EX-99.01 2 xcelearningsreleaseq22017.htm EXHIBIT 99.01 Exhibit

Exhibit 99.01
logoa01a01a07.jpg
 
414 Nicollet Mall
July 27, 2017
Minneapolis, MN 55401

XCEL ENERGY
SECOND QUARTER 2017 EARNINGS REPORT

•
GAAP and ongoing 2017 second quarter earnings per share were $0.45 compared with $0.39 per share in 2016.
•
Xcel Energy reaffirms 2017 GAAP and ongoing earnings guidance of $2.25 to $2.35 per share.

MINNEAPOLIS — Xcel Energy Inc. (NYSE: XEL) today reported 2017 second quarter GAAP and ongoing earnings of $227 million, or $0.45 per share, compared with $197 million, or $0.39 per share, in the same period in 2016.

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

“Second quarter results were in line with our plan and positions us to deliver earnings within our guidance range,” said Ben Fowke, chairman, president and CEO of Xcel Energy. “At the same time, we have accomplished key milestones in the regulatory arena that will bring tremendous value to our customers and shareholders over the longer term.”

The Minnesota Public Utilities Commission recently approved Xcel Energy’s plans for seven new wind farms in the Upper Midwest, part of the largest wind energy expansion in the country, and the Colorado Public Utilities Commission approved the settlement regarding the company’s proposal to deploy new and innovative technologies on the distribution grid. 

“These initiatives are key components of our plans to keep energy costs low, improve reliability, reduce carbon emissions by more than 60 percent by 2030, and enable new ways for customers to manage their own energy use,” Fowke said. “We look forward to executing on these plans and realizing their value,” 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:
(877) 874-1563
International Dial-In:
(719) 325-4790
Conference ID:
5168028

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 July 27 through 11:00 p.m. CDT on July 29.

Replay Numbers
 
US Dial-In:
(866) 375-1919
International Dial-In:
(719) 457-0820
Access Code:
5168028


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 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 June 30
 
Six Months Ended June 30
 
 
2017
 
2016
 
2017
 
2016
Operating revenues
 
 
 
 
 
 
 
 
Electric
 
$
2,338,017

 
$
2,224,142

 
$
4,637,077

 
$
4,409,261

Natural gas
 
289,839

 
258,899

 
915,542

 
824,588

Other
 
17,072

 
16,808

 
38,731

 
38,273

Total operating revenues
 
2,644,928

 
2,499,849

 
5,591,350

 
5,272,122

 
 
 
 
 
 
 
 
 
Operating expenses
 
 
 
 
 
 
 
 
Electric fuel and purchased power
 
919,099

 
855,968

 
1,844,320

 
1,717,820

Cost of natural gas sold and transported
 
114,320

 
90,071

 
479,454

 
402,188

Cost of sales — other
 
8,178

 
8,332

 
16,765

 
16,577

Operating and maintenance expenses
 
578,133

 
596,978

 
1,164,563

 
1,174,388

Conservation and demand side management expenses
 
64,860

 
55,916

 
132,393

 
113,352

Depreciation and amortization
 
365,720

 
322,534

 
730,924

 
642,554

Taxes (other than income taxes)
 
134,926

 
138,469

 
277,020

 
283,792

Total operating expenses
 
2,185,236

 
2,068,268

 
4,645,439

 
4,350,671

 
 
 
 
 
 
 
 
 
Operating income
 
459,692

 
431,581

 
945,911

 
921,451

 
 
 
 
 
 
 
 
 
Other income, net
 
2,608

 
1,560

 
9,054

 
5,810

Equity earnings of unconsolidated subsidiaries
 
7,541

 
9,617

 
15,416

 
22,799

Allowance for funds used during construction — equity
 
16,386

 
14,730

 
30,699

 
27,843

 
 


 
 
 
 
 


Interest charges and financing costs
 
 
 
 
 
 
 
 
Interest charges — includes other financing costs of
$5,876, $6,630, $11,374 and $12,966, respectively
 
164,195

 
162,980

 
330,129

 
319,423

Allowance for funds used during construction — debt
 
(7,613
)
 
(6,684
)
 
(14,635
)
 
(12,674
)
Total interest charges and financing costs
 
156,582

 
156,296

 
315,494

 
306,749

 
 
 
 
 
 
 
 
 
Income before income taxes
 
329,645

 
301,192

 
685,586

 
671,154

Income taxes
 
102,389

 
104,397

 
219,053

 
233,047

Net income
 
$
227,256

 
$
196,795

 
$
466,533

 
$
438,107

 
 
 
 
 
 
 
 
 
Weighted average common shares outstanding:
 
 
 
 
 
 
 
 
Basic
 
508,542

 
508,930

 
508,411

 
508,789

Diluted
 
509,135

 
509,490

 
508,955

 
509,311

 
 
 
 
 
 
 
 
 
Earnings per average common share:
 
 
 
 
 
 
 
 
Basic
 
$
0.45

 
$
0.39

 
$
0.92

 
$
0.86

Diluted
 
0.45

 
0.39

 
0.92

 
0.86

 
 
 
 
 
 
 
 
 
Cash dividends declared per common share
 
$
0.36

 
$
0.34

 
$
0.72

 
$
0.68


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 June 30
 
Six Months Ended June 30
Diluted Earnings (Loss) Per Share
 
2017
 
2016
 
2017
 
2016
Public Service Company of Colorado (PSCo)
 
$
0.20

 
$
0.17

 
$
0.42

 
$
0.40

NSP-Minnesota
 
0.17

 
0.15

 
0.36

 
0.34

Southwestern Public Service Company (SPS)
 
0.07

 
0.06

 
0.12

 
0.11

NSP-Wisconsin
 
0.03

 
0.02

 
0.07

 
0.06

Equity earnings of unconsolidated subsidiaries
 
0.01

 
0.01

 
0.02

 
0.03

Regulated utility (a)
 
0.48

 
0.42

 
0.99

 
0.93

Xcel Energy Inc. and other
 
(0.03
)
 
(0.04
)
 
(0.07
)
 
(0.07
)
GAAP diluted EPS (a)
 
$
0.45

 
$
0.39

 
$
0.92

 
$
0.86


(a) Amounts may not add due to rounding.

PSCo — Earnings increased $0.03 per share for the second quarter of 2017 and $0.02 per share year-to-date. The year-to-date increase in earnings was driven by higher electric and natural gas margins and lower operating and maintenance (O&M) expenses, partially offset by increased depreciation.

NSP-Minnesota — Earnings increased $0.02 per share for the second quarter of 2017 and year-to-date. The year-to-date increase in earnings was due to higher electric margins driven by the rate case in Minnesota, as well as increased natural gas margins, non-fuel riders and lower O&M expenses, partially offset by increased depreciation.

SPS — Earnings increased $0.01 per share for the second quarter of 2017 and year-to-date. The year-to-date increase in earnings was due to the positive impact of rate increases in Texas and New Mexico, which was partially offset by increased depreciation and timing of O&M expenses.

NSP-Wisconsin — Earnings increased $0.01 per share for the second quarter of 2017 and year-to-date. The year-to-date increase in earnings was driven by higher electric margins primarily due to rate increases, which were partially offset by additional depreciation.





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 June 30
 
Six Months Ended June 30
2016 GAAP diluted EPS
 
$
0.39

 
$
0.86

 
 
 
 
 
Components of change — 2017 vs. 2016
 
 
 
 
Higher electric margins
 
0.06

 
0.12

Lower effective tax rate (ETR) (a)
 
0.02

 
0.04

Higher natural gas margins
 
0.01

 
0.02

Lower O&M expenses
 
0.02

 
0.01

Higher depreciation and amortization
 
(0.05
)
 
(0.11
)
Higher conservation and DSM expenses (offset by higher revenues)
 
(0.01
)
 
(0.02
)
Other, net
 
0.01

 
—

2017 GAAP diluted EPS
 
$
0.45

 
$
0.92


(a) Lower ETR includes the impact of $4.8 million and $8.8 million of wind production tax credits (PTCs) for the three and six months ended June 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 the average customer historically uses per degree of temperature. Accordingly, deviations in weather 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 as defined above to derive the amount of demand associated with the weather impact.

The percentage increase (decrease) in normal and actual HDD, CDD and THI is provided in the following table:
 
Three Months Ended June 30
 
Six Months Ended June 30
 
2017 vs.
Normal
 
2016 vs.
Normal
 
2017 vs.
2016
 
2017 vs.
Normal
 
2016 vs.
Normal
 
2017 vs.
2016
HDD
(9.8
)%
 
(3.7
)%
 
(7.2
)%
 
(8.5
)%
 
(11.5
)%
 
2.3
 %
CDD
5.4

 
1.7

 
3.7

 
7.4

 
1.7

 
5.5

THI
(3.9
)
 
15.8

 
(16.1
)
 
(6.9
)
 
15.4

 
(21.4
)


5

Weather — The following table summarizes the estimated impact of temperature variations on EPS compared with sales under normal weather conditions:
 
Three Months Ended June 30
 
Six Months Ended June 30
 
2017 vs.
Normal
 
2016 vs.
Normal
 
2017 vs.
2016
 
2017 vs.
Normal
 
2016 vs.
Normal
 
2017 vs.
2016
Retail electric
$
0.005

 
$
0.013

 
$
(0.008
)
 
$
(0.021
)
 
$
(0.004
)
 
$
(0.017
)
Firm natural gas
(0.002
)
 
—

 
(0.002
)
 
(0.020
)
 
(0.013
)
 
(0.007
)
Total (excluding decoupling)
$
0.003

 
$
0.013

 
$
(0.010
)
 
$
(0.041
)
 
$
(0.017
)
 
$
(0.024
)
Decoupling - Minnesota
—

 
(0.007
)
 
0.007

 
0.009

 
(0.001
)
 
0.010

Total (adjusted for recovery from decoupling)
$
0.003

 
$
0.006

 
$
(0.003
)
 
$
(0.032
)
 
$
(0.018
)
 
$
(0.014
)

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 June 30
 
 
PSCo
 
NSP-Minnesota
 
SPS
 
NSP-Wisconsin
 
Xcel Energy
Actual
 
 
 
 
 
 
 
 
 
 
Electric residential (a)
 
(1.5
)%
 
(1.4
)%
 
6.4
%
 
0.7
%
 
(0.3
)%
Electric commercial and industrial
 
2.6

 
(0.9
)
 
2.5

 
3.4

 
1.3

Total retail electric sales
 
1.4

 
(1.1
)
 
3.1

 
2.7

 
0.9

Firm natural gas sales
 
(8.5
)
 
3.6

 
 N/A

 
4.2

 
(4.7
)
 
 
Three Months Ended June 30
 
 
PSCo
 
NSP-Minnesota
 
SPS
 
NSP-Wisconsin
 
Xcel Energy
Weather-normalized
 
 
 
 
 
 
 
 
 
 
Electric residential (a)
 
(0.3
)%
 
0.8
 %
 
0.8
%
 
2.3
%
 
0.5
 %
Electric commercial and industrial
 
3.0

 
(0.4
)
 
2.3

 
3.7

 
1.5

Total retail electric sales
 
2.0

 
(0.1
)
 
1.9

 
3.4

 
1.3

Firm natural gas sales
 
(3.9
)
 
4.6

 
 N/A

 
3.3

 
(1.2
)
 
 
Six Months Ended June 30
 
 
PSCo
 
NSP-Minnesota
 
SPS
 
NSP-Wisconsin
 
Xcel Energy
Actual
 
 
 
 
 
 
 
 
 
 
Electric residential (a)
 
(1.6
)%
 
(1.2
)%
 
(2.3
)%
 
(0.5
)%
 
(1.5
)%
Electric commercial and industrial
 
0.5

 
(1.0
)
 
1.6

 
1.5

 
0.3

Total retail electric sales
 
(0.1
)
 
(1.1
)
 
0.8

 
0.8

 
(0.2
)
Firm natural gas sales
 
(6.8
)
 
4.0

 
N/A

 
3.7

 
(2.9
)
 
 
Six Months Ended June 30
 
 
PSCo
 
NSP-Minnesota
 
SPS
 
NSP-Wisconsin
 
Xcel Energy
Weather-normalized
 
 
 
 
 
 
 
 
 
 
Electric residential (a)
 
(0.6
)%
 
0.1
 %
 
(1.5
)%
 
0.9
%
 
(0.3
)%
Electric commercial and industrial
 
0.7

 
(0.5
)
 
1.4

 
1.6

 
0.5

Total retail electric sales
 
0.3

 
(0.4
)
 
0.7

 
1.3

 
0.2

Firm natural gas sales
 
(1.0
)
 
4.2

 
N/A

 
3.3

 
0.9


6


 
 
Six Months Ended June 30 (Excluding Leap Day) (b)
 
 
PSCo
 
NSP-Minnesota
 
SPS
 
NSP-Wisconsin
 
Xcel Energy
Weather-normalized - adjusted for leap day
 
 
 
 
 
 
 
 
 
 
Electric residential (a)
 
—
 %
 
0.7
%
 
(0.9
)%
 
1.5
%
 
0.3
%
Electric commercial and industrial
 
1.2

 
—

 
1.9

 
2.1

 
1.0

Total retail electric sales
 
0.9

 
0.2

 
1.2

 
1.9

 
0.8

Firm natural gas sales
 
(0.2
)
 
5.1

 
N/A

 
4.2

 
1.7


(a) Extreme weather variations and additional factors such as 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 50-60 basis points for retail electric and 80-90 basis points for firm natural gas for the six months ended.

Weather-normalized Electric Sales Growth (Decline) — Year-To-Date Excluding Leap Day
•
PSCo’s flat residential sales reflect an increased number of customers and lower use per customer. The commercial and industrial (C&I) growth was mainly due to an increase in C&I customers and higher use per customer for both small and large C&I customers. The growth was primarily led by large customers that support the mining, oil and gas industries.
•
NSP-Minnesota’s residential sales growth reflects customer additions, partially offset by lower use per customer. Flat C&I sales resulted from lower sales to small customers, offset by customer growth. Increased sales to large customers in manufacturing and energy industries offset smaller declines in services and air transportation.
•
SPS’ residential fell largely due to lower use per customer. C&I sales growth reflects higher 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. The C&I growth was largely due to higher use per customer and an increase in small customers in the sand mining industry.

Weather-normalized Natural Gas Sales Growth (Decline) — Year-To-Date Excluding Leap Day
•
Across most natural gas 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 largely impacted by the fluctuation in the price of natural gas, coal and uranium used in the generation of electricity, but as a result of the design of fuel recovery mechanisms to recover current expenses, these price fluctuations have minimal impact on electric margin. The following table details the electric revenues and margin:
 
 
Three Months Ended June 30
 
Six Months Ended June 30
(Millions of Dollars)
 
2017
 
2016
 
2017
 
2016
Electric revenues
 
$
2,338

 
$
2,224

 
$
4,637

 
$
4,409

Electric fuel and purchased power
 
(919
)
 
(856
)
 
(1,844
)
 
(1,718
)
Electric margin
 
$
1,419

 
$
1,368

 
$
2,793

 
$
2,691



7

The following table summarizes the components of the changes in electric margin:
(Millions of Dollars)
 
Three Months Ended June 30
2017 vs. 2016
 
Six Months Ended June 30
2017 vs. 2016
Retail rate increases (Texas, Minnesota, New Mexico and Wisconsin)
 
$
34

 
$
75

Non-fuel riders
 
9

 
20

Higher conservation and DSM revenues (offset by higher expenses)
 
7

 
14

Retail sales growth, excluding weather impact
 
8

 
9

Decoupling (weather portion - Minnesota)
 
5

 
7

Wholesale transmission revenue, net of costs
 
(6
)
 
(13
)
Estimated impact of weather
 
(6
)
 
(13
)
Other, net 
 
—

 
3

Total increase in electric margin
 
$
51

 
$
102

 
Natural Gas Margin — Total natural gas expense tends to vary with changing sales requirements and the cost of natural gas purchases. However, due to the design of purchased natural gas cost recovery mechanisms for sales to retail customers, fluctuations in the cost of natural gas has minimal impact on natural gas margin. The following table details natural gas revenues and margin:
 
 
Three Months Ended June 30
 
Six Months Ended June 30
(Millions of Dollars)
 
2017
 
2016
 
2017
 
2016
Natural gas revenues
 
$
290

 
$
259

 
$
916

 
$
825

Cost of natural gas sold and transported
 
(114
)
 
(90
)
 
(479
)
 
(402
)
Natural gas margin
 
$
176

 
$
169

 
$
437

 
$
423


The following table summarizes the components of the changes in natural gas margin:
(Millions of Dollars)
 
Three Months Ended June 30
2017 vs. 2016
 
Six Months Ended June 30
2017 vs. 2016
Infrastructure and integrity riders
 
$
5

 
$
12

Higher conservation and DSM revenues (offset by higher expenses)
 
1

 
4

Estimated impact of weather
 
(1
)
 
(5
)
Other, net
 
2

 
3

Total increase in natural gas margin
 
$
7

 
$
14

 
O&M Expenses — O&M expenses decreased $18.8 million, or 3.2 percent, for the second quarter of 2017 and decreased $9.8 million, or 0.8 percent, year-to-date. The year-to-date decrease is primarily due to the timing of planned maintenance and overhauls at a number of generation facilities, offset by increases in employee benefits expense and the impact of previously deferred 2016 expenses associated with the Texas 2016 electric rate case (approximately $8 million) recognized in 2017 in connection with the settlement, offset by revenue recovery.

Conservation and DSM Expenses — Conservation and demand side management (DSM) expenses increased $8.9 million, or 16.0 percent, for the second quarter of 2017 and increased $19.0 million, or 16.8 percent, year-to-date. Increases were 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 $43.2 million, or 13.4 percent, for the second quarter of 2017 and increased $88.4 million, or 13.8 percent, year-to-date. The increase was primarily due to capital investments and prior year amortization of the excess depreciation reserve in Minnesota.

Allowance for Funds Used During Construction (AFUDC), Equity and Debt — AFUDC increased $2.6 million for the second quarter of 2017 and increased $4.8 million year-to-date. The increase was primarily due to higher average capital investments, particularly the Rush Creek wind project.


8

Interest Charges — Interest charges increased $1.2 million, or 0.7 percent, for the second quarter of 2017 and increased $10.7 million, or 3.4 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 $2.0 million for the second quarter of 2017 compared with the same period in 2016. The decrease was primarily due an increase in wind PTCs in 2017, an increase in permanent plant-related adjustments (e.g., AFUDC-equity) in 2017 and a tax expense for a state tax credit valuation allowance in 2016, partially offset by higher pretax earnings in the second quarter of 2017. The ETR was 31.1 percent for the second quarter of 2017 compared with 34.7 percent for the same period in 2016. The lower ETR in 2017 was primarily due to the adjustments referenced above.

Income tax expense decreased $14.0 million for the first six months of 2017 compared with the same period in 2016. The decrease in income tax expense was primarily due to an increase in wind PTCs in 2017, an increase in permanent plant-related adjustments (e.g., AFUDC-equity) in 2017 and a tax expense for a state tax credit valuation allowance in 2016, partially offset by higher pretax earnings in the six months ended June 30, 2017. The ETR was 32.0 percent for the first six months of 2017, compared to 34.7 percent for the first six 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)
 
June 30, 2017
 
Percentage of Total Capitalization
 
Dec. 31, 2016
 
Percentage of Total Capitalization
Current portion of long-term debt
 
$
0.5

 
2
%
 
$
0.3

 
1
%
Short-term debt
 
0.8

 
3

 
0.4

 
2

Long-term debt
 
14.1

 
53

 
14.2

 
55

Total debt
 
15.4

 
58

 
14.9

 
58

Common equity
 
11.1

 
42

 
11.0

 
42

Total capitalization
 
$
26.5

 
100
%
 
$
25.9

 
100
%

Credit Facilities — As of July 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

 
$
483

 
$
517

 
$
5

 
$
522

PSCo
 
700

 
3

 
697

 
1

 
698

NSP-Minnesota
 
500

 
145

 
355

 
1

 
356

SPS
 
400

 
101

 
299

 
—

 
299

NSP-Wisconsin
 
150

 
70

 
80

 
—

 
80

Total
 
$
2,750

 
$
802

 
$
1,948

 
$
7

 
$
1,955


(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 dependent in part 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.


9

As of July 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

2017 Planned 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;
•
Xcel Energy Inc. plans to issue approximately $300 million of senior unsecured bonds in the fourth quarter;
•
NSP-Minnesota plans to issue approximately $600 million of first mortgage bonds in the third quarter;
•
NSP-Wisconsin plans to issue approximately $100 million of first mortgage bonds in the fourth quarter; and
•
SPS plans to issue approximately $450 million of first mortgage bonds in the third quarter.

Financing plans are subject to change, depending on capital expenditures, internal cash generation, market conditions and other factors.

Note 4. Rates and Regulation

NSP-Minnesota – Minnesota 2016 Multi-Year Electric Rate Case — In June 2017, the Minnesota Public Utilities Commission (MPUC) issued a written order. NSP-Minnesota estimates the total rate increase to be approximately $245 million over the four-year period covering 2016-2019.

Key terms:
•
Four-year period covering 2016-2019;
•
Annual sales true-up;
•
Return on equity (ROE) of 9.2 percent and an equity ratio of 52.5 percent;
•
Nuclear related costs will not be considered provisional;
•
Continued use of all existing riders, however no new riders may be utilized during the four-year term;
•
Deferral of incremental 2016 property tax expense above a fixed threshold to 2018 and 2019;
•
Four-year stay-out provision for rate cases;
•
Property tax true-up mechanism for 2017-2019; and
•
Capital expenditure true-up mechanism for 2016-2019.
(Millions of Dollars, incremental)
 
2016
 
2017
 
2018
 
2019
 
Total
Revenues
 
$
74.99

 
$
59.86

 
$
—

 
$
50.12

 
$
184.97

NSP-Minnesota’s sales true-up
 
59.95

 
—

 
—

 
(0.20
)
 
59.75

   Total rate impact
 
$
134.94

 
$
59.86

 
$
—

 
$
49.92

 
$
244.72



10

NSP-Minnesota – Purchased Power Agreement (PPA) Terminations and Amendments — In June and July 2017, NSP-Minnesota filed requests with the MPUC and/or the North Dakota Public Service Commission for several initiatives including changes to four PPAs to reduce future costs for customers. These actions include the following:
•
The termination of a PPA with Benson Power LLC (Benson) for its 55 MW biomass facility in Benson, Minn. The termination of the Benson PPA requires Federal Energy Regulatory Commission approval and would result in payments of $95 million to terminate the PPA and acquire the facility, as well as additional expenditures of approximately $26 million to temporarily operate then close the facility.
•
The termination of a PPA with Laurentian Energy Authority I, LLC (Laurentian) for its 35 MW of biomass facilities in Hibbing and Virginia, Minn. The termination of the Laurentian PPA would result in $108.5 million of contract cancellation payments over six years.
•
The remaining two requested PPA changes involve a PPA extension for a 34 MW waste-to-energy facility at a price reflective of current market conditions and termination of another 12 MW waste-to-energy PPA.

NSP-Minnesota has requested recovery of all costs associated with these changes through the Fuel Clause Adjustment, including a return on NSP-Minnesota’s total investment in the Benson transaction over the remaining life of the current PPA through 2028. If approved, these actions together are intended to provide approximately $653 million in net cost savings to customers over the next 10 years.

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 January 2018. The rate filing is based on a 2018 forecast test year, a ROE of 10.0 percent, an equity ratio of 52.53 percent and a forecasted average net investment rate base of approximately $1.2 billion for the electric utility and $138.4 million for the natural gas utility.

Key dates in the procedural schedule are as follows:
•
Staff and intervenor testimony — Sept. 12, 2017;
•
Rebuttal testimony — Sept. 26, 2017;
•
Sur-rebuttal testimony — Oct. 3, 2017; and
•
Hearing — Oct. 5, 2017.

A PSCW decision is anticipated in the fourth quarter of 2017.

PSCo – Colorado Multi-Year Natural Gas Rate Case — In June 2017, PSCo filed a multi-year request with the Colorado Public Utilities Commission (CPUC) seeking to increase retail natural gas rates to recover capital investments and increased operating costs since PSCo’s previous case in 2015. The request, detailed below, is based on forecast test years, a 10.0 percent ROE and an equity ratio of 55.25 percent.
Revenue Request (Millions of Dollars)
 
2018
 
2019
 
2020
 
Total
New 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

 
N/A


(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 from customers through the rider. PSCo plans to request new PSIA rates for 2018 in November 2017. The recovery of new, 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.

Final rates are expected to be effective in February 2018. In conjunction with the multi-year base rate step increases, PSCo is also proposing a stay-out provision and an earnings test through the end of 2020.


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PSCo – Decoupling Filing — In July 2016, PSCo filed a request with the CPUC to approve a partial decoupling mechanism, which would adjust annual revenues based on changes in weather normalized average use per customer for the residential and small commercial classes. 

In July 2017, the CPUC issued a decision which approved the following key decisions regarding decoupling:
•
Effective Jan. 1, 2018 through December 2023 (subject to establishing new rates in the next electric rate case);
•
Applicable to the residential class and small commercial class;
•
Based on total class revenues (subject to establishing the base period in the next electric rate case);
•
Based on actual sales; and
•
Subject to a soft cap of 3 percent on any annual adjustment.
PSCo plans to seek reconsideration of the order.

PSCo – Advanced Grid Intelligence and Security — In July 2017, the CPUC approved PSCo’s certificate of public convenience and necessity for implementation of its advanced grid initiative. The project incorporates installing advanced meters, implementing hardware and software applications to allow the distribution system to operate at a lower voltage (integrated volt-var optimization) and installing communications infrastructure. These major projects are expected to improve customer experience, enhance grid reliability and enable the implementation of new and innovative programs and rate structures.

In June 2017, the CPUC approved a settlement, which delayed the advanced meter deployment from 2017-2021 to 2019-2024. The total capital cost of the project is currently estimated to be approximately $537 million for 2017-2024. As a result of the settlement, approximately $120 million of capital investment was deferred to 2022-2024.

Wind Development — During the first quarter of 2017, Xcel Energy announced plans to significantly expand its wind capacity by adding 1,550 MW of new wind generation at NSP-Minnesota and 1,230 MW at SPS. Previously, Xcel Energy received regulatory approval to build a 600 MW wind farm at PSCo.

In July 2017, the 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 MPUC approved an aggregate capital cap for the 750 MW of self-build projects, allowing NSP-Minnesota to include in rate base any savings versus a capital cost estimate for the projects. NSP-Minnesota would not recover capital costs in excess of the cap.

The Public Utility Commission of Texas (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.

Key dates in the PUCT procedural schedule are as follows:
•
Intervenor testimony — Oct. 2, 2017;
•
Staff testimony — Oct. 9, 2017;
•
Rebuttal testimony — Oct. 23, 2017; and
•
Hearing — Nov. 6 - Nov. 17, 2017.

Key dates in the NMPRC procedural schedule are as follows:
•
Staff and intervenor testimony — Oct. 24, 2017;
•
Rebuttal testimony — Nov. 9, 2017; and
•
Hearing — Nov. 28 - Dec. 1, 2017.

In total, Xcel Energy has proposed adding 3,380 MW of wind capacity by the end of 2020. Xcel Energy has filed to own and place in rate base 2,750 MW of these wind projects, while 630 MW would be through PPAs. These wind projects would qualify for 100 percent of the production tax credit and are intended to provide billions of dollars of savings to our customers and substantial environmental benefits. Projected savings/benefits assume fuel costs and generation mix consistent with those included in various commission approved resource plans and generation need filings.


12

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
Hale
 
478

 
TX
 
2019
 
SPS
 
Pending PUCT & NMPRC Approval
Sagamore
 
522

 
NM
 
2020
 
SPS
 
Pending PUCT & NMPRC Approval
Total Ownership
 
2,750

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
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

 
 
 
 
 
 
 
 

Xcel Energy’s total capital investment for the proposed wind ownership projects is approximately $4.2 billion for 2017-2020.

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

Xcel Energy 2017 Earnings Guidance — Xcel Energy’s 2017 GAAP and ongoing earnings guidance is $2.25 to $2.35 per share.(a) Key assumptions related to 2017 earnings are detailed below:
•
Constructive outcomes in all rate case and regulatory proceedings.
•
Normal weather patterns are experienced for the remainder of the year.
•
Weather-normalized retail electric utility sales are projected to increase 0 percent to 0.5 percent.
•
Weather-normalized retail firm natural gas sales are projected to increase 0 percent to 0.5 percent.
•
Capital rider revenue is projected to increase by $50 million to $60 million over 2016 levels. The change is largely due to the level of PTC, which flows back to customers.
•
O&M expenses are projected to be flat.
•
Depreciation expense is projected to increase approximately $180 million to $190 million over 2016 levels. The change in depreciation expense is largely due to changes in the amortization of the renewable development fund, which is offset in revenue and will not have an impact on earnings.
•
Property taxes are projected to increase approximately $0 million to $10 million over 2016 levels.
•
Interest expense (net of AFUDC — debt) is projected to increase $15 million to $25 million over 2016 levels.
•
AFUDC — equity is projected to increase approximately $5 million to $15 million from 2016 levels.
•
The ETR is projected to be approximately 31 percent to 33 percent. The change is largely due to the level of PTC, which flows back to customers.
•
Average common stock and equivalents are projected to be approximately 509 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 4 percent to 6 percent;
•
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.


13

XCEL ENERGY INC. AND SUBSIDIARIES
EARNINGS RELEASE SUMMARY (UNAUDITED)
(amounts in thousands, except per share data)
 
 
 
 
 
 
 
Three Months Ended June 30
 
 
2017
 
2016
Operating revenues:
 
 
 
 
Electric and natural gas
 
$
2,627,856

 
$
2,483,041

Other
 
17,072

 
16,808

Total operating revenues
 
2,644,928

 
2,499,849

 
 
 
 
 
Net income
 
$
227,256

 
$
196,795

 
 
 
 
 
Weighted average diluted common shares outstanding
 
509,135

 
509,490

 
 
 
 
 
Components of EPS — Diluted
 
 
 
 
Regulated utility
 
$
0.48

 
$
0.42

Xcel Energy Inc. and other costs
 
(0.03
)
 
(0.04
)
GAAP diluted EPS (a)
 
$
0.45

 
$
0.39

 
 
Six Months Ended June 30
 
 
2017
 
2016
Operating revenues:
 
 
 
 
Electric and natural gas
 
$
5,552,619

 
$
5,233,849

Other
 
38,731

 
38,273

Total operating revenues
 
5,591,350

 
5,272,122

 
 
 
 
 
Net income
 
$
466,533

 
$
438,107

 
 
 
 
 
Weighted average diluted common shares outstanding
 
508,955

 
509,311

 
 
 
 
 
Components of EPS — Diluted
 
 
 
 
Regulated utility
 
$
0.99

 
$
0.93

Xcel Energy Inc. and other costs
 
(0.07
)
 
(0.07
)
GAAP diluted EPS
 
$
0.92

 
$
0.86

Book value per share
 
$
21.91

 
$
21.07


(a) Amounts may not add due to rounding.




14