Xcel Energy Inc. (NYSE:XEL) today reported 2014 second quarter GAAP
earnings of $195 million, or $0.39 per share, compared with $197
million, or $0.40 per share, in the same period in 2013.
Electric and gas margins rose in the second quarter of 2014 primarily
driven by new rates in various jurisdictions. This positive factor,
along with lower interest expense, was more than offset by higher
operating and maintenance expenses, property taxes, and depreciation and
amortization expense as well as less favorable weather.
“Our second quarter financial results were in line with our projections
and we are pleased with our performance through the first six months,”
stated Chairman, President and Chief Executive Officer Ben Fowke.
“Notably, we are encouraged to see the continuation of
better-than-expected weather-normalized sales growth. In addition, our
year-to-date operating and maintenance expenses are consistent with our
plan and we are on track to meet our guidance of a 2 to 3 percent annual
increase over 2013 levels.
“During the second quarter, we filed rate cases in Colorado, Wisconsin
and South Dakota and continued settlement discussions in Texas. We also
received initial recommendations from the intervenors for the Minnesota
electric rate case and the Minnesota Department of Commerce regarding
the Monticello prudence review. We believe our request in Minnesota is
warranted and the costs associated with Monticello uprate and life
extension project were prudent. We will continue to provide support for
our positions and expect to reach constructive outcomes in each of these
regulatory proceedings.
“We are reaffirming our 2014 ongoing earnings guidance of $1.90 to $2.05
per share, which is based on several key assumptions, including
constructive outcomes of our regulatory proceedings,” said 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.
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US Dial-In:
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(877) 941-8609
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International Dial-In:
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(480) 629-9692
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Conference ID:
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4687079
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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 Investors. If you are unable to
participate in the live event, the call will be available for replay
from 1:00 p.m. CDT on July 31 through 11:59 p.m. CDT on Aug. 1.
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Replay Numbers
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US Dial-In:
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(800) 406-7325
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International Dial-In:
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(303) 590-3030
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Access Code:
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4687079#
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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 2014 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 do not undertake any obligation to update them to
reflect changes that occur after that date. Factors that could cause
actual results to differ materially include, but are not limited to:
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 Inc. and its subsidiaries; unusual
weather; effects of geopolitical events, including war and acts of
terrorism; 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; actions by
regulatory bodies impacting our nuclear operations, including those
affecting costs, operations or the approval of requests pending before
the Nuclear Regulatory Commission; financial or regulatory accounting
policies imposed by regulatory bodies; availability or cost of capital;
employee work force factors; and the other risk factors listed from time
to time by Xcel Energy in reports filed with the Securities and Exchange
Commission (SEC), including Risk Factors in Item 1A and Exhibit 99.01 of
Xcel Energy Inc.’s Annual Report on Form 10-K for the year ended
Dec. 31, 2013 and Quarterly Report on Form 10-Q for the quarter ended
March 31, 2014.
This information is not given in connection with any sale, offer for
sale or offer to buy any security.
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XCEL ENERGY INC. AND SUBSIDIARIES
|
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CONSOLIDATED STATEMENTS OF INCOME (Unaudited)
|
|
(amounts in thousands, except per share data)
|
|
|
|
|
|
|
Three Months Ended June 30
|
|
|
Six Months Ended June 30
|
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|
|
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2014
|
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2013
|
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|
2014
|
|
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2013
|
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Operating revenues
|
|
|
|
|
|
|
|
|
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|
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Electric
|
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|
$
|
2,297,638
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|
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$
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2,219,877
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$
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4,599,348
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|
|
$
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4,312,073
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Natural gas
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369,127
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|
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341,321
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|
|
|
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1,248,815
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|
|
|
|
1,010,917
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Other
|
|
|
|
18,331
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|
|
|
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17,715
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|
|
|
|
39,537
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|
|
|
|
38,772
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Total operating revenues
|
|
|
|
2,685,096
|
|
|
|
|
2,578,913
|
|
|
|
|
5,887,700
|
|
|
|
|
5,361,762
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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Operating expenses
|
|
|
|
|
|
|
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|
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Electric fuel and purchased power
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1,041,322
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|
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1,011,044
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2,108,643
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|
|
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1,936,087
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Cost of natural gas sold and transported
|
|
|
|
210,901
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|
|
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|
188,765
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|
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834,729
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|
|
|
|
628,140
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|
Cost of sales — other
|
|
|
|
7,642
|
|
|
|
|
7,881
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|
|
|
|
16,771
|
|
|
|
|
16,292
|
|
|
Operating and maintenance expenses
|
|
|
|
585,604
|
|
|
|
|
562,557
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|
|
|
|
1,145,747
|
|
|
|
|
1,091,788
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Conservation and demand side management program expenses
|
|
|
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70,834
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|
|
|
|
60,445
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|
|
|
|
148,380
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|
|
|
|
124,477
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Depreciation and amortization
|
|
|
|
255,307
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|
|
|
|
243,934
|
|
|
|
|
501,250
|
|
|
|
|
492,640
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|
Taxes (other than income taxes)
|
|
|
|
116,278
|
|
|
|
|
102,051
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|
|
|
|
240,980
|
|
|
|
|
215,478
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Total operating expenses
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|
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2,287,888
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|
|
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|
2,176,677
|
|
|
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|
4,996,500
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|
|
|
|
4,504,902
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
|
|
397,208
|
|
|
|
|
402,236
|
|
|
|
|
891,200
|
|
|
|
|
856,860
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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Other income, net
|
|
|
|
82
|
|
|
|
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413
|
|
|
|
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3,283
|
|
|
|
|
4,335
|
|
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Equity earnings of unconsolidated subsidiaries
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|
|
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7,811
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|
|
|
|
7,529
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|
|
|
|
15,249
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|
|
|
|
15,106
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|
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Allowance for funds used during construction — equity
|
|
|
|
23,608
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|
|
|
|
22,109
|
|
|
|
|
45,515
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|
|
|
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41,863
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|
|
|
|
|
|
|
|
|
|
|
|
|
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|
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Interest charges and financing costs
|
|
|
|
|
|
|
|
|
|
|
|
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Interest charges — includes other financing costs of
$5,614, $12,229, $11,406 and $18,038, respectively
|
|
|
|
139,400
|
|
|
|
|
146,853
|
|
|
|
|
278,494
|
|
|
|
|
286,484
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|
|
Allowance for funds used during construction — debt
|
|
|
|
(10,113
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)
|
|
|
|
(10,316
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)
|
|
|
|
(19,661
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)
|
|
|
|
(19,074
|
)
|
|
Total interest charges and financing costs
|
|
|
|
129,287
|
|
|
|
|
136,537
|
|
|
|
|
258,833
|
|
|
|
|
267,410
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes
|
|
|
|
299,422
|
|
|
|
|
295,750
|
|
|
|
|
696,414
|
|
|
|
|
650,754
|
|
|
Income taxes
|
|
|
|
104,258
|
|
|
|
|
98,893
|
|
|
|
|
240,029
|
|
|
|
|
217,327
|
|
|
Net income
|
|
|
$
|
195,164
|
|
|
|
$
|
196,857
|
|
|
|
$
|
456,385
|
|
|
|
$
|
433,427
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average common shares outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
|
503,272
|
|
|
|
|
497,747
|
|
|
|
|
501,408
|
|
|
|
|
493,786
|
|
|
Diluted
|
|
|
|
503,456
|
|
|
|
|
498,036
|
|
|
|
|
501,612
|
|
|
|
|
494,303
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings per average common share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
$
|
0.39
|
|
|
|
$
|
0.40
|
|
|
|
$
|
0.91
|
|
|
|
$
|
0.88
|
|
|
Diluted
|
|
|
|
0.39
|
|
|
|
|
0.40
|
|
|
|
|
0.91
|
|
|
|
|
0.88
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash dividends declared per common share
|
|
|
$
|
0.30
|
|
|
|
$
|
0.28
|
|
|
|
$
|
0.60
|
|
|
|
$
|
0.55
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 per share (EPS) of each
subsidiary discussed below do not represent a direct legal interest in
the assets and liabilities allocated to such subsidiary but rather
represent a direct interest in our assets and liabilities as a whole.
Diluted EPS by subsidiary is a financial measure not recognized under
GAAP and is calculated by dividing the net income or loss attributable
to the controlling interest of each subsidiary 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 earnings results. We believe that this measurement is useful to
investors to evaluate the actual and projected financial performance and
contribution of our subsidiaries. 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:
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|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30
|
|
|
Six Months Ended June 30
|
|
Diluted Earnings (Loss) Per Share
|
|
|
2014
|
|
|
2013
|
|
|
2014
|
|
|
2013
|
|
Public Service Company of Colorado (PSCo)
|
|
|
$
|
0.18
|
|
|
|
$
|
0.20
|
|
|
|
$
|
0.41
|
|
|
|
$
|
0.43
|
|
|
NSP-Minnesota
|
|
|
|
0.15
|
|
|
|
|
0.16
|
|
|
|
|
0.37
|
|
|
|
|
0.37
|
|
|
Southwestern Public Service Company (SPS)
|
|
|
|
0.06
|
|
|
|
|
0.05
|
|
|
|
|
0.09
|
|
|
|
|
0.08
|
|
|
NSP-Wisconsin
|
|
|
|
0.02
|
|
|
|
|
0.02
|
|
|
|
|
0.07
|
|
|
|
|
0.06
|
|
|
Equity earnings of unconsolidated subsidiaries
|
|
|
|
0.01
|
|
|
|
|
0.01
|
|
|
|
|
0.02
|
|
|
|
|
0.02
|
|
|
Regulated utility
|
|
|
|
0.42
|
|
|
|
|
0.44
|
|
|
|
|
0.96
|
|
|
|
|
0.96
|
|
|
Xcel Energy Inc. and other
|
|
|
|
(0.03
|
)
|
|
|
|
(0.04
|
)
|
|
|
|
(0.05
|
)
|
|
|
|
(0.08
|
)
|
|
GAAP diluted EPS
|
|
|
$
|
0.39
|
|
|
|
$
|
0.40
|
|
|
|
$
|
0.91
|
|
|
|
$
|
0.88
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PSCo — PSCo’s earnings decreased $0.02 per share for the
second quarter and six months ended June 30, 2014. Higher electric and
natural gas rates and weather-normalized sales growth were offset by
increased property taxes, depreciation, accruals associated with
electric earnings test refund obligations as well as the impact of
weather. See Note 4 for further discussion of rates and regulation.
NSP-Minnesota — NSP-Minnesota’s earnings decreased $0.01
per share for the second quarter of 2014 and were flat year-to-date.
Electric rate increases in Minnesota (interim, subject to refund) and
North Dakota, lower depreciation expense, weather-normalized sales
growth and the favorable year-over-year impact of weather were offset by
higher operating and maintenance (O&M) expenses, lower allowance for
funds used during construction (AFUDC) and higher property taxes.
SPS — SPS’ earnings increased $0.01 per share for the
second quarter and six months ended June 30, 2014. The positive impact
of higher electric rates in Texas and New Mexico and weather-normalized
sales growth were partially offset by increased O&M expenses and
depreciation.
NSP-Wisconsin — NSP-Wisconsin’s earnings were flat for the
second quarter of 2014 and increased $0.01 per share year-to-date.
Higher electric and natural gas margins, due to an electric rate
increase effective in January 2014, and weather-normalized sales growth
were partially offset by higher O&M expenses.
The following table summarizes significant components contributing to
the changes in 2014 EPS compared with the same period in 2013, which are
discussed in more detail later in the release:
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|
|
|
|
|
|
|
|
|
|
Three Months
|
|
|
Six Months
|
|
Diluted Earnings (Loss) Per Share
|
|
|
Ended June 30
|
|
|
Ended June 30
|
|
2013 GAAP diluted EPS
|
|
|
$
|
0.40
|
|
|
|
$
|
0.88
|
|
|
|
|
|
|
|
|
|
|
Components of change — 2014 vs. 2013
|
|
|
|
|
|
|
|
Higher electric margins
|
|
|
|
0.06
|
|
|
|
|
0.14
|
|
|
Higher natural gas margins
|
|
|
|
0.01
|
|
|
|
|
0.04
|
|
|
Lower interest charges
|
|
|
|
0.01
|
|
|
|
|
0.01
|
|
|
Higher AFUDC — equity
|
|
|
|
—
|
|
|
|
|
0.01
|
|
|
Higher O&M expenses
|
|
|
|
(0.03
|
)
|
|
|
|
(0.07
|
)
|
|
Higher taxes (other than income taxes)
|
|
|
|
(0.02
|
)
|
|
|
|
(0.03
|
)
|
|
Higher conservation and demand side management (DSM) program expenses
|
|
|
|
(0.01
|
)
|
|
|
|
(0.03
|
)
|
|
Higher depreciation and amortization
|
|
|
|
(0.01
|
)
|
|
|
|
(0.01
|
)
|
|
Dilution from equity issued through the at-the-market (ATM) program,
direct stock purchase plan and benefit plans
|
|
|
|
—
|
|
|
|
|
(0.01
|
)
|
|
Other, net
|
|
|
|
(0.02
|
)
|
|
|
|
(0.02
|
)
|
|
2014 GAAP diluted EPS
|
|
|
$
|
0.39
|
|
|
|
$
|
0.91
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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, conversely, 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, from both an energy and
demand perspective.
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, and 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 the time period used by the regulator in
establishing estimated volumes in the rate setting process. To calculate
the impact of weather on demand, a demand factor is applied to the
weather impact on sales as defined above to derive the amount of demand
associated with the weather impact.
The percentage increase (decrease) in normal and actual HDD, CDD and THI
are provided in the following table:
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30
|
|
|
Six Months Ended June 30
|
|
|
|
|
2014 vs.
|
|
|
2013 vs.
|
|
|
2014 vs.
|
|
|
2014 vs.
|
|
|
2013 vs.
|
|
|
2014 vs.
|
|
|
|
|
Normal
|
|
|
Normal
|
|
|
2013
|
|
|
Normal
|
|
|
Normal
|
|
|
2013
|
|
HDD
|
|
|
4.5
|
%
|
|
|
22.5
|
%
|
|
|
(16.6
|
)%
|
|
|
12.3
|
%
|
|
|
7.2
|
%
|
|
|
3.7
|
%
|
|
CDD
|
|
|
0.6
|
|
|
|
52.2
|
|
|
|
(29.6
|
)
|
|
|
1.0
|
|
|
|
51.8
|
|
|
|
(28.9
|
)
|
|
THI
|
|
|
9.3
|
|
|
|
6.6
|
|
|
|
7.1
|
|
|
|
8.4
|
|
|
|
6.5
|
|
|
|
7.1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weather — The following table summarizes the estimated
impact of temperature variations on EPS compared with sales under normal
weather conditions:
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30
|
|
|
Six Months Ended June 30
|
|
|
|
|
2014 vs.
|
|
|
2013 vs.
|
|
|
2014 vs.
|
|
|
2014 vs.
|
|
|
2013 vs.
|
|
|
2014 vs.
|
|
|
|
|
Normal
|
|
|
Normal
|
|
|
2013
|
|
|
Normal
|
|
|
Normal
|
|
|
2013
|
|
Retail electric
|
|
|
$
|
0.002
|
|
|
$
|
0.027
|
|
|
$
|
(0.025
|
)
|
|
|
$
|
0.034
|
|
|
$
|
0.031
|
|
|
$
|
0.003
|
|
Firm natural gas
|
|
|
|
0.001
|
|
|
|
0.007
|
|
|
|
(0.006
|
)
|
|
|
|
0.019
|
|
|
|
0.016
|
|
|
|
0.003
|
|
Total
|
|
|
$
|
0.003
|
|
|
$
|
0.034
|
|
|
$
|
(0.031
|
)
|
|
|
$
|
0.053
|
|
|
$
|
0.047
|
|
|
$
|
0.006
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Sales Growth (Decline) — The following tables summarize
Xcel Energy and its subsidiaries’ sales growth (decline) for actual and
weather-normalized sales in 2014:
|
|
|
|
|
|
|
Three Months Ended June 30
|
|
|
|
NSP-Minnesota
|
|
NSP-Wisconsin
|
|
PSCo
|
|
SPS
|
|
Xcel Energy
|
|
Actual
|
|
|
|
|
|
|
|
|
|
|
|
Electric residential
|
|
0.2
|
%
|
|
1.7
|
%
|
|
(5.0
|
)%
|
|
(2.8
|
)%
|
|
(2.0
|
)%
|
|
Electric commercial and industrial
|
|
(0.4
|
)
|
|
4.3
|
|
|
(1.5
|
)
|
|
3.1
|
|
|
0.4
|
|
|
Total retail electric sales
|
|
(0.3
|
)
|
|
3.6
|
|
|
(2.5
|
)
|
|
1.9
|
|
|
(0.2
|
)
|
|
Firm natural gas sales
|
|
0.3
|
|
|
(0.8
|
)
|
|
(6.0
|
)
|
|
N/A
|
|
|
(3.7
|
)
|
|
|
|
|
|
|
|
Three Months Ended June 30
|
|
|
|
NSP-Minnesota
|
|
NSP-Wisconsin
|
|
PSCo
|
|
SPS
|
|
Xcel Energy
|
|
Weather-normalized
|
|
|
|
|
|
|
|
|
|
|
|
Electric residential
|
|
2.0
|
%
|
|
0.8
|
%
|
|
1.1
|
%
|
|
1.0
|
%
|
|
1.4
|
%
|
|
Electric commercial and industrial
|
|
(0.1
|
)
|
|
4.0
|
|
|
1.1
|
|
|
3.7
|
|
|
1.5
|
|
|
Total retail electric sales
|
|
0.4
|
|
|
3.1
|
|
|
1.1
|
|
|
3.2
|
|
|
1.4
|
|
|
Firm natural gas sales
|
|
7.5
|
|
|
14.6
|
|
|
8.5
|
|
|
N/A
|
|
|
8.6
|
|
|
|
|
|
|
|
|
Six Months Ended June 30
|
|
|
|
NSP-Minnesota
|
|
NSP-Wisconsin
|
|
PSCo
|
|
SPS
|
|
Xcel Energy
|
|
Actual
|
|
|
|
|
|
|
|
|
|
|
|
Electric residential
|
|
3.2
|
%
|
|
5.4
|
%
|
|
(1.8
|
)%
|
|
3.7
|
%
|
|
1.6
|
%
|
|
Electric commercial and industrial
|
|
1.1
|
|
|
5.4
|
|
|
(0.1
|
)
|
|
3.8
|
|
|
1.7
|
|
|
Total retail electric sales
|
|
1.7
|
|
|
5.4
|
|
|
(0.5
|
)
|
|
3.6
|
|
|
1.7
|
|
|
Firm natural gas sales
|
|
12.7
|
|
|
13.8
|
|
|
(1.9
|
)
|
|
N/A
|
|
|
3.7
|
|
|
|
|
|
|
|
|
Six Months Ended June 30
|
|
|
|
NSP-Minnesota
|
|
NSP-Wisconsin
|
|
PSCo
|
|
SPS
|
|
Xcel Energy
|
|
Weather-normalized
|
|
|
|
|
|
|
|
|
|
|
|
Electric residential
|
|
1.2
|
%
|
|
0.7
|
%
|
|
1.2
|
%
|
|
2.0
|
%
|
|
1.3
|
%
|
|
Electric commercial and industrial
|
|
0.7
|
|
|
4.3
|
|
|
1.1
|
|
|
4.1
|
|
|
1.9
|
|
|
Total retail electric sales
|
|
0.8
|
|
|
3.2
|
|
|
1.2
|
|
|
3.6
|
|
|
1.7
|
|
|
Firm natural gas sales
|
|
3.7
|
|
|
4.7
|
|
|
5.7
|
|
|
N/A
|
|
|
5.0
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weather-normalized Electric Growth
-
NSP-Minnesota’s electric residential sales growth is primarily related
to outages from severe storms experienced during the second quarter of
2013, which served to lower sales in that period and, in turn,
increased year-over-year sales.
-
NSP-Wisconsin’s electric commercial and industrial (C&I) sales growth
was primarily related to certain energy sector and manufacturing
customers.
-
PSCo’s electric residential sales growth reflects an increased number
of customers. Several large mining and manufacturing customers drove
C&I growth.
-
SPS’ C&I growth was the result of continued expansion of oilfield
development in southeast New Mexico.
Weather-normalized Gas Growth
-
Across the gas service territories, strong sales were experienced
during the first half of the year, which continued the trend that
began in the last half of 2013. As normal weather conditions are
typically defined as a 30-year average of actual historical weather
conditions, significant weather fluctuations in periods of low demand
may result in large percentage changes on small volumes. Extreme
weather variations and additional factors such as windchill and cloud
cover may not be fully reflected.
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 little impact on electric
margin. The following table details the electric revenues and margin:
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30
|
|
|
Six Months Ended June 30
|
|
(Millions of Dollars)
|
|
|
2014
|
|
|
2013
|
|
|
2014
|
|
|
2013
|
|
Electric revenues
|
|
|
$
|
2,298
|
|
|
|
$
|
2,220
|
|
|
|
$
|
4,599
|
|
|
|
$
|
4,312
|
|
|
Electric fuel and purchased power
|
|
|
|
(1,041
|
)
|
|
|
|
(1,011
|
)
|
|
|
|
(2,109
|
)
|
|
|
|
(1,936
|
)
|
|
Electric margin
|
|
|
$
|
1,257
|
|
|
|
$
|
1,209
|
|
|
|
$
|
2,490
|
|
|
|
$
|
2,376
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table summarizes the components of the changes in electric
margin:
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
|
|
|
Six Months
|
|
|
|
|
Ended June 30 2014
|
|
|
Ended June 30 2014
|
|
(Millions of Dollars)
|
|
|
vs. 2013
|
|
|
vs. 2013
|
|
Retail rate increases (a)
|
|
|
$
|
38
|
|
|
|
$
|
73
|
|
|
Conservation and DSM program revenues (offset by expenses)
|
|
|
|
12
|
|
|
|
|
25
|
|
|
Transmission revenue, net of costs
|
|
|
|
10
|
|
|
|
|
21
|
|
|
Retail sales growth, excluding weather impact
|
|
|
|
7
|
|
|
|
|
20
|
|
|
Non-fuel riders
|
|
|
|
17
|
|
|
|
|
19
|
|
|
Estimated impact of weather
|
|
|
|
(19
|
)
|
|
|
|
3
|
|
|
PSCo earnings test refund obligations
|
|
|
|
(9
|
)
|
|
|
|
(20
|
)
|
|
Firm wholesale
|
|
|
|
(9
|
)
|
|
|
|
(13
|
)
|
|
Other, net
|
|
|
|
1
|
|
|
|
|
(14
|
)
|
|
Total increase in electric margin
|
|
|
$
|
48
|
|
|
|
$
|
114
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) Retail rates implemented in 2014 include interim rates in
Minnesota, subject to refund, and final rates for Colorado, Wisconsin,
New Mexico and North Dakota. In addition, retail rates in Texas were
implemented in the second quarter of 2013. See Note 4 for further
discussion.
Natural Gas Margin — The cost of natural gas 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 to recover current expenses for sales to retail customers,
fluctuations in the cost of natural gas have little effect on natural
gas margin. The following table details natural gas revenues and margin:
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended June 30
|
|
|
Six Months Ended June 30
|
|
(Millions of Dollars)
|
|
|
2014
|
|
|
2013
|
|
|
2014
|
|
|
2013
|
|
Natural gas revenues
|
|
|
$
|
369
|
|
|
|
$
|
341
|
|
|
|
$
|
1,249
|
|
|
|
$
|
1,011
|
|
|
Cost of natural gas sold and transported
|
|
|
|
(211
|
)
|
|
|
|
(189
|
)
|
|
|
|
(835
|
)
|
|
|
|
(628
|
)
|
|
Natural gas margin
|
|
|
$
|
158
|
|
|
|
$
|
152
|
|
|
|
$
|
414
|
|
|
|
$
|
383
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The following table summarizes the components of the changes in natural
gas margin:
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
|
|
|
Six Months
|
|
|
|
|
Ended June 30 2014
|
|
|
Ended June 30 2014
|
|
(Millions of Dollars)
|
|
|
vs. 2013
|
|
|
vs. 2013
|
|
Retail rate increase, net of refund (Colorado)
|
|
|
$
|
7
|
|
|
|
$
|
16
|
|
Retail sales growth
|
|
|
|
3
|
|
|
|
|
6
|
|
Pipeline system integrity adjustment rider (Colorado), partially
offset in O&M expenses
|
|
|
|
—
|
|
|
|
|
4
|
|
Estimated impact of weather
|
|
|
|
(5
|
)
|
|
|
|
3
|
|
Other, net
|
|
|
|
1
|
|
|
|
|
2
|
|
Total increase in natural gas margin
|
|
|
$
|
6
|
|
|
|
$
|
31
|
|
|
|
|
|
|
|
|
|
|
|
O&M Expenses — O&M expenses increased $23.0 million,
or 4.1 percent, for the second quarter of 2014 and $54.0 million, or 4.9
percent, for the six months ended June 30, 2014. The year-to-date
increase in O&M expense is partially due to the timing of a prior year
nuclear outage (i.e., amortization of the 2013 Monticello outage began
in July 2013). Xcel Energy continues to project annual O&M expenses will
increase 2 percent to 3 percent for 2014.
|
|
|
|
|
|
|
|
|
|
|
|
Three Months
|
|
|
Six Months
|
|
|
|
|
Ended June 30 2014
|
|
|
Ended June 30 2014
|
|
(Millions of Dollars)
|
|
|
vs. 2013
|
|
|
vs. 2013
|
|
Nuclear plant operations and amortization
|
|
|
$
|
15
|
|
|
|
$
|
27
|
|
Electric and gas distribution expenses
|
|
|
|
3
|
|
|
|
|
13
|
|
Plant generation costs
|
|
|
|
6
|
|
|
|
|
6
|
|
Transmission costs
|
|
|
|
3
|
|
|
|
|
6
|
|
Other, net
|
|
|
|
(4
|
)
|
|
|
|
2
|
|
Total increase in O&M expenses
|
|
|
$
|
23
|
|
|
|
$
|
54
|
|
|
|
|
|
|
|
|
|
|
|
-
Nuclear plant operations and amortization cost increases were
primarily related to the amortization of the 2013 Monticello outage
costs, as well as initiatives designed to improve the operational
efficiencies of the plants;
-
Electric and gas distribution expenses were primarily driven by
increased maintenance activities (e.g., vegetation management) and
repairs and amounts related to pipeline system integrity;
-
Plant generation costs were driven by the timing of overhauls; and
-
Transmission costs increased as a result of higher substation
maintenance and repairs.
Conservation and DSM Program Expenses — Conservation and
DSM program expenses increased $10.4 million, or 17.2 percent, for the
second quarter of 2014 and $23.9 million, or 19.2 percent, for the six
months ended June 30, 2014. These increases were primarily attributable
to higher electric recovery rates at NSP-Minnesota and PSCo.
Conservation costs are recovered from customers and expensed on a
kilowatt hour basis. As such, increased sales due to cold winter
temperatures or hot summer temperatures will increase revenues and
expenses.
Depreciation and Amortization — Depreciation and
amortization increased $11.4 million, or 4.7 percent, for the second
quarter of 2014 and $8.6 million, or 1.7 percent, year-to-date. The
increases were primarily attributed to normal system expansion,
partially offset by additional accelerated amortization of the excess
depreciation reserve associated with certain Minnesota assets. See
further discussion within Note 4.
Taxes (Other Than Income Taxes) — Taxes (other than income
taxes) increased $14.2 million, or 13.9 percent, for the second quarter
of 2014 and $25.5 million, or 11.8 percent, for the six months ended
June 30, 2014. The increases were due to higher property taxes primarily
in Minnesota and Colorado.
AFUDC, Equity and Debt — AFUDC increased $1.3 million for
the second quarter of 2014 and $4.2 million year-to-date. The increases
were due to construction related to the Clean Air Clean Jobs Act (CACJA)
project and the expansion of transmission facilities, partially offset
by the reduction caused by the portion of the Monticello life cycle
management (LCM)/extended power uprate (EPU) placed in service in July
2013.
Interest Charges — Interest charges decreased $7.5
million, or 5.1 percent, for the second quarter of 2014 and $8.0
million, or 2.8 percent, for the six months ended June 30, 2014. The
decreases were primarily due to refinancings at lower interest rates and
the write off of $6.3 million of unamortized debt expense associated
with the calling of junior subordinated notes in May 2013. These
positive factors were partially offset by higher long-term debt levels
in the current period.
Income Taxes — Income tax expense increased $5.4 million
for the second quarter of 2014. The increase in income tax expense was
primarily due to higher pretax earnings in 2014, decreased permanent
plant-related adjustments in 2014, recognition of research and
experimentation credits in 2013 and a tax benefit for a carryback claim
related to 2013. These were partially offset by a tax benefit for an
income exclusion in 2014. The effective tax rate (ETR) was 34.8 percent
for the second quarter of 2014, compared to 33.4 percent for the second
quarter of 2013 due to these adjustments.
Income tax expense increased $22.7 million for the first six months of
2014. The increase in income tax expense was primarily due to higher
pretax earnings in 2014, recognition of research and experimentation
credits in 2013 and a tax benefit for a carryback claim related to 2013.
These were partially offset by the successful resolution of a 2010-2011
Internal Revenue Service audit issue in 2014. The ETR was 34.5 percent
for the first six months of 2014, compared to 33.4 percent for the first
six months of 2013 due to these adjustments.
Note 3. Xcel Energy Capital Structure,
Financing and Credit Ratings
Following is the capital structure of Xcel Energy:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Percentage of
|
|
(Billions of Dollars)
|
|
|
June 30, 2014
|
|
|
Total Capitalization
|
|
Short-term debt
|
|
|
$
|
0.8
|
|
|
|
4
|
%
|
|
Long-term debt
|
|
|
|
11.8
|
|
|
|
52
|
|
|
Total debt
|
|
|
|
12.6
|
|
|
|
56
|
|
|
Common equity
|
|
|
|
9.9
|
|
|
|
44
|
|
|
Total capitalization
|
|
|
$
|
22.5
|
|
|
|
100
|
%
|
|
|
|
|
|
|
|
|
|
|
|
Credit Facilities — As of July 29,
2014, 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.
|
|
|
$
|
800.0
|
|
|
$
|
433.0
|
|
|
$
|
367.0
|
|
|
$
|
0.3
|
|
|
$
|
367.3
|
|
PSCo
|
|
|
|
700.0
|
|
|
|
303.5
|
|
|
|
396.5
|
|
|
|
0.3
|
|
|
|
396.8
|
|
NSP-Minnesota
|
|
|
|
500.0
|
|
|
|
105.9
|
|
|
|
394.1
|
|
|
|
0.7
|
|
|
|
394.8
|
|
SPS
|
|
|
|
300.0
|
|
|
|
83.0
|
|
|
|
217.0
|
|
|
|
0.9
|
|
|
|
217.9
|
|
NSP-Wisconsin
|
|
|
|
150.0
|
|
|
|
11.0
|
|
|
|
139.0
|
|
|
|
0.9
|
|
|
|
139.9
|
|
Total
|
|
|
$
|
2,450.0
|
|
|
$
|
936.4
|
|
|
$
|
1,513.6
|
|
|
$
|
3.1
|
|
|
$
|
1,516.7
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) These credit facilities expire in July 2017.
(b)
Includes outstanding commercial paper and letters of credit.
During the second quarter of 2014, Xcel Energy began working with its
bank group to amend and extend the existing revolving credit agreements
for Xcel Energy Inc. and each of its regulated subsidiaries. Xcel Energy
expects to finalize these agreements during the third quarter of 2014.
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 July 29, 2014, 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.
Financing — Xcel Energy issues debt and equity securities
to refinance retiring maturities, reduce short-term debt, fund capital
programs, infuse equity in subsidiaries, fund asset acquisitions and for
other general corporate purposes.
During 2014, Xcel Energy Inc. and its utility subsidiaries completed the
following bond issuances:
-
In March, PSCo issued $300 million of 4.30 percent first mortgage
bonds due March 15, 2044;
-
In May, NSP-Minnesota issued $300 million of 4.125 percent first
mortgage bonds due May 15, 2044;
-
In June, SPS issued $150 million of 3.30 percent first mortgage bonds
due June 15, 2024; and
-
In June, NSP-Wisconsin issued $100 million of 3.30 percent first
mortgage bonds due June 15, 2024.
In connection with SPS’ issuance of $150 million of 3.30 percent first
mortgage bonds due June 15, 2024, SPS issued $250 million of collateral
8.75 percent first mortgage bonds due Dec. 1, 2018 to the trustee under
its senior unsecured indenture in order to secure its previously issued
Series G Senior Notes, 8.75 percent due Dec. 1, 2018, equally and
ratably with SPS’ first mortgage bonds as required by the terms of such
Series G Senior Notes.
In March 2013, Xcel Energy Inc. filed a prospectus supplement under
which it may sell up to $400 million of its common stock through an ATM
program. During the six months ended June 30, 2014, Xcel Energy Inc.
issued approximately 5.7 million shares of common stock through this
program for approximately $175 million. As a result, Xcel Energy has
completed its ATM program. Xcel Energy does not anticipate issuing any
additional equity, beyond its dividend reinvestment program and to fund
benefit programs, over the next five years based on its current capital
expenditure plan.
Financing plans are subject to change, depending on capital
expenditures, internal cash generation, market conditions and other
factors.
Note 4. Rates and Regulation
NSP-Minnesota – Minnesota 2014 Multi-Year Electric Rate Case — In
November 2013, NSP-Minnesota filed a two-year electric rate case with
the Minnesota Public Utilities Commission (MPUC). The rate case is based
on a requested return on equity (ROE) of 10.25 percent, a 52.5 percent
equity ratio, a 2014 average electric rate base of $6.67 billion and an
additional average rate base of $412 million in 2015.
The NSP-Minnesota electric rate case reflects an increase in revenues of
approximately $193 million or 6.9 percent in 2014 and an additional $98
million or 3.5 percent in 2015. The request includes a proposed rate
moderation plan for 2014 and 2015. After reflecting interim rate
adjustments, NSP-Minnesota requested a rate increase of $127 million or
4.6 percent in 2014 and an incremental rate increase of $164 million or
5.6 percent in 2015.
NSP-Minnesota’s moderation plan includes the acceleration of the
eight-year amortization of the excess depreciation reserve and the use
of expected funds from the U.S. Department of Energy (DOE) for
settlement of certain claims. These DOE refunds would be in excess of
amounts needed to fund NSP-Minnesota’s decommissioning expense. The
interim rate adjustments are primarily associated with ROE, Monticello
LCM/EPU project costs and NSP-Minnesota’s request to amortize amounts
associated with the canceled Prairie Island (PI) EPU project.
In December 2013, the MPUC approved interim rates of $127 million
effective Jan. 3, 2014, subject to refund. The MPUC determined that the
costs of Sherco Unit 3 would be allowed in interim rates, and that
NSP-Minnesota’s request to accelerate the depreciation reserve
amortization was a permissible adjustment to its interim rate request.
In June 2014, intervening parties filed direct testimony proposing
modifications to NSP-Minnesota’s rate request. The Minnesota Department
of Commerce (DOC) recommended an increase of approximately $61.6 million
in 2014 and a step increase of $54.9 million for 2015, based on a
recommended ROE of 9.8 percent and an equity ratio of 52.5 percent.
In July 2014, NSP-Minnesota filed rebuttal testimony and reduced its
request to an increase in revenues of approximately $169.5 million or
6.2 percent in 2014 and an additional $95 million or 3.5 percent in
2015. The revision reflects an update to NSP-Minnesota’s 2014 sales
forecast and narrowed the number of disputed issues in the case by
agreeing to or partially agreeing to an outcome on several smaller
issues. NSP-Minnesota continues to support its initial filed position,
including cost recovery of the Monticello LCM/EPU project, an ROE of
10.25 percent and property taxes. For the 2015 increase, NSP-Minnesota
reduced its request by $3.5 million in order to focus the request on
specific capital projects.
The following table summarizes the DOC’s recommendations from
NSP-Minnesota’s filed request:
|
|
|
|
|
|
|
|
|
|
|
|
DOC Direct
|
|
|
NSP-Minnesota
|
|
|
|
|
Testimony
|
|
|
Rebuttal Testimony
|
|
(Millions of Dollars)
|
|
|
2014
|
|
|
2014
|
|
Filed rate request
|
|
|
$
|
192.7
|
|
|
|
$
|
192.7
|
|
|
Monticello EPU cost recovery
|
|
|
|
(31.3
|
)
|
|
|
|
—
|
|
|
Sales forecast
|
|
|
|
(29.5
|
)
|
|
|
|
(15.8
|
)
|
|
ROE
|
|
|
|
(26.9
|
)
|
|
|
|
—
|
|
|
Health care, pension and other benefits
|
|
|
|
(21.9
|
)
|
|
|
|
(0.8
|
)
|
|
Property taxes
|
|
|
|
(13.5
|
)
|
|
|
|
—
|
|
|
PI EPU
|
|
|
|
(5.8
|
)
|
|
|
|
(3.8
|
)
|
|
Other, net
|
|
|
|
(2.2
|
)
|
|
|
|
(2.8
|
)
|
|
Total recommendation 2014
|
|
|
$
|
61.6
|
|
|
|
$
|
169.5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DOC Direct
|
|
|
NSP-Minnesota
|
|
|
|
|
Testimony
|
|
|
Rebuttal Testimony
|
|
(Millions of Dollars)
|
|
|
2015 Step
|
|
|
2015 Step
|
|
Filed rate request
|
|
|
$
|
98.5
|
|
|
|
$
|
98.5
|
|
|
Depreciation
|
|
|
|
(17.5
|
)
|
|
|
|
—
|
|
|
Property taxes
|
|
|
|
(14.5
|
)
|
|
|
|
(3.3
|
)
|
|
Production tax credits to be included in base rates
|
|
|
|
(11.1
|
)
|
|
|
|
(11.1
|
)
|
|
DOE settlement proceeds
|
|
|
|
(10.8
|
)
|
|
|
|
10.1
|
|
|
Capital changes and disallowances
|
|
|
|
(5.6
|
)
|
|
|
|
—
|
|
|
Nuclear outage amortization
|
|
|
|
(5.5
|
)
|
|
|
|
—
|
|
|
Emission chemicals
|
|
|
|
(3.0
|
)
|
|
|
|
(0.2
|
)
|
|
Excess depreciation reserve adjustment
|
|
|
|
22.7
|
|
|
|
|
—
|
|
|
Other, net
|
|
|
|
1.7
|
|
|
|
|
1.0
|
|
|
Total recommendation 2015 step increase
|
|
|
|
54.9
|
|
|
|
|
95.0
|
|
|
Cumulative total for 2014 and 2015 step increase
|
|
|
$
|
116.5
|
|
|
|
$
|
264.5
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NSP-Minnesota’s rebuttal rate request, moderation plan, interim rate
adjustments and certain impacts on expenses are detailed in the table
below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Percentage
|
|
|
|
Percentage
|
|
(Millions of Dollars)
|
|
2014
|
|
Increase
|
|
2015
|
|
Increase
|
|
Rebuttal pre-moderation deficiency
|
|
$
|
250
|
|
|
|
|
$
|
68
|
|
|
|
|
Moderation change compared to prior year:
|
|
|
|
|
|
|
|
|
|
Depreciation reserve
|
|
|
(81
|
)
|
|
|
|
|
53
|
|
|
|
|
DOE settlement proceeds
|
|
|
—
|
|
|
|
|
|
(26
|
)
|
|
|
|
Rebuttal rate request
|
|
|
169
|
|
|
6.2
|
%
|
|
|
95
|
|
|
3.5
|
%
|
|
Interim rate adjustments
|
|
|
(66
|
)
|
|
|
|
|
66
|
|
|
|
|
PI EPU
|
|
|
4
|
|
|
|
|
|
(4
|
)
|
|
|
|
Revenue impact(a)
|
|
|
107
|
|
|
|
|
|
157
|
|
|
|
|
Depreciation expense - decrease/(increase)
|
|
|
81
|
|
|
|
|
|
(46
|
)
|
|
|
|
Recognition of DOE settlement proceeds
|
|
|
—
|
|
|
|
|
|
26
|
|
|
|
|
Rebuttal pre-tax impact on operating income
|
|
$
|
188
|
|
|
|
|
$
|
137
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) NSP-Minnesota’s total revenue for 2014 is capped at the
interim rate level of $127 million and pre-tax operating income is
capped at $208 million. This table demonstrates the impact of reducing
NSP-Minnesota’s rebuttal request.
NSP-Minnesota recorded a current regulatory liability representing the
current best estimate of a refund obligation associated with interim
rates of approximately $12.5 million as of June 30, 2014.
The next steps in the procedural schedule are expected to be as follows:
-
Surrebuttal Testimony — Aug. 4, 2014;
-
Evidentiary Hearing — Aug. 11-18, 2014;
-
Initial Brief — Sept. 23, 2014;
-
Reply Brief — Oct. 14, 2014; and
-
Administrative Law Judge (ALJ) Report — Dec. 22, 2014.
A final MPUC decision is anticipated in March 2015.
NSP-Minnesota – Nuclear Project Prudence Investigation —
In 2013, the MPUC initiated an investigation to determine whether the
final costs for the Monticello LCM/EPU project were prudent. Monticello
LCM/EPU project expenditures were approximately $665 million. Total
capitalized costs were approximately $748 million, which includes AFUDC.
Project expenditures were initially estimated at approximately $320
million, excluding AFUDC, in 2008 in NSP-Minnesota’s EPU certificate of
need and plant life extension filings.
In October 2013, NSP-Minnesota filed a report to further support the
change and prudence of the incurred costs. The filing indicated the
increase in costs was primarily attributable to three factors: (1) the
original estimate was based on a high level conceptual design and the
project scope increased as the actual conditions of the plant were
incorporated into the design; (2) implementation difficulties, including
the amount of work that occurred in confined and radioactive or
electrically sensitive spaces and NSP-Minnesota’s and its vendors’
ability to attract and retain experienced workers; and (3) additional
Nuclear Regulatory Commission (NRC) licensing related requests over the
five-plus year application process. NSP-Minnesota has provided
information that the cost deviation is in line with similar upgrade
projects undertaken by other utilities and the project remains
economically beneficial to customers. NSP-Minnesota has received all
necessary licenses from the NRC for the Monticello EPU, and has begun
the process to comply with the license requirements for higher power
levels, subject to NRC oversight and review.
On July 2, 2014, the DOC filed testimony and recommended a disallowance
of recovery of approximately $71.5 million of project costs, including
expenditures and associated AFUDC, on a Minnesota jurisdictional basis.
This equates to a total NSP System amount of approximately $94 million.
The DOC’s recommendation indicated that although the combined LCM/EPU
project is cost effective, NSP-Minnesota should have done a better job
of estimating initial project costs of the investments required to
achieve 71 megawatts (MW) of additional capacity (i.e., EPU costs) as
opposed to investments required to extend the life of the plant. They
asserted that approximately 85 percent of the total $665 million in
costs were associated with project components required solely to achieve
the EPU.
The DOC’s recommendation, NSP-Minnesota’s response and comments of other
parties are expected to be considered by an ALJ later this year, who in
turn will make a report of recommendations to the MPUC. The results and
any recommendations from the conclusion of this prudence proceeding are
expected to be considered by the MPUC in NSP-Minnesota’s pending
Minnesota 2014 Multi-Year electric rate case.
The next steps in the procedural schedule are expected to be as follows:
-
Rebuttal Testimony — Aug. 26, 2014;
-
Surrebuttal Testimony — Sept. 19, 2014;
-
Hearing — Sept. 25 - Sept. 30, 2014;
-
Reply Brief — Nov. 21, 2014; and
-
ALJ Report — Dec. 31, 2014.
A final MPUC decision is anticipated in the first quarter of 2015.
NSP System Resource Plans — In March 2013, the MPUC
approved NSP-Minnesota’s Resource Plan and ordered a competitive
acquisition process with the goal of adding approximately 500 MW of
generation to the NSP System by 2019.
In May 2014, the MPUC issued its order directing NSP-Minnesota to
negotiate a 100 MW solar purchased power agreement (PPA) with Geronimo
Energy, a natural gas, combined-cycle PPA with Calpine, a natural gas,
combustion turbine PPA with Invenergy and to file these agreements later
this fall. The MPUC also directed NSP-Minnesota to present its final
pricing terms for its 215 MW natural gas combustion turbine, self-build
option at the Black Dog site. The MPUC is expected to rule on the four
options later this year.
In early 2013, NSP-Minnesota also issued a request for proposal (RFP)
for wind generation and subsequently sought commission approval of the
following four wind projects:
-
A 200 MW ownership project for the Pleasant Valley wind farm in
Minnesota;
-
A 150 MW ownership project for the Border Winds wind farm in North
Dakota;
-
A 200 MW PPA with Geronimo Energy, LLC for the Odell wind farm in
Minnesota; and
-
A 200 MW PPA with Geronimo Energy, LLC for the Courtenay wind farm in
North Dakota.
In October 2013, the MPUC approved the four wind projects. In 2014, the
North Dakota Public Service Commission approved the prudence of the
Border Winds project as part of the rate case settlement and determined
it will address the Pleasant Valley project at a later date. In June and
July of 2014, NSP-Minnesota finalized agreements with Renewable Energy
Systems Americas, Inc. for the Pleasant Valley and Border Winds projects
and anticipates both projects going into service in 2015.
In April 2014, NSP-Minnesota issued a RFP for up to 100 MWs of solar
generation resources. Proposals were received in June 2014.
NSP-Minnesota is evaluating such bids and plans to submit
recommendations regarding selected bids with the MPUC in October 2014.
NSP-Minnesota - Gas Utility Infrastructure Cost (GUIC) Rider —
In the third quarter of 2014, NSP-Minnesota plans to file a GUIC rider
with the MPUC for approval to recover the cost of natural gas
infrastructure investments in Minnesota to improve safety and
reliability. Costs include funding for pipeline assessment and system
upgrades in 2015 and beyond, as well as deferred costs from
NSP-Minnesota’s existing sewer separation and pipeline integrity
management programs. Sewer separation costs stem from the inspection of
sewer lines and the redirection of gas pipes in the event their paths
are in conflict. NSP-Minnesota is requesting recovery of approximately
$14.9 million from Minnesota gas utility customers beginning Jan.1,
2015, including $4.8 million of deferred sewer separation and integrity
management costs. An MPUC decision is anticipated by the end of 2014.
South Dakota 2015 Electric Rate Case — In
June 2014, NSP-Minnesota filed a request with the South Dakota Public
Utilities Commission to increase South Dakota electric rates by $15.6
million annually, or 8.0 percent, effective Jan. 1, 2015. The request is
based on a 2013 historic test year adjusted for certain known and
measurable changes for 2014 and 2015, a requested ROE of 10.25 percent,
an average rate base of $433.2 million and an equity ratio of 53.86
percent. This request reflects NSP-Minnesota’s proposal to move recovery
of approximately $9.0 million for certain Transmission Cost Recovery
(TCR) rider and Infrastructure rider projects to base rates.
The major components of the request are as follows:
|
|
|
|
|
|
(Millions of Dollars)
|
|
|
Request
|
|
Nuclear investments and operating costs
|
|
|
$
|
13.4
|
|
|
Other production, transmission and distribution
|
|
|
|
5.0
|
|
|
Technology improvements
|
|
|
|
2.1
|
|
|
Pension and O&M
|
|
|
|
1.6
|
|
|
Wind generation facilities
|
|
|
|
1.4
|
|
|
Capital structure
|
|
|
|
1.1
|
|
|
Incremental increase to base rates
|
|
|
$
|
24.6
|
|
|
|
|
|
|
|
Infrastructure rider to be included in base rates
|
|
|
$
|
(8.4
|
)
|
|
TCR rider to be included in base rates
|
|
|
|
(0.6
|
)
|
|
Net request
|
|
|
$
|
15.6
|
|
|
|
|
|
|
|
|
A procedural schedule is anticipated to be established in the second
half of 2014. Final rates are expected to be effective in the first
quarter of 2015.
NSP-Wisconsin 2015 Electric Rate Case — In May 2014,
NSP-Wisconsin filed a request with the Public Service Commission of
Wisconsin (PSCW) to increase electric rates by $20.6 million, or 3.2
percent, effective Jan. 1, 2015. The request is for the limited purpose
of updating 2015 electric rates to reflect anticipated increases in the
production and transmission fixed charges and the fuel and purchased
power components of the interchange agreement with NSP-Minnesota. No
changes are being requested to the capital structure or the 10.2 percent
ROE authorized by the PSCW in the 2014 rate case. As part of an
agreement with stakeholders to limit the size and scope of the case,
NSP-Wisconsin also agreed to an earnings cap for 2015 only, in which 100
percent of the earnings above the authorized ROE would be refunded to
customers.
The major cost components of the requested increase are summarized below:
|
|
|
|
|
(Millions of Dollars)
|
|
Request
|
|
Production and transmission fixed charges
|
|
$
|
28.1
|
|
|
Fuel and purchased power
|
|
|
13.9
|
|
|
Sub-Total
|
|
$
|
42.0
|
|
|
|
|
|
|
NSP-Minnesota transmission depreciation reserve
|
|
$
|
(16.2
|
)
|
|
Monticello EPU deferral
|
|
|
(5.2
|
)
|
|
Total
|
|
$
|
20.6
|
|
|
|
|
|
|
|
The next steps in the procedural schedule are expected to be as follows:
-
Direct Testimony (PSCW staff and intervenors) — Oct. 3, 2014;
-
Rebuttal Testimony — Oct. 17, 2014;
-
Surrebuttal Testimony — Oct. 24, 2014; and
-
Evidentiary Hearing — Oct. 28, 2014.
A final PSCW decision is anticipated by the end of the year with final
rates implemented in January 2015.
PSCo – Colorado 2014 Electric Rate Case — In
June 2014, PSCo filed an electric rate case in Colorado with the
Colorado Public Utilities Commission (CPUC) requesting an increase in
annual revenue of approximately $137.7 million, or 4.89 percent. The
request includes the initiation of a CACJA rider as part of the overall
2015 rate case request of approximately $95 million, as well as
additional amounts for calendar years 2016 and 2017. The CACJA rider is
anticipated to increase revenue recovery by approximately $40 million in
2016 and then decline to approximately $36 million in 2017. PSCo’s
objective is to establish a multi-year regulatory plan that provides
certainty for PSCo and its customers.
The rate filing is based on a 2015 test year, a requested ROE of 10.35
percent, an electric rate base of $6.39 billion and an equity ratio of
56 percent. As part of the filing, PSCo will transfer approximately
$19.9 million from the transmission rider to base rates. This transfer
will not impact customer bills. The CACJA rider is projected to recover
incremental investment and expenses, based on a comprehensive plan to
retire certain coal plants, add pollution control equipment to other
existing coal units and add natural gas generation. The CACJA project
investment is expected to be completed by 2017.
In July 2014, the CPUC set hearings for early December 2014. A decision
as well as implementation of final rates are anticipated in the first
quarter of 2015.
Boulder, Colo. Municipalization — PSCo’s franchise
agreement with the City of Boulder (Boulder) expired on Dec. 31, 2010.
In November 2011, a ballot measure was passed by the citizens of
Boulder, which authorized the formation and operation of a municipal
light and power utility and the issuance of enterprise revenue bonds,
subject to certain restrictions, including the level of initial rates
and debt service coverage.
In May 2014, the Boulder City Council passed an ordinance to establish
an electric utility. In June 2014, PSCo filed a complaint in the Boulder
District Court seeking a declaratory ruling that this ordinance violates
Boulder’s charter requirements. Subsequently, Boulder filed a motion to
dismiss PSCo’s complaint, which is still pending.
Boulder sent PSCo its final offer of $128 million for certain portions
of PSCo’s transmission and distribution business, which includes Boulder
and certain areas outside city limits. PSCo has notified Boulder that
its offer has deficiencies related to property descriptions as well as
other relevant information impacting the remainder of PSCo’s system.
Under Colorado law, a condemning entity must pay the owner fair market
value for the taking of and damages to the remainder of the property. In
July 2014, Boulder filed a petition for condemnation in the Boulder
District Court.
The CPUC has previously ruled that it has jurisdiction under Colorado
law to determine the utility that will serve customers outside Boulder’s
city limits, and will determine certain system separation matters as
well as what facilities need to be constructed to ensure reliable
service. The CPUC has declared that it should make its determinations
prior to any eminent domain actions. In January 2014, Boulder appealed
this ruling to the Boulder District Court. PSCo and the CPUC filed
briefs in June 2014 in opposition of Boulder’s appeal. This matter is
currently pending.
If Boulder were to succeed in the eminent domain proceeding, PSCo would
seek to obtain full compensation for the business and its associated
property taken by Boulder, as well as for all damages resulting to PSCo
and its system. PSCo would also seek appropriate compensation for
stranded costs with the Federal Energy Regulatory Commission.
SPS – Texas 2014 Electric Rate Case — In January 2014, SPS
filed a retail electric rate case in Texas with each of its Texas
municipalities and the Public Utility Commission of Texas (PUCT) for a
net increase in annual revenue of approximately $52.7 million, or 5.8
percent. The net increase reflected a base rate increase, revenue
credits transferred from base rates to rate riders or the fuel clause,
and resetting the Transmission Cost Recovery Factor (TCRF) to zero when
the final base rates become effective. In April 2014, SPS revised its
request to a net increase of $48.1 million, based on updated information.
The rate filing is based on a historic test year ending June 2013, a
requested ROE of 10.40 percent, an electric rate base of approximately
$1.27 billion and an equity ratio of 53.89 percent. The requested rate
increase reflected an increase in depreciation expense of approximately
$16 million.
SPS, intervenors, and other parties have commenced settlement
negotiations. A final settlement is anticipated to be filed with the
PUCT in the third quarter of 2014. A final decision is anticipated later
this year and final rates are expected to be effective retroactive to
June 1, 2014.
SPS – New Mexico 2014 Electric Rate Case — In
December 2012, SPS filed an electric rate case in New Mexico with the
New Mexico Public Regulation Commission (NMPRC) for an increase in
annual revenue of approximately $45.9 million effective in 2014. The
rate filing was based on a 2014 forecast test year, a requested ROE of
10.65 percent, an electric rate base of $479.8 million and an equity
ratio of 53.89 percent.
In September 2013, SPS filed rebuttal testimony, revising its requested
rate increase to $32.5 million, based on updated information and an ROE
of 10.25 percent. The request reflected a base and fuel increase of
$20.9 million, an increase of rider revenue of $12.1 million and a
decrease to other of $0.5 million.
In March 2014, the NMPRC approved an overall increase of approximately
$33.1 million. The increase reflects a base rate increase of $12.7
million and rider recovery of $18.1 million for renewable energy costs,
both based on an ROE of 9.96 percent and an equity ratio of 53.89
percent. Final rates were effective April 5, 2014. In April 2014, the
New Mexico Attorney General (NMAG) filed a request for rehearing. The
rehearing request was denied by the NMPRC. In June 2014, the NMAG filed
an appeal of the NMPRC’s denial to the New Mexico Supreme Court. A
decision is expected in 2015.
The following table summarizes the NMPRC’s approval from SPS’ revised
request:
|
|
|
|
|
(Millions of Dollars)
|
|
NMPRC Approval
|
|
SPS revised request, September 2013
|
|
$
|
32.5
|
|
|
Fuel clause adjustment credit — non-renewable energy costs
|
|
|
2.3
|
|
|
SPS revised request, fuel adjusted
|
|
|
34.8
|
|
|
ROE (9.96 percent)
|
|
|
(1.2
|
)
|
|
Rate rider adjustment — renewable energy costs
|
|
|
6.0
|
|
|
Base rate reduction for rate rider — renewable energy costs
|
|
|
(6.0
|
)
|
|
Other, net
|
|
|
(0.5
|
)
|
|
Approved increase, March 2014
|
|
$
|
33.1
|
|
|
|
|
|
|
Means of recovery:
|
|
|
|
Base revenue
|
|
$
|
12.7
|
|
|
Rider revenue
|
|
|
18.1
|
|
|
Fuel clause
|
|
|
2.3
|
|
|
|
|
$
|
33.1
|
|
|
|
|
|
|
|
Note 5. Xcel Energy Earnings Guidance
and Long-Term EPS and Dividend Growth Rate Objectives
Xcel Energy Earnings Guidance — Xcel Energy’s 2014 ongoing
earnings guidance is $1.90 to $2.05 per share. Key assumptions related
to 2014 earnings are detailed below:
-
Constructive outcomes in all rate case and regulatory proceedings.
-
Normal weather patterns are experienced for the remainder of the year.
-
Weather-normalized retail electric utility sales are projected to
increase approximately 1.0 percent.
-
Weather-normalized retail firm natural gas sales are projected to
increase approximately 2.0 percent.
-
Capital rider revenue is projected to increase by $40 million to $50
million over 2013 levels.
-
O&M expenses are projected to increase approximately 2 percent to 3
percent over 2013 levels.
-
Depreciation expense is projected to increase $30 million to $40
million over 2013 levels, reflecting the proposed acceleration of the
amortization of the excess depreciation reserve as part of
NSP-Minnesota’s moderation plan in the Minnesota electric rate case.
The moderation plan, if approved by the MPUC, would reduce
depreciation expense by approximately $81 million in 2014.
-
Property taxes are projected to increase approximately $40 million to
$50 million over 2013 levels.
-
Interest expense (net of AFUDC — debt) is projected to decrease $5 to
$15 million from 2013 levels.
-
AFUDC — equity is projected to increase approximately $5 million to
$10 million over 2013 levels.
-
The ETR is projected to be approximately 34 percent to 36 percent.
-
Average common stock and equivalents are projected to be approximately
504 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 a normalized 2013 EPS of $1.90 per share, which represented the
mid-point of our 2013 earnings guidance range;
-
Deliver annual dividend increases of 4 percent to 6 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.
|
|
|
XCEL ENERGY INC. AND SUBSIDIARIES
|
|
EARNINGS RELEASE SUMMARY (Unaudited)
|
|
(amounts in thousands, except per share data)
|
|
|
|
|
|
|
Three Months Ended June 30
|
|
|
|
|
2014
|
|
|
2013
|
|
Operating revenues:
|
|
|
|
|
|
|
|
Electric and natural gas
|
|
|
$
|
2,666,765
|
|
|
|
$
|
2,561,198
|
|
|
Other
|
|
|
|
18,331
|
|
|
|
|
17,715
|
|
|
Total operating revenues
|
|
|
|
2,685,096
|
|
|
|
|
2,578,913
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
$
|
195,164
|
|
|
|
$
|
196,857
|
|
|
|
|
|
|
|
|
|
|
Weighted average diluted common shares outstanding
|
|
|
|
503,456
|
|
|
|
|
498,036
|
|
|
|
|
|
|
|
|
|
|
Components of EPS — Diluted
|
|
|
|
|
|
|
|
Regulated utility
|
|
|
$
|
0.42
|
|
|
|
$
|
0.44
|
|
|
Xcel Energy Inc. and other costs
|
|
|
|
(0.03
|
)
|
|
|
|
(0.04
|
)
|
|
GAAP diluted EPS
|
|
|
$
|
0.39
|
|
|
|
$
|
0.40
|
|
|
|
|
|
|
|
|
|
|
Six Months Ended June 30
|
|
|
|
|
2014
|
|
|
2013
|
|
Operating revenues:
|
|
|
|
|
|
|
|
Electric and natural gas
|
|
|
$
|
5,848,163
|
|
|
|
$
|
5,322,990
|
|
|
Other
|
|
|
|
39,537
|
|
|
|
|
38,772
|
|
|
Total operating revenues
|
|
|
|
5,887,700
|
|
|
|
|
5,361,762
|
|
|
|
|
|
|
|
|
|
|
Net income
|
|
|
$
|
456,385
|
|
|
|
$
|
433,427
|
|
|
|
|
|
|
|
|
|
|
Weighted average diluted common shares outstanding
|
|
|
|
501,612
|
|
|
|
|
494,303
|
|
|
|
|
|
|
|
|
|
|
Components of EPS — Diluted
|
|
|
|
|
|
|
|
Regulated utility
|
|
|
$
|
0.96
|
|
|
|
$
|
0.96
|
|
|
Xcel Energy Inc. and other costs
|
|
|
|
(0.05
|
)
|
|
|
|
(0.08
|
)
|
|
GAAP diluted EPS
|
|
|
$
|
0.91
|
|
|
|
$
|
0.88
|
|
|
Book value per share
|
|
|
$
|
19.64
|
|
|
|
$
|
18.70
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Copyright Business Wire 2014