- Second quarter GAAP and ongoing diluted earnings per share were
$0.54 in 2024 compared with $0.52 in 2023.
- Xcel Energy reaffirms 2024 EPS guidance of $3.50 to $3.60 per
share.
Xcel Energy Inc. (NASDAQ: XEL) today reported 2024 second
quarter GAAP and ongoing earnings of $302 million, or $0.54 per
share, compared with $288 million, or $0.52 per share in the same
period in 2023.
Second quarter ongoing earnings reflect recovery of increased
infrastructure investments and warmer than normal weather,
partially offset by increased depreciation, interest charges and
O&M expenses.
“Xcel Energy continues to meet the growing demand for energy
from our customers while driving forward the clean energy
transition and adapting to changing regulatory and environmental
conditions,” said Bob Frenzel, chairman, president and CEO of Xcel
Energy. “We are reaffirming our earnings guidance of $3.50 - $3.60
per share.”
“We continue to advance proposals to enhance the resiliency and
sustainability of our system for the safety and benefit of our
customers. In Colorado, we filed an updated Wildfire Mitigation
Plan that builds upon our existing investments,” Frenzel said. “We
also supported legislation that will help the state achieve a
smoother clean energy transition by enhancing the distribution
system planning process in Colorado. And in Minnesota, we
collaborated with stakeholders to achieve a settlement in our
natural gas rate case that supports improvements while keeping our
residential customers’ natural gas rates below the national
average.”
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:
2632580
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 Aug. 1st through Aug. 5th.
Replay Numbers
US Dial-In:
1 (866) 583-1035
Access Code:
2632580#
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 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, expected pension contributions, and expected impact on
our results of operations, financial condition and cash flows of
interest rate changes, increased credit exposure, and legal
proceeding outcomes, 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, 2023
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
workforce 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; cybersecurity 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 June
30
Six Months Ended June
30
2024
2023
2024
2023
Operating revenues
Electric
$
2,659
$
2,601
$
5,344
$
5,364
Natural gas
355
393
1,296
1,681
Other
14
28
37
57
Total operating revenues
3,028
3,022
6,677
7,102
Operating expenses
Electric fuel and purchased power
855
1,030
1,803
2,147
Cost of natural gas sold and
transported
118
170
601
1,014
Cost of sales — other
1
11
9
23
Operating and maintenance expenses
662
628
1,267
1,278
Conservation and demand side management
expenses
86
63
183
139
Depreciation and amortization
703
565
1,361
1,189
Taxes (other than income taxes)
154
137
325
321
Total operating expenses
2,579
2,604
5,549
6,111
Operating income
449
418
1,128
991
Other income, net
22
11
36
16
Earnings from equity method
investments
8
9
16
20
Allowance for funds used during
construction — equity
38
18
75
37
Interest charges and financing
costs
Interest charges — includes other
financing costs
319
268
610
521
Allowance for funds used during
construction — debt
(16
)
(12
)
(30
)
(22
)
Total interest charges and financing
costs
303
256
580
499
Income before income taxes
214
200
675
565
Income tax benefit
(88
)
(88
)
(115
)
(141
)
Net income
$
302
$
288
$
790
$
706
Weighted average common shares
outstanding:
Basic
557
551
556
551
Diluted
557
552
556
551
Earnings per average common
share:
Basic
$
0.54
$
0.52
$
1.42
$
1.28
Diluted
0.54
0.52
1.42
1.28
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. For the three and six months ended June 30,
2024 and 2023, 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 second quarter GAAP and ongoing diluted earnings
were $0.54 per share, compared with $0.52 per share in the same
period in 2023. The increase in earnings per share was primarily
driven by increased recovery of infrastructure investments and
warmer than normal weather, partially offset by higher
depreciation, interest charges and O&M expenses. 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 June
30
Six Months Ended June
30
Diluted Earnings (Loss) Per
Share
2024
2023
2024
2023
NSP-Minnesota
$
0.24
$
0.23
$
0.61
$
0.48
PSCo
0.21
0.17
0.61
0.56
SPS
0.16
0.15
0.26
0.25
NSP-Wisconsin
0.04
0.05
0.12
0.13
Earnings from equity method investments —
WYCO
0.01
0.01
0.02
0.02
Regulated utility (a)
0.66
0.60
1.62
1.43
Xcel Energy Inc. and Other
(0.12
)
(0.08
)
(0.20
)
(0.15
)
GAAP and ongoing diluted EPS
(a)
$
0.54
$
0.52
1.42
1.28
(a)
Amounts may not add due to rounding.
NSP-Minnesota — GAAP and ongoing earnings increased $0.01
per share for the second quarter and $0.13 year-to-date.
Year-to-date earnings primarily reflect increased recovery of
electric and natural gas infrastructure investments and lower
O&M expenses, partially offset by higher depreciation.
PSCo — GAAP and ongoing earnings increased $0.04 in the
second quarter and $0.05 year-to-date. The year-to-date change was
driven by increased recovery of electric infrastructure
investments, which was partially offset by increased
depreciation.
SPS — GAAP and ongoing earnings increased $0.01 for the
second quarter and year-to-date as regulatory rate outcomes and
increased sales and demand were partially offset by increased
depreciation.
NSP-Wisconsin — GAAP and ongoing earnings decreased $0.01
in the second quarter and year-to-date, largely due to unfavorable
weather and increased depreciation.
Xcel Energy Inc. and Other — Primarily includes financing
costs and interest income at the holding company and earnings from
investment funds, which are accounted for as equity method
investments. The decline in earnings is largely due to increased
interest rates and higher debt levels.
Components significantly contributing to changes in 2024 EPS
compared to 2023:
Diluted Earnings (Loss) Per
Share
Three Months Ended June
30
Six Months Ended June
30
GAAP and ongoing diluted EPS —
2023
$
0.52
$
1.28
Components of change - 2024 vs. 2023
Electric regulatory rate outcomes (a)
0.26
0.40
Higher AFUDC
0.04
0.08
Natural gas regulatory rate outcomes
(b)
0.02
0.05
(Higher) lower O&M expenses
(0.04
)
0.02
Higher depreciation and amortization
(0.18
)
(0.23
)
Higher interest charges
(0.07
)
(0.12
)
Other, net
(0.01
)
(0.06
)
GAAP and ongoing diluted EPS —
2024
$
0.54
$
1.42
(a)
Includes the revenue impact of regulatory
rate outcomes and non-fuel riders.
(b)
Includes the revenue impact of natural gas
regulatory rate outcomes and infrastructure and integrity
riders.
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, electric sales true-up and gas decoupling mechanism in
Minnesota predominately mitigate the positive and adverse impacts
of weather in that jurisdiction.
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 June
30
Six Months Ended June
30
2024 vs. Normal
2023 vs. Normal
2024 vs. 2023
2024 vs. Normal
2023 vs. Normal
2024 vs. 2023
Retail electric
$
0.006
$
0.001
$
0.005
$
(0.023
)
$
0.003
$
(0.026
)
Decoupling and sales true-up
0.025
(0.017
)
0.042
0.041
(0.023
)
0.064
Electric total
$
0.031
$
(0.016
)
$
0.047
$
0.018
$
(0.020
)
$
0.038
Firm natural gas
(0.011
)
(0.003
)
(0.008
)
(0.038
)
0.026
(0.064
)
Decoupling
0.002
—
0.002
0.019
—
0.019
Natural gas total
$
(0.009
)
$
(0.003
)
$
(0.006
)
$
(0.019
)
$
0.026
$
(0.045
)
Total
$
0.022
$
(0.019
)
$
0.041
$
(0.001
)
$
0.006
$
(0.007
)
Sales — Sales growth (decline) for actual and
weather-normalized sales in 2024 compared to 2023:
Three Months Ended June
30
PSCo
NSP-Minnesota
SPS
NSP-Wisconsin
Xcel Energy
Actual
Electric residential
12.1
%
(10.9
)%
11.7
%
(6.2
)%
0.4
%
Electric C&I
(0.8
)
(5.8
)
6.9
(3.4
)
(0.4
)
Total retail electric sales
3.2
(7.4
)
7.5
(4.1
)
(0.2
)
Firm natural gas sales
(9.7
)
(10.9
)
N/A
(9.5
)
(10.1
)
Three Months Ended June
30
PSCo
NSP-Minnesota
SPS
NSP-Wisconsin
Xcel Energy
Weather-Normalized
Electric residential
(0.3
)%
1.0
%
(0.2
)%
(1.2
)%
0.2
%
Electric C&I
(4.1
)
(3.6
)
6.2
(2.5
)
(0.8
)
Total retail electric sales
(2.9
)
(2.2
)
5.2
(2.2
)
(0.5
)
Firm natural gas sales
(4.4
)
(0.6
)
N/A
(3.6
)
(3.2
)
Six Months Ended June
30
PSCo
NSP-Minnesota
SPS
NSP-Wisconsin
Xcel Energy
Actual
Electric residential
4.2
%
(8.3
)%
4.2
%
(6.8
)%
(1.9
)%
Electric C&I
(0.2
)
(4.5
)
7.2
(2.6
)
0.3
Total retail electric sales
1.2
(5.7
)
6.6
(3.8
)
(0.3
)
Firm natural gas sales
(9.3
)
(13.6
)
N/A
(13.4
)
(10.9
)
Six Months Ended June
30
PSCo
NSP-Minnesota
SPS
NSP-Wisconsin
Xcel Energy
Weather-Normalized
Electric residential
0.3
%
—
%
(1.7
)%
(2.2
)%
(0.3
)%
Electric C&I
(1.5
)
(2.9
)
6.8
(2.0
)
0.4
Total retail electric sales
(0.9
)
(2.0
)
5.3
(2.1
)
0.2
Firm natural gas sales
2.2
0.8
N/A
(3.2
)
1.4
Six Months Ended June 30 (Leap
Year Adjusted)
PSCo
NSP-Minnesota
SPS
NSP-Wisconsin
Xcel Energy
Weather-Normalized
Electric residential
(0.3
)%
(0.6
)%
(2.4
)%
(2.8
)%
(0.9
)%
Electric C&I
(2.1
)
(3.5
)
6.2
(2.5
)
(0.1
)
Total retail electric sales
(1.5
)
(2.6
)
4.7
(2.6
)
(0.4
)
Firm natural gas sales
1.3
(0.2
)
N/A
(4.1
)
0.4
Weather-normalized and leap-year adjusted
electric sales growth (decline) — year-to-date
- PSCo — Residential sales decreased due to a 1.6% decrease in
use per customer, partially offset by customer growth of 1.3%. The
C&I sales decline was related to decreased use per customer,
primarily in the manufacturing, information and real estate
sectors.
- NSP-Minnesota — Residential sales decreased due to a 2.1%
decrease in use per customer, partially offset by a 1.5% increase
in customers. C&I sales declined due to decreased use per
customer, largely in the manufacturing sector.
- SPS — Residential sales declined as a result of a 2.9% decrease
in use per customer, partially offset by 0.5% customer growth.
C&I sales increased due to higher use per customer, primarily
driven by the energy sector.
- NSP-Wisconsin — Residential sales declined due to a 3.6%
decrease in use per customer, partially offset by 0.8% increase in
customers. C&I sales decline was associated with decreased use
per customer, experienced largely in the professional services and
manufacturing sectors.
Weather-normalized and leap-year adjusted
natural gas sales growth (decline) — year-to-date
- Increase in natural gas sales was driven by residential and
C&I customer growth in all jurisdictions and increased use per
customer in PSCo. Overall residential and C&I customer growth
was 1.1% and 0.6%, respectively.
Electric Revenues — Electric revenues are impacted by
fluctuations in the price of natural gas, coal and uranium,
regulatory outcomes, market prices and seasonality. In addition,
electric customers receive a credit for PTCs generated, which
reduce electric revenue and income taxes.
(Millions of Dollars)
Three Months Ended June 30,
2024 vs. 2023
Six Months Ended June 30, 2024
vs. 2023
Recovery of lower cost of electric fuel
and purchased power
$
(155
)
$
(331
)
Wholesale generation revenues
(13
)
(31
)
PTCs flowed back to customers (offset by
lower ETR)
(3
)
(12
)
Sales and demand (a)
(25
)
(10
)
Regulatory rate outcomes (MN, CO, TX, NM,
& WI)
159
225
Non-fuel riders
36
70
Conservation and demand side management
(offset in expense)
23
43
Revenue recognition for the Texas rate
case surcharge (b)
37
37
Estimated impact of weather (net of sales
true-up)
34
27
Other, net
(35
)
(38
)
Total increase (decrease)
$
58
$
(20
)
(a)
Sales excludes weather impact, net of
sales true-up mechanism in Minnesota.
(b)
Recognition of revenue from the Texas rate
case outcome is largely offset by recognition of previously
deferred costs.
Natural Gas Revenues — Natural gas revenues vary with
changing sales, the cost of natural gas and regulatory
outcomes.
(Millions of Dollars)
Three Months Ended June 30,
2024 vs. 2023
Six Months Ended June 30, 2024
vs. 2023
Recovery of lower cost of natural gas
$
(51
)
$
(410
)
Estimated impact of weather (net of
decoupling)
(4
)
(33
)
Regulatory rate outcomes
13
35
Retail sales growth (net of
decoupling)
(1
)
9
Infrastructure and integrity riders
2
5
Other, net
3
9
Total decrease
$
(38
)
$
(385
)
Electric Fuel and Purchased Power — Expenses incurred for
electric fuel and purchased power are impacted by fluctuations in
market prices of natural gas, coal and uranium, as well as
seasonality. These incurred expenses are generally recovered
through various regulatory recovery mechanisms. As a result,
changes in these expenses are largely offset in operating revenues
and have minimal earnings impact.
Electric fuel and purchased power expenses decreased $175
million for the second quarter and $344 million year-to-date. The
decrease is primarily due to timing of fuel recovery mechanisms and
lower commodity prices.
Cost of Natural Gas Sold and Transported — Expenses
incurred for the cost of natural gas sold are impacted by market
prices and seasonality. These costs are generally recovered through
various regulatory recovery mechanisms. As a result, changes in
these expenses are largely offset in operating revenues and have
minimal earnings impact.
Natural gas sold and transported decreased $52 million for the
second quarter and $413 million year-to-date. The decrease is
primarily due to lower commodity prices and volumes.
O&M Expenses — O&M expenses increased $34 million
for the second quarter and decreased $11 million year-to-date. The
year-to-date decrease was primarily due to decreased labor and
benefit costs, gain on a land sale in the first quarter and lower
bad debt expenses, partially offset by recognition of previously
deferred costs associated with the Texas Electric Rate Case and
planned generation outages that both occurred in the second
quarter, as well as increased wildfire mitigation costs.
Depreciation and Amortization — Depreciation and
amortization increased $138 million for the second quarter and $172
million year-to-date. The year-to-date increase was largely the
result of system expansion as well as recognition of previously
deferred costs and depreciation rate changes associated with the
Texas Rate Case, partially offset by wind and nuclear life
extensions implemented in 2023 in the Minnesota Electric Rate
Case.
Interest Charges — Interest charges increased $51 million
for the second quarter and $89 million year-to-date, largely due to
increased debt levels and higher interest rates.
AFUDC, Equity and Debt — AFUDC increased $24 million for
the second quarter and $46 million year-to-date, driven by
increased investment in renewable and transmission projects.
Income Taxes — Effective income tax rate:
Three Months Ended June
30
Six Months Ended June
30
2024
2023
2024 vs. 2023
2024
2023
2024 vs. 2023
Federal statutory rate
21.0
%
21.0
%
—
%
21.0
%
21.0
%
—
%
State tax (net of federal tax effect)
5.1
5.1
—
4.9
4.9
—
(Decreases) increases:
Wind PTCs (a)
(60.3
)
(64.0
)
3.7
(36.8
)
(44.1
)
7.3
Plant regulatory differences (b)
(7.0
)
(6.3
)
(0.7
)
(6.0
)
(5.8
)
(0.2
)
Other tax credits, net NOL & tax
credit allowances
(1.3
)
(1.4
)
0.1
(0.8
)
(1.5
)
0.7
Other, net
1.4
1.6
(0.2
)
0.7
0.5
0.2
Effective income tax rate
(41.1
)%
(44.0
)%
2.9
%
(17.0
)%
(25.0
)%
8.0
%
(a)
PTCs (net of transfer discounts) are
generally 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. 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)
June 30, 2024
Percentage of Total
Capitalization
Dec. 31, 2023
Percentage of Total
Capitalization
Current portion of long-term debt
$
854
2
%
$
552
1
%
Short-term debt
802
2
785
2
Long-term debt
27,716
58
24,913
57
Total debt
29,372
62
26,250
60
Common equity
17,954
38
17,616
40
Total capitalization
$
47,326
100
%
$
43,866
100
%
Liquidity — As of July 30, 2024, 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
$
792
$
708
$
2
$
710
PSCo
700
31
669
602
1,271
NSP-Minnesota
700
12
688
129
817
SPS
500
—
500
252
752
NSP-Wisconsin
150
—
150
178
328
Total
$
3,550
$
835
$
2,715
$
1,163
$
3,878
(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 and long-term outlook assigned to Xcel Energy
Inc. and its utility subsidiaries as of July 30, 2024:
Moody’s
S&P Global Ratings
Fitch
Company
Credit Type
Rating
Outlook
Rating
Outlook
Rating
Outlook
Xcel Energy Inc.
Unsecured
Baa1
Stable
BBB
Negative
BBB+
Negative
NSP-Minnesota
Secured
Aa3
Stable
A
Negative
A+
Stable
NSP-Wisconsin
Secured
Aa3
Negative
A
Negative
A+
Stable
PSCo
Secured
A1
Stable
A
Negative
A+
Stable
SPS
Secured
A3
Stable
A-
Negative
A-
Stable
Xcel Energy Inc.
Commercial paper
P-2
A-2
F2
NSP-Minnesota
Commercial paper
P-1
A-2
F2
NSP-Wisconsin
Commercial paper
P-1
A-2
F2
PSCo
Commercial paper
P-2
A-2
F2
SPS
Commercial paper
P-2
A-2
F2
2024 Financing Activity — During 2024, Xcel Energy Inc.
and its utility subsidiaries issued the following long-term debt.
No further debt issuances are planned for 2024.
Issuer
Security
Amount (in millions)
Tenor
Coupon
Xcel Energy Inc.
Senior Unsecured Notes
$
800
10 Year
5.50
%
NSP-Minnesota
First Mortgage Bonds
700
30 Year
5.40
PSCo
First Mortgage Bonds
1,200
10 Year & 30 Year
5.35 & 5.75
SPS
First Mortgage Bonds
600
30 Year
6.00
NSP-Wisconsin
First Mortgage Bonds
400
30 Year
5.65
Xcel Energy issued approximately $93 million of equity through
its at-the-market program through June 2024.
Financing plans are subject to change, depending on capital
expenditures, regulatory outcomes, internal cash generation, market
conditions, changes in tax policies and other factors.
Note 4. Rates, Regulation and
Other
NSP-Minnesota — 2024 Minnesota Natural Gas Rate
Case — In November 2023, NSP-Minnesota filed a request with the
Minnesota Public Utilities Commission (MPUC) for a natural gas rate
increase of approximately $59 million, or 9.6%. The request is
based on a ROE of 10.2%, a 52.5% equity ratio and a 2024 forward
test year with rate base of approximately $1.27 billion. In
December 2023, the MPUC approved NSP-Minnesota’s request for
interim rates, subject to refund, of approximately $51 million
(implemented on Jan. 1, 2024).
In June 2024, NSP-Minnesota and various parties filed an
uncontested settlement, which includes the following terms:
- Natural gas rate increase of $46 million, or 7.5%.
- ROE of 9.6%.
- Equity ratio of 52.5%.
- Rate base of $1.25 billion.
- No change to Commission approved decoupling.
A MPUC decision and order is expected by the end of 2024.
NSP-Minnesota — North Dakota Natural Gas Rate Case
— In December 2023, NSP-Minnesota filed a request with the North
Dakota Public Service Commission (NDPSC) seeking an increase in
natural gas rates of $8.5 million (9.4%), based on a ROE of 10.20%,
an equity ratio of 52.5%, 2024 test year and rate base of $168
million. In February 2024, the NDPSC approved interim rates of $8
million, effective March 1, 2024.
In June 2024, the North Dakota staff filed testimony and
recommended a $6.3 million increase (7%), based on a ROE of 9.8%
and a 50% equity ratio.
The procedural schedule is as follows:
- Surrebuttal testimony: Aug. 12-26, 2024
- Evidentiary hearings: Sept. 3-5, 2024
A NDPSC decision is expected by year-end.
NSP-Minnesota — Minnesota 2023 Fuel Clause
Adjustment — In March 2024, NSP-Minnesota filed its annual fuel
clause adjustment true-up petition to the MPUC, with a proposed
refund of $126 million for fuel over-recoveries in 2023. In April
2024, the Department of Commerce (DOC) recommended the MPUC approve
the non-nuclear aspects of the petition.
In May 2024, the DOC and Minnesota Office of Attorney General
(OAG) filed comments relating to an outage at the Prairie Island
generating station that lasted from October 2023 through February
2024. The DOC recommended that NSP-Minnesota refund $20 million of
replacement power costs for 2023 as well as a future refund of
replacement power costs for 2024 once those costs are known. The
OAG recommended that NSP-Minnesota refund $18 million of
replacement power costs for 2023 and did not address 2024.
In July 2024, NSP-Minnesota filed reply comments in the 2023
proceeding in support of its position that no customer refund for
replacement power costs is warranted. A final decision by the MPUC
is expected in late 2024.
NSP-Minnesota — Sherco Unit 3 — In May 2024, the
Administrative Law Judge (ALJ) recommended a customer refund of $34
million (less a portion of the proceeds received from the
settlement with GE) related to purchase power costs incurred during
a Sherco Unit 3 outage in 2011. The ALJ indicated that
consideration of the $22 million of previously disallowed costs was
not in the scope of their recommendation. Xcel Energy has recorded
an estimate for a customer refund in this matter. A final decision
by the MPUC is expected in late 2024.
NSP-Wisconsin — Wisconsin 2025 Stay-Out Proposal — In
June 2024, NSP-Wisconsin filed a 2025 stay-out proposal with the
Public Service Commission of Wisconsin. The filing proposes to
offset $28 million and $3 million of the Company’s forecasted 2025
electric and natural gas revenue deficiency, respectively, by
amortizing Inflation Reduction Act (IRA) deferrals, stopping a
deferral related to IRA benefits ordered in a previous rate case,
and deferring revenue requirement impacts of two gas capital
projects. The Company expects to have a Commission decision before
year-end 2024.
PSCo — Colorado Natural Gas Rate Case — In January
2024, PSCo filed a request with the Colorado Public Utilities
Commission (CPUC) seeking an increase to retail natural gas rates
of $171 million (9.5%). The request is based on a 10.25% ROE, an
equity ratio of 55%, a 2023 test year and a $4.2 billion retail
rate base which includes projected capital additions through Dec.
31, 2023. PSCo has requested a proposed effective date of Nov. 1,
2024.
PSCo has proposed to defer collection of the increased rates
until Feb. 15, 2025 (following expiration of the rider to recover
Winter Storm Uri costs) to mitigate customer bill impacts, with
revenues for the deferred period collected over a 12-month period
beginning on that date.
In July 2024, three intervenors filed testimony, with CPUC Staff
(Staff) and the Utility Consumer Advocate (UCA) filing
comprehensive testimony. Staff and UCA opposed the deferral of
collections until Feb. 15, 2025, instead proposing Nov. 1, 2024 as
the effective date for new rates.
Proposed modifications:
(Millions of Dollars)
Staff
UCA
PSCo Direct Testimony
$
171
$
171
Recommended adjustments:
ROE
(40
)
(31
)
Capital structure and cost of capital
(27
)
(a)
(14
)
Test year adjustments to reflect average
vs. year-end balances
(19
)
(17
)
Capital adjustments (subject to separate
review)
(3
)
(1
)
Depreciation expense
15
—
Other, net
(4
)
(17
)
Total adjustments
(78
)
(80
)
Proposed revenue change
$
93
$
91
ROE
8.89
%
9.20
%
Equity ratio
52
%
51.4
%
Test Year
Dec 2023
Dec 2023
Rate Base Convention
13 month
13 month
(a)
Revised estimate.
Procedural schedule:
- Rebuttal testimony: Aug. 15, 2024
- Settlement deadline: Aug. 27, 2024
- Evidentiary hearing: Sept. 4-12, 2024
- Statement of position: Sept. 26, 2024
A CPUC decision is expected in the fourth quarter of 2024.
PSCo — Wildfire Mitigation Plan — In June 2024,
PSCo filed an Updated Wildfire Mitigation Plan (the Plan) and
request for recovery of costs covering the years 2025 to 2027 with
the CPUC. The estimated total cost for this plan is approximately
$1.9 billion. A CPUC decision is expected in early 2025.
The Plan is a key component of keeping our customers and
communities safe while providing reliable and affordable electric
service. The Plan integrates industry experience; incorporates
evolving risk assessment methodologies; adds new technology; and
expands the scope, pace and scale of our work to reduce wildfire
risk in a comprehensive and efficient manner under four core
programs that include the following:
- Situational awareness – Meteorology, area risk mapping and
modeling, artificial intelligence cameras and continuous
monitoring.
- Operational mitigations – Enhanced powerline safety settings
and public safety power shutoffs (PSPS).
- System resiliency – Asset assessment and remediations, pole
replacements, line rebuilds, targeted undergrounding and vegetation
management.
- Customer support – Coordination and real-time data sharing with
customers and other stakeholders and PSPS resiliency rebates.
Total capital investments and O&M expenses associated with
the proposed plan are estimated at the following:
(Millions of Dollars)
2025
2026
2027
Total
Capital investments
Situational awareness
$
24
$
17
$
10
$
51
Operational mitigations
58
66
83
207
System resiliency
368
411
565
1,344
Total capital investments
$
450
$
494
$
658
$
1,602
O&M expenses
Situational awareness
$
9
$
10
$
10
$
29
Operational mitigations
3
3
4
10
System resiliency
44
69
77
190
Customer support
7
8
9
24
Total O&M expenses
63
90
100
253
Total expenditures
$
513
$
584
$
758
$
1,855
PSCo — Clean Heat Plan — In August of 2023, PSCo filed a
Clean Heat Plan to reduce natural gas local distribution company
greenhouse gas emissions. PSCo proposed a diversified portfolio of
electrification, efficiency and lower-carbon gas options that would
create an emissions reduction pathway through 2028 consistent with
achieving a 2030 target reduction of 22 percent.
In June 2024, the CPUC approved a portfolio weighted
predominantly toward electrification and efficiency programs, based
on a budget of $441 million through 2027. The CPUC’s approval
included rider cost recovery. The CPUC directed PSCo to file the
next Clean Heat Plan in 2026.
SPS — New Mexico Resource Plan (IRP) — In October
2023, SPS filed its IRP with the New Mexico Public Regulation
Commission (NMPRC), which supports projected load growth and
increasing reliability requirements, and secures replacement energy
and capacity for retiring resources. SPS’ initial IRP modeling
projected resource needs ranging from approximately 5,300 MW to
10,200 MW by 2030. In February 2024, the NMPRC accepted the
IRP.
In July 2024, SPS issued a request for proposal (RFP), seeking
approximately 3,000 MW of accredited generation capacity by 2030.
The total capacity to be added to the system is expected to align
with the approximate range identified in the SPS IRP, depending on
the types of resources proposed in the RFP and their accredited
capacity factors.
The RFP will be evaluated in the first quarter of 2025. SPS is
expected to file for a certificate of need for the recommended
portfolio in the summer of 2025. The Texas and New Mexico
Commissions are expected to rule on the recommended portfolio in
2026.
Note 5. Wildfire
Litigation
2024 Smokehouse Creek Fire Complex — On February 26,
2024, multiple wildfires began in the Texas Panhandle, including
the Smokehouse Creek Fire and the 687 Reamer Fire, which burned
into the perimeter of the Smokehouse Creek Fire (together, referred
to herein as the “Smokehouse Creek Fire Complex”). The Texas
A&M Forest Service issued incident reports that determined that
the Smokehouse Creek Fire and the 687 Reamer Fire were caused by
power lines owned by SPS after wooden poles near each fire origin
failed. According to the Texas A&M Forest Service’s Incident
Viewer and news reports, the Smokehouse Creek Fire Complex burned
approximately 1,055,000 acres.
SPS is aware of approximately 21 complaints, most of which have
also named Xcel Energy Services Inc. as an additional defendant,
relating to the Smokehouse Creek Fire Complex, including one
putative class action on behalf of persons or entities who owned
rangelands or pastures that were damaged by the fire. The
complaints generally allege that SPS’s equipment ignited the
Smokehouse Creek Fire Complex and seek compensation for losses
resulting from the fire, asserting various causes of action under
Texas law. In addition to seeking compensatory damages, certain of
the complaints also seek exemplary damages. SPS has also received
approximately 141 claims for losses related to the Smokehouse Creek
Fire Complex through its claims process and has reached final
settlements on 43 of those claims. In July 2024, SPS reached a
settlement of a complaint related to one of the two fatalities
believed to be associated with the Smokehouse Creek Fire
Complex.
Texas law does not apply strict liability in determining an
electric utility company’s liability for fire-related damages. For
negligence claims under Texas law, a public utility has a duty to
exercise ordinary and reasonable care.
Potential liabilities related to the Smokehouse Creek Fire
Complex depend on various factors, including the cause of the
equipment failure and the extent and magnitude of potential
damages, including damages to residential and commercial
structures, personal property, vegetation, livestock and livestock
feed (including replacement feed), personal injuries and any other
damages, penalties, fines or restitution that may be imposed by
courts or other governmental entities if SPS is found to have been
negligent.
Based on the current state of the law and the facts and
circumstances available as of the date of this filing, Xcel Energy
believes it is probable that it will incur a loss in connection
with the Smokehouse Creek Fire Complex and accordingly has accrued
a $215 million estimated loss for the matter (before available
insurance), presented in other current liabilities as of June 30,
2024.
The aggregate liability of $215 million for claims in connection
with the Smokehouse Creek Fire Complex (before available insurance)
corresponds to the lower end of the range of Xcel Energy’s
reasonably estimable range of losses, and is subject to change
based on additional information. This $215 million estimate does
not include, among other things, amounts for (i) potential
penalties or fines that may be imposed by governmental entities on
Xcel Energy, (ii) exemplary or punitive damages, (iii) compensation
claims by federal, state, county and local government entities or
agencies, (iv) compensation claims for damage to trees, railroad
lines, or oil and gas equipment, or (v) other amounts that are not
reasonably estimable.
Xcel Energy remains unable to reasonably estimate any additional
loss or the upper end of the range because there are a number of
unknown facts and legal considerations that may impact the amount
of any potential liability. In the event that SPS or Xcel Energy
Services Inc. was found liable related to the litigation related to
the Smokehouse Creek Fire Complex and was required to pay damages,
such amounts could exceed our insurance coverage of approximately
$500 million for the annual policy period and could have a material
adverse effect on our financial condition, results of operations or
cash flows.
The process for estimating losses associated with potential
claims related to the Smokehouse Creek Fire Complex requires
management to exercise significant judgment based on a number of
assumptions and subjective factors, including the factors
identified above and estimates based on currently available
information and prior experience with wildfires. As more
information becomes available, management estimates and assumptions
regarding the potential financial impact of the Smokehouse Creek
Fire Complex may change.
SPS records insurance recoveries when it is deemed probable that
recovery will occur, and SPS can reasonably estimate the amount or
range. SPS has recorded an insurance receivable for $215 million,
presented within prepayments and other current assets as of June
30, 2024. While SPS plans to seek recovery of all insured losses,
it is unable to predict the ultimate amount and timing of such
insurance recoveries.
Marshall Wildfire Litigation — In December 2021, a
wildfire ignited in Boulder County, Colorado (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 (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.
PSCo is aware of 307 complaints, most of which have also named
Xcel Energy Inc. and Xcel Energy Services Inc. as additional
defendants, relating to the Marshall Fire. The complaints are on
behalf of at least 4,087 plaintiffs. 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, wrongful death, willful and
wanton conduct, negligent infliction of emotional distress, loss of
consortium and inverse condemnation. In addition to seeking
compensatory damages, certain of the complaints also seek exemplary
damages.
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. At the case
management conference in February 2024, a trial date was set for
September 2025. Discovery is now underway.
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.
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. Under Colorado law, in a civil action filed before Jan.
1, 2025, other than a medical malpractice action, the total award
for noneconomic loss is capped at $0.6 million per defendant unless
the court finds justification to exceed that amount by clear and
convincing evidence, in which case the maximum doubles.
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.
Note 6. Earnings Guidance and Long-Term
EPS and Dividend Growth Rate Objectives
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 actual 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%.
- Weather-normalized retail firm natural gas sales are projected
to be flat.
- Capital rider revenue is projected to increase $60 million to
$70 million (net of PTCs).
- O&M expenses are projected to increase 1% to 2%.
- Depreciation expense is projected to increase approximately
$305 million to $315 million.
- Property taxes are projected to be flat. This change is largely
earnings neutral and is offset in revenue due to property tax
trackers.
- Interest expense (net of AFUDC - debt) is projected to increase
$140 million to $150 million, net of interest income.
- AFUDC - equity is projected to increase $65 million to $75
million.
- ETR is projected to be ~(6%) to (8%). The assumption change is
largely due to an increase in the PTC rate, which is offset in
revenue and is largely earnings neutral. The negative ETR is
largely offset by PTCs flowing back to customers in capital riders
and fuel mechanisms and is largely earnings neutral. The projected
ETR does not reflect the potential impact of nuclear PTCs, which
are also expected to flow back to customers.
(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 actual ongoing earnings base of $3.35 per share.
- Deliver annual dividend increases of 5% to 7%.
- Target a dividend payout ratio of 50% to 60%.
- 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 June
30
2024
2023
Operating revenues:
Electric and natural gas
$
3,014
$
2,994
Other
14
28
Total operating revenues
3,028
3,022
Net income
$
302
$
288
Weighted average diluted common shares
outstanding
557
552
Components of EPS —
Diluted
Regulated utility
$
0.66
$
0.60
Xcel Energy Inc. and other costs
(0.12
)
(0.08
)
GAAP and ongoing diluted EPS
(a)
$
0.54
$
0.52
Book value per share
$
32.24
$
30.66
Cash dividends declared per common
share
0.5475
0.52
Six Months Ended June
30
2024
2023
Operating revenues:
Electric and natural gas
$
6,640
$
7,045
Other
37
57
Total operating revenues
6,677
7,102
Net income
$
790
$
706
Weighted average diluted common shares
outstanding
556
551
Components of EPS —
Diluted
Regulated utility
$
1.62
$
1.43
Xcel Energy Inc. and other costs
(0.20
)
(0.15
)
GAAP and ongoing diluted EPS
(a)
$
1.42
$
1.28
Book value per share
$
32.27
$
30.69
Cash dividends declared per common
share
1.095
1.04
(a)
Amounts may not add due to rounding.
View source
version on businesswire.com: https://www.businesswire.com/news/home/20240801924578/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
Grafico Azioni Xcel Energy (NASDAQ:XEL)
Storico
Da Dic 2024 a Gen 2025
Grafico Azioni Xcel Energy (NASDAQ:XEL)
Storico
Da Gen 2024 a Gen 2025
