Exhibit 99.01
| 414 Nicollet Mall | |||||
| July 30, 2020 | Minneapolis, MN 55401 | ||||
XCEL ENERGY
SECOND QUARTER 2020 EARNINGS REPORT
•GAAP 2020 second quarter earnings per share were $0.54 compared with $0.46 per share in 2019.
•Xcel Energy reaffirms 2020 EPS earnings guidance of $2.73 to $2.83 per share, which assumes the continued implementation of contingency plans will be sufficient to offset the negative impacts of the COVID-19 pandemic under our base case scenario. For additional information, see Notes 5 and 6.
MINNEAPOLIS — Xcel Energy Inc. (NASDAQ: XEL) today reported 2020 second quarter GAAP and ongoing earnings of $287 million, or $0.54 per share, compared with $238 million, or $0.46 per share in the same period in 2019.
“Despite lower sales due to COVID-19, Xcel Energy achieved strong second quarter results primarily due to the positive impact of weather and cost management efforts. We are on track with our financial plan and are reaffirming our 2020 earnings guidance of $2.73 to $2.83 per share. However, we’ll continue to monitor and manage through the economic uncertainty of this pandemic,” said Ben Fowke, chairman and CEO of Xcel Energy.
“At the same time we are delivering for our shareholders, we continue to deliver for our customers and communities. Across our service territory, we are working with key stakeholders and communities to find ways to help support economic recovery efforts. In Minnesota, we recently proposed a plan to spend nearly $3 billion in energy investments to help boost job growth and economic activity in the state,” continued Fowke. “Those proposed projects alone would create an estimated 5,000 jobs and add more wind and solar to our system in our home state. In addition, we continue to work with our customers and commissions to support those that are struggling with bills in these challenging times.”
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) 224-1121 | ||||
| International Dial-In: | (400) 120-9101 | ||||
| Conference ID: | 8266089 | ||||
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 July 30 through 12:00 p.m. CDT on August 2.
| Replay Numbers | |||||
| US Dial-In: | (888) 203-1112 | ||||
| International Dial-In: | (719) 457-0820 | ||||
| Access Code: | 8266089 | ||||
1
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 2020 earnings per share (EPS) guidance, long-term EPS and dividend growth rate objectives, future sales, future bad debt expense, and future operating performance, 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, 2019 and subsequent securities filings, 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.
For more information, contact:
| 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
This information is not given in connection with any
sale, offer for sale or offer to buy any security.
2
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 | |||||||||||||||||||||||||
| 2020 | 2019 | 2020 | 2019 | |||||||||||||||||||||||
| Operating revenues | ||||||||||||||||||||||||||
| Electric | $ | 2,286 | $ | 2,249 | $ | 4,489 | $ | 4,574 | ||||||||||||||||||
| Natural gas | 280 | 308 | 863 | 1,102 | ||||||||||||||||||||||
| Other | 20 | 20 | 45 | 42 | ||||||||||||||||||||||
| Total operating revenues | 2,586 | 2,577 | 5,397 | 5,718 | ||||||||||||||||||||||
| Operating expenses | ||||||||||||||||||||||||||
| Electric fuel and purchased power | 833 | 813 | 1,630 | 1,727 | ||||||||||||||||||||||
| Cost of natural gas sold and transported | 86 | 112 | 371 | 591 | ||||||||||||||||||||||
| Cost of sales — other | 8 | 10 | 17 | 19 | ||||||||||||||||||||||
| Operating and maintenance expenses | 550 | 586 | 1,129 | 1,184 | ||||||||||||||||||||||
Conservation and demand side management expenses | 68 | 65 | 142 | 137 | ||||||||||||||||||||||
| Depreciation and amortization | 473 | 439 | 936 | 872 | ||||||||||||||||||||||
| Taxes (other than income taxes) | 146 | 142 | 295 | 292 | ||||||||||||||||||||||
| Total operating expenses | 2,164 | 2,167 | 4,520 | 4,822 | ||||||||||||||||||||||
| Operating income | 422 | 410 | 877 | 896 | ||||||||||||||||||||||
| Other income (expense), net | 5 | 2 | (7) | 6 | ||||||||||||||||||||||
| Equity earnings of unconsolidated subsidiaries | 6 | 9 | 17 | 19 | ||||||||||||||||||||||
| Allowance for funds used during construction — equity | 37 | 20 | 61 | 40 | ||||||||||||||||||||||
| Interest charges and financing costs | ||||||||||||||||||||||||||
Interest charges — includes other financing costs of $7, $6, $14 and $13, respectively | 208 | 189 | 407 | 379 | ||||||||||||||||||||||
| Allowance for funds used during construction — debt | (12) | (10) | (22) | (20) | ||||||||||||||||||||||
| Total interest charges and financing costs | 196 | 179 | 385 | 359 | ||||||||||||||||||||||
| Income before income taxes | 274 | 262 | 563 | 602 | ||||||||||||||||||||||
| Income tax (benefit) expense | (13) | 24 | (19) | 49 | ||||||||||||||||||||||
| Net income | $ | 287 | $ | 238 | $ | 582 | $ | 553 | ||||||||||||||||||
| Weighted average common shares outstanding: | ||||||||||||||||||||||||||
| Basic | 527 | 516 | 526 | 515 | ||||||||||||||||||||||
| Diluted | 527 | 518 | 527 | 517 | ||||||||||||||||||||||
| Earnings per average common share: | ||||||||||||||||||||||||||
| Basic | $ | 0.54 | $ | 0.46 | $ | 1.10 | $ | 1.07 | ||||||||||||||||||
| Diluted | 0.54 | 0.46 | 1.10 | 1.07 | ||||||||||||||||||||||
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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 and six months ended June 30, 2020 and 2019, there were no such adjustments to GAAP earnings and therefore GAAP earnings equal ongoing earnings for these periods.
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Note 1. Earnings Per Share Summary
Xcel Energy’s 2020 second quarter earnings were $0.54 per share compared to $0.46 per share in 2019, largely reflecting lower O&M, lower income taxes and favorable weather, which offset declining sales due to the impacts of COVID-19. Second quarter sales results exceeded our base case scenario assumptions, however, there continues to be substantial uncertainty related to the impact of the COVID-19 pandemic on the remainder of the year.
All companies were negatively impacted by the pandemic starting in March 2020 and continuing into the second quarter. See Note 5 for further information regarding COVID-19, including impact on monthly weather-adjusted electric sales in the second quarter.
Summarized diluted EPS for Xcel Energy:
| Three Months Ended June 30 | Six Months Ended June 30 | |||||||||||||||||||||||||
| Diluted Earnings (Loss) Per Share | 2020 | 2019 | 2020 | 2019 | ||||||||||||||||||||||
| Public Service Company of Colorado (PSCo) | $ | 0.21 | $ | 0.20 | $ | 0.45 | $ | 0.47 | ||||||||||||||||||
| NSP-Minnesota | 0.22 | 0.19 | 0.43 | 0.41 | ||||||||||||||||||||||
| Southwestern Public Service Company (SPS) | 0.14 | 0.11 | 0.22 | 0.22 | ||||||||||||||||||||||
| NSP-Wisconsin | 0.02 | 0.02 | 0.09 | 0.06 | ||||||||||||||||||||||
| Equity earnings of unconsolidated subsidiaries | 0.01 | 0.01 | 0.02 | 0.02 | ||||||||||||||||||||||
Regulated utility (a) | 0.60 | 0.53 | 1.20 | 1.18 | ||||||||||||||||||||||
| Xcel Energy Inc. and Other | (0.07) | (0.06) | (0.10) | (0.11) | ||||||||||||||||||||||
Total (a) | $ | 0.54 | $ | 0.46 | $ | 1.10 | $ | 1.07 | ||||||||||||||||||
(a) Amounts may not add due to rounding.
PSCo — Earnings increased $0.01 per share for the second quarter of 2020 and decreased $0.02 per share year-to date. The decrease in year-to-date earnings was driven by lower sales and demand revenue primarily due to COVID-19, higher depreciation, interest charges and lower natural gas margins due to unfavorable weather, partially offset by higher AFUDC, an increase in electric margins (regulatory outcomes offset lower sales due to COVID-19) and lower O&M.
NSP-Minnesota — Earnings increased $0.03 per share for the second quarter of 2020 and $0.02 year-to-date. The increase in year-to-date earnings primarily reflects lower O&M and income taxes, partially offset by lower electric margins (reflecting lower sales from COVID-19) and natural gas margins as well as higher depreciation. Lower electric margins were due primarily to increased production tax credits (PTCs) flowed back to customers (offset in income tax) and decreased sales, partially offset by non-fuel riders.
SPS — Earnings increased $0.03 per share for the second quarter of 2020 and were flat year-to-date. Year-to-date earnings were driven by lower O&M and income taxes, offset by lower electric margin and increased depreciation. Lower electric margins were attributable to lower sales from COVID-19, increased PTCs flowed back to customers (offset in income tax) and a 2019 NMPRC revised order eliminating a $10 million retroactive refund of tax reform benefits, partially offset by an increase in wholesale transmission revenue.
NSP-Wisconsin — Earnings were flat for the second quarter of 2020 and increased $0.03 per share year-to-date. The increase in year-to-date earnings was driven by lower O&M and income taxes, as well as higher electric margin (due primarily to regulatory outcomes which offset lower sales from COVID-19), partially offset by lower natural gas margins due to unfavorable weather and increased depreciation.
Xcel Energy Inc. and Other — Primarily includes financing costs at the holding company.
5
Components significantly contributing to changes in 2020 EPS compared with the same period in 2019:
| Diluted Earnings (Loss) Per Share | Three Months Ended June 30 | Six Months Ended June 30 | ||||||||||||
| GAAP and ongoing diluted EPS — 2019 | $ | 0.46 | $ | 1.07 | ||||||||||
| Components of change — 2020 vs. 2019: | ||||||||||||||
Lower Effective Tax Rate (ETR) (a) | 0.07 | 0.10 | ||||||||||||
| Lower O&M | 0.05 | 0.08 | ||||||||||||
| Higher AFUDC | 0.03 | 0.04 | ||||||||||||
Higher electric margins (b) | 0.02 | 0.02 | ||||||||||||
| Higher depreciation and amortization | (0.05) | (0.09) | ||||||||||||
| Higher interest charges | (0.03) | (0.04) | ||||||||||||
| Lower natural gas margins | — | (0.03) | ||||||||||||
| Lower other income (expense), net | — | (0.02) | ||||||||||||
| Other (net) | (0.01) | (0.03) | ||||||||||||
| GAAP and ongoing diluted EPS — 2020 | $ | 0.54 | $ | 1.10 | ||||||||||
(a) Includes production tax credits (PTCs) and tax reform regulatory amounts, which are primarily offset in electric margin.
(b) The period-over-period change in electric margin was negatively impacted by reductions in sales and demand. See table below:
| Diluted Earnings (Loss) Per Share | Three Months Ended June 30 | Six Months Ended June 30 | ||||||||||||
| Electric margin (excluding reductions in sales and demand) | $ | 0.09 | $ | 0.09 | ||||||||||
Reductions in sales and demand (a) | (0.07) | (0.07) | ||||||||||||
| Higher electric margins | $ | 0.02 | $ | 0.02 | ||||||||||
(a) Sales decline excludes weather impact, net of decoupling/sales true-up and decrease in demand revenue is net of sales true-up.
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.
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.
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Percentage increase (decrease) in normal and actual HDD, CDD and THI:
| Three Months Ended June 30 | Six Months Ended June 30 | ||||||||||||||||||||||||||||||||||
| 2020 vs. Normal | 2019 vs. Normal | 2020 vs. 2019 | 2020 vs. Normal | 2019 vs. Normal | 2020 vs. 2019 | ||||||||||||||||||||||||||||||
| HDD | 2.2 | % | 16.9 | % | (11.8) | % | (4.1) | % | 12.8 | % | (14.4) | % | |||||||||||||||||||||||
| CDD | 22.4 | (45.2) | 191.2 | 22.5 | (45.5) | 139.9 | |||||||||||||||||||||||||||||
| THI | 15.0 | (26.7) | 63.6 | 14.7 | (26.9) | 63.6 | |||||||||||||||||||||||||||||
Weather — Estimated impact of temperature variations on EPS compared with normal weather conditions:
| Three Months Ended June 30 | Six Months Ended June 30 | ||||||||||||||||||||||||||||||||||
| 2020 vs. Normal | 2019 vs. Normal | 2020 vs. 2019 | 2020 vs. Normal | 2019 vs. Normal | 2020 vs. 2019 | ||||||||||||||||||||||||||||||
| Retail electric | $ | 0.028 | $ | (0.024) | $ | 0.052 | $ | 0.017 | $ | (0.005) | $ | 0.022 | |||||||||||||||||||||||
| Decoupling and sales true-up | (0.014) | 0.006 | (0.020) | (0.009) | 0.001 | (0.010) | |||||||||||||||||||||||||||||
| Electric total | $ | 0.014 | $ | (0.018) | $ | 0.032 | $ | 0.008 | $ | (0.004) | $ | 0.012 | |||||||||||||||||||||||
| Firm natural gas | 0.001 | 0.004 | (0.003) | (0.006) | 0.022 | (0.028) | |||||||||||||||||||||||||||||
| Total | $ | 0.015 | $ | (0.014) | $ | 0.029 | $ | 0.002 | $ | 0.018 | $ | (0.016) | |||||||||||||||||||||||
Sales Growth (Decline) — Sales growth (decline) for actual and weather-normalized sales in 2020 compared to the same period in 2019:
| Three Months Ended June 30 | ||||||||||||||||||||||||||||||||
| PSCo | NSP-Minnesota | SPS | NSP-Wisconsin | Xcel Energy | ||||||||||||||||||||||||||||
Actual (a) | ||||||||||||||||||||||||||||||||
| Electric residential | 13.5 | % | 10.2 | % | 13.4 | % | 10.8 | % | 11.9 | % | ||||||||||||||||||||||
| Electric commercial and industrial | (8.3) | (13.2) | (7.5) | (12.3) | (10.2) | |||||||||||||||||||||||||||
| Total retail electric sales | (1.7) | (6.6) | (4.4) | (6.5) | (4.5) | |||||||||||||||||||||||||||
| Firm natural gas sales | (13.0) | 0.4 | N/A | (3.8) | (8.5) | |||||||||||||||||||||||||||
| Three Months Ended June 30 | ||||||||||||||||||||||||||||||||
PSCo (b) | NSP-Minnesota | SPS | NSP-Wisconsin | Xcel Energy | ||||||||||||||||||||||||||||
Weather-normalized (a) | ||||||||||||||||||||||||||||||||
| Electric residential | 6.1 | % | 5.7 | % | 3.3 | % | 4.9 | % | 5.4 | % | ||||||||||||||||||||||
| Electric commercial and industrial | (10.4) | (14.2) | (8.6) | (13.3) | (11.5) | |||||||||||||||||||||||||||
| Total retail electric sales | (5.4) | (8.5) | (6.9) | (8.6) | (7.1) | |||||||||||||||||||||||||||
| Firm natural gas sales | (7.4) | 2.7 | N/A | 3.1 | (3.9) | |||||||||||||||||||||||||||
| Six Months Ended June 30 | ||||||||||||||||||||||||||||||||
| PSCo | NSP-Minnesota | SPS | NSP-Wisconsin | Xcel Energy | ||||||||||||||||||||||||||||
Actual (a) | ||||||||||||||||||||||||||||||||
| Electric residential | 5.7 | % | 2.1 | % | 5.4 | % | 1.0 | % | 3.8 | % | ||||||||||||||||||||||
| Electric commercial and industrial | (4.0) | (8.5) | (2.2) | (6.4) | (5.4) | |||||||||||||||||||||||||||
| Total retail electric sales | (1.0) | (5.4) | (1.1) | (4.3) | (2.9) | |||||||||||||||||||||||||||
| Firm natural gas sales | (8.2) | (10.4) | N/A | (12.0) | (9.1) | |||||||||||||||||||||||||||
| Six Months Ended June 30 | ||||||||||||||||||||||||||||||||
PSCo (b) | NSP-Minnesota | SPS | NSP-Wisconsin | Xcel Energy | ||||||||||||||||||||||||||||
Weather-normalized (a) | ||||||||||||||||||||||||||||||||
| Electric residential | 3.4 | % | 2.7 | % | 1.9 | % | 3.0 | % | 2.9 | % | ||||||||||||||||||||||
| Electric commercial and industrial | (5.0) | (8.7) | (2.7) | (6.5) | (5.8) | |||||||||||||||||||||||||||
| Total retail electric sales | (2.4) | (5.3) | (2.1) | (3.8) | (3.5) | |||||||||||||||||||||||||||
| Firm natural gas sales | (1.4) | 2.6 | N/A | 3.3 | 0.2 | |||||||||||||||||||||||||||
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| Six Months Ended June 30 (Leap Year Adjusted) | ||||||||||||||||||||||||||||||||
PSCo (b) | NSP-Minnesota | SPS | NSP-Wisconsin | Xcel Energy | ||||||||||||||||||||||||||||
Weather-normalized (Leap Year Adjusted) (a) | ||||||||||||||||||||||||||||||||
| Electric residential | 2.8 | % | 2.2 | % | 1.3 | % | 2.4 | % | 2.3 | % | ||||||||||||||||||||||
| Electric commercial and industrial | (5.5) | (9.2) | (3.3) | (7.1) | (6.4) | |||||||||||||||||||||||||||
| Total retail electric sales | (3.0) | (5.8) | (2.7) | (4.4) | (4.1) | |||||||||||||||||||||||||||
| Firm natural gas sales | (2.2) | 1.7 | N/A | 2.3 | (0.7) | |||||||||||||||||||||||||||
(a) Higher residential sales and lower C&I sales were primarily attributable to COVID-19.
(b) Colorado Public Utilities Commission (CPUC) approved a historical 10-year weather normalization approach for retail electric, effective March 1, 2020.
Weather-normalized and leap-year adjusted electric sales growth (decline) — year-to-date (excluding leap day)
•PSCo — Residential sales rose based on higher use per customer from stay-at-home mandates and an increased number of customers. The commercial and industrial (C&I) decline was due to lower use offsetting an increase in the number of C&I customers. The decline in C&I sales was primarily due to the shutdown of the economy from COVID-19, 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 from stay-at-home mandates and increased customer additions. The drop in C&I sales was as a result of customer growth offset by lower use per customer. Decreased sales to C&I customers were due to the shutdown of the economy from COVID-19 and declines in the energy, manufacturing and services sectors.
•SPS — Residential sales increased due to customer growth and higher use per customer from stay-at-home mandates. The decline in C&I sales was due to shutdowns of the economy from COVID-19, declines in oil and natural gas extraction due to lower commodity prices and lower manufacturing, agriculture & food and services.
•NSP-Wisconsin — Residential sales growth was attributable to higher use per customer from stay-at-home mandates and customer additions. The decline in C&I was largely due to the shutdown of the economy from COVID-19 and decreased sales to the manufacturing sector.
Weather-normalized and leap-year adjusted natural gas sales growth (decline) — year-to-date (excluding leap day)
•Natural gas sales reflect an increase in number of customers combined with lower customer use due to the shutdown of the economy from COVID-19.
Electric Margin — Electric revenues and fuel and purchased power expenses are impacted by fluctuations in the price of natural gas, coal and uranium used in the generation of electricity. 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 in a particular period.
Electric revenues and margin:
| Three Months Ended June 30 | Six Months Ended June 30 | |||||||||||||||||||||||||
| (Millions of Dollars) | 2020 | 2019 | 2020 | 2019 | ||||||||||||||||||||||
| Electric revenues | $ | 2,286 | $ | 2,249 | $ | 4,489 | $ | 4,574 | ||||||||||||||||||
| Electric fuel and purchased power | (833) | (813) | (1,630) | (1,727) | ||||||||||||||||||||||
| Electric margin | $ | 1,453 | $ | 1,436 | $ | 2,859 | $ | 2,847 | ||||||||||||||||||
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Changes in electric margin:
| (Millions of Dollars) | Three Months Ended June 30, 2020 vs. 2019 | Six Months Ended June 30, 2020 vs. 2019 | ||||||||||||
| Regulatory rate outcomes (Colorado, Wisconsin and New Mexico) | $ | 21 | $ | 34 | ||||||||||
| Wholesale transmission revenue (net) | 20 | 25 | ||||||||||||
| Non-fuel riders | 11 | 24 | ||||||||||||
| Estimated impact of weather (net of decoupling/sales true-up) | 21 | 8 | ||||||||||||
| PTCs flowed back to customers (offset by a lower ETR) | (31) | (53) | ||||||||||||
Sales and demand (a) | (47) | (46) | ||||||||||||
| New Mexico tax reform related regulatory settlement (2019) | — | (10) | ||||||||||||
| Other (net) | 22 | 30 | ||||||||||||
| Total increase in electric margin | $ | 17 | $ | 12 | ||||||||||
(a) Sales decline excludes weather impact, net of decoupling/sales true-up and decrease in demand revenue 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.
Natural gas revenues and margin:
| Three Months Ended June 30 | Six Months Ended June 30 | |||||||||||||||||||||||||
| (Millions of Dollars) | 2020 | 2019 | 2020 | 2019 | ||||||||||||||||||||||
| Natural gas revenues | $ | 280 | $ | 308 | $ | 863 | $ | 1,102 | ||||||||||||||||||
| Cost of natural gas sold and transported | (86) | (112) | (371) | (591) | ||||||||||||||||||||||
| Natural gas margin | $ | 194 | $ | 196 | $ | 492 | $ | 511 | ||||||||||||||||||
Changes in natural gas margin:
| (Millions of Dollars) | Three Months Ended June 30, 2020 vs. 2019 | Six Months Ended June 30, 2020 vs. 2019 | ||||||||||||
| Estimated impact of weather | $ | (2) | $ | (19) | ||||||||||
| Transport sales | — | (2) | ||||||||||||
| Regulatory rate outcomes (Wisconsin) | — | (2) | ||||||||||||
| Retail sales decline | (2) | (1) | ||||||||||||
| Infrastructure and integrity riders | 4 | 5 | ||||||||||||
| Conservation revenue (offset in expenses) | 2 | 3 | ||||||||||||
| Other (net) | (4) | (3) | ||||||||||||
| Total decrease in natural gas margin | $ | (2) | $ | (19) | ||||||||||
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O&M Expenses — O&M expenses decreased $36 million, or 6.1%, for the second quarter and $55 million, or 4.6%, year-to-date, largely reflecting management actions to reduce costs to offset the impact of lower sales from COVID-19. Significant changes are summarized as follows:
| (Millions of Dollars) | Three Months Ended June 30, 2020 vs. 2019 | Six Months Ended June 30, 2020 vs. 2019 | ||||||||||||
| Distribution | $ | (20) | $ | (30) | ||||||||||
| Employee benefits | 6 | (10) | ||||||||||||
| Transmission | (5) | (6) | ||||||||||||
| Generation | (4) | (6) | ||||||||||||
| Strategic initiatives | — | 6 | ||||||||||||
| Other (net) | (13) | (9) | ||||||||||||
| Total decrease in O&M expenses | $ | (36) | $ | (55) | ||||||||||
•Distribution expenses declined due to cost mitigation efforts including allocation of workforce, material and supply management, performance of maintenance and other items;
•Employee benefits were lower year-to-date primarily due to change in deferred compensation liability, offset in Other Income (Expense);
•Transmission expenses declined due to a reduction in labor related amounts and cost mitigation initiatives;
•Generation expenses were lower from timing of maintenance and overhauls at power plants and cost mitigation efforts, partially offset by an increase in wind related amounts;
•Strategic initiative amounts were higher year-to-date due to increased spending on customer experience transformation program expenses and advanced grid infrastructure; and
•Other primarily includes deferred amounts associated with the Texas 2019 electric rate case and the outcome of the CPUC’s rehearing of the Colorado 2019 electric rate case.
Depreciation and Amortization — Depreciation and amortization increased $34 million, or 7.7%, for the second quarter and $64 million, or 7.3%, year-to-date. Increase was primarily driven by the Hale, Lake Benton, Foxtail and Blazing Star I wind facilities going into service, as well as normal system expansion. In addition, depreciation rates were increased in Colorado and New Mexico as part of regulatory outcomes in 2020.
Other Income (Expense) — Other income (expense) increased $3 million for the second quarter and decreased $13 million year-to-date. Decrease is due to the performance of rabbi trust investments, which is offset in O&M expense (deferred compensation).
AFUDC, Equity and Debt — AFUDC increased $19 million for the second quarter and $23 million year-to-date. Increase was primarily due to additional AFUDC recorded on various wind projects currently under construction.
Interest Charges — Interest charges increased $19 million, or 10.1%, for the second quarter and $28 million, or 7.4% year-to-date. Increase was primarily due to higher debt levels to fund capital investments, partially offset by lower long-term and short-term interest rates.
Income Taxes — Income taxes decreased $37 million for the second quarter. Decrease was primarily driven by an increase in wind PTCs and an increase in plant regulatory differences. Wind PTCs are credited to customers (recorded as a reduction to revenue) and do not have a material impact on net income. The ETR was (4.7%) for the second quarter of 2020 compared with 9.2% for the same period in 2019.
Income taxes decreased $68 million for the first six months of 2020. Decrease was primarily driven by an increase in wind PTCs, lower pretax earnings and an increase in plant-related regulatory differences. Wind PTCs are credited to customers and do not have a material impact on net income. The ETR was (3.4%) for the first six months ending June 30, 2020 compared with 8.1% for the same period in 2019.
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Additional details:
| Three Months Ended June 30 | Six Months Ended June 30 | |||||||||||||||||||||||||||||||||||||
| 2020 | 2019 | 2020 vs 2019 | 2020 | 2019 | 2020 vs 2019 | |||||||||||||||||||||||||||||||||
| Federal statutory rate | 21.0 | % | 21.0 | % | — | % | 21.0 | % | 21.0 | % | — | % | ||||||||||||||||||||||||||
| State tax (net of federal tax effect) | 5.1 | 5.0 | 0.1 | 5.0 | 5.0 | — | ||||||||||||||||||||||||||||||||
| (Decreases) increases: | ||||||||||||||||||||||||||||||||||||||
| Wind PTCs | (21.1) | (11.9) | (9.2) | (19.1) | (10.0) | (9.1) | ||||||||||||||||||||||||||||||||
Plant regulatory differences (a) | (7.1) | (5.5) | (1.6) | (7.8) | (5.6) | (2.2) | ||||||||||||||||||||||||||||||||
| Other tax credits and NOL allowances (net) | (1.9) | (0.6) | (1.3) | (1.4) | (1.8) | 0.4 | ||||||||||||||||||||||||||||||||
| Other (net) | (0.7) | 1.2 | (1.9) | (1.1) | (0.5) | (0.6) | ||||||||||||||||||||||||||||||||
| Effective income tax rate | (4.7) | % | 9.2 | % | (13.9) | % | (3.4) | % | 8.1 | % | (11.5) | % | ||||||||||||||||||||||||||
(a) Regulatory differences for income tax primarily relate to the credit of excess deferred taxes to customers through the average rate assumption method. Income tax benefits associated with the credit of excess deferred credits are generally offset by corresponding revenue reductions.
Note 3. Capital Structure, Liquidity, Financing and Credit Ratings
Xcel Energy’s capital structure:
| (Millions of Dollars) | June 30, 2020 | Percentage of Total Capitalization | Dec. 31, 2019 | Percentage of Total Capitalization | ||||||||||||||||||||||
| Current portion of long-term debt | $ | 1,101 | 3 | % | $ | 702 | 2 | % | ||||||||||||||||||
| Short-term debt | 1,410 | 4 | 595 | 2 | ||||||||||||||||||||||
| Long-term debt | 19,463 | 55 | 17,407 | 54 | ||||||||||||||||||||||
| Total debt | 21,974 | 62 | 18,704 | 58 | ||||||||||||||||||||||
| Common equity | 13,385 | 38 | 13,239 | 42 | ||||||||||||||||||||||
| Total capitalization | $ | 35,359 | 100 | % | $ | 31,943 | 100 | % | ||||||||||||||||||
Liquidity — As of July 27, 2020, 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 | $ | 76 | $ | 1,174 | $ | 621 | $ | 1,795 | ||||||||||||||||||||||
| PSCo | 700 | 8 | 692 | 9 | 701 | |||||||||||||||||||||||||||
| NSP-Minnesota | 500 | 10 | 490 | 682 | 1,172 | |||||||||||||||||||||||||||
| SPS | 500 | 2 | 498 | 186 | 684 | |||||||||||||||||||||||||||
| NSP-Wisconsin | 150 | — | 150 | 10 | 160 | |||||||||||||||||||||||||||
| Total | $ | 3,100 | $ | 96 | $ | 3,004 | $ | 1,508 | $ | 4,512 | ||||||||||||||||||||||
Term Loan (c) | 500 | 500 | — | |||||||||||||||||||||||||||||
Term Loan (d) | 700 | 700 | — | |||||||||||||||||||||||||||||
(a) Credit facilities expire in June 2024.
(b) Includes outstanding commercial paper and letters of credit.
(c) The $500 million term loan matures in December 2020.
(d) The $700 million 364-day term loan matures in March 2021.
Term Loan Agreements — In December 2019, Xcel Energy Inc. extended a $500 million Term Loan Agreement for an additional 364 days. In March 2020, Xcel Energy Inc. entered into an incremental $700 million 364-Day Term Loan Agreement.
Bilateral Credit Agreement — In March 2020, NSP-Minnesota extended an uncommitted bilateral credit agreement which is limited in use to support letters of credit for one-year. NSP-Minnesota had $31 million of outstanding letters of credits as of June 30, 2020.
Forward Equity Agreements — In November 2019, Xcel Energy Inc. entered into forward equity agreements in connection with a $743 million public offering of 11.8 million shares, which is expected to be settled in shares later in 2020.
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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 27, 2020:
| 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 | |||||||||||||||||||||||
2020 Financing Activity — During 2020, 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 the following debt securities:
| Issuer | Security | Amount | Status | Tenor | Coupon | |||||||||||||||||||||||||||
| Xcel Energy Inc. | Senior Unsecured Bonds | $ | 600 | Completed | 10 Year | 3.4 | % | |||||||||||||||||||||||||
| NSP-Minnesota | First Mortgage Bonds | 700 | Completed | 31 year | 2.60 | |||||||||||||||||||||||||||
| NSP-Wisconsin | First Mortgage Bonds | 100 | Completed | 31 year | 3.05 | |||||||||||||||||||||||||||
| PSCo | First Mortgage Bonds | 750 | Completed | 11 / 31 year | 1.9/2.7 | |||||||||||||||||||||||||||
| SPS | First Mortgage Bonds | 350 | Completed | 30 year | 3.15 | |||||||||||||||||||||||||||
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
Mankato Energy Center (MEC) — In January 2020, Xcel Energy Inc. purchased MEC, a 760 MW natural gas combined cycle facility, for approximately $650 million from Southern Power Company (a subsidiary of Southern Company).
In July 2020, Xcel Energy Inc. sold MEC to Southwest Generation for $680 million, subject to working capital adjustments. Proceeds from the sale will primarily be used to reduce Xcel Energy’s overall financing needs.
NSP-Minnesota — Minnesota Resource Plan — In July 2019, NSP-Minnesota filed its Minnesota resource plan, which runs through 2034. The plan would result in an 80% carbon reduction by 2030 (from 2005) and puts NSP-Minnesota on a path to achieving its vision of being 100% carbon-free by 2050.
In June 2020, NSP-Minnesota filed a supplement to its resource plan, including new modeling scenarios required by the Minnesota Public Utilities Commission (MPUC). The updated preferred resource plan reflects the following:
•Retirement of all coal generation by 2030 with reduced operations at some units prior to retirement, including the early retirement of the King coal plant (511 MW) in 2028 and the Sherco 3 coal plant (517 MW) in 2030;
•Extending the life of the Monticello nuclear plant from 2030 to 2040;
•Continuing to run the Prairie Island nuclear plant through current end of life (2033 and 2034);
•Construction of the Sherco combined cycle natural gas plant;
•The addition of 3,500 MW of solar;
•The addition of 2,250 MW of wind;
•2,600 MW of firm peaking (combustion turbine, pumped hydro, battery storage, demand response etc.);
•Achieving 780 GWh in energy efficiency savings annually through 2034; and
•Adding 400 MW of incremental demand response by 2023, and a total of 1,500 MW of demand response by 2034.
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Initial comments are due Oct. 30, 2020 and reply comments are due Jan. 15, 2021. The MPUC is anticipated to make a final decision in the first half of 2021.
Minnesota Relief and Recovery — In 2020, the MPUC opened a Relief and Recovery docket and invited utilities in the state to submit potential projects that would create jobs and help jump start the economy to offset the impacts of COVID-19. In June 2020, NSP-Minnesota filed a Relief & Recovery proposal which identified approximately $3 billion of capital investment which may assist in Minnesota’s economic recovery from COVID-19. The filing included the following components:
•A wind repowering solicitation that could result in 800 to 1,000 MW with an estimated incremental investment of $1.0 to $1.4 billion;
•A 460 MW solar facility with an incremental investment of approximately $650 million;
•Incremental electric vehicle investment and rebates with an estimated cost of $155 million;
•Accelerated transmission investment of $180 million;
•Accelerated distribution investment of $615 million; and
•Accelerated natural gas investment of $50 million.
The MPUC scheduled a planning meeting to determine the procedural process and next steps.
PSCo 2020 Rider Filings — In July 2020, PSCo filed Wildfire and Advanced Grid rider requests with the Colorado Public Utilities Commission (CPUC) instead of filing a comprehensive electric rate case in 2020.
Wildfire Protection Rider — Seeks to establish a Wildfire Protection Rider to recover incremental costs associated with system investments to reduce wildfire risk. The rider would be effective no later than June 2021 and continue through 2025. Wildfire Protection capital additions are projected to total approximately $325 million. Forecasted annual revenue requirements from 2021 through 2025 are as follows:
| (Million of Dollars) | 2021 | 2022 | 2023 | 2024 | 2025 | |||||||||||||||
| Forecasted annual revenue requirement | $ | 17 | $ | 24 | $ | 29 | $ | 32 | $ | 34 | ||||||||||
Advanced Grid Rider — Seeks to establish an Advanced Grid Rider to recover incremental costs associated with the Advanced Grid Intelligence and Security Initiative (AGIS). The rider would be effective no later than May 2021 and continue through 2025. The PSCo portion of the AGIS initiative is projected to total approximately $850 million of capital additions. Forecasted annual revenue requirements from 2021 through 2025 are as follows:
| (Millions of Dollars) | 2021 | 2022 | 2023 | 2024 | 2025 | |||||||||||||||
| Forecasted annual revenue requirement | $ | 53 | $ | 69 | $ | 83 | $ | 89 | $ | 99 | ||||||||||
PSCo — Colorado 2020 Natural Gas Rate Case —In February 2020, PSCo filed a rate case with the CPUC seeking a net increase to retail gas rates of $126.8 million, reflecting a $144.5 million increase in base rate revenue, partially offset by $17.7 million of costs previously authorized through the Pipeline Integrity rider. The request was based on a 9.95% ROE, an equity ratio of 55.81% and a historic test year as of Sept. 30, 2019, adjusted for known and measurable differences for the 12-month period ended Sept. 30, 2020. In June 2020, PSCo revised its net increase to $121 million.
In July 2020, PSCo, the CPUC Staff and various intervenors filed a comprehensive unopposed settlement, which results in a net increase to retail gas rates of $77.3 million, reflecting a $94.1 million increase in base rate revenue, partially offset by $16.8 million of costs previously authorized through the Pipeline Integrity rider. The settlement is based on:
•A ROE of 9.20%;
•An equity ratio of 55.62%; and
•A historic test year as of Sept. 30, 2019, utilizing a year-end rate base, and incorporating a known and measurable adjustment for the Tungsten to Black Hawk pipeline as of April 30, 2020.
Rates will be implemented on April 1, 2021 and will be retroactively effective back to November 2020. In July 2020, the Administrative Law Judge granted an unopposed motion to schedule a hearing for Aug. 13, 2020 to review the settlement.
PSCo — Colorado 2019 Electric Rate Case — In 2019, PSCo filed a request with the CPUC seeking a net rate increase of$108.4 million, based on a requested ROE of 10.2% and an equity ratio of 55.6%.
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In February 2020, the CPUC issued a written decision, resulting in an estimated $34.9 million net base rate revenue increase. The CPUC decision included a 9.3% ROE, an equity ratio of 55.61%, based on a current test year ended Aug. 31, 2019, implementation of decoupling in 2020 and other items.
In May 2020, the CPUC deliberated on PSCo’s request for rehearing and revised its prior decision on the test year calculation, return on prepaid pension and medical assets, a disallowance of a capital investment for the Comanche Unit 3 superheater and Board compensation. In July 2020, the CPUC’s written decision was received. As a result, electric rates will increase approximately $12 million, retroactive back to Feb. 25, 2020. In addition, as a part of the rehearing, the CPUC plans to discuss the merits of opening an investigation of Comanche Unit 3 performance.
PSCo — Boulder Municipalization — In 2011, Boulder passed a ballot measure authorizing the formation of an electric municipal utility, subject to certain conditions. Subsequently, there have been various legal proceedings in multiple venues with jurisdiction over Boulder’s plan. In 2014, the Boulder City Council passed an ordinance to establish an electric utility. PSCo challenged the formation of this utility and the Colorado Court of Appeals ruled in PSCo’s favor, vacating a lower court decision. In June 2018, the Colorado Supreme Court rejected Boulder’s request to dismiss the case and remanded it to the Boulder District Court. The case was then settled in June 2019 after Boulder agreed to repeal the ordinance establishing the utility.
Boulder has filed multiple separation applications with the CPUC, which have been challenged by PSCo and other intervenors. In September 2017, the CPUC issued a written decision, agreeing with several key aspects of PSCo’s position. The CPUC has approved the designation of some electrical distribution assets for transfer, subject to Boulder completing certain filings.
In the fourth quarter of 2018, the Boulder City Council also adopted an Ordinance authorizing Boulder to begin negotiations for the acquisition of certain property or to otherwise condemn that property after Feb. 1, 2019. In the first quarter of 2019, Boulder sent PSCo a notice of intent to acquire certain electric distribution assets. In the third quarter of 2019, Boulder filed its condemnation litigation, which was later dismissed by the Boulder District Court in September 2019 on the grounds that Boulder had not completed the pre-requisite CPUC process and filings. Boulder is currently appealing this order. In October 2019, the CPUC approved the subsequent filings regarding asset transfers outside of substations, reaffirmed its 2017 decision on assets outside of substations and closed the CPUC proceeding.
In December 2019, Boulder filed a new condemnation action despite its ongoing appeal of the last condemnation case. PSCo subsequently filed a motion to dismiss or stay the new condemnation action. In February 2020, Boulder filed an application under section 210 of the Federal Power Act asking FERC to order PSCo to interconnect its facilities with a future Boulder municipal utility under Boulder’s preferred terms and conditions.
In July 2020, PSCo reached a settlement with certain Boulder officials that would end the city’s effort to municipalize. The settlement, if approved, would result in a 20-year franchise arrangement (with multiple opt-out conditions), an energy partnership, an undergrounding agreement and establish how the municipalization would move forward if Boulder exercised an opt-out. The settlement will require approval by the Boulder City Council in August 2020 and will further require approval by the citizens of Boulder in a ballot referendum in November 2020.
SPS — New Mexico 2019 Electric Rate Case — In 2019, SPS filed an electric rate case with the New Mexico Public Regulation Commission (NMPRC) seeking an increase in retail electric base rates of approximately $47 million. The rate request was based on an ROE of 10.10%, an equity ratio of 54.77%, a rate base of approximately $1.3 billion and a historic test year with rate base additions through Aug. 31, 2019. The request also included an increase of $14.6 million for accelerated depreciation including the early retirement of the Tolk coal plant in 2032.
In May 2020, the NMPRC approved a settlement, without modification, between SPS and various parties, which includes the following terms:
•Base rate revenue increase of $31 million;
•ROE of 9.45%;
•Equity ratio of 54.77%; and
•Acceleration of depreciation on the Tolk coal plant to reflect early retirement in 2037. The parties to the stipulation agreed not to oppose the full application of depreciation rates associated with the 2032 retirement date in SPS’ next base rate case.
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SPS — Texas 2019 Electric Rate Case — In August 2019, SPS filed an electric rate case with the PUCT seeking an increase in retail electric base rates of approximately $141 million. The filing requests an ROE of 10.35%, a 54.65% equity ratio, rate base of approximately $2.6 billion and is built on a 12 month period that ended June 30, 2019. SPS’ request was subsequently revised in March 2020 to approximately $130 million, based on a requested ROE of 10.1%, a 54.62% equity ratio, rate base of approximately $2.6 billion and historic test year ended June 30, 2019.
In May 2020, SPS and intervening parties filed an unopposed blackbox settlement, which reflects the following terms.
•An electric rate increase of $88 million;
•ROE of 9.45% and equity ratio of 54.62% for AFUDC purposes;
•Acceleration of the depreciation life of the Tolk coal plant; and
•Ring fence measures, similar to other Texas utilities.
Final rates are expected to be retroactively applied as of Sept. 12, 2019. A decision from the PUCT is anticipated in the third quarter of 2020.
Note 5. COVID-19
Although COVID-19 represents an unprecedented event that has led to numerous challenges, Xcel Energy believes its risk management program, including business continuity and disaster recovery planning, will allow us to proactively manage and successfully navigate the challenges, risks and uncertainties associated with the pandemic. In addition, we have implemented O&M contingency plans to reduce costs and seek regulatory deferral mechanisms to offset the negative impact of COVID-19 on sales, bad debt and other aspects of our business.
A high degree of uncertainty exists regarding COVID-19, the duration and magnitude of business restrictions, re-shut downs, if any, and the level and pace of recovery of the economy. Also, while we are implementing contingency plans, there are no guarantees these plans will be sufficient to offset the impact of COVID-19. The ultimate impact of this pandemic could have a material impact on Xcel Energy’s operations, financial results and cash flow.
An overview of certain risk considerations or areas which have or could significantly impact us, is as follows.
Sales — In the first half of 2020, Xcel Energy experienced a decline in weather and leap year adjusted sales. The decline in sales was primarily due to pandemic related mandates implemented in March 2020 involving the closure of non-essential businesses and state directives for individuals to stay-at-home. The stay-at-home directives and business closures moderated in May 2020.
Xcel Energy has decoupling and sales true-up mechanisms in Minnesota (all electric classes) and Colorado (residential and non-demand SC&I electric classes), which mitigate the impact of changes to sales levels as compared to a base line.
The following scenarios outline the potential impact of the pandemic on electric and natural gas sales and EPS, based on various assumptions of the duration of the stay-at-home provisions and economic recovery:
•Mild Scenario (severe impact through May with a V-shaped economic recovery).
◦Impact on weather-adjusted electric sales for 2020: an increase of ~1% in residential sales; a decline of ~4% in C&I sales; and a decline in total retail electric sales of ~2%.
◦Impact on 2020 natural gas sales: ~0%.
◦This sales decline would reduce EPS by approximately $0.11.
•Base Case Scenario (severe impact through the second quarter with slower U-shaped recovery with lingering effects).
◦Impact on weather-adjusted electric sales for 2020: an increase of ~1% in residential sales; a decline of 6% in C&I sales; and a decline in total retail electric sales of ~4%.
◦Impact on 2020 natural gas sales: a decline of ~1%.
◦This sales decline would reduce EPS by approximately $0.17.
•Severe Scenario (severe impact through the third quarter followed by protracted challenged L-shaped recovery).
◦Impact on weather-adjusted electric sales for 2020: an increase of ~1% in residential sales; a decline of ~12% in C&I sales; and a decline in total retail electric sales of ~8%.
◦Impact on 2020 natural gas sales: a decline of ~2%.
◦This sales decline would reduce EPS by approximately $0.37.
•Potential impacts due to other items could have negative EPS impact of $0.02 to $0.05, assuming constructive regulatory treatment.
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The estimated impact on our monthly weather-adjusted electric sales in the second quarter (primarily COVID-19) is as follows:
| Month | Residential | C&I | Total Electric Sales | |||||||||||||||||
| April | 3.2% | (13.7)% | (9.6)% | |||||||||||||||||
| May | 5.1 | (10.6) | (6.7) | |||||||||||||||||
| June | 8.9 | (10.0) | (4.7) | |||||||||||||||||
Xcel Energy incorporated the base case scenario into our 2020 guidance assumptions. The second quarter sales results came in better than anticipated in our base case scenario, however there still is substantial uncertainty on the adverse impact of COVID-19 for the remainder of the year.
Bad Debt — In March 2020, Xcel Energy announced it would not disconnect residential customers’ electric or natural gas service during the virus outbreak. Certain states have issued additional limitations on charging late fees and extended protection to other customer classes. Bad debt expense could significantly increase due to regulatory orders, pandemic related economic impacts and customers hardship. However, several of our commissions are allowing the deferral of incremental COVID-19 related expense, including bad debt expense as discussed further under Regulatory.
Regulatory — Xcel Energy has received orders in Minnesota, Wisconsin, Texas, New Mexico and Michigan, allowing regulatory deferral of incremental COVID-19 costs as a regulatory asset subject to future determination of amount and timing of recovery. Costs include, but are not limited to, bad debt expense, suspension of disconnections, waived late fees and other costs and/or foregone revenues.
Xcel Energy has also filed requests in North Dakota and South Dakota to record a regulatory asset and defer all incremental expenses related to the pandemic. In July 2020, PSCo reached an agreement with Staff and the OCC on the deferral of COVID-19 related bad debt expense. These requests are pending regulatory approval.
Xcel Energy serves the majority of its wholesale customers under formula transmission and production rates which true-up rates to actual costs to serve.
Xcel Energy deferred approximately $3 million of related expenses as of June 30, 2020. We will continue to monitor these costs and assess whether the actions of the regulator provide the evidence necessary to defer amounts as regulatory assets.
Contingency Plan — Xcel Energy has implemented contingency plans to reduce costs to offset the negative impact of COVID-19. Actions include reductions of employee expenses, consulting, variable compensation, delays of certain work activities, attrition and implementation of a hiring freeze. Based on these actions, our base case assumption is that 2020 O&M expenses will decline 4% to 5% compared with 2019. The ultimate level of O&M expenses will be dependent on actual sales levels.
We believe we can deliver earnings within our 2020 guidance range based on implementing contingency plans to offset the impact of the pandemic on sales and expense levels under the base case scenario. However, our contingency plans may not be able to offset the negative impact of COVID-19 under a severe scenario.
Supply Chain and Capital Expenditures — Xcel Energy’s ability to meet customer energy requirements, respond to storm-related disruptions and maintain our capital expenditure program are dependent on maintaining an efficient supply chain. During the first half of 2020, Xcel Energy did not experience any material supply chain, contractor or employee disruptions that prevented us from performing maintenance or construction activity. As a result, we have not significantly adjusted our 2020 capital expenditure plan.
However, in April 2020, we were informed of supply chain disruptions, which will likely result in delays in the completion of two of our wind farms into 2021. In May 2020, the U.S. Treasury provided a one-year extension of the continuity PTC safe harbor for renewable projects, including wind and solar, that began construction in 2016 or 2017. Thus, we believe these wind farms will meet the IRS continuity requirements if ultimately placed in service in 2021. As a result, we expect these wind projects will qualify for 100% PTC benefit.
Pension — The funded status of the Xcel Energy pension plans was approximately 90% in January 2020. The funded status of the pension plan is estimated to be approximately 83%, based on market conditions as of June 2020.
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Xcel Energy does not expect any material changes to its pension funding requirement at this time. In addition, Xcel Energy has pension trackers in Colorado and Texas, which allow us to defer amounts that are above or below a baseline.
Liquidity — Xcel Energy has taken steps to enhance its liquidity and believes it has more than adequate liquidity. We have completed our debt issuance plans for Xcel Energy and its operating companies for 2020. In July 2020, we completed the sale of the MEC facility which provided an additional $650 million of funds. As a result of these actions, Xcel Energy had approximately $4.5 billion of available liquidity as of July 27, 2020.
Furthermore, Xcel Energy has an outstanding forward equity agreement in connection with a $743 million public offering of 11.8 million shares. These shares have not been issued and we expect to settle this equity forward later in 2020, which will further enhance liquidity. Finally, Xcel Energy continues to have access to the capital markets on favorable terms.
For more information, see Note 3 Capital Structure, Liquidity, Financing and Credit Ratings.
Customer Service & Reliability — Xcel Energy remains committed to continuing to safely deliver reliable services to our customers as families and communities face the COVID-19 pandemic. We have exercised our business continuity plans to safely serve our customers, protect our employees and ensure critical positions remain staffed.
Key actions include:
•Executing work-from-home practices for employees who can do their work remotely;
•Enhancing cleaning practices within our facilities;
•Providing proper personal protective equipment and following CDC and state guidelines;
•Conducting employee temperature checks;
•Changing work practices to promote social distancing;
•Splitting crews and staggering work times;
•Limiting employee entry into customer homes to emergency situations only; and
•Reminding customers of increased risks of scam activity.
Employees — The health and safety of our workforce is one of our core values and we have taken several actions that reflect that during this pandemic:
•Continued pay for employees who have been quarantined and provide training to employees on how to stay safe and social distance;
•Expanded medical plan coverage for employees and their families to include 100% of COVID-19 medical costs;
•Offered up to an additional 80 hours of paid time off to employees for pandemic related illness;
•Expanded eligibility for our paid time off donation program to employees who have or are caring for a family member who has been diagnosed with the virus;
•Offered new anxiety and stress management tools, in addition to our existing Employee Assistance Program;
•Provided resources and educational materials to support employees adjusting to distance learning with their children; and
•Implemented an employee part-time and voluntary leave of absence program for pandemic-related needs.
Communities — Xcel Energy is committed to the communities in which we operate. Actions include the following:
•Plan to donate approximately $20 million in corporate giving, including COVID-19 relief in 2020.
•Donated over 300,000 masks to hospitals in the communities we serve; and launched a special $300,000 COVID-19 two-to-one matching campaign, which provides a match for employee donations to impacted non-profit organizations, in addition to our standard employee matching gift programs;
•Donating over 2.5 million high efficiency light bulbs;
•Submitted a proposal to reduce our approved 2020 Fuel Forecast by $25 million to provide immediate relief to our Minnesota customers, which will be implemented across the three summer months equally. Additionally, we proposed temporary relief to certain businesses in Minnesota through the Business Incentive and Sustainability Rider (approximately $6 million); and
•See Note 4 for discussion of the Minnesota Relief and Recovery filing.
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Note 6. Earnings Guidance and Long-Term EPS and Dividend Growth Rate Objectives
Xcel Energy 2020 Earnings Guidance — Xcel Energy reaffirms 2020 EPS earnings guidance of $2.73 to $2.83 per share (a) (b), which assumes the implementation of contingency plans will be sufficient to offset the negative impacts of COVID-19 under the base case scenario. However, these contingency plans would not be sufficient to offset the negative impacts of COVID-19 under the severe scenario, which would likely result in earnings below the guidance range. For additional information on the scenarios, see Note 5.
Key assumptions as compared with 2019 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 decline ~4%, under the base case scenario.
•Weather-normalized retail firm natural gas sales are projected to decline ~1%, under the base case scenario.
•Capital rider revenue is projected to increase $40 million to $45 million (net of PTCs). PTCs are credited to customers, through capital riders and reductions to electric margin.
•O&M expenses are projected to decline approximately 4% to 5% under the base case scenario.
•Depreciation expense is projected to increase approximately $180 million to $190 million, reflecting updated depreciation rates in regulatory proceedings which are offset by revenue increases.
•Property taxes are projected to increase approximately $35 million to $45 million.
•Interest expense (net of AFUDC - debt) is projected to increase $45 million to $55 million.
•AFUDC - equity is projected to increase approximately $35 million to $45 million.
•The ETR is projected to be ~0%. 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.
(b) The global outbreak of COVID-19 is currently impacting countries, communities, supply chains and markets. The ultimate severity of this event is uncertain and could have a material impact on our liquidity, financial condition, or results of operations.
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 2019 base of $2.60 per share, which represents the mid-point of the original 2019 guidance range of $2.55 to $2.65 per share;
• Deliver annual dividend increases of 5% to 7%;
• Target a dividend payout ratio of 60% to 70%; and
• Maintain senior secured debt credit ratings in the A range.
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XCEL ENERGY INC. AND SUBSIDIARIES
EARNINGS RELEASE SUMMARY (UNAUDITED)
(amounts in millions, except per share data)
| Three Months Ended June 30 | ||||||||||||||
| 2020 | 2019 | |||||||||||||
| Operating revenues: | ||||||||||||||
| Electric and natural gas | $ | 2,566 | $ | 2,557 | ||||||||||
| Other | 20 | 20 | ||||||||||||
| Total operating revenues | 2,586 | 2,577 | ||||||||||||
| Net income | $ | 287 | $ | 238 | ||||||||||
| Weighted average diluted common shares outstanding | 527 | 518 | ||||||||||||
| Components of EPS — Diluted | ||||||||||||||
| Regulated utility | $ | 0.60 | $ | 0.53 | ||||||||||
| Xcel Energy Inc. and other costs | (0.07) | (0.06) | ||||||||||||
GAAP and ongoing diluted EPS (a) | $ | 0.54 | $ | 0.46 | ||||||||||
| Book value per share | $ | 25.39 | $ | 23.96 | ||||||||||
| Cash dividends declared per common share | 0.43 | 0.41 | ||||||||||||
| Six Months Ended June 30 | ||||||||||||||
| 2020 | 2019 | |||||||||||||
| Operating revenues: | ||||||||||||||
| Electric and natural gas | $ | 5,352 | $ | 5,676 | ||||||||||
| Other | 45 | 42 | ||||||||||||
| Total operating revenues | 5,397 | 5,718 | ||||||||||||
| Net income | $ | 582 | $ | 553 | ||||||||||
| Weighted average diluted common shares outstanding | 527 | 517 | ||||||||||||
| Components of EPS — Diluted | ||||||||||||||
| Regulated utility | $ | 1.20 | $ | 1.18 | ||||||||||
| Xcel Energy Inc. and other costs | (0.10) | (0.11) | ||||||||||||
GAAP and ongoing diluted EPS (a) | 1.10 | 1.07 | ||||||||||||
| Book value per share | $ | 25.40 | $ | 23.92 | ||||||||||
| Cash dividends declared per common share | 0.86 | 0.81 | ||||||||||||
(a) Amounts may not add due to rounding.
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