|
x
|
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
|
¨
|
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
|
001-31387
|
|
41-1967505
|
(Commission File Number)
|
|
(I.R.S. Employer Identification No.)
|
(Registrant, State of Incorporation or Organization, Address of Principal Executive Officers and Telephone Number)
|
Northern States Power Company
|
(a Minnesota corporation)
|
414 Nicollet Mall
|
Minneapolis, MN 55401
|
612-330-5500
|
|
PART I
|
|
Item 1 —
Business
|
|
Item 1A —
Risk Factors
|
|
Item 1B —
Unresolved Staff Comments
|
|
Item 2 —
Properties
|
|
Item 3 —
Legal Proceedings
|
|
Item 4 —
Mine Safety Disclosures
|
|
|
|
PART II
|
|
Item 6 —
Selected Financial Data
|
|
Item 9A —
Controls and Procedures
|
|
Item 9B —
Other Information
|
|
|
|
PART III
|
|
Item 11 —
Executive Compensation
|
|
Item 14 —
Principal Accountant Fees and Services
|
|
|
|
PART IV
|
|
Item 15 —
Exhibits, Financial Statement Schedules
|
|
Item 16 —
Form 10-K Summary
|
|
|
|
Corps
|
U.S. Army Corps of Engineers
|
CPP
|
Clean Power Plan
|
CWA
|
Clean Water Act
|
CWIP
|
Construction work in progress
|
DCF
|
Discounted Cash Flows
|
ELG
|
Effluent limitations guidelines
|
EMANI
|
European Mutual Association for Nuclear Insurance
|
ETR
|
Effective tax rate
|
FASB
|
Financial Accounting Standards Board
|
FTR
|
Financial transmission right
|
GAAP
|
Generally accepted accounting principles
|
GE
|
General Electric
|
GHG
|
Greenhouse gas
|
IPP
|
Independent power producing entity
|
IRP
|
Integrated Resource Plan
|
ISFSI
|
Independent spent fuel storage installation
|
ITC
|
Investment tax credit
|
LLW
|
Low-level radioactive waste
|
LNG
|
Liquefied natural gas
|
MGP
|
Manufactured gas plant
|
MISO
|
Midcontinent Independent System Operator, Inc.
|
Moody’s
|
Moody’s Investor Services
|
Native load
|
Customer demand of retail and wholesale customers that a utility has an obligation to serve under statute or long-term contract.
|
NAV
|
Net asset value
|
NEIL
|
Nuclear Electric Insurance Ltd.
|
NETO
|
New England Transmission Owners
|
NOL
|
Net operating loss
|
O&M
|
Operating and maintenance
|
Paris Agreement
|
Establishes a framework for GHG mitigation actions by all countries (“nationally determined contributions”)
|
PI
|
Prairie Island nuclear generating plant
|
Pipeline Safety Act
|
Pipeline Safety, Regulatory Certainty, and Job Creation Act
|
PPA
|
Purchased power agreement
|
PTC
|
Production tax credit
|
REC
|
Renewable energy credit
|
ROE
|
Return on equity
|
RTO
|
Regional Transmission Organization
|
SAB
|
Staff Accounting Bulletin
|
SAB 118
|
Income Tax Accounting Implications of the Tax Cuts and Jobs Act
|
SERP
|
Supplemental executive retirement plan
|
SMMPA
|
Southern Minnesota Municipal Power Agency
|
Standard & Poor’s
|
Standard & Poor’s Ratings Services
|
TCJA
|
2017 federal tax reform enacted as Public Law No: 115-97, commonly referred to as the Tax Cuts and Jobs Act
|
TO
|
Transmission owner
|
VaR
|
Value at Risk
|
VIE
|
Variable interest entity
|
Westinghouse
|
Westinghouse Electric Corporation
|
|
|
Measurements
|
|
Bcf
|
Billion cubic feet
|
KV
|
Kilovolts
|
KWh
|
Kilowatt hours
|
MMBtu
|
Million British thermal units
|
MW
|
Megawatts
|
MWh
|
Megawatt hours
|
|
|
|
|
|
NSP-Minnesota
|
||
|
Electric customers
|
1.5 million
|
|
|
Natural gas customers
|
0.5 million
|
|
|
Consolidated earnings contribution
|
35% to 45%
|
|
|
Total assets
|
$18.5 billion
|
|
|
Electric generating capacity
|
7,530 MW
|
|
|
Gas storage capacity
|
14.7 Bcf
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended Dec. 31
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
Electric sales (Millions of KWh)
|
|
|
|
|
|
||||||
Residential
|
10,476
|
|
|
9,900
|
|
|
10,107
|
|
|||
Large C&I
|
8,877
|
|
|
8,829
|
|
|
8,890
|
|
|||
Small C&I
|
15,323
|
|
|
15,104
|
|
|
15,377
|
|
|||
Public authorities and other
|
224
|
|
|
225
|
|
|
248
|
|
|||
Total retail
|
34,900
|
|
|
34,058
|
|
|
34,622
|
|
|||
Sales for resale
|
6,736
|
|
|
5,739
|
|
|
5,333
|
|
|||
Total energy sold
|
41,636
|
|
|
39,797
|
|
|
39,955
|
|
|||
|
|
|
|
|
|
||||||
Number of customers at end of period
|
|
|
|
|
|
||||||
Residential
|
1,318,095
|
|
|
1,306,825
|
|
|
1,296,852
|
|
|||
Large C&I
|
558
|
|
|
557
|
|
|
555
|
|
|||
Small C&I
|
157,636
|
|
|
156,386
|
|
|
155,865
|
|
|||
Public authorities and other
|
8,124
|
|
|
7,774
|
|
|
7,368
|
|
|||
Total retail
|
1,484,413
|
|
|
1,471,542
|
|
|
1,460,640
|
|
|||
Wholesale
|
11
|
|
|
8
|
|
|
10
|
|
|||
Total customers
|
1,484,424
|
|
|
1,471,550
|
|
|
1,460,650
|
|
|||
|
|
|
|
|
|
||||||
Electric revenues (Millions of Dollars)
|
|
|
|
|
|
||||||
Residential
|
$
|
1,364.9
|
|
|
$
|
1,320.5
|
|
|
$
|
1,310.3
|
|
Large C&I
|
682.2
|
|
|
690.2
|
|
|
686.2
|
|
|||
Small C&I
|
1,500.6
|
|
|
1,560.3
|
|
|
1,513.0
|
|
|||
Public authorities and other
|
35.4
|
|
|
35.5
|
|
|
35.4
|
|
|||
Total retail
|
3,583.1
|
|
|
3,606.5
|
|
|
3,544.9
|
|
|||
Wholesale
|
193.4
|
|
|
161.6
|
|
|
124.9
|
|
|||
Interchange revenues from NSP-Wisconsin
|
473.7
|
|
|
490.2
|
|
|
475.5
|
|
|||
Other electric revenues
|
257.8
|
|
|
283.4
|
|
|
259.3
|
|
|||
Total electric revenues
|
$
|
4,508.0
|
|
|
$
|
4,541.7
|
|
|
$
|
4,404.6
|
|
|
|
|
|
|
|
||||||
KWh sales per retail customer
|
23,511
|
|
|
23,144
|
|
|
23,703
|
|
|||
Revenue per retail customer
|
$
|
2,414
|
|
|
$
|
2,451
|
|
|
$
|
2,427
|
|
Residential revenue per KWh
|
|
13.03
|
¢
|
|
|
13.34
|
¢
|
|
|
12.96
|
¢
|
Large C&I revenue per KWh
|
7.69
|
|
|
7.82
|
|
|
7.72
|
|
|||
Small C&I revenue per KWh
|
9.79
|
|
|
10.33
|
|
|
9.84
|
|
|||
Total retail revenue per KWh
|
10.27
|
|
|
10.59
|
|
|
10.24
|
|
|||
Wholesale revenue per KWh
|
2.87
|
|
|
2.82
|
|
|
2.34
|
|
|
|
|
|
2018
|
|
2017
|
||
Wind
|
|
16.4
|
%
|
|
18.3
|
%
|
Hydroelectric
|
|
5.8
|
|
|
6.3
|
|
Biomass and solar
|
|
4.8
|
|
|
4.2
|
|
Renewable
|
|
27.0
|
%
|
|
28.8
|
%
|
•
|
The NSP System had approximately 2,550 MW and 2,600 MW of wind energy on its system at the end of 2018 and 2017, respectively.
|
•
|
Average cost per MWh of wind energy under existing PPAs was approximately $44 for 2018 and 2017.
|
•
|
Average cost per MWh of wind energy from owned generation was approximately $37 and $42 for 2018 and 2017, respectively.
|
|
|
Coal
(a)
|
|
Nuclear
|
|
Natural Gas
|
|||||||||||||||
|
|
Cost
|
|
Percent
|
|
Cost
|
|
Percent
|
|
Cost
|
|
Percent
|
|||||||||
2018
|
|
$
|
2.13
|
|
|
42
|
%
|
|
$
|
0.80
|
|
|
45
|
%
|
|
$
|
3.87
|
|
|
13
|
%
|
2017
|
|
2.08
|
|
|
45
|
|
|
0.78
|
|
|
45
|
|
|
4.10
|
|
|
10
|
|
(a)
|
Includes refuse-derived fuel and wood.
|
Normal
|
|
Dec. 31, 2018 Actual
|
|
Dec. 31, 2017 Actual
(a)
|
35 - 50
|
|
47
|
|
53
|
(a)
|
Milder weather, purchase commitments and low power and natural gas prices impacted coal inventory levels.
|
(Millions of Dollars)
|
|
Gas Supply
|
|
Gas Transportation and Storage
(a)
|
||||
2018
|
|
$
|
—
|
|
|
$
|
406
|
|
2017
|
|
—
|
|
|
398
|
|
||
Year of Expiration
|
|
N/A
|
|
|
2020 - 2037
|
|
(a)
|
For incremental supplies, there are limited on-site fuel storage facilities, with a primary reliance on the spot market.
|
•
|
Current nuclear fuel supply contracts cover 100% of uranium concentrates requirements through 2021 and approximately 51% of the requirements for 2022 - 2033;
|
•
|
Current contracts for conversion services cover 100% of the requirements through 2021 and approximately 43% of the requirements for 2022 - 2033; and
|
•
|
Current enrichment service contracts cover 100% of the requirements through 2025 and approximately 19% of the requirements for 2026 - 2033.
|
System Peak Demand (in MW)
|
||||||||
2018
|
|
2017
|
||||||
8,927
|
|
|
June 29
|
|
8,546
|
|
|
July 17
|
•
|
CIP rider
— Recovers the costs of conservation and demand-side management programs.
|
•
|
EIR
— Recovers the costs of environmental improvement projects.
|
•
|
RDF
— Allocates money collected from retail customers to support emerging renewable energy projects and technologies.
|
•
|
RES
— Recovers the cost of renewable generation in Minnesota.
|
•
|
RER
— Recovers the cost of renewable generation in North Dakota.
|
•
|
SEP
— Recovers costs related to various energy policies approved by the Minnesota legislature.
|
•
|
TCR
— Recovers costs associated with investments in electric transmission and distribution grid modernization costs.
|
•
|
Infrastructure rider
— Recovers costs for investments in generation and incremental property taxes in South Dakota.
|
|
Year Ended Dec. 31
|
||||||||||
|
2018
|
|
2017
|
|
2016
|
||||||
Natural gas deliveries (Thousands of MMBtu)
|
|
|
|
|
|
||||||
Residential
|
43,876
|
|
|
38,365
|
|
|
35,592
|
|
|||
C&I
|
45,909
|
|
|
41,047
|
|
|
37,824
|
|
|||
Total retail
|
89,785
|
|
|
79,412
|
|
|
73,416
|
|
|||
Transportation and other
|
13,101
|
|
|
13,109
|
|
|
11,189
|
|
|||
Total deliveries
|
102,886
|
|
|
92,521
|
|
|
84,605
|
|
|||
|
|
|
|
|
|
||||||
Number of customers at end of period
|
|
|
|
|
|
||||||
Residential
|
475,441
|
|
|
470,255
|
|
|
465,745
|
|
|||
C&I
|
44,217
|
|
|
43,859
|
|
|
43,553
|
|
|||
Total retail
|
519,658
|
|
|
514,114
|
|
|
509,298
|
|
|||
Transportation and other
|
26
|
|
|
26
|
|
|
25
|
|
|||
Total customers
|
519,684
|
|
|
514,140
|
|
|
509,323
|
|
|||
|
|
|
|
|
|
||||||
Natural gas revenues (Millions of Dollars)
|
|
|
|
|
|
||||||
Residential
|
$
|
320.0
|
|
|
$
|
287.5
|
|
|
$
|
261.6
|
|
C&I
|
248.8
|
|
|
221.6
|
|
|
194.0
|
|
|||
Total retail
|
568.8
|
|
|
509.1
|
|
|
455.6
|
|
|||
Transportation and other
|
14.3
|
|
|
22.8
|
|
|
11.8
|
|
|||
Total natural gas revenues
|
$
|
583.1
|
|
|
$
|
531.9
|
|
|
$
|
467.4
|
|
|
|
|
|
|
|
||||||
MMBtu sales per retail customer
|
172.78
|
|
|
154.46
|
|
|
144.15
|
|
|||
Revenue per retail customer
|
$
|
1,095
|
|
|
$
|
990
|
|
|
$
|
895
|
|
Residential revenue per MMBtu
|
7.29
|
|
|
7.49
|
|
|
7.35
|
|
|||
C&I revenue per MMBtu
|
5.42
|
|
|
5.40
|
|
|
5.13
|
|
|||
Transportation and other revenue per MMBtu
|
1.09
|
|
|
1.74
|
|
|
1.05
|
|
2018
|
|
2017
|
||||||
MMBtu
|
|
Date
|
|
MMBtu
|
|
Date
|
||
786,751
|
|
(a)
|
Jan. 12
|
|
893,062
|
|
|
Dec. 26
|
(a)
|
Decrease in MMBtu output due to milder winter temperatures in 2018.
|
•
|
Risks associated with use of radioactive material in the production of energy, the management, handling, storage and disposal of radioactive materials;
|
•
|
Limitations on insurance available to cover losses that might arise in connection with nuclear operations, as well as obligations to contribute to an insurance pool in the event of damages at a covered U.S. reactor; and,
|
•
|
Uncertainties with the technological and financial aspects of decommissioning nuclear plants. For example, assumptions regarding decommissioning costs may change based on economic conditions and changes in the expected life of the asset may cause our funding obligations to change.
|
NSP-Minnesota
Station, Location and Unit |
|
Fuel
|
|
Installed
|
|
MW
(a)
|
|
|
Steam:
|
|
|
|
|
|
|
|
|
A.S. King-Bayport, MN, 1 Unit
|
|
Coal
|
|
1968
|
|
511
|
|
|
Sherco-Becker, MN
|
|
|
|
|
|
|
|
|
Unit 1
|
|
Coal
|
|
1976
|
|
680
|
|
|
Unit 2
|
|
Coal
|
|
1977
|
|
682
|
|
|
Unit 3
|
|
Coal
|
|
1987
|
|
517
|
|
(b)
|
Monticello MN, 1 Unit
|
|
Nuclear
|
|
1971
|
|
617
|
|
|
PI-Welch, MN
|
|
|
|
|
|
|
|
|
Unit 1
|
|
Nuclear
|
|
1973
|
|
521
|
|
|
Unit 2
|
|
Nuclear
|
|
1974
|
|
519
|
|
|
Various locations, 4 Units
|
|
Wood/Refuse
|
|
Various
|
|
36
|
|
(c)
|
Combustion Turbine:
|
|
|
|
|
|
|
|
|
Angus Anson-Sioux Falls, SD, 3 Units
|
|
Natural Gas
|
|
1994 - 2005
|
|
327
|
|
|
Black Dog-Burnsville, MN, 3 Units
|
|
Natural Gas
|
|
1987 - 2002
|
|
494
|
|
(d)
|
Blue Lake-Shakopee, MN, 6 Units
|
|
Natural Gas
|
|
1974 - 2005
|
|
453
|
|
|
High Bridge-St. Paul, MN, 3 Units
|
|
Natural Gas
|
|
2008
|
|
530
|
|
|
Inver Hills-Inver Grove Heights, MN, 6 Units
|
|
Natural Gas
|
|
1972
|
|
282
|
|
|
Riverside-Minneapolis, MN, 3 Units
|
|
Natural Gas
|
|
2009
|
|
454
|
|
|
Various locations, 14 Units
|
|
Natural Gas
|
|
Various
|
|
67
|
|
|
Wind:
|
|
|
|
|
|
|
|
|
Border-Rolette County, ND, 75 Units
|
|
Wind
|
|
2015
|
|
148
|
|
(e)
|
Courtenay Wind, ND, 100 Units
|
|
Wind
|
|
2016
|
|
195
|
|
(e)
|
Grand Meadow-Mower County, MN, 67 Units
|
|
Wind
|
|
2008
|
|
101
|
|
(e)
|
Nobles-Nobles County, MN, 134 Units
|
|
Wind
|
|
2010
|
|
200
|
|
(e)
|
Pleasant Valley-Mower County, MN, 100 Units
|
|
Wind
|
|
2015
|
|
196
|
|
(e)
|
|
|
|
|
Total
|
|
7,530
|
|
|
(a)
|
Summer 2018 net dependable capacity.
|
(b)
|
Based on NSP-Minnesota’s ownership of 59%.
|
(c)
|
Refuse-derived fuel is made from municipal solid waste.
|
(d)
|
Black Dog Unit 6 was commissioned and placed into operation in the third quarter of 2018.
|
(e)
|
The values disclosed are the maximum generation levels for these wind units. Capacity is attainable only when wind conditions are sufficiently available (on-demand net dependable capacity is zero).
|
Miles
|
|
|
Transmission
|
90
|
|
Distribution
|
10,437
|
|
(Millions of Dollars)
|
|
2018
|
|
2017
|
||||
First quarter
|
|
$
|
84.6
|
|
|
$
|
85.7
|
|
Second quarter
|
|
88.7
|
|
|
88.0
|
|
||
Third quarter
|
|
184.2
|
|
|
243.5
|
|
||
Fourth quarter
|
|
82.7
|
|
|
98.7
|
|
(Millions of Dollars)
|
|
2018
|
|
2017
|
||||
Electric revenues before TCJA impact
|
|
$
|
4,692.6
|
|
|
$
|
4,541.7
|
|
Electric fuel and purchased power before TCJA impact
|
|
(1,706.6
|
)
|
|
(1,626.9
|
)
|
||
Electric margin before TCJA impact
|
|
$
|
2,986.0
|
|
|
$
|
2,914.8
|
|
TCJA impact (offset as a reduction in income tax)
|
|
(179.1
|
)
|
|
—
|
|
||
Electric margin
|
|
$
|
2,806.9
|
|
|
$
|
2,914.8
|
|
(Millions of Dollars)
|
|
2018 vs. 2017
|
||
Purchased capacity costs
|
|
$
|
31.7
|
|
Retail sales growth (including Minnesota decoupling and sales true-up)
|
|
23.5
|
|
|
Non-fuel riders
|
|
19.0
|
|
|
Estimated impact of weather (net of Minnesota decoupling)
|
|
17.4
|
|
|
Wholesale transmission margin
|
|
8.0
|
|
|
Interchange agreement billings with NSP-Wisconsin
|
|
(17.9
|
)
|
|
Conservation incentive
|
|
(8.9
|
)
|
|
Other (net)
|
|
(1.6
|
)
|
|
Total increase in electric margin before TCJA impact
|
|
$
|
71.2
|
|
TCJA impact (offset as a reduction in income tax)
|
|
(179.1
|
)
|
|
Total decrease in electric margin
|
|
$
|
(107.9
|
)
|
(Millions of Dollars)
|
|
2018
|
|
2017
|
||||
Natural gas revenues before TCJA impact
|
|
$
|
590.0
|
|
|
$
|
531.9
|
|
Cost of natural gas sold and transported
|
|
(345.1
|
)
|
|
(301.8
|
)
|
||
Natural gas margin before TCJA impact
|
|
$
|
244.9
|
|
|
$
|
230.1
|
|
TCJA impact (offset as a reduction in income tax)
|
|
(6.9
|
)
|
|
—
|
|
||
Natural gas margin
|
|
$
|
238.0
|
|
|
$
|
230.1
|
|
(Millions of Dollars)
|
|
2018 vs. 2017
|
||
Estimated impact of weather
|
|
$
|
11.8
|
|
Sales growth
|
|
2.6
|
|
|
Other (net)
|
|
0.4
|
|
|
Total increase in natural gas margin before TCJA impact
|
|
$
|
14.8
|
|
TCJA impact (offset as a reduction in income tax)
|
|
(6.9
|
)
|
|
Total increase in natural gas margin
|
|
$
|
7.9
|
|
(Millions of Dollars)
|
|
2018 vs. 2017
|
||
Business systems and contract labor
|
|
$
|
16.5
|
|
Plant generation costs
|
|
11.4
|
|
|
Distribution costs
|
|
5.4
|
|
|
Nuclear plant operations and amortization
|
|
(9.7
|
)
|
|
Other (net)
|
|
1.4
|
|
|
Total increase in O&M expenses
|
|
$
|
25.0
|
|
•
|
Business systems and contract labor costs increased due to growing network and storage needs, cybersecurity, initiatives to support our customer strategy, and initiatives to improve business processes;
|
•
|
Plant generation costs increased primarily due to the timing of planned maintenance and overhauls at certain generation facilities;
|
•
|
Distribution costs reflect higher maintenance expenses, including vegetation management; and
|
•
|
Nuclear plant operations and amortization are lower largely reflecting savings initiatives and reduced refueling outage costs.
|
Utility Service
|
|
Approval Date
|
|
Additional Information
|
Electric and Natural Gas
|
|
August 2018
|
|
Minnesota
— In 2018, the MPUC ordered NSP-Minnesota to refund the 2018 impacts of TCJA, including $135 million to electric customers and low income program funding, and $6 million to natural gas customers.
|
Electric
|
|
July 2018
|
|
South Dakota
— In July 2018, the SDPUC approved a settlement providing a one-time customer refund of $11 million for the 2018 impact of the TCJA, while NSP-Minnesota would retain the TCJA benefits in 2019 and 2020 in exchange for a two-year rate case moratorium.
|
Natural Gas
|
|
November 2018
|
|
North Dakota
— In November 2018, the NDPSC approved a TCJA settlement in which NSP-Minnesota will amortize $1 million annually of the regulatory asset for the remediation of the MGP site in Fargo, ND and retain the TCJA savings to offset the MGP amortization expense.
|
Electric
|
|
February 2019
|
|
North Dakota
— In February 2019, the NDPSC approved a settlement including a one-time customer refund of $10 million for 2018, while NSP-Minnesota would retain the TCJA benefits in 2019 and 2020 in exchange for a two-year rate case moratorium.
|
Mechanism
|
|
Utility Service
|
|
Amount Requested (in millions)
|
|
Filing
Date
|
|
Approval
|
|
Additional Information
|
NSP-Minnesota (MPUC)
|
||||||||||
TCR
|
|
Electric
|
|
$98
|
|
November
2017
|
|
Pending
|
|
Reflects the revenue requirements for 2018 and a true-up for 2017 and is based on a proposed ROE of 10%. MPUC decision is expected during the first quarter of 2019.
|
CIP Incentive
|
|
Electric & Natural Gas
|
|
$34
|
|
March 2018
|
|
Received
|
|
MPUC approved 2017 CIP electric and natural gas financial incentives, effective October 2018, of $30 million and $4 million, respectively.
|
CIP Rider
|
|
Electric & Natural Gas
|
|
$57
|
|
March 2018
|
|
Received
|
|
The MPUC approved the forecasted 2018 electric and natural gas CIP riders with estimated 2019 recovery of $48 million and $9 million of electric and natural gas CIP expenses, respectively.
|
2018 GUIC
|
|
Natural Gas
|
|
$23
|
|
November 2017
|
|
Pending
|
|
Proposed ROE of 10%. MPUC decision is expected during the first quarter of 2019.
|
2019 GUIC
|
|
Natural Gas
|
|
$29
|
|
November 2018
|
|
Pending
|
|
Proposed ROE of 10.25%. Timing of MPUC decision is uncertain.
|
RDF
|
|
Electric
|
|
$42
|
|
October 2018
|
|
Received
|
|
MPUC approved the 2019 RDF rate based on a net revenue requirement of $42 million, effective January 2019.
|
RES
|
|
Electric
|
|
$23
|
|
November 2017
|
|
Pending
|
|
Reflects the revenue requirements for 2018, 2017 true-up and a proposed ROE of 10%. MPUC decision is expected in the first quarter of 2019.
|
|
|
Futures / Forwards
|
|||||||||||||||||||||
(Millions 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
|
|
2
|
|
|
$
|
2.2
|
|
|
$
|
5.4
|
|
|
$
|
1.7
|
|
|
$
|
1.4
|
|
|
$
|
10.7
|
|
|
|
Options
|
|||||||||||||||||||||
(Millions 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
|
|
2
|
|
|
$
|
0.3
|
|
|
$
|
4.2
|
|
|
$
|
0.8
|
|
|
$
|
—
|
|
|
$
|
5.3
|
|
(Millions of Dollars)
|
|
2018
|
|
2017
|
||||
Fair value of commodity trading net contract assets outstanding at Jan. 1
|
|
$
|
15.7
|
|
|
$
|
9.9
|
|
Contracts realized or settled during the period
|
|
(2.0
|
)
|
|
(3.7
|
)
|
||
Commodity trading contract additions and changes during the period
|
|
2.3
|
|
|
9.5
|
|
||
Fair value of commodity trading net contract assets outstanding at Dec. 31
|
|
$
|
16.0
|
|
|
$
|
15.7
|
|
(Millions of Dollars)
|
|
Year Ended Dec. 31
|
|
VaR Limit
|
|
Average
|
|
High
|
|
Low
|
||||||||||
2018
|
|
$
|
4.83
|
|
|
$
|
6.00
|
|
|
$
|
0.62
|
|
|
$
|
5.63
|
|
|
$
|
0.06
|
|
2017
|
|
0.18
|
|
|
3.00
|
|
|
0.21
|
|
|
0.66
|
|
|
0.04
|
|
/s/ BEN FOWKE
|
|
/s/ ROBERT C. FRENZEL
|
Ben Fowke
|
|
Robert C. Frenzel
|
Chairman and Chief Executive Officer
|
|
Executive Vice President, Chief Financial Officer
|
Feb. 22, 2019
|
|
Feb. 22, 2019
|
/s/ DELOITTE & TOUCHE LLP
|
Minneapolis, Minnesota
|
February 22, 2019
|
|
We have served as the Company’s auditor since 2002.
|
•
|
Certain costs, which would otherwise be charged to expense or other comprehensive income, are deferred as regulatory assets based on the expected ability to recover the costs in future rates; and
|
•
|
Certain credits, which would otherwise be reflected as income or other comprehensive 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.
|
Property, Plant and Equipment
|
(Millions of Dollars)
|
|
Dec. 31, 2018
|
|
Dec. 31, 2017
|
||||
Property, plant and equipment
|
|
|
|
|
||||
Electric plant
|
|
$
|
17,749.3
|
|
|
$
|
17,024.9
|
|
Natural gas plant
|
|
1,475.5
|
|
|
1,370.3
|
|
||
Common and other property
|
|
803.1
|
|
|
724.1
|
|
||
CWIP
|
|
615.1
|
|
|
530.1
|
|
||
Total property, plant and equipment
|
|
20,643.0
|
|
|
19,649.4
|
|
||
Less accumulated depreciation
|
|
(7,454.8
|
)
|
|
(7,018.2
|
)
|
||
Nuclear fuel
|
|
2,770.4
|
|
|
2,697.4
|
|
||
Less accumulated amortization
|
|
(2,416.9
|
)
|
|
(2,295.0
|
)
|
||
|
|
$
|
13,541.7
|
|
|
$
|
13,033.6
|
|
(Millions of Dollars)
|
|
Plant in Service
|
|
Accumulated Depreciation
|
|
CWIP
|
|
Percent Owned
|
|||||||
Electric Generation:
|
|
|
|
|
|
|
|
|
|||||||
Sherco Unit 3
|
|
$
|
604.2
|
|
|
$
|
415.0
|
|
|
$
|
1.0
|
|
|
59
|
%
|
Sherco Common Facilities
|
|
145.4
|
|
|
100.2
|
|
|
1.2
|
|
|
80
|
|
|||
Other
|
|
4.8
|
|
|
3.4
|
|
|
—
|
|
|
59
|
|
|||
Electric Transmission:
|
|
|
|
|
|
|
|
|
|||||||
CapX2020 Transmission
|
|
959.6
|
|
|
72.7
|
|
|
1.9
|
|
|
51
|
|
|||
Other
|
|
10.6
|
|
|
2.3
|
|
|
—
|
|
|
50
|
|
|||
Total
|
|
$
|
1,724.6
|
|
|
$
|
593.6
|
|
|
$
|
4.1
|
|
|
|
(Millions of Dollars)
|
|
See Note(s)
|
|
Remaining Amortization Period
|
|
Dec. 31, 2018
|
|
Dec. 31, 2017
|
|||||||||||||
Regulatory Assets
|
|
|
|
|
|
Current
|
|
Noncurrent
|
|
Current
|
|
Noncurrent
|
|||||||||
Pension and retiree medical obligations
|
|
9
|
|
|
Various
|
|
$
|
28.1
|
|
|
$
|
424.3
|
|
|
$
|
28.5
|
|
|
$
|
403.7
|
|
Net AROs
(a)
|
|
1, 10
|
|
|
Plant lives
|
|
—
|
|
|
323.4
|
|
|
—
|
|
|
193.1
|
|
||||
Excess deferred taxes - TCJA
|
|
7
|
|
|
Various
|
|
—
|
|
|
153.3
|
|
|
—
|
|
|
133.1
|
|
||||
Recoverable deferred taxes on AFUDC recorded in plant
|
|
|
|
Plant lives
|
|
—
|
|
|
117.6
|
|
|
—
|
|
|
119.0
|
|
|||||
Benson biomass PPA termination and asset purchase
|
|
|
|
Ten years
|
|
9.8
|
|
|
85.8
|
|
|
—
|
|
|
—
|
|
|||||
Contract valuation adjustments
(b)
|
|
1, 8
|
|
|
Term of related contract
|
|
14.1
|
|
|
76.0
|
|
|
14.4
|
|
|
89.8
|
|
||||
Laurentian biomass PPA termination
|
|
|
|
Five years
|
|
18.1
|
|
|
73.3
|
|
|
—
|
|
|
—
|
|
|||||
PI extended power update
|
|
|
|
Sixteen years
|
|
3.1
|
|
|
55.8
|
|
|
3.3
|
|
|
58.4
|
|
|||||
Purchased power contracts costs
|
|
|
|
Term of related contract
|
|
2.8
|
|
|
36.6
|
|
|
1.8
|
|
|
39.3
|
|
|||||
Conservation programs
(c)
|
|
1
|
|
|
One to two years
|
|
34.5
|
|
|
21.1
|
|
|
40.4
|
|
|
25.9
|
|
||||
Losses on reacquired debt
|
|
|
|
Term of related debt
|
|
2.1
|
|
|
15.5
|
|
|
2.2
|
|
|
17.6
|
|
|||||
Environmental remediation costs
|
|
1, 10
|
|
|
Pending future rate cases
|
|
1.3
|
|
|
14.3
|
|
|
—
|
|
|
24.6
|
|
||||
Nuclear refueling outage costs
|
|
1
|
|
|
One to two years
|
|
36.3
|
|
|
13.5
|
|
|
49.3
|
|
|
19.7
|
|
||||
Deferred purchased natural gas and electric energy costs
|
|
|
|
One to three years
|
|
5.6
|
|
|
12.6
|
|
|
13.5
|
|
|
13.3
|
|
|||||
Sales true-up and revenue decoupling
|
|
|
|
One to two years
|
|
38.3
|
|
|
6.7
|
|
|
37.3
|
|
|
12.4
|
|
|||||
State commission adjustments
|
|
|
|
Plant lives
|
|
—
|
|
|
3.4
|
|
|
—
|
|
|
3.5
|
|
|||||
Renewable resources and environmental initiatives
|
|
|
|
One to two years
|
|
39.2
|
|
|
0.4
|
|
|
45.9
|
|
|
0.4
|
|
|||||
Gas pipeline inspection and remediation costs
|
|
|
|
Less than one year
|
|
27.4
|
|
|
—
|
|
|
22.6
|
|
|
4.5
|
|
|||||
Other
|
|
|
|
Various
|
|
19.6
|
|
|
20.5
|
|
|
17.2
|
|
|
32.1
|
|
|||||
Total regulatory assets
|
|
|
|
|
|
$
|
280.3
|
|
|
$
|
1,454.1
|
|
|
$
|
276.4
|
|
|
$
|
1,190.4
|
|
(a)
|
Includes amounts recorded for future recovery of AROs, less amounts recovered through nuclear decommissioning accruals and gains from decommissioning investments.
|
(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 costs for conservation programs, as well as incentives allowed in certain jurisdictions.
|
(Millions of Dollars)
|
|
See Note(s)
|
|
Remaining Amortization Period
|
|
Dec. 31, 2018
|
|
Dec. 31, 2017
|
||||||||||||
Regulatory Liabilities
|
|
|
|
|
|
Current
|
|
Noncurrent
|
|
Current
|
|
Noncurrent
|
||||||||
Deferred income tax adjustments and TCJA refunds
(a)
|
|
7
|
|
Various
|
|
$
|
153.7
|
|
|
$
|
1,465.1
|
|
|
$
|
—
|
|
|
$
|
1,516.1
|
|
Plant removal costs
|
|
1, 10
|
|
Plant lives
|
|
—
|
|
|
484.6
|
|
|
—
|
|
|
441.6
|
|
||||
ITC deferrals
(b)
|
|
1
|
|
Various
|
|
—
|
|
|
8.9
|
|
|
—
|
|
|
9.5
|
|
||||
Deferred electric energy costs
|
|
|
|
Less than one year
|
|
22.8
|
|
|
—
|
|
|
11.3
|
|
|
—
|
|
||||
DOE Settlement
|
|
|
|
Less than one year
|
|
13.0
|
|
|
—
|
|
|
12.8
|
|
|
—
|
|
||||
Contract valuation adjustments
(c)
|
|
1, 8
|
|
Less than one year
|
|
10.4
|
|
|
—
|
|
|
17.2
|
|
|
—
|
|
||||
Renewable resources and environmental initiatives
|
|
|
|
Less than one year
|
|
8.8
|
|
|
—
|
|
|
19.4
|
|
|
—
|
|
||||
Other
|
|
|
|
Various
|
|
53.7
|
|
|
26.1
|
|
|
22.7
|
|
|
11.3
|
|
||||
Total regulatory liabilities
(d)
|
|
|
|
|
|
$
|
262.4
|
|
|
$
|
1,984.7
|
|
|
$
|
83.4
|
|
|
$
|
1,978.5
|
|
(a)
|
Includes the revaluation of recoverable/regulated plant ADIT and revaluation impact of non-plant ADIT due to the TCJA.
|
(b)
|
Includes impact of lower federal tax rate due to the TCJA.
|
(c)
|
Includes the fair value of certain long-term PPAs used to meet energy capacity requirements and valuation adjustments on natural gas commodity purchases.
|
(d)
|
Revenue subject for refund of
$12.5 million
and
$15.1 million
for 2018 and 2017, respectively, is included in other current liabilities.
|
|
|
Three Months Ended Dec. 31, 2018
|
|
Year Ended
|
||||||||||||
(Amounts in Millions, Except Interest Rates)
|
|
|
2018
|
|
2017
|
|
2016
|
|||||||||
Borrowing limit
|
|
$
|
250
|
|
|
$
|
250
|
|
|
$
|
250
|
|
|
$
|
250
|
|
Amount outstanding at period end
|
|
—
|
|
|
—
|
|
|
85
|
|
|
—
|
|
||||
Average amount outstanding
|
|
18
|
|
|
17
|
|
|
25
|
|
|
16
|
|
||||
Maximum amount outstanding
|
|
76
|
|
|
143
|
|
|
142
|
|
|
225
|
|
||||
Weighted average interest rate, computed on a daily basis
|
|
2.23
|
%
|
|
1.96
|
%
|
|
1.14
|
%
|
|
0.69
|
%
|
||||
Weighted average interest rate at period end
|
|
N/A
|
|
|
N/A
|
|
|
1.18
|
|
|
N/A
|
|
|
|
Three Months Ended Dec. 31, 2018
|
|
Year Ended Dec. 31
|
||||||||||||
(Amounts in Millions, Except Interest Rates)
|
|
|
2018
|
|
2017
|
|
2016
|
|||||||||
Borrowing limit
|
|
$
|
500
|
|
|
$
|
500
|
|
|
$
|
500
|
|
|
$
|
500
|
|
Amount outstanding at period end
|
|
150
|
|
|
150
|
|
|
20
|
|
|
85
|
|
||||
Average amount outstanding
|
|
62
|
|
|
38
|
|
|
62
|
|
|
73
|
|
||||
Maximum amount outstanding
|
|
198
|
|
|
198
|
|
|
237
|
|
|
353
|
|
||||
Weighted average interest rate, computed on a daily basis
|
|
2.53
|
%
|
|
2.08
|
%
|
|
1.10
|
%
|
|
0.65
|
%
|
||||
Weighted average interest rate at end of period
|
|
2.97
|
|
|
2.97
|
|
|
1.93
|
|
|
0.94
|
|
Debt-to-Total Capitalization Ratio
(a)
|
|
Amount Facility May Be Increased (millions)
|
|
Additional Periods For Which a One-Year Extension May Be Requested
(b)
|
|||||||
2018
|
|
2017
|
|
|
|
|
|||||
48
|
%
|
|
48
|
%
|
|
$
|
100
|
|
|
2
|
|
(a)
|
The credit facility has a financial covenant requiring that the debt-to-total capitalization ratio be less than or equal to
65%
.
|
(b)
|
All extension requests are subject to majority bank group approval.
|
Credit Facility
(a)
|
|
Drawn
(b)
|
|
Available
|
||||||
$
|
500
|
|
|
$
|
187
|
|
|
$
|
313
|
|
(a)
|
This credit facility matures in
June 2021
.
|
(b)
|
Includes outstanding commercial paper and letters of credit.
|
(Millions of Dollars)
|
|
Maturity Range
|
|
Interest Rate Range 2018
|
|
Interest Rate Range 2017
|
|
2018
|
|
2017
|
||||
NSP-Minnesota
|
|
|
|
|
|
|
|
|
|
|
||||
Mortgage bonds
|
|
2020-2047
|
|
2.15% - 7.13%
|
|
2.15% - 7.13%
|
|
$
|
5,000
|
|
|
$
|
5,000
|
|
Unamortized discount
|
|
|
|
|
|
|
|
(21
|
)
|
|
(22
|
)
|
||
Unamortized debt issuance cost
|
|
|
|
|
|
|
|
(42
|
)
|
|
(45
|
)
|
||
Current maturities
|
|
|
|
|
|
|
|
—
|
|
|
—
|
|
||
Total
|
|
|
|
|
|
|
|
$
|
4,937
|
|
|
$
|
4,933
|
|
|
|
Amount
|
|
Financing Instrument
|
|
Interest Rate
|
|
Maturity Date
|
|
NSP-Minnesota
|
|
600 million
|
|
First mortgage bonds
|
|
3.60
|
%
|
|
Sept. 15, 2047
|
|
|
Equity to Total Capitalization Ratio - Required Range
|
|
Equity to Total Capitalization Ratio - Actual
|
|||||
|
|
Low
|
|
High
|
|
2018
|
|||
NSP-Minnesota
|
|
47.1
|
%
|
|
57.5
|
%
|
|
52.3
|
%
|
|
|
Unrestricted Retained Earnings
|
|
Total Capitalization
|
|
Limit on Total Capitalization
|
||||||
NSP-Minnesota
|
|
$
|
1.0
|
billion
|
|
$
|
10.7
|
billion
|
|
$
|
11.5
|
billion
|
|
|
Year Ended Dec. 31, 2018
|
||||||||||||||
(Millions of Dollars)
|
|
Electric
|
|
Natural Gas
|
|
All Other
|
|
Total
|
||||||||
Major revenue types
|
|
|
|
|
|
|
|
|
||||||||
Revenue from contracts with customers:
|
|
|
|
|
|
|
|
|
||||||||
Residential
|
|
$
|
1,308.4
|
|
|
$
|
308.8
|
|
|
$
|
27.2
|
|
|
$
|
1,644.4
|
|
C&I
|
|
2,052.1
|
|
|
239.3
|
|
|
0.2
|
|
|
2,291.6
|
|
||||
Other
|
|
36.5
|
|
|
—
|
|
|
3.4
|
|
|
39.9
|
|
||||
Total retail
|
|
3,397.0
|
|
|
548.1
|
|
|
30.8
|
|
|
3,975.9
|
|
||||
Wholesale
|
|
189.2
|
|
|
—
|
|
|
—
|
|
|
189.2
|
|
||||
Transmission
|
|
238.1
|
|
|
—
|
|
|
—
|
|
|
238.1
|
|
||||
Interchange
|
|
473.7
|
|
|
—
|
|
|
—
|
|
|
473.7
|
|
||||
Other
|
|
28.3
|
|
|
11.7
|
|
|
—
|
|
|
40.0
|
|
||||
Total revenue from contracts with customers
|
|
4,326.3
|
|
|
559.8
|
|
|
30.8
|
|
|
4,916.9
|
|
||||
Alternative revenue and other
|
|
181.7
|
|
|
23.3
|
|
|
—
|
|
|
205.0
|
|
||||
Total revenues
|
|
$
|
4,508.0
|
|
|
$
|
583.1
|
|
|
$
|
30.8
|
|
|
$
|
5,121.9
|
|
•
|
Corporate federal tax rate reduction from
35%
to
21%
;
|
•
|
Normalization of resulting plant-related excess deferred taxes;
|
•
|
Elimination of the corporate alternative minimum tax;
|
•
|
Continued interest expense deductibility and discontinued bonus depreciation for regulated public utilities;
|
•
|
Limitations on certain executive compensation deductions;
|
•
|
Limitations on certain deductions for NOLs arising after Dec. 31, 2017 (limited to
80%
of taxable income);
|
•
|
Repeal of the section 199 manufacturing deduction; and,
|
•
|
Reduced deductions for meals and entertainment as well as state and local lobbying.
|
•
|
$1.1 billion
(
$1.5 billion
grossed-up for tax) of reclassifications of plant-related excess deferred taxes to regulatory liabilities upon valuation at the new
21%
federal rate. The regulatory liabilities will be amortized consistent with IRS normalization requirements, resulting in customer refunds over the average remaining life of the related property;
|
•
|
$133 million
and
$56 million
of reclassifications (grossed-up for tax) of excess deferred taxes for non-plant related deferred tax assets and liabilities, respectively, to regulatory assets and liabilities; and
|
•
|
$19 million
of total estimated income tax expense related to the federal tax reform implementation, and a
$5 million
reduction to net income related to the allocation of Xcel Energy Services Inc.’s tax rate change on its deferred taxes.
|
Tax Year(s)
|
|
Expiration
|
2009 - 2014
|
|
October 2019
|
2015
|
|
September 2019
|
2016
|
|
September 2020
|
2017
|
|
September 2021
|
(Millions of Dollars)
|
|
Dec. 31, 2018
|
|
Dec. 31, 2017
|
||||
Unrecognized tax benefit — Permanent tax positions
|
|
$
|
11.6
|
|
|
$
|
10.2
|
|
Unrecognized tax benefit — Temporary tax positions
|
|
5.3
|
|
|
7.9
|
|
||
Total unrecognized tax benefit
|
|
$
|
16.9
|
|
|
$
|
18.1
|
|
(Millions of Dollars)
|
|
2018
|
|
2017
|
|
2016
|
||||||
Balance at Jan. 1
|
|
$
|
18.1
|
|
|
$
|
60.8
|
|
|
$
|
55.4
|
|
Additions based on tax positions related to the current year
|
|
2.0
|
|
|
2.7
|
|
|
3.7
|
|
|||
Reductions based on tax positions related to the current year
|
|
(0.3
|
)
|
|
(1.7
|
)
|
|
(0.2
|
)
|
|||
Additions for tax positions of prior years
|
|
0.6
|
|
|
5.7
|
|
|
3.9
|
|
|||
Reductions for tax positions of prior years
|
|
(1.1
|
)
|
|
(49.4
|
)
|
|
(2.0
|
)
|
|||
Settlements with taxing authorities
|
|
(2.4
|
)
|
|
—
|
|
|
—
|
|
|||
Balance at Dec. 31
|
|
$
|
16.9
|
|
|
$
|
18.1
|
|
|
$
|
60.8
|
|
(Millions of Dollars)
|
|
Dec. 31, 2018
|
|
Dec. 31, 2017
|
||||
NOL and tax credit carryforwards
|
|
$
|
(12.7
|
)
|
|
$
|
(12.8
|
)
|
(Millions of Dollars)
|
|
2018
|
|
2017
|
|
2016
|
||||||
Payable for interest related to unrecognized tax benefits at Jan. 1
|
|
$
|
(0.9
|
)
|
|
$
|
(2.0
|
)
|
|
$
|
(0.2
|
)
|
Interest (expense) income related to unrecognized tax benefits
|
|
(0.3
|
)
|
|
1.1
|
|
|
(1.8
|
)
|
|||
Payable for interest related to unrecognized tax benefits at Dec. 31
|
|
$
|
(1.2
|
)
|
|
$
|
(0.9
|
)
|
|
$
|
(2.0
|
)
|
(Millions of Dollars)
|
|
2018
|
|
2017
|
||||
Federal NOL carryforward
|
|
$
|
—
|
|
|
$
|
631.6
|
|
Federal tax credit carryforwards
|
|
379.4
|
|
|
301.6
|
|
||
State NOL carryforwards
|
|
221.2
|
|
|
275.5
|
|
||
Valuation allowances for state NOL carryforwards
|
|
(0.8
|
)
|
|
(0.9
|
)
|
||
State tax credit carryforwards, net of federal detriment
(a)
|
|
87.9
|
|
|
90.7
|
|
||
Valuation allowances for state credit carryforwards, net of federal benefit
(b)
|
|
(78.5
|
)
|
|
(82.2
|
)
|
(a)
|
State tax credit carryforwards are net of federal detriment of
$23.4 million
and
$24.1 million
as of Dec. 31, 2018 and 2017, respectively.
|
(b)
|
Valuation allowances for state tax credit carryforwards were net of federal benefit of
$20.9 million
and
$21.8 million
as of Dec. 31, 2018 and 2017, respectively.
|
|
2018
|
|
2017
(a)
|
|
2016
(a)
|
|||
Federal statutory rate
|
21.0
|
%
|
|
35.0
|
%
|
|
35.0
|
%
|
State income tax on pretax income, net of federal tax effect
|
7.1
|
|
|
5.8
|
|
|
5.8
|
|
Increases (decreases) in tax from:
|
|
|
|
|
|
|
|
|
Wind PTCs recognized
|
(13.6
|
)
|
|
(11.4
|
)
|
|
(8.2
|
)
|
Regulatory differences - ARAM
(b)
|
(9.1
|
)
|
|
(0.1
|
)
|
|
(0.1
|
)
|
Other tax credit recognized, net of federal income tax expense
|
(1.3
|
)
|
|
(1.0
|
)
|
|
(0.8
|
)
|
Regulatory differences - other utility plant items
|
0.3
|
|
|
(0.2
|
)
|
|
(0.2
|
)
|
Change in unrecognized tax benefits
|
0.1
|
|
|
(1.6
|
)
|
|
0.2
|
|
Tax reform
|
—
|
|
|
2.7
|
|
|
—
|
|
Other, net
|
0.7
|
|
|
(0.2
|
)
|
|
(0.2
|
)
|
Effective income tax rate
|
5.2
|
%
|
|
29.0
|
%
|
|
31.5
|
%
|
(a)
|
Prior periods have been reclassified to conform to current year presentation.
|
(b)
|
ARAM is a method to flow back excess deferred taxes to customers.
|
(Millions of Dollars)
|
|
2018
|
|
2017
|
|
2016
|
||||||
Current federal tax (benefit) expense
|
|
$
|
(16.8
|
)
|
|
$
|
29.6
|
|
|
$
|
19.3
|
|
Current state tax expense
|
|
5.2
|
|
|
14.7
|
|
|
9.4
|
|
|||
Current change in unrecognized tax (benefit) expense
|
|
(1.1
|
)
|
|
(36.2
|
)
|
|
1.3
|
|
|||
Deferred federal tax (benefit) expense
|
|
(2.4
|
)
|
|
121.6
|
|
|
142.3
|
|
|||
Deferred state tax expense
|
|
42.1
|
|
|
46.7
|
|
|
53.8
|
|
|||
Deferred change in unrecognized tax expense
|
|
1.6
|
|
|
24.9
|
|
|
0.1
|
|
|||
Deferred ITCs
|
|
(1.4
|
)
|
|
(1.6
|
)
|
|
(1.7
|
)
|
|||
Total income tax expense
|
|
$
|
27.2
|
|
|
$
|
199.7
|
|
|
$
|
224.5
|
|
(Millions of Dollars)
|
|
2018
|
|
2017
|
|
2016
|
||||||
Deferred tax expense (benefit) excluding items below
|
|
$
|
70.1
|
|
|
$
|
(1,176.4
|
)
|
|
$
|
225.1
|
|
Amortization and adjustments to deferred income taxes on income tax regulatory assets and liabilities
|
|
(28.2
|
)
|
|
1,369.9
|
|
|
(28.7
|
)
|
|||
Tax expense allocated to other comprehensive income, net of adoption of ASU No. 2018-02, and other
|
|
(0.6
|
)
|
|
(0.3
|
)
|
|
(0.2
|
)
|
|||
Deferred tax expense
|
|
$
|
41.3
|
|
|
$
|
193.2
|
|
|
$
|
196.2
|
|
(Millions of Dollars)
|
|
2018
|
|
2017
|
||||
Deferred tax liabilities:
|
|
|
|
|
||||
Differences between book and tax bases of property
|
|
$
|
2,257.6
|
|
|
$
|
2,253.2
|
|
Regulatory assets
|
|
263.1
|
|
|
222.7
|
|
||
Pension expense
|
|
64.7
|
|
|
54.2
|
|
||
Other
|
|
11.3
|
|
|
16.4
|
|
||
Total deferred tax liabilities
|
|
$
|
2,596.7
|
|
|
$
|
2,546.5
|
|
|
|
|
|
|
||||
Deferred tax assets:
|
|
|
|
|
||||
Regulatory liabilities
|
|
$
|
382.8
|
|
|
$
|
386.6
|
|
Tax credit carryforward
|
|
467.3
|
|
|
392.4
|
|
||
NOL carryforward
|
|
17.9
|
|
|
153.5
|
|
||
NOL and tax credit valuation allowance
|
|
(78.6
|
)
|
|
(82.2
|
)
|
||
Other employee benefits
|
|
38.6
|
|
|
37.3
|
|
||
Deferred ITCs
|
|
6.4
|
|
|
6.8
|
|
||
Rate refund
|
|
49.7
|
|
|
6.6
|
|
||
Other
|
|
30.2
|
|
|
33.2
|
|
||
Total deferred tax assets
|
|
$
|
914.3
|
|
|
$
|
934.2
|
|
Net deferred tax liability
|
|
$
|
1,682.4
|
|
|
$
|
1,612.3
|
|
8.
|
Fair Value of Financial Assets and Liabilities
|
•
|
Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. The types of assets and liabilities included in Level 1 are highly liquid and actively traded instruments with quoted prices.
|
•
|
Level 2 — Pricing inputs are other than quoted prices in active markets, but are either directly or indirectly observable as of the reporting date. The types of assets and liabilities included in Level 2 are typically either comparable to actively traded securities or contracts, or priced with models using highly observable inputs.
|
•
|
Level 3 — Significant inputs to pricing have little or no observability as of the reporting date. The types of assets and liabilities included in Level 3 are those valued with models requiring significant management judgment or estimation.
|
|
|
Dec. 31, 2018
|
||||||||||||||||||||||
|
|
|
|
Fair Value
|
||||||||||||||||||||
(Millions of Dollars)
|
|
Cost
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
NAV
|
|
Total
|
||||||||||||
Nuclear decommissioning fund
(a)
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Cash equivalents
|
|
$
|
24.3
|
|
|
$
|
24.3
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
24.3
|
|
Commingled funds
|
|
758.1
|
|
|
79.2
|
|
|
—
|
|
|
—
|
|
|
819.1
|
|
|
$
|
898.3
|
|
|||||
Debt securities
|
|
465.6
|
|
|
—
|
|
|
435.6
|
|
|
—
|
|
|
—
|
|
|
$
|
435.6
|
|
|||||
Equity securities
|
|
401.4
|
|
|
696.5
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
$
|
696.5
|
|
|||||
Total
|
|
$
|
1,649.4
|
|
|
$
|
800.0
|
|
|
$
|
435.6
|
|
|
$
|
—
|
|
|
$
|
819.1
|
|
|
$
|
2,054.7
|
|
(a)
|
Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes
$52.5 million
of rabbi trust assets and miscellaneous investments.
|
|
|
Dec. 31, 2017
|
||||||||||||||||||||||
|
|
|
|
Fair Value
|
||||||||||||||||||||
(Millions of Dollars)
|
|
Cost
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
NAV
|
|
Total
|
||||||||||||
Nuclear decommissioning fund
(a)
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Cash equivalents
|
|
$
|
28.7
|
|
|
$
|
28.7
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
28.7
|
|
Commingled funds
|
|
701.3
|
|
|
222.8
|
|
|
—
|
|
|
—
|
|
|
659.1
|
|
|
$
|
881.9
|
|
|||||
Debt securities
|
|
437.7
|
|
|
—
|
|
|
441.6
|
|
|
—
|
|
|
—
|
|
|
$
|
441.6
|
|
|||||
Equity securities
|
|
423.1
|
|
|
791.1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
$
|
791.1
|
|
|||||
Total
|
|
$
|
1,590.8
|
|
|
$
|
1,042.6
|
|
|
$
|
441.6
|
|
|
$
|
—
|
|
|
$
|
659.1
|
|
|
$
|
2,143.3
|
|
(a)
|
Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes
$49.1 million
of rabbi trust assets and miscellaneous investments.
|
|
|
Final Contractual Maturity
|
||||||||||||||||||
(Millions 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
|
||||||||||
Debt securities
|
|
$
|
10.6
|
|
|
$
|
106.9
|
|
|
$
|
210.5
|
|
|
$
|
107.6
|
|
|
$
|
435.6
|
|
|
|
Dec. 31, 2018
|
||||||||||||||||||
|
|
|
|
Fair Value
|
||||||||||||||||
(Millions of Dollars)
|
|
Cost
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
||||||||||
Rabbi Trusts
(a)
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Cash equivalents
|
|
$
|
0.4
|
|
|
$
|
0.4
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
0.4
|
|
Mutual funds
|
|
10.8
|
|
|
10.7
|
|
|
—
|
|
|
—
|
|
|
10.7
|
|
|||||
Total
|
|
$
|
11.2
|
|
|
$
|
11.1
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
11.1
|
|
|
|
Dec. 31, 2017
|
||||||||||||||||||
|
|
|
|
Fair Value
|
||||||||||||||||
(Millions of Dollars)
|
|
Cost
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Total
|
||||||||||
Rabbi Trusts
(a)
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Cash equivalents
|
|
$
|
0.8
|
|
|
$
|
0.8
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
0.8
|
|
Mutual funds
|
|
10.3
|
|
|
11.3
|
|
|
—
|
|
|
—
|
|
|
$
|
11.3
|
|
||||
Total
|
|
$
|
11.1
|
|
|
$
|
12.1
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
12.1
|
|
(a)
|
Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet.
|
(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.
|
(Millions of Dollars)
|
|
2018
|
|
2017
|
|
2016
|
||||||
Accumulated other comprehensive loss related to cash flow hedges at Jan. 1
|
|
$
|
(20.9
|
)
|
|
$
|
(18.2
|
)
|
|
$
|
(19.1
|
)
|
After-tax net unrealized gains related to derivatives accounted for as hedges
|
|
—
|
|
|
0.1
|
|
|
—
|
|
|||
After-tax net realized losses on derivative transactions reclassified into earnings
|
|
0.7
|
|
|
0.9
|
|
|
0.9
|
|
|||
Adoption of ASU. 2018-02
(a)
|
|
—
|
|
|
(3.7
|
)
|
|
—
|
|
|||
Accumulated other comprehensive loss related to cash flow hedges at Dec. 31
|
|
$
|
(20.2
|
)
|
|
$
|
(20.9
|
)
|
|
$
|
(18.2
|
)
|
(a)
|
In 2017, NSP-Minnesota implemented ASU No. 2018-02 related to TCJA, which resulted in reclassification of certain credit balances within net accumulated other comprehensive loss to retained earnings.
|
|
|
Pre-Tax Fair Value
Gains (Losses) Recognized During the Period in: |
||||||
(Millions of Dollars)
|
|
Accumulated Other Comprehensive Loss
|
|
Regulatory (Assets) and Liabilities
|
||||
Year Ended Dec. 31, 2018
|
|
|
|
|
||||
Other derivative instruments
|
|
|
|
|
||||
Electric commodity
|
|
$
|
—
|
|
|
$
|
(5.5
|
)
|
Natural gas commodity
|
|
—
|
|
|
1.8
|
|
||
Total
|
|
$
|
—
|
|
|
$
|
(3.7
|
)
|
|
|
|
|
|
||||
Year Ended Dec. 31, 2017
|
|
|
|
|
||||
Derivatives designated as cash flow hedges
|
|
|
|
|
||||
Vehicle fuel and other commodity
|
|
$
|
0.1
|
|
|
$
|
—
|
|
Total
|
|
$
|
0.1
|
|
|
$
|
—
|
|
Other derivative instruments
|
|
|
|
|
||||
Electric commodity
|
|
$
|
—
|
|
|
$
|
9.3
|
|
Natural gas commodity
|
|
—
|
|
|
(1.9
|
)
|
||
Total
|
|
$
|
—
|
|
|
$
|
7.4
|
|
|
|
|
|
|
||||
Year Ended Dec. 31, 2016
|
|
|
|
|
||||
Other derivative instruments
|
|
|
|
|
||||
Electric commodity
|
|
—
|
|
|
14.4
|
|
||
Natural gas commodity
|
|
—
|
|
|
(1.2
|
)
|
||
Total
|
|
$
|
—
|
|
|
$
|
13.2
|
|
|
Pre-Tax (Gains) Losses
Reclassified into Income During the Period from: |
|
Pre-Tax Gains (Losses)
Recognized During the Period in Income |
|
||||||||
(Millions of Dollars)
|
Accumulated Other Comprehensive Loss
|
|
Regulatory
Assets and (Liabilities) |
|
|
|||||||
Year Ended Dec. 31, 2018
|
|
|
|
|
|
|
||||||
Derivatives designated as cash flow hedges
|
|
|
|
|
|
|
||||||
Interest rate
|
$
|
1.1
|
|
(a)
|
$
|
—
|
|
|
$
|
—
|
|
|
Vehicle fuel and other commodity
|
(0.1
|
)
|
(b)
|
—
|
|
|
—
|
|
|
|||
Total
|
$
|
1.0
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
Other derivative instruments
|
|
|
|
|
|
|
||||||
Commodity trading
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
10.9
|
|
(c)
|
Electric commodity
|
—
|
|
|
3.3
|
|
(d)
|
—
|
|
|
|||
Natural gas commodity
|
—
|
|
|
(1.9
|
)
|
(e)
|
(1.3
|
)
|
(e)
|
|||
Total
|
$
|
—
|
|
|
$
|
1.4
|
|
|
$
|
9.6
|
|
|
|
|
|
|
|
|
|
||||||
Year Ended Dec. 31, 2017
|
|
|
|
|
|
|
||||||
Derivatives designated as cash flow hedges
|
|
|
|
|
|
|
||||||
Interest rate
|
$
|
1.5
|
|
(a)
|
$
|
—
|
|
|
$
|
—
|
|
|
Total
|
$
|
1.5
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
Other derivative instruments
|
|
|
|
|
|
|
||||||
Commodity trading
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
9.4
|
|
(c)
|
Electric commodity
|
—
|
|
|
(13.8
|
)
|
(d)
|
—
|
|
|
|||
Natural gas commodity
|
—
|
|
|
1.0
|
|
(e)
|
(1.2
|
)
|
(e)
|
|||
Total
|
$
|
—
|
|
|
$
|
(12.8
|
)
|
|
$
|
8.2
|
|
|
|
|
|
|
|
|
|
||||||
Year Ended Dec. 31, 2016
|
|
|
|
|
|
|
||||||
Derivatives designated as cash flow hedges
|
|
|
|
|
|
|
||||||
Interest rate
|
$
|
1.4
|
|
(a)
|
$
|
—
|
|
|
$
|
—
|
|
|
Vehicle fuel and other commodity
|
0.1
|
|
(b)
|
—
|
|
|
—
|
|
|
|||
Total
|
$
|
1.5
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
Other derivative instruments
|
|
|
|
|
|
|
||||||
Commodity trading
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
2.8
|
|
(c)
|
Electric commodity
|
—
|
|
|
(6.1
|
)
|
(d)
|
—
|
|
|
|||
Natural gas commodity
|
—
|
|
|
4.0
|
|
(e)
|
(2.2
|
)
|
(e)
|
|||
Total
|
$
|
—
|
|
|
$
|
(2.1
|
)
|
|
$
|
0.6
|
|
|
(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 are recorded to cost of natural gas sold and transported. These derivative settlement gains and losses are shared with natural gas customers through purchased natural gas cost-recovery mechanisms, and reclassified out of income as regulatory assets and liabilities, as appropriate.
|
|
|
Dec. 31, 2018
|
|
Dec. 31, 2017
|
||||||||||||||||||||||||||||||||||||||||||||
|
|
Fair Value
|
|
Fair Value
Total |
|
Netting
(a)
|
|
|
|
Fair Value
|
|
Fair Value
Total |
|
Netting
(a)
|
|
|
||||||||||||||||||||||||||||||||
(Millions of Dollars)
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
|
|
Total
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
|
|
Total
|
||||||||||||||||||||||||||||
Current derivative assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||||||||||
Derivatives designated as cash flow hedges:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||||||||||
Vehicle fuel and other commodity
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
0.1
|
|
|
$
|
—
|
|
|
$
|
0.1
|
|
|
$
|
—
|
|
|
$
|
0.1
|
|
Other derivative instruments:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||||||||||
Commodity trading
|
|
1.1
|
|
|
27.1
|
|
|
2.2
|
|
|
30.4
|
|
|
(16.0
|
)
|
|
14.4
|
|
|
1.7
|
|
|
17.1
|
|
|
0.1
|
|
|
18.9
|
|
|
(11.7
|
)
|
|
7.2
|
|
||||||||||||
Electric commodity
|
|
—
|
|
|
—
|
|
|
10.5
|
|
|
10.5
|
|
|
(0.1
|
)
|
|
10.4
|
|
|
—
|
|
|
—
|
|
|
17.6
|
|
|
17.6
|
|
|
(0.4
|
)
|
|
17.2
|
|
||||||||||||
Natural gas commodity
|
|
—
|
|
|
1.0
|
|
|
—
|
|
|
1.0
|
|
|
—
|
|
|
1.0
|
|
|
—
|
|
|
0.1
|
|
|
—
|
|
|
0.1
|
|
|
—
|
|
|
0.1
|
|
||||||||||||
Total current derivative assets
|
|
$
|
1.1
|
|
|
$
|
28.1
|
|
|
$
|
12.7
|
|
|
$
|
41.9
|
|
|
$
|
(16.1
|
)
|
|
25.8
|
|
|
$
|
1.7
|
|
|
$
|
17.3
|
|
|
$
|
17.7
|
|
|
$
|
36.7
|
|
|
$
|
(12.1
|
)
|
|
24.6
|
|
||
PPAs
(b)
|
|
|
|
|
|
|
|
|
|
|
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
0.6
|
|
||||||||||||||||||||||
Current derivative instruments
|
|
|
|
|
|
|
|
|
|
|
|
$
|
25.8
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
25.2
|
|
||||||||||||||||||||
Noncurrent derivative assets
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||||||||||
Other derivative instruments:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||||||||||
Commodity trading
|
|
$
|
—
|
|
|
$
|
25.3
|
|
|
$
|
5.0
|
|
|
$
|
30.3
|
|
|
$
|
(13.4
|
)
|
|
$
|
16.9
|
|
|
$
|
—
|
|
|
$
|
29.1
|
|
|
$
|
5.4
|
|
|
$
|
34.5
|
|
|
$
|
(6.5
|
)
|
|
$
|
28.0
|
|
Total noncurrent derivative assets
|
|
$
|
—
|
|
|
$
|
25.3
|
|
|
$
|
5.0
|
|
|
$
|
30.3
|
|
|
$
|
(13.4
|
)
|
|
16.9
|
|
|
$
|
—
|
|
|
$
|
29.1
|
|
|
$
|
5.4
|
|
|
$
|
34.5
|
|
|
$
|
(6.5
|
)
|
|
28.0
|
|
||
PPAs
(b)
|
|
|
|
|
|
|
|
|
|
|
|
0.1
|
|
|
|
|
|
|
|
|
|
|
|
|
0.1
|
|
||||||||||||||||||||||
Noncurrent derivative instruments
|
|
|
|
|
|
|
|
|
|
|
|
$
|
17.0
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
28.1
|
|
|
|
Dec. 31, 2018
|
|
Dec. 31, 2017
|
||||||||||||||||||||||||||||||||||||||||||||
|
|
Fair Value
|
|
Fair Value
Total |
|
Netting
(a)
|
|
|
|
Fair Value
|
|
Fair Value
Total |
|
Netting
(a)
|
|
|
||||||||||||||||||||||||||||||||
(Millions of Dollars)
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
|
|
Total
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
|
|
Total
|
||||||||||||||||||||||||||||
Current derivative liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||||||||||
Other derivative instruments:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||||||||||
Commodity trading
|
|
$
|
1.4
|
|
|
$
|
23.9
|
|
|
$
|
1.7
|
|
|
$
|
27.0
|
|
|
$
|
(24.5
|
)
|
|
$
|
2.5
|
|
|
$
|
1.7
|
|
|
$
|
13.9
|
|
|
$
|
—
|
|
|
$
|
15.6
|
|
|
$
|
(12.0
|
)
|
|
$
|
3.6
|
|
Electric commodity
|
|
—
|
|
|
—
|
|
|
0.1
|
|
|
0.1
|
|
|
(0.1
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
0.4
|
|
|
0.4
|
|
|
(0.4
|
)
|
|
—
|
|
||||||||||||
Total current derivative liabilities
|
|
$
|
1.4
|
|
|
$
|
23.9
|
|
|
$
|
1.8
|
|
|
$
|
27.1
|
|
|
$
|
(24.6
|
)
|
|
2.5
|
|
|
$
|
1.7
|
|
|
$
|
13.9
|
|
|
$
|
0.4
|
|
|
$
|
16.0
|
|
|
$
|
(12.4
|
)
|
|
3.6
|
|
||
PPAs
(b)
|
|
|
|
|
|
|
|
|
|
|
|
14.0
|
|
|
|
|
|
|
|
|
|
|
|
|
14.1
|
|
||||||||||||||||||||||
Current derivative instruments
|
|
|
|
|
|
|
|
|
|
|
|
$
|
16.5
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
17.7
|
|
||||||||||||||||||||
Noncurrent derivative liabilities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||||||||||
Other derivative instruments:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||||||||||||||
Commodity trading
|
|
$
|
0.1
|
|
|
$
|
16.0
|
|
|
$
|
1.6
|
|
|
$
|
17.7
|
|
|
$
|
17.9
|
|
|
$
|
35.6
|
|
|
$
|
—
|
|
|
$
|
22.2
|
|
|
$
|
—
|
|
|
$
|
22.2
|
|
|
$
|
(9.4
|
)
|
|
$
|
12.8
|
|
Total noncurrent derivative liabilities
|
|
$
|
0.1
|
|
|
$
|
16.0
|
|
|
$
|
1.6
|
|
|
$
|
17.7
|
|
|
$
|
17.9
|
|
|
35.6
|
|
|
$
|
—
|
|
|
$
|
22.2
|
|
|
$
|
—
|
|
|
$
|
22.2
|
|
|
$
|
(9.4
|
)
|
|
12.8
|
|
||
PPAs
(b)
|
|
|
|
|
|
|
|
|
|
|
|
76.6
|
|
|
|
|
|
|
|
|
|
|
|
|
89.9
|
|
||||||||||||||||||||||
Noncurrent derivative instruments
|
|
|
|
|
|
|
|
|
|
|
|
$
|
112.2
|
|
|
|
|
|
|
|
|
|
|
|
|
$
|
102.7
|
|
(a)
|
NSP-Minnesota 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, 2018
and 2017. At
Dec. 31, 2018
and 2017, derivative assets and liabilities include
$31.5 million
and
$0 million
of obligations to return cash collateral, respectively. At Dec. 31, 2018 and 2017, derivative assets and liabilities include the rights to reclaim cash collateral of
$8.7 million
and
$3.1 million
, respectively. The counterparty netting excludes settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.
|
(b)
|
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.
|
|
|
Year Ended Dec. 31
|
||||||||||
(Millions of Dollars)
|
|
2018
|
|
2017
|
|
2016
|
||||||
Balance at Jan. 1
|
|
$
|
22.6
|
|
|
$
|
15.3
|
|
|
$
|
13.0
|
|
Purchases
|
|
26.4
|
|
|
40.6
|
|
|
28.0
|
|
|||
Settlements
|
|
(17.2
|
)
|
|
(41.7
|
)
|
|
(47.2
|
)
|
|||
Net transactions recorded during the period:
|
|
|
|
|
|
|
||||||
(Losses) gains recognized in earnings
(a)
|
|
(1.5
|
)
|
|
5.5
|
|
|
—
|
|
|||
Net (losses) gains recognized as regulatory assets and liabilities
|
|
(16.0
|
)
|
|
2.9
|
|
|
21.5
|
|
|||
Balance at Dec. 31
|
|
$
|
14.3
|
|
|
$
|
22.6
|
|
|
$
|
15.3
|
|
(a)
|
Amounts relate to commodity derivatives held at the end of the period.
|
|
|
2018
|
|
2017
|
||||||||||||
(Millions of Dollars)
|
|
Carrying
Amount |
|
Fair Value
|
|
Carrying
Amount |
|
Fair Value
|
||||||||
Long-term debt, including current portion
|
|
$
|
4,937.2
|
|
|
$
|
5,230.9
|
|
|
$
|
4,933.0
|
|
|
$
|
5,601.9
|
|
•
|
NSP-Minnesota discontinued subsidizing health care benefits for non-bargaining employees retiring after 1998 and for bargaining employees who retired after 1999.
|
•
|
Investment returns in 2018 were below the assumed level of
7.10%
;
|
•
|
Investment returns in 2017 were above the assumed level of
7.10%
;
|
•
|
Investment returns in 2016 were below the assumed level of
7.10%
; and
|
•
|
In 2019, NSP-Minnesota’s expected investment-return assumption is
7.10%
.
|
|
|
Dec. 31, 2018
(a)
|
|
Dec. 31, 2017
(a)
|
||||||||||||||||||||||||||||||||||||
(Millions of Dollars)
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Measured at NAV
|
|
Total
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Measured at NAV
|
|
Total
|
||||||||||||||||||||
Cash equivalents
|
|
$
|
31.8
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
31.8
|
|
|
$
|
53.4
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
53.4
|
|
Commingled funds:
|
|
241.0
|
|
|
—
|
|
|
—
|
|
|
271.2
|
|
|
512.2
|
|
|
285.2
|
|
|
—
|
|
|
—
|
|
|
302.4
|
|
|
587.6
|
|
||||||||||
Debt securities:
|
|
—
|
|
|
143.7
|
|
|
—
|
|
|
—
|
|
|
143.7
|
|
|
—
|
|
|
159.0
|
|
|
—
|
|
|
—
|
|
|
159.0
|
|
||||||||||
Equity securities:
|
|
29.3
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
29.3
|
|
|
32.1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
32.1
|
|
||||||||||
Other
|
|
0.5
|
|
|
1.3
|
|
|
—
|
|
|
(8.2
|
)
|
|
(6.4
|
)
|
|
(8.7
|
)
|
|
1.0
|
|
|
—
|
|
|
0.1
|
|
|
$
|
(7.6
|
)
|
|||||||||
Total
|
|
$
|
302.6
|
|
|
$
|
145.0
|
|
|
$
|
—
|
|
|
$
|
263.0
|
|
|
$
|
710.6
|
|
|
$
|
362.0
|
|
|
$
|
160.0
|
|
|
$
|
—
|
|
|
$
|
302.5
|
|
|
$
|
824.5
|
|
(a)
|
See Note 8 for further information on fair value measurement inputs and methods.
|
|
|
Dec. 31, 2018
(a)
|
|
Dec. 31, 2017
(a)
|
||||||||||||||||||||||||||||||||||||
(Millions of Dollars)
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Measured at NAV
|
|
Total
|
|
Level 1
|
|
Level 2
|
|
Level 3
|
|
Measured at NAV
|
|
Total
|
||||||||||||||||||||
Cash equivalents
|
|
$
|
0.1
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
0.1
|
|
|
$
|
0.4
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
0.4
|
|
Insurance contracts
|
|
—
|
|
|
0.3
|
|
|
—
|
|
|
—
|
|
|
0.3
|
|
|
—
|
|
|
0.7
|
|
|
—
|
|
|
—
|
|
|
0.7
|
|
||||||||||
Commingled funds
|
|
0.8
|
|
|
—
|
|
|
—
|
|
|
0.2
|
|
|
1.0
|
|
|
2.1
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2.1
|
|
||||||||||
Debt securities
|
|
—
|
|
|
1.0
|
|
|
—
|
|
|
—
|
|
|
1.0
|
|
|
—
|
|
|
2.8
|
|
|
—
|
|
|
—
|
|
|
2.8
|
|
||||||||||
Equity securities
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
0.5
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
0.5
|
|
||||||||||
Total
|
|
$
|
0.9
|
|
|
$
|
1.3
|
|
|
$
|
—
|
|
|
$
|
0.2
|
|
|
$
|
2.4
|
|
|
$
|
3.0
|
|
|
$
|
3.5
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
6.5
|
|
(a)
|
See Note 8 for further information on fair value measurement inputs and methods.
|
|
|
Pension Benefits
|
|
Postretirement Benefits
|
||||||||||||
(Millions of Dollars)
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||
Change in Benefit Obligation:
|
|
|
|
|
|
|
|
|
||||||||
Obligation at Jan. 1
|
|
$
|
1,035.1
|
|
|
$
|
1,036.5
|
|
|
$
|
88.8
|
|
|
$
|
86.7
|
|
Service cost
|
|
28.0
|
|
|
27.8
|
|
|
0.2
|
|
|
0.1
|
|
||||
Interest cost
|
|
35.2
|
|
|
40.7
|
|
|
3.1
|
|
|
3.4
|
|
||||
Plan amendments
|
|
—
|
|
|
(4.4
|
)
|
|
—
|
|
|
—
|
|
||||
Actuarial (gain) loss
|
|
(50.8
|
)
|
|
64.1
|
|
|
(9.0
|
)
|
|
5.9
|
|
||||
Plan participants’ contributions
|
|
—
|
|
|
—
|
|
|
0.4
|
|
|
0.4
|
|
||||
Benefit payments
(a)
|
|
(140.5
|
)
|
|
(129.6
|
)
|
|
(7.5
|
)
|
|
(7.7
|
)
|
||||
Obligation at Dec. 31
|
|
$
|
907.0
|
|
|
$
|
1,035.1
|
|
|
$
|
76.0
|
|
|
$
|
88.8
|
|
Change in Fair Value of Plan Assets:
|
|
|
|
|
|
|
|
|
||||||||
Fair value of plan assets at Jan. 1
|
|
$
|
824.5
|
|
|
$
|
783.2
|
|
|
$
|
6.5
|
|
|
$
|
3.7
|
|
Actual return on plan assets
|
|
(36.5
|
)
|
|
110.1
|
|
|
—
|
|
|
—
|
|
||||
Employer contributions
|
|
63.1
|
|
|
60.7
|
|
|
3.0
|
|
|
10.1
|
|
||||
Plan participants’ contributions
|
|
—
|
|
|
—
|
|
|
0.4
|
|
|
0.4
|
|
||||
Benefit payments
|
|
(140.5
|
)
|
|
(129.5
|
)
|
|
(7.5
|
)
|
|
(7.7
|
)
|
||||
Fair value of plan assets at Dec. 31
|
|
$
|
710.6
|
|
|
$
|
824.5
|
|
|
$
|
2.4
|
|
|
$
|
6.5
|
|
Funded status of plans at Dec. 31
|
|
$
|
(196.4
|
)
|
|
$
|
(210.6
|
)
|
|
$
|
(73.6
|
)
|
|
$
|
(82.3
|
)
|
Amounts recognized in the Consolidated Balance Sheet at Dec. 31:
|
|
|
|
|
|
|
|
|
||||||||
Current assets (liabilities)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(4.8
|
)
|
|
$
|
(1.3
|
)
|
Noncurrent assets (liabilities)
|
|
(196.4
|
)
|
|
(210.6
|
)
|
|
(68.8
|
)
|
|
(81.0
|
)
|
||||
Net amounts recognized
|
|
$
|
(196.4
|
)
|
|
$
|
(210.6
|
)
|
|
$
|
(73.6
|
)
|
|
$
|
(82.3
|
)
|
(a)
|
Includes approximately
$105 million
of lump-sum benefit payments used in the determination of a settlement charge.
|
Significant Assumptions Used to Measure Benefit Obligations:
|
|
|
|
|
|
|
|
|
||||
Discount rate for year-end valuation
|
|
4.31
|
%
|
|
3.63
|
%
|
|
4.32
|
%
|
|
3.62
|
%
|
Expected average long-term increase in compensation level
|
|
3.75
|
%
|
|
3.75
|
%
|
|
N/A
|
|
|
N/A
|
|
Mortality table
|
|
RP-2014
|
|
|
RP-2014
|
|
|
RP-2014
|
|
|
RP-2014
|
|
Health care costs trend rate
—
initial: Pre-65
|
|
N/A
|
|
|
N/A
|
|
|
6.50
|
%
|
|
7.00
|
%
|
Health care costs trend rate
—
initial: Post-65
|
|
N/A
|
|
|
N/A
|
|
|
5.30
|
%
|
|
5.50
|
%
|
Ultimate trend assumption
—
initial: Pre-65
|
|
N/A
|
|
|
N/A
|
|
|
4.50
|
%
|
|
4.50
|
%
|
Ultimate trend assumption
—
initial: Post-65
|
|
N/A
|
|
|
N/A
|
|
|
4.50
|
%
|
|
4.50
|
%
|
Years until ultimate trend is reached
|
|
N/A
|
|
|
N/A
|
|
|
4
|
|
|
5
|
|
|
|
Pension Benefits
|
|
Postretirement Benefits
|
||||||||||||||||||||
(Millions of Dollars)
|
|
2018
|
|
2017
|
|
2016
|
|
2018
|
|
2017
|
|
2016
|
||||||||||||
Service cost
|
|
$
|
28.0
|
|
|
$
|
27.8
|
|
|
$
|
28.3
|
|
|
$
|
0.2
|
|
|
$
|
0.1
|
|
|
$
|
0.1
|
|
Interest cost
|
|
35.2
|
|
|
40.7
|
|
|
45.4
|
|
|
3.1
|
|
|
3.4
|
|
|
3.9
|
|
||||||
Expected return on plan assets
|
|
(58.2
|
)
|
|
(60.1
|
)
|
|
(60.9
|
)
|
|
(0.4
|
)
|
|
(0.2
|
)
|
|
(0.2
|
)
|
||||||
Amortization of prior service cost
|
|
(0.1
|
)
|
|
1.1
|
|
|
0.9
|
|
|
(3.0
|
)
|
|
(3.0
|
)
|
|
(3.0
|
)
|
||||||
Amortization of net loss
|
|
38.5
|
|
|
39.6
|
|
|
36.8
|
|
|
2.4
|
|
|
2.0
|
|
|
1.6
|
|
||||||
Settlement charge
(a)
|
|
48.8
|
|
|
48.2
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Net periodic pension cost
|
|
92.2
|
|
|
97.3
|
|
|
50.5
|
|
|
2.3
|
|
|
2.3
|
|
|
2.4
|
|
||||||
Costs not recognized due to effects of regulation
|
|
(66.0
|
)
|
|
(72.2
|
)
|
|
(20.9
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Net benefit cost recognized for financial reporting
|
|
$
|
26.2
|
|
|
$
|
25.1
|
|
|
$
|
29.6
|
|
|
$
|
2.3
|
|
|
$
|
2.3
|
|
|
$
|
2.4
|
|
Significant Assumptions Used to Measure Costs:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||||||||||
Discount rate
|
|
3.63
|
%
|
|
4.13
|
%
|
|
4.66
|
%
|
|
3.62
|
%
|
|
4.13
|
%
|
|
4.65
|
%
|
||||||
Expected average long-term increase in compensation level
|
|
3.75
|
|
|
3.75
|
|
|
4.00
|
|
|
—
|
|
|
—
|
|
|
—
|
|
||||||
Expected average long-term rate of return on assets
|
|
7.10
|
|
|
7.10
|
|
|
7.10
|
|
|
5.30
|
|
|
5.80
|
|
|
5.80
|
|
(a)
|
A settlement charge is required when the amount of lump-sum distributions during the year is greater than the sum of the service and interest cost components of the annual net periodic pension cost. In 2018 and 2017, as a result of lump-sum distributions during the 2018 and 2017 plan years, NSP-Minnesota recorded a total pension settlement charge of
$48.8 million
in 2018 and
$48.2 million
in 2017, which was not recognized due to the effects of regulation.
|
|
|
Pension Benefits
|
|
Postretirement Benefits
|
||||||||||||
(Millions of Dollars)
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||||||
Amounts Not Yet Recognized as Components of Net Periodic Benefit Cost:
|
|
|
|
|
|
|
|
|
||||||||
Net loss
|
|
$
|
502.0
|
|
|
$
|
545.3
|
|
|
$
|
34.3
|
|
|
$
|
45.3
|
|
Prior service (credit) cost
|
|
(1.2
|
)
|
|
(1.3
|
)
|
|
(12.4
|
)
|
|
(15.4
|
)
|
||||
Total
|
|
$
|
500.8
|
|
|
$
|
544.0
|
|
|
$
|
21.9
|
|
|
$
|
29.9
|
|
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
|
|
$
|
35.5
|
|
|
$
|
37.7
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Noncurrent regulatory assets
|
|
465.3
|
|
|
506.3
|
|
|
20.5
|
|
|
28.0
|
|
||||
Deferred income taxes
|
|
—
|
|
|
—
|
|
|
0.4
|
|
|
0.5
|
|
||||
Net-of-tax accumulated other comprehensive income
|
|
—
|
|
|
—
|
|
|
1.0
|
|
|
1.4
|
|
||||
Total
|
|
$
|
500.8
|
|
|
$
|
544.0
|
|
|
$
|
21.9
|
|
|
$
|
29.9
|
|
|
|
|
|
|
|
|
|
|
||||||||
Measurement date
|
|
Dec. 31, 2018
|
|
|
Dec. 31, 2017
|
|
|
Dec. 31, 2018
|
|
|
Dec. 31, 2017
|
|
•
|
$150 million
in January 2019, of which
$47 million
is attributable to NSP-Minnesota;
|
•
|
$150 million
in 2018, of which
$63 million
was attributable to NSP-Minnesota;
|
•
|
$162 million
in 2017, of which
$61 million
was attributable to NSP-Minnesota; and,
|
•
|
$125 million
in 2016, of which
$49 million
was attributable to NSP-Minnesota.
|
•
|
$11 million
in January 2019, of which
$7 million
is attributable to NSP-Minnesota;
|
•
|
$11 million
in 2018, of which
$3 million
, was attributable to NSP-Minnesota;
|
•
|
$20 million
in 2017, of which
$10 million
was attributable to NSP-Minnesota; and,
|
•
|
$18 million
in 2016, of which
$9 million
was attributable to NSP-Minnesota.
|
|
|
Pension Benefits
|
|
Postretirement Benefits
|
||||||||
|
|
2018
|
|
2017
|
|
2018
|
|
2017
|
||||
Domestic and international equity securities
|
|
37
|
%
|
|
38
|
%
|
|
18
|
%
|
|
24
|
%
|
Long-duration fixed income and interest rate swap securities
|
|
28
|
|
|
23
|
|
|
—
|
|
|
—
|
|
Short-to-intermediate fixed income securities
|
|
18
|
|
|
21
|
|
|
70
|
|
|
60
|
|
Alternative investments
|
|
15
|
|
|
16
|
|
|
8
|
|
|
9
|
|
Cash
|
|
2
|
|
|
2
|
|
|
4
|
|
|
7
|
|
Total
|
|
100
|
%
|
|
100
|
%
|
|
100
|
%
|
|
100
|
%
|
(Millions 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
|
||||||||
2019
|
|
$
|
93.4
|
|
|
$
|
7.2
|
|
|
$
|
—
|
|
|
$
|
7.2
|
|
2020
|
|
81.2
|
|
|
7.0
|
|
|
—
|
|
|
7.0
|
|
||||
2021
|
|
80.1
|
|
|
6.7
|
|
|
—
|
|
|
6.7
|
|
||||
2022
|
|
79.0
|
|
|
6.3
|
|
|
—
|
|
|
6.3
|
|
||||
2023
|
|
77.2
|
|
|
6.0
|
|
|
—
|
|
|
6.0
|
|
||||
2024-2027
|
|
342.3
|
|
|
26.0
|
|
|
—
|
|
|
26.0
|
|
|
|
Dec. 31, 2018
|
||||||||||||||||||
(Millions of Dollars)
|
|
Jan. 1, 2018
|
|
Amounts Settled
(a)
|
|
Accretion
|
|
Cash Flow Revisions
(b)
|
|
Dec. 31, 2018
(c)
|
||||||||||
Electric
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Nuclear
|
|
$
|
1,873.6
|
|
|
$
|
—
|
|
|
$
|
94.7
|
|
|
$
|
—
|
|
|
$
|
1,968.3
|
|
Wind
|
|
94.1
|
|
|
—
|
|
|
4.3
|
|
|
6.5
|
|
|
104.9
|
|
|||||
Steam and other production
|
|
64.0
|
|
|
(6.6
|
)
|
|
2.1
|
|
|
(10.3
|
)
|
|
49.2
|
|
|||||
Distribution
|
|
5.8
|
|
|
—
|
|
|
0.2
|
|
|
8.5
|
|
|
14.5
|
|
|||||
Miscellaneous
|
|
1.9
|
|
|
—
|
|
|
—
|
|
|
(0.1
|
)
|
|
1.8
|
|
|||||
Natural gas
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Transmission and distribution
|
|
43.6
|
|
|
—
|
|
|
1.8
|
|
|
(7.2
|
)
|
|
38.2
|
|
|||||
Miscellaneous
|
|
0.2
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
0.2
|
|
|||||
Common
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Miscellaneous
|
|
0.7
|
|
|
—
|
|
|
0.1
|
|
|
—
|
|
|
0.8
|
|
|||||
Total liability
|
|
$
|
2,083.9
|
|
|
$
|
(6.6
|
)
|
|
$
|
103.2
|
|
|
$
|
(2.6
|
)
|
|
$
|
2,177.9
|
|
(a)
|
Amounts settled related to asbestos abatement projects and closure of certain ash containment facilities.
|
(b)
|
In 2018, AROs were revised for changes in timing and estimates of cash flows. Changes in gas transmission and distribution AROs were mainly related to increased gas line mileage and number of services, which were more than offset by increased discount rates. Changes in electric distribution AROs primarily related to increased labor costs.
|
(c)
|
There were
no
ARO amounts incurred in 2018.
|
|
|
Dec. 31, 2017
|
||||||||||||||||||
(Millions of Dollars)
|
|
Jan. 1, 2017
|
|
Amounts Settled
(a)
|
|
Accretion
|
|
Cash Flow Revisions
(b)
|
|
Dec. 31, 2017
(c)
|
||||||||||
Electric
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Nuclear
|
|
$
|
2,249.3
|
|
|
$
|
—
|
|
|
$
|
113.8
|
|
|
$
|
(489.5
|
)
|
|
$
|
1,873.6
|
|
Wind
|
|
90.1
|
|
|
—
|
|
|
4.0
|
|
|
—
|
|
|
94.1
|
|
|||||
Steam and other production
|
|
68.5
|
|
|
(4.9
|
)
|
|
2.4
|
|
|
(2.0
|
)
|
|
64.0
|
|
|||||
Distribution
|
|
5.6
|
|
|
—
|
|
|
0.2
|
|
|
—
|
|
|
5.8
|
|
|||||
Miscellaneous
|
|
1.8
|
|
|
—
|
|
|
0.1
|
|
|
—
|
|
|
1.9
|
|
|||||
Natural gas
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Transmission and distribution
|
|
35.8
|
|
|
—
|
|
|
1.5
|
|
|
6.3
|
|
|
43.6
|
|
|||||
Miscellaneous
|
|
0.2
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
0.2
|
|
|||||
Common
|
|
|
|
|
|
|
|
|
|
|
||||||||||
Miscellaneous
|
|
1.3
|
|
|
(0.6
|
)
|
|
—
|
|
|
—
|
|
|
0.7
|
|
|||||
Total liability
|
|
$
|
2,452.6
|
|
|
$
|
(5.5
|
)
|
|
$
|
122.0
|
|
|
$
|
(485.2
|
)
|
|
$
|
2,083.9
|
|
(a)
|
Amounts settled related to asbestos abatement projects and closure of certain ash containment facilities.
|
(b)
|
In 2017, AROs were revised for changes in timing and estimates of cash flows. Nuclear AROs decreased due to updated assumptions in the nuclear triennial filing.
|
(c)
|
There were
no
ARO amounts incurred in 2017.
|
|
|
Regulatory Basis
|
||||||
(Millions of Dollars)
|
|
2018
|
|
2017
|
||||
Estimated decommissioning cost obligation from most recently approved study (in 2014 dollars)
|
|
$
|
3,012.3
|
|
|
$
|
3,012.3
|
|
Effect of escalating costs
|
|
538.9
|
|
|
395.7
|
|
||
Estimated decommissioning cost obligation (in current dollars)
|
|
3,551.2
|
|
|
3,408.0
|
|
||
Effect of escalating costs to payment date
|
|
7,654.3
|
|
|
7,797.5
|
|
||
Estimated future decommissioning costs (undiscounted)
|
|
11,205.5
|
|
|
11,205.5
|
|
||
Effect of discounting obligation (using average risk-free interest rate of 3.33% and 2.80% for 2018 and 2017, respectively)
|
|
(6,911.5
|
)
|
|
(6,398.1
|
)
|
||
Discounted decommissioning cost obligation
|
|
$
|
4,294.0
|
|
|
$
|
4,807.4
|
|
Assets held in external decommissioning trust
|
|
$
|
2,054.7
|
|
|
$
|
2,143.3
|
|
Underfunding of external decommissioning fund compared to the discounted decommissioning obligation
|
|
2,239.3
|
|
|
2,664.1
|
|
(Millions of Dollars)
|
|
2018
|
|
2017
|
||||
Discounted decommissioning cost obligation - regulated basis
|
|
$
|
4,294.0
|
|
|
$
|
4,807.4
|
|
Differences in discount rate and market risk premium
|
|
(1,446.4
|
)
|
|
(1,402.8
|
)
|
||
O&M costs not included for GAAP
|
|
(879.3
|
)
|
|
(1,041.5
|
)
|
||
ARO differences between 2017 and 2014 cost studies
|
|
—
|
|
|
(489.5
|
)
|
||
Nuclear production decommissioning ARO - GAAP
|
|
$
|
1,968.3
|
|
|
$
|
1,873.6
|
|
(Millions of Dollars)
|
|
2018
|
|
2017
|
|
2016
|
||||||
Annual decommissioning recorded as depreciation expense:
(a) (b)
|
|
$
|
20.4
|
|
|
$
|
20.4
|
|
|
$
|
20.4
|
|
(a)
|
Decommissioning expense does not include depreciation of the capitalized nuclear asset retirement costs.
|
(b)
|
Decommissioning expenses in 2018, 2017 and 2016 include Minnesota’s retail jurisdiction annual funding requirement of approximately
$14.0
million.
|
(Millions of Dollars)
|
|
2018
|
|
2017
|
|
2016
|
||||||
Total expense
|
|
$
|
76.2
|
|
|
$
|
76.9
|
|
|
$
|
79.1
|
|
Capacity payments
|
|
62.5
|
|
|
62.7
|
|
|
63.4
|
|
(a)
|
Amounts do not include PPAs accounted for as executory contracts.
|
(b)
|
PPA operating leases contractually expire through
2026
.
|
(a)
|
Excludes contingent energy payments for renewable energy PPAs.
|
(b)
|
Includes amounts allocated to NSP-Wisconsin through intercompany charges.
|
(Millions of Dollars)
|
|
Coal
|
|
Nuclear fuel
|
|
Natural gas
supply |
|
Natural gas
storage and transportation |
||||||||
2019
|
|
$
|
194.7
|
|
|
$
|
127.1
|
|
|
$
|
43.6
|
|
|
$
|
107.4
|
|
2020
|
|
87.4
|
|
|
50.9
|
|
|
1.4
|
|
|
97.5
|
|
||||
2021
|
|
52.0
|
|
|
99.0
|
|
|
1.4
|
|
|
95.6
|
|
||||
2022
|
|
34.7
|
|
|
78.5
|
|
|
0.8
|
|
|
92.6
|
|
||||
2023
|
|
35.1
|
|
|
99.4
|
|
|
—
|
|
|
82.8
|
|
||||
Thereafter
|
|
3.5
|
|
|
337.1
|
|
|
—
|
|
|
320.7
|
|
||||
Total
(a)
|
|
$
|
407.4
|
|
|
$
|
792.0
|
|
|
$
|
47.2
|
|
|
$
|
796.6
|
|
(a)
|
Includes amounts allocated to NSP-Wisconsin through intercompany charges.
|
(Millions of Dollars)
|
|
Guarantor
|
|
Guarantee
Amount
|
|
Current
Exposure
|
|
Triggering
Event
|
||||
Guarantee of residual value of assets under the Bank of Tokyo-Mitsubishi Capital Corporation Equipment Leasing Agreement
|
|
NSP-Minnesota
|
|
$
|
4.8
|
|
|
$
|
—
|
|
|
(a)
|
(a)
|
Actual fair value of leased assets is less than the guaranteed residual value amount at the end of the lease term in
2019
.
|
|
|
2018
|
||||||||||||||
(Millions of Dollars)
|
|
Gains and Losses on Cash Flow Hedges
|
|
Unrealized Gains and Losses on Marketable Securities
|
|
Defined Benefit Pension and Postretirement Items
|
|
Total
|
||||||||
Accumulated other comprehensive (loss) income at Jan. 1
|
|
$
|
(20.9
|
)
|
|
$
|
0.1
|
|
|
$
|
(3.7
|
)
|
|
$
|
(24.5
|
)
|
Other comprehensive (loss) income before reclassifications (net of taxes of $0, $0, and $0.3 respectively)
|
|
—
|
|
|
(0.1
|
)
|
|
0.6
|
|
|
0.5
|
|
||||
Losses reclassified from net accumulated other comprehensive loss:
|
|
|
|
|
|
|
|
|
||||||||
Interest rate derivatives (net of taxes of $0.3, $0, and $0, respectively)
(a)
|
|
0.7
|
|
(a)
|
—
|
|
|
—
|
|
|
0.7
|
|
||||
Amortization of net actuarial loss (net of taxes of $0, $0, and $0.1, respectively)
|
|
—
|
|
|
—
|
|
|
0.2
|
|
(b)
|
0.2
|
|
||||
Net current period other comprehensive income (loss)
|
|
0.7
|
|
|
(0.1
|
)
|
|
0.8
|
|
|
1.4
|
|
||||
Accumulated other comprehensive loss at Dec. 31
|
|
$
|
(20.2
|
)
|
|
$
|
—
|
|
|
$
|
(2.9
|
)
|
|
$
|
(23.1
|
)
|
|
|
2017
|
||||||||||||||
(Millions of Dollars)
|
|
Gains and Losses on Cash Flow Hedges
|
|
Unrealized Gains and Losses on Marketable Securities
|
|
Defined Benefit Pension and Postretirement Items
|
|
Total
|
||||||||
Accumulated other comprehensive (loss) income at Jan. 1
|
|
$
|
(18.2
|
)
|
|
$
|
0.1
|
|
|
$
|
(2.7
|
)
|
|
$
|
(20.8
|
)
|
Other comprehensive (loss) income before reclassifications (net of taxes of $0, $0, and $0.1, respectively)
|
|
0.1
|
|
|
—
|
|
|
(0.5
|
)
|
|
(0.4
|
)
|
||||
Losses reclassified from net accumulated other comprehensive loss:
|
|
|
|
|
|
|
|
|
|
|
|
|
||||
Interest rate derivatives (net of taxes of $0.6, $0, and $0, respectively)
|
|
0.9
|
|
(a)
|
—
|
|
|
—
|
|
|
0.9
|
|
||||
Amortization of net actuarial loss (net of taxes of $0, $0, and $0.1, respectively)
|
|
—
|
|
|
—
|
|
|
0.1
|
|
(b)
|
0.1
|
|
||||
Net current period other comprehensive income (loss)
|
|
1.0
|
|
|
—
|
|
|
(0.4
|
)
|
|
0.6
|
|
||||
Adoption of ASU No. 2018-02
(c)
|
|
(3.7
|
)
|
|
—
|
|
|
(0.6
|
)
|
|
(4.3
|
)
|
||||
Accumulated other comprehensive (loss) income at Dec. 31
|
|
$
|
(20.9
|
)
|
|
$
|
0.1
|
|
|
$
|
(3.7
|
)
|
|
$
|
(24.5
|
)
|
(a)
|
Included in interest charges.
|
(b)
|
Included in the computation of net periodic pension and postretirement benefit costs. See Note 9 for further information.
|
(c)
|
In 2017, NSP-Minnesota implemented ASU No. 2018-02 related to the TCJA, which resulted in reclassification of certain credit balances within net accumulated other comprehensive loss to retained earnings.
|
•
|
Regulated Electric
— The regulated electric utility segment generates electricity which is transmitted and distributed in Minnesota, North Dakota and South Dakota. In addition, this segment includes sales for resale and provides wholesale transmission service to various entities in the United States. The regulated electric utility segment also includes NSP-Minnesota’s wholesale commodity and trading operations.
|
•
|
Regulated Natural Gas
— The regulated natural gas utility segment transports, stores and distributes natural gas in portions of Minnesota and North Dakota.
|
•
|
All Other
— Operating segments with revenues below the necessary quantitative thresholds are included in this category. Those primarily include appliance repair services, non-utility real estate activities and revenues associated with processing solid waste into refuse-derived fuel.
|
(Millions of Dollars)
|
|
2018
|
|
2017
|
|
2016
|
||||||
Regulated Electric
|
|
|
|
|
|
|
||||||
Operating revenues
(a)
|
|
$
|
4,508.0
|
|
|
$
|
4,541.8
|
|
|
$
|
4,404.6
|
|
Intersegment revenues
|
|
0.8
|
|
|
0.6
|
|
|
0.6
|
|
|||
Total operating revenue
|
|
$
|
4,508.8
|
|
|
$
|
4,542.4
|
|
|
$
|
4,405.2
|
|
Depreciation and amortization
|
|
697.8
|
|
|
661.3
|
|
|
554.3
|
|
|||
Interest charges and financing costs
|
|
199.5
|
|
|
199.8
|
|
|
200.8
|
|
|||
Income tax expense
|
|
16.4
|
|
|
179.9
|
|
|
215.5
|
|
|||
Net income
|
|
450.4
|
|
|
462.5
|
|
|
465.4
|
|
|||
Regulated Natural Gas
|
|
|
|
|
|
|
||||||
Operating revenues
(a)
|
|
$
|
583.1
|
|
|
$
|
531.9
|
|
|
$
|
467.4
|
|
Intersegment revenues
|
|
0.5
|
|
|
0.5
|
|
|
0.5
|
|
|||
Total operating revenue
|
|
$
|
583.6
|
|
|
$
|
532.4
|
|
|
$
|
467.9
|
|
Depreciation and amortization
|
|
43.3
|
|
|
38.7
|
|
|
41.8
|
|
|||
Interest charges and financing costs
|
|
14.8
|
|
|
13.5
|
|
|
13.2
|
|
|||
Income tax expense
|
|
10.2
|
|
|
10.0
|
|
|
12.0
|
|
|||
Net income
|
|
34.2
|
|
|
28.4
|
|
|
18.3
|
|
|||
All Other
|
|
|
|
|
|
|
||||||
Operating revenues
(a)
|
|
$
|
30.8
|
|
|
$
|
28.3
|
|
|
$
|
28.3
|
|
Depreciation and amortization
|
|
0.5
|
|
|
0.6
|
|
|
0.6
|
|
|||
Interest charges and financing costs
|
|
—
|
|
|
—
|
|
|
—
|
|
|||
Income tax expense
|
|
0.6
|
|
|
9.8
|
|
|
(3.0
|
)
|
|||
Net income
|
|
7.7
|
|
|
(0.8
|
)
|
|
5.0
|
|
|||
|
|
|
|
|
|
|
||||||
Consolidated Total
|
|
|
|
|
|
|
||||||
Total operating revenue
|
|
$
|
5,123.2
|
|
|
$
|
5,103.1
|
|
|
$
|
4,901.4
|
|
Reconciling eliminations
|
|
(1.3
|
)
|
|
(1.1
|
)
|
|
(1.1
|
)
|
|||
Consolidated total revenue
|
|
$
|
5,121.9
|
|
|
$
|
5,102.0
|
|
|
$
|
4,900.3
|
|
Depreciation and amortization
|
|
741.6
|
|
|
700.6
|
|
|
596.7
|
|
|||
Interest charges and financing costs
|
|
214.3
|
|
|
213.3
|
|
|
214.0
|
|
|||
Income tax expense
|
|
27.2
|
|
|
199.7
|
|
|
224.5
|
|
|||
Net income
|
|
492.3
|
|
|
490.1
|
|
|
488.7
|
|
(a)
|
Operating revenues include
$473.7 million
,
$490.2 million
, and
$475.5 million
of intercompany revenue for the years ended Dec. 31, 2018, 2017 and 2016, respectively. See Note 13 for further information.
|
(Millions of Dollars)
|
|
2018
|
|
2017
|
|
2016
|
||||||
Operating revenues:
|
|
|
|
|
|
|
||||||
Electric
|
|
$
|
473.7
|
|
|
$
|
490.2
|
|
|
$
|
475.5
|
|
Operating expenses:
|
|
|
|
|
|
|
||||||
Purchased power
|
|
61.1
|
|
|
66.8
|
|
|
63.0
|
|
|||
Transmission expense
|
|
96.8
|
|
|
110.5
|
|
|
107.5
|
|
|||
Other operating expenses — paid to Xcel Energy Services Inc.
|
|
534.8
|
|
|
539.4
|
|
|
513.0
|
|
|||
Interest expense
|
|
0.3
|
|
|
—
|
|
|
—
|
|
|
|
2018
|
|
2017
|
||||||||||||
(Millions of Dollars)
|
|
Accounts Receivable
|
|
Accounts Payable
|
|
Accounts Receivable
|
|
Accounts Payable
|
||||||||
NSP-Wisconsin
|
|
$
|
11.0
|
|
|
$
|
—
|
|
|
$
|
17.8
|
|
|
$
|
—
|
|
PSCo
|
|
—
|
|
|
17.9
|
|
|
—
|
|
|
7.7
|
|
||||
SPS
|
|
—
|
|
|
4.7
|
|
|
—
|
|
|
1.0
|
|
||||
Other subsidiaries of Xcel Energy Inc.
|
|
—
|
|
|
87.1
|
|
|
30.7
|
|
|
71.4
|
|
||||
|
|
$
|
11.0
|
|
|
$
|
109.7
|
|
|
$
|
48.5
|
|
|
$
|
80.1
|
|
14.
|
Summarized Quarterly Financial Data (Unaudited)
|
|
|
Quarter Ended
|
||||||||||||||
(Millions of Dollars)
|
|
March 31, 2018
|
|
June 30, 2018
|
|
Sept. 30, 2018
|
|
Dec. 31, 2018
|
||||||||
Operating revenues
|
|
$
|
1,310.8
|
|
|
$
|
1,187.7
|
|
|
$
|
1,351.8
|
|
|
$
|
1,271.6
|
|
Operating income
|
|
171.4
|
|
|
150.1
|
|
|
259.5
|
|
|
135.5
|
|
||||
Net income
|
|
111.7
|
|
|
92.4
|
|
|
201.2
|
|
|
87.0
|
|
|
|
Quarter Ended
|
||||||||||||||
(Millions of Dollars)
|
|
March 31, 2017
|
|
June 30, 2017
|
|
Sept. 30, 2017
|
|
Dec. 31, 2017
|
||||||||
Operating revenues
|
|
$
|
1,307.1
|
|
|
$
|
1,164.9
|
|
|
$
|
1,355.8
|
|
|
$
|
1,274.2
|
|
Operating income
(a)
|
|
182.5
|
|
|
173.1
|
|
|
339.7
|
|
|
187.4
|
|
||||
Net income
|
|
94.2
|
|
|
87.7
|
|
|
229.0
|
|
|
79.3
|
|
(a)
|
In 2018, NSP-Minnesota implemented ASU No. 2017-07 related to net periodic benefit cost, which resulted in retrospective reclassification of pension costs from O&M expense to other income.
|
1
|
Consolidated Financial Statements:
|
|
|
|
Management Report on Internal Controls Over Financial Reporting
—
For the year ended Dec. 31, 2018.
|
|
Report of Independent Registered Public Accounting Firm — Financial Statements
|
|
Consolidated Statements of Income
—
For the three years ended Dec. 31, 2018, 2017 and 2016.
|
|
Consolidated Statements of Comprehensive Income
—
For the three years ended Dec. 31, 2018, 2017 and 2016.
|
|
Consolidated Statements of Cash Flows
—
For the three years ended Dec. 31, 2018, 2017 and 2016.
|
|
Consolidated Balance Sheets
—
As of Dec. 31, 2018 and 2017.
|
|
Consolidated Statements of Common Stockholder’s Equity
—
For the three years ended Dec. 31, 2018, 2017 and 2016.
|
|
|
2
|
Schedule II
—
Valuation and Qualifying Accounts and Reserves for the years ended Dec. 31, 2018, 2017 and 2016.
|
|
|
3
|
Exhibits
|
|
|
*
|
Indicates incorporation by reference
|
+
|
Executive Compensation Arrangements and Benefit Plans Covering Executive Officers and Directors
|
Exhibit Number
|
Description
|
Report or Registration Statement
|
SEC File or Registration Number
|
Exhibit Reference
|
3.01
*
|
NSP-Minnesota Form 10-12G dated Oct. 5, 2000
|
000-31709
|
3.01
|
|
|
|
|
||
4.01
*
|
Xcel Energy Inc. Form S-3 dated April 18, 2018
|
001-03034
|
4(b)(3)
|
|
4.02
*
|
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2017
|
001-03034
|
4.11
|
|
4.03
*
|
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2017
|
001-03034
|
4.12
|
|
4.04
*
|
NSP-Minnesota Form 10-12G dated Oct. 5, 2000
|
000-31709
|
4.51
|
|
4.05
*
|
Xcel Energy Inc. Form S-3 dated April 18, 2018
|
001-03034
|
4(b)(7)
|
|
4.06
*
|
NSP-Minnesota Form 10-12G dated Oct. 5, 2000
|
000-31709
|
4.63
|
|
4.07
*
|
NSP-Minnesota Form 8-K dated July 14, 2005
|
001-31387
|
4.01
|
|
4.08
*
|
NSP-Minnesota Form 8-K dated May 18, 2006
|
001-31387
|
4.01
|
|
4.09
*
|
NSP-Minnesota Form 8-K dated June 19, 2007
|
001-31387
|
4.01
|
|
4.10
*
|
NSP-Minnesota Form 8-K dated Nov. 16, 2009
|
001-31387
|
4.01
|
|
4.11
*
|
NSP-Minnesota Form 8-K dated Aug. 4, 2010
|
001-31387
|
4.01
|
|
4.12
*
|
NSP-Minnesota Form 8-K dated Aug. 13, 2012
|
001-31387
|
4.01
|
|
4.13
*
|
NSP-Minnesota Form 8-K dated May 20, 2013
|
001-31387
|
4.01
|
|
4.14
*
|
NSP-Minnesota Form 8-K dated May 13, 2014
|
001-31387
|
4.01
|
4.15
*
|
NSP-Minnesota Form 8-K dated Aug. 11, 2015
|
001-31387
|
4.01
|
|
4.16
*
|
NSP-Minnesota Form 8-K dated May 31, 2016
|
001-31387
|
4.01
|
|
4.17
*
|
NSP-Minnesota Form 8-K dated Sept. 13, 2017
|
001-31387
|
4.01
|
|
10.01
*+
|
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2008
|
001-03034
|
10.02
|
|
10.02
*+
|
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2008
|
001-03034
|
10.05
|
|
10.03
*+
|
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2008
|
001-03034
|
10.08
|
|
10.04
*+
|
Xcel Energy Inc. Form U5B dated Nov. 16, 2000
|
001-03034
|
H-1
|
|
10.05
*+
|
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2008
|
001-03034
|
10.17
|
|
10.06
*
|
NSP-Wisconsin Form S-4 dated Jan. 21, 2004
|
333-112033
|
10.01
|
|
10.07
*+
|
Xcel Energy Inc. Form 10-Q for the quarter ended Sept. 30, 2009
|
001-03034
|
10.06
|
|
10.08
*+
|
Xcel Energy Inc. Form 10-Q for the quarter ended Sept. 30, 2009
|
001-03034
|
10.08
|
|
10.09
*+
|
Xcel Energy Inc. Definitive Proxy Statement dated April 6, 2010
|
001-03034
|
Schedule 14A
|
|
10.10
*+
|
Xcel Energy Inc. Definitive Proxy Statement dated April 6, 2010
|
001-03034
|
Schedule 14A
|
|
10.11
*+
|
Xcel Energy Inc. Definitive Proxy Statement dated April 5, 2011
|
001-03034
|
Schedule 14A
|
|
10.12
*+
|
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2008
|
001-03034
|
10.07
|
|
10.13
*+
|
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2011
|
001-03034
|
10.17
|
|
10.14
*+
|
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2011
|
001-03034
|
10.18
|
|
10.15
*+
|
Xcel Energy Inc. Form 10-Q for the quarter ended March 31, 2013
|
001-03034
|
10.01
|
|
10.16
*+
|
Xcel Energy Inc. Form 10-Q for the quarter ended March 31, 2013
|
001-03034
|
10.02
|
|
10.17
*+
|
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2013
|
001-03034
|
10.21
|
|
10.18
*+
|
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2013
|
001-03034
|
10.22
|
|
10.19
*+
|
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2013
|
001-03034
|
10.23
|
|
10.20
*+
|
Xcel Energy Inc. Definitive Proxy Statement dated April 6, 2015
|
001-03034
|
Schedule 14A
|
|
10.21
*+
|
Xcel Energy Inc. Form 8-K dated May 20, 2015
|
001-03034
|
10.02
|
|
10.22
*+
|
Xcel Energy Inc. Form 8-K dated May 20, 2015
|
001-03034
|
10.03
|
|
10.23
*+
|
Xcel Energy inc. Form 10-K for the year ended Dec. 31, 2015
|
001-03034
|
10.28
|
|
10.24
*+
|
Xcel Energy inc. Form 10-K for the year ended Dec. 31, 2015
|
001-03034
|
10.29
|
|
10.25
*+
|
Xcel Energy Inc. Form 10-Q for the quarter ended June 30, 2016
|
001-03034
|
10.01
|
|
10.26
*
|
Xcel Energy Inc. Form 8-K dated June 20, 2016
|
001-03034
|
99.02
|
|
10.27
*+
|
Xcel Energy inc. Form 10-Q for the quarter ended Sept. 30, 2016
|
001-03034
|
10.01
|
|
10.28
*+
|
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2016
|
001-03034
|
10.27
|
10.29
*+
|
Xcel Energy Inc. Form 10-Q for the quarter ended Sept. 30, 2017
|
001-03034
|
10.1
|
|
10.30
*+
|
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2017
|
001-03034
|
10.30
|
|
10.31
*+
|
Xcel Energy Inc. Form 10-Q for the quarter ended June 30, 2018
|
001-03034
|
10.01
|
|
10.32
*+
|
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2018
|
001-03034
|
10.34
|
|
10.33
*+
|
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2018
|
001-03034
|
10.35
|
|
10.34
*+
|
Xcel Energy Inc. Form 10-K for the year ended Dec. 31, 2018
|
001-03034
|
10.36
|
|
101
|
The following materials from NSP-Minnesota’s Annual Report on Form 10-K for the year ended Dec. 31, 2018 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 Stockholder’s Equity, (vi) Notes to Consolidated Financial Statements, (vii) document and entity information, and (viii) Schedule II.
|
|
Allowance for bad debts
|
||||||||||
(Millions of Dollars)
|
2018
|
|
2017
|
|
2016
|
||||||
Balance at Jan. 1
|
$
|
21.3
|
|
|
$
|
20.0
|
|
|
$
|
20.8
|
|
Additions Charged to Costs and Expenses
|
16.2
|
|
|
15.7
|
|
|
15.0
|
|
|||
Additions Charged to Other Accounts
(a)
|
4.1
|
|
|
3.8
|
|
|
4.2
|
|
|||
Deductions from Reserves
(b)
|
(18.1
|
)
|
|
(18.2
|
)
|
|
(20.0
|
)
|
|||
Balance at Dec. 31
|
$
|
23.5
|
|
|
$
|
21.3
|
|
|
$
|
20.0
|
|
(a)
|
Recovery of amounts previously written off.
|
(b)
|
Deductions relate primarily to bad debt write-offs.
|
|
|
NORTHERN STATES POWER COMPANY
(A MINNESOTA CORPORATION)
|
|
|
|
Feb. 22, 2019
|
|
/s/ ROBERT C. FRENZEL
|
|
|
Robert C. Frenzel
|
|
|
Executive Vice President, Chief Financial Officer and Director
|
|
|
(Principal Financial Officer)
|
/s/ BEN FOWKE
|
|
/s/ CHRISTOPHER B. CLARK
|
Ben Fowke
|
|
Christopher B. Clark
|
Chairman, Chief Executive Officer and Director
|
|
President and Director
|
(Principal Executive Officer)
|
|
|
|
|
|
/s/ ROBERT C. FRENZEL
|
|
/s/ JEFFREY S. SAVAGE
|
Robert C. Frenzel
|
|
Jeffrey S. Savage
|
Executive Vice President, Chief Financial Officer and Director
|
|
Senior Vice President, Controller
|
(Principal Financial Officer)
|
|
(Principal Accounting Officer)
|
|
|
|
/s/ DAVID L. EVES
|
|
|
David L. Eves
|
|
|
Executive Vice President and Director
|
|
|
/s/ DELOITTE & TOUCHE LLP
|
|
Minneapolis, Minnesota
|
|
February 22, 2019
|
|
1.
|
I have reviewed this report on Form 10-K of Northern States Power Company (a Minnesota corporation);
|
2.
|
Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
|
3.
|
Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
|
4.
|
The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
|
a.
|
Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
|
b.
|
Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
|
c.
|
Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
|
d.
|
Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
|
5.
|
The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
|
a.
|
All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
|
b.
|
Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
|
|
/s/ BEN FOWKE
|
|
Ben Fowke
|
|
Chairman, Chief Executive Officer and Director
|
1.
|
I have reviewed this report on Form 10-K of Northern States Power Company (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/ ROBERT C. FRENZEL
|
|
Robert C. Frenzel
|
|
Executive Vice President, Chief Financial Officer and Director
|
(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 NSP-Minnesota as of the dates and for the periods expressed in the Form 10-K.
|
|
/s/ BEN FOWKE
|
|
Ben Fowke
|
|
Chairman, Chief Executive Officer and Director
|
|
|
|
/s/ ROBERT C. FRENZEL
|
|
Robert C. Frenzel
|
|
Executive Vice President, Chief Financial Officer and Director
|