-
GAAP (generally accepted accounting principles) and ongoing 2015 third
quarter earnings per share were $0.84 compared with $0.73 per share in
2014.
-
Xcel Energy revises its 2015 ongoing earnings guidance range to $2.05
to $2.15 per share, compared to the previous range of $2.00 to $2.15
per share.
-
Xcel Energy initiates 2016 ongoing earnings guidance of $2.12 to $2.27
per share.
Xcel Energy Inc. (NYSE: XEL) today reported 2015 third quarter GAAP and
ongoing earnings of $426 million, or $0.84 per share, compared with $369
million, or $0.73 per share, in the same period in 2014.
Electric and gas margins rose in the third quarter of 2015 primarily due
to an increase in retail electric rates, non-fuel riders, the impact of
favorable weather and a lower earnings test refund in Colorado. These
positive factors were partially offset by higher depreciation and
interest charges, lower allowance for funds used during construction and
increased property taxes.
“Third quarter and year-to-date results demonstrate the ongoing,
successful execution of our regulatory initiatives along with continued
cost management efforts,” said Chairman, President and Chief Executive
Officer Ben Fowke.
“During the quarter, the EPA issued the final Clean Power Plan. Although
the regulations are groundbreaking and complex, Xcel Energy is well
positioned to meet the requirements and remains committed to delivering
the clean energy options our customers want while maintaining safety and
reliability and keeping costs affordable.”
“Specifically, in Minnesota we recently filed a revised resource plan
that will enable us to adapt to and embrace the rapid pace of change in
our industry. Our proposal calls for a 60 percent reduction in carbon
emissions from 2005 levels by 2030 and will result in 63 percent of NSP
System energy being carbon free by 2030. In addition to supporting our
effort to establish a long-term regulatory compact, this proposal will
advance our shift to renewable energy, add cleaner natural gas-powered
generation to our system and allow us to protect reliability, jobs and
community investments.”
Earnings Adjusted for Certain Items (Ongoing Earnings)
The following table provides a reconciliation of ongoing earnings per
share (EPS) to GAAP EPS:
|
|
|
|
|
|
|
|
|
Three Months Ended Sept. 30
|
|
Nine Months Ended Sept. 30
|
Diluted Earnings (Loss) Per Share
|
|
2015
|
|
2014
|
|
2015
|
|
2014
|
Ongoing diluted EPS
|
|
$
|
0.84
|
|
|
$
|
0.73
|
|
|
$
|
1.69
|
|
|
$
|
1.64
|
|
Loss on Monticello life cycle management/extended power uprate
project (a)
|
|
|
—
|
|
|
|
—
|
|
|
|
(0.16
|
)
|
|
|
—
|
|
GAAP diluted EPS
|
|
$
|
0.84
|
|
|
$
|
0.73
|
|
|
$
|
1.53
|
|
|
$
|
1.64
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) See Note 6.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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:
|
|
|
|
(888) 539-3613
|
International Dial-In:
|
|
|
|
(719) 457-2600
|
Conference ID:
|
|
|
|
4416633
|
|
|
|
|
|
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 October 29 through 10:59 p.m. CDT on
October 30.
|
|
|
|
|
Replay Numbers
|
|
|
|
|
US Dial-In:
|
|
|
|
(888) 203-1112
|
International Dial-In:
|
|
|
|
(719) 457-0820
|
Access Code:
|
|
|
|
4416633
|
|
|
|
|
|
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 2015 earnings per share
guidance and assumptions, are intended to be identified in this document
by the words “anticipate,” “believe,” “estimate,” “expect,” “intend,”
“may,” “objective,” “outlook,” “plan,” “project,” “possible,”
“potential,” “should” and similar expressions. Actual results may vary
materially. Forward-looking statements speak only as of the date they
are made and we expressly disclaim any obligation to update any
forward-looking information. The following factors, in addition to those
discussed in Xcel Energy's Annual Report on Form 10-K for the fiscal
year ended Dec. 31, 2014, and Quarterly Reports on Form 10-Q for the
quarters ended March 31, 2015 and June 30, 2015, 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; availability of 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
thousands, except per share data)
|
|
|
|
|
|
|
|
Three Months Ended Sept. 30
|
|
Nine Months Ended Sept. 30
|
|
|
2015
|
|
2014
|
|
2015
|
|
2014
|
Operating revenues
|
|
|
|
|
|
|
|
|
Electric
|
|
$
|
2,667,480
|
|
|
$
|
2,616,351
|
|
|
$
|
7,105,803
|
|
|
$
|
7,215,699
|
|
Natural gas
|
|
|
216,019
|
|
|
|
236,649
|
|
|
|
1,216,146
|
|
|
|
1,485,464
|
|
Other
|
|
|
17,813
|
|
|
|
16,807
|
|
|
|
56,716
|
|
|
|
56,344
|
|
Total operating revenues
|
|
|
2,901,312
|
|
|
|
2,869,807
|
|
|
|
8,378,665
|
|
|
|
8,757,507
|
|
|
|
|
|
|
|
|
|
|
Operating expenses
|
|
|
|
|
|
|
|
|
Electric fuel and purchased power
|
|
|
1,014,726
|
|
|
|
1,079,855
|
|
|
|
2,869,563
|
|
|
|
3,188,498
|
|
Cost of natural gas sold and transported
|
|
|
66,071
|
|
|
|
99,344
|
|
|
|
665,109
|
|
|
|
934,073
|
|
Cost of sales — other
|
|
|
8,203
|
|
|
|
8,012
|
|
|
|
26,416
|
|
|
|
24,783
|
|
Operating and maintenance expenses
|
|
|
565,984
|
|
|
|
568,391
|
|
|
|
1,746,093
|
|
|
|
1,714,138
|
|
Conservation and demand side management program expenses
|
|
|
57,314
|
|
|
|
75,172
|
|
|
|
165,260
|
|
|
|
223,552
|
|
Depreciation and amortization
|
|
|
280,121
|
|
|
|
255,395
|
|
|
|
827,821
|
|
|
|
756,645
|
|
Taxes (other than income taxes)
|
|
|
123,081
|
|
|
|
117,958
|
|
|
|
389,438
|
|
|
|
358,938
|
|
Loss on Monticello life cycle management/extended power uprate
project
|
|
|
—
|
|
|
|
—
|
|
|
|
129,463
|
|
|
|
—
|
|
Total operating expenses
|
|
|
2,115,500
|
|
|
|
2,204,127
|
|
|
|
6,819,163
|
|
|
|
7,200,627
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
785,812
|
|
|
|
665,680
|
|
|
|
1,559,502
|
|
|
|
1,556,880
|
|
|
|
|
|
|
|
|
|
|
Other income, net
|
|
|
1,626
|
|
|
|
1,404
|
|
|
|
5,748
|
|
|
|
4,687
|
|
Equity earnings of unconsolidated subsidiaries
|
|
|
8,162
|
|
|
|
7,401
|
|
|
|
24,360
|
|
|
|
22,650
|
|
Allowance for funds used during construction — equity
|
|
|
15,427
|
|
|
|
23,337
|
|
|
|
40,728
|
|
|
|
68,852
|
|
|
|
|
|
|
|
|
|
|
Interest charges and financing costs
|
|
|
|
|
|
|
|
|
Interest charges — includes other financing costs of $6,260,
$5,737, $17,819 and $17,144, respectively
|
|
|
152,566
|
|
|
|
143,219
|
|
|
|
441,728
|
|
|
|
421,713
|
|
Allowance for funds used during construction — debt
|
|
|
(7,031
|
)
|
|
|
(9,948
|
)
|
|
|
(19,340
|
)
|
|
|
(29,609
|
)
|
Total interest charges and financing costs
|
|
|
145,535
|
|
|
|
133,271
|
|
|
|
422,388
|
|
|
|
392,104
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
665,492
|
|
|
|
564,551
|
|
|
|
1,207,950
|
|
|
|
1,260,965
|
|
Income taxes
|
|
|
239,029
|
|
|
|
195,969
|
|
|
|
432,490
|
|
|
|
435,998
|
|
Net income
|
|
$
|
426,463
|
|
|
$
|
368,582
|
|
|
$
|
775,460
|
|
|
$
|
824,967
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares outstanding:
|
|
|
|
|
|
|
|
|
Basic
|
|
|
508,031
|
|
|
|
506,082
|
|
|
|
507,585
|
|
|
|
502,983
|
|
Diluted
|
|
|
508,427
|
|
|
|
506,365
|
|
|
|
507,976
|
|
|
|
503,213
|
|
|
|
|
|
|
|
|
|
|
Earnings per average common share:
|
|
|
|
|
|
|
|
|
Basic
|
|
$
|
0.84
|
|
|
$
|
0.73
|
|
|
$
|
1.53
|
|
|
$
|
1.64
|
|
Diluted
|
|
|
0.84
|
|
|
|
0.73
|
|
|
|
1.53
|
|
|
|
1.64
|
|
|
|
|
|
|
|
|
|
|
Cash dividends declared per common share
|
|
$
|
0.32
|
|
|
$
|
0.30
|
|
|
$
|
0.96
|
|
|
$
|
0.90
|
|
|
|
|
|
|
|
|
|
|
XCEL ENERGY INC. AND SUBSIDIARIES
Notes to Investor
Relations Earnings Release (Unaudited)
Due to the seasonality of Xcel Energy’s operating results, quarterly
financial results are not an appropriate base from which to project
annual results.
The only common equity securities that are publicly traded are common
shares of Xcel Energy Inc. The diluted earnings and EPS of each
subsidiary discussed below do not represent a direct legal interest in
the assets and liabilities allocated to such subsidiary but rather
represent a direct interest in our assets and liabilities as a whole.
Ongoing diluted EPS for Xcel Energy and by subsidiary is a financial
measure not recognized under GAAP. Ongoing diluted EPS is calculated by
dividing the net income or loss attributable to the controlling interest
of each subsidiary, adjusted for certain items, by the weighted average
fully diluted Xcel Energy Inc. common shares outstanding for the period.
We use this non-GAAP financial measure to evaluate and provide details
of Xcel Energy’s core earnings and underlying performance. We believe
this measurement is useful to investors in facilitating period over
period comparisons and evaluating or projecting financial results. This
non-GAAP financial measure should not be considered as an alternative to
measures calculated and reported in accordance with GAAP.
Note 1. Earnings Per Share Summary
The following table summarizes the diluted EPS for Xcel Energy:
|
|
|
|
|
|
|
Three Months Ended Sept. 30
|
|
Nine Months Ended Sept. 30
|
Diluted Earnings (Loss) Per Share
|
|
2015
|
|
2014
|
|
2015
|
|
2014
|
Public Service Company of Colorado (PSCo)
|
|
$
|
0.34
|
|
|
$
|
0.30
|
|
|
$
|
0.75
|
|
|
$
|
0.72
|
|
NSP-Minnesota
|
|
|
0.35
|
|
|
|
0.27
|
|
|
|
0.65
|
|
|
|
0.63
|
|
Southwestern Public Service Company (SPS)
|
|
|
0.12
|
|
|
|
0.13
|
|
|
|
0.21
|
|
|
|
0.23
|
|
NSP-Wisconsin
|
|
|
0.05
|
|
|
|
0.04
|
|
|
|
0.13
|
|
|
|
0.11
|
|
Equity earnings of unconsolidated subsidiaries
|
|
|
0.01
|
|
|
|
0.01
|
|
|
|
0.03
|
|
|
|
0.03
|
|
Regulated utility
|
|
|
0.87
|
|
|
|
0.75
|
|
|
|
1.77
|
|
|
|
1.72
|
|
Xcel Energy Inc. and other
|
|
|
(0.03
|
)
|
|
|
(0.02
|
)
|
|
|
(0.08
|
)
|
|
|
(0.08
|
)
|
Ongoing diluted EPS
|
|
|
0.84
|
|
|
|
0.73
|
|
|
|
1.69
|
|
|
|
1.64
|
|
Loss on Monticello life cycle management (LCM)/extended power
uprate (EPU) project (a)
|
|
|
—
|
|
|
|
—
|
|
|
|
(0.16
|
)
|
|
|
—
|
|
GAAP diluted EPS
|
|
$
|
0.84
|
|
|
$
|
0.73
|
|
|
$
|
1.53
|
|
|
$
|
1.64
|
|
|
(a) See Note 6.
|
|
PSCo — PSCo’s ongoing earnings increased $0.04 per share
for the third quarter of 2015 and $0.03 year-to-date. Higher revenue
primarily due to the Clean Air Clean Jobs Act (CACJA) rider (partially
offset by an electric base rate decrease), lower estimated electric
earnings test refunds and the impact of favorable weather were partially
offset by lower allowance for funds used during construction (AFUDC),
higher property taxes, depreciation and operating and maintenance (O&M)
expenses.
NSP-Minnesota — NSP-Minnesota’s ongoing earnings increased
$0.08 per share for the third quarter of 2015 and $0.02 year-to-date.
Revenues increased primarily due to electric rate cases in Minnesota,
North Dakota and South Dakota and were partially offset by higher
depreciation, higher O&M expenses, lower gas margins, higher interest
charges, unfavorable weather and weather-normalized sales decline.
SPS — SPS’ ongoing earnings decreased $0.01 per share for
the third quarter of 2015 and $0.02 year-to-date. Higher electric rates
in Texas were more than offset by higher O&M expenses, increased
depreciation, lower AFUDC and higher interest charges and unfavorable
weather.
NSP-Wisconsin — NSP-Wisconsin’s ongoing earnings per share
increased $0.01 for the third quarter of 2015 and $0.02 year-to-date.
Higher electric margins, primarily due to an electric rate increase and
weather-normalized sales growth and lower O&M expenses were partially
offset by higher depreciation and unfavorable weather.
The following table summarizes significant components contributing to
the changes in 2015 EPS compared with the same period in 2014:
|
|
|
|
|
Diluted Earnings (Loss) Per Share
|
|
Three Months Ended Sept. 30
|
|
Nine Months Ended Sept. 30
|
2014 GAAP and ongoing diluted EPS
|
|
$
|
0.73
|
|
|
$
|
1.64
|
|
|
|
|
|
|
Components of change — 2015 vs. 2014
|
|
|
|
|
Higher electric margins
|
|
|
0.14
|
|
|
|
0.25
|
|
Lower conservation and demand side management (DSM) program expenses
(offset by lower revenues)
|
|
|
0.02
|
|
|
|
0.07
|
|
Higher depreciation and amortization
|
|
|
(0.03
|
)
|
|
|
(0.09
|
)
|
Lower AFUDC — equity
|
|
|
(0.02
|
)
|
|
|
(0.06
|
)
|
Higher O&M expenses
|
|
|
—
|
|
|
|
(0.04
|
)
|
Higher taxes (other than income taxes)
|
|
|
(0.01
|
)
|
|
|
(0.04
|
)
|
Higher effective tax rate (ETR)
|
|
|
(0.01
|
)
|
|
|
(0.03
|
)
|
Higher interest charges
|
|
|
(0.01
|
)
|
|
|
(0.02
|
)
|
Dilution from equity issued through the direct stock purchase plan
and benefit plans
|
|
|
—
|
|
|
|
(0.02
|
)
|
Higher natural gas margins
|
|
|
0.02
|
|
|
|
—
|
|
Other, net
|
|
|
0.01
|
|
|
|
0.03
|
|
2015 ongoing diluted EPS
|
|
|
0.84
|
|
|
|
1.69
|
|
Loss on Monticello LCM/EPU project (a)
|
|
|
—
|
|
|
|
(0.16
|
)
|
2015 GAAP diluted EPS
|
|
$
|
0.84
|
|
|
$
|
1.53
|
|
|
(a) See Note 6.
|
|
Note 2. Regulated Utility Results
Estimated Impact of Temperature Changes on Regulated Earnings —
Unusually hot summers or cold winters increase electric and natural gas
sales, while mild weather reduces electric and natural gas sales. The
estimated impact of weather on earnings is based on the number of
customers, temperature variances and the amount of natural gas or
electricity the average customer historically uses per degree of
temperature. Accordingly, deviations in weather from normal levels can
affect Xcel Energy’s financial performance.
Degree-day or Temperature-Humidity Index (THI) data is used to estimate
amounts of energy required to maintain comfortable indoor temperature
levels based on each day’s average temperature and humidity. Heating
degree-days (HDD) is the measure of the variation in the weather based
on the extent to which the average daily temperature falls below 65°
Fahrenheit. Cooling degree-days (CDD) is the measure of the variation in
the weather based on the extent to which the average daily temperature
rises above 65° Fahrenheit. Each degree of temperature above 65°
Fahrenheit is counted as one cooling degree-day, and each degree of
temperature below 65° Fahrenheit is counted as one heating degree-day.
In Xcel Energy’s more humid service territories, a THI is used in place
of CDD, which adds a humidity factor to CDD. HDD, CDD and THI are most
likely to impact the usage of Xcel Energy’s residential and commercial
customers. Industrial customers are less sensitive to weather.
Normal weather conditions are defined as either the 20-year or 30-year
average of actual historical weather conditions. The historical period
of time used in the calculation of normal weather differs by
jurisdiction, based on regulatory practice. To calculate the impact of
weather on demand, a demand factor is applied to the weather impact on
sales as defined above to derive the amount of demand associated with
the weather impact.
The percentage decrease in normal and actual HDD, CDD and THI is
provided in the following table:
|
|
|
|
|
|
|
Three Months Ended Sept. 30
|
|
Nine Months Ended Sept. 30
|
|
|
2015 vs. Normal
|
|
2014 vs. Normal
|
|
2015 vs. 2014
|
|
2015 vs. Normal
|
|
2014 vs. Normal
|
|
2015 vs. 2014
|
HDD
|
|
(57.9
|
)%
|
|
(11.2
|
)%
|
|
(54.8
|
)%
|
|
(4.2
|
)%
|
|
11.5
|
%
|
|
(14.4
|
)%
|
CDD
|
|
15.1
|
|
|
(4.0
|
)
|
|
20.0
|
|
|
5.4
|
|
|
(2.5
|
)
|
|
8.3
|
|
THI
|
|
4.3
|
|
|
(17.3
|
)
|
|
29.2
|
|
|
(1.6
|
)
|
|
(11.2
|
)
|
|
13.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weather — The following table summarizes the estimated
impact of temperature variations on EPS compared with sales under normal
weather conditions:
|
|
|
|
|
|
|
Three Months Ended Sept. 30
|
|
Nine Months Ended Sept. 30
|
|
|
2015 vs. Normal
|
|
2014 vs. Normal
|
|
2015 vs. 2014
|
|
2015 vs. Normal
|
|
2014 vs. Normal
|
|
2015 vs. 2014
|
Retail electric
|
|
$
|
0.010
|
|
|
$
|
(0.024
|
)
|
|
$
|
0.034
|
|
|
$
|
(0.004
|
)
|
|
$
|
0.010
|
|
$
|
(0.014
|
)
|
Firm natural gas
|
|
|
(0.002
|
)
|
|
|
—
|
|
|
|
(0.002
|
)
|
|
|
(0.007
|
)
|
|
|
0.018
|
|
|
(0.025
|
)
|
Total
|
|
$
|
0.008
|
|
|
$
|
(0.024
|
)
|
|
$
|
0.032
|
|
|
$
|
(0.011
|
)
|
|
$
|
0.028
|
|
$
|
(0.039
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales Growth (Decline) — The following tables summarize
Xcel Energy and its subsidiaries’ sales growth (decline) for actual and
weather-normalized sales in 2015:
|
|
|
|
|
Three Months Ended Sept. 30
|
|
|
Xcel Energy
|
|
PSCo
|
|
NSP-Minnesota
|
|
NSP-Wisconsin
|
|
SPS
|
Actual
|
|
|
|
|
|
|
|
|
|
|
Electric residential (a)
|
|
4.3
|
%
|
|
4.2
|
%
|
|
3.3
|
%
|
|
6.2
|
%
|
|
6.6
|
%
|
Electric commercial and industrial
|
|
1.1
|
|
|
1.3
|
|
|
0.8
|
|
|
1.9
|
|
|
1.0
|
|
Total retail electric sales
|
|
1.9
|
|
|
2.2
|
|
|
1.4
|
|
|
3.0
|
|
|
1.4
|
|
Firm natural gas sales
|
|
(5.7
|
)
|
|
(7.9
|
)
|
|
(1.4
|
)
|
|
(3.1
|
)
|
|
N/A
|
|
|
|
|
|
Three Months Ended Sept. 30
|
|
|
Xcel Energy
|
|
PSCo
|
|
NSP-Minnesota
|
|
NSP-Wisconsin
|
|
SPS
|
Weather-normalized
|
|
|
|
|
|
|
|
|
|
|
Electric residential (a)
|
|
0.6
|
%
|
|
1.5
|
%
|
|
(0.2
|
)%
|
|
(0.6
|
)%
|
|
1.3
|
%
|
Electric commercial and industrial
|
|
—
|
|
|
(0.7
|
)
|
|
0.2
|
|
|
0.2
|
|
|
0.4
|
|
Total retail electric sales
|
|
0.1
|
|
|
—
|
|
|
—
|
|
|
(0.1
|
)
|
|
0.5
|
|
Firm natural gas sales
|
|
(0.3
|
)
|
|
(1.3
|
)
|
|
1.6
|
|
|
0.8
|
|
|
N/A
|
|
|
|
|
|
Nine Months Ended Sept. 30
|
|
|
Xcel Energy
|
|
PSCo
|
|
NSP-Minnesota
|
|
NSP-Wisconsin
|
|
SPS
|
Actual
|
|
|
|
|
|
|
|
|
|
|
Electric residential (a)
|
|
(1.4
|
)%
|
|
0.5
|
%
|
|
(2.9
|
)%
|
|
(4.6
|
)%
|
|
(0.3
|
)%
|
Electric commercial and industrial
|
|
—
|
|
|
—
|
|
|
(0.3
|
)
|
|
1.3
|
|
|
—
|
|
Total retail electric sales
|
|
(0.5
|
)
|
|
0.2
|
|
|
(1.1
|
)
|
|
(0.4
|
)
|
|
(0.2
|
)
|
Firm natural gas sales
|
|
(11.2
|
)
|
|
(9.0
|
)
|
|
(14.7
|
)
|
|
(12.5
|
)
|
|
N/A
|
|
|
|
|
|
Nine Months Ended Sept. 30
|
|
|
Xcel Energy
|
|
PSCo
|
|
NSP-Minnesota
|
|
NSP-Wisconsin
|
|
SPS
|
Weather-normalized
|
|
|
|
|
|
|
|
|
|
|
Electric residential (a)
|
|
(0.6
|
)%
|
|
(0.1
|
)%
|
|
(1.2
|
)%
|
|
(2.5
|
)%
|
|
1.0
|
%
|
Electric commercial and industrial
|
|
—
|
|
|
(0.7
|
)
|
|
0.1
|
|
|
1.5
|
|
|
0.3
|
|
Total retail electric sales
|
|
(0.2
|
)
|
|
(0.5
|
)
|
|
(0.3
|
)
|
|
0.3
|
|
|
0.3
|
|
Firm natural gas sales
|
|
(1.8
|
)
|
|
(2.3
|
)
|
|
(1.1
|
)
|
|
0.1
|
|
|
N/A
|
|
(a) Extreme weather variations and additional factors
such as windchill and cloud cover may not be reflected in
weather-normalized and actual growth estimates.
|
|
Weather-normalized Electric Year-to-Date Growth
(Decline)
-
SPS’ commercial and industrial (C&I) growth was driven by continued
expansion from oil and gas exploration and production in the
Southeastern New Mexico, Permian Basin area. This was partially offset
by the impact of wet weather which resulted in less irrigation by
agricultural customers. Residential growth reflects an increased
number of customers as well as greater use per customer.
-
NSP-Wisconsin’s electric sales growth was largely due to strong sales
to large C&I customers primarily in the oil, gas and sand mining
industries. Residential decline was primarily attributable to lower
use per customer.
-
PSCo’s C&I decline was primarily due to reduced sales to certain large
manufacturing customers and/or those that support the fracking
industry. Residential decrease was primarily the result of weaker use
per customer, partially offset by customer growth.
-
NSP-Minnesota’s C&I electric sales were flat as a result of higher use
for large customer class (particularly due to greater usage in the
petroleum industry), and an increase in the number of customers in
both the small and large classes, offset by lower use for the
remaining large and small customers in various industries. The
residential decrease was due to less use per customer, partially
offset by an increase in customer growth.
Weather-normalized Natural Gas Decline
-
Across natural gas service territories, lower natural gas sales
reflect a decline in customer use.
Electric Margin — Electric revenues and fuel and purchased
power expenses are largely impacted by the fluctuation in the price of
natural gas, coal and uranium used in the generation of electricity, but
as a result of the design of fuel recovery mechanisms to recover current
expenses, these price fluctuations have minimal impact on electric
margin. The following table details the electric revenues and margin:
|
|
|
|
|
|
|
Three Months Ended Sept. 30
|
|
Nine Months Ended Sept. 30
|
(Millions of Dollars)
|
|
2015
|
|
2014
|
|
2015
|
|
2014
|
Electric revenues
|
|
$
|
2,667
|
|
|
$
|
2,616
|
|
|
$
|
7,106
|
|
|
$
|
7,216
|
|
Electric fuel and purchased power
|
|
|
(1,015
|
)
|
|
|
(1,080
|
)
|
|
|
(2,870
|
)
|
|
|
(3,188
|
)
|
Electric margin
|
|
$
|
1,652
|
|
|
$
|
1,536
|
|
|
$
|
4,236
|
|
|
$
|
4,028
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table summarizes the components of the changes in electric
margin:
(Millions of Dollars)
|
|
Three Months Ended Sept. 30 2015 vs. 2014
|
|
Nine Months Ended Sept. 30 2015 vs. 2014
|
Non-fuel riders (a) (b)
|
|
$
|
20
|
|
|
$
|
87
|
|
Retail rate increases (b)
|
|
|
31
|
|
|
|
80
|
|
PSCo earnings test refund
|
|
|
26
|
|
|
|
61
|
|
Transmission revenue, net of costs
|
|
|
22
|
|
|
|
28
|
|
Conservation and DSM program revenues (offset by expenses)
|
|
|
(17
|
)
|
|
|
(46
|
)
|
Estimated impact of weather
|
|
|
26
|
|
|
|
(11
|
)
|
Other, net
|
|
|
8
|
|
|
|
9
|
|
Total increase in electric margin
|
|
$
|
116
|
|
|
$
|
208
|
|
|
(a) Primarily related to the new CACJA rider in
Colorado ($23 million and $74 million, respectively).
|
|
(b) Increase due to rate proceedings in Minnesota,
South Dakota, North Dakota, Texas, New Mexico and Wisconsin. These
increases were partially offset by a decline in Colorado retail
base rates, which was more than offset by increased CACJA rider
revenue as approved by the Colorado Public Utilities Commission
(CPUC) in the first quarter of 2015.
|
|
Natural Gas Margin — Total natural gas expense tends to
vary with changing sales requirements and the cost of natural gas
purchases. However, due to the design of purchased natural gas cost
recovery mechanisms for sales to retail customers, fluctuations in the
cost of natural gas has minimal impact on natural gas margin. The
following table details natural gas revenues and margin:
|
|
|
|
|
|
|
Three Months Ended Sept. 30
|
|
Nine Months Ended Sept. 30
|
(Millions of Dollars)
|
|
2015
|
|
2014
|
|
2015
|
|
2014
|
Natural gas revenues
|
|
$
|
216
|
|
|
$
|
237
|
|
|
$
|
1,216
|
|
|
$
|
1,485
|
|
Cost of natural gas sold and transported
|
|
|
(66
|
)
|
|
|
(99
|
)
|
|
|
(665
|
)
|
|
|
(934
|
)
|
Natural gas margin
|
|
$
|
150
|
|
|
$
|
138
|
|
|
$
|
551
|
|
|
$
|
551
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table summarizes the components of the changes in natural
gas margin:
|
|
|
|
|
(Millions of Dollars)
|
|
Three Months Ended Sept. 30 2015 vs.
2014
|
|
Nine Months Ended Sept. 30 2015 vs. 2014
|
Non-fuel riders, partially offset by expenses
|
|
$
|
7
|
|
|
$
|
25
|
|
Gas transport - Cherokee pipeline
|
|
|
2
|
|
|
|
4
|
|
Estimated impact of weather
|
|
|
(1
|
)
|
|
|
(20
|
)
|
Conservation and DSM program revenues (offset by expenses)
|
|
|
—
|
|
|
|
(11
|
)
|
Other, net
|
|
|
4
|
|
|
|
2
|
|
Total increase in natural gas margin
|
|
$
|
12
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
O&M Expenses — O&M expenses decreased $2.4 million, or
0.4 percent, for the third quarter of 2015 and increased $32.0 million,
or 1.9 percent, for the nine months ended Sept. 30, 2015. The
year-to-date increase in O&M is primarily due to the timing of planned
maintenance and overhauls at a number of our generation facilities as
well as an increase in contractor costs.
|
|
|
|
|
(Millions of Dollars)
|
|
Three Months Ended Sept. 30 2015 vs.
2014
|
|
Nine Months Ended Sept. 30 2015 vs. 2014
|
Plant generation costs
|
|
$
|
(8
|
)
|
|
$
|
13
|
|
Labor and contract labor
|
|
|
5
|
|
|
|
11
|
|
Electric and natural gas distribution expenses
|
|
|
7
|
|
|
|
7
|
|
Nuclear plant operations
|
|
|
(11
|
)
|
|
|
(7
|
)
|
Other, net
|
|
|
5
|
|
|
|
8
|
|
Total (decrease) increase in O&M expenses
|
|
$
|
(2
|
)
|
|
$
|
32
|
|
|
|
|
|
|
For the third quarter of 2015, O&M expenses decreased due to the
following:
-
Plant generation costs were related to the timing of overhauls and
discovery work; and
-
Nuclear expense decreases were primarily due to reduced costs driven
by operational initiatives and efficiencies.
Conservation and DSM Program Expenses — Conservation and
DSM program expenses decreased $17.9 million for the third quarter of
2015 and $58.3 million for the nine months ended Sept. 30, 2015. The
decreases were primarily attributable to lower electric and gas recovery
rates at NSP-Minnesota and PSCo. Lower conservation and DSM program
expenses are generally offset by lower revenues.
Depreciation and Amortization — Depreciation and
amortization increased $24.7 million, or 9.7 percent, for the third
quarter of 2015 and $71.2 million, or 9.4 percent, year-to-date.
Increases were primarily attributed to normal system expansion and lower
amortization of the excess depreciation reserve in Minnesota, partially
offset by Minnesota’s amortization of the Department of Energy
settlement.
Taxes (Other Than Income Taxes) — Taxes (other than income
taxes) increased $5.1 million, or 4.3 percent, for the third quarter of
2015 and $30.5 million, or 8.5 percent, for the nine months ended Sept.
30, 2015. Increases were due to higher property taxes primarily in
Colorado and Minnesota.
AFUDC, Equity and Debt — AFUDC decreased $10.8 million for
the third quarter of 2015 and $38.4 million year-to-date. Decreases were
primarily due to the implementation of the CACJA rider on Jan. 1, 2015,
facilitating earlier and alternative recovery of construction costs.
Interest Charges — Interest charges increased $9.3
million, or 6.5 percent, for the third quarter of 2015 and $20.0
million, or 4.7 percent, for the nine months ended Sept. 30, 2015.
Increases were primarily due to higher long-term debt levels, partially
offset by refinancings at lower interest rates.
Income Taxes — Income tax expense increased $43.1 million
for the third quarter of 2015 compared with the same period in 2014. The
increase was primarily due to higher pretax earnings and decreased
permanent plant-related adjustments in 2015. The ETR was 35.9 percent
for the third quarter of 2015 compared with 34.7 percent for the same
period in 2014. The higher ETR for 2015 was primarily due to the
plant-related adjustments referenced above.
Income tax expense decreased $3.5 million for the first nine months of
2015 compared with the same period in 2014. The decrease was primarily
due to lower pretax earnings, partially offset by decreased permanent
plant-related adjustments and the successful resolution of a 2010-2011
IRS audit issue in 2014. The ETR was 35.8 percent for the first nine
months of 2015, compared to 34.6 percent for the first nine months of
2014 primarily due to these adjustments.
Note 3. Xcel Energy Capital Structure,
Financing and Credit Ratings
Following is the capital structure of Xcel Energy:
|
|
|
|
|
(Billions of Dollars)
|
|
Sept. 30, 2015
|
|
Percentage of Total Capitalization
|
Current portion of long-term debt
|
|
$
|
0.5
|
|
2
|
%
|
Short-term debt
|
|
|
0.1
|
|
1
|
|
Long-term debt
|
|
|
12.7
|
|
53
|
|
Total debt
|
|
|
13.3
|
|
56
|
|
Common equity
|
|
|
10.5
|
|
44
|
|
Total capitalization
|
|
$
|
23.8
|
|
100
|
%
|
|
|
|
|
|
|
|
Credit Facilities — As of Oct. 26,
2015, Xcel Energy Inc. and its utility subsidiaries had the following
committed credit facilities available to meet liquidity needs:
|
|
|
|
|
|
|
|
|
|
|
(Millions of Dollars)
|
|
Credit Facility (a)
|
|
Drawn (b)
|
|
Available
|
|
Cash
|
|
Liquidity
|
Xcel Energy Inc.
|
|
$
|
1,000
|
|
$
|
—
|
|
$
|
1,000
|
|
$
|
6
|
|
$
|
1,006
|
PSCo
|
|
|
700
|
|
|
4
|
|
|
696
|
|
|
1
|
|
|
697
|
NSP-Minnesota
|
|
|
500
|
|
|
23
|
|
|
477
|
|
|
156
|
|
|
633
|
SPS
|
|
|
400
|
|
|
10
|
|
|
390
|
|
|
1
|
|
|
391
|
NSP-Wisconsin
|
|
|
150
|
|
|
15
|
|
|
135
|
|
|
1
|
|
|
136
|
Total
|
|
$
|
2,750
|
|
$
|
52
|
|
$
|
2,698
|
|
$
|
165
|
|
$
|
2,863
|
|
(a) These credit facilities expire in October 2019.
|
(b) Includes outstanding commercial paper and letters
of credit.
|
|
Credit Ratings — Access to the capital market at
reasonable terms is dependent in part on credit ratings. The following
ratings reflect the views of Moody’s Investors Service (Moody’s),
Standard & Poor’s Rating Services (Standard & Poor’s), and Fitch Ratings
(Fitch).
As of Oct. 26, 2015, the following represents the credit ratings
assigned to Xcel Energy Inc. and its utility subsidiaries:
|
|
|
|
|
|
|
|
|
Company
|
|
Credit Type
|
|
Moody’s
|
|
Standard & Poor’s
|
|
Fitch
|
Xcel Energy Inc.
|
|
Senior Unsecured Debt
|
|
A3
|
|
BBB+
|
|
BBB+
|
Xcel Energy Inc.
|
|
Commercial Paper
|
|
P-2
|
|
A-2
|
|
F2
|
NSP-Minnesota
|
|
Senior Unsecured Debt
|
|
A2
|
|
A-
|
|
A
|
NSP-Minnesota
|
|
Senior Secured Debt
|
|
Aa3
|
|
A
|
|
A+
|
NSP-Minnesota
|
|
Commercial Paper
|
|
P-1
|
|
A-2
|
|
F2
|
NSP-Wisconsin
|
|
Senior Unsecured Debt
|
|
A2
|
|
A-
|
|
A
|
NSP-Wisconsin
|
|
Senior Secured Debt
|
|
Aa3
|
|
A
|
|
A+
|
NSP-Wisconsin
|
|
Commercial Paper
|
|
P-1
|
|
A-2
|
|
F2
|
PSCo
|
|
Senior Unsecured Debt
|
|
A3
|
|
A-
|
|
A
|
PSCo
|
|
Senior Secured Debt
|
|
A1
|
|
A
|
|
A+
|
PSCo
|
|
Commercial Paper
|
|
P-2
|
|
A-2
|
|
F2
|
SPS
|
|
Senior Unsecured Debt
|
|
Baa1
|
|
A-
|
|
BBB+
|
SPS
|
|
Senior Secured Debt
|
|
A2
|
|
A
|
|
A-
|
SPS
|
|
Commercial Paper
|
|
P-2
|
|
A-2
|
|
F2
|
|
|
|
|
|
|
|
|
|
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.
During 2016, Xcel Energy Inc. and its utility subsidiaries anticipate
issuing the following:
-
Xcel Energy Inc. plans to issue approximately $600 million of senior
unsecured bonds;
-
NSP-Minnesota plans to issue approximately $250 million of first
mortgage bonds; and
-
SPS plans to issue approximately $350 million of first mortgage bonds.
During 2015, Xcel Energy Inc. and its utility subsidiaries completed the
following bond issuances:
-
In May, PSCo issued $250 million of 2.9 percent first mortgage bonds
due May 15, 2025;
-
In June, Xcel Energy Inc. issued $250 million of 1.2 percent senior
notes due June 1, 2017 and $250 million of 3.3 percent senior notes
due June 1, 2025;
-
In June, NSP-Wisconsin issued $100 million of 3.3 percent first
mortgage bonds due June 15, 2024;
-
In August, NSP-Minnesota issued $300 million of 2.2 percent first
mortgage bonds due Aug. 15, 2020 and $300 million of 4.0 percent first
mortgage bonds due Aug. 15, 2045; and
-
In September, SPS issued $200 million of 3.3 percent first mortgage
bonds due June 15, 2024.
Financing plans are subject to change, depending on capital
expenditures, internal cash generation, market conditions and other
factors.
Dividend Reinvestment and Stock Purchase Plan and Stock
Compensation Settlements — In October 2015, the Xcel Energy Inc.
Board of Directors authorized open market purchases by the plan
administrator as the source of shares for the dividend reinvestment
program as well as market purchases of up to 3.0 million shares for
stock compensation plan settlements.
Note 4. Rates and Regulation
NSP System Resource Plans — In January 2015, NSP-Minnesota
filed its 2016-2030 Integrated Resource Plan (the Plan) with the MPUC.
On Oct. 2, 2015, NSP-Minnesota filed revisions to the Plan. The revised
proposal addressed stakeholder recommendations as well as the final
Clean Power Plan (CPP) recently issued by the Environmental Protection
Agency. The revised Plan is based on four primary elements: (1)
accelerate the transition from coal energy to renewables, (2) preserve
regional system reliability, (3) pursue energy efficiency gains and grid
modernization, and (4) ensure customer benefits. The provisions included
in the Plan would allow for a 60 percent reduction in carbon emissions
from 2005 levels by 2030 and will result in 63 percent of NSP System
energy being carbon-free by 2030. Specific terms of the proposal include:
-
The addition of 800 megawatts (MW) of wind and 400 MW of utility scale
solar to the pre-2020 time-frame;
-
The addition of 1000 MW wind and 1000 MW utility scale solar between
2020-2030;
-
The retirement of Sherco Unit 2 in 2023 and Sherco Unit 1 in 2026;
-
The addition of a 230 MW (approximate capacity, actual size to be
determined) natural gas combustion turbine in North Dakota by 2025;
-
Replacement of Sherco coal generation with a 780 MW (approximate
capacity, actual size to be determined) natural gas combined cycle
unit at the Sherco site no later than 2026; and
-
Operation of the Monticello and Prairie Island nuclear plants through
their current license periods in the early 2030’s.
We believe this will provide substantial opportunities for the ownership
of replacement and renewable generation. The Plan is currently being
reviewed by the MPUC.
NSP-Wisconsin – Wisconsin 2016 Electric and Gas Rate Case —
In May 2015, NSP-Wisconsin filed a request with the Public
Service Commission of Wisconsin (PSCW) to increase rates for electric
and natural gas service effective Jan. 1, 2016. NSP-Wisconsin requested
an overall increase in annual electric rates of $27.4 million, or 3.9
percent, and an increase in natural gas rates of $5.9 million, or 5.0
percent.
The rate filing is based on a 2016 forecast test year, a return on
equity (ROE) of 10.2 percent, an equity ratio of 52.5 percent and a
forecasted average net investment rate base of approximately $1.2
billion for the electric utility and $111.2 million for the natural gas
utility.
On Oct. 1, 2015, the PSCW Staff and other intervenors, including the
Citizens Utility Board, filed their direct testimony in the case. The
PSCW Staff recommended an electric rate increase of $10.4 million, or
1.5 percent and a gas rate increase of $3.0 million, or 2.5 percent,
based on a ROE of 10.0 percent and an equity ratio of 52.5 percent. The
Citizens Utility Board recommended a ROE of 8.75 percent. None of the
intervenors presented a complete revenue requirements analysis. The
majority of the PSCW Staff adjustments relate to ROE, compensation
issues and capital related forecast disputes.
Key dates in the procedural schedule are as follows:
-
Initial Brief — Nov. 12, 2015;
-
Reply Brief — Nov. 19, 2015;
-
A PSCW decision is anticipated in December 2015; and
-
New rates effective on or about Jan. 1, 2016.
PSCo – Colorado 2015 Multi-Year Gas Rate Case — In March
2015, PSCo filed a multi-year request with the CPUC to increase Colorado
retail natural gas base rates by $40.5 million, or 3.5 percent, in 2015,
with subsequent step increases of $7.6 million, or 0.7 percent, in 2016
and $18.1 million, or 1.5 percent, in 2017.
The request is based on a historic test year (HTY) ended June 30, 2014
adjusted for known and measurable expenses and capital additions for
each of the subsequent periods in the multi-year plan and an equity
ratio of 56 percent. The rate case requests a ROE of 10.1 percent for
2015 and 2016 and 10.3 percent for 2017, and a rate base of $1.26
billion for 2015, $1.31 billion for 2016 and $1.36 billion for 2017.
PSCo also proposed a stay-out provision, in which PSCo would not request
implementation of new rates prior to January 2018, and implementation of
an earnings test for 2016 through 2017.
In addition, PSCo requested an extension of its pipeline system
integrity adjustment (PSIA) rider through 2020 to recover costs
associated with its pipeline integrity efforts. The request to extend
and modify the PSIA rider has an expected negative revenue impact of
approximately $0.1 million in 2015 and would provide incremental revenue
of $21.7 million for 2016 and $21.2 million for 2017. The following
table summarizes the request:
|
|
|
|
|
|
|
|
|
(Millions of Dollars)
|
|
2015
|
|
2016 Step
|
|
2017 Step
|
Total base rate increase
|
|
$
|
40.5
|
|
|
$
|
7.6
|
|
|
$
|
18.1
|
|
Incremental PSIA rider revenues
|
|
|
(0.1
|
)
|
|
|
21.7
|
|
|
|
21.2
|
|
Total revenue impact
|
|
$
|
40.4
|
|
|
$
|
29.3
|
|
|
$
|
39.3
|
|
|
|
|
|
|
|
|
|
|
In June 2015, the CPUC Staff (Staff) and the Office of Consumer Counsel
(OCC) issued their 2015 base rate recommendations. The following table
reflects the current positions of Staff and OCC:
|
|
|
|
|
(Millions of Dollars)
|
|
Staff
|
|
OCC
|
PSCo’s filed 2015 base rate request
|
|
$
|
40.5
|
|
|
$
|
40.5
|
|
ROE
|
|
|
(12.8
|
)
|
|
|
(13.7
|
)
|
Capital structure and cost of debt
|
|
|
(12.8
|
)
|
|
|
(4.8
|
)
|
Cherokee pipeline adjustment
|
|
|
(11.2
|
)
|
|
|
4.8
|
|
Move to 2014 HTY
|
|
|
(10.5
|
)
|
|
|
(16.4
|
)
|
O&M expenses
|
|
|
(3.5
|
)
|
|
|
(2.7
|
)
|
Other, net
|
|
|
(4.4
|
)
|
|
|
(1.9
|
)
|
Total adjustments
|
|
$
|
(55.2
|
)
|
|
$
|
(34.7
|
)
|
|
|
|
|
|
Recommended (decrease) increase
|
|
$
|
(14.7
|
)
|
|
$
|
5.8
|
|
|
|
|
|
|
The Staff’s recommendation for the PSIA rider is as follows:
|
|
|
|
|
(Millions of Dollars)
|
|
2016
|
|
2017
|
PSCo’s filed incremental PSIA request
|
|
$
|
21.7
|
|
|
$
|
21.2
|
|
Transfer PSIA O&M to base rates
|
|
|
(24.1
|
)
|
|
|
(2.0
|
)
|
ROE and capital structure
|
|
|
(8.2
|
)
|
|
|
(3.6
|
)
|
Transfer meter replacement program from base rates to PSIA
|
|
|
1.7
|
|
|
|
1.7
|
|
Total
|
|
$
|
(8.9
|
)
|
|
$
|
17.3
|
|
|
|
|
|
|
|
|
|
|
In July 2015, PSCo filed rebuttal testimony, maintaining its request for
a multi-year plan and requested ROEs and reflecting the most recent
sales forecast. PSCo’s rebuttal testimony, compared to its initial filed
base rate and rider request are summarized as follows:
|
|
|
|
|
|
|
(Millions of Dollars)
|
|
2015
|
|
2016 Step
|
|
2017 Step
|
PSCo’s filed base rate request
|
|
$
|
40.5
|
|
|
$
|
7.6
|
|
$
|
18.1
|
|
Shift O&M expenses between PSIA and base rates
|
|
|
—
|
|
|
|
7.0
|
|
|
6.4
|
|
Rebuttal corrections and adjustments
|
|
|
—
|
|
|
|
—
|
|
|
(7.7
|
)
|
Total base rate request
|
|
$
|
40.5
|
|
|
$
|
14.6
|
|
$
|
16.8
|
|
Incremental PSIA rider revenues
|
|
|
(0.1
|
)
|
|
|
14.7
|
|
|
21.7
|
|
Total revenue impact from rebuttal
|
|
$
|
40.4
|
|
|
$
|
29.3
|
|
$
|
38.5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
If PSCo’s revised request is accepted, PSIA revenue is projected to be
$67.0 million in 2015, $81.7 million in 2016 and $103.4 million in 2017.
Interim rates, subject to refund, were also implemented, effective Oct.
1, 2015, based on PSCo’s direct testimony. PSCo is expecting the ALJ’s
Recommended Decision in November 2015. The final CPUC decision is
expected no later than January 2016.
SPS – New Mexico 2015 Electric Rate Case — In October
2015, SPS filed an electric rate case with the New Mexico Public
Regulation Commission (NMPRC) for a net increase in base rates of
approximately $24.3 million for the New Mexico retail jurisdiction. The
proposed net amount reflects an increase in non-fuel base rates of $45.4
million and a decrease in base fuel revenue of approximately $21.1
million. The decrease in base fuel revenue will be reflected in
adjustments collected through the fuel and purchased power adjustment
clause. The rate filing is based on a June 30, 2015 HTY adjusted for
known and measurable changes, a requested ROE of 10.25 percent, an
electric jurisdictional rate base of approximately $734 million and an
equity ratio of 53.97 percent.
The major components of the requested rate increase are summarized below:
|
|
|
(Millions of Dollars)
|
|
Request
|
2015 base period deficiency
|
|
$
|
19.7
|
|
Capital expenditures — post-test year adjustments
|
|
|
12.3
|
|
Depreciation, higher rates reflecting changes in depreciable lives,
interim retirements and net salvage
|
|
|
3.7
|
|
Transmission revenue and expense, including charges paid to
Southwest Power Pool for construction of regionally shared
transmission projects
|
|
|
2.0
|
|
ROE, reflecting an increase from 9.96 percent to 10.25 percent
|
|
|
1.6
|
|
Rider revenue adjustments - gross receipts tax
|
|
|
1.3
|
|
Other, net
|
|
|
4.8
|
|
Requested rate increase
|
|
$
|
45.4
|
|
|
|
|
|
|
A NMPRC decision and implementation of final rates is anticipated in the
second half of 2016. In June 2015, the NMPRC dismissed a rate case
filing using a FTY based on new precedent. SPS has appealed that
decision to the New Mexico Supreme Court.
SPS – Texas 2015 Electric Rate Case — In December 2014,
SPS filed a retail electric rate case in Texas seeking an overall
increase in annual revenue of approximately $64.8 million, or 6.7
percent. The filing was based on a HTY ending June 2014, adjusted for
known and measurable changes, a ROE of 10.25 percent, an electric rate
base of approximately $1.6 billion and an equity ratio of 53.97 percent.
In March 2015, SPS revised its requested increase to $58.9 million based
on updated information.
SPS is seeking a waiver of the Public Utility Commission of Texas (PUCT)
post-test year adjustment rule which would allow for inclusion of $392
million (SPS total company) additional capital investment for the period
July 1, 2014 through Dec. 31, 2014.
In June 2015, SPS filed rebuttal testimony supporting a revised rate
increase of approximately $42.1 million, or 4.4 percent.
On Oct. 12, 2015, the administrative law judges (ALJs) issued their
Proposal for Decision (PFD) and recommended a rate increase of
approximately $1.2 million, based on a ROE of 9.70 percent and an equity
ratio of 53.97 percent.
The following table reflects the current positions of Alliance of Xcel
Municipalities (AXM), the Office of Public Utility Counsel (OPUC), the
PUCT Staff (Staff), SPS as well as the estimated recommendation of the
ALJs:
|
|
|
|
|
|
|
|
|
|
|
(Millions of Dollars)
|
|
AXM
|
|
OPUC
|
|
Staff
|
|
SPS Rebuttal Testimony
|
|
ALJs’ PFD (a)
|
SPS’ revised rate request
|
|
$
|
58.9
|
|
|
$
|
58.9
|
|
|
$
|
58.9
|
|
|
$
|
58.9
|
|
|
$
|
42.1
|
|
Investment for capital expenditures — post-test year adjustments
|
|
|
(11.3
|
)
|
|
|
(23.8
|
)
|
|
|
(23.8
|
)
|
|
|
—
|
|
|
|
(16.7
|
)
|
Lower ROE
|
|
|
(10.9
|
)
|
|
|
(13.5
|
)
|
|
|
(12.1
|
)
|
|
|
—
|
|
|
|
(6.3
|
)
|
Rate base adjustments (largely the removal of the prepaid pension
asset)
|
|
|
(6.2
|
)
|
|
|
(6.8
|
)
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
O&M expense adjustments
|
|
|
(13.7
|
)
|
|
|
(11.0
|
)
|
|
|
(7.9
|
)
|
|
|
(1.6
|
)
|
|
|
(5.3
|
)
|
Depreciation expense
|
|
|
(13.3
|
)
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
(3.9
|
)
|
Property taxes
|
|
|
—
|
|
|
|
(1.2
|
)
|
|
|
(4.4
|
)
|
|
|
(1.8
|
)
|
|
|
(3.7
|
)
|
Revenue adjustments
|
|
|
(2.2
|
)
|
|
|
(0.2
|
)
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
Wholesale load reductions
|
|
|
(13.2
|
)
|
|
|
—
|
|
|
|
(11.1
|
)
|
|
|
—
|
|
|
|
—
|
|
Southwest Power Pool transmission expansion plan
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
(7.3
|
)
|
|
|
(4.2
|
)
|
Other, net
|
|
|
(1.7
|
)
|
|
|
(0.6
|
)
|
|
|
(2.2
|
)
|
|
|
(1.8
|
)
|
|
|
(0.6
|
)
|
Total recommendation
|
|
$
|
(13.6
|
)
|
|
$
|
1.8
|
|
|
$
|
(2.6
|
)
|
|
$
|
46.4
|
|
|
$
|
1.4
|
|
Adjustment to move rate case expenses to a separate docket
|
|
|
—
|
|
|
|
—
|
|
|
|
—
|
|
|
|
(4.3
|
)
|
|
|
(0.2
|
)
|
Recommendation, excluding rate case expenses
|
|
$
|
(13.6
|
)
|
|
$
|
1.8
|
|
|
$
|
(2.6
|
)
|
|
$
|
42.1
|
|
|
$
|
1.2
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) The ALJs’ recommendation reflects proposed
adjustments to SPS’ rebuttal testimony which supports a $42.1
million rate increase.
|
|
SPS believes the ALJs’ recommended decision contains discrepancies and a
revised calculation will result in a higher recommended rate increase.
On Oct. 21, 2015, SPS filed a letter notifying the PUCT of its concerns
regarding the calculation.
New rates will be made effective retroactive to June 11, 2015 as
established by the PUCT. A PUCT decision is expected in December 2015.
Note 5. Xcel Energy Earnings Guidance
and Long-Term EPS and Dividend Growth Rate Objectives
Xcel Energy Earnings Guidance — Xcel Energy’s revised 2015
ongoing earnings guidance to $2.05 to $2.15 per share, compared with the
previous issued guidance of $2.00 to $2.15 per share. Key assumptions
related to 2015 earnings are detailed below:
-
Constructive outcomes in all rate case and regulatory proceedings.
-
Normal weather patterns are experienced for the remainder of the year.
-
Weather-normalized retail electric utility sales are projected to be
relatively flat.
-
Weather-normalized retail firm natural gas sales are projected to
decline approximately 2 percent.
-
Capital rider revenue is projected to increase by $150 million to $160
million over 2014 levels.
-
The change in O&M expenses is projected to be within a range of 0
percent to 2 percent from 2014 levels.
-
Depreciation expense is projected to increase $110 million to $120
million over 2014 levels. The change in the depreciation assumption
reflects an adjustment for eliminations and will not have any impact
on earnings.
-
Property taxes are projected to increase approximately $50 million to
$60 million over 2014 levels.
-
Interest expense (net of AFUDC — debt) is projected to increase $40
million to $50 million over 2014 levels.
-
AFUDC — equity is projected to decline approximately $30 million to
$40 million from 2014 levels.
-
The ETR is projected to be approximately 34 percent to 36 percent.
-
Average common stock and equivalents are projected to be approximately
508 million shares.
Xcel Energy’s 2016 ongoing earnings guidance is $2.12 to $2.27 per
share. Key assumptions related to 2016 earnings are detailed below:
-
Constructive outcomes in all rate case and regulatory proceedings,
including the implementation of interim rates in Minnesota consistent
with historical precedent.
-
Normal weather patterns are experienced for the year.
-
Weather-normalized retail electric utility sales are projected to
increase approximately 0.5 percent to 1.0 percent.
-
Weather normalized retail firm natural gas sales are projected to be
relatively flat.
-
Capital rider revenue is projected to increase by $70 million to $80
million over 2015 levels.
-
The change in O&M expenses is projected to be within a range of 0
percent to 2 percent from 2015 levels.
-
Depreciation expense is projected to increase approximately $200
million over 2015 levels.
-
Property taxes are projected to increase approximately $40 million to
$50 million over 2015 levels.
-
Interest expense (net of AFUDC — debt) is projected to increase $40
million to $50 million over 2015 levels.
-
AFUDC — equity is projected to decline approximately $5 million to $10
million from 2015 levels.
-
The ETR is projected to be approximately 34 percent to 36 percent.
-
Average common stock and equivalents are projected to be approximately
509 million shares.
Long-Term EPS and Dividend Growth Rate Objectives — Xcel
Energy expects to deliver an attractive total return to our shareholders
through a combination of earnings growth and dividend yield, based on
the following long-term objectives:
-
Deliver long-term annual EPS growth of 4 percent to 6 percent, based
on weather-normalized, ongoing 2014 EPS of $2.00;
-
Deliver annual dividend increases of 5 percent to 7 percent;
-
Target a dividend payout ratio of 60 percent to 70 percent; and
-
Maintain senior unsecured debt credit ratings in the BBB+ to A range.
Ongoing earnings is calculated using net income and adjusting for
certain nonrecurring or infrequent items that are, in management’s view,
not reflective of ongoing operations.
Note 6. Non-GAAP Reconciliation
Xcel Energy’s reported earnings are prepared in accordance with GAAP.
Xcel Energy’s management believes that ongoing earnings, or GAAP
earnings adjusted for certain items, reflect management’s performance in
operating the company and provides a meaningful representation of the
underlying performance of Xcel Energy’s core business. In addition, Xcel
Energy’s management uses ongoing earnings internally for financial
planning and analysis, for reporting of results to the Board of
Directors and when communicating its earnings outlook to analysts and
investors. This non-GAAP financial measure should not be considered as
an alternative to measures calculated and reported in accordance with
GAAP.
The following table provides a reconciliation of ongoing earnings to
GAAP earnings (net income):
|
|
|
|
|
|
|
|
|
Three Months Ended Sept. 30
|
|
Nine Months Ended Sept. 30
|
(Thousands of Dollars)
|
|
2015
|
|
2014
|
|
2015
|
|
2014
|
Ongoing earnings
|
|
$
|
426,463
|
|
|
$
|
368,582
|
|
|
$
|
854,610
|
|
|
$
|
824,967
|
|
Loss on Monticello LCM/EPU project
|
|
|
—
|
|
|
|
—
|
|
|
|
(79,150
|
)
|
|
|
—
|
|
GAAP earnings
|
|
$
|
426,463
|
|
|
$
|
368,582
|
|
|
$
|
775,460
|
|
|
$
|
824,967
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss on Monticello LCM/EPU Project — In March 2015, the
MPUC approved full recovery, including a return, on $415 million of the
project costs, inclusive of AFUDC, but only allow recovery of the
remaining $333 million of costs with no return on this portion of the
investment for years 2015 and beyond. As a result of this decision, Xcel
Energy recorded a pre-tax charge of approximately $129 million, or $79
million net of tax, in the first quarter of 2015. Given the nature of
this specific item, it has been excluded from ongoing earnings.
|
XCEL ENERGY INC. AND SUBSIDIARIES EARNINGS RELEASE
SUMMARY (Unaudited) (amounts in thousands, except per
share data)
|
|
|
|
Three Months Ended Sept. 30
|
|
|
2015
|
|
2014
|
Operating revenues:
|
|
|
|
|
Electric and natural gas
|
|
$
|
2,883,499
|
|
|
$
|
2,853,000
|
|
Other
|
|
|
17,813
|
|
|
|
16,807
|
|
Total operating revenues
|
|
|
2,901,312
|
|
|
|
2,869,807
|
|
|
|
|
|
|
Net income
|
|
$
|
426,463
|
|
|
$
|
368,582
|
|
|
|
|
|
|
Weighted average diluted common shares outstanding
|
|
|
508,427
|
|
|
|
506,365
|
|
|
|
|
|
|
Components of EPS — Diluted
|
|
|
|
|
Regulated utility
|
|
$
|
0.87
|
|
|
$
|
0.75
|
|
Xcel Energy Inc. and other costs
|
|
|
(0.03
|
)
|
|
|
(0.02
|
)
|
Ongoing diluted EPS
|
|
|
0.84
|
|
|
|
0.73
|
|
Loss on Monticello LCM/EPU project (a)
|
|
|
—
|
|
|
|
—
|
|
GAAP diluted EPS
|
|
$
|
0.84
|
|
|
$
|
0.73
|
|
|
|
|
|
|
|
|
Nine Months Ended Sept. 30
|
|
|
2015
|
|
2014
|
Operating revenues:
|
|
|
|
|
Electric and natural gas
|
|
$
|
8,321,949
|
|
|
$
|
8,701,163
|
|
Other
|
|
|
56,716
|
|
|
|
56,344
|
|
Total operating revenues
|
|
|
8,378,665
|
|
|
|
8,757,507
|
|
|
|
|
|
|
Net income
|
|
$
|
775,460
|
|
|
$
|
824,967
|
|
|
|
|
|
|
Weighted average diluted common shares outstanding
|
|
|
507,976
|
|
|
|
503,213
|
|
|
|
|
|
|
Components of EPS — Diluted
|
|
|
|
|
Regulated utility
|
|
$
|
1.77
|
|
|
$
|
1.72
|
|
Xcel Energy Inc. and other costs
|
|
|
(0.08
|
)
|
|
|
(0.08
|
)
|
Ongoing diluted EPS
|
|
|
1.69
|
|
|
|
1.64
|
|
Loss on Monticello LCM/EPU project (a)
|
|
|
(0.16
|
)
|
|
|
—
|
|
GAAP diluted EPS
|
|
$
|
1.53
|
|
|
$
|
1.64
|
|
Book value per share
|
|
$
|
20.79
|
|
|
$
|
20.09
|
|
|
|
|
|
|
|
|
|
|
(a) See Note 6.
|
|
|
|
|
|
|
|
|
|
View source version on businesswire.com: http://www.businesswire.com/news/home/20151029005136/en/
Copyright Business Wire 2015