Ongoing 2012 earnings per share were $1.82 compared with $1.72 per
share in 2011.
GAAP (generally accepted accounting principles) 2012 earnings per
share were $1.85 compared with $1.72 per share in 2011.
Xcel Energy reaffirms 2013 earnings guidance of $1.85 to $1.95 per
share.
MINNEAPOLIS--(BUSINESS WIRE)--
Xcel Energy Inc. (NYSE: XEL) today reported 2012 GAAP earnings of $905
million, or $1.85 per share compared with 2011 GAAP earnings of $841
million, or $1.72 per share.
Ongoing earnings, which exclude one adjustment, were $1.82 per share for
2012 compared with $1.72 per share in 2011. Ongoing earnings increased
largely due to increases in electric margins driven by the conclusion of
various rate cases, which reflect our continued investment in our
utility business and a lower effective tax rate. Partially offsetting
these positive factors were warmer than normal winter weather, increases
in depreciation expense, operating and maintenance expenses and property
taxes.
“We had an excellent year financially and operationally in 2012,” said
Ben Fowke, Chairman, President and Chief Executive Officer. “We
delivered earnings in the upper half of our guidance range, which
represents the eighth consecutive year in which we have met or exceeded
our earnings guidance and for the ninth consecutive year we increased
our dividend. We implemented a multi-year rate plan in Colorado and
reached constructive regulatory outcomes in several other rate cases.
Finally, we maintained excellent reliability during one of the warmest
years on record, all executed with outstanding safety performance.”
“We have established a solid strategy and continue to execute our
business plan. As a result, we are well positioned to deliver on our
2013 earnings guidance of $1.85 to $1.95 per share,” stated Fowke.
Earnings Adjusted for Certain Items (Ongoing Earnings)
The following table provides a reconciliation of ongoing earnings per
share to GAAP earnings per share:
Three Months Ended Dec. 31
Twelve Months Ended Dec. 31
Diluted Earnings Per Share
2012
2011
2012
2011
Ongoing(a) diluted earnings per share
$
0.29
$
0.29
$
1.82
$
1.72
Prescription drug tax benefit (a)
-
-
0.03
-
GAAPdiluted earnings per share
$
0.29
$
0.29
$
1.85
$
1.72
(a)
See Note 6.
At 9:00 a.m. CST today, Xcel Energy will host a conference call to
review financial results. To participate in the call, please dial in 5
to 10 minutes prior to the start and follow the operator’s instructions.
US Dial-In:
(877) 941-0844
International Dial-In:
(480) 629-9835
Conference ID:
4577479
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 2:00 p.m. CST on Jan. 31 through 11:59 p.m. CST on Feb. 1.
Replay Numbers
US Dial-In:
(800) 406-7325
International Dial-In:
(303) 590-3030
Access Code:
4577479 #
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 2013 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, 2011 and Quarterly Reports on Form 10-Q for the quarters ended
March 31, June 30 and Sept. 30, 2012.
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 Dec. 31
Twelve Months Ended Dec. 31
2012
2011
2012
2011
Operating revenues
Electric
$
2,010,976
$
1,988,800
$
8,517,296
$
8,766,593
Natural gas
520,513
560,109
1,537,374
1,811,926
Other
19,646
19,501
73,553
76,251
Total operating revenues
2,551,135
2,568,410
10,128,223
10,654,770
Operating expenses
Electric fuel and purchased power
898,752
920,293
3,623,935
3,991,786
Cost of natural gas sold and transported
323,495
370,351
880,939
1,163,890
Cost of sales — other
8,568
8,291
29,067
30,391
Operating and maintenance expenses
599,917
565,130
2,176,095
2,140,289
Conservation and demand side management program expenses
69,285
69,303
260,527
281,378
Depreciation and amortization
231,689
194,303
926,053
890,619
Taxes (other than income taxes)
103,032
96,738
408,924
374,815
Total operating expenses
2,234,738
2,224,409
8,305,540
8,873,168
Operating income
316,397
344,001
1,822,683
1,781,602
Other income, net
1,222
960
6,175
9,255
Equity earnings of unconsolidated subsidiaries
7,821
7,714
29,971
30,527
Allowance for funds used during construction — equity
18,336
12,533
62,840
51,223
Interest charges and financing costs
Interest charges — includes other financing costs of
$5,961, $6,295, $24,087 and $24,019, respectively
144,112
152,395
601,582
591,098
Allowance for funds used during construction — debt
(10,586
)
(6,606
)
(35,315
)
(28,181
)
Total interest charges and financing costs
133,526
145,789
566,267
562,917
Income from continuing operations before income taxes
210,250
219,419
1,355,402
1,309,690
Income taxes
70,042
78,478
450,203
468,316
Income from continuing operations
140,208
140,941
905,199
841,374
(Loss) income from discontinued operations, net of tax
(38
)
(432
)
30
(202
)
Net income
140,170
140,509
905,229
841,172
Dividend requirements on preferred stock
-
-
-
3,534
Premium on redemption of preferred stock
-
-
-
3,260
Earnings available to common shareholders
$
140,170
$
140,509
$
905,229
$
834,378
Weighted average common shares outstanding:
Basic
488,428
486,223
487,899
485,039
Diluted
489,136
486,991
488,434
485,615
Earnings per average common share:
Basic
$
0.29
$
0.29
$
1.86
$
1.72
Diluted
0.29
0.29
1.85
1.72
Cash dividends declared per common share
$
0.27
$
0.26
$
1.07
$
1.03
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 earnings and earnings per share (EPS) of
each subsidiary discussed below do not represent a direct legal interest
in the assets and liabilities allocated to such subsidiary but rather
represent a direct interest in our assets and liabilities as a whole.
EPS by subsidiary is a financial measure not recognized under GAAP that
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 our consolidated fully diluted
EPS determined in accordance with GAAP as an indicator of operating
performance.
Note 1.Earnings Per Share Summary
The following table summarizes the diluted earnings per share for Xcel
Energy:
Three Months Ended Dec. 31
Twelve Months Ended Dec. 31
Diluted Earnings (Loss) Per Share
2012
2011
2012
2011
Public Service Company of Colorado (PSCo)
$
0.16
$
0.18
$
0.90
$
0.82
NSP-Minnesota
0.13
0.11
0.70
0.73
Southwestern Public Service Company (SPS)
0.01
0.01
0.22
0.18
NSP-Wisconsin
0.02
0.02
0.10
0.10
Equity earnings of unconsolidated subsidiaries
0.01
0.01
0.04
0.04
Regulated utility — continuing operations (a)
0.33
0.33
1.96
1.87
Xcel Energy Inc. and other costs
(0.04
)
(0.04
)
(0.14
)
(0.15
)
Ongoing(b) diluted earnings per share
0.29
0.29
1.82
1.72
Prescription drug tax benefit (b)
-
-
0.03
-
GAAP diluted earnings per share
$
0.29
$
0.29
$
1.85
$
1.72
(a)
See Note 2.
(b)
See Note 6.
PSCo — PSCo’s ongoing earnings increased $0.08 per share
for 2012. The increase is primarily due to an electric rate increase,
effective May 2012, and the impact of warmer summer weather. The
increase was partially offset by decreased wholesale revenue due to the
expiration of a long-term power sales agreement with Black Hills Corp,
higher depreciation expense and operating and maintenance (O&M) expenses.
NSP-Minnesota — NSP-Minnesota’s 2012 ongoing earnings
decreased $0.03 per share. The decrease is primarily due to the
unfavorable impact of warmer than normal winter weather during the first
quarter, electric sales decline, higher property taxes, higher O&M
expenses and depreciation expense. These decreases were partially offset
by the 2012 rate increase and a lower effective tax rate.
SPS — SPS’ ongoing earnings increased $0.04 per share for
2012. The increase is the result of rate increases in New Mexico and
Texas, effective January 2012, partially offset by the impact of milder
weather during the second half of the year, higher depreciation expense
and property taxes.
NSP-Wisconsin — NSP-Wisconsin’s ongoing earnings were flat
for 2012. Ongoing earnings were positively impacted by rate increases,
effective January 2012, offset by higher O&M expenses.
The following table summarizes significant components contributing to
the changes in the 2012 EPS compared with the same periods in 2011,
which are discussed in more detail later in the release.
Three Months
Twelve Months
Diluted Earnings (Loss) Per Share
Ended Dec. 31
Ended Dec. 31
2011 GAAP and ongoing(a) diluted
earnings per share
$
0.29
$
1.72
Components of change — 2012 vs. 2011
Higher electric margins
0.05
0.15
Lower effective tax rate
0.01
0.04
Lower conservation and DSM expenses (generally offset in revenues)
-
0.03
Higher AFUDC - Equity
0.01
0.02
Higher natural gas margins
0.01
0.01
Higher operating and maintenance expenses
(0.04
)
(0.05
)
Higher depreciation and amortization
(0.05
)
(0.04
)
Higher taxes (other than income taxes)
(0.01
)
(0.04
)
Lower (higher) interest charges
0.01
(0.01
)
Other, net (including interest and premium on redemption of
preferred stock)
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 weather sensitive.
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 Dec. 31
Twelve Months Ended Dec. 31
2012 vs.
2011 vs.
2012 vs.
2012 vs.
2011 vs.
2012 vs.
Normal
Normal
2011
Normal
Normal
2011
HDD
(6.7
)
%
(8.7
)
%
2.1
%
(15.9
)
%
(1.0
)
%
(14.8
)
%
CDD (a)
N/A
N/A
N/A
46.1
38.1
5.7
THI (a)
N/A
N/A
N/A
36.1
37.9
0.2
(a) CDD and THI have no meaningful impact on fourth quarter
sales.
Weather — The following table summarizes the estimated
impact of temperature variations on EPS compared with sales under normal
weather conditions:
Three Months Ended Dec. 31
Twelve Months Ended Dec. 31
2012 vs.
2011 vs.
2012 vs.
2012 vs.
2011 vs.
2012 vs.
Normal
Normal
2011
Normal
Normal
2011
Retail electric
$
(0.002
)
$
(0.006
)
$
0.004
$
0.081
$
0.080
$
0.001
Firm natural gas
(0.003
)
(0.006
)
0.003
(0.033
)
0.002
(0.035
)
Total
$
(0.005
)
$
(0.012
)
$
0.007
$
0.048
$
0.082
$
(0.034
)
In 2012, Xcel Energy refined its estimate to incorporate the impact of
weather on demand charges. As a result, the estimated weather impact on
earnings per share for prior periods has been adjusted for comparison
purposes.
Sales Growth (Decline) — The following table summarizes
Xcel Energy’s sales growth (decline) for actual and weather-normalized
sales in 2012:
Three Months Ended Dec. 31
Weather
Actual
Normalized
Electric residential
0.5
%
0.0
%
Electric commercial and industrial
(0.4
)
(0.4
)
Total retail electric sales
(0.2
)
(0.3
)
Firm natural gas sales
0.0
(0.9
)
Twelve Months Ended Dec. 31
Twelve Months Ended Dec. 31
(Without Leap Day)
Weather
Weather
Actual
Normalized
Actual
Normalized
Electric residential
(1.0
)
%
(0.1
)
%
(1.2
)
%
(0.4
)
%
Electric commercial and industrial
0.1
0.0
(0.2
)
(0.2
)
Total retail electric sales
(0.3
)
0.0
(0.5
)
(0.3
)
Firm natural gas sales
(10.6
)
(0.3
)
(11.0
)
(0.8
)
Electric— 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 Dec. 31
Twelve Months Ended Dec. 31
(Millions of Dollars)
2012
2011
2012
2011
Electric revenues
$
2,011
$
1,989
$
8,517
$
8,767
Electric fuel and purchased power
(899
)
(920
)
(3,624
)
(3,992
)
Electric margin
$
1,112
$
1,069
$
4,893
$
4,775
The following table summarizes the components of the changes in electric
margin:
Three Months
Twelve Months
Ended Dec. 31
Ended Dec. 31
(Millions of Dollars)
2012 vs. 2011
2012 vs. 2011
Retail rate increases (Colorado, Texas, New Mexico, Wisconsin, South
Dakota,
North Dakota, Michigan and Minnesota) (a)
$
50
$
125
Demand revenue
7
13
Transmission revenue, net of costs
(7
)
13
Conservation and DSM incentive
(6
)
12
Estimated impact of weather
4
1
Firm wholesale (b)
(12
)
(48
)
Retail sales decrease, excluding weather impact
(2
)
(6
)
Conservation and DSM revenue (offset by expenses)
2
(5
)
Other, net
7
13
Total increase in electric margin
$
43
$
118
(a)
In the fourth quarter of 2011, NSP-Minnesota reduced depreciation
expense and revenues by approximately $30 million, representing a
full year of depreciation expense, based on the proposed rate case
settlements at that time. As a result, NSP-Minnesota recognized
higher revenues and depreciation expense, in the fourth quarter of
2012, of approximately $23 million. These settlement provisions did
not impact the year over year comparison.
(b)
Decrease is primarily due to the expiration of a long-term power
sales agreement with Black Hills Corp., effective Jan. 1, 2012.
Natural Gas — 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 Dec. 31
Twelve Months Ended Dec. 31
(Millions of Dollars)
2012
2011
2012
2011
Natural gas revenues
$
521
$
560
$
1,537
$
1,812
Cost of natural gas sold and transported
(323)
(370)
(881)
(1,164)
Natural gas margin
$
198
$
190
$
656
$
648
The following table summarizes the components of the changes in natural
gas margin:
Three Months
Twelve Months
Ended Dec. 31
Ended Dec. 31
(Millions of Dollars)
2012 vs. 2011
2012 vs. 2011
Pipeline system integrity adjustment rider (Colorado) offset by
expenses
$
7
$
29
Retail rate increase (Colorado, Wisconsin)
-
16
Estimated impact of weather
2
(26
)
Conservation and DSM revenue (offset by expenses)
(3
)
(17
)
Other, net
2
6
Total increase in natural gas margin
$
8
$
8
O&M Expenses — O&M expenses increased $34.8 million,
or 6.2 percent, for the fourth quarter of 2012 and $35.8 million, or 1.7
percent, for 2012, compared with 2011. The following table summarizes
the changes in O&M expenses:
Three Months
Twelve Months
Ended Dec. 31
Ended Dec. 31
(Millions of Dollars)
2012 vs. 2011
2012 vs. 2011
Employee benefits
$
(1
)
$
36
Pipeline system integrity costs
5
20
SmartGridCity™
11
11
Prairie Island Extended Power Uprate (EPU)
10
10
Plant generation costs
(12
)
(17
)
Bad debt expense
(2
)
(10
)
Labor and contract labor
10
(2
)
Other, net
14
(12
)
Total increase in O&M expenses
$
35
$
36
Higher employee benefits are mainly due to increased pension expense.
Higher pipeline system integrity costs relate to increased compliance
and inspection initiatives, which in Colorado are recovered through
the pipeline system integrity rider.
See Note 4 for further discussion of SmartGridCity and Prairie Island
EPU.
Lower plant generation costs are primarily attributable to fewer plant
overhauls in 2012.
Higher fourth quarter labor and contract labor costs are largely
driven by vegetation management and substation maintenance.
Conservation and Demand Side Management (DSM) Program Expenses —
Conservation and DSM program expenses were flat for the fourth quarter
of 2012 and decreased $20.9 million, or 7.4 percent, for 2012, compared
with 2011. The lower expenses are primarily attributable to lower gas
rider rates, as well as the timing of recovery of electric conservation
improvement program expenses at NSP-Minnesota. Conservation and DSM
program expenses are generally recovered in our major jurisdictions
concurrently through riders and base rates.
Depreciation and Amortization — Depreciation and
amortization increased $37.4 million, or 19.2 percent, for the fourth
quarter of 2012 and $35.4 million, or 4.0 percent, for 2012, compared
with 2011. NSP-Minnesota recognized higher revenues and higher
depreciation expense by approximately $23 million in the fourth quarter
of 2012, based on settlements in the Minnesota and South Dakota electric
rate cases, which resulted in a year-to-date adjustment lowering
depreciation and revenue in the fourth quarter of 2011. Overall, the
increase for 2012, compared to 2011 is primarily due to a portion of the
Monticello extended power uprate going into service in May 2011 at
NSP-Minnesota, the Jones Unit 3 going into service in June 2011 at SPS
and normal system expansion across Xcel Energy’s service territories.
Taxes (Other Than Income Taxes) — Taxes (other than income
taxes) increased $6.3 million, or 6.5 percent, for the fourth quarter of
2012 and $34.1 million, or 9.1 percent, for 2012, compared with 2011.
The increases are due to an increase in property taxes primarily in
Minnesota. Higher property taxes in Colorado related to the electric
retail business are being deferred, based on the multi-year rate
settlement approved by the Colorado Public Utilities Commission (CPUC)
in May 2012.
Allowance for Funds Used During Construction, Equity and Debt
(AFUDC) — AFUDC increased $9.8 million for the fourth quarter of
2012 and $18.8 million for 2012, compared with 2011. The increases are
primarily due to the expansion of PSCo’s transmission facilities,
additional construction related to the Colorado Clean Air Clean Jobs Act
(CACJA) and life extension work at the Prairie Island nuclear generating
plant.
Interest Charges — Interest charges decreased $8.3
million, or 5.4 percent, for the fourth quarter of 2012 and increased
$10.5 million, or 1.8 percent, for 2012, compared with 2011. The overall
increase is due to higher long-term debt levels to fund investment in
utility operations, partially offset by lower interest rates.
Income Taxes — Income tax expense for continuing
operations decreased $8.4 million for the fourth quarter of 2012,
compared with the same period in 2011. The decrease in income tax
expense was primarily due to a decrease in pretax income in 2012 and a
tax benefit related to the reversal of a tax valuation allowance in
2012. The effective tax rate for continuing operations was 33.3 percent
for the fourth quarter of 2012 compared with 35.8 percent for the same
period in 2011. The lower effective tax rate for 2012 was primarily due
to the adjustment referenced above. The effective tax rate would have
been 34.5 percent for the fourth quarter of 2012 without this tax
benefit.
Income tax expense for continuing operations decreased $18.1 million for
2012, compared with 2011. The decrease in income tax expense was
primarily due to a tax benefit of approximately $14.9 million associated
with a carryback and a tax benefit of $17 million related to the
restoration of a portion of the tax benefit written off in 2010
associated with federal subsidies for prescription drug plans. These
were partially offset by higher pretax income in 2012. The effective tax
rate for continuing operations was 33.2 percent for 2012 compared with
35.8 percent for 2011. The lower effective tax rate for 2012 was
primarily due to the adjustments referenced above. The effective tax
rate would have been 35.6 percent for 2012 without these tax benefits.
Note 3.Xcel Energy Capital Structure,
Financing and Credit Ratings
Following is the capital structure of Xcel Energy:
Percentage
of Total
(Billions of Dollars)
Dec. 31, 2012
Capitalization
Current portion of long-term debt
$
0.3
1
%
Short-term debt
0.6
3
Long-term debt
10.1
51
Total debt
11.0
55
Common equity
8.9
45
Total capitalization
$
19.9
100
%
Credit Facilities — As of Jan. 29, 2013, Xcel Energy Inc.
and its utility subsidiaries had the following committed credit
facilities available to meet liquidity needs:
(Millions of Dollars)
Facility
Drawn(a)
Available
Cash
Liquidity
Maturity
Xcel Energy Inc.
$
800.0
$
351.0
$
449.0
$
0.2
$
449.2
July 2017
PSCo
700.0
169.0
531.0
1.1
532.1
July 2017
NSP-Minnesota
500.0
323.2
176.8
0.6
177.4
July 2017
SPS
300.0
35.0
265.0
0.9
265.9
July 2017
NSP-Wisconsin
150.0
41.0
109.0
0.1
109.1
July 2017
Total
$
2,450.0
$
919.2
$
1,530.8
$
2.9
$
1,533.7
(a) Includes outstanding commercial paper and letters of
credit.
Credit Ratings — Access to reasonably priced capital
markets is dependent in part on credit and 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 Jan. 29, 2013, 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
Baa1
BBB+
BBB+
Xcel Energy Inc.
Commercial Paper
P-2
A-2
F2
NSP-Minnesota
Senior Unsecured Debt
A3
A-
A
NSP-Minnesota
Senior Secured Debt
A1
A
A+
NSP-Minnesota
Commercial Paper
P-2
A-2
F2
NSP-Wisconsin
Senior Unsecured Debt
A3
A-
A
NSP-Wisconsin
Senior Secured Debt
A1
A
A+
NSP-Wisconsin
Commercial Paper
P-2
A-2
F2
PSCo
Senior Unsecured Debt
Baa1
A-
A-
PSCo
Senior Secured Debt
A2
A
A
PSCo
Commercial Paper
P-2
A-2
F2
SPS
Senior Unsecured Debt
Baa2
A-
BBB+
SPS
Senior Secured Debt
A3
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.
Capital Expenditures — The 2012 actual and the current
estimated capital expenditure programs of Xcel Energy Inc. and its
subsidiaries for the years 2013 through 2017 are shown in the table
below. The capital expenditure forecast has been revised to reflect the
termination of the Prairie Island EPU.
Actual
Forecast
(Millions of Dollars)
2012
2013
2014
2015
2016
2017
By Subsidiary
NSP-Minnesota
$
1,018
$
1,395
$
1,135
$
910
$
925
$
1,080
PSCo
887
1,075
1,000
850
800
840
SPS
389
490
400
305
300
345
NSP-Wisconsin
155
180
240
245
230
235
WYCO
1
15
-
-
-
-
Total capital expenditures
$
2,450
$
3,155
$
2,775
$
2,310
$
2,255
$
2,500
By Function
2012
2013
2014
2015
2016
2017
Electric generation
$
772
$
1,025
$
710
$
550
$
465
$
570
Electric transmission
734
1,010
870
650
635
770
Electric distribution
486
515
525
525
535
545
Natural gas
247
355
365
335
325
320
Nuclear fuel
53
95
155
100
140
145
Other
158
155
150
150
155
150
Total capital expenditures
$
2,450
$
3,155
$
2,775
$
2,310
$
2,255
$
2,500
By Project
2012
2013
2014
2015
2016
2017
Other capital expenditures
$
1,720
$
1,710
$
1,610
$
1,555
$
1,600
$
1,755
PSCo CACJA
189
345
235
90
15
-
Other major transmission projects
179
245
260
175
320
415
CapX2020 transmission project
170
350
295
140
-
-
Natural gas pipeline replacement
100
140
170
190
130
135
Nuclear fuel
53
95
155
100
140
145
Nuclear capacity increases and life extension
39
270
50
60
50
50
Total capital expenditures
$
2,450
$
3,155
$
2,775
$
2,310
$
2,255
$
2,500
The capital expenditure programs of Xcel Energy are subject to
continuing review and modification. Actual utility construction
expenditures may vary from the estimates due to changes in electric and
natural gas projected load growth, regulatory decisions, legislative
initiatives, reserve margins, the availability of purchased power,
alternative plans for meeting long-term energy needs, compliance with
future environmental requirements, renewable portfolio standards, and
merger, acquisition and divestiture opportunities to support corporate
strategies.
Financing— Xcel Energy issues debt and
equity securities to refinance retiring maturities, reduce short-term
debt, fund construction programs, infuse equity in subsidiaries, fund
asset acquisitions and for other general corporate purposes. The current
estimated financing plans of Xcel Energy Inc. and its subsidiaries for
the years 2013 through 2017 are shown in the table below. The financing
plan has been revised to reflect the termination of the Prairie Island
EPU and the impacts of extended bonus depreciation under the recent
federal tax bill.
(Millions of Dollars)
Funding Capital Expenditures
Cash from Operations*
$
10,150
New Debt**
2,045
Equity
400
DRIP
400
2013-2017 Capital Expenditures
$
12,995
Maturing Debt
$
1,793
*
Cash from operations, net of dividend and pension funding.
**
Reflects a combination of short and long-term debt.
During 2012, Xcel Energy Inc. and its utility subsidiaries completed the
following financings:
In June, SPS issued $100 million of 30-year first mortgage bonds with
a coupon of 4.50 percent.
In August, NSP-Minnesota issued $300 million of 10-year first mortgage
bonds with a coupon of 2.15 percent, and $500 million of 30-year first
mortgage bonds with a coupon of 3.40 percent.
In September, PSCo issued $300 million of 10-year first mortgage bonds
with a coupon of 2.25 percent, and $500 million of 30-year first
mortgage bonds with a coupon of 3.60 percent.
In October, NSP-Wisconsin issued $100 million of 30-year first
mortgage bonds with a coupon of 3.70 percent.
During 2013, Xcel Energy Inc. and its utility subsidiaries anticipate
issuing the following:
NSP-Minnesota may issue approximately $400 million of first mortgage
bonds in the first half of 2013.
PSCo may issue approximately $500 million of first mortgage bonds in
the first half of 2013.
SPS may issue approximately $100 million of first mortgage bonds in
the first half of 2013.
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 2012 Electric Rate Case—In November 2012, NSP-Minnesota filed a request with the Minnesota
Public Utilities Commission (MPUC) for an increase in annual revenues of
approximately $285 million, or 10.7 percent. The rate filing is based on
a 2013 forecast test year, a requested return on equity (ROE) of 10.6
percent, an average electric rate base of approximately $6.3 billion and
an equity ratio of 52.56 percent.
In December 2012, the MPUC accepted the filing as complete and approved
the interim rates of approximately $251 million, as requested, effective
Jan. 1, 2013, subject to refund.
The procedural schedule is as follows:
Intervenor Direct Testimony – Feb. 28, 2013
Rebuttal Testimony – March 25, 2013
Surrebuttal Testimony – April 12, 2013
Evidentiary Hearing – April 18 – 24, 2013
Initial Brief – May 15, 2013
Reply Brief and Findings of Fact – May 30, 2013
Administrative Law Judge (ALJ) Report – July 3, 2013
MPUC Order – Anticipated by September 2013
Prairie Island Nuclear Plant EPU — In 2009, the MPUC
granted NSP-Minnesota a Certificate of Need (CON) for an EPU project at
the Prairie Island nuclear generating plant. The total estimated cost of
the EPU was $294 million, of which approximately $77.6 million has been
incurred, including AFUDC of approximately $13.3 million. Subsequently,
NSP-Minnesota filed a resource plan update and a change of circumstances
(COC) filing notifying the MPUC that there were changes in the size,
timing and cost estimates for this project, revisions to economic and
project design analysis and changes due to the estimated impact of
revised scheduled outages. The information indicated reductions to the
estimated benefit of the uprate project. As a result, NSP-Minnesota
concluded that further investment in this project would not benefit
customers. In December 2012, the MPUC voted unanimously that no party
had shown cause to prevent termination of the EPU CON. The MPUC is
expected to issue an order terminating the EPU CON in early 2013.
NSP-Minnesota plans to address recovery of incurred costs in the next
rate case for each of the NSP-Minnesota jurisdictions and to file a
request with the FERC for approval to recover a portion of the costs
from NSP-Wisconsin through the Interchange Agreement. NSP-Wisconsin
plans to seek cost recovery in a future rate case. Based on the outcome
of the MPUC decision, EPU costs incurred to date were compared to the
discounted value of the estimated future rate recovery based on past
jurisdictional precedent, resulting in a $10.1 million pretax charge in
December 2012.
NSP-Minnesota – North Dakota 2012 Electric Rate Case—In December 2012, NSP-Minnesota filed a request with the North
Dakota Public Service Commission (NDPSC) for an increase in annual
retail electric revenues of approximately $16.9 million, or 9.25
percent. The rate filing is based on a 2013 forecast test year, a
requested ROE of 10.6 percent, an electric rate base of approximately
$377.6 million and an equity ratio of 52.56 percent.
In January 2013, the NDPSC approved an interim electric increase of
$14.7 million, effective Feb. 16, 2013, subject to refund. A final NDPSC
decision on the case is expected in the third quarter of 2013.
NSP-Minnesota – South Dakota 2012 Electric Rate Case—In June 2012, NSP-Minnesota filed a request with the South Dakota
Public Utilities Commission (SDPUC) to increase electric rates by $19.4
million annually. The request was based on a 2011 historic test year
adjusted for known and measurable changes for 2012 and 2013, a requested
ROE of 10.65 percent, an average rate base of $367.5 million and an
equity ratio of 52.89 percent.
In December 2012, the procedural schedule was suspended to allow time to
construct a potential settlement agreement between NSP-Minnesota and the
SDPUC Staff. Interim rates of $19.4 million went into effect on Jan. 1,
2013, subject to refund. A SDPUC decision is expected in the first half
of 2013.
NSP-Wisconsin – 2012 Electric and Gas Rate Case — In June
2012, 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, 2013. NSP-Wisconsin requested an overall
increase in annual electric rates of $39.1 million, or 6.7 percent, and
an increase in natural gas rates of $5.3 million, or 4.9 percent.
The electric rate filing was based on a 2013 forecast test year, a ROE
of 10.40 percent, an equity ratio of 52.50 percent and an average 2013
electric rate base of approximately $788.6 million. The natural gas rate
request was solely due to a proposal to recover the initial costs
associated with the environmental cleanup of a site in Ashland, Wis.
In December 2012, the PSCW approved an electric rate increase of
approximately $35.5 million, or 6.1 percent, based on a 10.4 percent ROE
and an equity ratio of 52.50 percent. The PSCW also approved a natural
gas rate increase of $2.7 million, or 2.5 percent, to begin recovering
costs associated with the cleanup in Ashland, Wis. Final rates were
implemented on Jan. 1, 2013.
PSCo – Colorado 2012 Gas Rate Case —In
December 2012, PSCo filed a multi-year request with the Colorado Public
Utilities Commission (CPUC) to increase Colorado retail natural gas
rates by $48.5 million in 2013 with subsequent step increases of $9.9
million in 2014 and $12.1 million in 2015. PSCo also requested to
increase Colorado retail steam rates by $1.6 million in 2013 with
subsequent step increases of $0.9 million in 2014 and $2.3 million in
2015. Both requests are based on a 2013 forecast test year, a 10.5
percent ROE, a rate base of $1.3 billion for natural gas and $21 million
for steam and an equity ratio of 56 percent. Final rates are expected to
be effective in the third quarter of 2013.
PSCo is requesting an extension of its Pipeline System Integrity
Adjustment (PSIA) rider mechanism to collect the costs of accelerated
pipeline integrity efforts, including system renewal projects. PSCo
estimates that the PSIA will increase by $26.8 million in 2014 with a
subsequent step increase of $24.7 million in 2015 in addition to the
proposed changes in base rate revenue. In conjunction with the
multi-year base rate step increases, PSCo is proposing a stay-out
provision and an earnings test through the end of 2015.
PSCo – SmartGridCity™ (SGC) Cost Recovery —PSCo requested recovery of the revenue requirements associated
with $45 million of capital and $4 million of annual O&M costs incurred
to develop and operate SGC as part of its 2010 electric rate case. In
February 2011, the CPUC allowed recovery of approximately $28 million of
the capital cost and all of the O&M costs. In December 2011, PSCo
requested CPUC approval for the recovery of the remaining capital
investment in SGC and also provided the additional information
requested. On Jan. 17, 2013, the ALJ recommended denial of PSCo’s
request for recovery of the remaining portion of the SGC investment.
Parties will have an opportunity to appeal the ALJ’s recommended
decision by filing exceptions with the CPUC. If no exceptions are filed
within 20 days, the recommended decision will become effective. As a
result of the ALJ’s recommended decision, PSCo recognized a $10.7
million pre-tax charge in 2012, representing the net book value of the
disallowed investment.
PSCo Resource Plan — In July 2012, PSCo filed two separate
applications to update its resource plan. The first was an application
to purchase Brush Power, LLC and all of its assets including Brush
generating Units 1, 3 and 4 for a total purchase price of approximately
$75 million. The Brush units currently provide 237 MW of natural gas
fueled capacity and energy to PSCo under Purchased Power Agreements
(PPAs) that are set to expire in 2017 for Brush Unit 1 and Brush Unit 3,
and 2022 for Brush Unit 4.
The second application sought approval to retire Arapahoe Unit 4, a 109
MW coal-fired company-owned generating station at the end of 2013. This
was presented as an alternative to permanently fuel switching Arapahoe
Unit 4 to natural gas and instead replacing the capacity and associated
energy with a natural gas PPA with an existing generator.
In September 2012, the FERC approved the acquisition of Brush Power,
LLC. However, in December 2012, the CPUC denied approval of the
acquisition in oral deliberations due to the risks associated with the
transaction. PSCo has the ability to terminate the transaction based on
the regulatory outcome. The CPUC also denied PSCo’s proposal to retire
Arapahoe 4 by the end of 2013; however, this proposal could be revisited.
SPS – Texas 2012 Electric Rate Case—In
November 2012, SPS filed an electric rate case in Texas with the Public
Utility Commission of Texas for an increase in annual revenue of
approximately $90.2 million. The rate filing is based on a historic
twelve month test year ended June 30, 2012 adjusted for known and
measurable changes, a requested ROE of 10.65 percent, an electric rate
base of $1.15 billion and an equity ratio of 52 percent.
The procedural schedule is as follows:
Intervenor Direct Testimony – Feb. 22, 2013
Staff Direct Testimony – March 1, 2013
SPS Rebuttal Testimony – March 15, 2013
Hearing Starts – March 26, 2013
The procedural order also establishes July 1, 2013 as the latest date
rates from this case will become effective.
SPS – New Mexico 2012 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. The rate filing is based
on a 2014 forecast test year, a requested ROE of 10.65 percent, a
jurisdictional electric rate base of $365.5 million and an equity ratio
of 53.89 percent. A NMPRC decision is expected in the fourth quarter of
2013 with the implementation of final rates anticipated in the first
quarter of 2014.
Note 5.Xcel Energy Earnings Guidance
Xcel Energy’s 2013 earnings guidance is $1.85 to $1.95 per share. Key
assumptions related to 2013 earnings are detailed below:
Constructive outcomes in all rate case and regulatory proceedings.
Normal weather patterns are experienced for the year.
Weather-adjusted retail electric utility sales are projected to grow
approximately 0.5 percent.
Weather-adjusted retail firm natural gas sales are projected to
decline by approximately 1 percent.
Rider revenue recovery for certain projects have been rolled into base
rates, therefore the change is no longer meaningful.
O&M expenses are projected to increase approximately 4 percent to 5
percent over 2012 levels.
Depreciation expense is projected to increase $75 million to $85
million over 2012 levels.
Property taxes are projected to increase approximately $35 million to
$40 million over 2012 levels.
Interest expense (net of AFUDC — debt) is projected to
decrease $30 million to $35 million from 2012 levels.
AFUDC — equity is projected to increase approximately
$15 million to $20 million over 2012 levels.
The effective tax rate is projected to be approximately 34 percent to
36 percent.
Average common stock and equivalents are projected to be approximately
490 million to 500 million shares.
Note 6.Non-GAAP Reconciliation
Xcel Energy’s management believes that ongoing earnings provide a
meaningful comparison of earnings results and is representative of Xcel
Energy’s fundamental core earnings power. 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.
The following table provides a reconciliation of ongoing earnings to
GAAP earnings:
Three Months Ended Dec. 31
Twelve Months Ended Dec. 31
(Thousands of Dollars)
2012
2011
2012
2011
Ongoingearnings
$
140,208
$
140,941
$
888,255
$
841,374
Prescription drug tax benefit
-
-
16,944
-
Total continuing operations
140,208
140,941
905,199
841,374
(Loss) income from discontinued operations
(38
)
(432
)
30
(202
)
GAAPearnings
$
140,170
$
140,509
$
905,229
$
841,172
Impact of the Patient Protection and Affordable Care Act — In
March 2010, the Patient Protection and Affordable Care Act was signed
into law. The law includes provisions to generate tax revenue to help
offset the cost of the new legislation. One of these provisions reduces
the deductibility of retiree health care costs to the extent of federal
subsidies received by plan sponsors that provide retiree prescription
drug benefits equivalent to Medicare Part D coverage, beginning in 2013.
Xcel Energy expensed approximately $17 million of previously recognized
tax benefits relating to the federal subsidies during the first quarter
of 2010.
In the third quarter of 2012, Xcel Energy implemented a tax strategy
related to the allocation of funding of Xcel Energy’s retiree
prescription drug plan. This strategy restored a portion of the tax
benefit associated with federal subsidies for prescription drug plans
that had been accrued since 2004 and was expensed in 2010. As a result,
Xcel Energy recognized approximately $17 million of income tax benefit.
XCEL ENERGY INC. AND SUBSIDIARIES
EARNINGS RELEASE SUMMARY (Unaudited)
(amounts in thousands, except per share data)
Three Months Ended Dec. 31
2012
2011
Operating revenues:
Electric and natural gas revenues
$
2,531,489
$
2,548,909
Other
19,646
19,501
Total operating revenues
2,551,135
2,568,410
Income from continuing operations
140,208
140,941
Loss from discontinued operations
(38
)
(432
)
Net income
$
140,170
$
140,509
Earnings available to common shareholders
$
140,170
$
140,509
Weighted average diluted common shares outstanding
489,136
486,991
Components of Earnings per Share — Diluted
Regulated utility — continuing operations
$
0.33
$
0.33
Xcel Energy Inc. and other costs
(0.04
)
(0.04
)
Ongoing(a) diluted earnings per share
0.29
0.29
Prescription drug tax benefit (a)
-
-
GAAP diluted earnings per share
$
0.29
$
0.29
Twelve Months Ended Dec. 31
2012
2011
Operating revenues:
Electric and natural gas revenues
$
10,054,670
$
10,578,519
Other
73,553
76,251
Total operating revenues
10,128,223
10,654,770
Income from continuing operations
905,199
841,374
Income (loss) from discontinued operations
30
(202
)
Net income
$
905,229
$
841,172
Earnings available to common shareholders
$
905,229
$
834,378
Weighted average diluted common shares outstanding
488,434
485,615
Components of Earnings per Share — Diluted
Regulated utility — continuing operations
$
1.96
$
1.87
Xcel Energy Inc. and other costs
(0.14
)
(0.15
)
Ongoing(a) diluted earnings per share
1.82
1.72
Prescription drug tax benefit (a)
0.03
-
GAAPdiluted earnings per share
$
1.85
$
1.72
Book value per share
$
18.19
$
17.44
(a) See Note 6.
Xcel Energy Inc. Paul Johnson, 612-215-4535 Vice
President, Investor Relations and Financial Management or Jack
Nielsen, 612-215-4559 Director, Investor Relations or Cindy
Hoffman, 612-215-4536 Senior Investor Relations Analyst or For
news media inquiries only: Xcel Energy Media Relations, 612-215-5300 Xcel
Energy internet address: www.xcelenergy.com
Press Release $XEL Xcel Energy Inc.
MINNEAPOLIS--(BUSINESS WIRE)-- Xcel Energy Inc. (NYSE: XEL) today reported 2012 GAAP earnings of $905 million, or $1.85 per share compared with 2011 GAAP earnings of $841 million, or $1.72 per share.
Ongoing earnings, which exclude one adjustment, were $1.82 per share for 2012 compared with $1.72 per share in 2011. Ongoing earnings increased largely due to increases in electric margins driven by the conclusion of various rate cases, which reflect our continued investment in our utility business and a lower effective tax rate. Partially offsetting these positive factors were warmer than normal winter weather, increases in depreciation expense, operating and maintenance expenses and property taxes.
“We had an excellent year financially and operationally in 2012,” said Ben Fowke, Chairman, President and Chief Executive Officer. “We delivered earnings in the upper half of our guidance range, which represents the eighth consecutive year in which we have met or exceeded our earnings guidance and for the ninth consecutive year we increased our dividend. We implemented a multi-year rate plan in Colorado and reached constructive regulatory outcomes in several other rate cases. Finally, we maintained excellent reliability during one of the warmest years on record, all executed with outstanding safety performance.”
“We have established a solid strategy and continue to execute our business plan. As a result, we are well positioned to deliver on our 2013 earnings guidance of $1.85 to $1.95 per share,” stated Fowke.
Earnings Adjusted for Certain Items (Ongoing Earnings)
The following table provides a reconciliation of ongoing earnings per share to GAAP earnings per share:
(a)
At 9:00 a.m. CST 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.
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 2:00 p.m. CST on Jan. 31 through 11:59 p.m. CST on Feb. 1.
Except for the historical statements contained in this release, the matters discussed herein, are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements, including our 2013 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, 2011 and Quarterly Reports on Form 10-Q for the quarters ended March 31, June 30 and Sept. 30, 2012.
This information is not given in connection with any
sale, offer for sale or offer to buy any security.
10,654,770
8,291
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 earnings and earnings per share (EPS) of each subsidiary discussed below do not represent a direct legal interest in the assets and liabilities allocated to such subsidiary but rather represent a direct interest in our assets and liabilities as a whole. EPS by subsidiary is a financial measure not recognized under GAAP that 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 our consolidated fully diluted EPS determined in accordance with GAAP as an indicator of operating performance.
Note 1. Earnings Per Share Summary
The following table summarizes the diluted earnings per share for Xcel Energy:
PSCo — PSCo’s ongoing earnings increased $0.08 per share for 2012. The increase is primarily due to an electric rate increase, effective May 2012, and the impact of warmer summer weather. The increase was partially offset by decreased wholesale revenue due to the expiration of a long-term power sales agreement with Black Hills Corp, higher depreciation expense and operating and maintenance (O&M) expenses.
NSP-Minnesota — NSP-Minnesota’s 2012 ongoing earnings decreased $0.03 per share. The decrease is primarily due to the unfavorable impact of warmer than normal winter weather during the first quarter, electric sales decline, higher property taxes, higher O&M expenses and depreciation expense. These decreases were partially offset by the 2012 rate increase and a lower effective tax rate.
SPS — SPS’ ongoing earnings increased $0.04 per share for 2012. The increase is the result of rate increases in New Mexico and Texas, effective January 2012, partially offset by the impact of milder weather during the second half of the year, higher depreciation expense and property taxes.
NSP-Wisconsin — NSP-Wisconsin’s ongoing earnings were flat for 2012. Ongoing earnings were positively impacted by rate increases, effective January 2012, offset by higher O&M expenses.
The following table summarizes significant components contributing to the changes in the 2012 EPS compared with the same periods in 2011, which are discussed in more detail later in the release.
Three Months
Ended Dec. 31
Note 2. Regulated Utility Results — Continuing Operations
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 weather sensitive.
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:
(a) CDD and THI have no meaningful impact on fourth quarter sales.
Weather — The following table summarizes the estimated impact of temperature variations on EPS compared with sales under normal weather conditions:
In 2012, Xcel Energy refined its estimate to incorporate the impact of weather on demand charges. As a result, the estimated weather impact on earnings per share for prior periods has been adjusted for comparison purposes.
Sales Growth (Decline) — The following table summarizes Xcel Energy’s sales growth (decline) for actual and weather-normalized sales in 2012:
Three Months Ended Dec. 31
Actual
Twelve Months Ended Dec. 31
Actual
Actual
Electric — 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:
The following table summarizes the components of the changes in electric margin:
Three Months
Twelve Months
Ended Dec. 31
Ended Dec. 31
2012 vs. 2011
2012 vs. 2011
Natural Gas — 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:
The following table summarizes the components of the changes in natural gas margin:
Three Months
Twelve Months
Ended Dec. 31
Ended Dec. 31
2012 vs. 2011
2012 vs. 2011
O&M Expenses — O&M expenses increased $34.8 million, or 6.2 percent, for the fourth quarter of 2012 and $35.8 million, or 1.7 percent, for 2012, compared with 2011. The following table summarizes the changes in O&M expenses:
Three Months
Twelve Months
Ended Dec. 31
Ended Dec. 31
2012 vs. 2011
2012 vs. 2011
Conservation and Demand Side Management (DSM) Program Expenses — Conservation and DSM program expenses were flat for the fourth quarter of 2012 and decreased $20.9 million, or 7.4 percent, for 2012, compared with 2011. The lower expenses are primarily attributable to lower gas rider rates, as well as the timing of recovery of electric conservation improvement program expenses at NSP-Minnesota. Conservation and DSM program expenses are generally recovered in our major jurisdictions concurrently through riders and base rates.
Depreciation and Amortization — Depreciation and amortization increased $37.4 million, or 19.2 percent, for the fourth quarter of 2012 and $35.4 million, or 4.0 percent, for 2012, compared with 2011. NSP-Minnesota recognized higher revenues and higher depreciation expense by approximately $23 million in the fourth quarter of 2012, based on settlements in the Minnesota and South Dakota electric rate cases, which resulted in a year-to-date adjustment lowering depreciation and revenue in the fourth quarter of 2011. Overall, the increase for 2012, compared to 2011 is primarily due to a portion of the Monticello extended power uprate going into service in May 2011 at NSP-Minnesota, the Jones Unit 3 going into service in June 2011 at SPS and normal system expansion across Xcel Energy’s service territories.
Taxes (Other Than Income Taxes) — Taxes (other than income taxes) increased $6.3 million, or 6.5 percent, for the fourth quarter of 2012 and $34.1 million, or 9.1 percent, for 2012, compared with 2011. The increases are due to an increase in property taxes primarily in Minnesota. Higher property taxes in Colorado related to the electric retail business are being deferred, based on the multi-year rate settlement approved by the Colorado Public Utilities Commission (CPUC) in May 2012.
Allowance for Funds Used During Construction, Equity and Debt (AFUDC) — AFUDC increased $9.8 million for the fourth quarter of 2012 and $18.8 million for 2012, compared with 2011. The increases are primarily due to the expansion of PSCo’s transmission facilities, additional construction related to the Colorado Clean Air Clean Jobs Act (CACJA) and life extension work at the Prairie Island nuclear generating plant.
Interest Charges — Interest charges decreased $8.3 million, or 5.4 percent, for the fourth quarter of 2012 and increased $10.5 million, or 1.8 percent, for 2012, compared with 2011. The overall increase is due to higher long-term debt levels to fund investment in utility operations, partially offset by lower interest rates.
Income Taxes — Income tax expense for continuing operations decreased $8.4 million for the fourth quarter of 2012, compared with the same period in 2011. The decrease in income tax expense was primarily due to a decrease in pretax income in 2012 and a tax benefit related to the reversal of a tax valuation allowance in 2012. The effective tax rate for continuing operations was 33.3 percent for the fourth quarter of 2012 compared with 35.8 percent for the same period in 2011. The lower effective tax rate for 2012 was primarily due to the adjustment referenced above. The effective tax rate would have been 34.5 percent for the fourth quarter of 2012 without this tax benefit.
Income tax expense for continuing operations decreased $18.1 million for 2012, compared with 2011. The decrease in income tax expense was primarily due to a tax benefit of approximately $14.9 million associated with a carryback and a tax benefit of $17 million related to the restoration of a portion of the tax benefit written off in 2010 associated with federal subsidies for prescription drug plans. These were partially offset by higher pretax income in 2012. The effective tax rate for continuing operations was 33.2 percent for 2012 compared with 35.8 percent for 2011. The lower effective tax rate for 2012 was primarily due to the adjustments referenced above. The effective tax rate would have been 35.6 percent for 2012 without these tax benefits.
Note 3. Xcel Energy Capital Structure, Financing and Credit Ratings
Following is the capital structure of Xcel Energy:
(Billions of Dollars)
Credit Facilities — As of Jan. 29, 2013, Xcel Energy Inc. and its utility subsidiaries had the following committed credit facilities available to meet liquidity needs:
(a) Includes outstanding commercial paper and letters of credit.
Credit Ratings — Access to reasonably priced capital markets is dependent in part on credit and 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 Jan. 29, 2013, the following represents the credit ratings assigned to Xcel Energy Inc. and its utility subsidiaries:
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.
Capital Expenditures — The 2012 actual and the current estimated capital expenditure programs of Xcel Energy Inc. and its subsidiaries for the years 2013 through 2017 are shown in the table below. The capital expenditure forecast has been revised to reflect the termination of the Prairie Island EPU.
The capital expenditure programs of Xcel Energy are subject to continuing review and modification. Actual utility construction expenditures may vary from the estimates due to changes in electric and natural gas projected load growth, regulatory decisions, legislative initiatives, reserve margins, the availability of purchased power, alternative plans for meeting long-term energy needs, compliance with future environmental requirements, renewable portfolio standards, and merger, acquisition and divestiture opportunities to support corporate strategies.
Financing — Xcel Energy issues debt and equity securities to refinance retiring maturities, reduce short-term debt, fund construction programs, infuse equity in subsidiaries, fund asset acquisitions and for other general corporate purposes. The current estimated financing plans of Xcel Energy Inc. and its subsidiaries for the years 2013 through 2017 are shown in the table below. The financing plan has been revised to reflect the termination of the Prairie Island EPU and the impacts of extended bonus depreciation under the recent federal tax bill.
During 2012, Xcel Energy Inc. and its utility subsidiaries completed the following financings:
During 2013, Xcel Energy Inc. and its utility subsidiaries anticipate issuing the following:
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 2012 Electric Rate Case — In November 2012, NSP-Minnesota filed a request with the Minnesota Public Utilities Commission (MPUC) for an increase in annual revenues of approximately $285 million, or 10.7 percent. The rate filing is based on a 2013 forecast test year, a requested return on equity (ROE) of 10.6 percent, an average electric rate base of approximately $6.3 billion and an equity ratio of 52.56 percent.
In December 2012, the MPUC accepted the filing as complete and approved the interim rates of approximately $251 million, as requested, effective Jan. 1, 2013, subject to refund.
The procedural schedule is as follows:
Prairie Island Nuclear Plant EPU — In 2009, the MPUC granted NSP-Minnesota a Certificate of Need (CON) for an EPU project at the Prairie Island nuclear generating plant. The total estimated cost of the EPU was $294 million, of which approximately $77.6 million has been incurred, including AFUDC of approximately $13.3 million. Subsequently, NSP-Minnesota filed a resource plan update and a change of circumstances (COC) filing notifying the MPUC that there were changes in the size, timing and cost estimates for this project, revisions to economic and project design analysis and changes due to the estimated impact of revised scheduled outages. The information indicated reductions to the estimated benefit of the uprate project. As a result, NSP-Minnesota concluded that further investment in this project would not benefit customers. In December 2012, the MPUC voted unanimously that no party had shown cause to prevent termination of the EPU CON. The MPUC is expected to issue an order terminating the EPU CON in early 2013.
NSP-Minnesota plans to address recovery of incurred costs in the next rate case for each of the NSP-Minnesota jurisdictions and to file a request with the FERC for approval to recover a portion of the costs from NSP-Wisconsin through the Interchange Agreement. NSP-Wisconsin plans to seek cost recovery in a future rate case. Based on the outcome of the MPUC decision, EPU costs incurred to date were compared to the discounted value of the estimated future rate recovery based on past jurisdictional precedent, resulting in a $10.1 million pretax charge in December 2012.
NSP-Minnesota – North Dakota 2012 Electric Rate Case — In December 2012, NSP-Minnesota filed a request with the North Dakota Public Service Commission (NDPSC) for an increase in annual retail electric revenues of approximately $16.9 million, or 9.25 percent. The rate filing is based on a 2013 forecast test year, a requested ROE of 10.6 percent, an electric rate base of approximately $377.6 million and an equity ratio of 52.56 percent.
In January 2013, the NDPSC approved an interim electric increase of $14.7 million, effective Feb. 16, 2013, subject to refund. A final NDPSC decision on the case is expected in the third quarter of 2013.
NSP-Minnesota – South Dakota 2012 Electric Rate Case — In June 2012, NSP-Minnesota filed a request with the South Dakota Public Utilities Commission (SDPUC) to increase electric rates by $19.4 million annually. The request was based on a 2011 historic test year adjusted for known and measurable changes for 2012 and 2013, a requested ROE of 10.65 percent, an average rate base of $367.5 million and an equity ratio of 52.89 percent.
In December 2012, the procedural schedule was suspended to allow time to construct a potential settlement agreement between NSP-Minnesota and the SDPUC Staff. Interim rates of $19.4 million went into effect on Jan. 1, 2013, subject to refund. A SDPUC decision is expected in the first half of 2013.
NSP-Wisconsin – 2012 Electric and Gas Rate Case — In June 2012, 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, 2013. NSP-Wisconsin requested an overall increase in annual electric rates of $39.1 million, or 6.7 percent, and an increase in natural gas rates of $5.3 million, or 4.9 percent.
The electric rate filing was based on a 2013 forecast test year, a ROE of 10.40 percent, an equity ratio of 52.50 percent and an average 2013 electric rate base of approximately $788.6 million. The natural gas rate request was solely due to a proposal to recover the initial costs associated with the environmental cleanup of a site in Ashland, Wis.
In December 2012, the PSCW approved an electric rate increase of approximately $35.5 million, or 6.1 percent, based on a 10.4 percent ROE and an equity ratio of 52.50 percent. The PSCW also approved a natural gas rate increase of $2.7 million, or 2.5 percent, to begin recovering costs associated with the cleanup in Ashland, Wis. Final rates were implemented on Jan. 1, 2013.
PSCo – Colorado 2012 Gas Rate Case — In December 2012, PSCo filed a multi-year request with the Colorado Public Utilities Commission (CPUC) to increase Colorado retail natural gas rates by $48.5 million in 2013 with subsequent step increases of $9.9 million in 2014 and $12.1 million in 2015. PSCo also requested to increase Colorado retail steam rates by $1.6 million in 2013 with subsequent step increases of $0.9 million in 2014 and $2.3 million in 2015. Both requests are based on a 2013 forecast test year, a 10.5 percent ROE, a rate base of $1.3 billion for natural gas and $21 million for steam and an equity ratio of 56 percent. Final rates are expected to be effective in the third quarter of 2013.
PSCo is requesting an extension of its Pipeline System Integrity Adjustment (PSIA) rider mechanism to collect the costs of accelerated pipeline integrity efforts, including system renewal projects. PSCo estimates that the PSIA will increase by $26.8 million in 2014 with a subsequent step increase of $24.7 million in 2015 in addition to the proposed changes in base rate revenue. In conjunction with the multi-year base rate step increases, PSCo is proposing a stay-out provision and an earnings test through the end of 2015.
PSCo – SmartGridCity™ (SGC) Cost Recovery — PSCo requested recovery of the revenue requirements associated with $45 million of capital and $4 million of annual O&M costs incurred to develop and operate SGC as part of its 2010 electric rate case. In February 2011, the CPUC allowed recovery of approximately $28 million of the capital cost and all of the O&M costs. In December 2011, PSCo requested CPUC approval for the recovery of the remaining capital investment in SGC and also provided the additional information requested. On Jan. 17, 2013, the ALJ recommended denial of PSCo’s request for recovery of the remaining portion of the SGC investment. Parties will have an opportunity to appeal the ALJ’s recommended decision by filing exceptions with the CPUC. If no exceptions are filed within 20 days, the recommended decision will become effective. As a result of the ALJ’s recommended decision, PSCo recognized a $10.7 million pre-tax charge in 2012, representing the net book value of the disallowed investment.
PSCo Resource Plan — In July 2012, PSCo filed two separate applications to update its resource plan. The first was an application to purchase Brush Power, LLC and all of its assets including Brush generating Units 1, 3 and 4 for a total purchase price of approximately $75 million. The Brush units currently provide 237 MW of natural gas fueled capacity and energy to PSCo under Purchased Power Agreements (PPAs) that are set to expire in 2017 for Brush Unit 1 and Brush Unit 3, and 2022 for Brush Unit 4.
The second application sought approval to retire Arapahoe Unit 4, a 109 MW coal-fired company-owned generating station at the end of 2013. This was presented as an alternative to permanently fuel switching Arapahoe Unit 4 to natural gas and instead replacing the capacity and associated energy with a natural gas PPA with an existing generator.
In September 2012, the FERC approved the acquisition of Brush Power, LLC. However, in December 2012, the CPUC denied approval of the acquisition in oral deliberations due to the risks associated with the transaction. PSCo has the ability to terminate the transaction based on the regulatory outcome. The CPUC also denied PSCo’s proposal to retire Arapahoe 4 by the end of 2013; however, this proposal could be revisited.
SPS – Texas 2012 Electric Rate Case — In November 2012, SPS filed an electric rate case in Texas with the Public Utility Commission of Texas for an increase in annual revenue of approximately $90.2 million. The rate filing is based on a historic twelve month test year ended June 30, 2012 adjusted for known and measurable changes, a requested ROE of 10.65 percent, an electric rate base of $1.15 billion and an equity ratio of 52 percent.
The procedural schedule is as follows:
SPS – New Mexico 2012 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. The rate filing is based on a 2014 forecast test year, a requested ROE of 10.65 percent, a jurisdictional electric rate base of $365.5 million and an equity ratio of 53.89 percent. A NMPRC decision is expected in the fourth quarter of 2013 with the implementation of final rates anticipated in the first quarter of 2014.
Note 5. Xcel Energy Earnings Guidance
Xcel Energy’s 2013 earnings guidance is $1.85 to $1.95 per share. Key assumptions related to 2013 earnings are detailed below:
Note 6. Non-GAAP Reconciliation
Xcel Energy’s management believes that ongoing earnings provide a meaningful comparison of earnings results and is representative of Xcel Energy’s fundamental core earnings power. 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.
The following table provides a reconciliation of ongoing earnings to GAAP earnings:
Impact of the Patient Protection and Affordable Care Act — In March 2010, the Patient Protection and Affordable Care Act was signed into law. The law includes provisions to generate tax revenue to help offset the cost of the new legislation. One of these provisions reduces the deductibility of retiree health care costs to the extent of federal subsidies received by plan sponsors that provide retiree prescription drug benefits equivalent to Medicare Part D coverage, beginning in 2013. Xcel Energy expensed approximately $17 million of previously recognized tax benefits relating to the federal subsidies during the first quarter of 2010.
In the third quarter of 2012, Xcel Energy implemented a tax strategy related to the allocation of funding of Xcel Energy’s retiree prescription drug plan. This strategy restored a portion of the tax benefit associated with federal subsidies for prescription drug plans that had been accrued since 2004 and was expensed in 2010. As a result, Xcel Energy recognized approximately $17 million of income tax benefit.
Components of Earnings per Share — Diluted
Components of Earnings per Share — Diluted
(a) See Note 6.
Xcel Energy Inc.
Paul Johnson, 612-215-4535
Vice President, Investor Relations and Financial Management
or
Jack Nielsen, 612-215-4559
Director, Investor Relations
or
Cindy Hoffman, 612-215-4536
Senior Investor Relations Analyst
or
For news media inquiries only:
Xcel Energy Media Relations, 612-215-5300
Xcel Energy internet address: www.xcelenergy.com
Source: Xcel Energy Inc.