0000072903-17-000059.txt : 20171026 0000072903-17-000059.hdr.sgml : 20171026 20171025180232 ACCESSION NUMBER: 0000072903-17-000059 CONFORMED SUBMISSION TYPE: 8-K PUBLIC DOCUMENT COUNT: 3 CONFORMED PERIOD OF REPORT: 20171026 ITEM INFORMATION: Results of Operations and Financial Condition ITEM INFORMATION: Financial Statements and Exhibits FILED AS OF DATE: 20171026 DATE AS OF CHANGE: 20171025 FILER: COMPANY DATA: COMPANY CONFORMED NAME: XCEL ENERGY INC CENTRAL INDEX KEY: 0000072903 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC & OTHER SERVICES COMBINED [4931] IRS NUMBER: 410448030 STATE OF INCORPORATION: MN FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 8-K SEC ACT: 1934 Act SEC FILE NUMBER: 001-03034 FILM NUMBER: 171154043 BUSINESS ADDRESS: STREET 1: 414 NICOLLET MALL CITY: MINNEAPOLIS STATE: MN ZIP: 55401 BUSINESS PHONE: 6123305500 MAIL ADDRESS: STREET 1: 414 NICOLLET MALL CITY: MINNEAPOLIS STATE: MN ZIP: 55401 FORMER COMPANY: FORMER CONFORMED NAME: NORTHERN STATES POWER CO /MN/ DATE OF NAME CHANGE: 19920703 FILER: COMPANY DATA: COMPANY CONFORMED NAME: PUBLIC SERVICE CO OF COLORADO CENTRAL INDEX KEY: 0000081018 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC & OTHER SERVICES COMBINED [4931] IRS NUMBER: 840296600 STATE OF INCORPORATION: CO FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 8-K SEC ACT: 1934 Act SEC FILE NUMBER: 001-03280 FILM NUMBER: 171154045 BUSINESS ADDRESS: STREET 1: 1800 LARIMER STREET CITY: DENVER STATE: CO ZIP: 80202 BUSINESS PHONE: 3035717511 MAIL ADDRESS: STREET 1: P O BOX 840 STE 300 CITY: DENVER STATE: CO ZIP: 80201 FILER: COMPANY DATA: COMPANY CONFORMED NAME: NORTHERN STATES POWER CO CENTRAL INDEX KEY: 0001123852 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC & OTHER SERVICES COMBINED [4931] IRS NUMBER: 411967505 STATE OF INCORPORATION: MN FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 8-K SEC ACT: 1934 Act SEC FILE NUMBER: 001-31387 FILM NUMBER: 171154046 BUSINESS ADDRESS: STREET 1: 414 NICOLLET MALL CITY: MINNEAPOLIS STATE: MN ZIP: 55401 BUSINESS PHONE: 6123305500 MAIL ADDRESS: STREET 1: 414 NICOLLET MALL CITY: MINNEAPOLIS STATE: MN ZIP: 55401 FILER: COMPANY DATA: COMPANY CONFORMED NAME: SOUTHWESTERN PUBLIC SERVICE CO CENTRAL INDEX KEY: 0000092521 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC & OTHER SERVICES COMBINED [4931] IRS NUMBER: 750575400 STATE OF INCORPORATION: NM FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 8-K SEC ACT: 1934 Act SEC FILE NUMBER: 001-03789 FILM NUMBER: 171154044 BUSINESS ADDRESS: STREET 1: SPS TOWER STREET 2: TYLER AT SIXTH ST CITY: AMARILLO STATE: TX ZIP: 79101 BUSINESS PHONE: 3035717511 MAIL ADDRESS: STREET 1: PO BOX 1261 CITY: AMARILLO STATE: TX ZIP: 79170 FILER: COMPANY DATA: COMPANY CONFORMED NAME: NORTHERN STATES POWER CO /WI/ CENTRAL INDEX KEY: 0000072909 STANDARD INDUSTRIAL CLASSIFICATION: ELECTRIC & OTHER SERVICES COMBINED [4931] IRS NUMBER: 390508315 STATE OF INCORPORATION: WI FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 8-K SEC ACT: 1934 Act SEC FILE NUMBER: 001-03140 FILM NUMBER: 171154047 BUSINESS ADDRESS: STREET 1: 1414 W HAMILTON AVE CITY: EAU CLAIRE STATE: WI ZIP: 54702 BUSINESS PHONE: 7158392621 MAIL ADDRESS: STREET 1: P O BOX 8 CITY: EAU CLAIRE STATE: WI ZIP: 54702-008 8-K 1 xcel8-kerq32017.htm 8-K Document


 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 8-K
CURRENT REPORT
Pursuant to Section 13 or 15(d) of
the Securities Exchange Act of 1934
Date of Report (Date of earliest event reported) Oct. 26, 2017
 
Commission File
Number
 
Exact Name of Registrant as Specified in its Charter; State of
Incorporation; Address of Principal Executive Offices; and
Telephone Number
 
IRS Employer
Identification
Number
001-3034
 
XCEL ENERGY INC.
 
41-0448030
 
 
(a Minnesota corporation)
 
 
 
 
414 Nicollet Mall
 
 
 
 
Minneapolis, Minnesota 55401
 
 
 
 
(612) 330-5500
 
 
 
 
 
 
 
000-31387
 
NORTHERN STATES POWER COMPANY
 
41-1967505
 
 
(a Minnesota corporation)
 
 
 
 
414 Nicollet Mall
 
 
 
 
Minneapolis, Minnesota 55401
 
 
 
 
(612) 330-5500
 
 
 
 
 
 
 
001-03140
 
NORTHERN STATES POWER COMPANY
 
39-0508315
 
 
(a Wisconsin corporation)
 
 
 
 
1414 W. Hamilton Avenue
 
 
 
 
Eau Claire, Wisconsin 54701
 
 
 
 
(715) 737-2625
 
 
 
 
 
 
 
001-3280
 
PUBLIC SERVICE COMPANY OF COLORADO
 
84-0296600
 
 
(a Colorado corporation)
 
 
 
 
1800 Larimer, Suite 1100
 
 
 
 
Denver, Colorado 80202
 
 
 
 
(303) 571-7511
 
 
 
 
 
 
 
001-03789
 
SOUTHWESTERN PUBLIC SERVICE COMPANY
 
75-0575400
 
 
(a New Mexico corporation)
 
 
 
 
790 South Buchanan
 
 
 
 
Amarillo, Texas 79101
 
 
 
 
(303) 571-7511
 
 
 
Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions (see General Instruction A.2. below):

o Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)
o Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)
o Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))
o Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 405 of the Securities Act of 1933 (17 CFR §230.405) or Rule 12b-2 of the Securities Exchange Act of 1934 (17 CFR §240.12b-2).
Emerging growth company £

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. £

 





Item 2.02. Results of Operations and Financial Condition

On Oct. 26, 2017, Xcel Energy released earnings results for the third quarter of 2017.

See additional information in the Earnings Release furnished as exhibit 99.01.

Item 9.01. Financial Statements and Exhibits

(d) Exhibits

Exhibit No.
 
Description
 
 
 
 
Earnings Release of Xcel Energy dated Oct. 26, 2017.
.





SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

Oct. 26, 2017
Xcel Energy Inc.
(a Minnesota corporation)
 
Northern States Power Company
(a Minnesota corporation)
 
Northern States Power Company
(a Wisconsin corporation)
 
Public Service Company of Colorado
(a Colorado corporation)
 
Southwestern Public Service Company
(a New Mexico corporation)
 
 
 
/s/ ROBERT C. FRENZEL
 
Robert C. Frenzel
 
Executive Vice President, Chief Financial Officer


EX-99.01 2 xcelearningsreleaseq32017.htm EXHIBIT 99.01 Exhibit

Exhibit 99.01
logoa01a01a07.jpg
 
414 Nicollet Mall
Oct. 26, 2017
Minneapolis, MN 55401

XCEL ENERGY
THIRD QUARTER 2017 EARNINGS REPORT

GAAP and ongoing 2017 third quarter earnings per share were $0.97 compared with $0.90 per share in 2016.
Xcel Energy narrows its 2017 GAAP and ongoing earnings guidance to $2.27 to $2.32 per share compared with the previous guidance issued of $2.25 to $2.35 per share.
Xcel Energy initiates 2018 GAAP and ongoing earnings guidance of $2.37 to $2.47 per share.
Xcel Energy revises long-term EPS growth rate objectives to 5 to 6 percent.

MINNEAPOLIS — Xcel Energy Inc. (NYSE: XEL) today reported 2017 third quarter GAAP and ongoing earnings of $492 million, or $0.97 per share, compared with $458 million, or $0.90 per share, in the same period in 2016.

Earnings for the third quarter of 2017 increased due to higher electric margins to recover infrastructure investments, along with a lower effective tax rate and lower operating and maintenance expenses, partially offset by higher depreciation expense and property taxes.

“Third quarter earnings were strong,” said Ben Fowke, chairman, president and CEO of Xcel Energy. “Results lined up with our expectations and we expect to deliver 2017 earnings within our narrowed guidance range. In addition, we are well positioned for the future and are issuing 2018 earnings guidance of $2.37 to $2.47 per share, which is consistent with our long-term earnings growth objective.”

“We have made progress in our Steel-for-Fuel investment strategy with our proposal for a new 300 megawatt wind farm in South Dakota. We also announced our proposed Colorado Energy Plan, which would increase our renewable portfolio to 55 percent of our energy mix in Colorado by 2026, while transitioning from coal generation. Our Steel-for-Fuel strategy and Colorado Energy Plan deliver tremendous value to our customers and build on Xcel Energy’s commitment to transition our energy fleet to cleaner, carbon free resources while keeping customer bills low,” concluded Fowke.

At 9:00 a.m. CDT today, Xcel Energy will host a conference call to review financial results. To participate in the call, please dial- in 5 to 10 minutes prior to the start and follow the operator’s instructions.

US Dial-In:
(800) 289-0496
International Dial-In:
(719) 325-4835
Conference ID:
7237091

The conference call also will be simultaneously broadcast and archived on Xcel Energy’s website at www.xcelenergy.com. To access the presentation, click on Investor Relations. If you are unable to participate in the live event, the call will be available for replay from 1:00 p.m. CDT on Oct. 26 through 11:00 p.m. CDT on Oct. 27.

Replay Numbers
 
US Dial-In:
(888) 203-1112
International Dial-In:
(719) 457-0820
Access Code:
7237091


1


Except for the historical statements contained in this release, the matters discussed herein, are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements, including our 2017 and 2018 earnings per share guidance and assumptions, are intended to be identified in this document by the words “anticipate,” “believe,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should” and similar expressions. Actual results may vary materially. Forward-looking statements speak only as of the date they are made and we expressly disclaim any obligation to update any forward-looking information. The following factors, in addition to those discussed in Xcel Energy’s Annual Report on Form 10-K for the fiscal year ended Dec. 31, 2016 and subsequent securities filings, could cause actual results to differ materially from management expectations as suggested by such forward-looking information: general economic conditions, including inflation rates, monetary fluctuations and their impact on capital expenditures and the ability of Xcel Energy Inc. and its subsidiaries (collectively, Xcel Energy) to obtain financing on favorable terms; business conditions in the energy industry; including the risk of a slow down in the U.S. economy or delay in growth, recovery, trade, fiscal, taxation and environmental policies in areas where Xcel Energy has a financial interest; customer business conditions; actions of credit rating agencies; competitive factors including the extent and timing of the entry of additional competition in the markets served by Xcel Energy; unusual weather; effects of geopolitical events, including war and acts of terrorism; cyber security threats and data security breaches; state, federal and foreign legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rates or have an impact on asset operation or ownership or impose environmental compliance conditions; structures that affect the speed and degree to which competition enters the electric and natural gas markets; costs and other effects of legal and administrative proceedings, settlements, investigations and claims; financial or regulatory accounting policies imposed by regulatory bodies; outcomes of regulatory proceedings; availability or cost of capital; and employee work force factors.

For more information, contact:
Paul Johnson, Vice President, Investor Relations
(612) 215-4535
Olga Guteneva, Director of Investor Relations
(612) 215-4559
 
 
For news media inquiries only, please call Xcel Energy Media Relations
(612) 215-5300
Xcel Energy internet address: www.xcelenergy.com
 

This information is not given in connection with any
sale, offer for sale or offer to buy any security.

2


XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
(amounts in thousands, except per share data)
 
 
Three Months Ended Sept. 30
 
Nine Months Ended Sept. 30
 
 
2017
 
2016
 
2017
 
2016
Operating revenues
 
 
 
 
 
 
 
 
Electric
 
$
2,783,569

 
$
2,799,964

 
$
7,420,646

 
$
7,209,225

Natural gas
 
214,253

 
221,956

 
1,129,795

 
1,046,544

Other
 
19,075

 
18,227

 
57,806

 
56,500

Total operating revenues
 
3,016,897

 
3,040,147

 
8,608,247

 
8,312,269

 
 
 
 
 
 
 
 
 
Operating expenses
 
 
 
 
 
 
 
 
Electric fuel and purchased power
 
1,006,160

 
1,037,263

 
2,850,480

 
2,755,083

Cost of natural gas sold and transported
 
63,998

 
67,566

 
543,452

 
469,754

Cost of sales — other
 
8,451

 
8,648

 
25,216

 
25,225

Operating and maintenance expenses
 
541,539

 
590,009

 
1,706,102

 
1,764,397

Conservation and demand side management expenses
 
73,728

 
63,914

 
206,121

 
177,266

Depreciation and amortization
 
371,091

 
328,503

 
1,102,015

 
971,057

Taxes (other than income taxes)
 
133,571

 
117,190

 
410,591

 
400,982

Total operating expenses
 
2,198,538

 
2,213,093

 
6,843,977

 
6,563,764

 
 
 
 
 
 
 
 
 
Operating income
 
818,359

 
827,054

 
1,764,270

 
1,748,505

 
 
 
 
 
 
 
 
 
Other income, net
 
5,089

 
578

 
14,143

 
6,388

Equity earnings of unconsolidated subsidiaries
 
7,080

 
9,701

 
22,496

 
32,500

Allowance for funds used during construction — equity
 
23,483

 
17,199

 
54,182

 
45,042

 
 


 
 
 
 
 


Interest charges and financing costs
 
 
 
 
 
 
 
 
Interest charges — includes other financing costs of
$5,923, $6,060, $17,657 and $19,026, respectively
 
167,803

 
165,857

 
497,932

 
485,280

Allowance for funds used during construction — debt
 
(10,724
)
 
(7,532
)
 
(25,359
)
 
(20,206
)
Total interest charges and financing costs
 
157,079

 
158,325

 
472,573

 
465,074

 
 
 
 
 
 
 
 
 
Income before income taxes
 
696,932

 
696,207

 
1,382,518

 
1,367,361

Income taxes
 
204,791

 
238,412

 
423,844

 
471,459

Net income
 
$
492,141

 
$
457,795

 
$
958,674

 
$
895,902

 
 
 
 
 
 
 
 
 
Weighted average common shares outstanding:
 
 
 
 
 
 
 
 
Basic
 
508,581

 
508,941

 
508,468

 
508,840

Diluted
 
509,242

 
509,566

 
509,052

 
509,396

 
 
 
 
 
 
 
 
 
Earnings per average common share:
 
 
 
 
 
 
 
 
Basic
 
$
0.97

 
$
0.90

 
$
1.89

 
$
1.76

Diluted
 
0.97

 
0.90

 
1.88

 
1.76

 
 
 
 
 
 
 
 
 
Cash dividends declared per common share
 
$
0.36

 
$
0.34

 
$
1.08

 
$
1.02


3


XCEL ENERGY INC. AND SUBSIDIARIES
Notes to Investor Relations Earnings Release (Unaudited)

Due to the seasonality of Xcel Energy’s operating results, quarterly financial results are not an appropriate base from which to project annual results.

The only common equity securities that are publicly traded are common shares of Xcel Energy Inc. The diluted earnings and earnings per share (EPS) of each subsidiary discussed below do not represent a direct legal interest in the assets and liabilities allocated to such subsidiary but rather represent a direct interest in our assets and liabilities as a whole. Ongoing diluted EPS for Xcel Energy and by subsidiary is a financial measure not recognized under generally accepted accounting principles (GAAP). Ongoing diluted EPS is calculated by dividing the net income or loss attributable to the controlling interest of each subsidiary, adjusted for certain items, by the weighted average fully diluted Xcel Energy Inc. common shares outstanding for the period. We use this non-GAAP financial measure to evaluate and provide details of Xcel Energy’s core earnings and underlying performance. We believe this measurement is useful to investors in facilitating period over period comparisons and evaluating or projecting financial results. This non-GAAP financial measure should not be considered as an alternative to measures calculated and reported in accordance with GAAP.

Note 1. Earnings Per Share Summary

The following table summarizes diluted EPS for Xcel Energy:
 
 
Three Months Ended Sept. 30
 
Nine Months Ended Sept. 30
Diluted Earnings (Loss) Per Share
 
2017
 
2016
 
2017
 
2016
NSP-Minnesota
 
$
0.45

 
$
0.41

 
$
0.81

 
$
0.74

Public Service Company of Colorado (PSCo)
 
0.37

 
0.34

 
0.78

 
0.74

Southwestern Public Service Company (SPS)
 
0.13

 
0.13

 
0.25

 
0.24

NSP-Wisconsin
 
0.04

 
0.05

 
0.12

 
0.11

Equity earnings of unconsolidated subsidiaries
 
0.01

 
0.01

 
0.03

 
0.04

Regulated utility (a)
 
1.00

 
0.94

 
1.98

 
1.87

Xcel Energy Inc. and other
 
(0.03
)
 
(0.04
)
 
(0.10
)
 
(0.11
)
GAAP diluted EPS
 
$
0.97

 
$
0.90

 
$
1.88

 
$
1.76


(a)  
Amounts may not add due to rounding.

NSP-Minnesota — Earnings increased $0.04 per share for the third quarter of 2017 and $0.07 per share year-to-date. The year-to-date increase in earnings reflects electric rate increases, lower effective tax rate (ETR) and reduced operating and maintenance (O&M) expenses. The decrease in the ETR is largely driven by resolution of IRS appeals/audits and an increase in research and experimentation credits. The lower O&M expenses primarily relate to the timing of maintenance activities and the overhauls at various generation facilities and reduced expense for nuclear refueling outages. These positive factors were partially offset by depreciation expense (for additional capital investments, including the Courtenay Wind Farm, and prior year amortization of Minnesota’s excess depreciation reserve) and higher property taxes.

PSCo — Earnings increased $0.03 per share for the third quarter of 2017 and $0.04 per share year-to-date. The year-to-date increase in earnings, driven by higher electric margins, lower O&M expenses and lower ETR, were partially offset by increased depreciation expense associated with electric and natural gas investments. The lower O&M expenses are driven by the timing of maintenance and overhauls at various generation facilities and the impact of costs associated with storm damage in 2016.

SPS — Earnings were flat for the third quarter of 2017 and increased $0.01 per share year-to-date. The year-to-date increase in electric margin was attributable to rate increases in Texas and New Mexico, partially offset by the impact of unfavorable weather. This increase was largely offset by higher depreciation expense for transmission and distribution investments and timing of O&M expenses, including the prior year deferrals associated with the Texas 2016 rate case.

NSP-Wisconsin — Earnings decreased $0.01 per share for the third quarter of 2017 and increased $0.01 per share year-to-date. The year-to-date change was driven by increases in electric and natural gas rates, partially offset by depreciation expense primarily related to transmission and distribution investments and the impact of unfavorable weather.


4


The following table summarizes significant components contributing to the changes in 2017 EPS compared with the same period in 2016:
Diluted Earnings (Loss) Per Share
 
Three Months Ended Sept. 30
 
Nine Months Ended Sept. 30
2016 GAAP diluted EPS
 
$
0.90

 
$
1.76

 
 
 
 
 
Components of change — 2017 vs. 2016
 
 
 
 
Higher electric margins
 
0.02

 
0.14

Lower ETR (a)
 
0.07

 
0.10

Lower O&M expenses
 
0.06

 
0.07

Higher natural gas margins
 

 
0.01

Higher depreciation and amortization
 
(0.05
)
 
(0.16
)
Higher conservation and DSM expenses (offset by higher revenues)
 
(0.01
)
 
(0.03
)
Other, net
 
(0.02
)
 
(0.01
)
2017 GAAP diluted EPS
 
$
0.97

 
$
1.88


(a) 
Lower ETR includes the impact of an additional $9.6 million and $18.4 million of wind production tax credits (PTCs) for the three and nine months ended Sept. 30, 2017, respectively, which are largely flowed back to customers through electric margin.

Note 2. Regulated Utility Results

Estimated Impact of Temperature Changes on Regulated Earnings — Unusually hot summers or cold winters increase electric and natural gas sales, while mild weather reduces electric and natural gas sales. The estimated impact of weather on earnings is based on the number of customers, temperature variances and the amount of natural gas or electricity historically used per degree of temperature. Weather deviations from normal levels can affect Xcel Energy’s financial performance.

Degree-day or Temperature-Humidity Index (THI) data is used to estimate amounts of energy required to maintain comfortable indoor temperature levels based on each day’s average temperature and humidity. Heating degree-days (HDD) is the measure of the variation in the weather based on the extent to which the average daily temperature falls below 65° Fahrenheit. Cooling degree-days (CDD) is the measure of the variation in the weather based on the extent to which the average daily temperature rises above 65° Fahrenheit. Each degree of temperature above 65° Fahrenheit is counted as one CDD, and each degree of temperature below 65° Fahrenheit is counted as one HDD. In Xcel Energy’s more humid service territories, a THI is used in place of CDD, which adds a humidity factor to CDD. HDD, CDD and THI are most likely to impact the usage of Xcel Energy’s residential and commercial customers. Industrial customers are less sensitive to weather.

Normal weather conditions are defined as either the 20-year or 30-year average of actual historical weather conditions. The historical period of time used in the calculation of normal weather differs by jurisdiction, based on regulatory practice. To calculate the impact of weather on demand, a demand factor is applied to the weather impact on sales.

The percentage increase (decrease) in normal and actual HDD, CDD and THI is provided in the following table:
 
Three Months Ended Sept. 30
 
Nine Months Ended Sept. 30
 
2017 vs.
Normal
 
2016 vs.
Normal
 
2017 vs.
2016
 
2017 vs.
Normal
 
2016 vs.
Normal
 
2017 vs.
2016
HDD
(16.5
)%
 
(52.6
)%
 
67.5
 %
 
(13.6
)%
 
(12.7
)%
 
(2.2
)%
CDD
5.3

 
11.0

 
(4.5
)
 
5.9

 
8.3

 
(1.8
)
THI
(11.6
)
 
6.5

 
(17.5
)
 
(10.6
)
 
8.6

 
(18.5
)


5


Weather — The following table summarizes the estimated impact of temperature variations on EPS compared with normal weather conditions:
 
Three Months Ended Sept. 30
 
Nine Months Ended Sept. 30
 
2017 vs.
Normal
 
2016 vs.
Normal
 
2017 vs.
2016
 
2017 vs.
Normal
 
2016 vs.
Normal
 
2017 vs.
2016
Retail electric
$
(0.011
)
 
$
0.024

 
$
(0.035
)
 
$
(0.032
)
 
$
0.020

 
$
(0.052
)
Firm natural gas

 
(0.001
)
 
0.001

 
(0.020
)
 
(0.014
)
 
(0.006
)
Total (excluding decoupling)
$
(0.011
)
 
$
0.023

 
$
(0.034
)
 
$
(0.052
)
 
$
0.006

 
$
(0.058
)
Decoupling  Minnesota
0.015

 
(0.008
)
 
0.023

 
0.023

 
(0.009
)
 
0.032

Total (adjusted for recovery from decoupling)
$
0.004

 
$
0.015

 
$
(0.011
)
 
$
(0.029
)
 
$
(0.003
)
 
$
(0.026
)

Sales Growth (Decline) — The following tables summarize Xcel Energy and its subsidiaries’ sales growth (decline) for actual and weather-normalized sales in 2017 compared to the same period in 2016:
 
 
Three Months Ended Sept. 30
 
 
NSP-Minnesota
 
PSCo
 
SPS
 
NSP-Wisconsin
 
Xcel Energy
Actual
 
 
 
 
 
 
 
 
 
 
Electric residential (a)
 
(6.8
)%
 
(2.5
)%
 
(7.4
)%
 
(6.9
)%
 
(5.3
)%
Electric commercial and industrial
 
(2.7
)
 
0.8

 
(1.0
)
 
1.5

 
(0.9
)
Total retail electric sales
 
(3.9
)
 
(0.3
)
 
(2.5
)
 
(0.8
)
 
(2.2
)
Firm natural gas sales
 
8.5

 
4.7

 
 N/A

 
11.4

 
6.2

 
 
Three Months Ended Sept. 30
 
 
NSP-Minnesota
 
PSCo
 
SPS
 
NSP-Wisconsin
 
Xcel Energy
Weather-normalized
 
 
 
 
 
 
 
 
 
 
Electric residential (a)
 
(1.5
)%
 
(3.0
)%
 
(2.0
)%
 
(0.4
)%
 
(2.1
)%
Electric commercial and industrial
 
(1.9
)
 
0.7

 
0.3

 
3.0

 
(0.2
)
Total retail electric sales
 
(1.8
)
 
(0.6
)
 
(0.3
)
 
2.0

 
(0.8
)
Firm natural gas sales
 
6.9

 
(0.6
)
 
 N/A

 
9.6

 
2.1

 
 
Nine Months Ended Sept. 30
 
 
NSP-Minnesota
 
PSCo
 
SPS
 
NSP-Wisconsin
 
Xcel Energy
Actual
 
 
 
 
 
 
 
 
 
 
Electric residential (a)
 
(3.3
)%
 
(1.9
)%
 
(4.4
)%
 
(2.7
)%
 
(2.9
)%
Electric commercial and industrial
 
(1.6
)
 
0.6

 
0.7

 
1.5

 
(0.2
)
Total retail electric sales
 
(2.1
)
 
(0.2
)
 
(0.4
)
 
0.3

 
(1.0
)
Firm natural gas sales
 
4.4

 
(5.5
)
 
N/A

 
4.5

 
(1.9
)
 
 
Nine Months Ended Sept. 30
 
 
NSP-Minnesota
 
PSCo
 
SPS
 
NSP-Wisconsin
 
Xcel Energy
Weather-normalized
 
 
 
 
 
 
 
 
 
 
Electric residential (a)
 
(0.5
)%
 
(1.5
)%
 
(1.7
)%
 
0.4
%
 
(1.0
)%
Electric commercial and industrial
 
(1.0
)
 
0.7

 
1.0

 
2.1

 
0.2

Total retail electric sales
 
(0.9
)
 

 
0.3

 
1.6

 
(0.2
)
Firm natural gas sales
 
4.4

 
(1.0
)
 
N/A

 
4.0

 
1.0


6



 
 
Nine Months Ended Sept. 30 (Excluding Leap Day) (b)
 
 
NSP-Minnesota
 
PSCo
 
SPS
 
NSP-Wisconsin
 
Xcel Energy
Weather-normalized - adjusted for leap day
 
 
 
 
 
 
 
 
 
 
Electric residential (a)
 
(0.2
)%
 
(1.2
)%
 
(1.3
)%
 
0.8
%
 
(0.6
)%
Electric commercial and industrial
 
(0.7
)
 
1.0

 
1.3

 
2.4

 
0.6

Total retail electric sales
 
(0.5
)
 
0.3

 
0.7

 
1.9

 
0.2

Firm natural gas sales
 
5.3

 
(0.3
)
 
N/A

 
4.8

 
1.8

 
(a) Extreme weather variations, windchill and cloud cover may not be reflected in weather-normalized and actual growth estimates.
(b) The estimated impact of the 2016 leap day is excluded to present a more comparable year-over-year presentation. The estimated impact of the additional day of sales in 2016 was approximately 30-40 basis points for retail electric and 70-80 basis points for firm natural gas for the nine months ended.

Weather-normalized Electric Sales Growth (Decline) — Year-To-Date Excluding Leap Day
NSP-Minnesota’s residential sales decrease was a result of lower use per customer, partially offset by customer growth. The decline in commercial and industrial (C&I) sales was largely due to reduced usage, which offset an increase in the number of customers. Declines in services offset increased sales to large customers in manufacturing and energy industries.
PSCo’s decline in residential sales reflects lower use per customer, partially offset by customer additions. C&I growth was mainly due to an increase in customers and higher use for large C&I customers that support the mining, oil and natural gas industries, which were partially reduced by lower use for the small C&I class.
SPS’ residential sales fell largely due to lower use per customer. The increase in C&I sales reflects customer additions and greater use per customer driven by the oil and natural gas industry in the Permian Basin.
NSP-Wisconsin’s residential sales increase was primarily attributable to higher use per customer and customer additions. C&I growth was largely due to higher use per customer and an increase in sales to customers in the sand mining industry and large customers in the energy and manufacturing industries.

Weather-normalized Natural Gas Sales Growth (Decline) — Year-To-Date Excluding Leap Day
Across most service territories, higher natural gas sales reflect an increase in the number of customers, partially offset by a decline in customer use.

Electric Margin — Electric revenues and fuel and purchased power expenses are impacted by fluctuations in the price of natural gas, coal and uranium used in the generation of electricity. However, these price fluctuations have minimal impact on electric margin due to fuel recovery mechanisms that recover fuel expenses. The following table details the electric revenues and margin:
 
 
Three Months Ended Sept. 30
 
Nine Months Ended Sept. 30
(Millions of Dollars)
 
2017
 
2016
 
2017
 
2016
Electric revenues
 
$
2,784

 
$
2,800

 
$
7,421

 
$
7,209

Electric fuel and purchased power
 
(1,006
)
 
(1,037
)
 
(2,850
)
 
(2,755
)
Electric margin
 
$
1,778

 
$
1,763

 
$
4,571

 
$
4,454




7


The following table summarizes the components of the changes in electric margin:
(Millions of Dollars)
 
Three Months Ended Sept. 30
2017 vs. 2016
 
Nine Months Ended Sept. 30
2017 vs. 2016
Retail rate increases (Texas, Minnesota, New Mexico and Wisconsin)
 
$
25

 
$
102

Non-fuel riders
 
19

 
39

Higher conservation and DSM revenues (offset by higher expenses)
 
10

 
24

Decoupling (weather portion - Minnesota)
 
17

 
24

Estimated impact of weather
 
(26
)
 
(39
)
Wholesale transmission revenue, net of costs
 
(24
)
 
(37
)
Conservation incentive
 
(8
)
 
(12
)
Other, net 
 
2

 
16

Total increase in electric margin
 
$
15

 
$
117

 
Natural Gas Margin — Total natural gas expense varies with changing sales and the cost of natural gas. However, fluctuations in the cost of natural gas has minimal impact on natural gas margin due to natural gas cost recovery mechanisms. The following table details natural gas revenues and margin:
 
 
Three Months Ended Sept. 30
 
Nine Months Ended Sept. 30
(Millions of Dollars)
 
2017
 
2016
 
2017
 
2016
Natural gas revenues
 
$
214

 
$
222

 
$
1,130

 
$
1,047

Cost of natural gas sold and transported
 
(64
)
 
(68
)
 
(543
)
 
(470
)
Natural gas margin
 
$
150

 
$
154

 
$
587

 
$
577


The following table summarizes the components of the changes in natural gas margin:
(Millions of Dollars)
 
Three Months Ended Sept. 30
2017 vs. 2016
 
Nine Months Ended Sept. 30
2017 vs. 2016
Infrastructure and integrity riders
 
$
(1
)
 
$
11

Estimated impact of weather
 
1

 
(4
)
Other, net
 
(4
)
 
3

Total (decrease) increase in natural gas margin
 
$
(4
)
 
$
10

 
O&M Expenses — O&M expenses decreased $48.5 million, or 8.2 percent, for the third quarter of 2017 and $58.3 million, or 3.3 percent, year-to-date. The significant changes are summarized in the table below:
(Millions of Dollars)
 
Three Months Ended Sept. 30
2017 vs. 2016
 
Nine Months Ended Sept. 30
2017 vs. 2016
Plant generation costs
 
$
(4.5
)
 
$
(33.9
)
Nuclear plant operations and amortization
 
(11.0
)
 
(17.3
)
Electric distribution costs
 
(16.0
)
 
(10.7
)
Transmission costs
 
(3.1
)
 
(9.9
)
Employee benefits expense
 
(7.0
)
 
9.7

Texas 2016 electric rate case cost deferral
 

 
7.9

Other, net
 
(6.9
)
 
(4.1
)
  Total decrease in O&M expenses
 
$
(48.5
)
 
$
(58.3
)
Plant generation costs decreased primarily due to the timing of planned maintenance and overhauls at a number of generation facilities;
Nuclear plant operations and amortization expenses are lower mostly due to savings initiatives and reduced refueling outage costs;
Electric distribution costs declined as a result of storm damage expense incurred in 2016; and
Transmission costs decreased mostly due to the timing of transmission line maintenance.


8


Conservation and DSM Expenses — Conservation and demand side management (DSM) expenses increased $9.8 million, or 15.4 percent, for the third quarter of 2017 and $28.9 million, or 16.3 percent, year-to-date. The increase was due to higher recovery rates and additional customer participation in electric conservation programs, mostly in Minnesota. Conservation and DSM expenses are generally recovered in our major jurisdictions concurrently through riders and base rates. Timing of recovery may not correspond to the period in which costs were incurred.

Depreciation and Amortization — Depreciation and amortization increased $42.6 million, or 13.0 percent, for the third quarter of 2017 and $131.0 million, or 13.5 percent, year-to-date. The increase was primarily due to capital investments, including the Courtenay Wind Farm, a new enterprise resource planning system and prior year amortization of the excess depreciation reserve in Minnesota.

Taxes (Other than Income Taxes) — Taxes (other than income taxes) increased $16.4 million, or 14.0 percent for the third quarter of 2017 and $9.6 million, or 2.4 percent year-to-date. The increase was primarily due to higher property taxes in Minnesota.

AFUDC, Equity and Debt — Allowance for funds used during construction (AFUDC) increased $9.5 million for the third quarter of 2017 and $14.3 million year-to-date. The increase was primarily due to higher construction work in progress, particularly the Rush Creek wind project.

Interest Charges — Interest charges increased $1.9 million, or 1.2 percent, for the third quarter of 2017 and $12.7 million, or 2.6 percent, year-to-date. The increase was related to higher debt levels to fund capital investments, partially offset by refinancings at lower interest rates.

Income Taxes Income tax expense decreased $33.6 million for the third quarter and $47.6 million for the first nine months of 2017, compared to the same periods in 2016.  The decrease was primarily due to net tax benefits related to an increase in wind PTCs, the resolution of past appeals/audits, and an increase in research and experimentation credits.  The ETR was 29.4 percent for the third quarter of 2017 compared with 34.2 percent for the same period in 2016 and 30.7 percent for the first nine months of 2017, compared to 34.5 percent for the first nine months of 2016.  The lower ETR in 2017 was primarily due to the adjustments referenced above.

Note 3. Xcel Energy Capital Structure, Financing and Credit Ratings

Following is the capital structure of Xcel Energy:
(Billions of Dollars)
 
Sept. 30, 2017
 
Percentage of Total Capitalization
 
Dec. 31, 2016
 
Percentage of Total Capitalization
Current portion of long-term debt
 
$
0.3

 
1
%
 
$
0.3

 
1
%
Short-term debt
 
0.5

 
2

 
0.4

 
2

Long-term debt
 
14.6

 
54

 
14.2

 
55

Total debt
 
15.4

 
57

 
14.9

 
58

Common equity
 
11.4

 
43

 
11.0

 
42

Total capitalization
 
$
26.8

 
100
%
 
$
25.9

 
100
%

9



Credit Facilities As of Oct. 24, 2017, Xcel Energy Inc. and its utility subsidiaries had the following committed credit facilities available to meet liquidity needs:
(Millions of Dollars)
 
Credit Facility (a)
 
Drawn (b)
 
Available
 
Cash
 
Liquidity
Xcel Energy Inc.
 
$
1,000

 
$
366

 
$
634

 
$
1

 
$
635

PSCo
 
700

 
4

 
696

 
18

 
714

NSP-Minnesota
 
500

 
22

 
478

 

 
478

SPS
 
400

 
3

 
397

 
49

 
446

NSP-Wisconsin
 
150

 
119

 
31

 
1

 
32

Total
 
$
2,750

 
$
514

 
$
2,236

 
$
69

 
$
2,305

 
(a) 
These credit facilities expire in June 2021.
(b) 
Includes outstanding commercial paper and letters of credit.

Credit Ratings — Access to the capital market at reasonable terms is partially dependent on credit ratings. The following ratings reflect the views of Moody’s Investors Service (Moody’s), Standard & Poor’s Rating Services (Standard & Poor’s), and Fitch Ratings (Fitch).

The highest credit rating for debt is Aaa/AAA and the lowest investment grade rating is Baa3/BBB-. The highest rating for commercial paper is P-1/A-1/F-1 and the lowest rating is P-3/A-3/F-3. A security rating is not a recommendation to buy, sell or hold securities. Ratings are subject to revision or withdrawal at any time by the credit rating agency and each rating should be evaluated independently of any other rating.

As of Oct. 24, 2017, the following represents the credit ratings assigned to Xcel Energy Inc. and its utility subsidiaries:
Credit Type
 
Company
 
Moody’s
 
Standard & Poor’s
 
Fitch
Senior Unsecured Debt
 
Xcel Energy Inc.
 
A3
 
BBB+
 
BBB+
 
 
NSP-Minnesota
 
A2
 
A-
 
A
 
 
NSP-Wisconsin
 
A2
 
A-
 
A
 
 
PSCo
 
A3
 
A-
 
A
 
 
SPS
 
Baa1
 
A-
 
BBB+
Senior Secured Debt
 
NSP-Minnesota
 
Aa3
 
A
 
A+
 
 
NSP-Wisconsin
 
Aa3
 
A
 
A+
 
 
PSCo
 
A1
 
A
 
A+
 
 
SPS
 
A2
 
A
 
A-
Commercial Paper
 
Xcel Energy Inc.
 
P-2
 
A-2
 
F2
 
 
NSP-Minnesota
 
P-1
 
A-2
 
F2
 
 
NSP-Wisconsin
 
P-1
 
A-2
 
F2
 
 
PSCo
 
P-2
 
A-2
 
F2
 
 
SPS
 
P-2
 
A-2
 
F2

Capital Expenditures — The estimated base capital expenditures for Xcel Energy for 2018 through 2022 are shown in the table below:
 
 
Base Capital Forecast
By Subsidiary (Millions of Dollars)
 
2018
 
2019
 
2020
 
2021
 
2022
 
2018 - 2022
Total
NSP-Minnesota
 
$
1,370

 
$
1,910

 
$
1,450

 
$
1,590

 
$
1,500

 
$
7,820

PSCo
 
1,650

 
1,020

 
950

 
1,150

 
1,410

 
6,180

SPS
 
1,020

 
1,140

 
710

 
470

 
540

 
3,880

NSP-Wisconsin
 
250

 
250

 
240

 
280

 
290

 
1,310

Other (a)
 
20

 
(90
)
 
(90
)
 
(30
)
 

 
(190
)
Total capital expenditures
 
$
4,310

 
$
4,230

 
$
3,260

 
$
3,460

 
$
3,740

 
$
19,000


10


 
 
Base Capital Forecast
By Function (Millions of Dollars)
 
2018
 
2019
 
2020
 
2021
 
2022
 
2018 - 2022
Total
Electric distribution
 
$
750

 
$
810

 
$
870

 
$
1,110

 
$
1,380

 
$
4,920

Renewables
 
1,410

 
1,860

 
880

 
270

 

 
4,420

Electric transmission
 
770

 
540

 
570

 
860

 
980

 
3,720

Electric generation
 
520

 
370

 
290

 
520

 
530

 
2,230

Natural gas
 
460

 
400

 
410

 
420

 
510

 
2,200

Other (b)
 
400

 
250

 
240

 
280

 
340

 
1,510

Total capital expenditures
 
$
4,310

 
$
4,230

 
$
3,260

 
$
3,460

 
$
3,740

 
$
19,000


(a) Other category includes intercompany transfers for safe harbor wind turbines.
(b) Amounts in other category are net of intercompany transfers.

The base capital expenditure forecast does not include the Colorado Energy Plan, which if approved could increase the total capital investment up to $1.5 billion.

Xcel Energy’s capital expenditure forecast is subject to continuing review and modification. Actual capital expenditures may vary from estimates due to changes in electric and natural gas projected load growth, regulatory decisions, legislative initiatives, reserve requirements, availability of purchased power, alternative plans for meeting long-term energy needs, environmental regulation, and merger, acquisition and divestiture opportunities.

Financing for Capital Expenditures through 2022 — Xcel Energy issues debt and equity securities to refinance retiring maturities, reduce short-term debt, fund capital programs, infuse equity in subsidiaries, fund asset acquisitions and for other general corporate purposes. The current estimated financing plans of Xcel Energy for 2018 through 2022 are shown in the table below.
(Millions of Dollars)
 
 
Funding Capital Expenditures
 
 
Cash from Operations*
 
$
13,920

New Debt**
 
4,695

Equity through the Dividend Reinvestment Program (DRIP) and Benefit Programs
 
385

Base Capital Expenditures 2018-2022
 
$
19,000

 
 
 
Maturing Debt
 
$
3,450


* Net of dividends and pension funding.
**
Reflects a combination of short and long-term debt; net of refinancing.

Financing Activity — During 2017, Xcel Energy Inc. and its utility subsidiaries issued and anticipate issuing the following:
PSCo issued $400 million of 3.80 percent first mortgage bonds due June 15, 2047;
SPS issued $450 million of 3.70 percent first mortgage bonds due Aug. 15, 2047;
NSP-Minnesota issued $600 million of 3.60 percent first mortgage bonds due Sept. 15, 2047;
NSP-Wisconsin plans to issue approximately $100 million of first mortgage bonds in the fourth quarter; and
Xcel Energy Inc. plans to issue short-term debt in the fourth quarter to meet financing needs.

Xcel Energy Inc. and its utility subsidiaries’ 2018 financing plans reflect the following:
Xcel Energy Inc. plans to issue approximately $750 million of senior unsecured bonds;
NSP-Minnesota plans to issue approximately $300 million of first mortgage bonds;
NSP-Wisconsin plans to issue approximately $150 million of first mortgage bonds;
PSCo plans to issue approximately $700 million of first mortgage bonds; and
SPS plans to issue approximately $300 million of first mortgage bonds.

Financing plans are subject to change, depending on capital expenditures, internal cash generation, market conditions and other factors. Xcel Energy does not anticipate issuing any additional equity, beyond its DRIP and benefit programs, over the next five years based on its current base capital expenditure plan.


11


Debt Redemption

On Aug. 30, 2017, SPS reacquired $250 million of debt with a coupon rate of 8.75 percent and an original maturity date of Dec. 1, 2018. The redemption resulted in payment of an early redemption premium of $21.6 million which was deferred as a regulatory asset.
On Sept. 29, 2017, NSP-Minnesota reacquired $500 million of debt with a coupon rate of 5.25 percent and an original maturity date of March 1, 2018. The redemption resulted in payment of an early redemption premium of $7.9 million which was deferred as a regulatory asset.

Note 4. Rates and Regulation

NSP-Wisconsin – Wisconsin 2018 Electric and Natural Gas Rate Case — In May 2017, NSP-Wisconsin filed a request with the Public Service Commission of Wisconsin (PSCW) to increase electric rates by $24.7 million, or 3.6 percent, and natural gas rates by $12.0 million, or 10.1 percent, effective Jan. 1, 2018. The rate filing is based on a 2018 forecast test year, a return on equity (ROE) of 10.0 percent, an equity ratio of 52.53 percent and a forecasted rate base of approximately $1.2 billion for the electric utility and $138.4 million for the natural gas utility.

In September 2017, the PSCW Staff and the intervenors filed testimony. The PSCW Staff recommended an electric rate increase of $10.9 million, or 1.6 percent, and a natural gas rate increase of $9.9 million, or 8.3 percent, based on a ROE of 9.8 percent and an equity ratio of 51.45 percent.

A PSCW decision is anticipated in December 2017 with new rates effective in January 2018.

PSCo – Colorado 2017 Multi-Year Electric Rate Case — In October 2017, PSCo filed a multi-year request with the Colorado Public Utilities Commission (CPUC) seeking to increase electric rates approximately $245 million over four years. The request, summarized below, is based on forecast test years (FTY) ending Dec. 31, a 10.0 percent ROE and an equity ratio of 55.25 percent.
Revenue Request (Millions of Dollars)
 
2018
 
2019
 
2020
 
2021
 
Total
Revenue request
 
$
74.6

 
$
74.9

 
$
59.7

 
$
35.7

 
$
244.9

Clean Air Clean Jobs Act (CACJA) revenue conversion to base rates (a)
 
90.4

 

 

 

 
90.4

Transmission Cost Adjustment (TCA) revenue conversion to base rates (a)
 
42.7

 

 

 

 
42.7

  Total (b)
 
$
207.7

 
$
74.9

 
$
59.7

 
$
35.7

 
$
378.0

 
 
 
 
 
 
 
 
 
 
 
Expected year-end rate base (billions of dollars) (b)
 
$
6.8

 
$
7.1

 
$
7.3

 
$
7.4

 
 

(a) 
The roll-in of each of the TCA and CACJA rider revenues into base rates will not have an impact on total customer bills or total revenue as these costs are already being recovered through a rider. Transmission investments for 2019 through 2021 will be recovered through the TCA rider.

(b) 
This base rate request does not include the impacts associated with the renewable energy standard adjustment and retail electric commodity adjustment for the Rush Creek wind investments or any impacts of the proposed Colorado Energy Plan.

Final rates are expected to be effective in June 2018. PSCo also proposed a stay-out provision and earnings test through 2021.

12



PSCo – Colorado 2017 Multi-Year Natural Gas Rate Case — In June 2017, PSCo filed a multi-year request with the CPUC seeking to increase retail natural gas rates approximately $139 million over three years. The request, detailed below, is based on FTYs, a 10.0 percent ROE and an equity ratio of 55.25 percent.
Revenue Request (Millions of Dollars)
 
2018
 
2019
 
2020
 
Total
Revenue request
 
$
63.2

 
$
32.9

 
$
42.9

 
$
139.0

Pipeline System Integrity Adjustment (PSIA) revenue conversion to base rates (a)
 

 
93.9

 

 
93.9

Total
 
$
63.2

 
$
126.8

 
$
42.9

 
$
232.9

 
 
 
 
 
 
 
 
 
Expected year-end rate base (billions of dollars) (b)
 
$
1.5

 
$
2.3

 
$
2.4

 
 
 
(a) 
The roll-in of PSIA rider revenue into base rates will not have an impact on customer bills or total revenue as these costs are already being recovered through the rider. PSCo plans to request new PSIA rates for 2018 in November 2017. The recovery of incremental PSIA related investments in 2019 and 2020 are included in the base rate request.

(b) 
The additional rate base in 2019 predominantly reflects the roll-in of capital associated with the PSIA rider.

In October 2017, several parties filed answer testimony. The CPUC Staff (Staff) and the Office of Consumer Counsel (OCC), recommended a single 2016 historic test year (HTY), based on an average 13-month rate base, and opposed a multi-year plan (MYP). The Staff and OCC recommended an equity capital structure of 48.73 percent and 51.2 percent, respectively. Both the Staff and the OCC recommended the existing PSIA rider expire with the 2018 rates rolled into base rates beginning Jan. 1, 2019. Planned investments in 2019 and 2020 would be recoverable through base rates, subject to a future rate case.

The following represents adjustments to PSCo’s filed request made by Staff and OCC for 2018:
(Millions of Dollars)
 
Staff
 
OCC
Filed 2018 new revenue request
 
$
63.2

 
$
63.2

Impact of the change in test year
 
4.4

 
4.4

PSCo’s filed 2016 HTY
 
$
67.6

 
$
67.6

 
 
 
 
 
Recommended adjustments:
 
 
 
 
ROE (9.0 percent)
 
(13.5
)
 
(13.5
)
Capital structure and cost of debt
 
(10.2
)
 
(7.5
)
Change in amortization period
 
(5.4
)
 

Prepaid pension and retiree medical assets
 
(5.2
)
 

Change from 2016 year end to average rate base
 
(4.8
)
 
(4.8
)
Other, net
 
(5.0
)
 
(5.5
)
Total adjustments
 
$
(44.1
)
 
$
(31.3
)
 
 
 
 
 
Total recommended rate increase
 
$
23.5

 
$
36.3

 
The next steps in the procedural schedule are as follows:
Rebuttal testimony — Nov. 3, 2017;
Intervenor sur-rebuttal testimony — Nov. 15, 2017;
Hearings — Dec. 11 - 15 and 18 - 19, 2017; and
Statements of position — Jan. 19, 2018.

Interim rates, subject to refund, are expected to be effective Jan. 1, 2018. A final decision by the CPUC is anticipated in March 2018.


13


SPS – Texas 2017 Electric Rate Case — In August 2017, SPS filed a $66.4 million, or 7.1 percent, retail electric, non-fuel base rate increase case in Texas with each of its Texas municipalities and the Public Utilities Commission of Texas (PUCT). The request was based on the 12-month period ended June 30, 2017, with the final three months based on estimates, a requested ROE of 10.25 percent, a Texas retail electric rate base of approximately $1.9 billion and an equity ratio of 53.97 percent.

In October 2017, SPS revised its request to $54.6 million, or 5.8 percent, which reflects updated actual results. In addition, approximately $4.4 million of rate case expenses was bifurcated into a separate docket.

The following table summarizes SPS’ revised rate increase request:
Revenue Request (Millions of Dollars)
 
 
Incremental revenue request
 
$
69.2

Transmission Cost Recovery Factor (TCRF) revenue conversion to base rates (a)
 
(14.6
)
  Net revenue increase request
 
$
54.6

 
(a) 
The roll-in of the TCRF rider revenue into base rates will not have an impact on customer bills or total revenue as these costs are already being recovered through the rider. SPS can request another TCRF rider after the conclusion of this rate case to recover transmission investments subsequent to June 30, 2017.

Key dates in the procedural schedule are as follows:
Intervenors’ direct testimony — Feb. 22, 2018;
PUCT Staff direct testimony — March 1, 2018;
PUCT Staff and intervenors’ cross-rebuttal testimony — March 22, 2018;
SPS’ rebuttal testimony — March 23, 2018;
Hearings — April 10 - 20, 2018; and
Statutory deadline — Aug. 31, 2018.

The final rates are expected to be effective retroactive to Jan. 23, 2018 through a customer surcharge. A PUCT decision is expected in the third quarter of 2018.

PSCo – Colorado Energy Plan (CEP) — In May 2016, PSCo filed its 2016 Electric Resource Plan which included the estimated need for additional generation resources through 2024. In April 2017, the CPUC approved the modeling assumptions that will be used in the Request for Proposal (RFP) process. In August 2017, PSCo filed an updated capacity need with the CPUC of 450 megawatts (MW).

In August 2017, PSCo, along with various other stakeholders, filed a stipulation agreement proposing the CEP. The major components include:
Early retirement of 660 MW of coal-fired generation at Comanche Units 1 (2022) and 2 (2025);
An RFP which could result in the addition of up to 1,000 MW of wind, 700 MW solar and 700 MW of natural gas and/or storage;
Utility ownership targets of 50 percent renewable generation resources and 75 percent of natural gas-fired, storage, or renewable with storage generation resources;
Accelerated depreciation for the early retirement of the two Comanche units and establishment of a regulatory asset to collect the incremental depreciation expense and related costs;
Reduction of the Renewable Energy Standard Adjustment rider, from two percent to one percent, subject to regulatory proceedings, effective beginning 2021 or 2022; and
Construction of a new transmission switching station to further the development of renewable generating resources.

In August 2017, PSCo issued an All-Source RFP. Bids are due on Nov. 28, 2017. PSCo anticipates filing its’ recommended portfolios in April 2018. The CPUC is expected to rule on the stipulation agreement in March 2018. A CPUC decision on the recommended portfolio is anticipated in the summer of 2018.

Approval of the CEP could increase the total capital investment up to $1.5 billion. The CEP is not included in PSCo and Xcel Energy’s base capital expenditures forecast. See Note 3 for further discussion of the capital forecast.


14


Xcel Energy – Wind Development Xcel Energy plans to significantly expand its wind capacity at NSP-Minnesota, PSCo and SPS. The CPUC approved the Rush Creek wind project in 2016. In July 2017, the Minnesota Public Utilities Commission (MPUC) approved NSP-Minnesota’s proposal to add 1,550 MW of new wind generation, including ownership of 1,150 MW of wind generation by NSP-Minnesota.

The PUCT and New Mexico Public Regulation Commission (NMPRC) are expected to rule on SPS’ wind projects by the end of the first quarter of 2018. Hearings in Texas with the PUCT are scheduled for Nov. 6 through Nov. 17, 2017. Hearings in New Mexico with the NMPRC are scheduled for Nov. 28 through Dec. 1, 2017.

In September 2017, NSP-Minnesota filed with the MPUC seeking approval to build and own the Dakota Range project, a 300 MW wind project in South Dakota. The project is projected to be placed into service by the end of 2021 to qualify for 80 percent of the PTC. NSP-Minnesota has requested that the MPUC approve the proposed wind project by March 2018.

These wind projects (with the exception of the Dakota Range project) would qualify for 100 percent of the PTC and are expected to provide billions of dollars of savings to Xcel Energy’s customers and substantial environmental benefits. Projected savings/benefits assume fuel costs and generation mix consistent with various commission approved resource plans.

The following table details these wind projects:
Project Name
 
Capacity (MW)
 
State
 
Estimated Year of Completion
 
Ownership/PPA
 
Regulatory Status
Rush Creek
 
600

 
CO
 
2018
 
PSCo
 
Approved by CPUC
Freeborn
 
200

 
MN/IA
 
2020
 
NSP-Minnesota
 
Approved by MPUC
Blazing Star 1
 
200

 
MN
 
2019
 
NSP-Minnesota
 
Approved by MPUC
Blazing Star 2
 
200

 
MN
 
2020
 
NSP-Minnesota
 
Approved by MPUC
Lake Benton
 
100

 
MN
 
2019
 
NSP-Minnesota
 
Approved by MPUC
Foxtail
 
150

 
ND
 
2019
 
NSP-Minnesota
 
Approved by MPUC
Crowned Ridge
 
300

 
SD
 
2019
 
NSP-Minnesota
 
Approved by MPUC
Dakota Range
 
300

 
SD
 
2021
 
NSP-Minnesota
 
Pending MPUC Approval
Hale
 
478

 
TX
 
2019
 
SPS
 
Pending PUCT & NMPRC Approval
Sagamore
 
522

 
NM
 
2020
 
SPS
 
Pending PUCT & NMPRC Approval
Total Ownership
 
3,050

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Crowned Ridge
 
300

 
SD
 
2019
 
PPA
 
Approved by MPUC
Clean Energy 1
 
100

 
ND
 
2019
 
PPA
 
Approved by MPUC
Bonita
 
230

 
TX
 
2019
 
PPA
 
Pending PUCT & NMPRC Approval
Total PPA
 
630

 
 
 
 
 
 
 
 
Total Wind Capacity
 
3,680

 
 
 
 
 
 
 
 


15


Note 5. Xcel Energy Earnings Guidance and Long-Term EPS and Dividend Growth Rate Objectives

Xcel Energy 2017 Earnings Guidance — Xcel Energy’s narrowed 2017 GAAP and ongoing earnings guidance is $2.27 to $2.32 per share, compared with the previous issued guidance of $2.25 to $2.35 per share.(a) Key assumptions:
Constructive outcomes in all rate case and regulatory proceedings.
Normal weather patterns are experienced for the remainder of the year.
Weather-normalized retail electric sales are projected to be within a range of 0 percent to 0.5 percent over 2016 levels.
Weather-normalized retail firm natural gas sales are projected to be within a range of 0 percent to 0.5 percent over 2016 levels.
Capital rider revenue is projected to increase by $45 million to $55 million over 2016 levels.
O&M expenses are projected to be flat.
Depreciation expense is projected to increase approximately $180 million to $190 million over 2016 levels.
Property taxes are projected to be within a range of approximately $0 million to $10 million over 2016 levels.
Interest expense (net of AFUDC — debt) is projected to increase $10 million to $20 million over 2016 levels.
AFUDC — equity is projected to increase approximately $10 million to $20 million from 2016 levels.
The ETR is projected to be approximately 31 percent.
Average common stock and equivalents are projected to be approximately 509 million shares.
Xcel Energy 2018 Earnings Guidance — Xcel Energy’s 2018 GAAP and ongoing earnings guidance is $2.37 to $2.47 per share.(a) Key assumptions:
Constructive outcomes in all rate case and regulatory proceedings.
Normal weather patterns.
Weather-normalized retail electric sales are projected to be within a range of 0 percent to 0.5 percent over 2017 levels.
Weather-normalized retail firm natural gas sales are projected to be within a range of 0 percent to 0.5 percent below 2017 levels.
Capital rider revenue is projected to increase by $40 million to $50 million over 2017 levels.
O&M expenses are projected to be flat.
Depreciation expense is projected to increase approximately $120 million to$130 million over 2017 levels.
Property taxes are projected to increase approximately $35 million to $45 million over 2017 levels.
Interest expense (net of AFUDC — debt) is projected to increase $20 million to $30 million over 2017 levels.
AFUDC — equity is projected to increase approximately $20 million to $30 million from 2017 levels.
The ETR is projected to be approximately 30 percent to 32 percent.
Average common stock and equivalents are projected to be approximately 510 million shares.
(a)  
Ongoing earnings could differ from those prepared in accordance with GAAP for unplanned and/or unknown adjustments. Xcel Energy is unable to forecast if any of these items will occur or provide a quantitative reconciliation of the guidance for ongoing diluted EPS to corresponding GAAP diluted EPS.

Long-Term EPS and Dividend Growth Rate Objectives Xcel Energy expects to deliver an attractive total return to our shareholders through a combination of earnings growth and dividend yield, based on the following long-term objectives:
Deliver long-term annual EPS growth of 5 percent to 6 percent off of a 2017 base of $2.30 per share (which represents the midpoint of the 2017 guidance range of $2.25 to$2.35 per share);
Deliver annual dividend increases of 5 percent to 7 percent;
Target a dividend payout ratio of 60 percent to 70 percent; and
Maintain senior unsecured debt credit ratings in the BBB+ to A range.

Ongoing earnings is calculated using net income and adjusting for certain nonrecurring or infrequent items that are, in management’s view, not reflective of ongoing operations.



16


XCEL ENERGY INC. AND SUBSIDIARIES
EARNINGS RELEASE SUMMARY (UNAUDITED)
(amounts in thousands, except per share data)
 
 
 
 
 
 
 
Three Months Ended Sept. 30
 
 
2017
 
2016
Operating revenues:
 
 
 
 
Electric and natural gas
 
$
2,997,822

 
$
3,021,920

Other
 
19,075

 
18,227

Total operating revenues
 
3,016,897

 
3,040,147

 
 
 
 
 
Net income
 
$
492,141

 
$
457,795

 
 
 
 
 
Weighted average diluted common shares outstanding
 
509,242

 
509,566

 
 
 
 
 
Components of EPS — Diluted
 
 
 
 
Regulated utility
 
$
1.00

 
$
0.94

Xcel Energy Inc. and other costs
 
(0.03
)
 
(0.04
)
GAAP diluted EPS
 
$
0.97

 
$
0.90

 
 
Nine Months Ended Sept. 30
 
 
2017
 
2016
Operating revenues:
 
 
 
 
Electric and natural gas
 
$
8,550,441

 
$
8,255,769

Other
 
57,806

 
56,500

Total operating revenues
 
8,608,247

 
8,312,269

 
 
 
 
 
Net income
 
$
958,674

 
$
895,902

 
 
 
 
 
Weighted average diluted common shares outstanding
 
509,052

 
509,396

 
 
 
 
 
Components of EPS — Diluted
 
 
 
 
Regulated utility
 
$
1.98

 
$
1.87

Xcel Energy Inc. and other costs
 
(0.10
)
 
(0.11
)
GAAP diluted EPS
 
$
1.88

 
$
1.76

Book value per share
 
$
22.53

 
$
21.63






17
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