Market Overview

Xcel Energy Second Quarter 2018 Earnings Report

Share:
  • GAAP and ongoing 2018 second quarter earnings per share were $0.52
    compared with $0.45 per share in 2017.
  • Xcel Energy revised upward its 2018 guidance range to $2.41 to $2.51
    per share from its previous 2018 guidance range of $2.37 to $2.47 per
    share.

Xcel Energy Inc. (NASDAQ:XEL) today reported 2018 second quarter GAAP
and ongoing earnings of $265 million, or $0.52 per share, compared with
$227 million, or $0.45 per share in the same period in 2017.

GAAP and ongoing earnings were higher as a result of increased electric
and natural gas margins (excluding the impact of the Tax Cuts and Jobs
Act) which reflects favorable weather compared to last year and sales
growth, and increased allowance for funds used during construction,
partially offset by higher operating and maintenance expenses, as well
as depreciation and interest expenses.

"Xcel Energy achieved strong quarterly and year-to-date results and is
well-positioned to deliver earnings within our revised guidance range
for the year," said Ben Fowke, chairman, president and CEO of Xcel
Energy.

"We made outstanding progress with our industry-leading reductions in
carbon emissions while delivering exceptional value to customers and
stakeholders. In June, we filed our Colorado Energy Plan which, if
approved, will add 1,100 MW of wind, 700 MW of solar and 275 MW of
large-scale battery storage, as we retire one-third of our remaining
coal generation in the state. We've also achieved key regulatory
milestones and now have approvals for our new wind projects in Texas,
New Mexico and South Dakota," 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) 260-1479
International Dial-In: (334) 323-0522
Conference ID: 8039634
 

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 12:00 p.m. CDT on July 26 through 12:00 p.m. CDT on July 29.

 
Replay Numbers
US Dial-In:     (888) 203-1112
International Dial-In: (719) 457-0820
Access Code: 8039634
 

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 2018 earnings per share (EPS)
guidance, the Tax Cut and Jobs Act (TCJA)'s impact to Xcel Energy and
its customers, rate base, valuation of deferred tax assets and
liabilities, cash flow, credit metrics, long-term earnings per share and
dividend growth rate and potential regulatory options, as well as
assumptions and other statements identified in this document by the
words "anticipate," "believe," "could," "estimate," "expect," "intend,"
"may," "objective," "outlook," "plan," "project," "possible,"
"potential," "should," "will," "would" 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, 2017 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.

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

XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS
OF INCOME (UNAUDITED)

(amounts in millions, except per share
data)

  Three Months Ended June 30   Six Months Ended June 30
2018   2017 2018   2017
Operating revenues
Electric $ 2,348 $ 2,338 $ 4,617 $ 4,637
Natural gas 292 290 954 915
Other   18     17     38     39  
Total operating revenues 2,658 2,645 5,609 5,591
 
Operating expenses
Electric fuel and purchased power 935 919 1,867 1,844
Cost of natural gas sold and transported 104 114 479 479
Cost of sales — other 8 8 17 17
Operating and maintenance expenses 578 572 1,135 1,152
Conservation and demand side management expenses 69 65 139 132
Depreciation and amortization 377 366 760 731
Taxes (other than income taxes)   137     135     282     277  
Total operating expenses 2,208 2,179 4,679 4,632
 
Operating income 450 466 930 959
 
Other expense, net (2 ) (4 ) (1 ) (4 )
Equity earnings of unconsolidated subsidiaries 9 7 16 15
Allowance for funds used during construction — equity 26 16 49 31
 
Interest charges and financing costs

Interest charges — includes other financing costs of $6, $6, $12,
and $12, respectively

 

175 164 346 330
Allowance for funds used during construction — debt   (11 )   (8 )   (22 )   (15 )
Total interest charges and financing costs 164 156 324 315
 
Income before income taxes 319 329 670 686
Income taxes   54     102     114     219  
Net income $ 265   $ 227   $ 556   $ 467  
 
Weighted average common shares outstanding:
Basic 510 509 509 508
Diluted 510 509 510 509
 
Earnings per average common share:
Basic $ 0.52 $ 0.45 $ 1.09 $ 0.92
Diluted 0.52 0.45 1.09 0.92
 
Cash dividends declared per common share $ 0.38 $ 0.36 $ 0.76 $ 0.72
 

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.

Non-GAAP Financial Measures

The following discussion includes financial information prepared in
accordance with generally accepted accounting principles (GAAP), as well
as certain non-GAAP financial measures such as electric margin, natural
gas margin, ongoing earnings and ongoing diluted EPS. Generally, a
non-GAAP financial measure is a numerical measure of a company's
financial performance, financial position or cash flows that excludes
(or includes) amounts that are adjusted from the most directly
comparable measure calculated and presented in accordance with GAAP.
Xcel Energy's management uses non-GAAP measures internally for financial
planning and analysis, for reporting of results to the Board of
Directors, in determining whether performance targets are met for
performance-based compensation, and when communicating its earnings
outlook to analysts and investors. Non-GAAP financial measures are
intended to supplement investors' understanding of our operating
performance and should not be considered alternatives for financial
measures presented in accordance with GAAP. These measures are discussed
in more detail below and may not be comparable to other companies'
similarly titled non-GAAP financial measures.

Electric and Natural Gas Margins

Electric margin is presented as electric revenues less electric fuel and
purchased power expenses and natural gas margin is presented as natural
gas revenues less the cost of natural gas sold and transported. Expenses
incurred for electric fuel and purchased power and the cost of natural
gas sold and transported are generally recovered through various
regulatory recovery mechanisms, and as a result, changes in these
expenses are generally offset in operating revenues. Management believes
electric and natural gas margins provide the most meaningful basis for
evaluating our operations because they exclude the revenue impact of
fluctuations in these expenses. These margins can be reconciled to
operating income, a GAAP measure, by including other operating revenues,
cost of sales - other, operating and maintenance (O&M) expenses,
conservation and demand side management (DSM) expenses, depreciation and
amortization and taxes (other than income taxes).

Earnings Adjusted for Certain Items (Ongoing
Earnings and Diluted EPS)

Ongoing earnings reflect adjustments to GAAP earnings (net income) for
certain items. 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 these non-GAAP financial measures to evaluate and provide details of
Xcel Energy's core earnings and underlying performance. We believe these
measurements are useful to investors to evaluate the actual and
projected financial performance and contribution of our subsidiaries.
For the three and six months ended June 30, 2017 and 2018, there were no
such adjustments to GAAP earnings and therefore GAAP earnings equal
ongoing earnings for these periods.

Note 1. Earnings Per Share Summary

The following table summarizes GAAP and ongoing diluted EPS for Xcel
Energy:

   
Three Months Ended June 30 Six Months Ended June 30
Diluted Earnings (Loss) Per Share 2018   2017 2018   2017
Public Service Company of Colorado (PSCo) $ 0.24 $ 0.20 $ 0.50 $ 0.42
NSP-Minnesota 0.18 0.17 0.40 0.36
Southwestern Public Service Company (SPS) 0.11 0.07 0.18 0.12
NSP-Wisconsin 0.03 0.03 0.09 0.07
Equity earnings of unconsolidated subsidiaries   0.01     0.01     0.02     0.02  
Regulated utility (a) 0.58 0.48 1.19 0.99
Xcel Energy Inc. and other   (0.06 )   (0.03 )   (0.10 )   (0.07 )
Total $ 0.52   $ 0.45   $ 1.09   $ 0.92  
 

(a) Amounts may not add due to rounding.

 

Explanations for operating company results below exclude the offsetting
impacts on sales and income tax expense of the TCJA.

PSCo — Earnings increased $0.04 per share for the second
quarter of 2018 and increased $0.08 per share year-to-date. The
year-to-date increase in earnings was driven by higher electric and
natural gas margins due to the impact of an interim rate increase,
subject to refund, and favorable weather and increased allowance for
funds used during construction (AFUDC) primarily related to the Rush
Creek wind project. These items were partially offset by higher interest
charges and depreciation expense.

NSP-Minnesota — Earnings increased $0.01 per share for the
second quarter of 2018 and increased $0.04 per share year-to-date. The
year-to-date increase reflects lower operating and maintenance (O&M)
expenses and higher electric and natural gas margins due to favorable
weather. These positive factors were partially offset by higher
depreciation expense due to increased invested capital.

SPS — Earnings increased by $0.04 per share for the second
quarter of 2018 and increased $0.06 per share year-to-date. The
year-to-date increase was largely due to timing of O&M expenses, the
favorable impact of weather, sales growth and lower interest expense.

NSP-Wisconsin — Earnings were flat for the second quarter
of 2018 and increased $0.02 per share year-to-date. The year-to-date
increase was driven by higher natural gas and electric rates and the
impact of favorable weather, partially offset by additional depreciation
expense related to higher invested capital.

Xcel Energy Inc. and other — Xcel Energy Inc. and other
includes financing costs at the holding company and other items. The
decrease in earnings was primarily related to the tax impact related to
the TCJA as well as higher short-term debt levels.

The following table summarizes significant components contributing to
the changes in 2018 EPS compared with the same period in 2017:

   
Diluted Earnings (Loss) Per Share

Three Months
Ended June 30

Six Months
Ended June 30

GAAP and ongoing diluted EPS — 2017 $ 0.45 $ 0.92
 
Components of change — 2018 vs. 2017
Higher electric margins (excluding TCJA impacts) (a) 0.07 0.11
Higher natural gas margins (excluding TCJA impacts) (a) 0.03 0.07
Higher AFUDC — equity 0.02 0.04
(Higher) lower O&M expenses (0.01 ) 0.02
(Higher) lower ETR (excluding TCJA impacts) (a) (b) (0.01 ) 0.01
Higher depreciation and amortization (0.01 ) (0.03 )
Higher interest charges (0.01 ) (0.02 )
Higher taxes (other than income taxes) (0.01 )
Higher conservation and demand side management (DSM) expenses (c) (0.01 )
Other, net (0.01 ) (0.01 )
GAAP and ongoing diluted EPS — 2018 $ 0.52   $ 1.09  

 

(a) Estimated net impact of the TCJA, which includes
assumptions regarding future outcome of pending regulatory
proceedings:

Income tax — rate change and ARAM (net of deferral) $ 0.11 $ 0.21
Electric revenue reductions (0.08 ) (0.16 )
Natural gas revenue reductions (0.01 ) (0.02 )
Holding company — interest expense (0.02 ) (0.03 )
Total $   $  
 

(b) The ETR includes the impact of an additional $10
million and $15 million of wind Production Tax Credits (PTCs) for
the three and six months ended June 30, 2018, which are largely
flowed back to customers through electric margin.

(c) Offset by higher revenues.

 

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 June 30 Six Months Ended June 30
2018 vs.
Normal
  2017 vs.
Normal
  2018 vs.
2017
2018 vs.
Normal
  2017 vs.
Normal
  2018 vs.
2017
HDD 0.1 % (9.8 )% 9.4 % 0.3 % (8.5 )% 14.8 %
CDD 59.1 5.4 53.1 59.7 7.4 50.7
THI 108.1 (3.9 ) 125.3 107.4 (6.9 ) 125.1
 

Weather — The following table summarizes the estimated
impact of temperature variations on EPS compared with normal weather
conditions:

   
Three Months Ended June 30 Six Months Ended June 30
2018 vs.
Normal
  2017 vs.
Normal
  2018 vs.
2017
2018 vs.
Normal
  2017 vs.
Normal
  2018 vs.
2017
Retail electric $ 0.065 $ 0.005 $ 0.060 $ 0.067 $ (0.021 ) $ 0.088
Firm natural gas   0.002     (0.002 )   0.004     0.003     (0.020 )   0.023  
Total (before adjustments for decoupling) $ 0.067 $ 0.003 $ 0.064 $ 0.070 $ (0.041 ) $ 0.111
Decoupling Minnesota   (0.030 )       (0.030 )   (0.032 )   0.009     (0.041 )
Total (adjusted for decoupling) $ 0.037   $ 0.003   $ 0.034   $ 0.038   $ (0.032 ) $ 0.070  
 

Sales Growth (Decline) — The following tables summarize
Xcel Energy and its subsidiaries' sales growth (decline) for actual and
weather-normalized sales in 2018 compared to the same period in 2017:

 
Three Months Ended June 30
PSCo   NSP-Minnesota   SPS   NSP-Wisconsin   Xcel Energy
Actual
Electric residential (a) 3.9 % 11.9 % 12.2 % 9.1 % 8.7 %
Electric commercial and industrial 0.5 3.2 5.2 2.8 2.8
Total retail electric sales 1.6 5.5 6.4 4.3 4.4
Firm natural gas sales (3.2 ) 27.5 N/A 27.6 7.2
 
Three Months Ended June 30
PSCo NSP-Minnesota SPS NSP-Wisconsin Xcel Energy
Weather-normalized
Electric residential (a) 0.6 % 0.5 % 1.5 % (0.8 )% 0.6 %
Electric commercial and industrial (0.2 ) 0.8 4.1 1.3 1.3
Total retail electric sales 0.7 3.6 0.8 1.1
Firm natural gas sales 3.3 2.2 N/A 7.6 3.2
 
Six Months Ended June 30
PSCo NSP-Minnesota SPS NSP-Wisconsin Xcel Energy
Actual
Electric residential (a) 2.7 % 7.5 % 10.0 % 7.0 % 6.0 %
Electric commercial and industrial 1.1 1.8 5.2 3.8 2.6
Total retail electric sales 1.6 3.5 6.1 4.7 3.5
Firm natural gas sales 8.4 19.3 N/A 19.2 12.6
 
Six Months Ended June 30
PSCo NSP-Minnesota SPS NSP-Wisconsin Xcel Energy
Weather-normalized
Electric residential (a) 0.1 % (0.5 )% 1.3 % (1.1 )% (0.1 )%
Electric commercial and industrial 0.7 0.1 4.5 2.8 1.5
Total retail electric sales 0.5 (0.1 ) 4.0 1.7 1.1
Firm natural gas sales 2.3 1.2 N/A 3.3 2.0
 

(a) Extreme weather variations, windchill and cloud
cover may not be reflected in weather-normalized and actual growth
(decline) estimates.

 

Weather-normalized Electric Sales Growth (Decline)
— Year-To-Date

  • PSCo's higher residential sales reflect customer additions partially
    offset by lower use per customer. Commercial and industrial (C&I)
    growth was mainly due to an increase in customers and higher use for
    large C&I customers that support the fabricated metal, food products
    and metal mining industries.
  • NSP-Minnesota's residential sales decrease was a result of lower use
    per customer, partially offset by customer growth. The increase in C&I
    sales was a result of an increase in customers partially offset by
    lower use per customer. Increased sales to large customers in
    manufacturing and energy offset declines in services, largely related
    to energy efficiency.
  • SPS' residential sales grew largely due to higher use per customer and
    customer additions. The increase in C&I sales was driven by the oil
    and natural gas industry in the Permian Basin.
  • NSP-Wisconsin's residential sales decline was primarily attributable
    to lower use per customer partially offset by customer additions. C&I
    growth was largely due to higher use per large customer, customer
    additions and increased sales to small and large sand mining customers
    and large customers in the energy industries.

Weather-normalized Natural Gas Sales Growth —
Year-To-Date

  • Across most service territories, higher natural gas sales reflect an
    increase in the number of customers combined with increasing 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 June 30 Six Months Ended June 30
(Millions of Dollars) 2018   2017 2018   2017
Electric revenues before impact of the TCJA $ 2,422 $ 2,338 $ 4,755 $ 4,637
Electric fuel and purchased power before impact of the TCJA   (939 )   (919 )   (1,873 )   (1,844 )
Electric margin before impact of the TCJA $ 1,483 $ 1,419 $ 2,882 $ 2,793
Impact of the TCJA (offset as a reduction in income tax expense)   (70 )       (132 )    
Electric margin $ 1,413   $ 1,419   $ 2,750     2,793  
 

The following table summarizes the components of the changes in electric
margin:

   
(Millions of Dollars)

Three Months
Ended June 30,
2018 vs.
2017

Six Months
Ended June 30,
2018 vs. 2017

Estimated impact of weather (net of Minnesota decoupling) $ 24 $ 39
Purchased capacity costs 12 23
Retail sales growth (including Minnesota decoupling and sales
true-up)
10 14
Retail rate increase (Wisconsin, Texas and Michigan) 5 12
Non-fuel riders 7 8
Other, net   6     (7 )
Total increase in electric margin before impact of the TCJA $ 64 $ 89
Impact of the TCJA (offset as a reduction in income tax expense)   (70 )   (132 )
Total decrease in electric margin $ (6 ) $ (43 )
 

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 June 30 Six Months Ended June 30
(Millions of Dollars) 2018   2017 2018   2017
Natural gas revenues before impact of the TCJA $ 301 $ 290 $ 974 $ 915
Cost of natural gas sold and transported   (104 )   (114 )   (479 )   (479 )
Natural gas margin before impact of the TCJA $ 197 $ 176 $ 495 $ 436
Impact of the TCJA (offset as a reduction in income tax expense)   (9 )       (20 )    
Natural gas margin $ 188   $ 176   $ 475   $ 436  
 

The following table summarizes the components of the changes in natural
gas margin:

   
(Millions of Dollars)

Three Months
Ended June 30,
2018 vs.
2017

Six Months
Ended June 30,
2018 vs. 2017

Retail rate increase (Colorado - interim, subject to refund,
Wisconsin and Michigan)
$ 12 $ 24
Estimated impact of weather 3 18
Infrastructure and integrity riders 5 9
Sales growth 1 3
Other, net       5  
Total increase in natural gas margin before impact of the TCJA $ 21 $ 59
Impact of the TCJA (offset as a reduction in income tax expense)   (9 )   (20 )
Total increase in natural gas margin $ 12   $ 39  
 

O&M Expenses — O&M expenses increased $6 million, or
1.0 percent, for the second quarter of 2018 and decreased $17 million,
or 1.5 percent, year-to-date. The year-to-date change largely reflects
expense timing. The significant changes are summarized in the table
below:

   
(Millions of Dollars)

Three Months
Ended June 30,
2018 vs.
2017

Six Months
Ended June 30,
2018 vs. 2017

Nuclear plant operations and amortization $ (6 ) $ (16 )
Plant generation costs 8
Other, net   4     (1 )
Total increase (decrease) in O&M expenses $ 6   $ (17 )
 
  • Nuclear plant operations and amortization expenses are lower largely
    reflecting expense timing, savings initiatives and reduced refueling
    outage costs.
  • Plant generation costs increased in the second quarter primarily due
    to the timing of planned maintenance and overhauls at a number of
    generation facilities.

Conservation and DSM Expenses — Conservation and demand
side management (DSM) expenses increased $4 million, or 6.2 percent, for
the second quarter of 2018 and increased $7 million, or 5.3 percent,
year-to-date. The year-to-date increase was primarily due to higher
recovery rates in Colorado. Increased participation in Minnesota natural
gas conservation programs was partially offset by lower recovery rates.
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 $11 million, or 3.0 percent, for the second
quarter of 2018 and increased $29 million, or 4.0 percent, year-to-date.
The increase was primarily driven by capital expenditures due to planned
system investments and amortization of certain regulatory assets,
partially offset by lower depreciation rates in Minnesota.

Taxes (Other than Income Taxes) — Taxes (other than income
taxes) increased $2 million, or 1.5 percent, for the second quarter of
2018 and increased $5 million, or 1.8 percent, year-to-date. The
increase was primarily due to higher property taxes in Colorado.

AFUDC, Equity and Debt — AFUDC increased $13 million for
the second quarter of 2018 and $25 million year-to-date. The increase
was primarily due to the Rush Creek wind project in Colorado and other
capital investments.

Interest Charges — Interest charges increased $11 million,
or 6.7 percent, for the second quarter of 2018 and increased $16
million, or 4.8 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 $48 million
for the second quarter of 2018 compared with the same period in 2017.
The decrease and corresponding lower ETR was primarily driven by a lower
federal tax rate due to the TCJA, an increase in plant-related
regulatory differences related to ARAM(a) (net of deferrals)
and an increase in wind PTCs. The ETR was 16.9 percent for the second
quarter of 2018 compared with 31.0 percent for the same period in 2017.

Income tax expense decreased $105 million for the first six months of
2018 compared with the same period in 2017. The decrease and
corresponding lower ETR was primarily driven by a lower federal tax rate
due to the TCJA, an increase in plant-related regulatory differences
related to ARAM (net of deferrals), and an increase in wind PTCs. The
ETR was 17.0 percent for the first six months of 2018 compared with 31.9
percent for the same period in 2017.

   
Three Months Ended June 30 Six Months Ended June 30
2018   2017   2018 vs 2017   2018   2017   2018 vs 2017
Federal statutory rate 21.0 % 35.0 % (14.0 )% 21.0 %   35.0 %   (14.0 )%
State tax, net of federal tax effect 5.1 % 4.1 % 1.0 % 5.0 % 4.1 % 0.9 %
Increases (decreases) in tax from:
Wind production tax credits (5.4 ) (4.5 ) (0.9 ) (5.8 ) (4.2 ) (1.6 )
Regulatory differences - ARAM (5.4 ) (0.1 ) (5.3 ) (5.6 ) (0.1 ) (5.5 )
Regulatory differences - ARAM deferral (b) 4.0 4.0 4.8 4.8
Regulatory differences - other utility plant items (1.0 ) (0.9 ) (0.1 ) (1.0 ) (0.7 ) (0.3 )
Other, net (1.4 ) (2.6 ) 1.2     (1.4 ) (2.2 ) 0.8  
Effective income tax rate 16.9 % 31.0 % (14.1 )%   17.0 % 31.9 % (14.9 )%
 

(a) The average rate assumption method (ARAM); a method
to flow back excess deferred taxes to customers.

(b) The ARAM deferral may decrease during the year,
which would result in a reduction to tax expense with a
corresponding reduction to revenue, as we receive further
direction from our regulatory commissions regarding the return of
excess deferred taxes to our customers resulting from the TCJA.

 

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

Following is the capital structure of Xcel Energy:

       
(Millions of Dollars) June 30, 2018

Percentage of Total
Capitalization

Dec. 31, 2017

Percentage of Total
Capitalization

Current portion of long-term debt $ 856 3 % $ 457 2 %
Short-term debt 682 2 814 3
Long-term debt   15,311   54     14,520   53  
Total debt 16,849 59 15,791 58
Common equity   11,650   41     11,455   42  
Total capitalization $ 28,499   100 % $ 27,246   100 %
 

Credit Facilities As of July 23,
2018, 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. $ 1,250 $ 464 $ 786 $ 1 $ 787
PSCo 700 4 696 174 870
NSP-Minnesota 500 37 463 1 464
SPS 400 144 256 1 257
NSP-Wisconsin   150     48       102       1       103
Total $ 3,000   $ 697     $ 2,303     $ 178     $ 2,481
 

(a) These credit facilities expire in June 2021, with
the exception of Xcel Energy's Inc.'s 364-day term loan agreement
entered into in December 2017.

(b) Includes outstanding commercial paper, term loan
borrowings 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 July 23, 2018, 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
 

2018 Planned Financing Activity — During 2018, Xcel Energy
Inc. and its utility subsidiaries issued and anticipate issuing the
following:

  • PSCo issued $350 million of 3.70 percent first mortgage green bonds
    due June 15, 2028 and $350 million of 4.10 percent first mortgage
    green bonds due June 15, 2048;
  • Xcel Energy Inc. issued $500 of 4.0 percent senior notes due June 15,
    2028;
  • NSP-Wisconsin plans to issue approximately $200 million of first
    mortgage bonds; and
  • SPS plans to issue approximately $250 million of first mortgage bonds.

Xcel Energy also plans to issue approximately $300 million of
incremental equity in 2018 in addition to approximately $75 million of
equity to be issued through the dividend reinvestment program and
benefit programs.

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
– Wind Development
— In 2017, the Minnesota Public Utility
Commission (MPUC) approved NSP-Minnesota's proposal to add 1,550
megawatts (MW) of new wind generation including ownership of 1,150 MW of
wind generation. An order from the NDPSC is expected later in 2018.

Dakota Range — In April 2018, the MPUC approved
NSP-Minnesota's petition to build and own the Dakota Range, a 300
megawatt (MW) wind project in South Dakota. The project is expected to
be placed into service by the end of 2021 and qualify for 80 percent of
the PTC. NSP-Minnesota's total capital investment for the Dakota Range
is expected to be approximately $350 million. A North Dakota Public
Service Commission decision is expected later in 2018.

PSCo – Colorado 2017 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
approximately $139 million over three years. The request, detailed
below, was based on forecast test years (FTY), a 10.0 percent return on
equity (ROE) and an equity ratio of 55.25 percent.

       
Revenue Request (Millions of Dollars) 2018 2019 2020 Total
Revenue request $ 63 $ 33 $ 43 $ 139
Pipeline System Integrity Adjustment (PSIA) rider conversion to base
rates (a)
      94         94
Total $ 63   $ 127   $ 43   $ 233
 
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 revenue as these
costs are already being recovered through the rider. 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 February 2018, the administrative law judge (ALJ) approved a TCJA
settlement agreement between PSCo and the CPUC Staff, which reduced
provisional rates by $20 million, based on a preliminary TCJA estimate
of $29 million. The settlement remains subject to CPUC approval. The
impact of the TCJA will be trued-up later in 2018. Annualized
provisional rates of approximately $43 million were effective March 1,
2018.

In May 2018, the ALJ issued an interim recommended decision which would
result in a 2018 overall rate increase of approximately $46 million,
prior to the impact of the TCJA. The estimated rate increase reflects a
2016 HTY with a 13-month average rate base of $1.6 billion, a ROE of
9.35 percent and an equity ratio of 54.2 percent.

On July 12, 2018, the CPUC deliberated and approved several of the ALJ's
recommendations including application of a 2016 historic test year
(HTY), with a 13-month average rate base, and an ROE of 9.35 percent.
The CPUC adjusted the equity ratio to 54.6 percent and provided no
return on the prepaid pension and retiree medical asset. With these
adjustments the total rate increase, prior to TCJA impacts, would be $47
million.

The estimated impact of the CPUC's decision is presented below:

 
(Millions of Dollars)

Estimated Impact of the
CPUC's Decision

Filed 2018 revenue request based on a FTY $ 63
Impact of the change in test year   5  
PSCo's deficiency based on a 2016 HTY - year-end rate base 68
 
Adjustments:
ROE at 9.35 percent (9 )
Equity ratio of 54.6 percent (2 )
Change in amortization period for certain regulatory assets,
including a debt return
(6 )
Loss of return on prepaid pension and retiree medical (4 )
Change from 2016 year-end to average rate base (5 )
Other, net   5  
Total adjustments (21 )
 
Total rate increase, prior to the TCJA impacts $ 47  
 

The CPUC is expected to issue its order on the natural gas rate case in
the third quarter of 2018. The CPUC is expected to issue a final
decision with the impacts of the TCJA, later in 2018.

PSIA Rider
In June 2018, PSCo
filed for an extension to the PSIA rider through 2020. PSCo requested an
expedited decision by Nov. 15, 2018. PSCo also requested authorization
to roll-in recovery of costs in the current PSIA rider into base rates
effective Jan. 1, 2019, if the CPUC rejects the proposed PSIA extension
or fails to rule on the request by the end of 2018.

Additionally, PSCo reduced PSIA revenues by approximately $8 million for
2018 for the impact of the TCJA, effective May 1, 2018. PSIA revenues
are subject to the CPUC approved PSIA rider true-up process.

PSCo – Colorado Energy Plan (CEP) — In 2016, PSCo filed
its 2016 Electric Resource Plan (ERP) which included the estimated need
for additional generation resources through spring of 2024. In 2017,
PSCo filed an updated capacity need with the CPUC of 450 MW in 2023.

In 2017, PSCo and various other stakeholders filed a stipulation
agreement proposing the CEP, an alternative plan that increases PSCo's
potential capacity need up to 1,110 MW due to the proposed retirement of
two coal units.

In June 2018, PSCo filed its 120-day update report with the CPUC which
includes multiple portfolios and recommends a preferred CEP portfolio.
PSCo's investment under the preferred CEP portfolio would be
approximately $1 billion, including investment in transmission to
support the significant increase in renewable generation in the state.
The preferred CEP portfolio includes the following additions as well as
the retirement of the two coal-fired generation units:

       
Total Capacity PSCo's Ownership
Wind generation 1,100 MW 500 MW
Solar generation 700 MW
Battery storage 275 MW
Natural gas generation 380 MW 380 MW
 

On July 13, 2018, the Independent Evaluator (IE) for the ERP filed their
report on the process, modeling and evaluation of the various offers
received through the RFP process. Generally, the IE report was favorable
to the process employed and the outcomes included in the modeling.
Certain recommendations for future ERP processes were provided with a
primary focus regarding enhanced modeling of new resource types such as
battery storage.

On July 23, 2018, various stakeholders commented on the 120-day update
report for the ERP and the CEP. Many community, advocate and developer
interests supported the CEP, while certain stakeholders opposed the CEP
and the associated early coal plant retirements. The CPUC staff
indicated that PSCo's preferred CEP plan is a valid option, but
expressed concerns on the saving assumptions, complexity of modeling and
the utilization of production tax credits.

A CPUC decision is anticipated in September 2018.

SPS – Texas 2017 Electric Rate Case — In 2017, SPS filed a
$54 million, or 5.8 percent, retail electric, non-fuel base rate
increase case in Texas with each of its Texas municipalities and the
Public Utility Commission of Texas (PUCT). The request was based on a
HTY ended June 30, 2017, a requested ROE of 10.25 percent, an electric
rate base of approximately $1.9 billion and an equity ratio of 53.97
percent. The request also reflects the acceleration of depreciation
lives for the two generating units at the Tolk Generating Station from
2042 and 2045 to 2032.

In May 2018, SPS filed rebuttal testimony and revised its request to an
overall increase in the annual base rate revenue of approximately $32
million, or 5.9 percent, net of the TCJA (approximately $32 million
after adjusting for a 58 percent equity ratio) and other adjustments.
This request would be equivalent to approximately $17 million after
adjusting for the Transmission Cost Recovery Factor (TCRF) rider.

In June 2018, SPS, the PUCT Staff and various intervenors reached a
settlement, which results in no overall change to SPS' revenues after
adjusting for the impact of the TCJA and the lower costs of long-term
debt. The following are key terms:

  • The ability to use an equity ratio that reflects SPS' actual capital
    structure, which SPS has informed the parties it intends to be 57
    percent to mitigate the impact of TCJA on credit metrics;
  • A 9.5 percent ROE for the calculation of AFUDC;
  • TCRF rider will remain in effect;
  • SPS will accelerate depreciation rates for the Tolk Generating Station
    Units 1 and 2 by 50 percent of the original request; and
  • SPS agrees that it will file its next base rate case no later than
    Dec. 31, 2019.

A reconciliation of the settlement is as follows:

 
(Millions of Dollars)
Original base rate request $ 69
Base rate revenue to be recovered through TCRF   (15 )
Net revenue request 54
Adjustment for TCJA and other items   (37 )
Requested incremental revenue 17
Unspecified settlement adjustments (13 )
Accelerated depreciation (Tolk plant)   (4 )
SPS' net revenue change $  
 

Under the terms of the settlement, the final rates would not change from
the current rates. However, SPS would be permitted to surcharge
customers for unrecovered TCRF charges that were not billed during the
period of Jan. 23, 2018 through June 10, 2018. A PUCT decision is
expected in the third quarter of 2018.

SPS – New Mexico 2017 Electric Rate Case — In October
2017, SPS filed an electric rate case with the New Mexico Public
Regulation Commission (NMPRC) seeking an increase in base rates of
approximately $43 million. The request was based on a HTY ended June 30,
2017, a ROE of 10.25 percent, an equity ratio of 53.97 percent, a 35
percent federal income tax rate and a rate base of approximately $885
million, including rate base additions through Nov. 30, 2017.

In May 2018, SPS reduced its request to $27 million, net of the TCJA
(approximately $11 million) and other adjustments, based on a requested
ROE of 10.25 percent and an equity ratio of 58.0 percent.

In June 2018, the New Mexico Hearing Examiner issued a recommended
decision proposing an increase of $12 million, based on a ROE of 9.4
percent and an equity ratio of 53.97 percent. She also denied SPS'
requests to shorten depreciation lives related to Tolk Units 1 and 2 and
Cunningham Unit 1. The Hearing Examiner rejected intervenor proposals to
refund the impacts of the TCJA back to Jan. 1, 2018.

The following table summarizes certain parties' proposed modifications
to SPS' request, SPS' revised request, and the Hearing Examiner's
recommendation:

       
(Millions of Dollars)

NMPRC Staff
Testimony

NMAG
Testimony

SPS Rebuttal
Testimony

Hearing
Examiner's
Recommendation

SPS request $ 43 $ 43 $ 43 $ 43
Reduction to request for the impact of the TCJA   (11 )   (11 )   (11 )   (11 )
SPS request, including the impact of the TCJA 32 32 32 32
 
ROE (4 ) (6 ) (5 )
Capital structure (7 ) (3 ) (3 )
Depreciation lives (Tolk and Cunningham plants) (3 ) (3 ) (3 )
Disallow rate case expenses (2 ) (3 ) (1 )
Regional transmission revenue and expense (adjustment for the impact
of the TCJA):
Impact of the TCJA (3 ) (1 )
Aligning costs with transmission plant in rate base (1 )
Post test year plant (updated to actual) (1 ) (2 ) (3 )
Excess generation adjustment (1 ) (1 )
Other, net   (4 )   (4 )   (1 )   (6 )
Recommended rate increase $ 11   $ 7   $ 27   $ 12  
 
ROE 9.0 % 9.21 % 10.25 % 9.4 %
Equity ratio 52.0 % 53.97 % 58.0 % 53.97 %
 

SPS anticipates a decision and implementation of final rates in the
third quarter of 2018.

SPS – Wind Proposals — In 2017, SPS filed proposals with
the NMPRC and the PUCT to build, own and operate 1,000 MW of new wind
generation through two wind farms (the Hale wind project in Texas and
the Sagamore wind project in New Mexico) for a cost of approximately
$1.6 billion. In addition, the proposal includes a purchased power
agreement for 230 MW of wind. SPS' wind proposal was approved by both
the NMPRC and the PUCT during 2018.

Note 5. Tax Cuts and Jobs Act

Tax Reform Regulatory Proceedings

The specific impacts of the TCJA on customer rates are subject to
regulatory approval. Each of the states in Xcel Energy's service areas
have opened dockets to address the impacts of the TCJA.

NSP-Minnesota — In April 2018, NSP-Minnesota updated the
estimated impact of the TCJA, which reflected an overall reduction in
2018 revenue requirements of approximately $136 million for electric and
$7 million for natural gas, and made recommendations regarding the
sharing of those benefits with ratepayers. The proposed electric options
included: customer refunds and rider impacts of $68 million, deferral of
$44 million to allow for a rate case stay-out for 2020, acceleration of
depreciation for the King coal plant of $22 million and low income
program funding of $2 million. The proposed natural gas options included
customer refunds and rider impacts of $3 million, with the remaining
TCJA benefits deferred to mitigate increased costs in the next natural
gas rate case.

In June 2018, the Minnesota Department of Commerce (DOC) recommended to
implement refunds for the current tax impacts (approximately $90
million), and incorporate the deferred tax impacts (approximately $53
million) in NSP-Minnesota's next electric and gas rate cases. A decision
from the MPUC is expected in 2018.

NSP-Minnesota North and South Dakota — In
February 2018, NSP-Minnesota proposed using the reduced revenue
requirements from the TCJA to defer planned future rate filings in North
Dakota and South Dakota. In July 2018, the South Dakota Public Utilities
Commission (SDPUC) approved a settlement which proposed a one-time
customer refund of $11 million for the 2018 impact of the TCJA and a
two-year rate case moratorium.

NSP-Wisconsin — In May 2018, the Public Service Commission
of Wisconsin issued its final order which requires customer refunds of
$27 million and defers approximately $5 million until NSP-Wisconsin's
next rate case proceeding.

NSP-Wisconsin Michigan — In May 2018, the
Michigan Public Service Commission approved electric and natural gas tax
reform settlement agreements. Most of the electric TCJA benefits were
included in NSP-Wisconsin's recently approved Michigan 2018 electric
base rate case. Natural gas TCJA benefits are to be returned to
customers commencing in July 2018.

PSCo Colorado Natural Gas — In February
2018, the ALJ approved PSCo and the CPUC Staff's TCJA settlement
agreement which includes a $20 million reduction to provisional rates
effective March 1, 2018. A final true-up would provide customers the
full net benefit of the TCJA retroactive to January 2018.

PSCo Colorado Electric — In April 2018,
PSCo, the CPUC Staff and the Office of Consumer Counsel filed a TCJA
settlement agreement that recommended a customer refund of $42 million
in 2018, with the remainder of $59 million be used to accelerate the
amortization of an existing prepaid pension asset. In June 2018, the
CPUC approved the customer refund of $42 million, effective June 1,
2018. The CPUC set the decision regarding the remainder of the $59
million for hearing before an ALJ. Revisions to the TCJA settlement will
be addressed in a future electric rate case.

SPSTexas — In June 2018, SPS, the PUCT
Staff and various intervenors reached a settlement in the Texas electric
rate case which included the impacts of the TCJA. The settlement
reflects no change in customer rates or refunds and SPS' actual capital
structure, which SPS has informed the parties it intends to be a 57
percent equity ratio to offset the negative impacts on its credit
metrics and potentially its credit ratings.

SPSNew Mexico — In February 2018, SPS
indicated that the TCJA would reduce revenue requirements by
approximately $11 million and recommended increasing its equity ratio to
58 percent to offset the negative impact of the TCJA on its credit
metrics and potentially its credit ratings. The impact of the TCJA is
expected to be addressed as part of SPS' pending New Mexico electric
rate case, as discussed in Note 4.

Note 6. Xcel Energy Earnings Guidance
and Long-Term EPS and Dividend Growth Rate Objectives

Xcel Energy 2018 Earnings Guidance — Xcel Energy revised
upward its 2018 guidance range to $2.41 to $2.51 per share from its
previous 2018 guidance range of $2.37 to $2.47 per share.(a) Key
assumptions:

  • Constructive outcomes in all rate case and regulatory proceedings.
  • Normal weather patterns for the remainder of the year.
  • Weather-normalized retail electric sales are projected to be within a
    range of 0 percent to 1.0 percent over 2017 levels.
  • Weather-normalized retail firm natural gas sales are projected to
    increase 1.0 percent to 1.5 percent over 2017 levels.
  • Capital rider revenue is projected to increase $40 million to $50
    million over 2017 levels. PTCs are flowed back to customers, primarily
    through capital riders and reductions to electric margin.
  • O&M expenses are projected to increase 1 percent to 2 percent over
    2017 levels.
  • Depreciation expense is projected to increase approximately $100
    million to $110 million over 2017 levels.
  • Property taxes are projected to increase approximately $10 million to
    $20 million over 2017 levels.
  • Interest expense (net of AFUDC - debt) is projected to increase $30
    million to $40 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 15 percent to 17 percent.
    This range may decrease to 8 percent to 10 percent as we receive
    clarity and direction from our commissions as to the treatment of
    excess deferred taxes that resulted from the TCJA. A reduction to the
    ETR resulting from the flowback of excess deferred taxes would be
    offset by a correlated reduction to revenue. Additionally, the lower
    ETR for 2018 compared to 2017 reflects additional PTCs which are
    flowed back to customers through margin.

(a) 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. 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;
  • 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.

XCEL ENERGY INC. AND SUBSIDIARIES
EARNINGS RELEASE
SUMMARY (UNAUDITED)

(amounts in millions, except per share
data)

   
Three Months Ended June 30
2018 2017
Operating revenues:
Electric and natural gas $ 2,640 $ 2,628
Other   18     17  
Total operating revenues 2,658 2,645
 
Net income $ 265 $ 227
 
Weighted average diluted common shares outstanding 510 509
 

Components of EPS — Diluted

Regulated utility $ 0.58 $ 0.48
Xcel Energy Inc. and other costs   (0.06 )   (0.03 )
GAAP and ongoing diluted EPS $ 0.52   $ 0.45  
 
Six Months Ended June 30
2018 2017
Operating revenues:
Electric and natural gas $ 5,571 $ 5,552
Other   38     39  
Total operating revenues 5,609 5,591
 
Net income $ 556 $ 467
 
Weighted average diluted common shares outstanding 510 509

 

Components of EPS — Diluted

Regulated utility $ 1.19 $ 0.99
Xcel Energy Inc. and other costs   (0.10 )   (0.07 )
GAAP and ongoing diluted EPS   1.09     0.92  
Book value per share $ 22.90 $ 21.91
 

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