)
|
|
3,684
|
|
||
Total
|
|
1,199,865
|
|
|
1,103,684
|
|
||
Less current maturities
|
|
—
|
|
|
—
|
|
||
Total SPS long-term debt
|
|
$
|
1,199,865
|
|
|
$
|
1,103,684
|
|
|
|
|
|
|
XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CAPITALIZATION
—
(Continued)
(amounts in thousands, except share and per share data)
|
||||||||
|
|
Dec. 31
|
||||||
|
|
2013
|
|
2012
|
||||
NSP-Wisconsin
|
|
|
|
|
||||
First Mortgage Bonds, Series due:
|
|
|
|
|
||||
Oct. 1, 2018, 5.25%
|
|
$
|
150,000
|
|
|
$
|
150,000
|
|
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%
|
|
558
|
|
|
591
|
|
||
Other
|
|
1,760
|
|
|
1,829
|
|
||
Unamortized discount
|
|
(2,321
|
)
|
|
(2,457
|
)
|
||
Total
|
|
468,597
|
|
|
468,563
|
|
||
Less current maturities
|
|
107
|
|
|
1,246
|
|
||
Total NSP-Wisconsin long-term debt
|
|
$
|
468,490
|
|
|
$
|
467,317
|
|
|
|
|
|
|
||||
Other Subsidiaries
|
|
|
|
|
|
|
||
Various Eloigne Co. Affordable Housing Project Notes, due 2014-2050, 0% — 8.36%
|
|
$
|
37,490
|
|
|
$
|
39,984
|
|
Total
|
|
37,490
|
|
|
39,984
|
|
||
Less current maturities
|
|
1,128
|
|
|
2,881
|
|
||
Total other subsidiaries long-term debt
|
|
$
|
36,362
|
|
|
$
|
37,103
|
|
|
|
|
|
|
||||
Xcel Energy Inc.
|
|
|
|
|
|
|
||
Unsecured Senior Notes, Series due:
|
|
|
|
|
|
|
||
May 9, 2016, 0.75%
|
|
$
|
450,000
|
|
|
$
|
—
|
|
April 1, 2017, 5.613%
|
|
253,979
|
|
|
253,979
|
|
||
May 15, 2020, 4.7%
|
|
550,000
|
|
|
550,000
|
|
||
July 1, 2036, 6.5%
|
|
300,000
|
|
|
300,000
|
|
||
Sept. 15, 2041, 4.8%
|
|
250,000
|
|
|
250,000
|
|
||
Junior Subordinated Notes, Series due:
|
|
|
|
|
|
|||
Jan. 1, 2068, 7.6%
|
|
—
|
|
|
400,000
|
|
||
Elimination of PSCo capital lease obligation with affiliates
|
|
(72,087
|
)
|
|
(74,358
|
)
|
||
Unamortized discount
|
|
(7,702
|
)
|
|
(9,205
|
)
|
||
Total
|
|
1,724,190
|
|
|
1,670,416
|
|
||
Less current maturities (including elimination of PSCo capital lease obligation)
|
|
(2,617
|
)
|
|
(2,271
|
)
|
||
Total Xcel Energy Inc. long-term debt
|
|
$
|
1,726,807
|
|
|
$
|
1,672,687
|
|
Total long-term debt
|
|
$
|
10,910,754
|
|
|
$
|
10,143,905
|
|
|
|
|
|
|
||||
Common Stockholders’ Equity
|
|
|
|
|
|
|
||
Common stock — 1,000,000,000 shares authorized of $2.50 par value; 497,971,508 and 487,959,516 shares outstanding at Dec. 31, 2013 and 2012, respectively
|
|
$
|
1,244,929
|
|
|
$
|
1,219,899
|
|
Additional paid in capital
|
|
5,619,313
|
|
|
5,353,015
|
|
||
Retained earnings
|
|
2,807,983
|
|
|
2,413,816
|
|
||
Accumulated other comprehensive loss
|
|
(106,275
|
)
|
|
(112,653
|
)
|
||
Total common stockholders’ equity
|
|
$
|
9,565,950
|
|
|
$
|
8,874,077
|
|
(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, 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.
|
2.
|
Accounting Pronouncements
|
3.
|
Selected Balance Sheet Data
|
(Thousands of Dollars)
|
|
Dec. 31, 2013
|
|
Dec. 31, 2012
|
||||
Accounts receivable, net
|
|
|
|
|
||||
Accounts receivable
|
|
$
|
797,267
|
|
|
$
|
769,440
|
|
Less allowance for bad debts
|
|
(53,107
|
)
|
|
(51,394
|
)
|
||
|
|
$
|
744,160
|
|
|
$
|
718,046
|
|
(Thousands of Dollars)
|
|
Dec. 31, 2013
|
|
Dec. 31, 2012
|
||||
Inventories
|
|
|
|
|
||||
Materials and supplies
|
|
$
|
225,308
|
|
|
$
|
213,739
|
|
Fuel
|
|
189,485
|
|
|
189,425
|
|
||
Natural gas
|
|
161,745
|
|
|
132,410
|
|
||
|
|
$
|
576,538
|
|
|
$
|
535,574
|
|
(Thousands of Dollars)
|
|
Dec. 31, 2013
|
|
Dec. 31, 2012
|
||||
Property, plant and equipment, net
|
|
|
|
|
||||
Electric plant
|
|
$
|
30,341,310
|
|
|
$
|
28,285,031
|
|
Natural gas plant
|
|
4,086,651
|
|
|
3,836,335
|
|
||
Common and other property
|
|
1,485,547
|
|
|
1,480,558
|
|
||
Plant to be retired
(a)
|
|
101,279
|
|
|
152,730
|
|
||
CWIP
|
|
2,371,566
|
|
|
1,757,189
|
|
||
Total property, plant and equipment
|
|
38,386,353
|
|
|
35,511,843
|
|
||
Less accumulated depreciation
|
|
(12,608,305
|
)
|
|
(12,048,697
|
)
|
||
Nuclear fuel
|
|
2,186,799
|
|
|
2,090,801
|
|
||
Less accumulated amortization
|
|
(1,842,688
|
)
|
|
(1,744,599
|
)
|
||
|
|
$
|
26,122,159
|
|
|
$
|
23,809,348
|
|
(a)
|
As a result of the CPUC’s 2010 approval of PSCo’s CACJA compliance plan, subsequent CPCNs and the December 2013 approval of PSCo’s preferred plans for applicable generating resources, PSCo has received approval for early retirement of Cherokee Units 1, 2 and 3, Arapahoe Units 3 and 4 and Valmont Unit 5 between 2011 and 2017. In 2011, Cherokee Unit 2 was retired, in 2012, Cherokee Unit 1 was retired, and in 2013, Arapahoe Units 3 and 4 were retired. Amounts are presented net of accumulated depreciation.
|
4.
|
Borrowings and Other Financing Instruments
|
(Amounts in Millions, Except Interest Rates)
|
|
Three Months Ended
Dec. 31, 2013
|
||
Borrowing limit
|
|
$
|
2,450
|
|
Amount outstanding at period end
|
|
759
|
|
|
Average amount outstanding
|
|
515
|
|
|
Maximum amount outstanding
|
|
759
|
|
|
Weighted average interest rate, computed on a daily basis
|
|
0.29
|
%
|
|
Weighted average interest rate at period end
|
|
0.25
|
|
(Amounts in Millions, Except Interest Rates)
|
|
Twelve Months Ended
Dec. 31, 2013
|
|
Twelve Months Ended
Dec. 31, 2012
|
|
Twelve Months Ended
Dec. 31, 2011
|
||||||
Borrowing limit
|
|
$
|
2,450
|
|
|
$
|
2,450
|
|
|
$
|
2,450
|
|
Amount outstanding at period end
|
|
759
|
|
|
602
|
|
|
219
|
|
|||
Average amount outstanding
|
|
481
|
|
|
403
|
|
|
430
|
|
|||
Maximum amount outstanding
|
|
1,160
|
|
|
634
|
|
|
824
|
|
|||
Weighted average interest rate, computed on a daily basis
|
|
0.31
|
%
|
|
0.35
|
%
|
|
0.36
|
%
|
|||
Weighted average interest rate at end of period
|
|
0.25
|
|
|
0.36
|
|
|
0.40
|
|
•
|
Xcel Energy Inc. may increase its credit facility by up to
$200 million
, NSP-Minnesota and PSCo may each increase their credit facilities by
$100 million
and SPS may increase its credit facility by
$50 million
. The NSP-Wisconsin credit facility cannot be increased.
|
•
|
Each credit facility has a financial covenant requiring that the debt-to-total capitalization ratio of each entity be less than or equal to
65 percent
. Each entity was in compliance at Dec. 31, 2013 and 2012, respectively, as evidenced by the table below:
|
•
|
If Xcel Energy Inc. or any of its utility subsidiaries do not comply with the covenant, an event of default may be declared, and if not remedied, any outstanding amounts due under the facility can be declared due by the lender.
|
•
|
The Xcel Energy Inc. credit facility has a cross-default provision that provides Xcel Energy Inc. will be in default on its borrowings under the facility if it or any of its subsidiaries, except NSP-Wisconsin as long as its total assets do not comprise more than
15 percent
of Xcel Energy’s consolidated total assets, default on certain indebtedness in an aggregate principal amount exceeding
$75 million
.
|
•
|
The interest rates under these lines of credit are based on Eurodollar borrowing margins ranging from 87.5 to 175 basis points per year based on the applicable long-term credit ratings.
|
•
|
The commitment fees, also based on applicable long-term credit ratings, are calculated on the unused portion of the lines of credit at a range of 7.5 to 27.5 basis points per year.
|
(Millions of Dollars)
|
|
Credit Facility
(a)
|
|
Drawn
(b)
|
|
Available
|
||||||
Xcel Energy Inc.
|
|
$
|
800.0
|
|
|
$
|
476.0
|
|
|
$
|
324.0
|
|
PSCo
|
|
700.0
|
|
|
6.4
|
|
|
693.6
|
|
|||
NSP-Minnesota
|
|
500.0
|
|
|
146.9
|
|
|
353.1
|
|
|||
SPS
|
|
300.0
|
|
|
109.5
|
|
|
190.5
|
|
|||
NSP-Wisconsin
|
|
150.0
|
|
|
68.0
|
|
|
82.0
|
|
|||
Total
|
|
$
|
2,450.0
|
|
|
$
|
806.8
|
|
|
$
|
1,643.2
|
|
(a)
|
These credit facilities expire in July 2017.
|
(b)
|
Includes outstanding commercial paper and letters of credit.
|
•
|
In March 2013, PSCo issued
$250 million
of
2.50 percent
first mortgage bonds due
March 15, 2023
and
$250 million
of
3.95 percent
first mortgage bonds due
March 15, 2043
.
|
•
|
In May 2013, Xcel Energy Inc. issued
$450 million
of
0.75 percent
senior unsecured notes due
May 9, 2016
.
|
•
|
In May 2013, NSP-Minnesota issued
$400 million
of
2.60 percent
first mortgage bonds due
May 15, 2023
.
|
•
|
In August 2013, SPS issued
$100 million
of
4.50 percent
first mortgage bonds due
Aug. 15, 2041
. Including the
$300 million
of this series previously issued, total principal outstanding for this series is
$400 million
.
|
•
|
In June 2012, SPS issued an additional
$100 million
of its
4.50 percent
first mortgage bonds due
Aug. 15, 2041
.
|
•
|
In August 2012, NSP-Minnesota issued
$300 million
of
2.15 percent
first mortgage bonds due
Aug. 15, 2022
, and
$500 million
of
3.40 percent
first mortgage bonds due
Aug. 15, 2042
.
|
•
|
In September 2012, PSCo issued
$300 million
of
2.25 percent
first mortgage bonds due
Sept. 15, 2022
, and
$500 million
of
3.60 percent
first mortgage bonds due
Sept. 15, 2042
.
|
•
|
In October 2012, NSP-Wisconsin issued
$100 million
of
3.70 percent
first mortgage bonds due
Oct. 1, 2042
.
|
•
|
PSCo currently has authorization to issue up to an additional
$1 billion
of long-term debt and up to
$800 million
of short-term debt.
|
•
|
SPS currently has no authorization to issue any long-term debt in 2014 and up to
$400 million
of short-term debt.
|
•
|
NSP-Wisconsin currently has authorization to issue up to an additional
$150 million
of long-term debt and up to
$150 million
of short-term debt.
|
•
|
NSP-Minnesota has authorization to issue long-term securities provided the equity-to-total capitalization ratio remains between
46.8 percent
and
57.2 percent
and to issue short-term debt provided it does not exceed
15 percent
of total capitalization. Total capitalization for NSP-Minnesota cannot exceed
$9 billion
.
|
5.
|
Joint Ownership of Generation, Transmission and Gas Facilities
|
(Thousands of Dollars)
|
|
Plant in
Service
|
|
Accumulated
Depreciation
|
|
CWIP
|
|
Ownership %
|
|||||||
NSP-Minnesota
|
|
|
|
|
|
|
|
|
|||||||
Electric Generation:
|
|
|
|
|
|
|
|
|
|||||||
Sherco Unit 3
|
|
$
|
596,314
|
|
|
$
|
371,925
|
|
|
$
|
4,533
|
|
|
59.0
|
%
|
Sherco Common Facilities Units 1, 2 and 3
|
|
145,579
|
|
|
87,289
|
|
|
61
|
|
|
80.0
|
|
|||
Sherco Substation
|
|
4,790
|
|
|
2,884
|
|
|
—
|
|
|
59.0
|
|
|||
Electric Transmission:
|
|
|
|
|
|
|
|
|
|||||||
Grand Meadow Line and Substation
|
|
10,647
|
|
|
1,225
|
|
|
—
|
|
|
50.0
|
|
|||
CapX2020 Transmission
|
|
340,333
|
|
|
77,803
|
|
|
503,714
|
|
|
53.3
|
|
|||
Total NSP-Minnesota
|
|
$
|
1,097,663
|
|
|
$
|
541,126
|
|
|
$
|
508,308
|
|
|
|
(Thousands of Dollars)
|
|
Plant in
Service
|
|
Accumulated
Depreciation
|
|
CWIP
|
|
Ownership %
|
|||||||
NSP-Wisconsin
|
|
|
|
|
|
|
|
|
|||||||
Electric Transmission:
|
|
|
|
|
|
|
|
|
|||||||
CapX2020 Transmission
|
|
$
|
13,337
|
|
|
$
|
4,659
|
|
|
$
|
30,199
|
|
|
77.9
|
%
|
La Crosse, Wis. to Madison, Wis.
|
|
—
|
|
|
—
|
|
|
5,431
|
|
|
50.0
|
|
|||
Total NSP-Wisconsin
|
|
$
|
13,337
|
|
|
$
|
4,659
|
|
|
$
|
35,630
|
|
|
|
(Thousands of Dollars)
|
|
Plant in
Service
|
|
Accumulated
Depreciation
|
|
CWIP
|
|
Ownership %
|
|||||||
PSCo
|
|
|
|
|
|
|
|
|
|||||||
Electric Generation:
|
|
|
|
|
|
|
|
|
|||||||
Hayden Unit 1
|
|
$
|
97,879
|
|
|
$
|
63,474
|
|
|
$
|
53
|
|
|
75.5
|
%
|
Hayden Unit 2
|
|
119,972
|
|
|
57,875
|
|
|
5,563
|
|
|
37.4
|
|
|||
Hayden Common Facilities
|
|
36,916
|
|
|
16,055
|
|
|
2
|
|
|
53.1
|
|
|||
Craig Units 1 and 2
|
|
60,089
|
|
|
34,754
|
|
|
537
|
|
|
9.7
|
|
|||
Craig Common Facilities 1, 2 and 3
|
|
37,177
|
|
|
17,247
|
|
|
—
|
|
|
6.5
|
|
|||
Comanche Unit 3
|
|
877,489
|
|
|
63,963
|
|
|
581
|
|
|
66.7
|
|
|||
Comanche Common Facilities
|
|
19,812
|
|
|
711
|
|
|
2,255
|
|
|
82.0
|
|
|||
Electric Transmission:
|
|
|
|
|
|
|
|
|
|||||||
Transmission and other facilities, including substations
|
|
150,502
|
|
|
59,118
|
|
|
827
|
|
|
Various
|
|
|||
Gas Transportation:
|
|
|
|
|
|
|
|
|
|||||||
Rifle, Colo. to Avon, Colo.
|
|
16,278
|
|
|
6,044
|
|
|
—
|
|
|
60.0
|
|
|||
Total PSCo
|
|
$
|
1,416,114
|
|
|
$
|
319,241
|
|
|
$
|
9,818
|
|
|
|
6.
|
Income Taxes
|
•
|
The top tax rate for dividends increased from
15 percent
to
20 percent
. The
20 percent
dividend rate is now consistent with the tax rates for capital gains;
|
•
|
The research and experimentation (R&E) credit was extended for 2012 and 2013;
|
•
|
PTCs were extended for projects that begin construction before the end of 2013; and
|
•
|
50 percent
bonus depreciation was extended
one
year through 2013. Additionally, some longer production period property placed in service in 2014 is also eligible for
50 percent
bonus depreciation.
|
State
|
|
Year
|
Colorado
|
|
2009
|
Minnesota
|
|
2009
|
Texas
|
|
2008
|
Wisconsin
|
|
2009
|
(Millions of Dollars)
|
|
Dec. 31, 2013
|
|
Dec. 31, 2012
|
||||
Unrecognized tax benefit — Permanent tax positions
|
|
$
|
12.9
|
|
|
$
|
4.7
|
|
Unrecognized tax benefit — Temporary tax positions
|
|
28.3
|
|
|
29.8
|
|
||
Total unrecognized tax benefit
|
|
$
|
41.2
|
|
|
$
|
34.5
|
|
(Millions of Dollars)
|
|
2013
|
|
2012
|
|
2011
|
||||||
Balance at Jan. 1
|
|
$
|
34.5
|
|
|
$
|
34.7
|
|
|
$
|
40.5
|
|
Additions based on tax positions related to the current year
|
|
15.1
|
|
|
5.2
|
|
|
11.9
|
|
|||
Reductions based on tax positions related to the current year
|
|
(0.4
|
)
|
|
(5.7
|
)
|
|
(1.9
|
)
|
|||
Additions for tax positions of prior years
|
|
21.6
|
|
|
9.6
|
|
|
14.0
|
|
|||
Reductions for tax positions of prior years
|
|
(4.8
|
)
|
|
(9.3
|
)
|
|
(2.4
|
)
|
|||
Settlements with taxing authorities
|
|
(24.8
|
)
|
|
—
|
|
|
(27.3
|
)
|
|||
Lapse of applicable statutes of limitations
|
|
—
|
|
|
—
|
|
|
(0.1
|
)
|
|||
Balance at Dec. 31
|
|
$
|
41.2
|
|
|
$
|
34.5
|
|
|
$
|
34.7
|
|
(Millions of Dollars)
|
|
Dec. 31, 2013
|
|
Dec. 31, 2012
|
||||
NOL and tax credit carryforwards
|
|
$
|
(27.1
|
)
|
|
$
|
(33.5
|
)
|
(Millions of Dollars)
|
|
2013
|
|
2012
|
||||
Federal NOL carryforward
|
|
$
|
1,311
|
|
|
$
|
969
|
|
Federal tax credit carryforwards
|
|
294
|
|
|
257
|
|
||
State NOL carryforwards
|
|
1,706
|
|
|
1,465
|
|
||
Valuation allowances for state NOL carryforwards
|
|
(51
|
)
|
|
(52
|
)
|
||
State tax credit carryforwards, net of federal detriment
(a)
|
|
17
|
|
|
17
|
|
(a)
|
State tax credit carryforwards are net of federal detriment of
$9 million
as of Dec. 31, 2013 and 2012.
|
(Thousands of Dollars)
|
|
2013
|
|
2012
|
|
2011
|
||||||
Current federal tax (benefit) expense
|
|
$
|
(46,173
|
)
|
|
$
|
7,876
|
|
|
$
|
3,399
|
|
Current state tax expense
|
|
7,678
|
|
|
31,478
|
|
|
9,971
|
|
|||
Current change in unrecognized tax expense (benefit)
|
|
13,162
|
|
|
(1,704
|
)
|
|
(8,266
|
)
|
|||
Deferred federal tax expense
|
|
439,085
|
|
|
366,409
|
|
|
383,931
|
|
|||
Deferred state tax expense
|
|
80,907
|
|
|
50,741
|
|
|
78,770
|
|
|||
Deferred change in unrecognized tax (benefit) expense
|
|
(4,930
|
)
|
|
2,013
|
|
|
6,705
|
|
|||
Deferred investment tax credits
|
|
(5,753
|
)
|
|
(6,610
|
)
|
|
(6,194
|
)
|
|||
Total income tax expense
|
|
$
|
483,976
|
|
|
$
|
450,203
|
|
|
$
|
468,316
|
|
(Thousands of Dollars)
|
|
2013
|
|
2012
|
|
2011
|
||||||
Deferred tax expense excluding items below
|
|
$
|
588,053
|
|
|
$
|
559,860
|
|
|
$
|
446,893
|
|
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities
|
|
(64,420
|
)
|
|
(63,862
|
)
|
|
(7,108
|
)
|
|||
Tax (expense) benefit allocated to OCI
|
|
(8,572
|
)
|
|
12,102
|
|
|
26,798
|
|
|||
Other
|
|
1
|
|
|
(6
|
)
|
|
(16
|
)
|
|||
Deferred tax expense
|
|
$
|
515,062
|
|
|
$
|
508,094
|
|
|
$
|
466,567
|
|
(Thousands of Dollars)
|
|
2013
|
|
2012
|
||||
Deferred tax liabilities:
|
|
|
|
|
|
|
||
Differences between book and tax bases of property
|
|
$
|
5,562,446
|
|
|
$
|
4,867,142
|
|
Regulatory assets
|
|
321,636
|
|
|
293,367
|
|
||
Other
|
|
254,639
|
|
|
220,781
|
|
||
Total deferred tax liabilities
|
|
$
|
6,138,721
|
|
|
$
|
5,381,290
|
|
|
|
|
|
|
||||
Deferred tax assets:
|
|
|
|
|
|
|
||
NOL carryforward
|
|
$
|
532,774
|
|
|
$
|
430,765
|
|
Tax credit carryforward
|
|
311,388
|
|
|
273,776
|
|
||
Unbilled revenue - fuel costs
|
|
58,908
|
|
|
60,068
|
|
||
Rate refund
|
|
49,804
|
|
|
8,109
|
|
||
Environmental remediation
|
|
42,886
|
|
|
44,549
|
|
||
Regulatory liabilities
|
|
40,947
|
|
|
34,471
|
|
||
Deferred investment tax credits
|
|
34,231
|
|
|
35,767
|
|
||
Other
|
|
81,202
|
|
|
95,308
|
|
||
NOL and tax credit valuation allowances
|
|
(3,263
|
)
|
|
(3,314
|
)
|
||
Total deferred tax assets
|
|
$
|
1,148,877
|
|
|
$
|
979,499
|
|
Net deferred tax liability
|
|
$
|
4,989,844
|
|
|
$
|
4,401,791
|
|
7.
|
Earnings Per Share
|
•
|
RSU equity awards subject to a performance condition; included in common shares outstanding when all necessary conditions for settlement have been satisfied by the end of the reporting period.
|
•
|
PSP liability awards subject to a performance condition; any portions settled in shares are included in common shares outstanding upon settlement.
|
|
|
2013
|
|
2012
|
|
2011
|
|||||||||||||||||||||||||||
(Amounts in thousands, except per share data)
|
|
Income
|
|
Shares
|
|
Per
Share
Amount
|
|
Income
|
|
Shares
|
|
Per
Share
Amount
|
|
Income
|
|
Shares
|
|
Per
Share
Amount
|
|||||||||||||||
Net income
|
|
$
|
948,234
|
|
|
|
|
|
|
|
|
$
|
905,229
|
|
|
|
|
|
|
|
|
$
|
841,172
|
|
|
|
|
|
|||||
Less: Dividend requirements on preferred stock
|
|
—
|
|
|
|
|
|
|
|
|
—
|
|
|
|
|
|
|
|
|
(3,534
|
)
|
|
|
|
|
||||||||
Less: Premium on redemption of preferred stock
|
|
—
|
|
|
|
|
|
|
|
|
—
|
|
|
|
|
|
|
|
|
(3,260
|
)
|
|
|
|
|
||||||||
Basic earnings per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||
Earnings available to common shareholders
|
|
948,234
|
|
|
496,073
|
|
|
$
|
1.91
|
|
|
905,229
|
|
|
487,899
|
|
|
$
|
1.86
|
|
|
834,378
|
|
|
485,039
|
|
|
$
|
1.72
|
|
|||
Effect of dilutive securities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
401(k) equity awards
|
|
—
|
|
|
459
|
|
|
|
|
|
—
|
|
|
535
|
|
|
|
|
|
—
|
|
|
576
|
|
|
|
|
||||||
Diluted earnings per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||
Earnings available to common shareholders
|
|
$
|
948,234
|
|
|
496,532
|
|
|
$
|
1.91
|
|
|
$
|
905,229
|
|
|
488,434
|
|
|
$
|
1.85
|
|
|
$
|
834,378
|
|
|
485,615
|
|
|
$
|
1.72
|
|
8.
|
Share-Based Compensation
|
|
|
2011
|
|||||
(Awards in Thousands)
|
|
Awards
|
|
Average
Exercise Price |
|||
Outstanding and exercisable at Jan. 1
|
|
2,498
|
|
|
$
|
30.42
|
|
Exercised
|
|
(1,173
|
)
|
|
25.90
|
|
|
Expired
|
|
(1,325
|
)
|
|
34.42
|
|
|
Outstanding and exercisable at Dec. 31
|
|
—
|
|
|
—
|
|
(Thousands of Dollars)
|
|
2011
|
||
Market value of exercises
|
|
$
|
30,761
|
|
Intrinsic value of options exercised
(a)
|
|
380
|
|
(a)
|
Intrinsic value is calculated as market price at exercise date less the option exercise price.
|
(Thousands of Dollars)
|
|
2011
|
||
Cash received from stock options exercised
|
|
$
|
30,381
|
|
Tax benefit realized for the tax deductions from stock options exercised
|
|
157
|
|
(Shares in Thousands)
|
|
2013
|
|
2012
|
|
2011
|
||||||
Granted shares
|
|
33
|
|
|
33
|
|
|
15
|
|
|||
Grant date fair value
|
|
$
|
28.30
|
|
|
$
|
26.43
|
|
|
$
|
23.62
|
|
(Shares in Thousands)
|
|
Shares
|
|
Weighted Average
Grant Date Fair Value |
|||
Nonvested restricted stock at Jan. 1, 2013
|
|
54
|
|
|
$
|
24.85
|
|
Granted
|
|
33
|
|
|
28.30
|
|
|
Vested
|
|
(27
|
)
|
|
23.65
|
|
|
Dividend equivalents
|
|
2
|
|
|
28.88
|
|
|
Nonvested restricted stock at Dec. 31, 2013
|
|
62
|
|
|
27.33
|
|
(Units in Thousands)
|
|
2013
|
|
2012
|
|
2011
|
||||||
Granted units
|
|
774
|
|
|
591
|
|
|
828
|
|
|||
Weighted average grant date fair value
|
|
$
|
27.65
|
|
|
$
|
27.35
|
|
|
$
|
23.63
|
|
(Units in Thousands)
|
|
Units
|
|
Weighted
Average Grant Date Fair Value |
|||
Nonvested RSUs at Jan. 1, 2013
|
|
1,155
|
|
|
$
|
25.41
|
|
Granted
|
|
774
|
|
|
27.65
|
|
|
Forfeited
|
|
(81
|
)
|
|
26.32
|
|
|
Vested
|
|
(600
|
)
|
|
23.62
|
|
|
Dividend equivalents
|
|
64
|
|
|
26.11
|
|
|
Nonvested RSUs at Dec. 31, 2013
|
|
1,312
|
|
|
27.53
|
|
(Units in Thousands)
|
|
2013
|
|
2012
|
|
2011
|
||||||
Granted units
|
|
69
|
|
|
65
|
|
|
60
|
|
|||
Grant date fair value
|
|
$
|
29.52
|
|
|
$
|
27.41
|
|
|
$
|
25.12
|
|
(Units in Thousands)
|
|
Units
|
|
Weighted
Average Grant Date Fair Value |
|||
Stock equivalent units at Jan. 1, 2013
|
|
577
|
|
|
$
|
21.71
|
|
Granted
|
|
69
|
|
|
29.52
|
|
|
Units distributed
|
|
(32
|
)
|
|
18.23
|
|
|
Dividend equivalents
|
|
22
|
|
|
29.06
|
|
|
Stock equivalent units at Dec. 31, 2013
|
|
636
|
|
|
22.98
|
|
(In Thousands)
|
|
2013
|
|
2012
|
|
2011
|
|||
Awards granted
|
|
215
|
|
|
161
|
|
|
311
|
|
(In Thousands)
|
|
2013
|
|
2012
|
|
2011
|
||||||
Awards settled
|
|
108
|
|
|
286
|
|
|
305
|
|
|||
Settlement amount (cash and common stock)
|
|
$
|
3,057
|
|
|
$
|
7,554
|
|
|
$
|
7,200
|
|
(Thousands of Dollars)
|
|
2013
|
|
2012
|
|
2011
|
||||||
Compensation cost for share-based awards
(a) (b) (c)
|
|
$
|
24,613
|
|
|
$
|
26,970
|
|
|
$
|
45,006
|
|
Tax benefit recognized in income
|
|
9,571
|
|
|
10,513
|
|
|
17,559
|
|
|||
Capitalized compensation cost for share-based awards
|
|
1,698
|
|
|
4,270
|
|
|
3,857
|
|
(a)
|
Compensation costs for share-based payment arrangements is included in O&M expense in the consolidated statements of income.
|
(b)
|
Included in compensation cost for share-based awards are matching contributions related to the Xcel Energy 401(k) plan, which totaled
$7.0 million
,
$22.2 million
and
$21.6 million
for the years ended 2013, 2012 and 2011, respectively.
|
(c)
|
In October 2013, Xcel Energy determined that it would settle the 2013 401(k) employer match in cash instead of common stock for all employee groups except PSCo bargaining employees. Share-based compensation accounting for the impacted employee groups ceased in October 2013, and corresponding expense amounts recorded to equity were reclassified to a liability for expected cash settlements.
|
9.
|
Benefit Plans and Other Postretirement Benefits
|
•
|
NSP-Minnesota had
2,022
a
nd NSP-Wisconsin had
399
bargaining employees covered under a collective-bargaining agreement, which expires at the end of 2016. NSP-Minnesota also had an additional
248
nuclear operation bargaining employees covered under several collective-bargaining agreements, which expire at various dates in 2015 and 2016.
|
•
|
PSCo had
2,086
bargaining employees covered under a collective-bargaining agreement, which expires in May 2014.
|
•
|
SPS had
832
bargaining employees covered under a collective-bargaining agreement, which expires in October 2014.
|
|
|
2013
|
|
2012
|
||
Domestic and international equity securities
|
|
30
|
%
|
|
25
|
%
|
Long-duration fixed income and interest rate swap securities
|
|
33
|
|
|
40
|
|
Short-to-intermediate fixed income securities
|
|
15
|
|
|
10
|
|
Alternative investments
|
|
20
|
|
|
23
|
|
Cash
|
|
2
|
|
|
2
|
|
Total
|
|
100
|
%
|
|
100
|
%
|
|
|
Dec. 31, 2013
|
||||||||||||||
(Thousands of Dollars)
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
||||||||
Cash equivalents
|
|
$
|
109,700
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
109,700
|
|
Derivatives
|
|
—
|
|
|
29,759
|
|
|
—
|
|
|
29,759
|
|
||||
Government securities
|
|
—
|
|
|
230,212
|
|
|
—
|
|
|
230,212
|
|
||||
Corporate bonds
|
|
—
|
|
|
547,715
|
|
|
—
|
|
|
547,715
|
|
||||
Asset-backed securities
|
|
—
|
|
|
6,754
|
|
|
—
|
|
|
6,754
|
|
||||
Mortgage-backed securities
|
|
—
|
|
|
15,025
|
|
|
—
|
|
|
15,025
|
|
||||
Common stock
|
|
99,346
|
|
|
—
|
|
|
—
|
|
|
99,346
|
|
||||
Private equity investments
|
|
—
|
|
|
—
|
|
|
152,849
|
|
|
152,849
|
|
||||
Commingled funds
|
|
—
|
|
|
1,769,076
|
|
|
—
|
|
|
1,769,076
|
|
||||
Real estate
|
|
—
|
|
|
—
|
|
|
47,553
|
|
|
47,553
|
|
||||
Securities lending collateral obligation and other
|
|
—
|
|
|
2,151
|
|
|
—
|
|
|
2,151
|
|
||||
Total
|
|
$
|
209,046
|
|
|
$
|
2,600,692
|
|
|
$
|
200,402
|
|
|
$
|
3,010,140
|
|
|
|
Dec. 31, 2012
|
||||||||||||||
(Thousands of Dollars)
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
||||||||
Cash equivalents
|
|
$
|
164,096
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
164,096
|
|
Derivatives
|
|
—
|
|
|
12,955
|
|
|
—
|
|
|
12,955
|
|
||||
Government securities
|
|
—
|
|
|
298,141
|
|
|
—
|
|
|
298,141
|
|
||||
Corporate bonds
|
|
—
|
|
|
622,597
|
|
|
—
|
|
|
622,597
|
|
||||
Asset-backed securities
|
|
—
|
|
|
—
|
|
|
14,639
|
|
|
14,639
|
|
||||
Mortgage-backed securities
|
|
—
|
|
|
—
|
|
|
39,904
|
|
|
39,904
|
|
||||
Common stock
|
|
73,247
|
|
|
—
|
|
|
—
|
|
|
73,247
|
|
||||
Private equity investments
|
|
—
|
|
|
—
|
|
|
158,498
|
|
|
158,498
|
|
||||
Commingled funds
|
|
—
|
|
|
1,524,563
|
|
|
—
|
|
|
1,524,563
|
|
||||
Real estate
|
|
—
|
|
|
—
|
|
|
64,597
|
|
|
64,597
|
|
||||
Securities lending collateral obligation and other
|
|
—
|
|
|
(29,454
|
)
|
|
—
|
|
|
(29,454
|
)
|
||||
Total
|
|
$
|
237,343
|
|
|
$
|
2,428,802
|
|
|
$
|
277,638
|
|
|
$
|
2,943,783
|
|
(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)
|
|
Jan. 1, 2012
|
|
Net Realized
Gains (Losses) |
|
Net Unrealized
Gains (Losses) |
|
Purchases,
Issuances and Settlements, Net |
|
Transfers Out of Level 3
|
|
Dec. 31, 2012
|
||||||||||||
Asset-backed securities
|
|
$
|
31,368
|
|
|
$
|
3,886
|
|
|
$
|
(5,363
|
)
|
|
$
|
(15,252
|
)
|
|
$
|
—
|
|
|
$
|
14,639
|
|
Mortgage-backed securities
|
|
73,522
|
|
|
1,822
|
|
|
(2,127
|
)
|
|
(33,313
|
)
|
|
—
|
|
|
39,904
|
|
||||||
Private equity investments
|
|
159,363
|
|
|
17,537
|
|
|
(22,587
|
)
|
|
4,185
|
|
|
—
|
|
|
158,498
|
|
||||||
Real estate
|
|
37,106
|
|
|
19
|
|
|
6,048
|
|
|
21,424
|
|
|
—
|
|
|
64,597
|
|
||||||
Total
|
|
$
|
301,359
|
|
|
$
|
23,264
|
|
|
$
|
(24,029
|
)
|
|
$
|
(22,956
|
)
|
|
$
|
—
|
|
|
$
|
277,638
|
|
(Thousands of Dollars)
|
|
Jan. 1, 2011
|
|
Net Realized
Gains (Losses) |
|
Net Unrealized
Gains (Losses) |
|
Purchases,
Issuances and Settlements, Net |
|
Transfers Out of Level 3
|
|
Dec. 31, 2011
|
||||||||||||
Asset-backed securities
|
|
$
|
26,986
|
|
|
$
|
2,391
|
|
|
$
|
(2,504
|
)
|
|
$
|
4,495
|
|
|
$
|
—
|
|
|
$
|
31,368
|
|
Mortgage-backed securities
|
|
113,418
|
|
|
1,103
|
|
|
(5,926
|
)
|
|
(35,073
|
)
|
|
—
|
|
|
73,522
|
|
||||||
Private equity investments
|
|
122,223
|
|
|
3,971
|
|
|
12,412
|
|
|
20,757
|
|
|
—
|
|
|
159,363
|
|
||||||
Real estate
|
|
73,701
|
|
|
(629
|
)
|
|
20,271
|
|
|
(56,237
|
)
|
|
—
|
|
|
37,106
|
|
||||||
Total
|
|
$
|
336,328
|
|
|
$
|
6,836
|
|
|
$
|
24,253
|
|
|
$
|
(66,058
|
)
|
|
$
|
—
|
|
|
$
|
301,359
|
|
(Thousands of Dollars)
|
|
2013
|
|
2012
|
||||
Accumulated Benefit Obligation at Dec. 31
|
|
$
|
3,282,651
|
|
|
$
|
3,475,154
|
|
|
|
|
|
|
||||
Change in Projected Benefit Obligation:
|
|
|
|
|
|
|
||
Obligation at Jan. 1
|
|
$
|
3,639,530
|
|
|
$
|
3,226,219
|
|
Service cost
|
|
96,282
|
|
|
86,364
|
|
||
Interest cost
|
|
140,690
|
|
|
157,035
|
|
||
Plan amendments
|
|
(4,120
|
)
|
|
6,240
|
|
||
Actuarial (gain) loss
|
|
(153,338
|
)
|
|
400,429
|
|
||
Benefit payments
|
|
(278,340
|
)
|
|
(236,757
|
)
|
||
Obligation at Dec. 31
|
|
$
|
3,440,704
|
|
|
$
|
3,639,530
|
|
(Thousands of Dollars)
|
|
2013
|
|
2012
|
||||
Change in Fair Value of Plan Assets:
|
|
|
|
|
||||
Fair value of plan assets at Jan. 1
|
|
$
|
2,943,783
|
|
|
$
|
2,670,280
|
|
Actual return on plan assets
|
|
152,259
|
|
|
312,167
|
|
||
Employer contributions
|
|
192,438
|
|
|
198,093
|
|
||
Benefit payments
|
|
(278,340
|
)
|
|
(236,757
|
)
|
||
Fair value of plan assets at Dec. 31
|
|
$
|
3,010,140
|
|
|
$
|
2,943,783
|
|
(Thousands of Dollars)
|
|
2013
|
|
2012
|
||||
Funded Status of Plans at Dec. 31:
|
|
|
|
|
||||
Funded status
(a)
|
|
$
|
(430,564
|
)
|
|
$
|
(695,747
|
)
|
(a)
|
Amounts are recognized in noncurrent liabilities on Xcel Energy’s consolidated balance sheets.
|
(Thousands of Dollars)
|
|
2013
|
|
2012
|
||||
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:
|
|
|
|
|
||||
Net loss
|
|
$
|
1,549,474
|
|
|
$
|
1,800,770
|
|
Prior service credit
|
|
(12,624
|
)
|
|
(2,633
|
)
|
||
Total
|
|
$
|
1,536,850
|
|
|
$
|
1,798,137
|
|
(Thousands of Dollars)
|
|
2013
|
|
2012
|
||||
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
|
|
$
|
125,702
|
|
|
$
|
115,811
|
|
Noncurrent regulatory assets
|
|
1,343,432
|
|
|
1,606,524
|
|
||
Deferred income taxes
|
|
26,403
|
|
|
31,075
|
|
||
Net-of-tax accumulated OCI
|
|
41,313
|
|
|
44,727
|
|
||
Total
|
|
$
|
1,536,850
|
|
|
$
|
1,798,137
|
|
Measurement date
|
|
Dec. 31, 2013
|
|
Dec. 31, 2012
|
|
|
2013
|
|
2012
|
||
Significant Assumptions Used to Measure Benefit Obligations:
|
|
|
|
|
||
Discount rate for year-end valuation
|
|
4.75
|
%
|
|
4.00
|
%
|
Expected average long-term increase in compensation level
|
|
3.75
|
|
|
3.75
|
|
Mortality table
|
|
RP 2000
|
|
|
RP 2000
|
|
•
|
In January 2014, contributions of
$130.0 million
were made across
three
of Xcel Energy’s pension plans;
|
•
|
In 2013, contributions of
$192.4 million
were made across
four
of Xcel Energy’s pension plans;
|
•
|
In 2012, contributions of
$198.1 million
were made across
four
of Xcel Energy’s pension plans;
|
•
|
In 2011, contributions of
$137.3 million
were made across
three
of Xcel Energy’s pension plans;
|
•
|
For future years, Xcel Energy anticipates contributions will be made as necessary.
|
(Thousands of Dollars)
|
|
2013
|
|
2012
|
|
2011
|
||||||
Service cost
|
|
$
|
96,282
|
|
|
$
|
86,364
|
|
|
$
|
77,319
|
|
Interest cost
|
|
140,690
|
|
|
157,035
|
|
|
161,412
|
|
|||
Expected return on plan assets
|
|
(198,452
|
)
|
|
(207,095
|
)
|
|
(221,600
|
)
|
|||
Amortization of prior service cost
|
|
5,871
|
|
|
21,065
|
|
|
22,533
|
|
|||
Amortization of net loss
|
|
144,151
|
|
|
108,982
|
|
|
78,510
|
|
|||
Net periodic pension cost
|
|
188,542
|
|
|
166,351
|
|
|
118,174
|
|
|||
Costs not recognized due to effects of regulation
|
|
(36,724
|
)
|
|
(39,217
|
)
|
|
(37,198
|
)
|
|||
Net benefit cost recognized for financial reporting
|
|
$
|
151,818
|
|
|
$
|
127,134
|
|
|
$
|
80,976
|
|
|
|
2013
|
|
2012
|
|
2011
|
|||
Significant Assumptions Used to Measure Costs:
|
|
|
|
|
|
|
|||
Discount rate
|
|
4.00
|
%
|
|
5.00
|
%
|
|
5.50
|
%
|
Expected average long-term increase in compensation level
|
|
3.75
|
|
|
4.00
|
|
|
4.00
|
|
Expected average long-term rate of return on assets
|
|
6.88
|
|
|
7.10
|
|
|
7.50
|
|
•
|
The former NSP, which includes NSP-Minnesota and NSP-Wisconsin, discontinued contributing toward health care benefits for nonbargaining employees retiring after 1998 and for bargaining employees who retired after 1999.
|
•
|
Xcel Energy discontinued contributing toward health care benefits for former NCE, which includes PSCo and SPS, nonbargaining employees retiring after June 30, 2003.
|
•
|
Employees of NCE who retired in 2002 continue to receive employer-subsidized health care benefits.
|
•
|
Nonbargaining employees of the former NCE who retired after 1998, bargaining employees of the former NCE who retired after 1999 and nonbargaining employees of NCE who retired after June 30, 2003, are eligible to participate in the Xcel Energy health care program with no employer subsidy.
|
|
|
Dec. 31, 2013
|
||||||||||||||
(Thousands of Dollars)
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
||||||||
Cash equivalents
|
|
$
|
20,438
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
20,438
|
|
Derivatives
|
|
—
|
|
|
(414
|
)
|
|
—
|
|
|
(414
|
)
|
||||
Government securities
|
|
—
|
|
|
58,421
|
|
|
—
|
|
|
58,421
|
|
||||
Insurance contracts
|
|
—
|
|
|
52,808
|
|
|
—
|
|
|
52,808
|
|
||||
Corporate bonds
|
|
—
|
|
|
51,861
|
|
|
—
|
|
|
51,861
|
|
||||
Asset-backed securities
|
|
—
|
|
|
3,358
|
|
|
—
|
|
|
3,358
|
|
||||
Mortgage-backed securities
|
|
—
|
|
|
24,246
|
|
|
—
|
|
|
24,246
|
|
||||
Commingled funds
|
|
—
|
|
|
298,258
|
|
|
—
|
|
|
298,258
|
|
||||
Other
|
|
—
|
|
|
(16,940
|
)
|
|
—
|
|
|
(16,940
|
)
|
||||
Total
|
|
$
|
20,438
|
|
|
$
|
471,598
|
|
|
$
|
—
|
|
|
$
|
492,036
|
|
|
|
Dec. 31, 2012
|
||||||||||||||
(Thousands of Dollars)
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
||||||||
Cash equivalents
|
|
$
|
91,278
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
91,278
|
|
Derivatives
|
|
—
|
|
|
4
|
|
|
—
|
|
|
4
|
|
||||
Government securities
|
|
—
|
|
|
73,449
|
|
|
—
|
|
|
73,449
|
|
||||
Insurance contracts
|
|
—
|
|
|
50,008
|
|
|
—
|
|
|
50,008
|
|
||||
Corporate bonds
|
|
—
|
|
|
43,810
|
|
|
—
|
|
|
43,810
|
|
||||
Asset-backed securities
|
|
—
|
|
|
—
|
|
|
757
|
|
|
757
|
|
||||
Mortgage-backed securities
|
|
—
|
|
|
—
|
|
|
39,958
|
|
|
39,958
|
|
||||
Commingled funds
|
|
—
|
|
|
228,423
|
|
|
—
|
|
|
228,423
|
|
||||
Other
|
|
—
|
|
|
(46,845
|
)
|
|
—
|
|
|
(46,845
|
)
|
||||
Total
|
|
$
|
91,278
|
|
|
$
|
348,849
|
|
|
$
|
40,715
|
|
|
$
|
480,842
|
|
(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
|
|
$
|
757
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(757
|
)
|
|
$
|
—
|
|
Mortgage-backed securities
|
|
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)
|
|
Jan. 1, 2012
|
|
Net Realized
Gains (Losses) |
|
Net Unrealized
Gains (Losses) |
|
Purchases,
Issuances and Settlements, Net |
|
Transfers Out of Level 3
|
|
Dec. 31, 2012
|
||||||||||||
Asset-backed securities
|
|
$
|
7,867
|
|
|
$
|
(331
|
)
|
|
$
|
1,481
|
|
|
$
|
(8,260
|
)
|
|
$
|
—
|
|
|
$
|
757
|
|
Mortgage-backed securities
|
|
27,253
|
|
|
(724
|
)
|
|
3,301
|
|
|
10,128
|
|
|
—
|
|
|
39,958
|
|
||||||
Private equity investments
|
|
479
|
|
|
—
|
|
|
(65
|
)
|
|
(414
|
)
|
|
—
|
|
|
—
|
|
||||||
Real estate
|
|
144
|
|
|
—
|
|
|
35
|
|
|
(179
|
)
|
|
—
|
|
|
—
|
|
||||||
Total
|
|
$
|
35,743
|
|
|
$
|
(1,055
|
)
|
|
$
|
4,752
|
|
|
$
|
1,275
|
|
|
$
|
—
|
|
|
$
|
40,715
|
|
(Thousands of Dollars)
|
|
Jan. 1, 2011
|
|
Net Realized
Gains (Losses) |
|
Net Unrealized
Gains (Losses) |
|
Purchases,
Issuances and Settlements, Net |
|
Transfers Out of Level 3
|
|
Dec. 31, 2011
|
||||||||||||
Asset-backed securities
|
|
$
|
2,585
|
|
|
$
|
(10
|
)
|
|
$
|
(664
|
)
|
|
$
|
5,956
|
|
|
$
|
—
|
|
|
$
|
7,867
|
|
Mortgage-backed securities
|
|
19,212
|
|
|
(1,669
|
)
|
|
2,623
|
|
|
7,087
|
|
|
—
|
|
|
27,253
|
|
||||||
Private equity investments
|
|
—
|
|
|
12
|
|
|
53
|
|
|
414
|
|
|
—
|
|
|
479
|
|
||||||
Real estate
|
|
—
|
|
|
(2
|
)
|
|
(34
|
)
|
|
180
|
|
|
—
|
|
|
144
|
|
||||||
Total
|
|
$
|
21,797
|
|
|
$
|
(1,669
|
)
|
|
$
|
1,978
|
|
|
$
|
13,637
|
|
|
$
|
—
|
|
|
$
|
35,743
|
|
(Thousands of Dollars)
|
|
2013
|
|
2012
|
||||
Change in Fair Value of Plan Assets:
|
|
|
|
|
||||
Fair value of plan assets at Jan. 1
|
|
$
|
480,842
|
|
|
$
|
426,835
|
|
Actual return on plan assets
|
|
33,644
|
|
|
56,385
|
|
||
Plan participants’ contributions
|
|
9,580
|
|
|
14,241
|
|
||
Employer contributions
|
|
17,561
|
|
|
47,143
|
|
||
Benefit payments
|
|
(49,591
|
)
|
|
(63,762
|
)
|
||
Fair value of plan assets at Dec. 31
|
|
$
|
492,036
|
|
|
$
|
480,842
|
|
(Thousands of Dollars)
|
|
2013
|
|
2012
|
||||
Funded Status of Plans at Dec. 31:
|
|
|
|
|
||||
Funded status
|
|
$
|
(239,392
|
)
|
|
$
|
(371,110
|
)
|
Current liabilities
|
|
(6,807
|
)
|
|
(6,070
|
)
|
||
Noncurrent liabilities
|
|
(232,585
|
)
|
|
(365,040
|
)
|
||
Net postretirement amounts recognized on consolidated balance sheets
|
|
$
|
(239,392
|
)
|
|
$
|
(371,110
|
)
|
(Thousands of Dollars)
|
|
2013
|
|
2012
|
||||
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:
|
|
|
|
|
||||
Net loss
|
|
$
|
195,630
|
|
|
$
|
321,946
|
|
Prior service credit
|
|
(86,298
|
)
|
|
(84,228
|
)
|
||
Transition obligation
|
|
2
|
|
|
827
|
|
||
Total
|
|
$
|
109,334
|
|
|
$
|
238,545
|
|
(Thousands of Dollars)
|
|
2013
|
|
2012
|
||||
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
|
|
$
|
12,102
|
|
|
$
|
6,930
|
|
Noncurrent regulatory assets
|
|
99,071
|
|
|
226,052
|
|
||
Current regulatory liabilities
|
|
(319
|
)
|
|
(954
|
)
|
||
Noncurrent regulatory liabilities
|
|
(8,858
|
)
|
|
(3,453
|
)
|
||
Deferred income taxes
|
|
2,965
|
|
|
4,050
|
|
||
Net-of-tax accumulated OCI
|
|
4,373
|
|
|
5,920
|
|
||
Total
|
|
$
|
109,334
|
|
|
$
|
238,545
|
|
Measurement date
|
|
Dec. 31, 2013
|
|
Dec. 31, 2012
|
|
|
2013
|
|
2012
|
||
Significant Assumptions Used to Measure Benefit Obligations:
|
|
|
|
|
||
Discount rate for year-end valuation
|
|
4.82
|
%
|
|
4.10
|
%
|
Mortality table
|
|
RP 2000
|
|
|
RP 2000
|
|
Health care costs trend rate — initial
|
|
7.00
|
|
|
7.50
|
|
|
|
One-Percentage Point
|
||||||
(Thousands of Dollars)
|
|
Increase
|
|
Decrease
|
||||
APBO
|
|
$
|
75,617
|
|
|
$
|
(63,360
|
)
|
Service and interest components
|
|
3,580
|
|
|
(2,826
|
)
|
(Thousands of Dollars)
|
|
2013
|
|
2012
|
|
2011
|
||||||
Service cost
|
|
$
|
4,079
|
|
|
$
|
4,203
|
|
|
$
|
4,824
|
|
Interest cost
|
|
32,141
|
|
|
37,861
|
|
|
42,086
|
|
|||
Expected return on plan assets
|
|
(33,011
|
)
|
|
(28,409
|
)
|
|
(31,962
|
)
|
|||
Amortization of transition obligation
|
|
825
|
|
|
14,320
|
|
|
14,444
|
|
|||
Amortization of prior service credit
|
|
(12,501
|
)
|
|
(7,552
|
)
|
|
(4,932
|
)
|
|||
Amortization of net loss
|
|
22,325
|
|
|
16,906
|
|
|
13,294
|
|
|||
Net periodic postretirement benefit cost
|
|
13,858
|
|
|
37,329
|
|
|
37,754
|
|
|||
Additional cost recognized due to effects of regulation
|
|
—
|
|
|
3,891
|
|
|
3,891
|
|
|||
Net benefit cost recognized for financial reporting
|
|
$
|
13,858
|
|
|
$
|
41,220
|
|
|
$
|
41,645
|
|
|
|
2013
|
|
2012
|
|
2011
|
|||
Significant Assumptions Used to Measure Costs:
|
|
|
|
|
|
|
|||
Discount rate
|
|
4.10
|
%
|
|
5.00
|
%
|
|
5.50
|
%
|
Expected average long-term rate of return on assets
|
|
7.11
|
|
|
6.75
|
|
|
7.50
|
|
(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 |
||||||||
2014
|
|
$
|
313,226
|
|
|
$
|
53,516
|
|
|
$
|
2,627
|
|
|
$
|
50,889
|
|
2015
|
|
266,802
|
|
|
54,576
|
|
|
2,806
|
|
|
51,770
|
|
||||
2016
|
|
267,186
|
|
|
55,965
|
|
|
2,969
|
|
|
52,996
|
|
||||
2017
|
|
269,526
|
|
|
56,513
|
|
|
3,135
|
|
|
53,378
|
|
||||
2018
|
|
272,908
|
|
|
58,181
|
|
|
3,291
|
|
|
54,890
|
|
||||
2019-2023
|
|
1,339,764
|
|
|
282,860
|
|
|
18,274
|
|
|
264,586
|
|
(Thousands of Dollars)
|
|
2013
|
|
2012
|
|
2011
|
||||||
Multiemployer pension contributions:
|
|
|
|
|
|
|
||||||
NSP-Minnesota
|
|
$
|
23,515
|
|
|
$
|
14,984
|
|
|
$
|
17,811
|
|
NSP-Wisconsin
|
|
130
|
|
|
163
|
|
|
169
|
|
|||
Total
|
|
$
|
23,645
|
|
|
$
|
15,147
|
|
|
$
|
17,980
|
|
Multiemployer other postretirement benefit contributions:
|
|
|
|
|
|
|
||||||
NSP-Minnesota
|
|
$
|
390
|
|
|
$
|
197
|
|
|
$
|
336
|
|
Total
|
|
$
|
390
|
|
|
$
|
197
|
|
|
$
|
336
|
|
10.
|
Other Income, Net
|
(Thousands of Dollars)
|
|
2013
|
|
2012
|
|
2011
|
||||||
Interest income
|
|
$
|
8,343
|
|
|
$
|
10,327
|
|
|
$
|
10,639
|
|
Other nonoperating income
|
|
3,025
|
|
|
3,483
|
|
|
3,722
|
|
|||
Insurance policy expense
|
|
(8,292
|
)
|
|
(7,365
|
)
|
|
(4,785
|
)
|
|||
Other nonoperating expense
|
|
(104
|
)
|
|
(270
|
)
|
|
(321
|
)
|
|||
Other income, net
|
|
$
|
2,972
|
|
|
$
|
6,175
|
|
|
$
|
9,255
|
|
|
|
Dec. 31, 2013
|
||||||||||||||||||
|
|
|
|
Fair Value
|
||||||||||||||||
(Thousands of Dollars)
|
|
Cost
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
||||||||||
Nuclear decommissioning fund
(a)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Cash equivalents
|
|
$
|
33,281
|
|
|
$
|
33,281
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
33,281
|
|
Commingled funds
|
|
457,986
|
|
|
—
|
|
|
452,227
|
|
|
—
|
|
|
452,227
|
|
|||||
International equity funds
|
|
78,812
|
|
|
—
|
|
|
81,671
|
|
|
—
|
|
|
81,671
|
|
|||||
Private equity investments
|
|
52,143
|
|
|
—
|
|
|
—
|
|
|
62,696
|
|
|
62,696
|
|
|||||
Real estate
|
|
45,564
|
|
|
—
|
|
|
—
|
|
|
57,368
|
|
|
57,368
|
|
|||||
Debt securities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Government securities
|
|
34,304
|
|
|
—
|
|
|
27,628
|
|
|
—
|
|
|
27,628
|
|
|||||
U.S. corporate bonds
|
|
80,275
|
|
|
—
|
|
|
83,538
|
|
|
—
|
|
|
83,538
|
|
|||||
International corporate bonds
|
|
15,025
|
|
|
—
|
|
|
15,358
|
|
|
—
|
|
|
15,358
|
|
|||||
Municipal bonds
|
|
241,112
|
|
|
—
|
|
|
232,016
|
|
|
—
|
|
|
232,016
|
|
|||||
Equity securities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Common stock
|
|
406,695
|
|
|
581,243
|
|
|
—
|
|
|
—
|
|
|
581,243
|
|
|||||
Total
|
|
$
|
1,445,197
|
|
|
$
|
614,524
|
|
|
$
|
892,438
|
|
|
$
|
120,064
|
|
|
$
|
1,627,026
|
|
(a)
|
Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes
$87.1 million
of equity investments in unconsolidated subsidiaries and
$41.9 million
of miscellaneous investments.
|
|
|
Dec. 31, 2012
|
||||||||||||||||||
|
|
|
|
Fair Value
|
||||||||||||||||
(Thousands of Dollars)
|
|
Cost
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
||||||||||
Nuclear decommissioning fund
(a)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Cash equivalents
|
|
$
|
246,904
|
|
|
$
|
237,938
|
|
|
$
|
8,966
|
|
|
$
|
—
|
|
|
$
|
246,904
|
|
Commingled funds
|
|
396,681
|
|
|
—
|
|
|
417,583
|
|
|
—
|
|
|
417,583
|
|
|||||
International equity funds
|
|
66,452
|
|
|
—
|
|
|
69,481
|
|
|
—
|
|
|
69,481
|
|
|||||
Private equity investments
|
|
27,943
|
|
|
—
|
|
|
—
|
|
|
33,250
|
|
|
33,250
|
|
|||||
Real estate
|
|
32,561
|
|
|
—
|
|
|
—
|
|
|
39,074
|
|
|
39,074
|
|
|||||
Debt securities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Government securities
|
|
21,092
|
|
|
—
|
|
|
21,521
|
|
|
—
|
|
|
21,521
|
|
|||||
U.S. corporate bonds
|
|
162,053
|
|
|
—
|
|
|
169,488
|
|
|
—
|
|
|
169,488
|
|
|||||
International corporate bonds
|
|
15,165
|
|
|
—
|
|
|
16,052
|
|
|
—
|
|
|
16,052
|
|
|||||
Municipal bonds
|
|
21,392
|
|
|
—
|
|
|
23,650
|
|
|
—
|
|
|
23,650
|
|
|||||
Asset-backed securities
|
|
2,066
|
|
|
—
|
|
|
—
|
|
|
2,067
|
|
|
2,067
|
|
|||||
Mortgage-backed securities
|
|
28,743
|
|
|
—
|
|
|
—
|
|
|
30,209
|
|
|
30,209
|
|
|||||
Equity securities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Common stock
|
|
379,093
|
|
|
420,263
|
|
|
—
|
|
|
—
|
|
|
420,263
|
|
|||||
Total
|
|
$
|
1,400,145
|
|
|
$
|
658,201
|
|
|
$
|
726,741
|
|
|
$
|
104,600
|
|
|
$
|
1,489,542
|
|
(a)
|
Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes
$91.2 million
of equity investments in unconsolidated subsidiaries and
$37.1 million
of miscellaneous investments.
|
(Thousands of Dollars)
|
|
Jan. 1, 2013
|
|
Purchases
|
|
Settlements
|
|
Gains
Recognized as Regulatory Assets and Liabilities |
|
Transfers Out of Level 3
(a)
|
|
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)
|
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)
|
|
Jan. 1, 2012
|
|
Purchases
|
|
Settlements
|
|
Gains (Losses)
Recognized as Regulatory Assets and Liabilities |
|
Transfers Out of Level 3
|
|
Dec. 31, 2012
|
||||||||||||
Private equity investments
|
|
$
|
9,203
|
|
|
$
|
20,671
|
|
|
$
|
(1,931
|
)
|
|
$
|
5,307
|
|
|
$
|
—
|
|
|
$
|
33,250
|
|
Real estate
|
|
26,395
|
|
|
9,777
|
|
|
(3,611
|
)
|
|
6,513
|
|
|
—
|
|
|
39,074
|
|
||||||
Asset-backed securities
|
|
16,501
|
|
|
—
|
|
|
(14,450
|
)
|
|
16
|
|
|
—
|
|
|
2,067
|
|
||||||
Mortgage-backed securities
|
|
78,664
|
|
|
33,016
|
|
|
(79,899
|
)
|
|
(1,572
|
)
|
|
—
|
|
|
30,209
|
|
||||||
Total
|
|
$
|
130,763
|
|
|
$
|
63,464
|
|
|
$
|
(99,891
|
)
|
|
$
|
10,264
|
|
|
$
|
—
|
|
|
$
|
104,600
|
|
(Thousands of Dollars)
|
|
Jan. 1, 2011
|
|
Purchases
|
|
Settlements
|
|
Gains (Losses)
Recognized as Regulatory Assets and Liabilities |
|
Transfers Out of Level 3
|
|
Dec. 31, 2011
|
||||||||||||
Private equity investments
|
|
$
|
—
|
|
|
$
|
9,203
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
9,203
|
|
Real estate
|
|
—
|
|
|
24,768
|
|
|
—
|
|
|
1,627
|
|
|
—
|
|
|
26,395
|
|
||||||
Asset-backed securities
|
|
33,174
|
|
|
16,518
|
|
|
(32,560
|
)
|
|
(631
|
)
|
|
—
|
|
|
16,501
|
|
||||||
Mortgage-backed securities
|
|
72,589
|
|
|
168,688
|
|
|
(161,134
|
)
|
|
(1,479
|
)
|
|
—
|
|
|
78,664
|
|
||||||
Total
|
|
$
|
105,763
|
|
|
$
|
219,177
|
|
|
$
|
(193,694
|
)
|
|
$
|
(483
|
)
|
|
$
|
—
|
|
|
$
|
130,763
|
|
|
|
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
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
27,628
|
|
|
$
|
27,628
|
|
U.S. corporate bonds
|
|
780
|
|
|
17,850
|
|
|
63,089
|
|
|
1,819
|
|
|
83,538
|
|
|||||
International corporate bonds
|
|
—
|
|
|
2,222
|
|
|
13,136
|
|
|
—
|
|
|
15,358
|
|
|||||
Municipal bonds
|
|
3,554
|
|
|
25,663
|
|
|
33,109
|
|
|
169,690
|
|
|
232,016
|
|
|||||
Debt securities
|
|
$
|
4,334
|
|
|
$
|
45,735
|
|
|
$
|
109,334
|
|
|
$
|
199,137
|
|
|
$
|
358,540
|
|
(Amounts in Thousands)
(a)(b)
|
|
Dec. 31, 2013
|
|
Dec. 31, 2012
|
||
MWh of electricity
|
|
58,423
|
|
|
55,976
|
|
MMBtu of natural gas
|
|
9,854
|
|
|
725
|
|
Gallons of vehicle fuel
|
|
482
|
|
|
682
|
|
(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)
|
|
2013
|
|
2012
|
|
2011
|
||||||
Accumulated other comprehensive loss related to cash flow hedges at Jan. 1
|
|
$
|
(61,241
|
)
|
|
$
|
(45,738
|
)
|
|
$
|
(8,094
|
)
|
After-tax net unrealized gains (losses) related to derivatives accounted for as hedges
|
|
12
|
|
|
(19,200
|
)
|
|
(38,292
|
)
|
|||
After-tax net realized losses on derivative transactions reclassified into earnings
|
|
1,476
|
|
|
3,697
|
|
|
648
|
|
|||
Accumulated other comprehensive loss related to cash flow hedges at Dec. 31
|
|
$
|
(59,753
|
)
|
|
$
|
(61,241
|
)
|
|
$
|
(45,738
|
)
|
|
|
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
|
|
|
|
|
Year Ended Dec. 31, 2012
|
|
||||||||||||||||||
|
|
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
|
|
$
|
(31,913
|
)
|
|
$
|
—
|
|
|
$
|
6,582
|
|
(a)
|
$
|
—
|
|
|
$
|
—
|
|
|
Vehicle fuel and other commodity
|
|
120
|
|
|
—
|
|
|
(198
|
)
|
(b)
|
—
|
|
|
—
|
|
|
|||||
Total
|
|
$
|
(31,793
|
)
|
|
$
|
—
|
|
|
$
|
6,384
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
Other derivative instruments
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Commodity trading
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
12,226
|
|
(c)
|
Electric commodity
|
|
—
|
|
|
44,162
|
|
|
—
|
|
|
(39,999
|
)
|
(d)
|
—
|
|
|
|||||
Natural gas commodity
|
|
—
|
|
|
(10,809
|
)
|
|
—
|
|
|
80,902
|
|
(e)
|
(137
|
)
|
(d)
|
|||||
Total
|
|
$
|
—
|
|
|
$
|
33,353
|
|
|
$
|
—
|
|
|
$
|
40,903
|
|
|
$
|
12,089
|
|
|
|
|
Year Ended Dec. 31, 2011
|
|
||||||||||||||||||
|
|
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
|
|
$
|
(63,573
|
)
|
|
$
|
—
|
|
|
$
|
1,424
|
|
(a)
|
$
|
—
|
|
|
$
|
—
|
|
|
Vehicle fuel and other commodity
|
|
195
|
|
|
—
|
|
|
(178
|
)
|
(b)
|
—
|
|
|
—
|
|
|
|||||
Total
|
|
$
|
(63,378
|
)
|
|
$
|
—
|
|
|
$
|
1,246
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
Other derivative instruments
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Commodity trading
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
6,418
|
|
(c)
|
Electric commodity
|
|
—
|
|
|
49,818
|
|
|
—
|
|
|
(40,492
|
)
|
(d)
|
—
|
|
|
|||||
Natural gas commodity
|
|
—
|
|
|
(111,574
|
)
|
|
—
|
|
|
91,743
|
|
(e)
|
(382
|
)
|
(d)
|
|||||
Total
|
|
$
|
—
|
|
|
$
|
(61,756
|
)
|
|
$
|
—
|
|
|
$
|
51,251
|
|
|
$
|
6,036
|
|
|
(a)
|
Amounts are recorded to interest charges.
|
(b)
|
Amounts are recorded to O&M expenses.
|
(c)
|
Amounts are recorded to electric operating revenues. Portions of these gains and losses are subject to sharing with electric customers through margin-sharing mechanisms and deducted from gross revenue, as appropriate.
|
(d)
|
Amounts are recorded to electric fuel and purchased power. These derivative settlement gains and losses are shared with electric customers through fuel and purchased energy cost-recovery mechanisms, and reclassified out of income as regulatory assets or liabilities, as appropriate.
|
(e)
|
Amounts for the years ended Dec. 31, 2012 and 2011 included
$5.0 million
and
$12.7 million
, respectively, of settlement losses on derivatives entered to mitigate natural gas price risk for electric generation, recorded to electric fuel and purchased power, subject to cost-recovery mechanisms and reclassified to a regulatory asset, as appropriate. Such losses for the year ended Dec. 31, 2013 were immaterial. The remaining settlement losses for the years ended Dec. 31, 2013, 2012 and 2011 relate to natural gas operations and are recorded to cost of natural gas sold and transported. These losses are subject to cost-recovery mechanisms and reclassified out of income to a regulatory asset, as appropriate.
|
|
|
Dec. 31, 2013
|
||||||||||||||||||||||
|
|
Fair Value
|
|
Fair Value Total
|
|
Counterparty
Netting
(b)
|
|
|
||||||||||||||||
(Thousands of Dollars)
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
|
|
Total
|
||||||||||||||
Current derivative assets
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Derivatives designated as cash flow hedges:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Vehicle fuel and other commodity
|
|
$
|
—
|
|
|
$
|
88
|
|
|
$
|
—
|
|
|
$
|
88
|
|
|
$
|
—
|
|
|
$
|
88
|
|
Other derivative instruments:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Commodity trading
|
|
—
|
|
|
20,610
|
|
|
1,167
|
|
|
21,777
|
|
|
(7,994
|
)
|
|
13,783
|
|
||||||
Electric commodity
|
|
—
|
|
|
—
|
|
|
47,112
|
|
|
47,112
|
|
|
(8,210
|
)
|
|
38,902
|
|
||||||
Natural gas commodity
|
|
—
|
|
|
5,906
|
|
|
—
|
|
|
5,906
|
|
|
—
|
|
|
5,906
|
|
||||||
Total current derivative assets
|
|
$
|
—
|
|
|
$
|
26,604
|
|
|
$
|
48,279
|
|
|
$
|
74,883
|
|
|
$
|
(16,204
|
)
|
|
58,679
|
|
|
PPAs
(a)
|
|
|
|
|
|
|
|
|
|
|
|
33,028
|
|
|||||||||||
Current derivative instruments
|
|
|
|
|
|
|
|
|
|
|
|
$
|
91,707
|
|
||||||||||
Noncurrent derivative assets
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Derivatives designated as cash flow hedges:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Vehicle fuel and other commodity
|
|
$
|
—
|
|
|
$
|
29
|
|
|
$
|
—
|
|
|
$
|
29
|
|
|
$
|
(16
|
)
|
|
$
|
13
|
|
Other derivative instruments:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Commodity trading
|
|
—
|
|
|
32,074
|
|
|
3,395
|
|
|
35,469
|
|
|
(9,071
|
)
|
|
26,398
|
|
||||||
Total noncurrent derivative assets
|
|
$
|
—
|
|
|
$
|
32,103
|
|
|
$
|
3,395
|
|
|
$
|
35,498
|
|
|
$
|
(9,087
|
)
|
|
26,411
|
|
|
PPAs
(a)
|
|
|
|
|
|
|
|
|
|
|
|
58,431
|
|
|||||||||||
Noncurrent derivative instruments
|
|
|
|
|
|
|
|
|
|
|
|
$
|
84,842
|
|
|
|
Dec. 31, 2013
|
||||||||||||||||||||||
|
|
Fair Value
|
|
Fair Value Total
|
|
Counterparty
Netting
(b)
|
|
|
||||||||||||||||
(Thousands of Dollars)
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
|
|
Total
|
||||||||||||||
Current derivative liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Other derivative instruments:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Commodity trading
|
|
$
|
—
|
|
|
$
|
10,546
|
|
|
$
|
1,804
|
|
|
$
|
12,350
|
|
|
$
|
(12,002
|
)
|
|
$
|
348
|
|
Electric commodity
|
|
—
|
|
|
—
|
|
|
8,210
|
|
|
8,210
|
|
|
(8,210
|
)
|
|
—
|
|
||||||
Total current derivative liabilities
|
|
$
|
—
|
|
|
$
|
10,546
|
|
|
$
|
10,014
|
|
|
$
|
20,560
|
|
|
$
|
(20,212
|
)
|
|
348
|
|
|
PPAs
(a)
|
|
|
|
|
|
|
|
|
|
|
|
23,034
|
|
|||||||||||
Current derivative instruments
|
|
|
|
|
|
|
|
|
|
|
|
$
|
23,382
|
|
||||||||||
Noncurrent derivative liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Other derivative instruments:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Commodity trading
|
|
$
|
—
|
|
|
$
|
14,382
|
|
|
$
|
—
|
|
|
$
|
14,382
|
|
|
$
|
(9,087
|
)
|
|
$
|
5,295
|
|
Total noncurrent derivative liabilities
|
|
$
|
—
|
|
|
$
|
14,382
|
|
|
$
|
—
|
|
|
$
|
14,382
|
|
|
$
|
(9,087
|
)
|
|
5,295
|
|
|
PPAs
(a)
|
|
|
|
|
|
|
|
|
|
|
|
203,929
|
|
|||||||||||
Noncurrent derivative instruments
|
|
|
|
|
|
|
|
|
|
|
|
$
|
209,224
|
|
(a)
|
In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, Xcel Energy began recording several long-term PPAs at fair value due to accounting requirements related to underlying price adjustments. As these purchases are recovered through normal regulatory recovery mechanisms in the respective jurisdictions, the changes in fair value for these contracts were offset by regulatory assets and liabilities. During 2006, Xcel Energy qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.
|
(b)
|
Xcel Energy nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Dec. 31, 2013. At Dec. 31, 2013, derivative assets and liabilities include obligations to return cash collateral of
$0.2 million
and rights to reclaim cash collateral of
$4.2 million
. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.
|
|
|
Dec. 31, 2012
|
||||||||||||||||||||||
|
|
Fair Value
|
|
Fair Value Total
|
|
Counterparty
Netting
(b)
|
|
|
||||||||||||||||
(Thousands of Dollars)
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
|
|
Total
|
||||||||||||||
Current derivative assets
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Derivatives designated as cash flow hedges:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Vehicle fuel and other commodity
|
|
$
|
—
|
|
|
$
|
95
|
|
|
$
|
—
|
|
|
$
|
95
|
|
|
$
|
—
|
|
|
$
|
95
|
|
Other derivative instruments:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Commodity trading
|
|
—
|
|
|
26,303
|
|
|
692
|
|
|
26,995
|
|
|
(6,675
|
)
|
|
20,320
|
|
||||||
Electric commodity
|
|
—
|
|
|
—
|
|
|
16,724
|
|
|
16,724
|
|
|
(843
|
)
|
|
15,881
|
|
||||||
Natural gas commodity
|
|
—
|
|
|
7
|
|
|
—
|
|
|
7
|
|
|
(7
|
)
|
|
—
|
|
||||||
Total current derivative assets
|
$
|
—
|
|
|
$
|
26,405
|
|
|
$
|
17,416
|
|
|
$
|
43,821
|
|
|
$
|
(7,525
|
)
|
|
36,296
|
|
||
PPAs
(a)
|
|
|
|
|
|
|
|
|
|
|
|
32,717
|
|
|||||||||||
Current derivative instruments
|
|
|
|
|
|
|
|
|
|
|
|
$
|
69,013
|
|
||||||||||
Noncurrent derivative assets
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Derivatives designated as cash flow hedges:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Vehicle fuel and other commodity
|
|
$
|
—
|
|
|
$
|
86
|
|
|
$
|
—
|
|
|
$
|
86
|
|
|
$
|
(47
|
)
|
|
$
|
39
|
|
Other derivative instruments:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Commodity trading
|
|
—
|
|
|
41,282
|
|
|
77
|
|
|
41,359
|
|
|
(4,162
|
)
|
|
37,197
|
|
||||||
Total noncurrent derivative assets
|
$
|
—
|
|
|
$
|
41,368
|
|
|
$
|
77
|
|
|
$
|
41,445
|
|
|
$
|
(4,209
|
)
|
|
37,236
|
|
||
PPAs
(a)
|
|
|
|
|
|
|
|
|
|
|
|
89,061
|
|
|||||||||||
Noncurrent derivative instruments
|
|
|
|
|
|
|
|
|
|
|
|
$
|
126,297
|
|
|
|
Dec. 31, 2012
|
||||||||||||||||||||||
|
|
Fair Value
|
|
Fair Value Total
|
|
Counterparty
Netting
(b)
|
|
|
||||||||||||||||
(Thousands of Dollars)
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
|
|
Total
|
||||||||||||||
Current derivative liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Other derivative instruments:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Commodity trading
|
|
$
|
—
|
|
|
$
|
18,622
|
|
|
$
|
1
|
|
|
$
|
18,623
|
|
|
$
|
(9,112
|
)
|
|
$
|
9,511
|
|
Electric commodity
|
|
—
|
|
|
—
|
|
|
843
|
|
|
843
|
|
|
(843
|
)
|
|
—
|
|
||||||
Natural gas commodity
|
|
—
|
|
|
98
|
|
|
—
|
|
|
98
|
|
|
(7
|
)
|
|
91
|
|
||||||
Total current derivative liabilities
|
|
$
|
—
|
|
|
$
|
18,720
|
|
|
$
|
844
|
|
|
$
|
19,564
|
|
|
$
|
(9,962
|
)
|
|
9,602
|
|
|
PPAs
(a)
|
|
|
|
|
|
|
|
|
|
|
|
22,880
|
|
|||||||||||
Current derivative instruments
|
|
|
|
|
|
|
|
|
|
|
|
$
|
32,482
|
|
||||||||||
Noncurrent derivative liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Other derivative instruments:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Commodity trading
|
|
$
|
—
|
|
|
$
|
21,417
|
|
|
$
|
—
|
|
|
$
|
21,417
|
|
|
$
|
(4,210
|
)
|
|
$
|
17,207
|
|
Total noncurrent derivative liabilities
|
|
$
|
—
|
|
|
$
|
21,417
|
|
|
$
|
—
|
|
|
$
|
21,417
|
|
|
$
|
(4,210
|
)
|
|
17,207
|
|
|
PPAs
(a)
|
|
|
|
|
|
|
|
|
|
|
|
225,659
|
|
|||||||||||
Noncurrent derivative instruments
|
|
|
|
|
|
|
|
|
|
|
|
$
|
242,866
|
|
(a)
|
In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting, Xcel Energy began recording several long-term PPAs at fair value due to accounting requirements related to underlying price adjustments. As these purchases are recovered through normal regulatory recovery mechanisms in the respective jurisdictions, the changes in fair value for these contracts were offset by regulatory assets and liabilities. During 2006, Xcel Energy qualified these contracts under the normal purchase exception. Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.
|
(b)
|
Xcel Energy nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at Dec. 31, 2012. At Dec. 31, 2012, derivative assets and liabilities include obligations to return cash collateral of
$0.6 million
and rights to reclaim cash collateral of
$3.0 million
. The counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.
|
|
|
Year Ended Dec. 31
|
||||||||||
(Thousands of Dollars)
|
|
2013
|
|
2012
|
|
2011
|
||||||
Balance at Jan. 1
|
|
$
|
16,649
|
|
|
$
|
12,417
|
|
|
$
|
2,392
|
|
Purchases
|
|
61,474
|
|
|
37,595
|
|
|
33,609
|
|
|||
Settlements
|
|
(45,199
|
)
|
|
(44,950
|
)
|
|
(36,555
|
)
|
|||
Net transactions recorded during the period:
|
|
|
|
|
|
|
||||||
Gains recognized in earnings
(a)
|
|
3,947
|
|
|
463
|
|
|
69
|
|
|||
Gains recognized as regulatory assets and liabilities
|
|
4,789
|
|
|
11,124
|
|
|
12,902
|
|
|||
Balance at Dec. 31
|
|
$
|
41,660
|
|
|
$
|
16,649
|
|
|
$
|
12,417
|
|
(a)
|
These amounts relate to commodity derivatives held at the end of the period.
|
|
|
2013
|
|
2012
|
||||||||||||
(Thousands of Dollars)
|
|
Carrying Amount
|
|
Fair Value
|
|
Carrying Amount
|
|
Fair Value
|
||||||||
Long-term debt, including current portion
|
|
$
|
11,191,517
|
|
|
$
|
11,878,643
|
|
|
$
|
10,402,060
|
|
|
$
|
12,207,866
|
|
(Millions of Dollars)
|
|
2014
|
|
Percentage
Increase
|
|
2015
|
|
Percentage
Increase |
||||
Pre-moderation deficiency
|
|
$
|
274
|
|
|
|
|
$
|
81
|
|
|
|
Moderation change compared to prior year:
|
|
|
|
|
|
|
|
|
||||
Excess theoretical depreciation reserve
|
|
(81
|
)
|
|
|
|
53
|
|
|
|
||
DOE settlement proceeds
|
|
—
|
|
|
|
|
(36
|
)
|
|
|
||
Filed rate request
|
|
193
|
|
|
6.9%
|
|
98
|
|
|
3.5%
|
||
Interim rate adjustments
|
|
(66
|
)
|
|
|
|
66
|
|
|
|
||
Impact on customer bill
|
|
127
|
|
|
4.6%
|
|
164
|
|
|
5.6%
|
||
Potential expense deferral (Monticello/Prairie Island EPU projects)
|
|
16
|
|
|
|
|
—
|
|
|
|
||
Depreciation expense - reduction/(increase)
|
|
81
|
|
|
|
|
(46
|
)
|
|
|
||
Recognition of DOE settlement proceeds
|
|
—
|
|
|
|
|
36
|
|
|
|
||
Pre-tax impact on operating income
|
|
$
|
224
|
|
|
|
|
$
|
154
|
|
|
|
•
|
Direct Testimony — June 5, 2014;
|
•
|
Rebuttal Testimony — July 7, 2014;
|
•
|
Surrebuttal Testimony — Aug. 4, 2014;
|
•
|
Evidentiary Hearing — Aug. 11-18, 2014;
|
•
|
Reply Brief — Oct. 14, 2014; and
|
•
|
ALJ Report — Dec. 22, 2014.
|
(Millions of Dollars)
|
|
MPUC Order
|
||
NSP-Minnesota original request
|
|
$
|
285
|
|
ROE
|
|
(43
|
)
|
|
Sherco Unit 3
|
|
(34
|
)
|
|
Reduced recovery for nuclear plants
|
|
(15
|
)
|
|
Incentive compensation
|
|
(4
|
)
|
|
Sales forecast
|
|
(26
|
)
|
|
Pension
|
|
(13
|
)
|
|
Employee benefits
|
|
(6
|
)
|
|
Black Dog remediation
|
|
(5
|
)
|
|
Estimated impact of the theoretical depreciation reserve
|
|
(24
|
)
|
|
NSP-Wisconsin wholesale allocation
|
|
(7
|
)
|
|
Other, net
|
|
(5
|
)
|
|
Recommended rate increase
|
|
103
|
|
|
Estimated impact of cost deferrals
|
|
20
|
|
|
Estimated impact of the theoretical depreciation reserve
|
|
24
|
|
|
Impact on pre-tax income
|
|
$
|
147
|
|
•
|
Direct Testimony — July 2, 2014;
|
•
|
Rebuttal Testimony — Aug. 26, 2014;
|
•
|
Surrebuttal Testimony — Sept. 19, 2014;
|
•
|
Hearing — Sept. 29-Oct. 3, 2014;
|
•
|
Reply Brief — Nov. 21, 2014; and
|
•
|
ALJ report — Dec. 31, 2014.
|
(Millions of Dollars)
|
|
Amended Settlement Impact
|
||
Proposed 12 month settlement base rate increase
|
|
$
|
9.0
|
|
Pre-effective period impact (Jan. 1, 2013 - Feb. 15, 2013)
|
|
(1.6
|
)
|
|
Proposed settlement base rate increase
|
|
7.4
|
|
|
Retention of DOE settlement proceeds
|
|
3.9
|
|
|
Other, net
|
|
(0.3
|
)
|
|
Amended settlement’s 2013 impact
|
|
$
|
11.0
|
|
•
|
An approval of
two
new rate rider tariff mechanisms to recover transmission and North Dakota renewable costs;
|
•
|
An authorized ROE of
9.75
,
10.0
,
10.0
and
10.25 percent
in 2013 through 2016, respectively;
|
•
|
A
50 percent
earnings sharing mechanism for amounts earned in excess of the authorized ROEs during the term of the settlement;
|
•
|
The continued use of a
12
month CP demand allocator for certain rate base and operating expenses;
|
•
|
A commitment to develop a generation cost allocation mechanism over the next
16 months
that reflects North Dakota energy policy; providing for the exclusion of resources deemed inconsistent with North Dakota energy policy beginning in 2016 (such as certain Minnesota wind and biomass purchase power agreements) and reflecting replacement of those costs based on either system average costs or like resource costs (base load for base load generation, etc.) and recognizing the time needed to address complexity among multiple jurisdictions by providing that a plan for this mechanism be filed by June 2015;
|
•
|
The commitment to construct up to
400
MW of thermal generation in North Dakota by 2036 subject to least-cost resource planning principles; and
|
•
|
The retention of DOE settlement proceeds received in 2012, 2013 and expected in 2014.
|
(Millions of Dollars)
|
|
CPUC Decision
|
||
PSCo deficiency based on a FTY
|
|
$
|
44.8
|
|
HTY adjustment
|
|
(5.4
|
)
|
|
ROE and capital structure adjustments
|
|
(8.3
|
)
|
|
Revenue adjustments
|
|
(1.4
|
)
|
|
Other
|
|
(0.1
|
)
|
|
Recommendation
|
|
29.6
|
|
|
Neutralize PSIA - base rate transfer
|
|
(13.8
|
)
|
|
Incremental base revenue
|
|
$
|
15.8
|
|
•
|
Evidentiary hearing — March 3 - March 7, 2014;
|
•
|
Initial brief — March 28, 2014; and
|
•
|
Reply brief — April 11, 2014.
|
(Millions of Dollars)
|
|
SPS Request
|
||
Base rate increase
|
|
$
|
81.5
|
|
Resetting TCRF
|
|
(12.9
|
)
|
|
Credit to customers for gain on sale to Lubbock moved to a rider
|
|
(4.9
|
)
|
|
Net increase in base revenue
|
|
63.7
|
|
|
Fuel clause offsets
|
|
(11.0
|
)
|
|
Retail customer net bill impact
|
|
$
|
52.7
|
|
•
|
Intervenor testimony — May 22, 2014;
|
•
|
PUCT Staff testimony — May 29, 2014;
|
•
|
Cross-rebuttal testimony — June 12, 2014;
|
•
|
Rebuttal testimony — June 16, 2014;
|
•
|
Evidentiary hearing — June 25, 2014; and
|
•
|
A PUCT decision and implementation of final rates are anticipated in the third quarter of 2014.
|
•
|
Intervenor testimony — April 17, 2014;
|
•
|
Rebuttal testimony — May 6, 2014; and
|
•
|
Evidentiary hearings — May 15 - May 16, 2014.
|
(Millions of Dollars)
|
|
Staff
Testimony
August 2013
|
|
NMAG
Testimony August 2013 |
||||
SPS revised request
|
|
$
|
43.3
|
|
|
$
|
43.3
|
|
Rate rider for renewable energy costs
(a)
|
|
(14.5
|
)
|
|
(8.5
|
)
|
||
Present revenues (sales growth and weather)
|
|
(4.4
|
)
|
|
(6.4
|
)
|
||
ROE (9.8 percent and 8.63 percent, respectively)
|
|
(3.2
|
)
|
|
(8.1
|
)
|
||
Capital structure
|
|
(1.5
|
)
|
|
(1.1
|
)
|
||
Employee benefits
|
|
(2.8
|
)
|
|
(1.8
|
)
|
||
Reduced recovery for payroll expense
|
|
(0.1
|
)
|
|
(0.1
|
)
|
||
Gain on sale of transmission assets
|
|
—
|
|
|
(1.7
|
)
|
||
Fuel clause revenue
|
|
6.0
|
|
|
—
|
|
||
Other, net
|
|
(5.0
|
)
|
|
(6.6
|
)
|
||
Recommended rate increase
|
|
$
|
17.8
|
|
|
$
|
9.0
|
|
Means of recovery:
|
|
|
|
|
||||
Base revenue
|
|
$
|
8.8
|
|
|
$
|
(6.0
|
)
|
Rider revenue
|
|
7.3
|
|
|
13.3
|
|
||
Fuel cost adjustment revenue
|
|
1.7
|
|
|
1.7
|
|
||
|
|
$
|
17.8
|
|
|
$
|
9.0
|
|
(a)
|
Adjustments represent recommended deferrals, extended amortizations and moving costs from rider to fuel in base rates.
|
(Millions of Dollars)
|
|
Coal
|
|
Nuclear fuel
|
|
Natural gas supply
|
|
Natural gas
storage and
transportation
|
||||||||
2014
|
|
$
|
947.6
|
|
|
$
|
128.8
|
|
|
$
|
492.8
|
|
|
$
|
272.3
|
|
2015
|
|
770.7
|
|
|
79.9
|
|
|
234.4
|
|
|
266.4
|
|
||||
2016
|
|
500.2
|
|
|
121.5
|
|
|
232.0
|
|
|
207.5
|
|
||||
2017
|
|
221.3
|
|
|
127.5
|
|
|
225.4
|
|
|
164.2
|
|
||||
2018
|
|
73.2
|
|
|
69.4
|
|
|
278.4
|
|
|
106.6
|
|
||||
Thereafter
|
|
428.6
|
|
|
697.6
|
|
|
1,211.3
|
|
|
1,214.2
|
|
||||
Total
|
|
$
|
2,941.6
|
|
|
$
|
1,224.7
|
|
|
$
|
2,674.3
|
|
|
$
|
2,231.2
|
|
(a)
|
Excludes contingent energy payments for renewable PPAs.
|
(Millions of Dollars)
|
|
2013
|
|
2012
|
||||
Storage, leaseholds and rights
|
|
$
|
200.5
|
|
|
$
|
200.5
|
|
Gas pipeline
|
|
20.7
|
|
|
20.7
|
|
||
Property held under capital lease
|
|
221.2
|
|
|
221.2
|
|
||
Accumulated depreciation
|
|
(41.8
|
)
|
|
(35.5
|
)
|
||
Total property held under capital leases, net
|
|
$
|
179.4
|
|
|
$
|
185.7
|
|
(Millions of Dollars)
|
|
Operating
Leases
|
|
PPA
Operating
Leases
(a) (b)
|
|
Total
Operating
Leases
|
|
Capital Leases
|
|
||||||||
2014
|
|
$
|
26.5
|
|
|
$
|
214.2
|
|
|
$
|
240.7
|
|
|
$
|
18.0
|
|
|
2015
|
|
25.4
|
|
|
207.4
|
|
|
232.8
|
|
|
17.8
|
|
|
||||
2016
|
|
22.4
|
|
|
197.0
|
|
|
219.4
|
|
|
17.1
|
|
|
||||
2017
|
|
17.2
|
|
|
192.7
|
|
|
209.9
|
|
|
15.0
|
|
|
||||
2018
|
|
16.1
|
|
|
194.4
|
|
|
210.5
|
|
|
14.7
|
|
|
||||
Thereafter
|
|
143.6
|
|
|
1,771.9
|
|
|
1,915.5
|
|
|
289.1
|
|
|
||||
Total minimum obligation
|
|
|
|
|
|
|
|
371.7
|
|
|
|||||||
Interest component of obligation
|
|
|
|
|
|
|
|
(264.3
|
)
|
|
|||||||
Present value of minimum obligation
|
|
|
|
|
|
|
|
$
|
107.4
|
|
(c)
|
(a)
|
Amounts do not include PPAs accounted for as executory contracts.
|
(b)
|
PPA operating leases contractually expire through 2033.
|
(c)
|
Future commitments exclude certain amounts related to Xcel Energy’s
50 percent
ownership interest in WYCO.
|
(Thousands of Dollars)
|
|
Dec. 31, 2013
|
|
Dec. 31, 2012
|
||||
Current assets
|
|
$
|
7,982
|
|
|
$
|
3,380
|
|
Property, plant and equipment, net
|
|
65,451
|
|
|
72,489
|
|
||
Other noncurrent assets
|
|
1,654
|
|
|
6,044
|
|
||
Total assets
|
|
$
|
75,087
|
|
|
$
|
81,913
|
|
|
|
|
|
|
||||
Current liabilities
|
|
$
|
11,388
|
|
|
$
|
8,458
|
|
Mortgages and other long-term debt payable
|
|
38,049
|
|
|
37,720
|
|
||
Other noncurrent liabilities
|
|
707
|
|
|
7,678
|
|
||
Total liabilities
|
|
$
|
50,144
|
|
|
$
|
53,856
|
|
(Millions of Dollars)
|
|
IBM
Agreement
|
|
Accenture
Agreement
|
||||
2014
|
|
$
|
35.5
|
|
|
$
|
8.9
|
|
2015
|
|
32.2
|
|
|
8.8
|
|
||
2016
|
|
31.5
|
|
|
8.8
|
|
||
2017
|
|
31.6
|
|
|
—
|
|
||
2018
|
|
31.1
|
|
|
—
|
|
||
Thereafter
|
|
15.5
|
|
|
—
|
|
(Millions of Dollars)
|
|
Guarantor
|
|
Guarantee
Amount
|
|
Current
Exposure
|
|
Triggering
Event
|
||||
Guarantee of customer loans for the Farm Rewiring Program
(a)
|
|
NSP-Wisconsin
|
|
$
|
1.0
|
|
|
$
|
0.3
|
|
|
(e)
|
Guarantee of the indemnification obligations of Xcel Energy Services Inc. under the aircraft leases
(b)
|
|
Xcel Energy Inc.
|
|
9.2
|
|
|
—
|
|
|
(f)
|
||
Guarantee of residual value of assets under the BTM Capital Corporation Equipment Leasing Agreement
(c)
|
|
NSP-Minnesota
|
|
9.2
|
|
|
—
|
|
|
(g)
|
||
Total guarantees issued
|
|
|
|
$
|
19.4
|
|
|
$
|
0.3
|
|
|
|
Guarantee performance and payment of surety bonds for Xcel Energy Inc. and its subsidiaries
(d)
|
|
Xcel Energy Inc.
|
|
$
|
32.1
|
|
|
(i)
|
|
(h)
|
(a)
|
The term of this guarantee expires in 2017, which is the final scheduled repayment date for the loans. As of Dec. 31, 2013,
no
claims had been made by the lender.
|
(b)
|
The term of this guarantee expires in 2017 when the associated leases expire.
|
(c)
|
The terms of these guarantees expire in 2014 and 2015 when the associated leases expire.
|
(d)
|
The surety bonds primarily relate to workers compensation benefits and utility projects. The workers compensation bonds are renewed annually and the project based bonds expire in conjunction with the completion of the related projects.
|
(e)
|
The debtor becomes the subject of bankruptcy or other insolvency proceedings.
|
(f)
|
Nonperformance and/or nonpayment.
|
(g)
|
Actual fair value of leased assets is less than the guaranteed residual value amount at the end of the lease term.
|
(h)
|
Failure of Xcel Energy Inc. or one of its subsidiaries to perform under the agreement that is the subject of the relevant bond. In addition, per the indemnity agreement between Xcel Energy Inc. and the various surety companies, the surety companies have the discretion to demand that collateral be posted.
|
(i)
|
Due to the magnitude of projects associated with the surety bonds, the total current exposure of this indemnification cannot be determined. Xcel Energy Inc. believes the exposure to be significantly less than the total amount of the outstanding bonds.
|
(Thousands of Dollars)
|
|
Beginning
Balance
Jan. 1, 2013
|
|
Liabilities
Recognized
|
|
Liabilities
Settled
|
|
Accretion
|
|
Revisions
to Prior
Estimates
|
|
Ending
Balance
Dec. 31, 2013
|
||||||||||||
Electric plant
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Nuclear production decommissioning
|
|
$
|
1,546,358
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
81,940
|
|
|
$
|
—
|
|
|
$
|
1,628,298
|
|
Steam and other production ash containment
|
|
61,735
|
|
|
—
|
|
|
—
|
|
|
2,105
|
|
|
15,513
|
|
|
79,353
|
|
||||||
Steam and other production asbestos
|
|
45,461
|
|
|
—
|
|
|
(1,059
|
)
|
|
2,551
|
|
|
3,874
|
|
|
50,827
|
|
||||||
Wind production
|
|
35,864
|
|
|
—
|
|
|
—
|
|
|
1,600
|
|
|
—
|
|
|
37,464
|
|
||||||
Electric distribution
|
|
24,150
|
|
|
—
|
|
|
—
|
|
|
708
|
|
|
(12,672
|
)
|
|
12,186
|
|
||||||
Other
|
|
3,152
|
|
|
—
|
|
|
—
|
|
|
240
|
|
|
159
|
|
|
3,551
|
|
||||||
Natural gas plant
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Gas transmission and distribution
|
|
1,258
|
|
|
—
|
|
|
—
|
|
|
81
|
|
|
(141
|
)
|
|
1,198
|
|
||||||
Gas gathering
|
|
—
|
|
|
575
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
575
|
|
||||||
Common and other property
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Common general plant asbestos
|
|
1,197
|
|
|
—
|
|
|
—
|
|
|
66
|
|
|
(783
|
)
|
|
480
|
|
||||||
Common miscellaneous
|
|
621
|
|
|
—
|
|
|
—
|
|
|
59
|
|
|
778
|
|
|
1,458
|
|
||||||
Total liability
|
|
$
|
1,719,796
|
|
|
$
|
575
|
|
|
$
|
(1,059
|
)
|
|
$
|
89,350
|
|
|
$
|
6,728
|
|
|
$
|
1,815,390
|
|
(Thousands of Dollars)
|
|
Beginning
Balance
Jan. 1, 2012
|
|
Liabilities
Recognized
|
|
Liabilities
Settled
|
|
Accretion
|
|
Revisions
to Prior
Estimates
|
|
Ending
Balance
Dec. 31, 2012
|
||||||||||||
Electric plant
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Nuclear production decommissioning
|
|
$
|
1,482,741
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
75,301
|
|
|
$
|
(11,684
|
)
|
|
$
|
1,546,358
|
|
Steam and other production ash containment
|
|
41,278
|
|
|
—
|
|
|
—
|
|
|
1,614
|
|
|
18,843
|
|
|
61,735
|
|
||||||
Steam and other production asbestos
|
|
54,342
|
|
|
1,962
|
|
|
(9,372
|
)
|
|
3,417
|
|
|
(4,888
|
)
|
|
45,461
|
|
||||||
Wind production
|
|
40,515
|
|
|
2,928
|
|
|
—
|
|
|
2,068
|
|
|
(9,647
|
)
|
|
35,864
|
|
||||||
Electric distribution
|
|
27,592
|
|
|
—
|
|
|
—
|
|
|
1,000
|
|
|
(4,442
|
)
|
|
24,150
|
|
||||||
Other
|
|
2,390
|
|
|
—
|
|
|
—
|
|
|
92
|
|
|
670
|
|
|
3,152
|
|
||||||
Natural gas plant
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Gas transmission and distribution
|
|
1,201
|
|
|
—
|
|
|
—
|
|
|
73
|
|
|
(16
|
)
|
|
1,258
|
|
||||||
Common and other property
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Common general plant asbestos
|
|
1,135
|
|
|
—
|
|
|
—
|
|
|
62
|
|
|
—
|
|
|
1,197
|
|
||||||
Common miscellaneous
|
|
599
|
|
|
—
|
|
|
—
|
|
|
22
|
|
|
—
|
|
|
621
|
|
||||||
Total liability
|
|
$
|
1,651,793
|
|
|
$
|
4,890
|
|
|
$
|
(9,372
|
)
|
|
$
|
83,649
|
|
|
$
|
(11,164
|
)
|
|
$
|
1,719,796
|
|
(Millions of Dollars)
|
|
2013
|
|
2012
|
||||
NSP-Minnesota
|
|
$
|
378
|
|
|
$
|
377
|
|
NSP-Wisconsin
|
|
116
|
|
|
114
|
|
||
PSCo
|
|
359
|
|
|
365
|
|
||
SPS
|
|
53
|
|
|
67
|
|
||
Total Xcel Energy
|
|
$
|
906
|
|
|
$
|
923
|
|
14.
|
Nuclear Obligations
|
|
|
|
Regulatory Basis
|
||||||
(Thousands of Dollars)
|
|
|
2013
|
|
2012
|
||||
Estimated decommissioning cost obligation from most recently approved study (2011 dollars)
|
|
|
$
|
2,694,079
|
|
|
$
|
2,694,079
|
|
Effect of escalating costs (to 2013 and 2012 dollars, respectively, at 3.63/2.63 percent)
|
|
|
189,924
|
|
|
93,327
|
|
||
Estimated decommissioning cost obligation (in current dollars)
|
|
|
2,884,003
|
|
|
2,787,406
|
|
||
Effect of escalating costs to payment date (3.63/2.63 percent)
|
|
|
5,697,285
|
|
|
5,793,882
|
|
||
Estimated future decommissioning costs (undiscounted)
|
|
|
8,581,288
|
|
|
8,581,288
|
|
||
Effect of discounting obligation (using risk-free interest rate)
|
|
|
(6,215,050
|
)
|
|
(6,243,332
|
)
|
||
Discounted decommissioning cost obligation
|
|
|
$
|
2,366,238
|
|
|
$
|
2,337,956
|
|
|
|
|
|
|
|
||||
Assets held in external decommissioning trust
|
|
|
$
|
1,627,026
|
|
|
$
|
1,489,542
|
|
Underfunding of external decommissioning fund compared to the discounted decommissioning obligation
|
|
|
739,212
|
|
|
848,414
|
|
(Thousands of Dollars)
|
|
2013
|
|
2012
|
|
2011
|
||||||
Annual decommissioning recorded as depreciation expense:
(a)
|
|
|
|
|
|
|
|
|
|
|||
Externally funded
|
|
$
|
6,402
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Internally funded (including interest costs)
|
|
—
|
|
|
(1,251
|
)
|
|
(456
|
)
|
|||
Net decommissioning expense recorded
|
|
$
|
6,402
|
|
|
$
|
(1,251
|
)
|
|
$
|
(456
|
)
|
(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, 2013
|
|
Dec. 31, 2012
|
|||||||||||||
Regulatory Assets
|
|
|
|
|
|
Current
|
|
Noncurrent
|
|
Current
|
|
Noncurrent
|
|||||||||
Pension and retiree medical obligations
(a)
|
|
9
|
|
|
Various
|
|
$
|
118,179
|
|
|
$
|
1,192,808
|
|
|
$
|
100,713
|
|
|
$
|
1,552,375
|
|
Recoverable deferred taxes on AFUDC recorded in plant
|
|
1
|
|
|
Plant lives
|
|
—
|
|
|
359,215
|
|
|
—
|
|
|
321,680
|
|
||||
Contract valuation adjustments
(b)
|
|
1, 11
|
|
|
Term of related contract
|
|
3,620
|
|
|
153,393
|
|
|
3,775
|
|
|
147,755
|
|
||||
Net AROs
(c)
|
|
1, 13, 14
|
|
|
Plant lives
|
|
—
|
|
|
160,544
|
|
|
—
|
|
|
178,146
|
|
||||
Conservation programs
(d)
|
|
1
|
|
|
One to six years
|
|
55,088
|
|
|
63,275
|
|
|
60,956
|
|
|
84,146
|
|
||||
Environmental remediation costs
|
|
1, 13
|
|
|
Various
|
|
4,735
|
|
|
119,175
|
|
|
3,986
|
|
|
109,377
|
|
||||
Renewable resources and environmental initiatives
|
|
13
|
|
|
One to four years
|
|
46,076
|
|
|
37,858
|
|
|
59,518
|
|
|
38,138
|
|
||||
Depreciation differences
|
|
1
|
|
|
One to seventeen years
|
|
10,918
|
|
|
95,844
|
|
|
5,274
|
|
|
50,057
|
|
||||
Purchased power contract costs
|
|
13
|
|
|
Term of related contract
|
|
—
|
|
|
68,182
|
|
|
—
|
|
|
63,134
|
|
||||
Losses on reacquired debt
|
|
4
|
|
|
Term of related debt
|
|
5,525
|
|
|
36,534
|
|
|
5,917
|
|
|
42,060
|
|
||||
Nuclear refueling outage costs
|
|
1
|
|
|
One to two years
|
|
86,333
|
|
|
36,477
|
|
|
56,035
|
|
|
22,647
|
|
||||
Gas pipeline inspection and remediation costs
|
|
12
|
|
|
Various
|
|
5,416
|
|
|
33,884
|
|
|
5,416
|
|
|
27,560
|
|
||||
Recoverable purchased natural gas and electric energy costs
|
|
1
|
|
|
One to two years
|
|
42,288
|
|
|
15,495
|
|
|
32,098
|
|
|
8,340
|
|
||||
Sherco Unit 3 deferral
|
|
|
|
Twenty-one years
|
|
503
|
|
|
10,063
|
|
|
—
|
|
|
—
|
|
|||||
State commission adjustments
|
|
1
|
|
|
Plant lives
|
|
444
|
|
|
14,204
|
|
|
374
|
|
|
12,181
|
|
||||
Prairie Island EPU
(e)
|
|
12
|
|
|
Pending rate cases
|
|
—
|
|
|
69,668
|
|
|
—
|
|
|
67,590
|
|
||||
Property tax
|
|
|
|
Three years
|
|
18,427
|
|
|
30,626
|
|
|
6,005
|
|
|
12,010
|
|
|||||
Other
|
|
|
|
Various
|
|
20,249
|
|
|
11,973
|
|
|
12,910
|
|
|
24,833
|
|
|||||
Total regulatory assets
|
|
|
|
|
|
$
|
417,801
|
|
|
$
|
2,509,218
|
|
|
$
|
352,977
|
|
|
$
|
2,762,029
|
|
(a)
|
Includes
$303.3 million
and
$330.3 million
for the regulatory recognition of the NSP-Minnesota pension expense of which
$23.2 million
and
$24.3 million
is included in the current asset at Dec. 31, 2013 and 2012, respectively. Also included are
$17.7 million
and
$21.5 million
of regulatory assets related to the nonqualified pension plan of which
$2.2 million
is included in the current asset at Dec. 31, 2013 and 2012, respectively.
|
(b)
|
Includes the fair value of certain long-term PPAs used to meet energy capacity requirements and valuation adjustments on natural gas commodity purchases.
|
(c)
|
Includes amounts recorded for future recovery of AROs, less amounts recovered through nuclear decommissioning accruals and gains from decommissioning investments.
|
(d)
|
Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions.
|
(e)
|
For the canceled Prairie Island EPU project, NSP-Minnesota plans to address recovery of incurred costs in the pending multi-year rate case.
|
(Thousands of Dollars)
|
|
See Note(s)
|
|
Remaining
Amortization Period |
|
Dec. 31, 2013
|
|
Dec. 31, 2012
|
||||||||||||
Regulatory Liabilities
|
|
|
|
|
|
Current
|
|
Noncurrent
|
|
Current
|
|
Noncurrent
|
||||||||
Plant removal costs
|
|
1, 13
|
|
Plant lives
|
|
$
|
—
|
|
|
$
|
906,403
|
|
|
$
|
—
|
|
|
$
|
922,963
|
|
Deferred electric and steam production and natural gas costs
|
|
1
|
|
Less than one year
|
|
96,574
|
|
|
—
|
|
|
90,454
|
|
|
—
|
|
||||
DOE settlement
|
|
12
|
|
One to two years
|
|
44,208
|
|
|
1,131
|
|
|
22,700
|
|
|
1,131
|
|
||||
Investment tax credit deferrals
|
|
1, 6
|
|
Various
|
|
—
|
|
|
56,535
|
|
|
—
|
|
|
59,052
|
|
||||
Deferred income tax adjustment
|
|
1, 6
|
|
Various
|
|
—
|
|
|
43,581
|
|
|
—
|
|
|
44,667
|
|
||||
Conservation programs
(b)
|
|
1, 12
|
|
Less than one year
|
|
19,531
|
|
|
—
|
|
|
6,292
|
|
|
—
|
|
||||
Contract valuation adjustments
(a)
|
|
1, 11
|
|
Term of related contract
|
|
54,455
|
|
|
6,849
|
|
|
29,431
|
|
|
11,159
|
|
||||
Gain from asset sales
|
|
12
|
|
One to three years
|
|
12,859
|
|
|
4,568
|
|
|
7,318
|
|
|
10,311
|
|
||||
Renewable resources and environmental initiatives
|
|
12, 13
|
|
Various
|
|
2,499
|
|
|
1,412
|
|
|
256
|
|
|
1,412
|
|
||||
Low income discount program
|
|
|
|
Less than one year
|
|
6,229
|
|
|
—
|
|
|
6,164
|
|
|
—
|
|
||||
PSCo earnings test
|
|
12
|
|
One to two years
|
|
22,891
|
|
|
19,203
|
|
|
1,732
|
|
|
1,732
|
|
||||
Other
|
|
|
|
Various
|
|
15,523
|
|
|
19,713
|
|
|
4,511
|
|
|
7,512
|
|
||||
Total regulatory liabilities
|
|
|
|
|
|
$
|
274,769
|
|
|
$
|
1,059,395
|
|
|
$
|
168,858
|
|
|
$
|
1,059,939
|
|
(a)
|
Includes the fair value of certain long-term PPAs used to meet energy capacity requirements and valuation adjustments on natural gas commodity purchases.
|
(b)
|
Includes costs for conservation programs, as well as incentives allowed in certain jurisdictions.
|
16.
|
Other Comprehensive Income
|
(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 at Jan. 1
|
|
$
|
(61,241
|
)
|
|
$
|
(99
|
)
|
|
$
|
(51,313
|
)
|
|
$
|
(112,653
|
)
|
Other comprehensive gain before reclassifications
|
|
12
|
|
|
176
|
|
|
1,408
|
|
|
1,596
|
|
||||
Losses reclassified from net accumulated other comprehensive loss
|
|
1,476
|
|
|
—
|
|
|
3,306
|
|
|
4,782
|
|
||||
Net current period OCI
|
|
1,488
|
|
|
176
|
|
|
4,714
|
|
|
6,378
|
|
||||
Accumulated other comprehensive gain (loss) at Dec. 31
|
|
$
|
(59,753
|
)
|
|
$
|
77
|
|
|
$
|
(46,599
|
)
|
|
$
|
(106,275
|
)
|
(Thousands of Dollars)
|
|
Amounts Reclassified
from Accumulated
Other Comprehensive
Loss
|
|
||
(Gains) losses on cash flow hedges:
|
|
|
|
||
Interest rate derivatives
|
|
$
|
4,107
|
|
(a)
|
Vehicle fuel derivatives
|
|
(90
|
)
|
(b)
|
|
Total, pre-tax
|
|
4,017
|
|
|
|
Tax benefit
|
|
(2,541
|
)
|
|
|
Total, net of tax
|
|
1,476
|
|
|
|
Defined benefit pension and postretirement losses:
|
|
|
|
||
Amortization of net loss
|
|
7,077
|
|
(c)
|
|
Prior service cost
|
|
372
|
|
(c)
|
|
Transition obligation
|
|
8
|
|
(c)
|
|
Total, pre-tax
|
|
7,457
|
|
|
|
Tax benefit
|
|
(4,151
|
)
|
|
|
Total, net of tax
|
|
3,306
|
|
|
|
Total amounts reclassified, net of tax
|
|
$
|
4,782
|
|
|
(a)
|
Included in interest charges.
|
(b)
|
Included in O&M expenses.
|
(c)
|
Included in the computation of net periodic pension and post retirement benefit costs. See Note 9 for details regarding these benefit plans.
|
•
|
Xcel Energy’s regulated electric utility segment generates, transmits and distributes electricity in Minnesota, Wisconsin, Michigan, North Dakota, South Dakota, Colorado, Texas and New Mexico. In addition, this segment includes sales for resale and provides wholesale transmission service to various entities in the United States. Regulated electric utility also includes commodity trading operations.
|
•
|
Xcel Energy’s regulated natural gas utility segment transports, stores and distributes natural gas primarily in portions of Minnesota, Wisconsin, North Dakota, Michigan and Colorado.
|
•
|
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
|
||||||||||
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
|
|
(Thousands of Dollars)
|
|
Regulated
Electric
|
|
Regulated
Natural Gas
|
|
All Other
|
|
Reconciling
Eliminations
|
|
Consolidated
Total
|
||||||||||
2012
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Operating revenues from external customers
|
|
$
|
8,517,296
|
|
|
$
|
1,537,374
|
|
|
$
|
73,553
|
|
|
$
|
—
|
|
|
$
|
10,128,223
|
|
Intersegment revenues
|
|
1,169
|
|
|
1,425
|
|
|
—
|
|
|
(2,594
|
)
|
|
—
|
|
|||||
Total revenues
|
|
$
|
8,518,465
|
|
|
$
|
1,538,799
|
|
|
$
|
73,553
|
|
|
$
|
(2,594
|
)
|
|
$
|
10,128,223
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Depreciation and amortization
|
|
$
|
801,649
|
|
|
$
|
115,038
|
|
|
$
|
9,366
|
|
|
$
|
—
|
|
|
$
|
926,053
|
|
Interest charges and financing costs
|
|
397,457
|
|
|
49,456
|
|
|
119,324
|
|
|
—
|
|
|
566,237
|
|
|||||
Income tax expense (benefit)
|
|
465,626
|
|
|
50,322
|
|
|
(65,745
|
)
|
|
—
|
|
|
450,203
|
|
|||||
Net income (loss)
|
|
851,929
|
|
|
98,061
|
|
|
(44,761
|
)
|
|
—
|
|
|
905,229
|
|
(Thousands of Dollars)
|
|
Regulated
Electric
|
|
Regulated
Natural Gas
|
|
All Other
|
|
Reconciling
Eliminations
|
|
Consolidated
Total
|
||||||||||
2011
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Operating revenues from external customers
|
|
$
|
8,766,593
|
|
|
$
|
1,811,926
|
|
|
$
|
76,251
|
|
|
$
|
—
|
|
|
$
|
10,654,770
|
|
Intersegment revenues
|
|
1,269
|
|
|
2,358
|
|
|
—
|
|
|
(3,627
|
)
|
|
—
|
|
|||||
Total revenues
|
|
$
|
8,767,862
|
|
|
$
|
1,814,284
|
|
|
$
|
76,251
|
|
|
$
|
(3,627
|
)
|
|
$
|
10,654,770
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Depreciation and amortization
|
|
$
|
773,392
|
|
|
$
|
106,870
|
|
|
$
|
10,357
|
|
|
$
|
—
|
|
|
$
|
890,619
|
|
Interest charges and financing costs
|
|
402,668
|
|
|
52,115
|
|
|
108,336
|
|
|
—
|
|
|
563,119
|
|
|||||
Income tax expense (benefit)
|
|
473,848
|
|
|
57,408
|
|
|
(62,940
|
)
|
|
—
|
|
|
468,316
|
|
|||||
Net income (loss)
|
|
788,967
|
|
|
101,842
|
|
|
(49,637
|
)
|
|
—
|
|
|
841,172
|
|
18.
|
Summarized Quarterly Financial Data (Unaudited)
|
|
|
Quarter Ended
|
||||||||||||||
(Amounts in thousands, except per share data)
|
|
March 31, 2013
|
|
June 30, 2013
|
|
Sept. 30, 2013
|
|
Dec. 31, 2013
|
||||||||
Operating revenues
|
|
$
|
2,782,849
|
|
|
$
|
2,578,913
|
|
|
$
|
2,822,338
|
|
|
$
|
2,730,822
|
|
Operating income
|
|
454,624
|
|
|
402,236
|
|
|
665,113
|
|
|
325,582
|
|
||||
Net income
|
|
236,570
|
|
|
196,857
|
|
|
364,752
|
|
|
150,055
|
|
||||
Earnings per share total — basic
|
|
$
|
0.48
|
|
|
$
|
0.40
|
|
|
$
|
0.73
|
|
|
$
|
0.30
|
|
Earnings per share total — diluted
|
|
0.48
|
|
|
0.40
|
|
|
0.73
|
|
|
0.30
|
|
||||
Cash dividends declared per common share
|
|
0.27
|
|
|
0.28
|
|
|
0.28
|
|
|
0.28
|
|
|
|
Quarter Ended
|
||||||||||||||
(Amounts in thousands, except per share data)
|
|
March 31, 2012
|
|
June 30, 2012
|
|
Sept. 30, 2012
|
|
Dec. 31, 2012
|
||||||||
Operating revenues
|
|
$
|
2,578,079
|
|
|
$
|
2,274,668
|
|
|
$
|
2,724,341
|
|
|
$
|
2,551,135
|
|
Operating income
|
|
380,162
|
|
|
405,690
|
|
|
720,434
|
|
|
316,397
|
|
||||
Net income
|
|
183,893
|
|
|
183,060
|
|
|
398,106
|
|
|
140,170
|
|
||||
Earnings per share total — basic
|
|
$
|
0.38
|
|
|
$
|
0.38
|
|
|
$
|
0.82
|
|
|
$
|
0.29
|
|
Earnings per share total — diluted
|
|
0.38
|
|
|
0.38
|
|
|
0.81
|
|
|
0.29
|
|
||||
Cash dividends declared per common share
|
|
0.26
|
|
|
0.27
|
|
|
0.27
|
|
|
0.27
|
|
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 13, 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 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)).
|
||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
||
NSP-Minnesota
|
|||||||||||||
4.10*
|
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 1988, file no. 001-03034). Supplemental Indentures between NSP-Minnesota and said Trustee, dated as follows:
|
||||||||||||
|
Supplemental 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, Rider A).
|
||||||||||||
|
Supplemental 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 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, Rider A).
|
||||||||||||
4.11*
|
Supplemental 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).
|
||||||||||||
4.12*
|
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).
|
||||||||||||
4.13*
|
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).
|
||||||||||||
4.14*
|
Supplemental 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 Current Report on Form 10-Q, (file no. 001-31387) dated Sept. 30, 2002).
|
||||||||||||
4.15*
|
Supplemental Trust Indenture dated Aug. 1, 2002 between NSP-Minnesota and BNY Midwest Trust Company, as successor Trustee, creating $450 million principal amount of 8.0 percent First Mortgage Bonds, Series due Aug. 28, 2012 (Exhibit 4.01 to NSP-Minnesota Current Report on Form 8-K, (file no. 001-31387) dated Aug. 22, 2002).
|
||||||||||||
4.16*
|
Supplemental 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 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 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 Indenture dated March 1, 2008 between NSP-Minnesota and The Bank of New York Trust Company, NA, as successor Trustee (Exhibit 4.01 to Form 8-K (file no. 001-31387) dated March 11, 2008).
|
||||||||||||
4.20*
|
Supplemental 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 Sept. 1, 2039 (Exhibit 4.01 of Form 8-K of NSP-Minnesota dated Nov. 16, 2009 (file no. 001-31387)).
|
||||||||||||
4.21*
|
Supplemental 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 Form 8-K dated Aug. 11, 2010 (file no. 001-31387)).
|
4.22*
|
Supplemental 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’s 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’s Form 8-K dated May 20, 2013 (file no. 001-31387)).
|
||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
||
NSP-Wisconsin
|
|||||||||||||
4.24*
|
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).
|
||||||||||||
4.25*
|
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).
|
||||||||||||
4.26*
|
Supplemental Trust Indenture, dated Dec. 1, 1996 (Exhibit 4.01 to Form 8-K (file no. 001-03140) dated Dec. 12, 1996).
|
||||||||||||
4.27*
|
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).
|
||||||||||||
4.28*
|
Supplemental Trust Indenture dated Sept. 1, 2003 between NSP-Wisconsin and US 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) dated Nov. 13, 2003).
|
||||||||||||
4.29*
|
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)).
|
||||||||||||
4.30*
|
Supplemental 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)).
|
||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
||
PSCo
|
|||||||||||||
4.31*
|
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)).
|
||||||||||||
4.32*
|
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.
|
|
Dated as of
|
|
Previous Filing: Form; Date or file no.
|
|
Exhibit
No.
|
|||
Nov. 1, 1993
|
|
S-3, (33-51167)
|
|
4(b)(2)
|
|
|
Sept. 1, 2002
|
|
8-K, Sept. 18, 2002 (001-03280)
|
|
4.01
|
|
|
Jan. 1, 1994
|
|
10-K, 1993
|
|
4(b)(3)
|
|
|
Sept. 15, 2002
|
|
10-Q, Sept. 30, 2002 (001-03280)
|
|
4.04
|
|
|
Sept. 2, 1994
|
|
8-K, September 1994
|
|
4(b)
|
|
|
March 1, 2003
|
|
S-3, April 14, 2003 (333-104504)
|
|
4(b)(3)
|
|
|
May 1, 1996
|
|
10-Q, June 30, 1996
|
|
4(b)
|
|
|
April 1, 2003
|
|
10-Q May 15, 2003 (001-03280)
|
|
4.02
|
|
|
Nov. 1, 1996
|
|
10-K, 1996 (001-03280)
|
|
4(b)(3)
|
|
|
May 1, 2003
|
|
S-4, June 11, 2003 (333-106011)
|
|
4.9
|
|
|
Feb. 1, 1997
|
|
10-Q, March 31, 1997 (001-03280)
|
|
4(a)
|
|
|
Sept. 1, 2003
|
|
8-K, Sept. 2, 2003 (001-03280)
|
|
4.02
|
|
|
April 1, 1998
|
|
10-Q, March 31,1998 (001-03280)
|
|
4(b)
|
|
|
Sept. 15, 2003
|
|
Xcel 10-K, March 15, 2004 (001-03034)
|
|
4.100
|
|
|
Aug. 15, 2002
|
|
10-Q, Sept. 30, 2002 (001-03280)
|
|
4.03
|
|
|
Aug. 1, 2005
|
|
PSCo 8-K, Aug. 18, 2005 (001-03280)
|
|
4.02
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||
4.33*
|
Indenture dated July 1, 1999, between PSCo and The Bank of New York, providing for the issuance of Senior Debt Securities and 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).
|
||||||||||||
4.34*
|
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).
|
||||||||||||
4.35*
|
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. 14, 2007).
|
||||||||||||
4.36*
|
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)).
|
10.08*+
|
Xcel Energy Executive Annual Incentive Award Plan (as amended and restated effective Feb. 17, 2010) (incorporated by reference to Appendix A to Schedule 14A, Definitive Proxy Statement to Xcel Energy Inc. (file no. 001-03034) dated April 6, 2010).
|
||||||||||||
10.09*+
|
Xcel Energy 2010 Executive Annual Discretionary Award Plan (Exhibit 10.24 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2009).
|
||||||||||||
10.10*+
|
Xcel Energy 2005 Long-Term Incentive Plan (as amended and restated effective Feb. 17, 2010) (incorporated by reference to Appendix B to Schedule 14A, Definitive Proxy Statement to Xcel Energy Inc. (file no. 001-03034) dated April 6, 2010).
|
||||||||||||
10.11*+
|
Xcel Energy 2010 Executive Annual Discretionary Award Plan (as amended and restated effective Dec. 15, 2010) (Exhibit 10.23 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2010).
|
||||||||||||
10.12*+
|
Xcel Energy 2005 Long-Term Incentive Plan Form of Bonus Stock Agreement (Exhibit 10.24 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2010).
|
||||||||||||
10.13*+
|
Xcel Energy 2005 Long-Term Incentive Plan Form of Performance Share Agreement (Exhibit 10.25 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2010).
|
||||||||||||
10.14a*
+
|
Xcel Energy 2005 Long-Term Incentive Plan Form of Restricted Stock Unit Agreement (Exhibit 10.26 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2010).
|
||||||||||||
10.14b*
+
|
Xcel Energy 2005 Long-Term Incentive Plan Form of Time-Based Restricted Stock Unit Agreement (Exhibit 10.14b to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2012).
|
||||||||||||
10.15*+
|
Stock Equivalent Plan for Non-Employee Directors of Xcel Energy as amended and restated effective Feb. 23, 2011 (Appendix A to the Xcel Energy Definitive Proxy Statement (file no. 001-03034) filed April 5, 2011).
|
||||||||||||
10.16*+
|
Xcel Energy Inc. Nonqualified Deferred Compensation Plan (2009 Restatement) (as amended and restated effective Nov. 29, 2011) (Exhibit 10.17 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2011).
|
||||||||||||
10.17*+
|
Second Amendment dated Oct. 26, 2011 to the Xcel Energy Senior Executive Severance and Change-in-Control Policy (Exhibit 10.18 to Form 10-K of Xcel Energy (file no. 001-03034) for the year ended Dec. 31, 2011).
|
||||||||||||
10.18*+
|
Amended and Restated Credit Agreement, dated as of July 27, 2012 among Xcel Energy Inc., as Borrower, the several lenders from time to time parties thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, Bank of America, N.A., and Barclays Bank Plc, as Syndication Agents, and Wells Fargo Bank, National Association, as Documentation Agent (Incorporated by reference to Exhibit 99.01 to Form 8-K, dated July 27, 2012 (file no. 001-03034)).
|
||||||||||||
10.19*+
|
First Amendment dated Feb. 20, 2013 to the Xcel Energy Executive Annual Incentive Award Plan (as amended and restated effective Feb. 17, 2010) (Exhibit 10.01 to Form 10-Q of Xcel Energy (file no. 001-03034) for the quarter ended March 31, 2013).
|
||||||||||||
10.20*+
|
Fourth Amendment dated Feb. 20, 2013 to the Xcel Energy Senior Executive Severance and Change-in-Control Policy (Exhibit 10.02 to Form 10-Q of Xcel Energy (file no. 001-03034) for the quarter ended March 31, 2013).
|
||||||||||||
10.21
+
|
First Amendment dated May 21, 2013 to the Xcel Energy Inc. Long-Term Incentive Plan (as amended and restated effective Feb. 17, 2010).
|
||||||||||||
10.22
+
|
Second Amendment dated May 21, 2013 to the Xcel Energy Inc. Non-Qualified Deferred Compensation Plan (2009 Restatement).
|
||||||||||||
10.23
+
|
Xcel Energy 2005 Long-Term Incentive Plan Form of Long-Term Incentive Award Agreement.
|
||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
||
NSP-Minnesota
|
|||||||||||||
10.24*
|
Ownership and Operating Agreement, dated March 11, 1982, between NSP-Minnesota, Southern Minnesota Municipal Power Agency and United Minnesota Municipal Power Agency concerning Sherburne County Generating Unit No. 3 (Exhibit 10.01 to Form 10-Q for the quarter ended Sept. 30, 1994, file no. 001-03034).
|
||||||||||||
10.25*
|
Restated Interchange Agreement dated Jan. 16, 2001 between NSP-Wisconsin and NSP-Minnesota (Exhibit 10.01 to NSP-Wisconsin Form S-4 (file no. 333-112033) dated Jan. 21, 2004).
|
||||||||||||
10.26*
|
Amended and Restated Credit Agreement, dated as of July 27, 2012 among NSP-Minnesota, as Borrower, the several lenders from time to time parties thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, Bank of America, N.A., and Barclays Bank Plc, as Syndication Agents, and Wells Fargo Bank, NA, as Documentation Agent (Incorporated by reference to Exhibit 99.02 to Form 8-K, dated July 27, 2012 (file no. 001-03034)).
|
||||||||||||
|
|
NSP-Wisconsin
|
|||||||||||||
10.27*
|
Restated Interchange Agreement dated Jan. 16, 2001 between NSP-Wisconsin and NSP-Minnesota (Exhibit 10.01 to Form S-4 (file no. 333-112033) dated Jan. 21, 2004).
|
||||||||||||
10.28*
|
Amended and Restated Credit Agreement, dated as of July 27, 2012 among NSP-Wisconsin, as Borrower, the several lenders from time to time parties thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, Bank of America, N.A., and Barclays Bank Plc, as Syndication Agents, and Wells Fargo Bank, National Association, as Documentation Agent (Incorporated by reference to Exhibit 99.05 to Form 8-K, dated July 27, 2012 (file no. 001-03034)).
|
||||||||||||
|
|
||||||||||||
PSCo
|
|
||||||||||||
10.29*
|
Amended and Restated Coal Supply Agreement entered into Oct. 1, 1984 but made effective as of Jan. 1, 1976 between PSCo and Amax Inc. on behalf of its division, Amax Coal Co. (Form 10-K (file no. 001-03280) Dec. 31, 1984 — Exhibit 10I (1)).
|
||||||||||||
10.30*
|
First Amendment to Amended and Restated Coal Supply Agreement entered into May 27, 1988 but made effective Jan. 1, 1988 between PSCo and Amax Coal Co. (Form 10-K (file no. 001-03280) Dec. 31, 1988 — Exhibit 10I (2)).
|
||||||||||||
10.31*
|
Proposed Settlement Agreement excerpts, as filed with the CPUC (Exhibit 99.02 to Form 8-K (file no. 001-03034) dated Dec. 3, 2004).
|
||||||||||||
10.32*
|
Settlement Agreement among PSCo and Concerned Environmental and Community Parties, dated Dec. 3, 2004 (Exhibit 99.03 to Form 8-K (file no. 001-03034) dated Dec. 3, 2004).
|
||||||||||||
10.33*
|
Amended and Restated Credit Agreement, dated as of July 27, 2012 among PSCo, as Borrower, the several lenders from time to time parties thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, Bank of America, N.A., and Barclays Bank Plc, as Syndication Agents, and Wells Fargo Bank, National Association, as Documentation Agent (Incorporated by reference to Exhibit 99.03 to Form 8-K, dated July 27, 2012 (file no. 001-03034)).
|
||||||||||||
|
|
||||||||||||
SPS
|
|
||||||||||||
10.34*
|
Coal Supply Agreement (Harrington Station) between SPS and TUCO, dated May 1, 1979 (Form 8-K (file no. 001-03789), May 14, 1979 — Exhibit 3).
|
||||||||||||
10.35*
|
Master Coal Service Agreement between Swindell-Dressler Energy Supply Co. and TUCO, dated July 1, 1978 (Form 8-K, (file no. 001-03789) May 14, 1979 — Exhibit 5(A)).
|
||||||||||||
10.36*
|
Guaranty of Master Coal Service Agreement between Swindell-Dressler Energy Supply Co. and TUCO (Form 8-K, (file no. 3789) May 14, 1979 — Exhibit 5(B)).
|
||||||||||||
10.37*
|
Coal Supply Agreement (Tolk Station) between SPS and TUCO dated April 30, 1979, as amended Nov. 1, 1979 and Dec. 30, 1981 (Form 10-Q, (file no. 3789) Feb. 28, 1982 — Exhibit 10(b)).
|
||||||||||||
10.38*
|
Master Coal Service Agreement between Wheelabrator Coal Services Co. and TUCO dated Dec. 30, 1981, as amended Nov. 1, 1979 and Dec. 30, 1981 (Form 10-Q, (file no. 3789) Feb. 28, 1982 — Exhibit 10(c)).
|
||||||||||||
10.39*
|
Power Purchase Agreement dated May 23, 1997 between Borger Energy Associates, L.P, and SPS.
|
||||||||||||
10.40*
|
Amended and Restated Credit Agreement, dated as of July 27, 2012 among SPS, as Borrower, the several lenders from time to time parties thereto, JPMorgan Chase Bank, N.A., as Administrative Agent, Bank of America, N.A., and Barclays Bank Plc, as Syndication Agents, and Wells Fargo Bank, National Association, as Documentation Agent (Incorporated by reference to Exhibit 99.04 to Form 8-K, dated July 27, 2012 (file no. 001-03034)).
|
||||||||||||
|
|
||||||||||||
Xcel Energy Inc.
|
|||||||||||||
Statement of Computation of Ratio of Earnings to Fixed Charges.
|
|||||||||||||
Subsidiaries of Xcel Energy Inc.
|
|||||||||||||
Consent of Independent Registered Public Accounting Firm.
|
|||||||||||||
Powers of Attorney.
|
|||||||||||||
Principal Executive Officer’s certification pursuant to 18 U.S. C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
|
|||||||||||||
Principal Financial Officer’s certification pursuant to 18 U.S. C. Section 1350, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
|
|||||||||||||
Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
|
|||||||||||||
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, 2013 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
|
||||||||||
|
2013
|
|
2012
|
|
2011
|
||||||
Income
|
|
|
|
|
|
||||||
Equity earnings of subsidiaries
|
$
|
1,018,783
|
|
|
$
|
976,395
|
|
|
$
|
904,315
|
|
Total income
|
1,018,783
|
|
|
976,395
|
|
|
904,315
|
|
|||
Expenses and other deductions
|
|
|
|
|
|
||||||
Operating expenses
|
18,513
|
|
|
15,948
|
|
|
14,513
|
|
|||
Other income
|
(206
|
)
|
|
(652
|
)
|
|
(760
|
)
|
|||
Interest charges and financing costs
|
102,914
|
|
|
116,731
|
|
|
104,499
|
|
|||
Total expenses and other deductions
|
121,221
|
|
|
132,027
|
|
|
118,252
|
|
|||
Income before income taxes
|
897,562
|
|
|
844,368
|
|
|
786,063
|
|
|||
Income tax benefit
|
(50,672
|
)
|
|
(60,861
|
)
|
|
(55,109
|
)
|
|||
Net income
|
948,234
|
|
|
905,229
|
|
|
841,172
|
|
|||
Dividend requirements on preferred stock
|
—
|
|
|
—
|
|
|
3,534
|
|
|||
Premium on redemption of preferred stock
|
—
|
|
|
—
|
|
|
3,260
|
|
|||
Earnings available to common shareholders
|
$
|
948,234
|
|
|
$
|
905,229
|
|
|
$
|
834,378
|
|
|
|
|
|
|
|
||||||
Other Comprehensive Income
|
|
|
|
|
|
||||||
Pension and retiree medical benefits, net of tax of $5,897, $(2,331) and $(2,247), respectively
|
4,714
|
|
|
(3,311
|
)
|
|
(3,205
|
)
|
|||
Derivative instruments, net of tax of $2,558, $(9,906) and $(24,488), respectively
|
1,488
|
|
|
(15,503
|
)
|
|
(37,644
|
)
|
|||
Other, net of tax of $117, $135 and $(63), respectively
|
176
|
|
|
196
|
|
|
(93
|
)
|
|||
Other comprehensive income (loss)
|
6,378
|
|
|
(18,618
|
)
|
|
(40,942
|
)
|
|||
Comprehensive income
|
$
|
954,612
|
|
|
$
|
886,611
|
|
|
$
|
793,436
|
|
|
|
|
|
|
|
||||||
Weighted average common shares outstanding:
|
|
|
|
|
|
||||||
Basic
|
496,073
|
|
|
487,899
|
|
|
485,039
|
|
|||
Diluted
|
496,532
|
|
|
488,434
|
|
|
485,615
|
|
|||
Earnings per average common share:
|
|
|
|
|
|
||||||
Basic
|
$
|
1.91
|
|
|
$
|
1.86
|
|
|
$
|
1.72
|
|
Diluted
|
1.91
|
|
|
1.85
|
|
|
1.72
|
|
|||
Cash dividends declared per common share
|
1.11
|
|
|
1.07
|
|
|
1.03
|
|
|||
|
|
|
|
|
|
||||||
See Notes to Condensed Financial Statements
|
|
|
2013
|
|
2012
|
||||||||||||
(Thousands of Dollars)
|
|
Accounts Receivable
|
|
Accounts Payable
|
|
Accounts Receivable
|
|
Accounts Payable
|
||||||||
NSP-Minnesota
|
|
$
|
57,596
|
|
|
$
|
—
|
|
|
$
|
63,682
|
|
|
$
|
—
|
|
NSP-Wisconsin
|
|
6,933
|
|
|
—
|
|
|
7,631
|
|
|
—
|
|
||||
PSCo
|
|
74,739
|
|
|
—
|
|
|
—
|
|
|
(3,362
|
)
|
||||
SPS
|
|
5,705
|
|
|
—
|
|
|
15,806
|
|
|
—
|
|
||||
Xcel Energy Services Inc.
|
|
60,138
|
|
|
—
|
|
|
61,217
|
|
|
—
|
|
||||
Xcel Energy Ventures Inc.
|
|
20,194
|
|
|
—
|
|
|
20,427
|
|
|
—
|
|
||||
Other subsidiaries of Xcel Energy Inc.
|
|
15,145
|
|
|
—
|
|
|
30,037
|
|
|
—
|
|
||||
|
|
$
|
240,450
|
|
|
$
|
—
|
|
|
$
|
198,800
|
|
|
$
|
(3,362
|
)
|
(Amounts in Millions, Except Interest Rates)
|
|
Three Months Ended Dec. 31, 2013
|
||
Lending limit
|
|
$
|
250
|
|
Loan outstanding at period end
|
|
72
|
|
|
Average loan outstanding
|
|
109.8
|
|
|
Maximum loan outstanding
|
|
182
|
|
|
Weighted average interest rate, computed on a daily basis
|
|
0.31
|
%
|
|
Weighted average interest rate at end of period
|
|
0.25
|
|
|
Money pool interest income
|
|
$
|
0.1
|
|
(Amounts in Millions, Except Interest Rates)
|
|
Twelve Months Ended Dec. 31, 2013
|
|
Twelve Months Ended Dec. 31, 2012
|
|
Twelve Months Ended Dec. 31, 2011
|
||||||
Lending limit
|
|
$
|
250
|
|
|
$
|
250
|
|
|
$
|
250
|
|
Loan outstanding at period end
|
|
72
|
|
|
—
|
|
|
18
|
|
|||
Average loan outstanding
|
|
88.2
|
|
|
26.1
|
|
|
0.4
|
|
|||
Maximum loan outstanding
|
|
243
|
|
|
226
|
|
|
43
|
|
|||
Weighted average interest rate, computed on a daily basis
|
|
0.30
|
%
|
|
0.33
|
%
|
|
0.35
|
%
|
|||
Weighted average interest rate at end of period
|
|
0.25
|
|
|
N/A
|
|
|
0.35
|
|
|||
Money pool interest income
|
|
$
|
0.3
|
|
|
$
|
0.1
|
|
|
$
|
—
|
|
XCEL ENERGY INC. AND SUBSIDIARIES
VALUATION AND QUALIFYING ACCOUNTS
YEARS ENDED DEC. 31, 2013, 2012 AND 2011
(amounts in thousands)
|
|||||||||||||||||||
|
|
|
Additions
|
|
|
|
|
||||||||||||
|
Balance at
Jan. 1
|
|
Charged to
Costs and
Expenses
|
|
Charged to
Other
Accounts
(a)
|
|
Deductions from
Reserves
(b)(c)
|
|
Balance at
Dec. 31
|
||||||||||
Allowance for bad debts:
|
|
|
|
|
|
|
|
|
|
||||||||||
2013
|
$
|
51,394
|
|
|
$
|
37,627
|
|
|
$
|
14,469
|
|
|
$
|
50,383
|
|
|
$
|
53,107
|
|
2012
|
58,565
|
|
|
33,808
|
|
|
16,033
|
|
|
57,012
|
|
|
51,394
|
|
|||||
2011
|
54,563
|
|
|
44,521
|
|
|
15,636
|
|
|
56,155
|
|
|
58,565
|
|
|||||
NOL and tax credit valuation allowances:
|
|
|
|
|
|
|
|
|
|
||||||||||
2013
|
$
|
3,314
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
51
|
|
|
$
|
3,263
|
|
2012
|
5,683
|
|
|
32
|
|
|
—
|
|
|
2,401
|
|
|
3,314
|
|
|||||
2011
|
1,927
|
|
|
4,379
|
|
|
—
|
|
|
623
|
|
|
5,683
|
|
(a)
|
Recovery of amounts previously written off as related to allowance for bad debts.
|
(b)
|
Principally bad debts written off as related to allowance for bad debts.
|
(c)
|
Reductions to valuation allowances for NOL and tax credit carryforwards primarily due to changes in tax laws, expirations of certain carryforwards and identification of various tax planning strategies.
|
|
|
XCEL ENERGY INC.
|
|
|
|
Feb. 21, 2014
|
By:
|
/s/ TERESA S. MADDEN
|
|
|
Teresa S. Madden
|
|
|
Senior Vice President and Chief Financial Officer
|
|
|
(Principal Financial Officer)
|
1.
|
Section 8, subsection (d) is hereby amended and restated in its entirety as follows:
|
2.
|
Section 14, subsection (m) is hereby amended and restated in its entirety as
|
|
/s/ Benjamin G.S. Fowke III
|
|
|
|
|
By:
|
Benjamin G.S. Fowke III
|
|
|
|
|
Title:
|
Chief Executive Officer
|
|
|
|
|
Grant Date
|
Performance Period
|
Total Performance Shares
(at Target)
|
[DATE]
|
[PERFORMANCE PERIOD]
|
[#]
|
Grant Date
|
Restricted Period
|
Total Restricted Stock Units
|
[DATE]
|
[RESTRICTED PERIOD]
|
[#]
|
|
XCEL ENERGY INC.
|
|
|
By:
|
|
|
|
|
|
|
ACCEPTED:
|
|
|
|
Participant Signature
|
|
|
|
Date
|
(a)
|
If your employment with Xcel Energy terminates due to voluntary termination or involuntary termination, with or without cause, prior to the Vesting Date (as defined in Section 4(a) hereof, or as set forth in the Agreement, as applicable), your unvested Award shall be forfeited on the date of such termination.
|
(b)
|
If your employment with Xcel Energy terminates due to death during any Performance Period or Restricted Period, as applicable, your unvested Award (at Target), together with any credited dividend equivalent units, shall immediately vest one hundred percent (100%) and shall be paid as soon as administratively feasible in accordance with Section 5(b) hereof.
|
(c)
|
If your employment with Xcel Energy terminates due to permanent and total disability during any Performance Period or Restricted Period, as applicable, your unvested Award (at Target), together with any credited dividend equivalent units, shall immediately vest one hundred percent (100%) and shall be paid to you (or your personal representative) as soon as administratively feasible in cash, shares or a combination thereof as provided in Section 5(a) hereof.
|
(d)
|
If your employment with Xcel Energy terminates due to retirement (as defined under any retirement plan of Xcel Energy in which you participate):
|
(i)
|
after the expiration of a Performance Period, but prior to the applicable Vesting Date, you will continue to be eligible to have your Award vest in accordance with the terms of the applicable Performance Goal Annex(es); or
|
(ii)
|
during any Performance Period, you will continue to be eligible to have a pro rata portion of your Award vest, such pro rata portion to be equal to the amount of the Award that would otherwise vest in accordance with the terms of the applicable Performance Goal Annex(es) had you not retired multiplied by a fraction whose numerator is the number of whole months during which you were actively employed with Xcel Energy during such Performance Period and whose denominator is [the length of the Performance Period, expressed as a number of months].
|
(iii)
|
any unvested Award whose vesting is not subject to the satisfaction of Performance Goals set forth in a Performance Goals Annex shall be forfeited on the date of your retirement.
|
|
Year Ended Dec. 31
|
||||||||||||||||||
|
2013
|
|
2012
|
|
2011
|
|
2010
|
|
2009
|
||||||||||
Earnings, as defined:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Pretax income from continuing operations
|
$
|
1,432,210
|
|
|
$
|
1,355,402
|
|
|
$
|
1,309,690
|
|
|
$
|
1,188,591
|
|
|
$
|
1,056,838
|
|
Add: Fixed charges
|
686,258
|
|
|
734,564
|
|
|
725,375
|
|
|
708,529
|
|
|
705,740
|
|
|||||
Add: Dividends from unconsolidated subsidiaries
|
36,416
|
|
|
33,470
|
|
|
34,034
|
|
|
32,538
|
|
|
29,059
|
|
|||||
Deduct: Equity earnings of unconsolidated subsidiaries
|
30,020
|
|
|
29,971
|
|
|
30,527
|
|
|
29,948
|
|
|
24,664
|
|
|||||
Total earnings, as defined
|
$
|
2,124,864
|
|
|
$
|
2,093,465
|
|
|
$
|
2,038,572
|
|
|
$
|
1,899,710
|
|
|
$
|
1,766,973
|
|
Fixed charges, as defined:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Interest charges
|
$
|
575,199
|
|
|
$
|
601,582
|
|
|
$
|
591,098
|
|
|
$
|
577,291
|
|
|
$
|
561,654
|
|
Interest charges on life insurance policy borrowings
|
245
|
|
|
310
|
|
|
332
|
|
|
372
|
|
|
324
|
|
|||||
Interest component of leases
|
110,814
|
|
|
132,672
|
|
|
133,945
|
|
|
130,866
|
|
|
143,762
|
|
|||||
Total fixed charges, as defined
|
$
|
686,258
|
|
|
$
|
734,564
|
|
|
$
|
725,375
|
|
|
$
|
708,529
|
|
|
$
|
705,740
|
|
Ratio of earnings to fixed charges
|
3.1
|
|
|
2.8
|
|
|
2.8
|
|
|
2.7
|
|
|
2.5
|
|
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
|
(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 Omnibus Incentive Plan)
|
•
|
No. 333-115754 and 333-175189 (relating to Stock Equivalent Plan for Non-Employee Directors)
|
•
|
No. 333-191673 (relating to the Xcel Energy Dividend Reinvestment and Cash Payment Plan)
|
•
|
No. 333-183536 (relating to senior debt securities, junior subordinated debt securities and common stock
|
•
|
No. 333-192845 (relating to NSP-MN)
|
•
|
No. 333-192835 (relating to NSP-WI)
|
•
|
No. 333-191629 (relating to PSCo)
|
•
|
No. 333-188179 (relating to SPS)
|
/s/ DELOITTE & TOUCHE LLP
|
|
Minneapolis, Minnesota
|
|
February 21, 2014
|
|
|
/s/ Benjamin G.S. Fowke III
|
|
|
Benjamin G.S. Fowke III
|
|
|
Chairman, President, Chief Executive Officer and Director
|
|
/s/ Gail Koziara Boudreaux
|
|
|
Gail Koziara Boudreaux
|
|
|
Director
|
|
/s/ Fredric W. Corrigan
|
|
|
Fredric W. Corrigan
|
|
|
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/ 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/ BENJAMIN G.S. FOWKE III
|
|
Benjamin G.S. Fowke III
|
|
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
|
|
Senior Vice President and 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/ BENJAMIN G.S. FOWKE III
|
|
Benjamin G.S. Fowke III
|
|
Chairman, President, Chief Executive Officer and Director
|
|
|
|
/s/ TERESA S. MADDEN
|
|
Teresa S. Madden
|
|
Senior Vice President and 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.
|