- GAAP 2021 first quarter EPS was $0.67 compared with $0.56 in
2020.
- Xcel Energy reaffirms 2021 EPS earnings guidance of $2.90 to
$3.00.
Xcel Energy Inc. (NASDAQ: XEL) today reported 2021 first quarter
GAAP and ongoing earnings of $362 million, or $0.67 per share,
compared with $295 million, or $0.56 per share in the same period
in 2020.
Earnings reflect higher electric and natural gas margins, which
more than offset additional depreciation, interest charges and less
allowance for funds used during construction (AFUDC).
“Xcel Energy had a strong first quarter and we are reaffirming
our expectation to deliver earnings within our annual guidance
range,” said Ben Fowke, chairman and CEO. “We are also pleased to
have achieved a significant milestone, reducing carbon emission 51%
from 2005 levels, bringing us more than halfway to our vision of
delivering 100% carbon-free electricity to our customers by
2050.”
“We recently proposed significant measures in Colorado that will
transform the energy landscape and help the state continue its
clean energy leadership. Our Colorado Clean Energy Plan adds more
than 5,000 megawatts of renewable energy and accelerates the
retirement of our coal plants. The plan will reduce carbon
emissions 85% in Colorado and increase renewable energy to nearly
80% by 2030. To support this ambitious plan, we also proposed a
significant transmission expansion that would add 560 miles of new
lines to deliver renewable energy.”
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:
(888) 394-8218
International Dial-In:
(400) 120-9101
Conference ID:
7731118
The conference call also will be simultaneously broadcast and
archived on Xcel Energy’s website at www.xcelenergy.com. To access
the presentation, click on Investor Relations. If you are unable to
participate in the live event, the call will be available for
replay from 12:00 p.m. CDT on April 29 through 12:00 p.m. CDT on
May 2.
Replay Numbers
US Dial-In:
(888) 203-1112
International Dial-In:
(719) 457-0820
Access Code:
7731118
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 the 2021 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, 2020 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; operational safety, including
our nuclear generation facilities; 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; ability to recover
costs, changes in regulation and subsidiaries’ ability to recover
costs from customers; reductions in our credit ratings and the cost
of maintaining certain contractual relationships; general economic
conditions, including inflation rates, monetary fluctuations and
their impact on capital expenditures and 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; and costs of potential regulatory
penalties.
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 March
31
2021
2020
Operating revenues
Electric
$
2,870
$
2,203
Natural gas
647
583
Other
24
25
Total operating revenues
3,541
2,811
Operating expenses
Electric fuel and purchased power
1,386
797
Cost of natural gas sold and
transported
299
285
Cost of sales — other
8
9
Operating and maintenance expenses
584
579
Conservation and demand side management
expenses
73
74
Depreciation and amortization
521
463
Taxes (other than income taxes)
163
149
Total operating expenses
3,034
2,356
Operating income
507
455
Other income (expense), net
5
(11
)
Equity earnings of unconsolidated
subsidiaries
14
11
Allowance for funds used during
construction — equity
14
23
Interest charges and financing
costs
Interest charges — includes other
financing costs of $7 and $7, respectively
205
199
Allowance for funds used during
construction — debt
(5
)
(10
)
Total interest charges and financing
costs
200
189
Income before income taxes
340
289
Income tax benefit
(22
)
(6
)
Net income
$
362
$
295
Weighted average common shares
outstanding:
Basic
538
526
Diluted
539
527
Earnings per average common
share:
Basic
$
0.67
$
0.56
Diluted
0.67
0.56
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), electric margin, natural gas margin,
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 excludes (or
includes) amounts that are adjusted from 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.
Electric and Natural Gas
Margins
Electric margin is presented as electric revenues less electric
fuel and purchased power expenses. Natural gas margin is presented
as natural gas revenues less the cost of natural gas sold and
transported. Expenses incurred for electric fuel and purchased
power and the cost of natural gas are generally recovered through
various regulatory recovery mechanisms. As a result, changes in
these expenses are generally offset in operating revenues.
Management believes electric and natural gas margins provide the
most meaningful basis for evaluating our operations because they
exclude the revenue impact of fluctuations in these expenses. These
margins can be reconciled to operating income, a GAAP measure, by
including other operating revenues, cost of sales - other,
operating and maintenance (O&M) expenses, conservation and
demand side management (DSM) expenses, depreciation and
amortization and taxes (other than income taxes).
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 is calculated
by dividing the net income or loss of each subsidiary, 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 of 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 months ended March 31, 2021 and
2020, 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 2021 first quarter earnings were $0.67 per share
compared to $0.56 per share in 2020, primarily reflecting higher
electric and natural gas margins (driven by capital investment
recovery and regulatory outcomes), which more than offset
additional depreciation, interest charges, less AFUDC and declining
sales primarily due to the impacts of COVID-19. First quarter
earnings also reflect margin from proprietary commodity trading
transactions, primarily entered into under Xcel Energy’s ordinary
practices prior to the weather event. See Note 5 for further
discussion.
Summarized diluted EPS for Xcel Energy:
Three Months Ended March
31
Diluted Earnings (Loss) Per
Share
2021
2020
PSCo
$
0.31
$
0.24
NSP-Minnesota
0.24
0.20
SPS
0.11
0.08
NSP-Wisconsin
0.06
0.06
Equity earnings of unconsolidated
subsidiaries
0.01
0.01
Regulated utility (a)
0.73
0.60
Xcel Energy Inc. and Other
(0.06
)
(0.04
)
Total (a)
$
0.67
$
0.56
(a) Amounts may not add due to rounding.
PSCo — Earnings increased $0.07 per share for the first
quarter of 2021, reflecting higher natural gas and electric margins
(primarily capital investment recovery and regulatory outcomes),
partially offset by additional depreciation and taxes (other than
income taxes).
NSP-Minnesota — Earnings increased $0.04 per share for
the first quarter of 2021, reflecting higher electric margin
(primarily capital investment recovery), partially offset by
increased depreciation.
SPS — Earnings increased $0.03 per share for the first
quarter of 2021, reflecting higher electric margin (regulatory
outcomes in Texas and New Mexico), partially offset by increased
depreciation.
NSP-Wisconsin — Earnings were flat for the first quarter
of 2021.
Xcel Energy Inc. and Other — Primarily includes financing
costs at the holding company.
Components significantly contributing to changes in 2021 EPS
compared to 2020:
Diluted Earnings (Loss) Per
Share
Three Months Ended March
31
GAAP and ongoing diluted EPS -
2020
$
0.56
Components of change - 2021 vs. 2020
Higher electric margin
0.11
Higher natural gas margins
0.07
Lower ETR (a)
0.06
Higher other income (expense), net
0.02
Higher depreciation and amortization
(0.08
)
Lower AFUDC
(0.02
)
Higher interest charges
(0.01
)
Higher O&M
(0.01
)
Other, net
(0.03
)
GAAP and ongoing diluted EPS -
2021
$
0.67
(a) Includes production tax credits (PTCs) and plant regulatory
amounts, which are primarily offset in electric margin.
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.
Degree-day or Temperature-Humidity Index (THI) data is used to
estimate amounts of energy required to maintain comfortable indoor
temperature levels based on each day’s average temperature and
humidity. Heating degree-days (HDD) is the measure of the variation
in the weather based on the extent to which the average daily
temperature falls below 65° Fahrenheit. Cooling degree-days (CDD)
is the measure of the variation in the weather based on the extent
to which the average daily temperature rises above 65° Fahrenheit.
Each degree of temperature above 65° Fahrenheit is counted as one
CDD, and each degree of temperature below 65° Fahrenheit is counted
as one HDD. In Xcel Energy’s more humid service territories, a THI
is used in place of CDD, which adds a humidity factor to CDD. HDD,
CDD and THI are most likely to impact the usage of Xcel Energy’s
residential and commercial customers. Industrial customers are less
sensitive to weather. Typically, sales are not impacted in the
first or fourth quarter due to THI or CDD.
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.
Percentage increase (decrease) in normal and actual HDD:
Three Months Ended March
31
2021 vs. Normal
2020 vs. Normal
2021 vs. 2020
HDD
1.3
%
(5.5)
%
6.5
%
Weather — Estimated impact of temperature variations on
EPS compared with normal weather conditions:
Three Months Ended March
31
2021 vs. Normal
2020 vs. Normal
2021 vs. 2020
Retail electric
$
—
$
(0.011
)
$
0.011
Decoupling and sales true-up
0.002
0.006
(0.004
)
Electric total
$
0.002
$
(0.005
)
$
0.007
Firm natural gas
0.003
(0.007
)
0.010
Total
$
0.005
$
(0.012
)
$
0.017
Sales — Sales growth (decline) for actual and
weather-normalized sales in 2021 compared to 2020:
Three Months Ended March
31
PSCo
NSP-Minnesota
SPS
NSP-Wisconsin
Xcel Energy
Actual (a)
Electric residential
6.3
%
5.1
%
8.8
%
4.7
%
6.0
%
Electric C&I
(4.8
)
(6.6
)
(7.1
)
(1.8
)
(5.8
)
Total retail electric sales
(1.0
)
(2.9
)
(4.3
)
0.2
(2.4
)
Firm natural gas sales
4.7
0.5
N/A
0.8
3.1
Three Months Ended March
31
PSCo
NSP-Minnesota
SPS
NSP-Wisconsin
Xcel Energy
Weather-Normalized (a)
Electric residential
4.9
%
4.5
%
3.8
%
2.9
%
4.4
%
Electric C&I
(5.1
)
(6.7
)
(7.3
)
(1.9
)
(6.0
)
Total retail electric sales
(1.7
)
(3.1
)
(5.4
)
(0.4
)
(3.0
)
Firm natural gas sales
(0.9
)
(1.3
)
N/A
(2.7
)
(1.2
)
Three Months Ended March 31
(2020 Leap Year Adjusted)
PSCo
NSP-Minnesota
SPS
NSP-Wisconsin
Xcel Energy
Weather-Normalized (a)
Electric residential
6.1
%
5.7
%
5.0
%
4.0
%
5.6
%
Electric C&I
(4.1
)
(5.6
)
(6.3
)
(0.8
)
(5.0
)
Total retail electric sales
(0.6
)
(2.0
)
(4.3
)
0.7
(1.9
)
Firm natural gas sales
0.2
(0.2
)
N/A
(1.5
)
—
(a) Higher residential sales and lower commercial and industrial
(C&I) sales were primarily attributable to COVID-19.
Weather-normalized and leap-year adjusted
electric sales growth (decline) — year-to-date (excluding leap
day)
Each of our utility subsidiaries experienced higher residential
sales and lower C&I sales as a result of COVID-19 beginning in
March 2020. In addition, the following items impacted sales:
- PSCo — Residential sales rose based on an increased number of
customers and higher use per customer. The decline in C&I sales
was primarily due to decreases in the manufacturing and service
industries, partially offset by an increase in the energy
sector.
- NSP-Minnesota — Residential sales growth reflects higher use
per customer and increased customer additions. The decline in
C&I sales was primarily due to decreases within the
manufacturing and service sectors.
- SPS — Residential sales increased due to customer growth and
higher use per customer. The decline in C&I sales was driven by
decreases within the energy and manufacturing sectors.
- NSP-Wisconsin — Residential sales growth was attributable to
customer additions and higher use per customer. The decline in
C&I sales was largely related to decreases in the energy and
manufacturing industries, partially offset by an increase in the
service sector.
Weather-normalized and leap-year adjusted
natural gas sales growth (decline) — year-to-date (excluding leap
day)
- Natural gas sales primarily reflect lower customer use, offset
by an increase in the number of customers.
Electric Margin — 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
have minimal impact on electric margin due to fuel recovery
mechanisms that recover fuel expenses. In addition, electric
customers receive a credit for PTCs generated, which reduced
electric revenue and margin. See Note 5 for discussion on the
impact of Winter Storm Uri.
Electric revenues and margin:
Three Months Ended March
31
(Millions of Dollars)
2021
2020
Electric revenues
$
2,870
$
2,203
Electric fuel and purchased power
(1,386
)
(797
)
Electric margin
$
1,484
$
1,406
Changes in electric margin:
(Millions of Dollars)
Three Months Ended March 31,
2021 vs. 2020
Non-fuel riders
$
44
Regulatory rate outcomes (Colorado, Texas,
New Mexico, Wisconsin and North Dakota)
44
Proprietary commodity trading, net of
sharing (see Note 5)
27
Wholesale transmission revenue (net)
11
Estimated impact of weather (net of
decoupling/sales true-up)
5
PTCs flowed back to customers (offset by
lower ETR)
(37
)
Sales and demand (a)
(14
)
Other (net)
(2
)
Total increase in electric margin
$
78
(a) Sales excludes weather impact, net of decoupling/sales
true-up, and demand is net of sales true-up.
Natural Gas Margin — Natural gas expense varies with
changing sales and the cost of natural gas. However, fluctuations
in the cost of natural gas has minimal impact on natural gas margin
due to cost recovery mechanisms. See Note 5 for discussion on the
impact of Winter Storm Uri.
Natural gas revenues and margin:
Three Months Ended March
31
(Millions of Dollars)
2021
2020
Natural gas revenues
$
647
$
583
Cost of natural gas sold and
transported
(299
)
(285
)
Natural gas margin
$
348
$
298
Changes in natural gas margin:
(Millions of Dollars)
Three Months Ended March 31,
2021 vs. 2020
Regulatory rate outcomes (Colorado)
$
40
Estimated impact of weather
7
Other (net)
3
Total increase in natural gas margin
$
50
O&M Expenses — O&M expenses increased $5 million,
or 0.9%, for the first quarter of 2021. The increase was primarily
due to expenses associated with new wind farms, software and
infrastructure costs, compensation, damage prevention and storms,
partially offset by continuous improvement initiatives.
Depreciation and Amortization — Depreciation and
amortization increased $58 million, or 12.5%, for the first quarter
of 2021. The increase was primarily driven by several wind farms
going into service, as well as normal system expansion. In
addition, 2021 depreciation expense increased as a result of
implementation of new depreciation rates in Colorado, New Mexico
and Texas.
Other Income (Expense) — Other income (expense) increased
$16 million for the first quarter of 2021, largely related to rabbi
trust performance primarily offset in O&M expenses
(compensation).
AFUDC, Equity and Debt — AFUDC decreased $14 million for
the first quarter of 2021. Decrease was driven by various wind
projects placed into service.
Interest Charges — Interest charges increased $6 million,
or 3.0%, for the first quarter of 2021. The increase was largely
attributable to higher debt levels to fund capital investments,
partially offset by lower long-term and short-term interest
rates.
Income Taxes — Effective income tax rate:
Three Months Ended March
31
2021
2020
2021 vs 2020
Federal statutory rate
21.0
%
21.0
%
—
%
State tax (net of federal tax effect)
4.9
4.9
—
(Decreases) increases:
Wind PTCs
(24.6
)
(17.2
)
(7.4
)
Plant regulatory differences (a)
(6.1
)
(8.4
)
2.3
Other (net)
(1.7
)
(2.4
)
0.7
Effective income tax rate
(6.5
)%
(2.1
)%
(4.4
)%
(a) Regulatory differences for income tax primarily relate to
the credit of excess deferred taxes to customers. Income tax
benefits associated with the credit of excess deferred credits are
generally offset by corresponding revenue reductions.
Income tax benefit increased $16 million for the first quarter
of 2021. The increase was primarily driven by an increase in wind
PTCs due to additional wind facilities going into service. Wind
PTCs are credited to customers (recorded as a reduction to revenue)
and do not have a material impact on net income. Impact of wind
PTCs was partially offset by higher pretax earnings in 2021.
Note 3. Capital Structure, Liquidity,
Financing and Credit Ratings
Xcel Energy’s capital structure:
(Millions of Dollars)
March 31, 2021
Percentage of Total
Capitalization
Dec. 31, 2020
Percentage of Total
Capitalization
Current portion of long-term debt
$
21
—
%
$
421
1
%
Short-term debt
1,477
4
584
2
Long-term debt
21,470
57
19,645
56
Total debt
22,968
61
20,650
59
Common equity
14,700
39
14,575
41
Total capitalization
$
37,668
100
%
$
35,225
100
%
Liquidity — As of April 26, 2021, 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.
$
1,250
$
200
$
1,050
$
3
$
1,053
PSCo
700
8
692
144
836
NSP-Minnesota
500
10
490
518
1,008
SPS
500
2
498
43
541
NSP-Wisconsin
150
—
150
2
152
Total
$
3,100
$
220
$
2,880
$
710
$
3,590
Term Loan (c)
1,200
1,200
—
(a) Expires June 2024. (b) Includes outstanding commercial paper
and letters of credit. (c) Matures February 2022.
Term Loan Agreements — In February 2021, Xcel Energy Inc.
entered into a $1.2 billion 364-Day Term Loan Agreement in order to
enhance liquidity due to the incremental fuel costs from Winter
Storm Uri and potential regulatory lag in recovery. See Note 5 for
further discussion.
Bilateral Credit Agreement — In April 2021, NSP-Minnesota
extended an uncommitted bilateral credit agreement of $75 million,
which is limited in use to support letters of credit for one-year.
NSP-Minnesota had $49 million of outstanding letters of credits as
of March 31, 2021.
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 April 26, 2021:
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
2021 Financing Activity — During 2021, Xcel Energy plans
to issue approximately $75 to $80 million of equity through the
DRIP and benefit programs. In addition, Xcel Energy Inc. and its
utility subsidiaries issued or anticipate issuing the
following:
Issuer
Security
Amount
Status
Tenor
Coupon
PSCo
First Mortgage Bonds
$
750
Completed
10 Year
1.875
%
SPS
First Mortgage Bonds
250
Completed
29 Year
3.15
NSP-Minnesota
First Mortgage Bonds
425
Completed
10 Year
2.25
NSP-Minnesota
First Mortgage Bonds
425
Completed
31 Year
3.20
NSP-Wisconsin
First Mortgage Bonds
125
Planned - Q2
N/A
N/A
Financing plans are subject to change, depending on capital
expenditures, regulatory outcomes, internal cash generation, market
conditions and other factors.
Note 4. Rates and
Regulation
NSP-Minnesota — Minnesota Relief and Recovery —
Recent proposals include:
- In February 2021, NSP-Minnesota proposed to acquire a 120 MW
repowered wind farm from ALLETE for $210 million. A MPUC decision
was requested by July 29, 2021.
- In April 2021, NSP-Minnesota proposed to add 460 MW of solar
facilities at the Sherco site with an incremental investment of
$575 million. A MPUC decision is expected in the second half of
2021.
NSP-Minnesota — 2020 North Dakota Electric Rate
Case — In November 2020 and revised in March 2021,
NSP-Minnesota filed a rate case with the North Dakota Public
Service Commission (NDPSC). NSP-Minnesota is requesting an increase
in annual retail electric revenues of approximately $19 million.
The rate filing is based on a 2021 forecast test year, a requested
ROE of 10.2%, an equity ratio of 52.5% and an electric rate base of
approximately $677 million. Interim rates, subject to refund, of
approximately $16 million were implemented in January 2021 and
subsequently revised to $13 million, effective April 1, 2021.
PSCo — Wildfire Protection Rider — In 2020, PSCo
requested to establish a rider to recover incremental costs
associated with system investments to reduce wildfire risk,
projected to be approximately $325 million from 2021 through 2025.
In February 2021, the administrative law judge (ALJ) issued a
recommended decision approving the wildfire mitigation program as
it was in the public’s interest, but denied PSCo’s rider request in
favor of deferred accounting with ultimate recovery in a future
rate case. In April 2021, the CPUC accepted the ALJ’s recommended
decision.
Forecasted annual revenue requirements from 2021 through
2025:
(Millions of Dollars)
2021
2022
2023
2024
2025
Forecasted annual revenue requirement
$
17
$
24
$
29
$
32
$
34
PSCo — Pipeline System Integrity Adjustment (PSIA)
Rider Extension — In February 2021, PSCo requested to extend
its PSIA rider for three years (through the end of 2024). The
extension is intended to allow for a wind down of the rider and
transition of recovery of the projects included in the rider to
base rates in 2025. A CPUC decision is expected in the fourth
quarter of 2021.
PSCo — Colorado’s Power Pathway Transmission Expansion
— In March 2021, PSCo filed for a Certificate of Public
Convenience and Necessity for the Power Pathway transmission
project. Xcel Energy proposed a 560-mile, 345 kV double circuit
transmission network to enable 5,500 MW of renewable generation in
eastern Colorado with an estimated cost of approximately $1.7
billion. PSCo also presented an extension of the Power Pathway
project into southeast Colorado, referred to as the May Valley -
Longhorn Extension ($0.3 billion). PSCo expects future filings for
related network upgrades, voltage support and interconnection
facilities, which with the May Valley - Longhorn Extension, could
result in an incremental investment of $0.5 - $1 billion. A CPUC
decision regarding the Power Pathway project, as well as the May
Valley - Longhorn Extension, is expected in late 2021.
PSCo — Electric Resource Plan — In March 2021,
PSCo filed its 2021 Electric Resource Plan with the CPUC. The
filing outlines the proposed future retirements/conversions of
PSCo’s remaining coal plants and would result in an 80% renewable
fuel mix and an 85% carbon emissions reduction target by 2030.
Major components of PSCo's proposed preferred plan include:
- Early retirement of Comanche Generating Station: Unit 3 in 2040
(currently 2070).
- Early retirement of Hayden Generating Station: Unit 1 in 2028
(currently 2030); Unit 2 in 2027 (currently 2036).
- Conversion of Pawnee Generating Station from coal to natural
gas in 2028 with retirement in 2041.
- 2,300 megawatts of wind power.
- 1,600 megawatts of large-scale solar power.
- 400 megawatts of energy storage.
- 1,300 megawatts of flexible dispatchable resources (including
natural gas).
- 1,200 megawatts of distributed generation solar resources.
The preferred plan proposes to create a regulatory asset to
recover costs over their original depreciation lives for the Hayden
power plant and the coal handling equipment at Pawnee. It also
proposes the use of securitization to finance and recover the
remaining book life and decommissioning costs for Comanche 3 upon
retirement in 2040.
A CPUC decision on the resource plan is expected by the end of
2021 (Phase I) with the competitive solicitation for resource
additions expected in 2022 (Phase II). Incremental generation
system costs to meet carbon emission reduction targets are proposed
to be recovered through a statutorily-authorized Clean Energy Plan
Rider.
SPS — New Mexico 2021 Electric Rate Case — In January
2021, SPS filed an electric rate case with the New Mexico Public
Regulation Commission (NMPRC) seeking an increase in base rates of
approximately $88 million. SPS’ net rate increase to New Mexico
customers is expected to be approximately $48 million, or 10%, as a
result of offsetting fuel cost reductions and PTCs from the
Sagamore wind project. PTCs are being credited to customers through
the fuel clause.
The request is based on a historic test year ended Sept. 30,
2020, including expected capital additions through Feb. 28, 2021, a
ROE of 10.35%, an equity ratio of 54.72% and a retail rate base of
approximately $1.9 billion.
The request includes the effect of approximately 400 MW of
reduced peak load in 2021 from a wholesale transmission customer
and changes to depreciation lives of SPS’ Tolk coal-fired power
plant (from 2037 to 2032) and the coal handling assets at the
Harrington facility (to 2024).
Procedural schedule expected to be as follows:
- Staff and intervenor testimony — May 17, 2021.
- Rebuttal testimony — June 9, 2021.
- Deadline to file stipulation — June 23, 2021.
- Public hearing or hearing on stipulation — July 26 - Aug. 6,
2021.
- End of nine month suspension — Nov. 3, 2021.
A NMPRC decision and implementation of final rates is
anticipated in the fourth quarter of 2021.
SPS — Texas 2021 Electric Rate Case — In February 2021,
SPS filed an electric rate case with the Public Utilities
Commission of Texas (PUCT) and its municipalities with original
rate jurisdiction seeking an increase in base rates of
approximately $143 million. SPS’ net rate increase to Texas
customers is expected to be approximately $74 million, or 9.2%, as
a result of offsetting $69 million in fuel cost reductions and PTCs
from the Sagamore wind project.
The request is based on an ROE of 10.35%, an equity ratio of
54.60% (based on actual capital structure), a Texas retail rate
base of approximately $3.3 billion and a historic test year based
on the 12-month period ended Dec. 31, 2020.
The request includes the effect of losing approximately 400 MW
from a wholesale transmission customer and changes to depreciation
lives of SPS’ Tolk power plant (from 2037 to 2032) and the coal
handling assets of the Harrington facility (to 2024).
Procedural schedule expected to be as follows:
- Intervenor testimony — Aug. 13, 2021.
- Staff testimony — Aug. 20, 2021.
- Rebuttal testimony — Sept. 15, 2021.
- Public hearing — Oct. 18 - Oct. 28, 2021.
Once final rates are approved, a surcharge will be requested
from March 15, 2021 through the effective date of new base rates. A
PUCT decision is expected in the first quarter of 2022.
Note 5. Winter Storm Uri
In mid-February 2021, the central portion of the United States
experienced a major winter storm (Winter Storm Uri). Extreme cold
temperatures impacted certain operational assets as well as the
availability of renewable generation across the region. The cold
weather also affected the country’s supply and demand for natural
gas. These factors contributed to extremely high market prices for
natural gas and electricity. In addition, NSP-Minnesota’s three
peak shaving plants, which are used to ensure system reliability
under Design Day conditions, have been unavailable since early 2021
due to required repairs to address safety concerns with the units.
Despite the extreme conditions, Xcel Energy’s customers experienced
minimal disruptions as a result of preemptive infrastructure
investments and the response of our employees.
As a result of the extremely high market prices, Xcel Energy
incurred net natural gas, fuel and purchased energy costs of
approximately $965 million (largely deferred as regulatory assets).
The utility subsidiaries mitigated the customer impact by
approximately $190 million primarily through sales of excess
generation.
The estimated net impact was as follows:
(in millions)
Natural Gas for
Distribution
Natural Gas for Electric
Generation
Other Electric
Generation
Subtotal Costs
Net Market Settlements
(a)
Total Impact
NSP-Minnesota
$
250
$
5
$
15
$
270
$
(40
)
$
230
NSP- Wisconsin
45
—
—
45
—
45
PSCo
305
315
5
625
(15
)
610
SPS
—
200
15
215
(135
)
80
Total
$
600
$
520
$
35
$
1,155
$
(190
)
$
965
(a) Net market settlements includes purchases of energy and
other charges to serve our customers as well as sales of energy
facilitated through Independent System Operators (ISOs) or
bilateral transactions, each subject to mechanisms for recovery and
sharing with our customers.
In addition, higher market prices resulted in $27 million of net
gains (after customer sharing) related to proprietary commodity
trading. These transactions were primarily entered into under Xcel
Energy’s ordinary trading practices prior to Winter Storm Uri.
Certain energy transactions are subject to final ISO
re-settlement calculations and the impacts of credit losses shared
among market participants. Such adjustments are not expected to be
material to our results of operations, financial condition or cash
flows.
Regulatory Overview — Xcel Energy has natural gas, fuel
and purchased energy mechanisms in each jurisdiction for the
purpose of recovering incurred costs. However, the utility
subsidiaries have deferred February cost increases for future
recovery and are proposing to recover the cost increases over a
period of up to two years in order to significantly mitigate the
impact to customer bills. Additionally, we are not requesting
recovery of associated financing costs in order to further limit
the impact to our customers. The following proceedings have been
initiated:
Utility Subsidiary
Jurisdiction
Regulatory Status
NSP-Minnesota
Minnesota
NSP-Minnesota has filed its report with
the MPUC detailing its preparedness and actions during the storm
and proposing recovery of incremental costs from natural gas
customers over 24 months with no financing charge. Comments are due
in May 2021.
South Dakota
In April, NSP-Minnesota filed a letter
with the South Dakota Public Utilities Commission noting that we
were a net seller in the market, resulting in lower fuel clause
costs.
North Dakota
NSP-Minnesota has filed its report with
the NDPSC detailing its preparedness and actions during the storm
and proposing recovery of incremental costs from natural gas
customers over 24 months with no financing charge.
NSP-Wisconsin
Wisconsin
In March, the Public Service Commission of
Wisconsin staff determined the natural gas costs incurred during
the storm were prudent and approved NSP-Wisconsin's proposal to
recover these costs over a nine-month period through December 2021
with no financing charge.
Michigan
In March, NSP-Wisconsin filed testimony in
the pending gas recovery plan proceeding to address $2 million of
under-recovery associated with Winter Storm Uri.
PSCo
Colorado
PSCo filed an initial response with the
CPUC in March. In May 2021, PSCo intends to file a plan to recover
the weather-related costs over 24 months with no financing
charge.
SPS
Texas
SPS intends to file for a surcharge in the
second quarter to recover fuel costs over 24 months with no
financing charge. Prudence of fuel costs will be subject to review
in SPS' upcoming fuel reconciliation case.
New Mexico
The NMPRC approved SPS' requested fuel
mechanism variance to permit recovery over 24 months with no
financing charge (subject to NMPRC review).
To enhance liquidity and for the ability to propose recovering
the increased fuel costs over a longer time period (i.e., mitigate
customer bill impacts), Xcel Energy Inc. entered into a $1.2
billion 364-Day Term Loan Agreement and increased the size of its
previously planned debt issuances at the utility subsidiaries.
Note 6. Earnings Guidance and Long-Term
EPS and Dividend Growth Rate Objectives
Xcel Energy 2021 Earnings Guidance — Xcel Energy’s 2021
GAAP and ongoing earnings guidance is a range of $2.90 to $3.00 per
share.(a)
Key assumptions as compared with 2020 levels unless noted:
- Constructive outcomes in all rate case and regulatory
proceedings.
- Modest impacts from COVID-19.
- 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 relatively flat.
- Capital rider revenue is projected to increase $100 million to
$110 million (net of PTCs). PTCs are credited to customers, through
capital riders, fuel clause or base rates and results in a
reduction to electric margin.
- O&M expenses are projected to be relatively flat.
- Depreciation expense is projected to increase approximately
$155 million to $165 million. The change in depreciation expense is
largely earnings neutral and primarily reflects the timing of
deferrals and revenue recognition in the Texas rate case.
- Property taxes are projected to increase approximately $40
million to $50 million.
- Interest expense (net of AFUDC - debt) is projected to increase
$20 million to $30 million.
- AFUDC - equity is projected to decline approximately $40
million to $50 million.
- ETR is projected to be (7%) to (8%). The ETR reflects benefits
of PTCs which are credited to customers through electric margin and
will not have a material impact on net income.
(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
2020 base of $2.78 per share, which represents the mid-point of the
original 2020 guidance range of $2.73 to $2.83 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 March
31
2021
2020
Operating revenues:
Electric and natural gas
$
3,517
$
2,786
Other
24
25
Total operating revenues
3,541
2,811
Net income
$
362
$
295
Weighted average diluted common shares
outstanding
539
527
Components of EPS —
Diluted
Regulated utility
$
0.73
$
0.60
Xcel Energy Inc. and other costs
(0.06
)
(0.04
)
GAAP and ongoing diluted EPS
(a)(b)
$
0.67
$
0.56
Book value per share
$
27.29
$
25.26
Cash dividends declared per common
share
0.46
0.43
(a) For the three months ended March 31, 2021, there were no
adjustments to GAAP earnings and therefore GAAP earnings equal
ongoing earnings for these periods.
(b) Amounts may not add due to rounding.
View source
version on businesswire.com: https://www.businesswire.com/news/home/20210429005180/en/
Paul Johnson, Vice President, 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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