Company Announcements

Xcel Energy Second Quarter 2022 Earnings Report

  • Second quarter GAAP diluted earnings per share were $0.60 in 2022 compared with $0.58 in 2021.
  • Xcel Energy reaffirms 2022 EPS earnings guidance range of $3.10 to $3.20.

MINNEAPOLISMINNEAPOLIS--(BUSINESS WIRE)--Jul. 28, 2022-- 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.

 

Paul Johnson, Vice President - Treasurer & Investor Relations (612) 215-4535

For news media inquiries only, please call Xcel Energy Media Relations (612) 215-5300

Xcel Energy website address: www.xcelenergy.com

Source: Xcel Energy Inc.