- Third quarter GAAP diluted earnings per share were $1.18 in
2022 compared with $1.13 in 2021.
- Year-to-date GAAP diluted earnings per share for 2022 were
$2.48 compared with $2.38 in 2021.
- Xcel Energy narrows its 2022 EPS guidance range to $3.14 to
$3.19 from $3.10 to $3.20.
- Xcel Energy initiates 2023 EPS guidance of $3.30 to $3.40.
Xcel Energy Inc. (NASDAQ: XEL) today reported 2022 third quarter
GAAP and ongoing earnings of $649 million, or $1.18 per share,
compared with $609 million, or $1.13 per share in the same period
in 2021.
Earnings reflect capital investment recovery and other
regulatory outcomes, partially offset by higher depreciation,
interest expense and operating and maintenance (O&M)
expenses.
“Xcel Energy had a strong third quarter – both operationally and
financially – which has allowed us to narrow our 2022 earnings
guidance to $3.14 to $3.19 per share,” said Bob Frenzel, chairman,
president and CEO of Xcel Energy.
“This quarter also saw the passage of the groundbreaking
Inflation Reduction Act, whose clean energy provisions will provide
significant customer benefit, reduce the cost of the clean energy
transition and improve our liquidity through tax credit
transferability. As a result of the legislation, the cost of our
recently approved 460-MW Sherco Solar project will be reduced by
more than 30%. It will also lower the cost of 10,000 MWs of
renewables that were approved as part of our Minnesota and Colorado
resource plans and further enhance Xcel Energy’s and the region’s
competitive advantage due to strong wind and solar resources in our
states.”
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:
(866) 580-3963
International Dial-In:
(400) 120-0558
Conference ID:
0230649
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 12:00 p.m. CDT on Oct. 27 through 12:00 p.m. CDT on
Oct. 31.
Replay Numbers
US Dial-In:
1 (866) 583-1035
Access Code:
0230649#
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 2022 and
2023 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, 2021
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:
uncertainty around the impacts and duration of the COVID-19
pandemic, including potential workforce impacts resulting from
vaccination requirements, quarantine policies or government
restrictions, and sales volatility; 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; 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; natural disaster and resource depletion, including
compliance with any accompanying legislative and regulatory
changes; costs of potential regulatory penalties; regulatory
changes and/or limitations related to the use of natural gas as an
energy source; 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
2022
2021
2022
2021
Operating revenues
Electric
$
3,699
$
3,176
$
9,255
$
8,643
Natural gas
357
268
1,923
1,364
Other
26
23
79
69
Total operating revenues
4,082
3,467
11,257
10,076
Operating expenses
Electric fuel and purchased power
1,497
1,210
3,772
3,643
Cost of natural gas sold and
transported
173
86
1,134
603
Cost of sales — other
11
11
32
28
O&M expenses
611
568
1,827
1,752
Conservation and demand side management
expenses
86
78
259
222
Depreciation and amortization
607
537
1,807
1,586
Taxes (other than income taxes)
173
152
523
472
Total operating expenses
3,158
2,642
9,354
8,306
Operating income
924
825
1,903
1,770
Other (expense) income, net
(15
)
(3
)
(20
)
5
Earnings from equity method
investments
1
13
27
47
Allowance for funds used during
construction — equity
20
21
53
53
Interest charges and financing
costs
Interest charges — includes other
financing costs of $8, $7, $24 and $22, respectively
244
211
705
628
Allowance for funds used during
construction — debt
(7
)
(7
)
(19
)
(18
)
Total interest charges and financing
costs
237
204
686
610
Income before income taxes
693
652
1,277
1,265
Income tax expense (benefit)
44
43
(80
)
(17
)
Net income
$
649
$
609
$
1,357
$
1,282
Weighted average common shares
outstanding:
Basic
548
539
546
539
Diluted
548
539
546
539
Earnings per average common
share:
Basic
$
1.19
$
1.13
$
2.48
$
2.38
Diluted
1.18
1.13
2.48
2.38
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.
We believe these measurements are useful to investors to evaluate
the actual and projected financial performance and contribution of
our subsidiaries. For the three and nine months ended Sept. 30,
2022 and 2021, there were no such adjustments to GAAP earnings and
therefore GAAP earnings equal ongoing earnings for these
periods.
Note 1. Earnings Per Share
Summary
Xcel Energy’s third quarter diluted earnings were $1.18 per
share in 2022, compared with $1.13 per share in 2021. The increase
was driven by regulatory rate outcomes, partially offset by higher
depreciation, interest charges and O&M expenses. Costs for
natural gas significantly increased in 2022 due to supply and
demand conditions. However, 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
2022
2021
2022
2021
PSCo
$
0.45
$
0.40
$
1.02
$
0.96
NSP-Minnesota
0.49
0.46
0.94
0.91
SPS
0.25
0.25
0.52
0.48
NSP-Wisconsin
0.07
0.07
0.19
0.15
Earnings from equity method investments —
WYCO
0.01
0.01
0.03
0.03
Regulated utility (a)
1.28
1.19
2.69
2.54
Xcel Energy Inc. and Other
(0.09
)
(0.06
)
(0.21
)
(0.16
)
Total (a)
$
1.18
$
1.13
$
2.48
$
2.38
(a)
Amounts may not add due to
rounding.
PSCo — Earnings increased $0.05 per share for the third
quarter of 2022 and $0.06 year-to-date. Higher year-to-date
earnings reflect regulatory rate outcomes, partially offset by
increased depreciation and O&M expenses.
NSP-Minnesota — Earnings increased $0.03 per share for
the third quarter of 2022 and year-to-date. The year-to-date
increase is primarily due to regulatory rate outcomes, partially
offset by increased depreciation, O&M expenses and a Winter
Storm Uri cost disallowance (see Note 5).
SPS — Earnings were flat for the third quarter of 2022
and increased $0.04 per share year-to-date. Higher year-to-date
earnings largely reflect regulatory rate outcomes, strong sales
growth and favorable weather, partially offset by higher
depreciation, O&M expenses and interest charges.
NSP-Wisconsin — Earnings were flat for the third quarter
of 2022 and increased $0.04 per share year-to-date. The
year-to-date increase is due to regulatory rate outcomes and sales
growth, partially offset by higher depreciation and O&M
expenses.
Xcel Energy Inc. and Other — Primarily includes financing
costs at the holding company and earnings from Energy Impact
Partners (EIP) funds equity method investments. Earnings decreased
$0.05 per share year-to-date, largely attributable to higher
interest charges.
Components significantly contributing to changes in 2022 EPS
compared to 2021:
Diluted Earnings (Loss) Per
Share
Three Months Ended Sept.
30
Nine Months Ended Sept.
30
GAAP and ongoing diluted EPS —
2021
$
1.13
$
2.38
Components of change - 2022 vs. 2021
Higher electric revenues, net of electric
fuel and purchased power
0.33
0.67
Lower effective tax rate (ETR) (a)
0.02
0.12
Higher natural gas revenues, net of cost
of natural gas sold and transported
—
0.04
Higher depreciation and amortization
(0.10
)
(0.30
)
Higher O&M expenses
(0.06
)
(0.10
)
Higher interest charges
(0.04
)
(0.10
)
Higher taxes (other than income taxes)
(0.03
)
(0.07
)
Lower other (expense) income
(0.02
)
(0.03
)
Other, net
(0.05
)
(0.13
)
GAAP and ongoing diluted EPS —
2022
$
1.18
$
2.48
(a)
Includes production tax credits
(PTCs) and plant regulatory amounts, which are primarily offset as
a reduction to electric revenues.
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 and proposed 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
2022 vs. Normal
2021 vs. Normal
2022 vs. 2021
2022 vs. Normal
2021 vs. Normal
2022 vs. 2021
Retail electric
$
0.074
$
0.067
$
0.007
$
0.123
$
0.122
$
0.001
Decoupling and sales true-up
(0.032
)
(0.035
)
0.003
(0.055
)
(0.076
)
0.021
Electric total
$
0.042
$
0.032
$
0.010
$
0.068
$
0.046
$
0.022
Firm natural gas
—
—
—
0.019
0.004
0.015
Total
$
0.042
$
0.032
$
0.010
$
0.087
$
0.050
$
0.037
Sales — Sales growth (decline) for actual and
weather-normalized sales in 2022 compared to 2021:
Three Months Ended Sept.
30
PSCo
NSP-Minnesota
SPS
NSP-Wisconsin
Xcel Energy
Actual
Electric residential
(1.7
)%
(2.7
)%
7.8
%
(0.1
) %
(0.7
)%
Electric C&I
(2.3
)
0.2
7.2
3.7
1.6
Total retail electric sales
(2.0
)
(0.8
)
7.3
2.6
0.9
Firm natural gas sales
(1.6
)
—
N/A
2.3
(0.9
)
Three Months Ended Sept.
30
PSCo
NSP-Minnesota
SPS
NSP-Wisconsin
Xcel Energy
Weather-Normalized
Electric residential
(4.6
)%
0.5
%
3.3
%
(0.1
)%
(1.1
)%
Electric C&I
(3.2
)
0.4
6.4
3.5
1.2
Total retail electric sales
(3.7
)
0.4
5.9
2.5
0.5
Firm natural gas sales
(1.5
)
(2.2
)
N/A
—
(1.6
)
Nine Months Ended Sept.
30
PSCo
NSP-Minnesota
SPS
NSP-Wisconsin
Xcel Energy
Actual
Electric residential
(2.9
)%
(1.4
)%
4.9
%
1.3
%
(0.9
)%
Electric C&I
(0.3
)
2.3
9.6
3.6
3.6
Total retail electric sales
(1.2
)
1.1
8.6
2.9
2.2
Firm natural gas sales
(3.4
)
19.9
N/A
20.2
4.9
Nine Months Ended Sept.
30
PSCo
NSP-Minnesota
SPS
NSP-Wisconsin
Xcel Energy
Weather-Normalized
Electric residential
(3.7
)%
0.6
%
0.7
%
0.6
%
(1.0
)%
Electric C&I
(0.5
)
2.7
9.0
3.8
3.5
Total retail electric sales
(1.6
)
2.0
7.4
2.8
2.2
Firm natural gas sales
(2.4
)
6.0
N/A
7.4
0.9
Weather-normalized electric sales growth
(decline) — year-to-date
- PSCo — Residential sales declined due to decreased use per
customer, partially offset by a 1.1% increase in customers. C&I
sales decline was attributable to decreased use per customer,
primarily in the manufacturing sector (largely due to an
alternative generation arrangement with a significant customer),
partially offset by strong small C&I sales in the professional
services and health care sectors.
- NSP-Minnesota — Residential sales growth reflects a 1.2%
increase in customers, partially offset by decreased use per
customer. Growth in C&I sales was primarily due to higher use
per customer, particularly in the manufacturing, real estate and
leasing, and food service sectors.
- SPS — Residential sales growth was primarily attributable to a
1.0% increase in customers, partially offset by lower use per
customer. C&I sales increased due to higher use per customer,
primarily driven by the energy sector.
- NSP-Wisconsin — Residential sales growth was driven by a 0.7%
increase in customers. C&I sales growth was primarily
associated with higher use per customer, experienced primarily in
the transportation and manufacturing sectors.
Weather-normalized natural gas sales
growth (decline) — year-to-date
- Natural gas sales reflect a higher use per customer,
experienced primarily in NSP-Minnesota and NSP-Wisconsin, partially
offset by a decrease in PSCo (lower residential use per customer).
In addition, residential and C&I customer growth was 1.2% and
0.5%, 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 that recover fuel
expenses. 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 and
explanation of the changes are listed as follows:
Three Months Ended Sept.
30
Nine Months Ended Sept.
30
(Millions of Dollars)
2022
2021
2022
2021
Electric revenues
$
3,699
$
3,176
$
9,255
$
8,643
Electric fuel and purchased power
(1,497
)
(1,210
)
(3,772
)
(3,643
)
Electric margin
$
2,202
$
1,966
$
5,483
$
5,000
(Millions of Dollars)
Three Months Ended Sept. 30,
2022 vs. 2021
Nine Months Ended Sept. 30,
2022 vs. 2021
Regulatory rate outcomes (Minnesota,
Colorado, Texas, New Mexico and Wisconsin)
$
165
$
361
Revenue recognition for the Texas rate
case surcharge (a)
—
85
Sales and demand (b)
24
84
Non-fuel riders
8
48
Conservation and demand side management
(offset in expenses)
9
31
Wholesale transmission (net)
19
25
Estimated impact of weather (net of
decoupling/sales true-up)
7
16
PTCs flowed back to customers (offset by
lower ETR)
(17
)
(120
)
Proprietary commodity trading, net of
sharing (c)
(1
)
(33
)
Other (net)
22
(14
)
Total increase
$
236
$
483
(a)
Recognition of revenue from the
Texas rate case outcome is largely offset by recognition of
previously deferred costs.
(b)
Sales excludes weather impact,
net of decoupling in Colorado and proposed sales true-up mechanism
in Minnesota.
(c)
Includes $27 million of net gains
recognized in the first quarter of 2021, driven by market changes
associated with Winter Storm Uri.
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 revenues, cost of natural gas sold and transported
and margin and explanation of the changes are listed as
follows:
Three Months Ended Sept.
30
Nine Months Ended Sept.
30
(Millions of Dollars)
2022
2021
2022
2021
Natural gas revenues
$
357
$
268
$
1,923
$
1,364
Cost of natural gas sold and
transported
(173
)
(86
)
(1,134
)
(603
)
Natural gas margin
$
184
$
182
$
789
$
761
(Millions of Dollars)
Three Months Ended Sept. 30,
2022 vs. 2021
Nine Months Ended Sept. 30,
2022 vs. 2021
Regulatory rate outcomes (Minnesota,
Wisconsin, North Dakota, Colorado)
$
2
$
16
Estimated impact of weather
—
11
Conservation revenue (offset in
expenses)
2
9
Infrastructure and integrity riders
4
7
Winter Storm Uri disallowances (see Note
5)
(7
)
(20
)
Other (net)
1
5
Total increase
$
2
$
28
O&M Expenses — O&M expenses increased $43 million
for the third quarter and $75 million year-to-date. O&M costs
increased due to recognition of previously deferred amounts related
to the 2021 Texas Electric Rate Case, additional investments in
technology and customer programs, higher costs for storms and
vegetation management and inflationary impacts. These increases
were partially offset by a reduction in employee benefit costs and
timing of certain power plant overhaul costs.
Depreciation and Amortization — Depreciation and
amortization increased $70 million for the third quarter and $221
million year-to-date. The increase was primarily driven by normal
system expansion, recognition of previously deferred costs related
to the Texas Electric Rate Case and several wind farms going into
service.
Other (Expense) Income — Other (expense) income decreased
$12 million for the third quarter and $25 million year-to-date,
largely related to rabbi trust performance, which is primarily
offset in O&M expenses (employee benefit costs).
Interest Charges — Interest charges increased $33 million
for the third quarter and $77 million year-to-date, largely due to
higher interest rates and increased long-term debt levels to fund
capital investments.
Income Taxes — Effective income tax rate:
Three Months Ended Sept.
30
Nine Months Ended Sept.
30
2022
2021
2022 vs 2021
2022
2021
2022 vs 2021
Federal statutory rate
21.0
%
21.0
%
—
%
21.0
%
21.0
%
—
%
State tax (net of federal tax effect)
4.9
5.0
(0.1
)
4.9
5.0
(0.1
)
(Decreases) increases:
Wind PTCs (a)
(12.3
)
(12.1
)
(0.2
)
(25.2
)
(20.0
)
(5.2
)
Plant regulatory differences (b)
(5.8
)
(5.8
)
—
(5.5
)
(6.0
)
0.5
Other tax credits, net operating loss
& tax credits allowances
(1.2
)
(1.2
)
—
(1.4
)
(1.1
)
(0.3
)
Other (net)
(0.3
)
(0.3
)
—
(0.1
)
(0.2
)
0.1
Effective income tax rate
6.3
%
6.6
%
(0.3
)%
(6.3
)%
(1.3
)%
(5.0
)%
(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.
Income tax expense increased $1 million for the third quarter
and income tax benefit increased $63 million year-to-date. The
year-to-date increase was primarily driven by an increase in wind
PTCs due to greater production at existing wind farms, several new
wind farms going into service and an increase in the PTC rate.
Inflation Reduction Act — In August 2022, the Inflation
Reduction Act (IRA) was signed into law.
Key provisions impacting Xcel Energy include:
- Extends current PTC and ITC (Investment Tax Credit) for
renewable technologies (e.g., wind and solar).
- Restores full value of the PTC and ITC for qualifying
facilities placed in-service after 2021.
- Creates a PTC for solar, clean hydrogen and nuclear.
- Establishes an ITC for energy storage, microgrids,
interconnection facilities, etc.
- Allows companies to monetize or sell credits to unrelated
parties.
Xcel Energy anticipates the IRA will drive approximately $500
million of customer savings over the next 5 years for existing
company owned renewable projects, assuming appropriate regulatory
mechanisms and development of a market for the sale of credits. The
IRA will drive additional customer savings as Xcel Energy adds new
renewable projects due to the extension of tax credits and
transferability.
The IRA is expected to allow Xcel Energy to monetize tax credits
more efficiently with the incremental benefits passed through to
customers. Transferability provisions apply to eligible tax credits
generated starting in 2023 for both new and existing facilities.
Xcel Energy anticipates tax credit transferability from existing
renewable projects will improve cash from operations by $1.8
billion (2023-2027), assuming constructive regulatory outcomes and
the development of a market. Tax credit transferability has been
included in our five-year financing plan and rate base
projections.
The IRA creates a nuclear PTC beginning in 2024 that may also
provide additional customer savings. The annual customer benefit
from these PTCs could range from $0 to $200 million, depending on
locational marginal pricing, as well as constructive U.S. Treasury
guidance regarding computation of the credits.
In addition, the IRA created a new corporate alternative minimum
tax (AMT). Xcel Energy does not anticipate AMT having a material
cash impact based on current estimates and our interpretation of
AMT application.
Note 3. Capital Structure, Liquidity,
Financing and Credit Ratings
Xcel Energy’s capital structure:
(Millions of Dollars)
Sept. 30, 2022
Percentage of Total
Capitalization
Dec. 31, 2021
Percentage of Total
Capitalization
Current portion of long-term debt
$
651
2
%
$
601
1
%
Short-term debt
158
—
1,005
3
Long-term debt
23,309
58
21,779
56
Total debt
24,118
60
23,385
60
Common equity
16,384
40
15,612
40
Total capitalization
$
40,502
100
%
$
38,997
100
%
Liquidity — As of Oct. 25, 2022, 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
$
129
$
1,371
$
1
$
1,372
PSCo
700
264
436
3
439
NSP-Minnesota
700
55
645
4
649
SPS
500
67
433
1
434
NSP-Wisconsin
150
—
150
3
153
Total
$
3,550
$
515
$
3,035
$
12
$
3,047
(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. 25, 2022:
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-2
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 2023 through
2027:
Base Capital Forecast
(Millions of Dollars)
By Regulated Utility
2023
2024
2025
2026
2027
2023 - 2027 Total
PSCo
$
2,140
$
2,440
$
2,550
$
1,980
$
2,190
$
11,300
NSP-Minnesota
2,000
2,400
2,530
2,200
2,580
11,710
SPS
710
780
720
770
900
3,880
NSP-Wisconsin
540
570
500
450
540
2,600
Other (a)
10
10
(30
)
10
10
10
Total base capital expenditures
$
5,400
$
6,200
$
6,270
$
5,410
$
6,220
$
29,500
(a)
Other category includes
intercompany transfers for safe harbor wind turbines.
Base Capital Forecast
(Millions of Dollars)
By Function
2023
2024
2025
2026
2027
2023 - 2027 Total
Electric distribution
$
1,610
$
1,790
$
1,680
$
2,000
$
2,450
$
9,530
Electric transmission
1,280
1,650
1,890
1,690
1,900
8,410
Electric generation
710
910
900
560
650
3,730
Natural gas
740
730
760
650
680
3,560
Other
780
840
570
510
540
3,240
Renewables
280
280
470
—
—
1,030
Total base capital expenditures
$
5,400
$
6,200
$
6,270
$
5,410
$
6,220
$
29,500
The base plan does not include any potential renewable
generation assets approved in our Minnesota and Colorado resource
plans or additional transmission capital needed to integrate new
renewable generation additions in Colorado, beyond the Pathway
project. We expect further clarification in the second half of 2023
after the commissions rule on the recommended resource plan
portfolios, which could result in incremental capital expenditures
of approximately $2 to $4 billion (assuming 50% ownership of the
renewable projects).
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 2027 — 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 2023 through 2027 (includes the estimated impact of
approximately $1.8 billion of tax credit transferability):
(Millions of Dollars)
Funding Capital Expenditures
Cash from operations (a)
$
20,540
New debt (b)
8,210
Equity through the Dividend Reinvestment
and Stock Purchase Program (DRIP) and benefit program
425
Other equity
325
Base capital expenditures 2023-2027
$
29,500
Maturing Debt
$
3,800
(a)
Net of dividends and pension
funding.
(b)
Reflects a combination of short
and long-term debt; net of refinancing.
2022 Financing Activity — During 2022, Xcel Energy plans
to issue approximately $75 to $80 million of equity through the
DRIP and benefit programs. In 2022, approximately $150 million of
equity has been issued through an at-the-market program. Xcel
Energy and its utility subsidiaries issued the following long-term
debt:
Issuer
Security
Amount
Tenor
Coupon
Xcel Energy
Unsecured Senior Notes
$
700
10 Year
4.60
%
PSCo
First Mortgage Bonds
300
10 Year
4.10
PSCo
First Mortgage Bonds
400
30 Year
4.50
SPS
First Mortgage Bonds
200
30 Year
5.15
NSP-Minnesota
First Mortgage Bonds
500
30 Year
4.50
NSP-Wisconsin
First Mortgage Bonds
100
30 Year
4.86
Financing plans are subject to change, depending on legislative
initiatives (e.g., federal tax law changes), capital expenditures,
regulatory outcomes, 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 MPUC. The rate case is based on a requested ROE of
10.2%, a 52.5% equity ratio and forward test years.
The request is detailed as follows:
(Amounts in Millions, Except
Percentages)
2022
2023
2024
Total
Rate request (annual increase)
$
396
$
150
$
131
$
677
Increase percentage
12.2
%
4.8
%
4.2
%
21.2
%
Rate base
$
10,931
$
11,446
$
11,918
N/A
In December 2021, the MPUC approved interim rates, subject to
refund, of $247 million, effective Jan. 1, 2022. On Sept. 30, 2022,
NSP-Minnesota requested an incremental increase to interim rates of
$122 million, effective Jan. 1, 2023. On Oct. 21, 2022, intervening
parties to the rate case filed comments recommending the MPUC deny
NSP-Minnesota’s request. A MPUC decision is expected in late
2022.
In October 2022, nine parties filed testimony. The Minnesota
Department of Commerce (DOC), Office of Attorney General (OAG),
Xcel Large Industrial Customers (XLI), the Citizens Utility Board
of Minnesota (CUB) and Just Solar Coalition (JSC) were the only
parties to quantify recommended financial adjustments. XLI
recommended $112 million in proposed adjustments, based on reducing
ROE, reducing recovery of incentive compensation and not including
the prepaid pension asset in rate base. CUB recommended adjustments
based on reducing ROE. Other parties provided specific issue
recommendations.
Proposed DOC modifications to NSP-Minnesota’s request:
(Millions of Dollars)
2022
2023
2024
NSP-Minnesota’s filed base revenue
request
$
396
$
546
$
677
Recommended adjustments:
Rate base and rate of return (a)
(71
)
(58
)
(57
)
MISO capacity credits
(55
)
(94
)
(94
)
Monticello and wind farm life
extension
(21
)
(54
)
(51
)
PTC and ND ITC forecast
(28
)
(40
)
(43
)
Property tax
(14
)
(22
)
(32
)
Prepaid pension asset and liability
(13
)
(21
)
(32
)
O&M expenses
(18
)
(26
)
(29
)
Other, net
(48
)
(57
)
(65
)
Total adjustments
(268
)
(372
)
(403
)
Total proposed revenue change
$
128
$
174
$
274
(a)
Included in the rate base and
rate of return adjustments is an annual proposed increase in the
cost of debt.
Positions on NSP-Minnesota’s filed rate request:
Recommended Position
DOC
XLI
CUB
JSC
ROE
9.25
%
9.17
%
8.80-9.00%
9.06
%
Equity
52.5
%
N/A
N/A
N/A
Next steps in the procedural schedule are expected to be as
follows:
- Rebuttal testimony: Nov. 8, 2022.
- Hearing: Dec. 13-16, 2022.
- ALJ Report: March 31, 2023.
- MPUC Order: June 30, 2023.
NSP-Minnesota — 2022 Minnesota Natural Gas Rate
Case — In November 2021, NSP-Minnesota filed a request with the
MPUC for an annual natural gas rate increase of $36 million, or
6.6%. The filing is based on a 2022 forecast test year and includes
a requested return on equity (ROE) of 10.5%, an equity ratio of
52.5% and a rate base of $934 million. In December 2021, the MPUC
approved an interim rate increase of $25 million, subject to
refund, effective Jan. 1, 2022.
In October 2022, NSP-Minnesota and various parties filed an
uncontested settlement, which includes the following key terms:
- Base rate revenue increase of $21 million, with a true up to
weather normalized actual sales for 2022.
- Revenue decoupling mechanism.
- Symmetrical property tax true-up.
- ROE of 9.57%.
- Equity ratio of 52.5%.
A hearing is scheduled for the fourth quarter of 2022 and a MPUC
order is expected in the first half of 2023.
NSP-Minnesota — 2021 North Dakota Natural Gas Rate
Case — In September 2021, NSP-Minnesota filed a request with
the North Dakota Public Service Commission (NDPSC) for a natural
gas rate increase of $7 million, or 10.5%. The filing is based on a
requested ROE of 10.5%, an equity ratio of 52.54%, a 2022 forecast
test year and a rate base of $124 million. Interim rates of $7
million, subject to refund, were implemented on Nov. 1, 2021.
In May 2022, NSP-Minnesota and NDPSC Staff reached a natural gas
settlement, which reflects a rate increase of $5 million, based on
a 9.8% ROE and 52.54% equity ratio. A NDPSC decision is
pending.
NSP-Minnesota — 2022 South Dakota Electric Rate Case — In
June 2022, NSP-Minnesota filed a South Dakota electric rate case
(first since 2014) seeking a revenue increase of approximately $44
million. The filing is based on a 2021 historic test year adjusted
for certain known and measurable changes for 2022 and 2023, a
requested return on equity of 10.75%, rate base of approximately
$947 million and an equity ratio of 53%. Final rates are expected
to be effective in the first quarter of 2023.
NSP-Minnesota — Wind Repowering — In January 2021, the
MPUC approved NSP-Minnesota’s request for the repowering of 651 MW
of owned wind projects. Two of the four repowering projects, where
construction has not yet begun (in-service dates in 2025), now
expect costs in excess of the original approval. While the capital
costs have increased, the passage of the IRA and other changes
result in a levelized cost of energy that is approximately 30%
lower than the original approval. In October 2022, NSP-Minnesota
filed a request with the MPUC seeking approval of the higher
capital costs for these repowering projects.
NSP-Minnesota — Sherco Solar Proposal — In September
2022, the MPUC approved NSP-Minnesota’s proposal to add 460 MW of
solar facilities at the Sherco site. The project is expected to
cost approximately $690 million (two phases to be completed in 2024
and 2025). As a result of the IRA, the levelized cost of the
project is expected to be approximately 30% lower than previously
estimated.
PSCo — Natural Gas Rate Case — In January 2022, PSCo
filed a request with the CPUC seeking a net increase to retail
natural gas rates of $107 million. The total change to base rates
is $215 million, which reflects the transfer of $108 million
previously recovered from customers through the Pipeline System
Integrity Adjustment (PSIA) rider. The request is based on a 10.25%
ROE, an equity ratio of 55.66% and a 2022 current test year with a
projected rate base of $3.6 billion. PSCo has requested a proposed
effective date of Nov. 1, 2022. Additionally, PSCo’s request
includes step revenue increases of $40 million (effective Nov. 1,
2023) and $41 million (effective Nov. 1, 2024) related to continued
capital investment.
In October 2022, the CPUC issued a written decision approving a
rate increase net of rider roll-ins of $64 million. The decision
reflects a stated weighted average cost of capital (WACC) of 6.7%,
a historic test year with a year-end rate base and $16 million of
incremental depreciation expense. PSCo has the option to determine
its ROE within a range of 9.2% to 9.5% and its equity ratio within
a range of 52% to 55%, as long as it results in a WACC of 6.7%.
PSCo anticipates using a ROE of 9.2% and an equity ratio of 53.8%.
The CPUC denied the 2023-2024 step increases.
Note 5. Winter Storm Uri
In February 2021, the United States experienced Winter Storm
Uri. As a result of the extremely high market prices, Xcel Energy
incurred net natural gas, fuel and purchased energy costs of
approximately $1 billion. Xcel Energy has received recovery
approval from all of our impacted states except for Texas, which is
pending. A summary of pending and recently approved regulatory
requests for cost recovery is listed below.
Utility Subsidiary
Jurisdiction
Regulatory Status
NSP-Minnesota
Minnesota
In 2021, the MPUC allowed
recovery of $179 million of costs (with no financing charge)
starting in September 2021, pending a prudency review. The C&I
class ($82 million) will be recovered over 27 months and the
residential class ($97 million) will be recovered over a 63-month
recovery period.
In May 2022, the ALJs found the
Winter Storm Uri fuel costs were prudently incurred and recommended
no disallowances.
In August 2022, the MPUC approved
recovery of Uri storm costs with a $19 million disallowance.
PSCo
Colorado
In May 2021, PSCo filed a request
with the CPUC to recover $263 million in weather-related electric
costs, $287 million in incremental natural gas costs and $4 million
in incremental steam costs over 24 months with no financing
charge.
In May 2022, an ALJ recommended
full recovery of all costs with no cost disallowances. In July
2022, the CPUC approved a partial settlement providing full
recovery of fuel costs with the exception of an $8 million
disallowance.
SPS
Texas
In 2021, SPS filed to recover $88
million of Winter Storm Uri costs over 24 months, as part of the
Texas fuel surcharge filing, with total under-recovered costs of
$121 million.
In April 2022, interim rates
designed to recover $121 million over 30 months were approved. The
interim rate recovery does not address the prudence of costs nor
the retention of $11 million related to market sales during the
event. These items will be reviewed through the triennial Fuel
Reconciliation proceeding and are subject to a final PUCT
decision.
In July 2022, the intervenors
filed recommendations in the Fuel Reconciliation proceeding. The
Texas Industrial Energy Consumers and PUCT staff recommended
disallowances of approximately $10 million (off-system sales
margins). The Office of Public Utility Counsel recommended
disallowances of approximately $15 million (off-system sales
margins and adjustment to energy loss factors). The Alliance of
Xcel Municipalities recommended disallowances of approximately $100
million (natural gas storage, contracted capability and off-system
sales margins).
A recommendation from the ALJ is
expected in the fourth quarter of 2022 and a final decision is
anticipated in the first quarter of 2023.
Note 6. Earnings Guidance and Long-Term
EPS and Dividend Growth Rate Objectives
Xcel Energy 2022 Earnings Guidance — Xcel Energy’s 2022
GAAP and ongoing earnings guidance is a narrowed range of $3.14 to
$3.19 per share.(a)
Key assumptions as compared with 2021 levels unless noted:
- Constructive outcomes in all rate case and regulatory
proceedings.
- Normal weather patterns for the remainder of the year.
- Weather-normalized retail electric sales are projected to
increase ~2%.
- Weather-normalized retail firm natural gas sales are projected
to increase ~1%.
- Capital rider revenue is projected to be relatively flat (net
of PTCs). The reduction in capital rider revenue is due to changes
in expected PTC levels and is largely earnings neutral.
- O&M expenses are projected to increase approximately
4%.
- Depreciation expense is projected to increase approximately
$295 million to $305 million.
- Property taxes are projected to increase approximately $35
million to $45 million.
- Interest expense (net of AFUDC - debt) is projected to increase
$100 million to $110 million.
- AFUDC - equity is projected to be relatively flat.
- ETR is projected to be ~(7%) to (9%).
Xcel Energy 2023 Earnings Guidance — Xcel Energy’s 2023
GAAP and ongoing earnings guidance is a range of $3.30 to $3.40 per
share.(a)
Key assumptions as compared with 2022 projected levels unless
noted:
- Constructive outcomes in all rate case and regulatory
proceedings.
- Normal weather patterns for the year.
- Weather-normalized retail electric sales are projected to
increase ~1%.
- Weather-normalized retail firm natural gas sales are projected
to be relatively flat.
- Capital rider revenue is projected to increase $70 million to
$80 million (net of PTCs).
- O&M expenses are projected to be relatively flat.
- Depreciation expense is projected to increase approximately
$140 million to $150 million.
- Property taxes are projected to increase approximately $35
million to $45 million.
- Interest expense (net of AFUDC - debt) is projected to increase
$110 million to $120 million.
- AFUDC - equity is projected to increase $0 million to $10
million.
- ETR is projected to be ~(5%) to (7%).
(a)
Ongoing earnings is calculated
using net income and adjusting for certain nonrecurring or
infrequent items that are, in management’s view, not reflective of
ongoing operations. Ongoing earnings could differ from those
prepared in accordance with GAAP for unplanned and/or unknown
adjustments. Xcel Energy is unable to forecast if any of these
items will occur or provide a quantitative reconciliation of the
guidance for ongoing 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
2022 base of $3.15 per share, which represents the mid-point of the
original 2022 guidance range of $3.10 to $3.20 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
2022
2021
Operating revenues:
Electric and natural gas
$
4,056
$
3,444
Other
26
23
Total operating revenues
4,082
3,467
Net income
$
649
$
609
Weighted average diluted common shares
outstanding
548
539
Components of EPS —
Diluted
Regulated utility
$
1.28
$
1.19
Xcel Energy Inc. and other costs
(0.09
)
(0.06
)
GAAP and ongoing diluted EPS
(a)
$
1.18
$
1.13
Book value per share
$
29.90
$
28.12
Cash dividends declared per common
share
0.4875
0.4575
Nine Months Ended Sept.
30
2022
2021
Operating revenues:
Electric and natural gas
$
11,178
$
10,007
Other
79
69
Total operating revenues
11,257
10,076
Net income
$
1,357
$
1,282
Weighted average diluted common shares
outstanding
546
539
Components of EPS —
Diluted
Regulated utility
$
2.69
$
2.54
Xcel Energy Inc. and other costs
(0.21
)
(0.16
)
GAAP and ongoing diluted EPS
(a)
2.48
2.38
Book value per share
$
29.98
$
28.14
Cash dividends declared per common
share
1.4625
1.3725
(a)
For the three and nine months
ended Sept. 30, 2022, there were no adjustments to GAAP earnings
and therefore GAAP earnings equal ongoing earnings for these
periods.
View source
version on businesswire.com: https://www.businesswire.com/news/home/20221027005150/en/
Paul Johnson, Vice President - Treasurer & Investor
Relations (612) 215-4535
For news media inquiries only, please call Xcel Energy Media
Relations (612) 215-5300
Xcel Energy website address: www.xcelenergy.com
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