- Third quarter GAAP diluted earnings per share were $1.19 in
2023 compared with $1.18 in 2022.
- Third quarter diluted ongoing earnings per share were $1.23 in
2023 compared with $1.18 in 2022.
- Year-to-date GAAP diluted earnings per share for 2023 were
$2.47 compared to $2.48 in 2022.
- Year-to-date diluted ongoing earnings per share for 2023 were
$2.52 compared to $2.48 in 2022.
- Xcel Energy narrows its 2023 ongoing EPS guidance to $3.32 to
$3.37 from $3.30 to $3.40 per share.
- Xcel Energy initiates 2024 EPS guidance of $3.50 to $3.60 per
share.
Xcel Energy Inc. (NASDAQ: XEL) today reported 2023 third quarter
GAAP earnings of $656 million, or $1.19 per share, compared with
$649 million, or $1.18 per share in the same period in 2022 and
ongoing earnings of $682 million, or $1.23 per share, compared with
$649 million, or $1.18 per share in the same period in 2022. See
Note 7 for reconciliation from GAAP to ongoing earnings.
Third quarter ongoing earnings results reflect the impact of
increased recovery of infrastructure investments, higher sales and
demand, lower operating and maintenance (O&M) expenses,
partially offset by increased interest charges and
depreciation.
“Xcel Energy delivered solid performance during the third
quarter,” said Bob Frenzel, chairman, president and CEO of Xcel
Energy. “As a result, we are narrowing our 2023 ongoing earnings
guidance to $3.32 to $3.37 per share and initiating 2024 guidance
of $3.50 to $3.60 per share.”
“We made significant progress on our industry-leading clean
energy transition plans. In September, we filed a proposed plan for
the largest clean energy transition effort in Colorado history. The
plan includes approximately 6,500 MW of renewable energy and
battery storage, and approximately 600 MW of natural gas resources
to ensure reliability. With the benefits of the Inflation Reduction
Act, the resources in the plan would have an annual rate impact of
approximately 2.3%.”
“In addition, in October the U.S. Department of Energy selected
the Heartland Hydrogen Hub, including multiple clean hydrogen
projects from Xcel Energy, to receive up to $925 million in federal
funding. The award will serve as a catalyst for a future hydrogen
ecosystem in the Upper Midwest,” said Frenzel. “The future is
bright for Xcel Energy, our communities, customers and
investors.”
At 9:00 a.m. CDT today, Xcel Energy will host a conference call
to review financial results. To participate in the call, please
dial in 5 to 10 minutes prior to the start and follow the
operator’s instructions.
US Dial-In:
1 (866) 580-3963
International Dial-In:
(400) 120-0558
Conference ID:
2633836
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 under Company. If you are
unable to participate in the live event, the call will be available
for replay from Oct. 27th through Oct. 30th.
Replay Numbers
US Dial-In:
1 (866) 583-1035
Access Code:
2633836#
Except for the historical statements contained in this report,
the matters discussed herein are forward-looking statements that
are subject to certain risks, uncertainties and assumptions. Such
forward-looking statements, including those relating to 2023 and
2024 EPS guidance, long-term EPS and dividend growth rate
objectives, future sales, future expenses, future tax rates, future
operating performance, estimated base capital expenditures and
financing plans, projected capital additions and forecasted annual
revenue requirements with respect to rider filings, expected rate
increases to customers, expectations and intentions regarding
regulatory proceedings, and expected impact on our results of
operations, financial condition and cash flows of resettlement
calculations and credit losses relating to certain energy
transactions, as well as assumptions and other statements are
intended to be identified in this document by the words
“anticipate,” “believe,” “could,” “estimate,” “expect,” “intend,”
“may,” “objective,” “outlook,” “plan,” “project,” “possible,”
“potential,” “should,” “will,” “would” and similar expressions.
Actual results may vary materially. Forward-looking statements
speak only as of the date they are made, and we expressly disclaim
any obligation to update any forward-looking information. The
following factors, in addition to those discussed in Xcel Energy’s
Annual Report on Form 10-K for the fiscal year ended Dec. 31, 2022
and subsequent filings with the Securities and Exchange Commission,
could cause actual results to differ materially from management
expectations as suggested by such forward-looking information:
operational safety, including our nuclear generation facilities and
other utility operations; successful long-term operational
planning; commodity risks associated with energy markets and
production; rising energy prices and fuel costs; qualified employee
work force and third-party contractor factors; violations of our
Codes of Conduct; our ability to recover costs and our
subsidiaries’ ability to recover costs from customers; changes in
regulation; reductions in our credit ratings and the cost of
maintaining certain contractual relationships; general economic
conditions, including recessionary conditions, inflation rates,
monetary fluctuations, supply chain constraints and their impact on
capital expenditures and/or the ability of Xcel Energy Inc. and its
subsidiaries to obtain financing on favorable terms; availability
or cost of capital; our customers’ and counterparties’ ability to
pay their debts to us; assumptions and costs relating to funding
our employee benefit plans and health care benefits; our
subsidiaries’ ability to make dividend payments; tax laws;
uncertainty regarding epidemics, the duration and magnitude of
business restrictions including shutdowns (domestically and
globally), the potential impact on the workforce, including
shortages of employees or third-party contractors due to quarantine
policies, vaccination requirements or government restrictions,
impacts on the transportation of goods and the generalized impact
on the economy; effects of geopolitical events, including war and
acts of terrorism; cyber security threats and data security
breaches; seasonal weather patterns; changes in environmental laws
and regulations; climate change and other weather events; natural
disaster and resource depletion, including compliance with any
accompanying legislative and regulatory changes; costs of potential
regulatory penalties and wildfire damages in excess of liability
insurance coverage; regulatory changes and/or limitations related
to the use of natural gas as an energy source; challenging labor
market conditions and our ability to attract and retain a qualified
workforce; and our ability to execute on our strategies or achieve
expectations related to environmental, social and governance
matters including as a result of evolving legal, regulatory and
other standards, processes, and assumptions, the pace of scientific
and technological developments, increased costs, the availability
of requisite financing, and changes in carbon markets.
This information is not given in connection
with any sale, offer for sale or offer to buy any security.
XCEL ENERGY INC. AND
SUBSIDIARIES
CONSOLIDATED STATEMENTS OF
INCOME (UNAUDITED)
(amounts in millions, except per
share data)
Three Months Ended Sept.
30
Nine Months Ended Sept.
30
2023
2022
2023
2022
Operating revenues
Electric
$
3,387
$
3,699
$
8,751
$
9,255
Natural gas
245
357
1,926
1,923
Other
30
26
87
79
Total operating revenues
3,662
4,082
10,764
11,257
Operating expenses
Electric fuel and purchased power
1,181
1,497
3,328
3,772
Cost of natural gas sold and
transported
70
173
1,084
1,134
Cost of sales — other
14
11
37
32
Operating and maintenance expenses
586
611
1,864
1,827
Conservation and demand side management
expenses
76
86
215
259
Depreciation and amortization
618
607
1,807
1,807
Taxes (other than income taxes)
168
173
489
523
Loss on Comanche Unit 3 litigation
34
—
34
—
Total operating expenses
2,747
3,158
8,858
9,354
Operating income
915
924
1,906
1,903
Other income (expense), net
3
(15
)
19
(20
)
Earnings from equity method
investments
7
1
27
27
Allowance for funds used during
construction — equity
26
20
63
53
Interest charges and financing
costs
Interest charges — includes other
financing costs of $8, $8, $16 and $16, respectively
269
244
790
705
Allowance for funds used during
construction — debt
(14
)
(7
)
(36
)
(19
)
Total interest charges and financing
costs
255
237
754
686
Income before income taxes
696
693
1,261
1,277
Income tax expense (benefit)
40
44
(101
)
(80
)
Net income
$
656
$
649
$
1,362
$
1,357
Weighted average common shares
outstanding:
Basic
552
548
551
546
Diluted
552
548
552
546
Earnings per average common
share:
Basic
$
1.19
$
1.19
$
2.47
$
2.48
Diluted
1.19
1.18
2.47
2.48
XCEL ENERGY INC. AND SUBSIDIARIES Notes
to Investor Relations Earnings Release (Unaudited)
Due to the seasonality of Xcel Energy’s operating results,
quarterly financial results are not an appropriate base from which
to project annual results.
Non-GAAP Financial Measures
The following discussion includes financial information prepared
in accordance with generally accepted accounting principles (GAAP),
as well as certain non-GAAP financial measures such as ongoing
return on equity (ROE), ongoing earnings and ongoing diluted EPS.
Generally, a non-GAAP financial measure is a measure of a company’s
financial performance, financial position or cash flows that
adjusts measures calculated and presented in accordance with GAAP.
Xcel Energy’s management uses non-GAAP measures for financial
planning and analysis, for reporting of results to the Board of
Directors, in determining performance-based compensation and
communicating its earnings outlook to analysts and investors.
Non-GAAP financial measures are intended to supplement investors’
understanding of our performance and should not be considered
alternatives for financial measures presented in accordance with
GAAP. These measures are discussed in more detail below and may not
be comparable to other companies’ similarly titled non-GAAP
financial measures.
Ongoing ROE
Ongoing ROE is calculated by dividing the net income or loss of
Xcel Energy or each subsidiary, adjusted for certain nonrecurring
items, by each entity’s average stockholder’s equity. We use these
non-GAAP financial measures to evaluate and provide details of
earnings results.
Earnings Adjusted for Certain Items
(Ongoing Earnings and Ongoing Diluted EPS)
GAAP diluted EPS reflects the potential dilution that could
occur if securities or other agreements to issue common stock
(i.e., common stock equivalents) were settled. The weighted average
number of potentially dilutive shares outstanding used to calculate
Xcel Energy Inc.’s diluted EPS is calculated using the treasury
stock method. Ongoing earnings reflect adjustments to GAAP earnings
(net income) for certain items. Ongoing diluted EPS for Xcel Energy
is calculated by dividing net income or loss, adjusted for certain
items, by the weighted average fully diluted Xcel Energy Inc.
common shares outstanding for the period. Ongoing diluted EPS for
each subsidiary is calculated by dividing the net income or loss
for such subsidiary, adjusted for certain items, by the weighted
average fully diluted Xcel Energy Inc. common shares outstanding
for the period.
We use these non-GAAP financial measures to evaluate and provide
details of Xcel Energy’s core earnings and underlying performance.
For instance, to present ongoing earnings and ongoing diluted
earnings per share, we may adjust the related GAAP amounts for
certain items that are non-recurring in nature. We believe these
measurements are useful to investors to evaluate the actual and
projected financial performance and contribution of our
subsidiaries. These non-GAAP financial measures should not be
considered as an alternative to measures calculated and reported in
accordance with GAAP.
Note 1. Earnings Per Share
Summary
Xcel Energy’s third quarter GAAP diluted earnings were $1.19 per
share, compared with $1.18 per share in the same period in 2022 and
ongoing diluted earnings were $1.23 per share in 2023, compared
with $1.18 per share in 2022. The increase in ongoing earnings per
share was primarily driven by increased recovery of infrastructure
investments, higher sales and demand and lower O&M expenses,
partially offset by increased interest charges and depreciation.
Fluctuations in electric and natural gas revenues associated with
changes in fuel and purchased power and/or natural gas sold and
transported generally do not significantly impact earnings (changes
in costs are offset by the related variation in revenues).
Summarized diluted EPS for Xcel Energy:
Three Months Ended Sept.
30
Nine Months Ended Sept.
30
Diluted Earnings (Loss) Per
Share
2023
2022
2023
2022
PSCo
$
0.41
$
0.45
$
0.97
$
1.02
NSP-Minnesota
0.47
0.49
0.95
0.94
SPS
0.30
0.25
0.55
0.52
NSP-Wisconsin
0.06
0.07
0.18
0.19
Earnings from equity method investments —
WYCO
0.01
0.01
0.03
0.02
Regulated utility (a)
1.25
1.28
2.68
2.69
Xcel Energy Inc. and Other
(0.06
)
(0.09
)
(0.22
)
(0.21
)
GAAP diluted EPS (a)
1.19
1.18
2.47
2.48
Loss on Comanche Unit 3 litigation (b)
0.05
—
0.05
—
Ongoing diluted EPS (a)
$
1.23
$
1.18
$
2.52
$
2.48
(a)
Amounts may not add due to rounding.
(b)
See Note 7.
PSCo — GAAP diluted earnings decreased $0.04 per share
and ongoing diluted earnings increased $0.01 per share for the
third quarter. Year-to-date GAAP diluted earnings decreased $0.05
per share and ongoing diluted earnings were flat. Year-to-date
ongoing earnings primarily reflect higher recovery of
infrastructure investment (electric and natural gas), which were
offset by increased depreciation and interest charges. See Note 7
for reconciliation from GAAP to ongoing earnings.
NSP-Minnesota — GAAP and ongoing earnings decreased $0.02
per share for the third quarter of 2023 and increased $0.01 per
share year-to-date. The year-to-date change was driven by increased
recovery of electric infrastructure investments, partially offset
by higher O&M expenses, interest charges and unfavorable
weather.
SPS — GAAP and ongoing earnings increased $0.05 per share
for the third quarter of 2023 and $0.03 year-to-date. The impact of
regulatory rate outcomes and sales growth was partially offset by
unfavorable weather, increased depreciation and interest
expenses.
NSP-Wisconsin — GAAP and ongoing earnings decreased $0.01
per share for the third quarter of 2023 and year-to-date.
Additional electric and natural gas infrastructure investment
recoveries were offset by higher depreciation, O&M expenses and
interest expenses.
Xcel Energy Inc. and Other — Primarily includes financing
costs and interest income at the holding company and earnings from
Energy Impact Partners (EIP) funds equity method investments.
Year-to-date fluctuations are largely attributable to increased
interest rates.
Components significantly contributing to changes in 2023 EPS
compared to 2022:
Diluted Earnings (Loss) Per
Share
Three Months Ended Sept.
30
Nine Months Ended Sept.
30
GAAP and ongoing diluted EPS —
2022
$
1.18
$
2.48
Components of change - 2023 vs. 2022
(Lower) higher natural gas revenues, net
of cost of natural gas sold and transported
(0.01
)
0.07
Lower conservation and demand side
management expenses (offset in electric revenues)
0.02
0.06
Higher other income (expense)
0.02
0.05
Lower taxes (other than income taxes)
0.01
0.05
Lower effective tax rate (ETR) (a)
0.01
0.03
Higher depreciation and amortization
(0.02
)
—
Higher interest charges
(0.03
)
(0.11
)
Higher (lower) electric revenues, net of
electric fuel and purchased power
0.01
(0.08
)
Lower (higher) O&M expenses
0.03
(0.05
)
Loss on Comanche Unit 3 litigation
(0.05
)
(0.05
)
Other, net
0.02
0.02
GAAP diluted EPS — 2023
1.19
2.47
Loss on Comanche Unit 3 litigation (See
Note 7)
0.05
0.05
Ongoing diluted EPS — 2023 (b)
$
1.23
$
2.52
(a)
Includes production tax credits (PTCs) and
plant regulatory amounts, which are primarily offset as a reduction
to electric revenues.
(b)
Amounts may not add due to rounding.
Note 2. Regulated Utility
Results
Estimated Impact of Temperature Changes on Regulated
Earnings — Unusually hot summers or cold winters increase
electric and natural gas sales, while mild weather reduces electric
and natural gas sales. The estimated impact of weather on earnings
is based on the number of customers, temperature variances, the
amount of natural gas or electricity historically used per degree
of temperature and excludes any incremental related operating
expenses that could result due to storm activity or vegetation
management requirements. As a result, weather deviations from
normal levels can affect Xcel Energy’s financial performance.
However, decoupling mechanisms in Colorado (mechanism expired in
September 2023) and sales true-up mechanisms in Minnesota
predominately mitigate the positive and adverse impacts of weather
for the electric utility in those jurisdictions.
Normal weather conditions are defined as either the 10, 20 or
30-year average of actual historical weather conditions. The
historical period of time used in the calculation of normal weather
differs by jurisdiction, based on regulatory practice. To calculate
the impact of weather on demand, a demand factor is applied to the
weather impact on sales. Extreme weather variations, windchill and
cloud cover may not be reflected in weather-normalized
estimates.
Weather — Estimated impact of temperature variations on
EPS compared with normal weather conditions:
Three Months Ended Sept.
30
Nine Months Ended Sept.
30
2023 vs. Normal
2022 vs. Normal
2023 vs. 2022
2023 vs. Normal
2022 vs. Normal
2023 vs. 2022
Retail electric
$
0.032
$
0.074
$
(0.042
)
$
0.035
$
0.123
$
(0.088
)
Decoupling and sales true-up
0.007
(0.032
)
0.039
(0.015
)
(0.055
)
0.040
Electric total
$
0.039
$
0.042
$
(0.003
)
$
0.020
$
0.068
$
(0.048
)
Firm natural gas
(0.002
)
—
(0.002
)
0.024
0.019
0.005
Decoupling
$
0.001
$
—
$
0.001
$
0.001
$
—
$
0.001
Gas total
$
(0.001
)
$
—
$
(0.001
)
$
0.025
$
0.019
$
0.006
Total
$
0.038
$
0.042
$
(0.004
)
$
0.045
$
0.087
$
(0.042
)
Sales — Sales growth (decline) for actual and
weather-normalized sales in 2023 compared to 2022:
Three Months Ended Sept.
30
PSCo
NSP-Minnesota
SPS
NSP-Wisconsin
Xcel Energy
Actual
Electric residential
(5.9
)%
0.7
%
3.6
%
0.3
%
(1.4
)%
Electric C&I
(2.0
)
(1.6
)
6.5
(2.3
)
0.5
Total retail electric sales
(3.4
)
(0.8
)
5.7
(1.6
)
(0.1
)
Firm natural gas sales
1.3
—
N/A
(3.2
)
0.6
Three Months Ended Sept.
30
PSCo
NSP-Minnesota
SPS
NSP-Wisconsin
Xcel Energy
Weather-Normalized
Electric residential
5.6
%
2.6
%
1.8
%
0.4
%
3.4
%
Electric C&I
1.7
(1.8
)
6.0
(2.5
)
1.3
Total retail electric sales
3.0
(0.4
)
4.9
(1.7
)
1.9
Firm natural gas sales
2.4
3.0
N/A
0.3
2.5
Nine Months Ended Sept.
30
PSCo
NSP-Minnesota
SPS
NSP-Wisconsin
Xcel Energy
Actual
Electric residential
(4.4
)%
(0.1
)%
(3.3
)%
(2.6
)%
(2.4
)%
Electric C&I
(2.1
)
(0.7
)
5.5
(0.3
)
0.7
Total retail electric sales
(2.9
)
(0.5
)
3.8
(1.0
)
(0.2
)
Firm natural gas sales
4.9
(10.7
)
N/A
(12.7
)
(1.6
)
Nine Months Ended Sept.
30
PSCo
NSP-Minnesota
SPS
NSP-Wisconsin
Xcel Energy
Weather-Normalized
Electric residential
1.4
%
0.6
%
0.9
%
(0.5
)%
0.8
%
Electric C&I
(0.2
)
(0.9
)
5.7
(0.2
)
1.2
Total retail electric sales
0.3
(0.4
)
4.7
(0.3
)
1.1
Firm natural gas sales
1.6
(1.4
)
N/A
(1.9
)
0.4
Weather-normalized electric sales growth
(decline) — year-to-date
- PSCo — Residential sales increased due to a 1.3% increase in
customers. The C&I sales decline was related to decreased use
per customer, primarily in the manufacturing and agricultural
sectors.
- NSP-Minnesota — Residential sales increased due to a 1.1%
increase in customers, partially offset by a decreased use per
customer. C&I sales declined due to decreased use per customer,
due to general economic conditions.
- SPS — Residential sales growth was primarily attributable to a
0.7% increase in customers and increased use per customer. C&I
sales increased due to higher use per customer, primarily driven by
the energy sector.
- NSP-Wisconsin — Residential sales declined due to decreased use
per customer, offset by a 0.7% increase in customers. C&I sales
decline was associated with decreased use per customer, experienced
largely in the manufacturing sector.
Weather-normalized natural gas sales
growth (decline) — year-to-date
- Natural gas sales reflect a lower use per residential customer
in all jurisdictions, partially offset by an increase in C&I
use per customer in PSCo. In addition, residential and C&I
customer growth was 1.2% and 0.7%, respectively.
Electric Margin — Electric margin is presented as
electric revenues less electric fuel and purchased power expenses.
Expenses incurred for electric fuel and purchased power are
generally recovered through various regulatory recovery mechanisms.
As a result, changes in these expenses are generally offset in
operating revenues.
Electric revenues and fuel and purchased power expenses are
impacted by fluctuations in the price of natural gas, coal and
uranium. However, these price fluctuations generally have minimal
earnings impact due to fuel recovery mechanisms. In addition,
electric customers receive a credit for PTCs generated, which
reduce electric revenue and income taxes.
Electric revenues, fuel and purchased power and margin:
Three Months Ended Sept.
30
Nine Months Ended Sept.
30
(Millions of Dollars)
2023
2022
2023
2022
Electric revenues
$
3,387
$
3,699
$
8,751
$
9,255
Electric fuel and purchased power
(1,181
)
(1,497
)
(3,328
)
(3,772
)
Electric margin
$
2,206
$
2,202
$
5,423
$
5,483
(Millions of Dollars)
Three Months Ended Sept. 30,
2023 vs. 2022
Nine Months Ended Sept. 30,
2023 vs. 2022
Revenue recognition for the Texas rate
case surcharge (a)
$
—
$
(85
)
Conservation and demand side management
(offset in expense)
(14
)
(48
)
Estimated impact of weather (net of
decoupling/sales true-up)
(2
)
(34
)
PTCs flowed back to customers (offset by
lower ETR)
(10
)
(33
)
Non-fuel riders
39
70
Sales and demand (b)
18
38
Wholesale transmission (net)
(8
)
15
Regulatory rate outcomes (Minnesota,
Colorado, Texas, New Mexico, Wisconsin, South Dakota and
Michigan)
1
13
Other (net)
(20
)
4
Total increase (decrease)
$
4
$
(60
)
(a)
The decline in electric margin is due to
the recognition of the Texas rate case outcome in the second
quarter of 2022, which was largely offset by recognition of
previously deferred costs.
(b)
Sales excludes weather impact, net of
partial decoupling in Colorado (mechanism expired in September) and
sales true-up mechanism in Minnesota.
Natural Gas Margin — Natural gas margin is presented as
natural gas revenues less the cost of natural gas sold and
transported. Expenses incurred for the cost of natural gas sold are
generally recovered through various regulatory recovery mechanisms.
As a result, changes in these expenses are generally offset in
operating revenues.
Natural gas expense varies with changing sales and the cost of
natural gas. However, fluctuations in the cost of natural gas
generally have minimal earnings impact due to cost recovery
mechanisms.
Natural gas revenues, cost of natural gas sold and transported
and margin:
Three Months Ended Sept.
30
Nine Months Ended Sept.
30
(Millions of Dollars)
2023
2022
2023
2022
Natural gas revenues
$
245
$
357
$
1,926
$
1,923
Cost of natural gas sold and
transported
(70
)
(173
)
(1,084
)
(1,134
)
Natural gas margin
$
175
$
184
$
842
$
789
(Millions of Dollars)
Three Months Ended Sept. 30,
2023 vs. 2022
Nine Months Ended Sept. 30,
2023 vs. 2022
Regulatory rate outcomes (Colorado and
Wisconsin)
$
—
$
49
Estimated impact of weather (net of
decoupling)
—
5
Other (net)
(9
)
(1
)
Total (decrease) increase
$
(9
)
$
53
O&M Expenses — O&M expenses decreased $25 million
for the third quarter and increased $37 million year-to-date. The
year-to-date increase was primarily due to higher bad debt
expenses; the impact of inflationary pressures, including labor
increases and insurance, and unplanned maintenance at generating
plants, offset by the change in deferred costs associated with the
Texas Electric Rate Cases (offset in electric revenues) and impact
of management cost containment actions.
Depreciation and Amortization — Depreciation and
amortization increased $11 million for the third quarter and was
flat year-to-date. Year-to-date activity is related to system
expansion, offset by the recognition of previously deferred
depreciation costs associated with the Texas Electric Rate Case in
2022 (approximately $40 million) and depreciation life extensions
implemented in the Minnesota Electric Rate Case.
Taxes (other than Income Taxes) — Taxes decreased $5
million for the third quarter and $34 million year-to-date,
primarily due to deferrals related to the Minnesota Electric Rate
Case and the recognition of previously deferred costs associated
with the Texas Electric Rate Case in 2022, partially offset by an
increase in Colorado property tax expense.
Other Income (Expense) — Other income (expense) increased
$18 million for the third quarter and $39 million year-to-date,
largely related to interest earned on cash balances and rabbi trust
performance, which is partially offset in O&M expenses
(employee benefit costs).
Interest Charges — Interest charges increased $25 million
for the third quarter and $85 million year-to-date, largely due to
higher interest rates and increased long-term debt levels,
partially offset by the recognition of previously deferred costs
associated with the Texas Electric Rate Case in 2022.
Income Taxes — Effective income tax rate:
Three Months Ended Sept.
30
Nine Months Ended Sept.
30
2023
2022
2023 vs. 2022
2023
2022
2023 vs. 2022
Federal statutory rate
21.0
%
21.0
%
—
%
21.0
%
21.0
%
—
%
State tax (net of federal tax effect)
5.0
4.9
0.1
4.9
4.9
—
(Decreases) increases:
Wind PTCs (a)
(13.8
)
(12.3
)
(1.5
)
(27.3
)
(25.2
)
(2.1
)
Plant regulatory differences (b)
(5.3
)
(5.8
)
0.5
(5.5
)
(5.5
)
—
Other tax credits, net operating loss
& tax credits allowances
(1.1
)
(1.2
)
0.1
(1.2
)
(1.4
)
0.2
Other (net)
(0.1
)
(0.3
)
0.2
0.1
(0.1
)
0.2
Effective income tax rate
5.7
%
6.3
%
(0.6
)%
(8.0
)%
(6.3
)%
(1.7
)%
(a)
Wind PTCs are credited to customers
(reduction to revenue) and do not materially impact earnings.
(b)
Plant regulatory differences primarily
relate to the credit of excess deferred taxes to customers through
the average rate assumption method. Income tax benefits associated
with the credit are offset by corresponding revenue reductions.
Note 3. Capital Structure, Liquidity,
Financing and Credit Ratings
Xcel Energy’s capital structure:
(Millions of Dollars)
Sept. 30, 2023
Percentage of Total
Capitalization
Dec. 31, 2022
Percentage of Total
Capitalization
Current portion of long-term debt
$
1,051
2
%
$
1,151
3
%
Short-term debt
—
—
813
2
Long-term debt
24,910
58
22,813
55
Total debt
25,961
60
24,777
60
Common equity
17,309
40
16,675
40
Total capitalization
$
43,270
100
%
$
41,452
100
%
Liquidity — As of Oct. 23, 2023, Xcel Energy Inc. and its
utility subsidiaries had the following committed credit facilities
available to meet liquidity needs:
(Millions of Dollars)
Credit Facility (a)
Drawn (b)
Available
Cash
Liquidity
Xcel Energy Inc.
$
1,500
$
—
$
1,500
$
19
$
1,519
PSCo
700
239
461
3
464
NSP-Minnesota
700
15
685
8
693
SPS
500
—
500
18
518
NSP-Wisconsin
150
—
150
8
158
Total
$
3,550
$
254
$
3,296
$
56
$
3,352
(a)
Expires September 2027.
(b)
Includes outstanding commercial paper and
letters of credit.
Credit Ratings — Access to the capital markets at
reasonable terms is partially dependent on credit ratings. The
following ratings reflect the views of Moody’s, S&P Global
Ratings and Fitch. The highest credit rating for debt is Aaa/AAA
and the lowest investment grade rating is Baa3/BBB-. The highest
rating for commercial paper is P-1/A-1/F-1 and the lowest rating is
P-3/A-3/F-3. A security rating is not a recommendation to buy, sell
or hold securities. Ratings are subject to revision or withdrawal
at any time by the credit rating agency and each rating should be
evaluated independently of any other rating.
Credit ratings assigned to Xcel Energy Inc. and its utility
subsidiaries as of Oct. 23, 2023:
Credit Type
Company
Moody’s
S&P Global Ratings
Fitch
Senior unsecured debt
Xcel Energy Inc.
Baa1
BBB+
BBB+
Senior secured debt
NSP-Minnesota
Aa3
A+
A+
NSP-Wisconsin
Aa3
A
A+
PSCo
A1
A
A+
SPS
A3
A
A-
Commercial paper
Xcel Energy Inc.
P-2
A-2
F2
NSP-Minnesota
P-1
A-1
F2
NSP-Wisconsin
P-1
A-2
F2
PSCo
P-2
A-2
F2
SPS
P-2
A-2
F2
Capital Expenditures — Base capital expenditures and
incremental capital forecasts for Xcel Energy for 2024 through
2028:
Base Capital Forecast
(Millions of Dollars)
By Regulated Utility
2024
2025
2026
2027
2028
Total
PSCo
$
2,580
$
2,940
$
3,030
$
3,070
$
2,640
$
14,260
NSP-Minnesota
2,660
2,970
2,380
2,500
2,180
12,690
SPS
910
780
660
870
830
4,050
NSP-Wisconsin
570
600
570
600
650
2,990
Other (a)
(20
)
—
10
10
10
10
Total base capital expenditures
$
6,700
$
7,290
$
6,650
$
7,050
$
6,310
$
34,000
(a)
Other category includes intercompany
transfers for safe harbor wind turbines.
Base Capital Forecast
(Millions of Dollars)
By Function
2024
2025
2026
2027
2028
Total
Electric transmission
$
1,880
$
2,150
$
2,500
$
2,840
$
2,080
$
11,450
Electric distribution
1,720
1,840
2,030
2,200
2,410
10,200
Electric generation
930
1,160
780
740
600
4,210
Natural gas
740
680
630
620
570
3,240
Renewables
670
740
40
20
20
1,490
Other
760
720
670
630
630
3,410
Total base capital expenditures
$
6,700
$
7,290
$
6,650
$
7,050
$
6,310
$
34,000
The base plan does not include any potential renewable
generation assets associated with the Colorado recommended
Preferred Plan (pending CPUC approval) and potential renewable
generation additions at the NSP System and SPS, which could result
in additional capital expenditures of approximately $10 billion.
Xcel Energy generally expects to fund additional capital investment
with approximately 40% equity and 60% debt.
Xcel Energy’s capital expenditure forecast is subject to
continuing review and modification. Actual capital expenditures may
vary from estimates due to changes in electric and natural gas
projected load growth, safety and reliability needs, regulatory
decisions, legislative initiatives (e.g., federal clean energy and
tax policy), reserve requirements, availability of purchased power,
alternative plans for meeting long-term energy needs, environmental
initiatives and regulation, and merger, acquisition and divestiture
opportunities.
Financing for Capital Expenditures through 2028 — 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. Current estimated financing plans of
Xcel Energy for 2024 through 2028 (includes the impact of tax
credit transferability):
(Millions of Dollars)
Funding Capital Expenditures
Cash from operations (a)
$
20,520
New debt (b)
10,980
Equity through the Dividend Reinvestment
and Stock Purchase Program (DRIP) and benefit program
500
Other equity
2,000
Base capital expenditures 2024-2028
$
34,000
Maturing debt
$
3,780
(a)
Net of dividends and pension funding.
(b)
Reflects a combination of short and
long-term debt; net of refinancing.
2023 Financing Activity — During 2023, Xcel Energy plans
to issue approximately $85 million of equity through the DRIP and
benefit programs. In addition, we issued approximately $62 million
of equity under the ATM program in the first nine months of 2023.
Xcel Energy and its utility subsidiaries issued the following
long-term debt:
Issuer
Security
Amount (in millions)
Status
Tenor
Coupon
Xcel Energy
Unsecured Senior Notes
$
800
Completed
10 Year
5.45
%
PSCo
First Mortgage Bonds
850
Completed
30 Year
5.25
NSP-Minnesota
First Mortgage Bonds
800
Completed
30 Year
5.10
NSP-Wisconsin
First Mortgage Bonds
125
Completed
30 Year
5.30
SPS
First Mortgage Bonds
100
Completed
30 Year
6.00
Financing plans are subject to change, depending on regulatory
outcomes, capital expenditures, tax credit transferability market,
legislative initiatives, internal cash generation, market
conditions and other factors.
Note 4. Rates, Regulation and
Other
NSP-Minnesota — 2022 Minnesota Electric Rate Case
— In October 2021, NSP-Minnesota filed a three-year electric rate
case with the Minnesota Public Utilities Commission (MPUC). The
rate request was based on a ROE of 10.2%, a 52.5% equity ratio and
forward test years. In December 2021, the MPUC approved interim
rates, subject to refund, of $247 million, effective Jan. 1, 2022.
In November 2022, NSP-Minnesota revised its rate request to $498
million over three years.
In July 2023, the MPUC approved a three-year rate increase of
approximately $316 million for 2022-2024, based on a ROE of 9.25%
and an equity ratio of 52.5%. The MPUC also approved a continuation
of the sales true-up mechanism.
In October 2023, the MPUC denied NSP-Minnesota’s request for
reconsideration of certain aspects of the decision. NSP-Minnesota
plans to file an appeal of the decision to the Minnesota Court of
Appeals in November 2023.
NSP-Minnesota — 2024 Minnesota Natural Gas Rate
Case — NSP-Minnesota plans to file a request with the MPUC for
an annual natural gas rate case in November 2023.
NSP-Wisconsin — Wisconsin Rate Case — In April
2023, NSP-Wisconsin filed a Wisconsin rate case seeking an electric
increase of $40 million (rate increase of 4.8%) and a natural gas
increase of $9 million (rate increase of 5.3%). The rate filing is
based on a 2024 forecast test year, a ROE of 10.25%, an equity
ratio of 52.5% and a forecasted average net rate base of
approximately $2.1 billion for the electric utility and $284
million for the natural gas utility.
On Sept. 1, 2023, the Public Service Commission of Wisconsin
(PSCW) Staff recommended an electric base rate decrease of $3
million or (0.3)% when including depreciation, fuel and purchased
power adjustments and a natural gas rate increase of $5 million, or
3.1%. The recommendation was based on a ROE of 9.7% and an equity
ratio of 52.5%.
In September 2023, NSP-Wisconsin filed rebuttal testimony and
updated its request for depreciation life extensions and other
updates. NSP-Wisconsin revised its requested rate increase to $25
million for the electric utility and $7 million for the natural gas
utility. NSP-Wisconsin will update forecasted fuel costs before the
Commission decision. Prudently incurred 2024 fuel costs will be
trued up to actuals in a fuel reconciliation process, subject to a
2% band.
A PSCW decision is anticipated late fourth quarter 2023 with new
rates effective in January 2024.
PSCo — Electric Rate Case — In November 2022, PSCo
filed a Colorado electric rate case seeking a net increase of $262
million, or 8.2%. The total request reflects a $312 million
increase (subsequently adjusted to $303 million in rebuttal), which
includes $50 million of authorized costs previously recovered
through various rider mechanisms. The request was based on a 10.25%
ROE, an equity ratio of 55.7% and a 2023 forecast test year with a
2023 average rate base of $11.3 billion.
In September 2023, the Colorado Public Utility Commission (CPUC)
approved a settlement between PSCo and various parties, which
included the following terms:
- Retail revenue increase (excluding rider roll-ins) of $95
million (increase of 2.96%), based on a 2022 historic test year
using year-end rate base with forward looking known and measurable
adjustments.
- Weighted-average cost of capital of 6.95% (based on 55.69%
equity ratio and 9.3% ROE).
- Termination of the revenue decoupling pilot with implementation
of new rates.
- Continuation of previously authorized trackers and
deferrals.
- Collection of PSCo’s requested 2023 TCA revenues, previously
suspended by the CPUC. Beginning in 2024, projects eligible for
recovery will be limited to projects which increase transmission
capacity or are part of an approved wildfire mitigation plan.
Rates became effective in September 2023.
PSCo — Colorado Resource Plan — In August 2022,
the CPUC approved a settlement for the Colorado Resource Plan among
PSCo and various intervenors. This settlement provides for an
expected carbon reduction and the retirement of PSCo’s remaining
coal plant by the end of 2030.
In September 2023, PSCo filed its recommended Preferred Plan.
The filing also includes several other alternative scenarios.
PSCo’s Preferred Plan results in the exit of coal by the end of
2030, roughly doubling wind and solar energy from 2022 levels, and
reduction of greenhouse gas emissions by more than 80% from 2005
levels. It also reflects an average annual rate impact of
approximately 2.3% which is inclusive of generation and
transmission network and interconnection costs.
The Preferred Plan includes the following resources:
Generation Resource (in
MW)
Company Owned
PPAs
Total
Wind Resources
2,531
875
3,406
Solar
1,109
860
1,969
Storage
500
670
1,170
Natural Gas
628
—
628
Biomass
19
—
19
Total
4,787
2,405
7,192
If approved by the CPUC, Xcel Energy expects to invest $7.9
billion in generation resources. In addition, the plan requires
approximately $2.9 billion of incremental investments in
transmission capacity upgrades and new lines to fully integrate the
renewable generation.
The CPUC is expected to render a decision on the recommended
Preferred Plan by the end of 2023 or in early 2024.
SPS — 2022 New Mexico Electric Rate Case — In
November 2022, SPS filed a New Mexico electric rate case seeking a
revenue increase of $78 million, or 10%. In May 2023, SPS revised
its request to $75 million. The request is based on a ROE of
10.75%, an equity ratio of 54.7%, a future test year ending June
30, 2024, rate base of $2.4 billion and acceleration of the Tolk
coal plant depreciation life from 2032 to 2028.
In October 2023, the NMPRC approved a settlement between SPS,
New Mexico Public Regulation Commission (NMPRC) Staff, and various
parties, which included the following terms:
- Base rate revenue increase of $33 million, based on the filed
future test year.
- ROE of 9.5%.
- Equity ratio of 54.7%.
- Acceleration of Tolk coal plant depreciation life to 2028.
Rates went into effect in October 2023.
SPS — 2023 Texas Electric Rate Case — In February
2023, SPS filed a Texas electric rate case seeking an increase in
base rate revenue of $149 million (13%). In March 2023, SPS updated
the filing, which increased the rate revenue request to $158
million (14% impact to customer bills). The request is based on a
ROE of 10.65%, an equity ratio of 54.6% and retail rate base of
$3.6 billion. Additionally, the request reflects the acceleration
of the Tolk coal plant depreciation life from 2034 to 2028. SPS is
requesting a surcharge from July 13, 2023 through the effective
date of new base rates.
In September 2023, SPS and various parties reached a settlement
in principle regarding the overall revenue requirement and key
terms. The parties are still completing cost allocation and rate
design settlement details and will file the settlement assuming
finalization of remaining issues.
A PUCT decision is expected in the first quarter of 2024.
SPS New Mexico Resource Plan — In October 2023, SPS filed
its Integrated Resource Plan (IRP) with the NMPRC, which supports
projected load growth and secures replacement energy and capacity
for retiring resources. SPS presented three load forecasts ranging
from a low load growth scenario to a high load growth forecast (the
“Electrification Forecast”). Based on these forecast scenarios,
SPS’ initial IRP modeling projects a total resource need ranging
from approximately 5,300 MW to 10,200 MW by 2030. Upon acceptance
of the IRP, SPS expects to issue an RFP for new generation in
mid-2024. The RFP will be evaluated in the latter half of 2024 with
project selection expected in early 2025.
Note 5. New Technology and Government
Grants
Hydrogen Hub Grant — In October 2023, the U.S. Department
of Energy (DOE) selected the Heartland Hydrogen Hub, including
multiple clean hydrogen projects from Xcel Energy, for award
negotiations to receive up to $925 million. The Heartland Hydrogen
Hub is one of seven selected to receive DOE funding. The hub
includes Xcel Energy, Marathon Petroleum Corporation and TC Energy,
in collaboration with the University of North Dakota’s Energy &
Environmental Resource Center, to produce and use low-carbon
hydrogen at commercial scale in Minnesota, Wisconsin, South Dakota,
North Dakota and Montana. The hub aims to reduce carbon emissions
by more than 1 million metric tons per year. Xcel Energy expects to
receive a large portion of the federal award for its projects
within the hub, subject to negotiations. In its application, Xcel
Energy proposed investing approximately $2 billion over a decade
for clean hydrogen producing equipment and infrastructure. Project
detailed design will begin after the Heartland Hydrogen Hub
finishes award negotiations. Project development will likely
continue through 2035.
Form Energy Long Duration Storage Grant — In September
2023, the DOE awarded Xcel Energy a $70 million grant to support
our two 10 MW, 100-hour battery pilots with Form Energy. Xcel
Energy expects to develop a 10 MW 100-hour-battery storage unit at
the Sherco retiring coal plant site in Minnesota and the Comanche
retiring coal plant site in Colorado. Combined with grants from
Breakthrough Energy’s Catalyst Fund, Xcel Energy has secured $90
million to support these pilots, which will reduce the costs of the
projects for our customers. Long duration energy storage systems
are critical to achieve 100% carbon free generation and strengthen
the grid from the variability of renewable energy.
Wildfire/Extreme Weather Grant — In October 2023, the DOE
awarded Xcel Energy $100 million to support projects to mitigate
the threat of wildfires and ensure resiliency of the grid through
extreme weather. Xcel Energy plans to match the grant with $140
million of investment. The projects will take a number of steps to
boost grid resiliency, including adding fire-resistant coatings to
6,000 wood poles, improving equipment safety features in power
lines and electric vehicle chargers in high fire risk conditions,
moving high-risk distribution circuits underground, and enhancing
vegetation management. They will also build on current programs
using emerging technology, such as drones aided by artificial
intelligence that inspect power lines for safety, wind strength
testing, satellite identification of trees that pose a risk and
modeling software to predict how fires would spread.
Joint Target Interconnection Queue (JTIQ) Grant — In
October 2023, the DOE awarded a $464 million grant to Xcel Energy
and several other utilities for five JTIQ projects. The projects
are part of a collaboration between MISO and SPP that will help to
fund the construction of high-voltage transmission lines that
improve reliability and resolve constraints in the transmission
system for up to 30 gigawatts of new generation. Xcel Energy is
part of two of these project awards.
Note 6. Significant
Litigation
Marshall Wildfire Litigation — In December 2021, a
wildfire ignited in Boulder County, Colorado (the “Marshall Fire”),
which burned over 6,000 acres and destroyed or damaged over 1,000
structures. On June 8, 2023, the Boulder County Sheriff’s Office
released its Marshall Fire Investigative Summary and Review and its
supporting documents (the “Sheriff’s Report”). According to an
October 2022 statement from the Colorado Insurance Commissioner,
the Marshall Fire is estimated to have caused more than $2 billion
in property losses.
According to the Sheriff’s Report, on Dec. 30, 2021, a fire
ignited on a residential property in Boulder, Colorado, located in
PSCo’s service territory, for reasons unrelated to PSCo’s power
lines. According to the Sheriff’s Report, approximately one hour
and 20 minutes after the first ignition, a second fire ignited just
south of the Marshall Mesa Trailhead in unincorporated Boulder
County, Colorado, also located in PSCo’s service territory.
According to the Sheriff’s Report, the second ignition started
approximately 80 to 110 feet away from PSCo’s power lines in the
area.
The Sheriff’s Report states that the most probable cause of the
second ignition was hot particles discharged from PSCo’s power
lines after one of the power lines detached from its insulator in
strong winds, and further states that it cannot be ruled out that
the second ignition was caused by an underground coal fire.
According to the Sheriff’s Report, no design, installation or
maintenance defects or deficiencies were identified on PSCo’s
electrical circuit in the area of the second ignition. PSCo
disputes that its power lines caused the second ignition.
As of Oct. 24, 2023, PSCo is aware of 14 complaints, certain of
which have also named Xcel Energy Inc. as a defendant, on behalf of
at least 675 plaintiffs relating to the Marshall Fire and expects
that it may receive further complaints. The complaints generally
allege that PSCo’s equipment ignited the Marshall Fire and assert
various causes of action under Colorado law, including negligence,
premises liability, trespass, nuisance, and inverse condemnation.
In September 2023, the Boulder County District Court Judge
consolidated eight lawsuits that were pending at that time into a
single action for pretrial purposes and has subsequently
consolidated additional lawsuits that have been filed.
Colorado courts do not apply strict liability in determining an
electric utility company’s liability for fire-related damages. For
inverse condemnation claims, Colorado courts assess whether a
defendant acted with intent to take a plaintiff’s property or
intentionally took an action which has the natural consequence of
taking the property. For negligence claims, Colorado courts look to
whether electric power companies have operated their system with a
heightened duty of care consistent with the practical conduct of
its business, and liability does not extend to occurrences that
cannot be reasonably anticipated.
Under Colorado law, in a civil action other than a medical
malpractice action, the total award for noneconomic loss is capped
at $0.6 million per defendant for claims that accrued at the time
of the Marshall Fire unless the court finds justification to exceed
that amount by clear and convincing evidence, in which case the
maximum doubles. Colorado law does not impose joint and several
liability in tort actions. Instead, under Colorado law, a defendant
is liable for the degree or percentage of the negligence or fault
attributable to that defendant, except where the defendant
conspired with another defendant. A jury’s verdict in a Colorado
civil case must be unanimous.
Colorado law caps punitive or exemplary damages to an amount
equal to the amount of the actual damages awarded to the injured
party, except the court may increase any award of punitive damages
to a sum up to three times the amount of actual damages if the
conduct that is the subject of the claim has continued during the
pendency of the case or the defendant has acted in a willful and
wanton manner during the action which further aggravated
plaintiff’s damages.
In the event Xcel Energy Inc. or PSCo was found liable related
to this litigation and were required to pay damages, such amounts
could exceed our insurance coverage of approximately $500 million
and have a material adverse effect on our financial condition,
results of operations or cash flows. However, due to uncertainty as
to the cause of the fire and the extent and magnitude of potential
damages, Xcel Energy Inc. and PSCo are unable to estimate the
amount or range of possible losses in connection with the Marshall
Fire.
Comanche Unit 3 Litigation — In 2021, CORE Electric
Cooperative (CORE) filed a lawsuit in Denver County District Court,
alleging PSCo breached ownership agreement terms by failing to
operate Comanche Unit 3 in accordance with prudent utility
practices. In April 2022, CORE filed a supplement to include
damages related to a 2022 outage. Also in 2022, CORE sent notice of
withdrawal from the ownership agreement based on the same alleged
breaches.
In February 2023, the court granted PSCo’s motion precluding
CORE from seeking damages related to its withdrawal as part of the
lawsuit. In September 2023, the court denied PSCo’s motion for
summary judgment on other categories of damages and allowed CORE to
seek approximately $253 million at trial (before interest),
including an alleged $187 million reduction in the value of CORE’s
ownership interest in the Comanche 3 facility and $60 million of
alleged lost power costs.
On Oct. 25, 2023, the jury awarded CORE lost power damages of
$26 million. PSCo recognized $34 million for the verdict in the
third quarter of 2023, including estimated interest and other
costs. PSCo intends to file an appeal of this decision.
Note 7. Non-GAAP
Reconciliation
Xcel Energy’s reported earnings are prepared in accordance with
GAAP. Xcel Energy’s management believes that ongoing earnings, or
GAAP earnings adjusted for certain items, reflect management’s
performance in operating the company and provides a meaningful
representation of the underlying performance of Xcel Energy’s core
business. In addition, Xcel Energy’s management uses ongoing
earnings internally for financial planning and analysis, for
reporting of results to the Board of Directors and when
communicating its earnings outlook to analysts and investors. This
non-GAAP financial measure should not be considered as an
alternative to measures calculated and reported in accordance with
GAAP.
Earnings Adjusted for Certain Items (Ongoing
Earnings)
The following table provides a reconciliation of GAAP earnings
(net income) to ongoing earnings:
Three Months Ended Sept.
30
Nine Months Ended Sept.
30
(Millions of Dollars)
2023
2022
2023
2022
GAAP net income
$
656
$
649
$
1,362
$
1,357
Loss on Comanche Unit 3 Litigation
34
—
34
—
Less: tax effect of adjustment
(8
)
—
(8
)
—
Ongoing earnings
$
682
$
649
$
1,388
$
1,357
Comanche Unit 3 Litigation — As a result of an Oct. 25,
2023 jury verdict in Denver County District Court awarding CORE
lost power damages and other costs, PSCo recognized a $34 million
loss for the matter in the third quarter of 2023. Given the
non-recurring nature of this specific item, it has been excluded
from ongoing earnings. See Note 6.
Note 8. Earnings Guidance and Long-Term
EPS and Dividend Growth Rate Objectives
Xcel Energy 2023 Earnings Guidance — Xcel Energy’s 2023
ongoing earnings guidance is a narrowed range of $3.32 to $3.37 per
share, from the original guidance of $3.30 to $3.40 per
share.(a)
Key assumptions as compared with 2022 levels unless noted:
- Constructive outcomes in all pending rate case and regulatory
proceedings.
- Normal weather patterns for the remainder of the year.
- Weather-normalized retail electric sales are projected to
increase ~1% to 2%.
- Weather-normalized retail firm natural gas sales are projected
to increase ~1%.
- Capital rider revenue is projected to increase $40 million to
$50 million (net of PTCs).
- O&M expenses are projected to decline ~1% to 2%.
- Depreciation expense is projected to increase approximately $25
million to $35 million.
- Property taxes are projected to decrease $30 million to $35
million.
- Interest expense (net of AFUDC - debt) is projected to increase
$90 million to $100 million.
- AFUDC - equity is projected to increase $10 million to $15
million.
- ETR is projected to be ~(9%) to (11%). The negative ETR is
largely offset by PTCs flowing back to customers in the capital
riders and fuel mechanisms and is largely earnings neutral.
Xcel Energy 2024 Earnings Guidance — Xcel Energy’s 2024
ongoing earnings guidance is a range of $3.50 to $3.60 per
share.(a)
Key assumptions as compared with 2023 projected levels unless
noted:
- Constructive outcomes in all pending rate case and regulatory
proceedings.
- Normal weather patterns for the year.
- Weather-normalized retail electric sales are projected to
increase 2% to 3%.
- Weather-normalized retail firm natural gas sales are projected
to increase ~1%.
- Capital rider revenue is projected to increase $35 million to
$45 million (net of PTCs).
- O&M expenses are projected to increase 1% to 2%.
- Depreciation expense is projected to increase approximately
$250 million to $260 million.
- Property taxes are projected to increase $40 million to $50
million.
- Interest expense (net of AFUDC - debt) is projected to increase
$115 million to $125 million.
- AFUDC - equity is projected to increase $40 million to $50
million.
- ETR is projected to be ~(4%) to (6%). The negative ETR is
largely offset by PTCs flowing back to customers in the capital
riders and fuel mechanisms and is largely earnings neutral.
(a)
Ongoing earnings is calculated using net
income and adjusting for certain nonrecurring or infrequent items
that are, in management’s view, not reflective of ongoing
operations. Ongoing earnings could differ from those prepared in
accordance with GAAP for unplanned and/or unknown adjustments. As
Xcel Energy is unable to quantify the financial impacts of any
additional adjustments that may occur for the year, we are unable
to provide a quantitative reconciliation of the guidance for
ongoing EPS to corresponding GAAP EPS.
Long-Term EPS and Dividend Growth Rate Objectives — Xcel
Energy expects to deliver an attractive total return to our
shareholders through a combination of earnings growth and dividend
yield, based on the following long-term objectives:
- Deliver long-term annual EPS growth of 5% to 7% based off of a
2023 base of $3.35 per share, which represents the mid-point of the
original 2023 guidance range of $3.30 to $3.40 per share.
- Deliver annual dividend increases of 5% to 7%.
- Target a dividend payout ratio of 60% to 70%.
- Maintain senior secured debt credit ratings in the A
range.
XCEL ENERGY INC. AND
SUBSIDIARIES
EARNINGS RELEASE SUMMARY
(UNAUDITED)
(amounts in millions, except per
share data)
Three Months Ended Sept.
30
2023
2022
Operating revenues:
Electric and natural gas
$
3,632
$
4,056
Other
30
26
Total operating revenues
3,662
4,082
Net income
$
656
$
649
Weighted average diluted common shares
outstanding
552
548
Components of EPS —
Diluted
Regulated utility
$
1.25
$
1.28
Xcel Energy Inc. and other costs
(0.06
)
(0.09
)
GAAP diluted EPS (a)
1.19
1.18
Loss on Comanche Unit 3 litigation (See
Note 7)
0.05
—
Ongoing diluted EPS (a)
$
1.23
$
1.18
Book value per share
$
31.38
$
29.90
Cash dividends declared per common
share
0.52
0.4875
Nine Months Ended Sept.
30
2023
2022
Operating revenues:
Electric and natural gas
$
10,677
$
11,178
Other
87
79
Total operating revenues
10,764
11,257
Net income
$
1,362
$
1,357
Weighted average diluted common shares
outstanding
552
546
Components of EPS —
Diluted
Regulated utility
$
2.68
$
2.69
Xcel Energy Inc. and other costs
(0.22
)
(0.21
)
GAAP and ongoing diluted EPS
(a)
2.47
2.48
Loss on Comanche Unit 3 litigation (See
Note 7)
0.05
—
Ongoing diluted EPS (a)
$
2.52
$
2.48
Book value per share
$
31.43
$
29.98
Cash dividends declared per common
share
1.56
1.4625
(a)
Amounts may not add due to rounding.
View source
version on businesswire.com: https://www.businesswire.com/news/home/20231027013689/en/
Paul Johnson, Vice President - Treasurer & Investor
Relations, (612) 215-4535 Roopesh Aggarwal, Senior Director -
Investor Relations, (303) 571-2855 Xcel Energy website address:
www.xcelenergy.com (612) 215-5300
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