-
GAAP and ongoing 2018 first quarter earnings per share were $0.57
compared with $0.47 per share in 2017.
-
Xcel Energy reaffirms 2018 GAAP and ongoing earnings guidance of $2.37
to $2.47 per share.
Xcel Energy Inc. (NASDAQ: XEL) today reported 2018 first quarter GAAP
and ongoing earnings of $291 million, or $0.57 per share, compared with
$239 million, or $0.47 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 reflect favorable weather compared to last year, timing of
operating and maintenance expenses and an increased allowance for funds
used during construction, partially offset by higher depreciation and
interest expenses.
“Xcel Energy delivered solid first-quarter results and is
well-positioned to achieve our overall objectives for 2018,” said Ben
Fowke, chairman, president and CEO of Xcel Energy. “We are happy with
our progress in executing our industry-leading wind energy expansion
that puts us on pace to achieve over a 60 percent reduction in carbon
across our eight states by 2030 while keeping customer bills affordable
and helping our stakeholders achieve their policy goals.”
“We combined our financial performance with outstanding operational
performance. In April, two of our states weathered epic storms; a
historic blizzard buried Minnesota with record snow totals and days
later, a fierce wind storm battered Colorado with hurricane-force gusts.
Our crews worked around the clock, facing challenging conditions to get
the lights back on for thousands of our customers and communities, and
demonstrated why I believe we have the best storm response in the
industry,” concluded Fowke.
At 9:00 a.m. CDT today, Xcel Energy will host a conference call to
review financial results. To participate in the call, please dial- in 5
to 10 minutes prior to the start and follow the operator’s instructions.
US Dial-In:
|
|
|
(800) 967-7137
|
International Dial-In:
|
|
|
(719) 457-2735
|
Conference ID:
|
|
|
3737478
|
|
|
|
|
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 April 26 through 11:00 p.m. CDT on April 29.
Replay Numbers
|
|
|
|
US Dial-In:
|
|
|
(888) 203-1112
|
International Dial-In:
|
|
|
(719) 457-0820
|
Access Code:
|
|
|
3737478
|
|
|
|
|
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 March 31
|
|
|
2018
|
|
2017
|
Operating revenues
|
|
|
|
|
Electric
|
|
$
|
2,270
|
|
|
$
|
2,299
|
|
Natural gas
|
|
662
|
|
|
626
|
|
Other
|
|
19
|
|
|
21
|
|
Total operating revenues
|
|
2,951
|
|
|
2,946
|
|
|
|
|
|
|
Operating expenses
|
|
|
|
|
Electric fuel and purchased power
|
|
932
|
|
|
925
|
|
Cost of natural gas sold and transported
|
|
375
|
|
|
365
|
|
Cost of sales — other
|
|
8
|
|
|
9
|
|
Operating and maintenance expenses
|
|
557
|
|
|
580
|
|
Conservation and demand side management expenses
|
|
71
|
|
|
68
|
|
Depreciation and amortization
|
|
383
|
|
|
365
|
|
Taxes (other than income taxes)
|
|
145
|
|
|
142
|
|
Total operating expenses
|
|
2,471
|
|
|
2,454
|
|
|
|
|
|
|
Operating income
|
|
480
|
|
|
492
|
|
|
|
|
|
|
Other income, net
|
|
1
|
|
|
1
|
|
Equity earnings of unconsolidated subsidiaries
|
|
6
|
|
|
8
|
|
Allowance for funds used during construction — equity
|
|
23
|
|
|
14
|
|
|
|
|
|
|
Interest charges and financing costs
|
|
|
|
|
Interest charges — includes other financing costs of $6 and $6,
respectively
|
|
171
|
|
|
166
|
|
Allowance for funds used during construction — debt
|
|
(11
|
)
|
|
(7
|
)
|
Total interest charges and financing costs
|
|
160
|
|
|
159
|
|
|
|
|
|
|
Income before income taxes
|
|
350
|
|
|
356
|
|
Income taxes
|
|
59
|
|
|
117
|
|
Net income
|
|
$
|
291
|
|
|
$
|
239
|
|
|
|
|
|
|
Weighted average common shares outstanding:
|
|
|
|
|
Basic
|
|
509
|
|
|
508
|
|
Diluted
|
|
509
|
|
|
509
|
|
|
|
|
|
|
Earnings per average common share:
|
|
|
|
|
Basic
|
|
$
|
0.57
|
|
|
$
|
0.47
|
|
Diluted
|
|
0.57
|
|
|
0.47
|
|
|
|
|
|
|
Cash dividends declared per common share
|
|
$
|
0.38
|
|
|
$
|
0.36
|
|
|
|
|
|
|
|
|
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 months ended March 31, 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 March 31
|
Diluted Earnings (Loss) Per Share
|
|
2018
|
|
2017
|
Public Service Company of Colorado (PSCo)
|
|
$
|
0.26
|
|
|
$
|
0.22
|
|
NSP-Minnesota
|
|
0.22
|
|
|
0.19
|
|
Southwestern Public Service Company (SPS)
|
|
0.07
|
|
|
0.05
|
|
NSP-Wisconsin
|
|
0.06
|
|
|
0.04
|
|
Equity earnings of unconsolidated subsidiaries
|
|
0.01
|
|
|
0.01
|
|
Regulated utility
|
|
0.62
|
|
|
0.51
|
|
Xcel Energy Inc. and other
|
|
(0.05
|
)
|
|
(0.04
|
)
|
Total
|
|
$
|
0.57
|
|
|
$
|
0.47
|
|
|
|
|
|
|
|
|
|
|
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 first
quarter of 2018. The increase in earnings was driven by higher 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 depreciation
expense.
NSP-Minnesota — Earnings increased $0.03 per share for the
first quarter of 2018. The increase reflects lower O&M expenses and
higher 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 $0.02 per share for the first
quarter of 2018, largely due to timing of O&M expenses, the favorable
impact of weather and lower interest expense.
NSP-Wisconsin — Earnings increased $0.02 per share for the
first quarter of 2018. The increase was driven by higher natural gas and
electric rates and the impact of favorable weather, partially offset by
additional depreciation and amortization expense related to higher
invested capital.
The following table summarizes significant components contributing to
the changes in 2018 EPS compared with the same period in 2017:
|
|
Three Months
|
Diluted Earnings (Loss) Per Share
|
|
Ended March 31
|
GAAP and ongoing diluted EPS — 2017
|
|
$
|
0.47
|
|
|
|
|
Components of change — 2018 vs. 2017
|
|
|
Higher electric margins (excluding TCJA impacts) (a)
|
|
0.04
|
|
Higher natural gas margins (excluding TCJA impacts) (a)
|
|
0.04
|
|
Lower O&M expenses
|
|
0.03
|
|
Higher AFUDC — equity
|
|
0.02
|
|
Lower ETR (excluding TCJA impacts) (a) (b)
|
|
0.01
|
|
Higher depreciation and amortization
|
|
(0.02
|
)
|
Higher interest charges
|
|
(0.01
|
)
|
Other, net
|
|
(0.01
|
)
|
GAAP and ongoing diluted EPS — 2018
|
|
$
|
0.57
|
|
|
|
|
(a)TCJA impact:
|
|
|
Income tax - rate change
|
|
$
|
0.10
|
|
Electric revenue reductions
|
|
(0.08
|
)
|
Gas revenue reductions
|
|
(0.01
|
)
|
Holding company - interest expense
|
|
(0.01
|
)
|
Total
|
|
$
|
—
|
|
|
|
|
|
|
(b)
|
|
The ETR includes the impact of an additional $4 million of wind
Production Tax Credits (PTCs) for the three months ended March 31,
2018, which are largely flowed back to customers through electric
margin.
|
|
|
|
Note 2. Regulated Utility Results
Estimated Impact of Temperature Changes on Regulated Earnings —
Unusually hot summers or cold winters increase electric and natural gas
sales, while mild weather reduces electric and natural gas sales. The
estimated impact of weather on earnings is based on the number of
customers, temperature variances and the amount of natural gas or
electricity historically used per degree of temperature. Weather
deviations from normal levels can affect Xcel Energy’s financial
performance.
Degree-day or Temperature-Humidity Index (THI) data is used to estimate
amounts of energy required to maintain comfortable indoor temperature
levels based on each day’s average temperature and humidity. Heating
degree-days (HDD) is the measure of the variation in the weather based
on the extent to which the average daily temperature falls below 65°
Fahrenheit. Cooling degree-days (CDD) is the measure of the variation in
the weather based on the extent to which the average daily temperature
rises above 65° Fahrenheit. Each degree of temperature above 65°
Fahrenheit is counted as one CDD, and each degree of temperature below
65° Fahrenheit is counted as one HDD. In Xcel Energy’s more humid
service territories, a THI is used in place of CDD, which adds a
humidity factor to CDD. HDD, CDD and THI are most likely to impact the
usage of Xcel Energy’s residential and commercial customers. Industrial
customers are less sensitive to weather.
Normal weather conditions are defined as either the 20-year or 30-year
average of actual historical weather conditions. The historical period
of time used in the calculation of normal weather differs by
jurisdiction, based on regulatory practice. To calculate the impact of
weather on demand, a demand factor is applied to the weather impact on
sales.
There was no impact on sales for the first quarter of 2018 due to THI or
CDD. The percentage increase (decrease) in normal and actual HDD is
provided in the following table:
|
|
|
|
|
Three Months Ended March 31
|
|
|
|
|
|
2018 vs.
|
|
2017 vs.
|
|
2018 vs.
|
|
|
|
|
|
Normal
|
|
Normal
|
|
2017
|
HDD
|
|
|
|
|
0.3%
|
|
(14.4)%
|
|
16.0%
|
|
|
|
|
|
|
|
|
|
|
Weather — The following table summarizes the estimated
impact of temperature variations on EPS compared with normal weather
conditions:
|
|
Three Months Ended March 31
|
|
|
2018 vs.
|
|
2017 vs.
|
|
2018 vs.
|
|
|
Normal
|
|
Normal
|
|
2017
|
Retail electric
|
|
$
|
0.003
|
|
|
$
|
(0.025
|
)
|
|
$
|
0.028
|
|
Firm natural gas
|
|
0.003
|
|
|
(0.018
|
)
|
|
0.021
|
|
Total (before adjustments for decoupling)
|
|
$
|
0.006
|
|
|
$
|
(0.043
|
)
|
|
$
|
0.049
|
|
Decoupling – Minnesota
|
|
(0.002
|
)
|
|
0.008
|
|
|
(0.010
|
)
|
Total (adjusted for decoupling)
|
|
$
|
0.004
|
|
|
$
|
(0.035
|
)
|
|
$
|
0.039
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 March 31
|
|
|
PSCo
|
|
NSP-Minnesota
|
|
SPS
|
|
NSP-Wisconsin
|
|
Xcel Energy
|
Actual
|
|
|
|
|
|
|
|
|
|
|
Electric residential (a)
|
|
1.5
|
%
|
|
3.7
|
%
|
|
7.7
|
%
|
|
5.4
|
%
|
|
3.5
|
%
|
Electric commercial and industrial
|
|
1.7
|
|
|
0.4
|
|
|
5.2
|
|
|
4.9
|
|
|
2.3
|
|
Total retail electric sales
|
|
1.6
|
|
|
1.4
|
|
|
5.8
|
|
|
5.0
|
|
|
2.7
|
|
Firm natural gas sales
|
|
12.8
|
|
|
17.0
|
|
|
N/A
|
|
16.7
|
|
|
14.5
|
|
|
|
|
|
|
Three Months Ended March 31
|
|
|
PSCo
|
|
NSP-Minnesota
|
|
SPS
|
|
NSP-Wisconsin
|
|
Xcel Energy
|
Weather-normalized
|
|
|
|
|
|
|
|
|
|
|
Electric residential (a)
|
|
(0.4
|
)%
|
|
(1.3
|
)%
|
|
1.2
|
%
|
|
(1.3
|
)%
|
|
(0.6
|
)%
|
Electric commercial and industrial
|
|
1.6
|
|
|
(0.6
|
)
|
|
4.9
|
|
|
4.3
|
|
|
1.8
|
|
Total retail electric sales
|
|
0.9
|
|
|
(0.8
|
)
|
|
4.3
|
|
|
2.5
|
|
|
1.1
|
|
Firm natural gas sales
|
|
2.0
|
|
|
1.0
|
|
|
N/A
|
|
2.1
|
|
|
1.7
|
|
|
|
|
|
|
|
|
|
|
|
|
(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)
-
PSCo’s decline in residential sales reflects lower use per customer,
partially offset by customer additions. 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 metal mining industries,
which were partially reduced by lower use for the small C&I class.
-
NSP-Minnesota’s residential sales decrease was a result of lower use
per customer, partially offset by customer growth. The decline in C&I
sales was largely due to reduced usage, which offset an increase in
the number of customers. Declines in service related industries offset
increased sales to large customers in the manufacturing and energy
industries.
-
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 increased sales to small and large sand
mining and energy industry customers.
Weather-normalized Natural Gas Sales Growth
-
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 March 31
|
(Millions of Dollars)
|
|
2018
|
|
2017
|
Electric revenues
|
|
$
|
2,333
|
|
|
$
|
2,299
|
|
Electric fuel and purchased power
|
|
(932
|
)
|
|
(925
|
)
|
Electric margin before impact of the TCJA
|
|
$
|
1,401
|
|
|
$
|
1,374
|
|
Impact of the TCJA (offset as a reduction in income tax expense)
|
|
(63
|
)
|
|
—
|
|
Electric margin
|
|
$
|
1,338
|
|
|
$
|
1,374
|
|
|
|
|
|
|
|
|
|
|
The following table summarizes the components of the changes in electric
margin:
|
|
Three Months
|
|
|
Ended March 31,
|
(Millions of Dollars)
|
|
2018 vs. 2017
|
Firm wholesale
|
|
$
|
(7
|
)
|
Estimated impact of weather, net of Minnesota decoupling
|
|
15
|
|
Purchased capacity costs
|
|
11
|
|
Retail rate increase (Wisconsin)
|
|
5
|
|
Other, net
|
|
3
|
|
Total increase in electric margin before impact of the TCJA
|
|
$
|
27
|
|
Impact of the TCJA (offset as a reduction in income tax expense)
|
|
(63
|
)
|
Total decrease in electric margin
|
|
$
|
(36
|
)
|
|
|
|
|
|
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 March 31
|
(Millions of Dollars)
|
|
2018
|
|
2017
|
Natural gas revenues
|
|
$
|
673
|
|
|
$
|
626
|
|
Cost of natural gas sold and transported
|
|
(375
|
)
|
|
(365
|
)
|
Natural gas margin before impact of the TCJA
|
|
$
|
298
|
|
|
$
|
261
|
|
Impact of the TCJA (offset as a reduction in income tax expense)
|
|
(11
|
)
|
|
—
|
|
Natural gas margin
|
|
$
|
287
|
|
|
$
|
261
|
|
|
|
|
|
|
|
|
|
|
The following table summarizes the components of the changes in natural
gas margin:
|
|
Three Months
|
|
|
Ended March 31,
|
(Millions of Dollars)
|
|
2018 vs. 2017
|
Estimated impact of weather
|
|
$
|
15
|
|
Retail rate increase (Colorado - interim, subject to refund,
Wisconsin and Michigan)
|
|
12
|
|
Infrastructure and integrity riders
|
|
4
|
|
Sales growth
|
|
2
|
|
Other, net
|
|
4
|
|
Total increase in natural gas margin before impact of the TCJA
|
|
$
|
37
|
|
Impact of the TCJA (offset as a reduction in income tax expense)
|
|
(11
|
)
|
Total increase in natural gas margin
|
|
$
|
26
|
|
|
|
|
|
|
O&M Expenses — O&M expenses decreased $23 million, or
4.0 percent, for the first quarter of 2018, largely reflecting expense
timing. The significant changes are summarized in the table below:
|
|
Three Months
|
|
|
Ended March 31,
|
(Millions of Dollars)
|
|
2018 vs. 2017
|
Nuclear plant operations and amortization
|
|
$
|
(10
|
)
|
Plant generation costs
|
|
(9
|
)
|
Other, net
|
|
(4
|
)
|
Total decrease in O&M expenses
|
|
$
|
(23
|
)
|
|
|
|
|
|
-
Nuclear plant operations and amortization expenses are lower largely
reflecting expense timing, savings initiatives and reduced refueling
outage costs.
-
Plant generation costs decreased 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 $3 million, or 4.4 percent, for
the first quarter of 2018. The increase was primarily due to higher
recovery rates for Colorado electric and natural gas sales. 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 $18 million, or 4.9 percent for the first quarter
of 2018. The increase was primarily driven by capital expenditures due
to planned system investments.
Taxes (Other than Income Taxes) — Taxes (other than income
taxes) increased $3 million, or 2.1 percent for the first quarter of
2018. The increase was primarily due to higher property taxes in
Colorado.
AFUDC, Equity and Debt — AFUDC increased $13 million for
the first quarter of 2018. The increase was primarily due to the Rush
Creek wind project in Colorado and other capital investments.
Interest Charges — Interest charges increased $5 million,
or 3.0 percent, for the first quarter of 2018. 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 $58 million
for the first quarter of 2018 compared with the same period in 2017. The
decrease was primarily driven by a lower federal tax rate due to the
TCJA, an increase in wind PTCs, an increase in plant-related regulatory
differences related to ARAM (a) and an increase in other tax
credits. This was partially offset by the deferral of ARAM. The
following table reconciles the effective tax rate for the first quarter
of 2018 and 2017.
|
|
Three Months ended March 31
|
|
|
|
|
2018
|
|
2017
|
|
2018 vs 2017
|
Federal statutory rate
|
|
21.0
|
%
|
|
35.0
|
%
|
|
(14.0
|
)%
|
State tax, net of federal tax effect
|
|
4.9
|
%
|
|
4.0
|
%
|
|
0.9
|
%
|
Increases (decreases) in tax from:
|
|
|
|
|
|
|
Wind production tax credits
|
|
(6.0
|
)
|
|
(4.0
|
)
|
|
(2.0
|
)
|
Regulatory differences - ARAM
|
|
(5.8
|
)
|
|
(0.1
|
)
|
|
(5.7
|
)
|
Regulatory differences - ARAM deferral (b)
|
|
5.4
|
|
|
—
|
|
|
5.4
|
|
Regulatory differences - other utility plant items
|
|
(1.0
|
)
|
|
(0.5
|
)
|
|
(0.5
|
)
|
Other, net
|
|
(1.6
|
)
|
|
(1.5
|
)
|
|
(0.1
|
)
|
Effective income tax rate
|
|
16.9
|
%
|
|
32.9
|
%
|
|
(16.0
|
)%
|
|
|
|
|
|
|
|
(a)
|
|
The average rate assumption method (ARAM); a method to flow back
excess deferred taxes to customers.
|
(b)
|
|
As we receive further direction from our regulatory commissions
regarding the return of excess deferred taxes to our customers
resulting from the TCJA, the ARAM deferral may decrease during the
year, which would result in a reduction to tax expense with a
corresponding reduction to revenue.
|
|
|
|
Note 3. Xcel Energy Capital Structure,
Financing and Credit Ratings
Following is the capital structure of Xcel Energy:
|
|
|
|
Percentage of Total
|
|
|
|
Percentage of Total
|
(Millions of Dollars)
|
|
March 31, 2018
|
|
Capitalization
|
|
Dec. 31, 2017
|
|
Capitalization
|
Current portion of long-term debt
|
|
$
|
457
|
|
1
|
%
|
|
$
|
457
|
|
2
|
%
|
Short-term debt
|
|
1,025
|
|
4
|
|
|
814
|
|
3
|
|
Long-term debt
|
|
14,522
|
|
53
|
|
|
14,520
|
|
53
|
|
Total debt
|
|
16,004
|
|
58
|
|
|
15,791
|
|
58
|
|
Common equity
|
|
11,561
|
|
42
|
|
|
11,455
|
|
42
|
|
Total capitalization
|
|
$
|
27,565
|
|
100
|
%
|
|
$
|
27,246
|
|
100
|
%
|
|
|
|
|
|
|
|
|
|
|
|
Credit Facilities — As of April 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.
|
|
$
|
1,500
|
|
$
|
775
|
|
$
|
725
|
|
$
|
1
|
|
$
|
726
|
PSCo
|
|
700
|
|
54
|
|
646
|
|
1
|
|
647
|
NSP-Minnesota
|
|
500
|
|
36
|
|
464
|
|
1
|
|
465
|
SPS
|
|
400
|
|
19
|
|
381
|
|
1
|
|
382
|
NSP-Wisconsin
|
|
150
|
|
36
|
|
114
|
|
—
|
|
114
|
Total
|
|
$
|
3,250
|
|
$
|
920
|
|
$
|
2,330
|
|
$
|
4
|
|
$
|
2,334
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a)
|
|
These credit facilities expire in June 2021, with the exception of
Xcel Energy’s Inc.’s $500 million 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 April 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
|
|
|
|
|
|
|
|
|
|
Financing Activity — Xcel Energy Inc. and its utility
subsidiaries’ 2018 financing plans reflect the following:
-
Xcel Energy Inc. plans to issue approximately $750 million of senior
unsecured bonds;
-
NSP-Minnesota plans to issue approximately $300 million of first
mortgage bonds;
-
NSP-Wisconsin plans to issue approximately $200 million of first
mortgage bonds;
-
PSCo plans to issue approximately $750 million of first mortgage
bonds; and
-
SPS plans to issue approximately $350 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 – Dakota Range — In 2017, NSP-Minnesota
filed with the Minnesota Public Utility Commission (MPUC) and the North
Dakota Public Service Commission (NDPSC) seeking approval to build and
own the Dakota Range, a 300 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. In March 2018, NSP-Minnesota submitted
supplemental filings to the MPUC and NDPSC regarding the impacts of the
TCJA and other updated information for Dakota Range. These impacts
result in a minimal increase in the revenue requirement for Dakota Range
and the project continues to show significant benefits to customers.
MPUC and NDPSC decisions are pending.
PSCo – Colorado 2017 Multi-Year Electric Rate Case — In
October 2017, PSCo filed a multi-year request with the Colorado Public
Utilities Commission (CPUC) seeking to increase electric rates
approximately $245 million over four years. The request was based on
forecast test years (FTY), a 10.0 percent return on equity (ROE) and an
equity ratio of 55.25 percent. Interim rates, subject to refund and
interest, were to be effective on June 1, 2018.
Revenue Request (Millions of Dollars)
|
|
2018
|
|
2019
|
|
2020
|
|
2021
|
|
Total
|
Revenue request
|
|
$
|
74
|
|
$
|
75
|
|
$
|
60
|
|
$
|
36
|
|
$
|
245
|
Clean Air Clean Jobs Act (CACJA) rider conversion to base rates
|
|
90
|
|
—
|
|
—
|
|
—
|
|
90
|
Transmission Cost Adjustment (TCA) rider conversion to base rates
|
|
43
|
|
—
|
|
—
|
|
—
|
|
43
|
Total
|
|
$
|
207
|
|
$
|
75
|
|
$
|
60
|
|
$
|
36
|
|
$
|
378
|
|
|
|
|
|
|
|
|
|
|
|
Expected year-end rate base (billions of dollars)
|
|
$
|
6.8
|
|
$
|
7.1
|
|
$
|
7.3
|
|
$
|
7.4
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
In March 2018, PSCo, CPUC Staff and Office of Consumer Council (OCC)
reached a settlement and filed a motion with the CPUC requesting changes
to the procedural schedule and scope of the electric case, which
included delaying the implementation of provisional rates from June 2018
to January 2019 and requiring PSCO to file updated test year information
for 2019-2021 which included the impacts of TCJA. In April 2018, the
CPUC denied the motion on procedural grounds and dismissed the electric
rate case. PSCo anticipates filing a new electric rate case in the
summer of 2018 with new rates expected to be effective in the first
quarter of 2019.
PSCo – Colorado 2017 Multi-Year Natural Gas Rate Case — In
June 2017, PSCo filed a multi-year request with the CPUC seeking to
increase retail natural gas rates approximately $139 million over three
years. The request, detailed below, is based on FTYs, a 10.0 percent ROE
and an equity ratio of 55.25 percent.
Revenue Request (Millions of Dollars)
|
|
2018
|
|
2019
|
|
2020
|
|
Total
|
Revenue request
|
|
$
|
63
|
|
$
|
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 October 2017, the CPUC Staff and the OCC recommended a single 2016
historic test year (HTY) based on an average 13-month rate base, and
opposed a multi-year request. In addition, they recommended an equity
ratio of 48.73 percent and 51.2 percent, respectively, and the existing
PSIA rider expire with the 2018 rates rolled into base rates beginning
Jan. 1, 2019. Planned investments in 2019 and 2020 would be recoverable
through a future rate case. The Staff and OCC provide for a recommended
2018 rate increase of approximately $30 million and $39 million,
respectively.
Provisional rates, subject to refund, of $63 million were implemented on
Jan. 1, 2018.
On Jan. 31, 2018, the CPUC ordered deferred accounting for the impacts
of TCJA and opened a statewide TCJA proceeding, as discussed below. In
February 2018, the ALJ approved a settlement agreement between PSCo and
the CPUC, which reduced provisional rates by $20 million to address the
impacts of the TCJA. The CPUC is expected to rule on the regulatory
treatment of the TCJA and the natural gas rate case later in 2018.
On April 20, 2018, PSCo filed for a PSIA extension through 2020 in the
event that the CPUC does not adopt its multi-year plan proposal.
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 megawatts (MW)
in 2023.
In 2017, PSCo and various other stakeholders filed a stipulation
agreement (Stipulation) proposing the CEP, an alternative plan that
increases the amount of new renewable resources sought under the ERP.
The CEP would increase PSCo’s potential capacity need up to 1,110 MW due
to the proposed retirement of two coal units. The major components
include:
-
Early retirement of 660 MWs of coal-fired generation at Comanche Units
1 (2022) and 2 (2025);
-
Accelerated depreciation for the early retirement of the two Comanche
units and establishment of a regulatory asset to collect the
incremental depreciation expense and related costs;
-
A request for proposal (RFP) for up to 1,000 MW of wind, 700 MW of
solar and 700 MW of natural gas and/or storage;
-
Utility ownership targets of 50 percent renewable generation resources
and 75 percent of natural gas-fired, storage, or renewable with
storage generation resources; and
-
Reduction of the renewable energy standard adjustment rider (RESA),
from two percent to one percent effective beginning 2021 or 2022.
In March 2018, the CPUC required additional portfolio requirements
beyond the terms of the Stipulation. The CPUC requested PSCo to present
750 MW and 1,100 MW portfolios, and to include a least-cost portfolio in
addition to the recommended portfolio. They also requested a scenario
without the RESA reduction offsetting the cost of accelerated
depreciation. The order did not explicitly approve the Stipulation and
deferred action on issues such as the treatment of accelerated
depreciation which is being addressed in a separate proceeding.
PSCo is currently evaluating bids from a RFP and anticipates filing its
recommended portfolios in May 2018. A CPUC decision on the recommended
portfolio is anticipated in the summer of 2018.
SPS – Texas 2017 Electric Rate Case — In 2017, SPS filed a
$55 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 following table summarizes SPS’ rate increase request:
Revenue Request (Millions of Dollars)
|
|
|
Incremental revenue request
|
|
$
|
69
|
|
Transmission Cost Recovery Factor (TCRF) rider conversion to base
rates (a)
|
|
(14
|
)
|
Net revenue increase request
|
|
$
|
55
|
|
|
|
|
|
|
(a)
|
|
The roll-in of the TCRF 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. SPS can request another TCRF
rider after the conclusion of this rate case to recover transmission
investments subsequent to June 30, 2017.
|
|
|
|
Key dates in the revised procedural schedule are as follows:
-
Intervenors’ direct testimony — April 25, 2018;
-
PUCT Staff direct testimony — May 2, 2018;
-
PUCT Staff and intervenors’ cross-rebuttal testimony — May 14, 2018;
-
SPS’ rebuttal testimony — May 23, 2018; and
-
Hearings — June 4 - 14, 2018.
As indicated below, the PUCT has opened a docket on the impact of the
TCJA, which may have an impact on this rate case. In February 2018, SPS
filed supplemental testimony with the PUCT, which indicated that TCJA
would reduce revenue requirements by approximately $32 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 final rates are expected to be effective retroactive
to Jan. 23, 2018 through a customer surcharge. A PUCT decision is
expected in the fourth 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 retail electric
base rates of approximately $43 million. The request is based on a HTY
ended June 30, 2017, a ROE of 10.25 percent, an equity ratio of 53.97
percent and a rate base of approximately $885 million, including rate
base additions through Nov. 30, 2017. This rate case also takes into
account the decline in sales of 380 MW in 2017 from certain wholesale
customers and seeks to adjust the life of SPS’ Tolk power plant (Unit 1
from 2042 to 2032 and Unit 2 from 2045 to 2032).
In February 2018, SPS filed supplemental information, which indicated
that the TCJA would reduce revenue requirements by approximately $11
million. In addition, SPS requested an increase in the equity ratio of
58 percent and an adjustment to regional transmission revenue for the
impacts of TCJA.
On April 13, 2018, the NMPRC Staff, the New Mexico Attorney General
(NMAG), and several other parties filed testimony. The recommended ROE’s
ranged from 9.0 percent to of 9.21 percent, and the recommended equity
ratios were 51.0 percent to 53.97 percent.
The following table summarizes certain parties’ recommendations from
SPS’ request:
Millions of Dollars
|
|
NMPRC Staff Testimony
|
|
NMAG Testimony
|
SPS request
|
|
$
|
43
|
|
|
$
|
43
|
|
Reduction to request for the impact of the TCJA
|
|
(11
|
)
|
|
(11
|
)
|
SPS request, including the impact of the TCJA
|
|
32
|
|
|
32
|
|
|
|
|
|
|
ROE (9.0 percent and 9.21 percent, respectively)
|
|
(4
|
)
|
|
(6
|
)
|
Capital structure (52.0 percent and 53.97 percent, respectively)
|
|
(7
|
)
|
|
(3
|
)
|
Accelerated depreciation (Tolk plant)
|
|
(3
|
)
|
|
(3
|
)
|
Disallow rate case expenses
|
|
(2
|
)
|
|
(3
|
)
|
Regional transmission revenue (adjustment for the impact of the TCJA)
|
|
—
|
|
—
|
|
(3
|
)
|
Post test year plant (estimated numbers were updated to actual)
|
|
(1
|
)
|
|
(2
|
)
|
Other, net
|
|
(4
|
)
|
|
(5
|
)
|
Recommended rate increase
|
|
$
|
11
|
|
|
$
|
7
|
|
|
|
|
|
|
|
|
|
|
Key dates in the procedural schedule are as follows:
-
SPS’ rebuttal testimony — May 2, 2018; and
-
Hearings — May 15 - 25, 2018.
SPS anticipates a decision and implementation of final rates in the
second half 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.
In March 2018, the NMPRC approved SPS’ request consistent with the terms
of SPS’ and the parties’ modified unanimous settlement. The key terms of
the settlement are:
-
An investment cap of $1,675 per kilowatt, which is equal to 102.5
percent of the estimated construction costs;
-
SPS customers would receive a credit to their bills if actual capacity
factors fall below 48 percent;
-
SPS customers would receive 100 percent of the federal PTC; and
-
SPS will sell the output from the two wind farms into the market and
keep the revenue and the grossed-up PTCs during the time the rate case
is pending before the wind projects go into base rates. If the market
revenue and grossed up PTC value exceeds the estimated revenue
requirement, SPS will refund the excess amount to customers as an
additional customer protection during the interim period.
In February 2018, SPS and the parties filed an unopposed settlement with
the PUCT. The key terms of the settlement are similar to the terms
approved by the NMPRC above except that the ratemaking treatment of the
market revenues and grossed-up PTCs will be treated in a traditional
ratemaking manner and the effective date of the rates in the rate cases
placing the wind farms in rates will be 35 days after SPS files the rate
cases.
In April 2018, the PUCT requested additional information regarding the
settlement. SPS filed a response and the PUCT is scheduled to consider
the settlement April 27, 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. Xcel Energy has
made filings and is working with various stakeholders in its
jurisdictions to determine the appropriate treatment for the TCJA.
NSP-Minnesota — The MPUC opened a TCJA docket and issued a
request for information on the impacts of the TCJA in January 2018. In
March 2018, the Minnesota Department of Commerce recommended adjusting
rates or implementing refunds for the current tax impacts and
incorporating the deferred tax impacts in each utility’s next rate case.
In April 2018, NSP-Minnesota filed an update of 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. The filing also proposed recommended options for
delivering tax reform benefits to customers. 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. A MPUC decision is expected later in 2018.
Dockets have also been opened in North Dakota and South Dakota. In
February 2018, NSP-Minnesota proposed using the reduced revenue
requirements from the TCJA to defer planned future rate filings in both
jurisdictions.
NSP-Wisconsin — In January 2018, the Public Service
Commission of Wisconsin (PSCW) issued an order requiring public
utilities to apply deferred accounting for the impacts of the TCJA. In
March 2018, NSP-Wisconsin filed recommended plans for Wisconsin, which
for electric operations included an option for an immediate bill credit
for a portion of the tax savings in 2018 and 2019, while deferring the
remainder until NSP-Wisconsin’s 2020 electric rate case. For the natural
gas operations, NSP-Wisconsin proposed using the TCJA to reduce the
unamortized regulatory asset for the Ashland/Northern States Power
Lakefront Superfund Site clean-up. A PSCW decision on the regulatory
treatment of the TCJA is anticipated later in 2018.
For Michigan, NSP-Wisconsin has reached settlement in its electric rate
case, which reflects the impacts of the TCJA, and has proposed customer
refunds for natural gas operations.
PSCo — In January 2018, the CPUC opened a statewide TCJA
proceeding and ordered deferred accounting for all investor-owned
utilities.
-
Colorado 2017 Multi-Year Natural Gas Rate Case
- In February 2018, the administrative law judge (ALJ)
approved PSCo and the CPUC Staff’s settlement agreement addressing the
TCJA, which includes a $20 million reduction to provisional rates
effective March 1, 2018. A final true-up, including any outcomes
associated with the statewide proceeding, would provide customers the
full net benefit of the TCJA effective January 2018. A CPUC decision
is pending.
-
Colorado Electric - In
April 2018, PSCo, the CPUC Staff and the OCC filed a TCJA settlement
agreement with the CPUC that identified a reduction in electric
revenue requirements of approximately $101 million for the TCJA in
2018. The settlement 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. With the dismissal
of the 2017 rate case, revisions to the TCJA settlement are required
to address the impacts of the TCJA for 2019 until new base rates go
into effect in connection with a future electric rate case that PSCo
anticipates filing later this summer. A CPUC decision is pending.
SPS — In January 2018, the PUCT issued an order requiring
utilities to apply deferred accounting for the impacts of the TCJA. In
February 2018, SPS filed with the PUCT supplemental testimony, which
indicated that the TCJA would reduce revenue requirements by
approximately $32 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 Texas electric rate
case, as discussed in Note 4.
In February 2018, SPS filed with the NMPRC a preliminary quantification
of the impacts of the TCJA on its ongoing New Mexico 2017 electric rate
case, which 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’s 2018
GAAP and ongoing earnings guidance is $2.37 to $2.47 per share.(a) Key
assumptions:
-
Constructive outcomes in all rate case and regulatory proceedings.
-
Normal weather patterns.
-
Weather-normalized retail electric sales are projected to be within a
range of 0 percent to 0.5 percent over 2017 levels.
-
Weather-normalized retail firm natural gas sales are projected to be
within a range of 0 percent to 0.5 percent over 2017 levels.
-
Capital rider revenue is projected to increase by $30 million to $40
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 be flat to 2017 levels.
-
Depreciation expense is projected to increase approximately $120
million to $130 million over 2017 levels. The change is depreciation
expense is largely due to the dismissal of the PSCo electric rate
case, which delays the impact of higher depreciation rates.
-
Property taxes are projected to increase approximately $30 million to
$40 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 March 31
|
|
|
2018
|
|
2017
|
Operating revenues:
|
|
|
|
|
Electric and natural gas
|
|
$
|
2,932
|
|
|
$
|
2,925
|
|
Other
|
|
19
|
|
|
21
|
|
Total operating revenues
|
|
2,951
|
|
|
2,946
|
|
|
|
|
|
|
Net income
|
|
$
|
291
|
|
|
$
|
239
|
|
|
|
|
|
|
Weighted average diluted common shares outstanding
|
|
509
|
|
|
509
|
|
|
|
|
|
|
Components of EPS — Diluted
|
|
|
|
|
Regulated utility
|
|
$
|
0.62
|
|
|
$
|
0.51
|
|
Xcel Energy Inc. and other costs
|
|
(0.05
|
)
|
|
(0.04
|
)
|
GAAP and ongoing diluted EPS
|
|
$
|
0.57
|
|
|
$
|
0.47
|
|
Book value per share
|
|
$
|
22.73
|
|
|
$
|
21.80
|
|
View source version on businesswire.com: https://www.businesswire.com/news/home/20180426005266/en/
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