Xcel Energy Second Quarter 2022 Earnings Report
Xcel Energy Inc. (NASDAQ: XEL) today reported 2022 second quarter GAAP and ongoing earnings of $328 million, or $0.60 per share, compared with $311 million, or $0.58 per share in the same period in 2021.
Earnings reflect capital investment recovery and other regulatory outcomes, partially offset by higher depreciation, interest expense and operating and maintenance (O&M) expenses.
“We had a solid quarter and as a result we are reaffirming our 2022 earnings guidance of $3.10 to $3.20 per share,” said Bob Frenzel, chairman, president and CEO of Xcel Energy. “We achieved a significant regulatory milestone with approval of our Colorado Electric Resource Plan. Executing this plan and our Power Pathway transmission project will secure affordable, resilient, clean energy for our customers, reducing carbon emissions 85% in the state by 2030, generating 80% of electricity from renewable sources by the same year and retiring all coal generation in the state by Jan. 1, 2031.”
“Xcel Energy was also recently honored with several leadership awards, being inducted into the Climate Leadership Hall of Fame and receiving the Hubert H. Humphrey Public Leadership Award for groundbreaking sustainability goals.”
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:
(800) 289-0720
International Dial-In:
(400) 120-9264
Conference ID:
4087867
The conference call also will be simultaneously broadcast and archived on Xcel Energy’s website at www.xcelenergy.com. To access the presentation, click on Investors under Company. If you are unable to participate in the live event, the call will be available for replay from 12:00 p.m. CDT on July 28 through 12:00 p.m. CDT on July 31.
Replay Numbers
US Dial-In:
(888) 203-1112
International Dial-In:
(719) 457-0820
Access Code:
4087867
Except for the historical statements contained in this report, the matters discussed herein are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements, including those relating to 2022 EPS guidance, long-term EPS and dividend growth rate objectives, future sales, future expenses, future tax rates, future operating performance, estimated base capital expenditures and financing plans, projected capital additions and forecasted annual revenue requirements with respect to rider filings, expected rate increases to customers, expectations and intentions regarding regulatory proceedings, and expected impact on our results of operations, financial condition and cash flows of resettlement calculations and credit losses relating to certain energy transactions, as well as assumptions and other statements are intended to be identified in this document by the words “anticipate,” “believe,” “could,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should,” “will,” “would” and similar expressions. Actual results may vary materially. Forward-looking statements speak only as of the date they are made, and we expressly disclaim any obligation to update any forward-looking information. The following factors, in addition to those discussed in Xcel Energy’s Annual Report on Form 10-K for the fiscal year ended Dec. 31, 2021 and subsequent filings with the Securities and Exchange Commission, could cause actual results to differ materially from management expectations as suggested by such forward-looking information: uncertainty around the impacts and duration of the COVID-19 pandemic, including potential workforce impacts resulting from vaccination requirements, quarantine policies or government restrictions, and sales volatility; operational safety, including our nuclear generation facilities and other utility operations; successful long-term operational planning; commodity risks associated with energy markets and production; rising energy prices and fuel costs; qualified employee work force and third-party contractor factors; violations of our Codes of Conduct; 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, supply chain constraints and their impact on capital expenditures and/or the ability of Xcel Energy Inc. and its subsidiaries to obtain financing on favorable terms; availability or cost of capital; our customers’ and counterparties’ ability to pay their debts to us; assumptions and costs relating to funding our employee benefit plans and health care benefits; our subsidiaries’ ability to make dividend payments; tax laws; effects of geopolitical events, including war and acts of terrorism; cyber security threats and data security breaches; seasonal weather patterns; changes in environmental laws and regulations; climate change and other weather; natural disaster and resource depletion, including compliance with any accompanying legislative and regulatory changes; costs of potential regulatory penalties; and regulatory changes and/or limitations related to the use of natural gas as an energy source.
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
2022
2021
2022
2021
Operating revenues
Electric
$
2,923
$
2,597
$
5,556
$
5,467
Natural gas
476
449
1,566
1,096
Other
25
22
53
46
Total operating revenues
3,424
3,068
7,175
6,609
Operating expenses
Electric fuel and purchased power
1,181
1,047
2,275
2,433
Cost of natural gas sold and transported
251
218
961
517
Cost of sales — other
11
9
21
17
O&M expenses
614
600
1,216
1,184
Conservation and demand side management expenses
81
71
173
144
Depreciation and amortization
638
528
1,200
1,049
Taxes (other than income taxes)
179
157
350
320
Total operating expenses
2,955
2,630
6,196
5,664
Operating income
469
438
979
945
Other (expense) income, net
(6
)
3
(5
)
8
Earnings from equity method investments
11
20
26
34
Allowance for funds used during construction — equity
20
18
33
32
Interest charges and financing costs
Interest charges — includes other financing costs of $8, $7, $15 and $14, respectively
247
212
461
417
Allowance for funds used during construction — debt
(7
)
(6
)
(12
)
(11
)
Total interest charges and financing costs
240
206
449
406
Income before income taxes
254
273
584
613
Income tax benefit
(74
)
(38
)
(124
)
(60
)
Net income
$
328
$
311
$
708
$
673
Weighted average common shares outstanding:
Basic
546
539
545
539
Diluted
546
539
546
539
Earnings per average common share:
Basic
$
0.60
$
0.58
$
1.30
$
1.25
Diluted
0.60
0.58
1.30
1.25
XCEL ENERGY INC. AND SUBSIDIARIES
Notes to Investor Relations Earnings Release (Unaudited)
Due to the seasonality of Xcel Energy’s operating results, quarterly financial results are not an appropriate base from which to project annual results.
Non-GAAP Financial Measures
The following discussion includes financial information prepared in accordance with generally accepted accounting principles (GAAP), as well as certain non-GAAP financial measures such as ongoing return on equity (ROE), ongoing earnings and ongoing diluted EPS. Generally, a non-GAAP financial measure is a measure of a company’s financial performance, financial position or cash flows that adjusts measures calculated and presented in accordance with GAAP. Xcel Energy’s management uses non-GAAP measures for financial planning and analysis, for reporting of results to the Board of Directors, in determining performance-based compensation and communicating its earnings outlook to analysts and investors. Non-GAAP financial measures are intended to supplement investors’ understanding of our performance and should not be considered alternatives for financial measures presented in accordance with GAAP. These measures are discussed in more detail below and may not be comparable to other companies’ similarly titled non-GAAP financial measures.
Ongoing ROE
Ongoing ROE is calculated by dividing the net income or loss of Xcel Energy or each subsidiary, adjusted for certain nonrecurring items, by each entity’s average stockholder’s equity. We use these non-GAAP financial measures to evaluate and provide details of earnings results.
Earnings Adjusted for Certain Items (Ongoing Earnings and Ongoing Diluted EPS)
GAAP diluted EPS reflects the potential dilution that could occur if securities or other agreements to issue common stock (i.e., common stock equivalents) were settled. The weighted average number of potentially dilutive shares outstanding used to calculate Xcel Energy Inc.’s diluted EPS is calculated using the treasury stock method. Ongoing earnings reflect adjustments to GAAP earnings (net income) for certain items. Ongoing diluted EPS for Xcel Energy is calculated by dividing net income or loss, adjusted for certain items, by the weighted average fully diluted Xcel Energy Inc. common shares outstanding for the period. Ongoing diluted EPS for each subsidiary is calculated by dividing the net income or loss for such subsidiary, adjusted for certain items, by the weighted average fully diluted Xcel Energy Inc. common shares outstanding for the period.
We use these non-GAAP financial measures to evaluate and provide details of Xcel Energy’s core earnings and underlying performance. We believe these measurements are useful to investors to evaluate the actual and projected financial performance and contribution of our subsidiaries. For the three and six months ended June 30, 2022 and 2021, there were no such adjustments to GAAP earnings and therefore GAAP earnings equal ongoing earnings for these periods.
Note 1. Earnings Per Share Summary
Xcel Energy’s second quarter diluted earnings were $0.60 per share in 2022, compared with $0.58 per share in 2021. The increase was driven by regulatory recovery of capital investment, partially offset by higher depreciation, interest expense and O&M expenses. Costs for natural gas sold and transported significantly increased in 2022 primarily due to market price fluctuations. However, fluctuations in electric and natural gas revenues associated with changes in fuel and purchased power and/or natural gas sold and transported generally do not significantly impact earnings (changes in costs are offset by the related variation in revenues).
Summarized diluted EPS for Xcel Energy:
Three Months Ended June 30
Six Months Ended June 30
Diluted Earnings (Loss) Per Share
2022
2021
2022
2021
PSCo
$
0.24
$
0.25
$
0.56
$
0.56
NSP-Minnesota
0.22
0.21
0.45
0.45
SPS
0.17
0.13
0.27
0.23
NSP-Wisconsin
0.03
0.03
0.11
0.09
Earnings from equity method investments — WYCO
0.01
0.01
0.02
0.02
Regulated utility (a)
0.67
0.62
1.41
1.35
Xcel Energy Inc. and Other
(0.07
)
(0.04
)
(0.11
)
(0.10
)
Total (a)
$
0.60
$
0.58
$
1.30
$
1.25
(a)
Amounts may not add due to rounding.
PSCo — Earnings decreased $0.01 per share for the second quarter of 2022 and were flat year-to-date. Year-to-date earnings reflect a Winter Storm Uri cost disallowance (see Note 5) and unrecovered incremental purchased power costs due to the Comanche Unit 3 outage (see Note 4).
NSP-Minnesota — Earnings increased $0.01 per share for the second quarter of 2022 and were flat year-to-date, as regulatory recovery of capital investment was offset by increased depreciation and interest expense.
SPS — Earnings increased $0.04 per share for the second quarter of 2022 and year-to-date, primarily due to regulatory outcomes, strong sales growth and favorable weather.
NSP-Wisconsin — Earnings were flat for the second quarter of 2022 and increased $0.02 per share year-to-date. The year-to-date increase reflects the impact of regulatory rate outcomes, sales growth and favorable weather, partially offset by higher depreciation and O&M expenses.
Xcel Energy Inc. and Other — Primarily includes financing costs at the holding company and earnings from Energy Impact Partners (EIP) funds equity method investments.
Components significantly contributing to changes in 2022 EPS compared to 2021:
Diluted Earnings (Loss) Per Share
Three Months Ended
June 30
Six Months Ended
June 30
GAAP and ongoing diluted EPS — 2021
$
0.58
$
1.25
Components of change - 2022 vs. 2021
Higher electric revenues, net of electric fuel and purchased power
0.26
0.34
Lower effective tax rate (ETR) (a)
0.06
0.10
(Lower) higher natural gas revenues, net of cost of natural gas sold and transported
(0.01
)
0.04
Higher depreciation and amortization
(0.15
)
(0.21
)
Higher interest charges
(0.05
)
(0.06
)
Higher taxes (other than income taxes)
(0.03
)
(0.04
)
Higher O&M expenses
(0.02
)
(0.04
)
Lower other (expense) income
(0.01
)
(0.02
)
Other, net
(0.03
)
(0.06
)
GAAP and ongoing diluted EPS — 2022
$
0.60
$
1.30
(a)
Includes production tax credits (PTCs) and plant regulatory amounts, which are primarily offset as a reduction to electric revenues.
Note 2. Regulated Utility Results
Estimated Impact of Temperature Changes on Regulated Earnings — Unusually hot summers or cold winters increase electric and natural gas sales, while mild weather reduces electric and natural gas sales. The estimated impact of weather on earnings is based on the number of customers, temperature variances, the amount of natural gas or electricity historically used per degree of temperature and excludes any incremental related operating expenses that could result due to storm activity or vegetation management requirements. As a result, weather deviations from normal levels can affect Xcel Energy’s financial performance. However, decoupling mechanisms in Colorado and proposed sales true-up mechanisms in Minnesota predominately mitigate the positive and adverse impacts of weather for the electric utility.
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
2022 vs. Normal
2021 vs. Normal
2022 vs. 2021
2022 vs. Normal
2021 vs. Normal
2022 vs. 2021
Retail electric
$
0.028
$
0.056
$
(0.028
)
$
0.049
$
0.055
$
(0.006
)
Decoupling and sales true-up
(0.013
)
(0.044
)
0.031
(0.023
)
(0.041
)
0.018
Electric total
$
0.015
$
0.012
$
0.003
$
0.026
$
0.014
$
0.012
Firm natural gas
0.003
0.002
0.001
0.019
0.005
0.014
Total
$
0.018
$
0.014
$
0.004
$
0.045
$
0.019
$
0.026
Sales — Sales growth (decline) for actual and weather-normalized sales in 2022 compared to 2021:
Three Months Ended June 30
PSCo
NSP-Minnesota
SPS
NSP-Wisconsin
Xcel Energy
Actual
Electric residential
(6.3
) %
(5.9
) %
6.5
%
(3.0
) %
(4.2
) %
Electric C&I
(1.1
)
0.6
11.7
2.5
3.2
Total retail electric sales
(2.8
)
(1.4
)
10.8
0.9
1.2
Firm natural gas sales
(9.6
)
27.3
N/A
22.5
2.2
Three Months Ended June 30
PSCo
NSP-Minnesota
SPS
NSP-Wisconsin
Xcel Energy
Weather-Normalized
Electric residential
(5.0
) %
0.9
%
(1.6
) %
1.3
%
(1.7
) %
Electric C&I
(0.6
)
2.4
10.8
3.7
3.9
Total retail electric sales
(2.1
)
2.0
8.6
3.0
2.3
Firm natural gas sales
(6.0
)
12.7
N/A
11.4
0.2
Six Months Ended June 30
PSCo
NSP-Minnesota
SPS
NSP-Wisconsin
Xcel Energy
Actual
Electric residential
(3.7
) %
(0.6
) %
3.2
%
2.0
%
(1.0
) %
Electric C&I
0.8
3.5
11.0
3.6
4.7
Total retail electric sales
(0.8
)
2.2
9.4
3.1
3.0
Firm natural gas sales
(3.6
)
22.1
N/A
22.2
5.6
Six Months Ended June 30
PSCo
NSP-Minnesota
SPS
NSP-Wisconsin
Xcel Energy
Weather-Normalized
Electric residential
(3.2
) %
0.7
%
(0.8
) %
1.0
%
(1.0
) %
Electric C&I
1.0
4.1
10.4
3.9
4.8
Total retail electric sales
(0.4
)
3.0
8.2
3.0
3.1
Firm natural gas sales
(2.5
)
6.9
N/A
8.3
1.2
Weather-normalized electric sales growth (decline) — year-to-date
PSCo — Residential sales declined due to decreased use per customer, partially offset by a 1.1% increase in customers. The growth in C&I sales was due to a 1.1% increase in customers, primarily in the professional services and retail sectors. NSP-Minnesota — Residential sales growth reflects a 1.2% increase in customers, partially offset by decreased use per customer. The growth in C&I sales was primarily due to higher use per customer, particularly in the manufacturing, real estate and leasing, and food service sectors. SPS — Residential sales declined due to a lower use per customer, partially offset by a 1.0% increase in customers. C&I sales increased due to higher use per customer, primarily driven by the energy sector. NSP-Wisconsin — Residential sales growth was driven by a 0.7% increase in customers. C&I sales growth was primarily due to higher use per customer, primarily from increases in the manufacturing and transportation sectors.Weather-normalized natural gas sales growth (decline) — year-to-date
Natural gas sales reflect a higher customer use, primarily in NSP-Minnesota and NSP-Wisconsin, as well as a 1.2% increase in residential customers and a 0.5% increase in C&I customers.Electric Margin — Electric margin is presented as electric revenues less electric fuel and purchased power expenses. Expenses incurred for electric fuel and purchased power are generally recovered through various regulatory recovery mechanisms. As a result, changes in these expenses are generally offset in operating revenues.
Electric revenues and fuel and purchased power expenses are impacted by fluctuations in the price of natural gas, coal and uranium. However, these price fluctuations generally have minimal earnings impact due to fuel recovery mechanisms that recover fuel expenses. In addition, electric customers receive a credit for PTCs generated, which reduce electric revenue and income taxes.
Electric revenues, fuel and purchased power and margin and explanation of the changes are listed as follows:
Three Months Ended June 30
Six Months Ended June 30
(Millions of Dollars)
2022
2021
2022
2021
Electric revenues
$
2,923
$
2,597
$
5,556
$
5,467
Electric fuel and purchased power
(1,181
)
(1,047
)
(2,275
)
(2,433
)
Electric margin
$
1,742
$
1,550
$
3,281
$
3,034
(Millions of Dollars)
Three Months
Ended June 30,
2022 vs. 2021
Six Months
Ended June 30,
2022 vs. 2021
Regulatory rate outcomes (Minnesota, Colorado, Texas, New Mexico and Wisconsin)
$
124
$
187
Revenue recognition for the Texas rate case surcharge (a)
85
85
Sales and demand (b)
38
60
Non-fuel riders
7
41
Conservation and demand side management (offset in expense)
9
22
Estimated impact of weather (net of decoupling/sales true-up)
2
9
PTCs flowed back to customers (offset by lower ETR)
(50
)
(103
)
Proprietary commodity trading, net of sharing (c)
(8
)
(33
)
Comanche Unit 3 outage unrecovered purchased power cost (see Note 4)
(8
)
(18
)
Other (net)
(7
)
(3
)
Total increase
$
192
$
247
(a)
Recognition of revenue from the Texas rate case outcome is largely offset by recognition of previously deferred costs. See Note 4 for additional information.
(b)
Sales excludes weather impact, net of decoupling in Colorado and proposed sales true-up mechanism in Minnesota.
(c)
Includes $27 million of net gains recognized in the first quarter of 2021, driven by market changes associated with Winter Storm Uri.
Natural Gas Margin — Natural gas margin is presented as natural gas revenues less the cost of natural gas sold and transported. Expenses incurred for the cost of natural gas sold are generally recovered through various regulatory recovery mechanisms. As a result, changes in these expenses are generally offset in operating revenues.
Natural gas revenues, cost of natural gas sold and transported and margin and explanation of the changes are listed as follows:
Three Months Ended June 30
Six Months Ended June 30
(Millions of Dollars)
2022
2021
2022
2021
Natural gas revenues
$
476
$
449
$
1,566
$
1,096
Cost of natural gas sold and transported
(251
)
(218
)
(961
)
(517
)
Natural gas margin
$
225
$
231
$
605
$
579
(Millions of Dollars)
Three Months
Ended June 30,
2022 vs. 2021
Six Months
Ended June 30,
2022 vs. 2021
Regulatory rate outcomes (Minnesota, Wisconsin, North Dakota, Colorado)
$
(3
)
$
14
Estimated impact of weather
1
11
Other (net)
(4
)
1
Total (decrease) increase
$
(6
)
$
26
O&M Expenses — O&M expenses increased $14 million for the second quarter and $32 million year-to-date. O&M costs increased due to recognition of previously deferred amounts related to the Texas Electric Rate Case, additional investments in technology and customer programs and higher costs for storms and vegetation management. These increases were partially offset by a reduction in employee benefit costs and timing of certain power plant overhaul costs.
Depreciation and Amortization — Depreciation and amortization increased $110 million for the second quarter and $151 million year-to-date. The increase was primarily driven by several wind farms going into service, normal system expansion and recognition of previously deferred costs related to the Texas Electric Rate Case.
Other (Expense) Income — Other (expense) income decreased $9 million for the second quarter and $13 million year-to-date, largely related to rabbi trust performance, which is primarily offset in O&M expenses (employee benefit costs).
Interest Charges — Interest charges increased $35 million for the second quarter and $44 million year-to-date, largely due to increased long-term debt levels to fund capital investments and deferred balances related to Winter Storm Uri.
Income Taxes — Effective income tax rate:
Three Months Ended June 30
Six Months Ended June 30
2022
2021
2022 vs 2021
2022
2021
2022 vs 2021
Federal statutory rate
21.0
%
21.0
%
—
%
21.0
%
21.0
%
—
%
State tax (net of federal tax effect)
5.2
4.9
0.3
5.0
4.9
0.1
(Decreases) increases:
Wind PTCs (a)
(48.3
)
(33.1
)
(15.2
)
(40.4
)
(28.4
)
(12.0
)
Plant regulatory differences (b)
(5.5
)
(6.6
)
1.1
(5.1
)
(6.3
)
1.2
Other tax credits, net operating loss & tax credits allowances
(1.4
)
(1.0
)
(0.4
)
(1.5
)
(1.1
)
(0.4
)
Other (net)
(0.1
)
0.9
(1.0
)
(0.2
)
0.1
(0.3
)
Effective income tax rate
(29.1
) %
(13.9
) %
(15.2
) %
(21.2
) %
(9.8
) %
(11.4
) %
(a)
Wind PTCs are credited to customers (reduction to revenue) and do not materially impact net income.
(b)
Plant regulatory differences primarily relate to the credit of excess deferred taxes to customers through the average rate assumption method. Income tax benefits associated with the credit are offset by corresponding revenue reductions.
Income tax benefit increased $36 million for the second quarter and $64 million year-to-date, primarily driven by an increase in wind PTCs due to greater production at existing wind farms and several new wind farms going into service.
In April 2022, the IRS published inflation factors used to determine the PTC rate. As a result, the 2022 PTC rate on the sale of electricity produced from wind is 2.6 cents per kilowatt hour, compared to 2.5 cents for 2021.
Note 3. Capital Structure, Liquidity, Financing and Credit Ratings
Xcel Energy’s capital structure:
(Millions of Dollars)
June 30, 2022
Percentage of Total
Capitalization
Dec. 31, 2021
Percentage of Total
Capitalization
Current portion of long-term debt
$
651
2
%
$
601
1
%
Short-term debt
136
—
1,005
3
Long-term debt
23,205
58
21,779
56
Total debt
23,992
60
23,385
60
Common equity
15,971
40
15,612
40
Total capitalization
$
39,963
100
%
$
38,997
100
%
Liquidity — As of July 25, 2022, Xcel Energy Inc. and its utility subsidiaries had the following committed credit facilities available to meet liquidity needs:
(Millions of Dollars)
Credit Facility (a)
Drawn (b)
Available
Cash
Liquidity
Xcel Energy Inc.
$
1,250
$
73
$
1,177
$
5
$
1,182
PSCo
700
196
504
2
506
NSP-Minnesota
500
11
489
2
491
SPS
500
2
498
5
503
NSP-Wisconsin
150
86
64
1
65
Total
$
3,100
$
368
$
2,732
$
15
$
2,747
(a)
Expires June 2024.
(b)
Includes outstanding commercial paper and letters of credit.
Credit Ratings — Access to the capital markets at reasonable terms is partially dependent on credit ratings. The following ratings reflect the views of Moody’s, S&P Global Ratings and Fitch. The highest credit rating for debt is Aaa/AAA and the lowest investment grade rating is Baa3/BBB-. The highest rating for commercial paper is P-1/A-1/F-1 and the lowest rating is P-3/A-3/F-3. A security rating is not a recommendation to buy, sell or hold securities. Ratings are subject to revision or withdrawal at any time by the credit rating agency and each rating should be evaluated independently of any other rating.
Credit ratings assigned to Xcel Energy Inc. and its utility subsidiaries as of July 25, 2022:
Credit Type
Company
Moody’s
S&P Global Ratings
Fitch
Senior unsecured debt
Xcel Energy Inc.
Baa1
BBB+
BBB+
Senior secured debt
NSP-Minnesota
Aa3
A
A+
NSP-Wisconsin
Aa3
A
A+
PSCo
A1
A
A+
SPS
A3
A
A-
Commercial paper
Xcel Energy Inc.
P-2
A-2
F2
NSP-Minnesota
P-1
A-2
F2
NSP-Wisconsin
P-1
A-2
F2
PSCo
P-2
A-2
F2
SPS
P-2
A-2
F2
2022 Financing Activity — During 2022, Xcel Energy plans to issue approximately $75 to $80 million of equity through the DRIP and benefit programs. In addition, Xcel Energy may issue up to $800 million in equity from 2022-2026. In 2022, approximately $150 million of equity has been issued through an at-the-market program. Xcel Energy and its utility subsidiaries issued or plan to issue the following long-term debt:
Issuer
Security
Amount
Status
Tenor
Coupon
Xcel Energy
Unsecured Senior Notes
$
700
Completed
10 Year
4.60
%
PSCo
First Mortgage Bonds
300
Completed
10 Year
4.10
PSCo
First Mortgage Bonds
400
Completed
30 Year
4.50
SPS
First Mortgage Bonds
200
Completed
30 Year
5.15
NSP-Minnesota
First Mortgage Bonds
500
Completed
30 Year
4.50
NSP-Wisconsin
First Mortgage Bonds
100
Q3 (a)
30 Year
4.86
(a)
The NSP-Wisconsin private placement first mortgage bonds have been priced and the transaction is expected to close on Sept. 12, 2022.
Financing plans are subject to change, depending on legislative initiatives (e.g., federal tax law changes), capital expenditures, regulatory outcomes, internal cash generation, market conditions and other factors.
Note 4. Rates, Regulation and Other
NSP-Minnesota — 2022 Minnesota Electric Rate Case — In October 2021, NSP-Minnesota filed a three-year electric rate case with the MPUC. The rate case is based on a requested ROE of 10.2%, a 52.50% equity ratio and forward test years. The request is detailed as follows:
(Amounts in Millions, Except Percentages)
2022
2023
2024
Total
Rate request
$
396
$
150
$
131
$
677
Increase percentage
12.2
%
4.8
%
4.2
%
21.2
%
Rate base
$
10,931
$
11,446
$
11,918
N/A
In December 2021, the MPUC approved interim rates, subject to refund, of $247 million, effective Jan. 1, 2022. Next steps in the procedural schedule are expected to be as follows:
Intervenor testimony: Oct. 3, 2022. Rebuttal testimony: Nov. 8, 2022. Hearing: Dec. 13-16, 2022. Administrative Law Judge (ALJ) Report: March 31, 2023. MPUC Order: June 30, 2023.NSP-Minnesota — 2022 Minnesota Natural Gas Rate Case — In November 2021, NSP-Minnesota filed a request with the MPUC for an annual natural gas rate increase of $36 million, or 6.6%. The filing is based on a 2022 forecast test year and includes a requested ROE of 10.5%, an equity ratio of 52.5% and a rate base of $934 million. In December 2021, the MPUC approved interim rates of $25 million, subject to refund, effective Jan. 1, 2022. Next steps in the procedural schedule are expected to be as follows:
Intervenor testimony: Aug. 30, 2022. Rebuttal testimony: Oct. 4, 2022. Hearing: Nov. 1-4, 2022. ALJ Report: Feb. 6, 2023. MPUC Order: April 26, 2023.NSP-Minnesota — 2021 North Dakota Natural Gas Rate Case — In September 2021, NSP-Minnesota filed a request with the North Dakota Public Service Commission (NDPSC) for a natural gas rate increase of $7 million, or 10.5%. The filing is based on a requested ROE of 10.5%, an equity ratio of 52.54%, a 2022 forecast test year and a rate base of $124 million. Interim rates of $7 million, subject to refund, were implemented on Nov. 1, 2021.
In May 2022, NSP-Minnesota and NDPSC Staff reached a natural gas settlement, which reflects a rate increase of $5 million, based on a 9.8% ROE and 52.54% equity ratio. A NDPSC decision is expected in the third quarter of 2022.
NSP-Minnesota — 2022 South Dakota Electric Rate Case — On June 30, 2022, NSP-Minnesota filed a South Dakota electric rate case (first since 2014) seeking a revenue increase of approximately $44 million. The filing is based on a 2021 historic test year adjusted for certain known and measurable changes for 2022 and 2023, a requested return on equity of 10.75%, rate base of approximately $947 million and an equity ratio of 53%. Final rates are expected to be effective in the first quarter of 2023.
NSP-Minnesota — Wind Repowering — In January 2021, the MPUC approved NSP-Minnesota’s request for the repowering of 651 MW of owned wind projects. Two of the four repowering projects, where construction has not yet begun (in-service dates in 2025), now expect costs in excess of the original approval. Evaluation of options to mitigate the impact of these cost increases is on-going. An update to the MPUC is expected in the third or fourth quarter 2022.
NSP-Minnesota — Sherco Solar Proposal — In April 2021, NSP-Minnesota proposed to add 460 MW of solar facilities at the Sherco site with an initial estimated investment of approximately $575 million. NSP-Minnesota requested a delay in the procedural schedule due to recent solar supply chain disruptions and potential impact on pricing. An updated request was filed with the MPUC in July 2022 and a decision is now anticipated in the fourth quarter of 2022 or the first quarter of 2023. The proposed facilities are still expected to be in-service by the end of 2025.
NSP System — MISO Capacity Credits — The NSP System offered 1,500 MW of excess capacity into the Midcontinent Independent System Operator, Inc. (MISO) planning resource auction for June 2022 through May 2023. Due to a projected overall capacity shortfall in the MISO region, the 1,500 MWs offered cleared the auction at maximum pricing and is expected to generate revenues of approximately $89 million in 2022 and approximately $64 million in 2023. During the second quarter of 2022, the NSP System received approximately $13 million of capacity credits. These amounts will primarily be used to mitigate customer rate increases or returned through earnings sharing or other mechanisms.
PSCo — Resource Plan Settlement — In June 2022, the Colorado Public Utilities Commission (CPUC) verbally approved a revised settlement, which will result in the further acceleration of the retirement of the Comanche Unit 3 coal plant, an expected carbon reduction of at least 85% and an 80% renewable mix by 2030. The CPUC deferred a decision on the method of cost recovery for the retiring coal units to a separate docket, which will consider accelerated depreciation, creation of regulatory assets and securitization. PSCo expects to file a recovery method docket in the fall.
Key settlement terms include:
Early retirement of Hayden: Unit 2 in 2027 (was 2036); and Unit 1 in 2028 (was 2030). Conversion of the Pawnee coal plant to natural gas by no later than Jan. 1, 2026. Early retirement of Comanche Unit 3 by Jan. 1, 2031 (was 2070) with reduced operations beginning in 2025. Addition of ~2,400 MW of wind. Addition of ~1,600 MW of universal-scale solar. Addition of 400 MW of storage. Addition of 1,300 MW of flexible, dispatchable generation. Addition of ~1,200 MW of distributed solar resources through our renewable energy programs.PSCo — Natural Gas Rate Case — In January 2022, PSCo filed a request with the CPUC seeking a net increase to retail natural gas rates of $107 million. The total change to base rates is $215 million, which reflects the transfer of $108 million previously recovered from customers through the Pipeline System Integrity Adjustment (PSIA) rider. The request is based on a 10.25% ROE, an equity ratio of 55.66% and a 2022 current test year with a projected rate base of $3.6 billion. PSCo has requested a proposed effective date of Nov. 1, 2022. Additionally, PSCo’s request includes step revenue increases of $40 million (effective Nov. 1, 2023) and $41 million (effective Nov. 1, 2024) related to continued capital investment.
On June 15, 2022, eight parties filed testimony, with the CPUC Staff (Staff) and Office of the Utility Consumer Advocate (UCA) filing comprehensive testimony. The Staff and UCA both recommended a historic test year with average rate base and no step increases for 2023 and 2024.
Proposed modifications to PSCo's request:
2022 Rate Request (Millions of Dollars)
Staff
UCA
Filed base revenue request
$
215
$
215
Less: previously authorized costs (existing riders)
108
108
Filed net increase to revenue
107
107
Recommended adjustments:
Test year adjustments
(33
)
(41
)
ROE
(42
)
(42
)
Weather normalization adjustment
—
(7
)
Depreciation expense change
14
—
Other, net
(15
)
(5
)
Total recommended adjustments
(76
)
(95
)
Total proposed revenue change
$
31
$
12
Positions on PSCo's filed gas rate request:
Recommended Position
Staff
UCA
ROE
9.00
%
9.00
%
Equity
55.00
%
51.50
%
Test year
Historic
Historic
In July 2022, PSCo filed rebuttal testimony and updated its revenue request from $215 million to $202 million.
Next steps in the procedural schedule are expected to be as follows:
Settlement deadline: Aug. 3, 2022. Evidentiary hearings: Aug. 17-23, 2022. Statement of position: Sept. 21, 2022.PSCo — Comanche Unit 3 Outage — In late January 2022, PSCo experienced an outage at the Comanche Unit 3 coal plant. The plant returned to service in June 2022. PSCo will not seek recovery of the approximately $18 million of incremental replacement power costs, subject to true-up, incurred during the outage.
SPS — Texas 2021 Electric Rate Case — In 2021, SPS filed an electric rate case with the PUCT and its municipalities seeking an increase in base rates of approximately $140 million. In May 2022, the PUCT approved a settlement between SPS and intervening parties, which reflects the following terms:
Base rate increase of $89 million, effective retroactively to March 15, 2021. A 9.35% ROE and 7.01% weighted average cost of capital for AFUDC purposes only. Depreciation lives for Tolk accelerated to 2034 and Harrington coal assets accelerated to 2024.In July 2022, SPS filed to surcharge the final under-recovered amount, estimated to be approximately $85 million, substantially offset by the recognition of previously deferred costs.
Note 5. Winter Storm Uri
In February 2021, the United States experienced Winter Storm Uri. As a result of the extremely high market prices, Xcel Energy incurred net natural gas, fuel and purchased energy costs of approximately $1 billion.
Regulatory Overview — Xcel Energy has natural gas, fuel and purchased energy mechanisms in each jurisdiction for recovering incurred costs. However, the utility subsidiaries have deferred February 2021 cost increases for future recovery and sought recovery of the cost increases over a period of up to 63 months to mitigate the impact to customer bills. Additionally, we did not request recovery of financing costs in order to further limit the impact to our customers.
Xcel Energy currently has approval for recovery of Winter Storm Uri costs in Wisconsin, Michigan, North Dakota and New Mexico. There were no material costs for South Dakota. A summary of the pending regulatory requests for cost recovery in the other states is listed below.
Utility Subsidiary
Jurisdiction
Regulatory Status
NSP-Minnesota
Minnesota
In 2021, the MPUC allowed recovery of $179 million of costs (with no financing charge) starting in September 2021, with a potential true-up pending a prudency review. The C&I class ($82 million) will be recovered over 27 months and the residential class ($97 million) will be recovered over a 63-month recovery period.
The Department of Commerce recommended a disallowance of $122 million, the Office of the Attorney General recommended disallowances of $110 million to $148 million and the Citizens Utility Board recommended a $69 million disallowance.
In May 2022, the ALJs found the Winter Storm Uri fuel costs were prudently incurred and recommended no disallowances. A MPUC decision is expected in August 2022.
PSCo
Colorado
In May 2021, PSCo filed a request with the CPUC to recover $263 million in weather-related electric costs, $287 million in incremental natural gas costs and $4 million in incremental steam costs over 24 months with no financing charge.
In October, a partial settlement was reached with the Staff and the Colorado Energy Office, allowing full recovery of the Winter Storm Uri costs over a 24-month (electric) and 30-month period (natural gas), with no carrying charges. In May 2022, an ALJ recommended full recovery of all costs with no cost disallowances. In July 2022, the CPUC approved the partial settlement, but included an $8 million disallowance.
SPS
Texas
In 2021, SPS filed to recover $88 million of Winter Storm Uri costs over 24 months, as part of the Texas fuel surcharge filing, with total under-recovered costs of $121 million.
In April 2022, interim rates designed to recover $121 million over 30 months were implemented. The interim rate recovery does not address the prudence of costs nor the retention of $11 million related to market sales during the event. These items will be reviewed through the triennial Fuel Reconciliation proceeding and are subject to a final PUCT decision.
In July 2022, the intervenors filed recommendations in the Fuel Reconciliation proceeding. The Texas Industrial Energy Consumers and PUCT staff recommended disallowances of approximately $10 million (off-system sales margins). The Office of Public Utility Counsel recommended disallowances of approximately $15 million (off-system sales margins and adjustment to energy loss factors). The Alliance of Xcel Municipalities recommended disallowances of approximately $100 million (natural gas storage, contracted capability and off-system sales margins).
A hearing is scheduled to begin in August and a recommendation from the ALJ is expected in the fourth quarter of 2022.
Note 6. Earnings Guidance and Long-Term EPS and Dividend Growth Rate Objectives
Xcel Energy 2022 Earnings Guidance — Xcel Energy’s 2022 GAAP and ongoing earnings guidance is a range of $3.10 to $3.20 per share.(a)
Key assumptions as compared with 2021 levels unless noted:
Constructive outcomes in all rate case and regulatory proceedings. Normal weather patterns for the remainder of the year. Weather-normalized retail electric sales are projected to increase ~2%. Weather-normalized retail firm natural gas sales are projected to increase ~1%. Capital rider revenue is projected to increase $0 million to $10 million (net of PTCs). O&M expenses are projected to increase approximately 2%. Depreciation expense is projected to increase approximately $300 million to $310 million. The change in assumption is primarily a result of new rates going into effect in Texas and will be offset by revenue with minimal impact on earnings. Property taxes are projected to increase approximately $35 million to $45 million. Interest expense (net of AFUDC - debt) is projected to increase $100 million to $110 million. The assumption change reflects higher interest rates and slightly larger debt issuances. AFUDC - equity is projected to be relatively flat. ETR is projected to be ~(6%) to (8%).(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 2021 base of $2.96 per share, which represents the mid-point of the revised 2021 guidance range of $2.94 to $2.98 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 June 30
2022
2021
Operating revenues:
Electric and natural gas
$
3,399
$
3,046
Other
25
22
Total operating revenues
3,424
3,068
Net income
$
328
$
311
Weighted average diluted common shares outstanding
546
539
Components of EPS — Diluted
Regulated utility
$
0.67
$
0.62
Xcel Energy Inc. and other costs
(0.07
)
(0.04
)
GAAP and ongoing diluted EPS (a)
$
0.60
$
0.58
Book value per share
$
29.24
$
27.43
Cash dividends declared per common share
0.4875
0.4575
Six Months Ended June 30
2022
2021
Operating revenues:
Electric and natural gas
$
7,122
$
6,563
Other
53
46
Total operating revenues
7,175
6,609
Net income
$
708
$
673
Weighted average diluted common shares outstanding
546
539
Components of EPS — Diluted
Regulated utility
$
1.41
$
1.35
Xcel Energy Inc. and other costs
(0.11
)
(0.10
)
GAAP and ongoing diluted EPS (a)
1.30
1.25
Book value per share
$
29.27
$
27.45
Cash dividends declared per common share
0.975
0.92
(a)
For the three and six months ended June 30, 2022, there were no adjustments to GAAP earnings and therefore GAAP earnings equal ongoing earnings for these periods.
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