XCEL ENERGY INC. The following discussion and analysis by management focuses on those factors that had a material effect onXcel Energy's financial condition, results of operations and cash flows during the periods presented, or are expected to have a material impact in the future. It should be read in conjunction with the accompanying unaudited consolidated financial statements and the related notes to consolidated financial statements. Due to the seasonality ofXcel Energy's operating results, quarterly financial results are not an appropriate base from which to project annual results. The demand for electric power and natural gas is affected by seasonal differences in the weather. In general, peak sales of electricity occur in the summer months, and peak sales of natural gas occur in the winter months. As a result, the overall operating results may fluctuate substantially on a seasonal basis. Additionally,Xcel Energy's operations have historically generated less revenues and income when weather conditions are milder in the winter and cooler in the summer. Non-GAAP Financial Measures The following discussion includes financial information prepared in accordance with GAAP, as well as certain non-GAAP financial measures such as 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. 21
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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, O&M expenses, conservation and 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 calculateXcel 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 dilutedXcel 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 dilutedXcel Energy Inc. common shares outstanding for the period. We use these non-GAAP financial measures to evaluate and provide details ofXcel 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 nine months endedSept. 30, 2020 and 2019, there were no such adjustments to GAAP earnings and therefore GAAP earnings equal ongoing earnings for these periods. Results of Operations The only common equity securities that are publicly traded are common shares ofXcel Energy Inc. Diluted earnings and EPS of each subsidiary discussed below do not represent a direct legal interest in the assets and liabilities allocated to such subsidiary but rather represent a direct interest in our assets and liabilities as a whole. All companies were negatively impacted by the pandemic starting inMarch 2020 and continuing into the third quarter. See COVID-19 section below for further information, including estimated impact on weather-adjusted electric sales. Summarized diluted EPS forXcel Energy : Three Months Ended Sept. 30 Nine Months Ended Sept. 30 Diluted Earnings (Loss) Per Share 2020 2019 2020 2019 NSP-Minnesota $ 0.46$ 0.40 $ 0.89$ 0.81 PSCo 0.42 0.39 0.87 0.86 SPS 0.24 0.20 0.46 0.42 NSP-Wisconsin 0.08 0.06 0.16 0.12 Equity earnings of unconsolidated subsidiaries 0.01 0.01 0.04 0.04 Regulated utility (a) 1.21 1.06 2.42 2.24 Xcel Energy Inc. and Other (0.07)
(0.05) (0.17) (0.16) Total (a) $ 1.14$ 1.01 $ 2.25$ 2.08 (a) Amounts may not add due to rounding. Summary of EarningsXcel Energy -Xcel Energy's earnings increased$0.13 per share for the third quarter of 2020 and$0.17 per share year-to-date. Earnings primarily reflect higher electric margin (largely due to capital investment recovery) and AFUDC, which offset increased depreciation and declining sales due to the impacts of COVID-19. NSP-Minnesota - Earnings increased$0.06 per share for the third quarter of 2020 and$0.08 per share year-to-date. Year-to-date results reflect lower O&M expenses and higher electric margin (regulatory outcomes offset lower sales primarily due to COVID-19), partially offset by increased depreciation and lower natural gas margin. PSCo - Earnings increased$0.03 per share for the third quarter of 2020 and$0.01 per share year-to date. The increase in year-to-date earnings was driven by higher electric margin (regulatory outcomes offset lower sales due to COVID-19), increased AFUDC and reduced O&M expenses, partially offset by higher depreciation, interest expense and taxes (other than income taxes). SPS - Earnings increased$0.04 per share for the third quarter of 2020 and$0.04 per share year-to-date. Year-to-date results reflect higher electric margin (regulatory outcomes offset lower sales due to COVID-19) and lower O&M expenses, partially offset by increased depreciation, interest expense and taxes (other than income taxes). NSP-Wisconsin - Earnings increased$0.02 per share for the third quarter of 2020 and$0.04 per share year-to-date. The increase in year-to-date earnings was driven by higher electric margin (2020 Wisconsin Fuel Settlement offset lower sales due to COVID-19) and AFUDC, as well as lower O&M expenses. These items were partially offset by increased depreciation and lower natural gas margin.Xcel Energy Inc. and Other - Primarily includes financing costs at the holding company. 22
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Changes in GAAP and Ongoing Diluted EPS
Components significantly contributing to changes in 2020 EPS compared with the
same period in 2019:
Three Months Ended Nine Months Ended Sept.
Diluted Earnings (Loss) Per Share Sept. 30 30
GAAP and ongoing diluted EPS - 2019 $ 1.01 $ 2.08
Components of change - 2020 vs. 2019
Higher electric margin (a) 0.20 0.22
Lower ETR (b) 0.07 0.17
Lower O&M - 0.08
Higher AFUDC 0.03 0.07
Higher depreciation and amortization (0.09) (0.19)
Higher interest charges (0.03) (0.07)
Lower natural gas margins - (0.03)
Lower other income (expense), net (0.01) (0.03)
Other (net) (0.04) (0.05)
GAAP and ongoing diluted EPS - 2020 $ 1.14 $ 2.25
(a) Period-over-period change in electric margin was negatively impacted by reductions in sales and demand due to COVID-19 as follows:
Three Months Ended Sept. Nine Months Ended Sept.
Diluted Earnings (Loss) Per Share 30 30
Electric margin (excluding reductions in sales
and demand) $ 0.21 $ 0.30
Reductions in sales and demand (*) (0.01) (0.08)
Higher electric margins $ 0.20 $ 0.22
(*) Sales decline excludes weather impact, net of decoupling/sales true-up and
decrease in demand revenue is net of sales true-up.
(b) Includes PTCs and tax reform regulatory amounts, which are primarily
offset in electric margin.
Statement of Income Analysis
The following summarizes the items that affected the individual revenue and
expense items reported in the consolidated statements of income.
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 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. HDD is the measure of the variation in the weather
based on the extent to which the average daily temperature falls below 65°
Fahrenheit. 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.
Percentage increase (decrease) in normal and actual HDD, CDD and THI:
Three Months Ended Sept. 30 Nine Months Ended Sept. 30
2020 vs. Normal 2019 vs. Normal 2020 vs. 2019 2020 vs. Normal 2019 vs. Normal 2020 vs. 2019
HDD 48.4 % (64.0) % 251.2 % (2.8) % 10.7 % (11.2) %
CDD 20.7 27.4 1.3 21.2 6.4 21.3
THI 4.6 (2.6) 8.3 7.0 (8.2) 18.3
Weather - Estimated impact of temperature variations on EPS compared with normal
weather conditions:
Three Months Ended Sept. 30 Nine Months Ended Sept. 30
2019 vs.
2020 vs. Normal 2019 vs. Normal 2020 vs. 2019 2020 vs. Normal Normal 2020 vs. 2019
Retail electric $ 0.079 $ 0.040 $ 0.039 $ 0.096 $ 0.035 $ 0.061
Decoupling and sales
true-up (0.035) - (0.035) (0.044) 0.001 (0.045)
Electric total $ 0.044 $ 0.040 $ 0.004 $ 0.052 $ 0.036 $ 0.016
Firm natural gas - (0.001) 0.001 (0.005) 0.021 (0.026)
Total $ 0.044 $ 0.039 $ 0.005 $ 0.047 $ 0.057 $ (0.010) Sales - Sales growth (decline) for actual and weather-normalized sales in 2020 compared to the same period in 2019:
Three Months Ended Sept. 30
PSCo NSP-Minnesota SPS NSP-Wisconsin Xcel Energy
Actual (a)
Electric residential 8.7 % 11.8 % 4.4 % 6.6 % 9.1 %
Electric C&I (4.5) (5.2) (5.5) (4.1) (5.0)
Total retail electric sales (0.1) 0.1 (3.5) (1.2) (0.9)
Firm natural gas sales 1.1 2.1 N/A 11.2 2.0
Three Months Ended Sept. 30
PSCo NSP-Minnesota SPS NSP-Wisconsin Xcel Energy
Weather-Normalized (a)
Electric residential 3.8 % 4.3 % 2.2 % 2.0 % 3.7 %
Electric C&I (4.2) (5.3) (5.0) (4.6) (4.8)
Total retail electric sales (1.6) (2.3) (3.5) (2.7) (2.4)
Firm natural gas sales (4.8) (1.8) N/A 6.6 (3.3)
Nine Months Ended Sept. 30
PSCo NSP-Minnesota SPS NSP-Wisconsin Xcel Energy
Actual (a)
Electric residential 6.9 % 5.6 % 5.0 % 2.9 % 5.8 %
Electric C&I (4.2) (7.3) (3.4) (5.6) (5.2)
Total retail electric sales (0.7) (3.4) (2.0) (3.2) (2.2)
Firm natural gas sales (7.3) (9.3) N/A (9.9) (8.1)
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Nine Months Ended Sept. 30
PSCo NSP-Minnesota SPS NSP-Wisconsin Xcel Energy
Weather-Normalized (a)
Electric residential 3.5 % 3.3 % 2.0 % 2.7 % 3.2 %
Electric C&I (4.7) (7.5) (3.5) (5.8) (5.5)
Total retail electric sales (2.1) (4.2) (2.6) (3.4) (3.1)
Firm natural gas sales (1.7) 2.2 N/A 3.6 (0.2)
Nine Months Ended Sept. 30 (Leap Year Adjusted)
PSCo NSP-Minnesota SPS NSP-Wisconsin Xcel Energy
Weather-Normalized (a)
Electric residential 3.2 % 3.0 % 1.6 % 2.3 % 2.8 %
Electric C&I (5.1) (7.8) (3.9) (6.2) (5.8)
Total retail electric sales (2.5) (4.6) (3.0) (3.8) (3.5)
Firm natural gas sales (2.5) 1.4 N/A 2.8 (1.0)
(a) Higher residential sales and lower C&I sales were primarily attributable
to COVID-19.
Weather-normalized and leap-year adjusted electric sales growth (decline) -
year-to-date (excluding leap day)
•PSCo - Residential sales rose based on higher use per customer from increased
working from home and an increased number of customers. The decline in C&I sales
was primarily due to the economic contraction from COVID-19, particularly noted
within the manufacturing and service industries.
•NSP-Minnesota - Residential sales growth reflects higher use per customer from
increased working from home and an increase in customers. Decrease in C&I sales
were driven by the energy, manufacturing and services sectors, primarily related
to COVID-19.
•SPS - Residential sales increased due to customer growth and higher use per
customer from increased working from home. The decline in C&I sales was driven
by shutdowns of the economy from COVID-19, primarily within the energy and
manufacturing sectors.
•NSP-Wisconsin - Residential sales growth was attributable to higher use per
customer from increased working from home and customer additions. The decline in
C&I sales was largely related to COVID-19, specifically 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 primarily lower C&I customer use due to the economic
contraction from COVID-19, partially offset by an increase in number of
residential and C&I customers.
Electric Margin
Electric revenues and fuel and purchased power expenses are impacted by
fluctuations in the price of natural gas, coal and uranium. However, these price
fluctuations have minimal impact on electric margin due to fuel recovery
mechanisms that recover fuel expenses. In addition, electric customers receive a
credit for PTCs generated, which reduced electric revenue and margin.
Electric revenues and margin:
Three Months Ended Sept. 30 Nine Months Ended Sept. 30
(Millions of Dollars) 2020 2019 2020 2019
Electric revenues $ 2,941 $ 2,771 $ 7,430 $ 7,345
Electric fuel and
purchased power (981) (952) (2,611) (2,679)
Electric margin $ 1,960 $ 1,819 $ 4,819 $ 4,666
Changes in electric margin:
Three MonthsEnded Nine Months Ended
Sept. 30, 2020 vs. Sept. 30, 2020 vs.
(Millions of Dollars) 2019 2019
Regulatory rate outcomes (Colorado , Wisconsin ,
Texas and New Mexico) (a) $ 123 $ 158
Non-fuel riders 19 43
Wholesale transmission revenue (net) 10 35
MEC purchased capacity costs (b) 4 35
Estimated impact of weather (net of
decoupling/sales true-up) 4 12
PTCs flowed back to customers (offset by lower ETR) (28) (81)
Sales and demand (c) (9) (56)
Other (net) 18 7
Total increase in electric margin $ 141 $ 153
(a) Includes approximately $70 million of revenue and margin due to the Texas
rate case outcome, which is largely offset by recognition of previously deferred
costs, see Public Utility Regulation below for additional information.
(b) Prior to the MEC acquisition (first quarter of 2020), all purchased power
costs were recorded as a component of electric fuel and purchased power. During
Xcel Energy's ownership of MEC, all non-fuel related costs including
depreciation, O&M and interest expenses were recorded within separate statement
of income line items in our consolidated financial results. MEC was sold in the
third quarter of 2020.
(c) Sales increase (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 Sept. 30 Nine Months Ended Sept. 30
(Millions of Dollars) 2020 2019 2020 2019
Natural gas revenues $ 219 $ 222 $ 1,082 $ 1,324
Cost of natural gas sold
and transported (54) (55) (425) (646)
Natural gas margin $ 165 $ 167 $ 657 $ 678 Changes in natural gas margin:
Three Months Ended Nine Months Ended
Sept. 30, 2020 vs. Sept. 30, 2020 vs.
(Millions of Dollars) 2019 2019
Estimated impact of weather $ 1 $ (18)
Retail sales decline (1) (2)
Regulatory rate outcomes (Wisconsin) - (2)
Transport sales 1 (1)
Infrastructure and integrity riders 1 6
Other (net) (4) (4)
Total decrease in natural gas margin $ (2) $ (21)
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Non-Fuel Operating Expenses and Other Items O&M Expenses - O&M expenses decreased$1 million , or 0.2%, for the third quarter and$56 million , or 3.2%, 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: Three Months Ended Nine Months Ended Sept. 30, 2020 vs. Sept. 30, 2020 vs. (Millions of Dollars) 2019 2019 Distribution $ (10) $ (40) Transmission (4) (10) Generation (3) (8) Texas rate case deferral 13 5 Other (net) 3 (3) Total decrease in O&M expenses $ (1) $ (56) •Distribution declined due to cost mitigation/continuous improvement efforts and the timing of maintenance activities; •Transmission declined due to cost mitigation/continuous improvement initiatives. •Generation was lower from timing of maintenance and overhauls at power plants and cost mitigation/continuous improvement efforts, which were partially offset by an increase in wind related O&M expenses from our renewable expansion. •Texas rate case deferral amounts were due to recognition of previously deferred amounts related with the Texas Electric Rate Case. •Included within Other (net) are amounts associated with the sale of MEC. During the third quarter of 2020,Xcel Energy recognized a net gain of approximately$20 million on the sale, which was offset by charitable giving, including COVID-19 relief efforts. Depreciation and Amortization - Depreciation and amortization increased$66 million , or 14.8%, for the third quarter and$130 million , or 9.9%, year-to-date. Increase was primarily driven by Hale,Lake Benton , Foxtail, Blazing Star I andCheyenne Ridge wind facilities going into service, as well as normal system expansion. In addition, new depreciation rates were implemented inColorado ,New Mexico andTexas as part of regulatory outcomes in 2020. Other Income (Expense) - Other income (expense) decreased$7 million for the third quarter and$20 million year-to-date. The decrease was substantially due to the performance of rabbi trust investments primarily in the first half of 2020, which was offset in O&M expenses. AFUDC, Equity and Debt - AFUDC increased$19 million for the third quarter and$42 million year-to-date. Increase was primarily due to various wind projects under construction. Interest Charges - Interest charges increased$22 million , or 11.1%, for the third quarter and$50 million , or 8.7% year-to-date. The increase was largely 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$29 million for the third quarter. The decrease was primarily driven by an increase in wind PTCs, an increase in plant regulatory differences and a carryback tax benefit, partially offset by higher pretax earnings. 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 6.7% for the third quarter of 2020 compared with 12.0% for 2019. Income taxes decreased$97 million year-to-date. The decrease was primarily driven by an increase in wind PTCs 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 2.0% for the first nine months endingSept. 30, 2020 compared with 10.1% for 2019. Public Utility Regulation TheFERC and various state and local regulatory commissions regulateXcel Energy Inc.'s utility subsidiaries and WGI. The electric and natural gas rates charged to customers ofXcel Energy Inc.'s utility subsidiaries and WGI are approved by theFERC or the regulatory commissions in the states in which they operate. The rates are designed to recover plant investment, operating costs and an allowed return on investment.Xcel Energy Inc.'s utility subsidiaries request changes in rates for utility services through filings with governing commissions. Changes in operating costs can affectXcel Energy's financial results, depending on the timing of rate case filings and implementation of final rates. Other factors affecting rate filings are new investments, sales, conservation and DSM efforts, and the cost of capital. In addition, the regulatory commissions authorize the ROE, capital structure and depreciation rates in rate proceedings. Decisions by these regulators can significantly impactXcel Energy's results of operations. Except to the extent noted below, the circumstances set forth in Public Utility Regulation included in Item 7 of Xcel Energy's Annual Report on Form 10-K for the year endedDec. 31, 2019 and in Item 2 ofXcel Energy's Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2020 and Form 10 -Q for the quarterly period ended June 30, 2020 appropriately represent, in all material respects, the current status of public utility regulation and are incorporated by reference. NSP-Minnesota Pending and Recently Concluded Regulatory Proceedings Amount Filing Proceeding (in millions) Date Approval 2020 Electric Rate Case TBD November 2020 Pending Filing 2020 TCR Electric Rider$82 November 2019 Pending 2020 GUIC Electric Rider$21 November 2019 Pending 2020 RES Electric Rider$102 November 2019 Pending Additional Information: 2020 Electric Rate Case - NSP-Minnesota plans to file an electric rate case inNovember 2020 , including a stay-out alternative. TCR Electric Rider - InNovember 2019 , NSP-Minnesota filed the TCR Rider. The filing included an ROE of 9.06%. Timing of an MPUC ruling is uncertain. GUIC Electric Rider - InNovember 2019 , NSP-Minnesota filed the GUIC Rider with the MPUC. The filing included an ROE of 9.04%. Timing of an MPUC ruling is uncertain. 25
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RES Electric Rider - InNovember 2019 , NSP-Minnesota filed the RES Rider with the MPUC. The requested amount includes a true-up for the 2019 rider of$38 million and the 2020 requested amount of$64 million . The filing included an ROE of 9.06%. Timing of an MPUC ruling is uncertain. NSP-Minnesota - Minnesota Resource Plan - InJuly 2019 , NSP-Minnesota filed itsMinnesota 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. InJune 2020 , NSP-Minnesota filed a supplement to its resource plan, including new modeling scenarios required by the 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 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 theMonticello nuclear plant from 2030 to 2040; •Continuing to run thePrairie 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. Initial comments are dueJan. 15, 2021 and reply comments are dueMarch 15, 2021 . The MPUC is anticipated to make a final decision during 2021. Minnesota Relief and Recovery - In 2020, the MPUC opened a 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. NSP-Minnesota's filing included the following components: •InSeptember 2020 , NSP-Minnesota proposed to accelerate approximately$865 million of grid investment and sought approval for approximately$150 million of incremental electric vehicle rebates; •InSeptember 2020 , NSP-Minnesota proposed to repower 651 MW of owned wind projects with a capital investment of approximately$750 million . In addition, developers proposed repowering 67 MW of wind projects under power purchase agreements (PPAs). NSP-Minnesota estimates over$160 million in customers savings over the life of the projects. NSP-Minnesota has requested a decision from the MPUC by year-end. •In the first quarter of 2021, NSP-Minnesota plans to propose solar facilities of approximately 460MW with an incremental investment of approximately$650 million . NSP-Minnesota anticipates a MPUC decision in the second or third quarter of 2021. Minnesota State ROFR Statute Complaint - InSeptember 2017 , LSP Transmission filed a complaint in theMinnesota District Court against theMinnesota Attorney General, MPUC and DOC. The complaint was in response to MISO assigningNSP-Minnesota andITC Midwest, LLC to jointly own a new 345 kilovolt transmission line fromMankato toWinnebago, Minnesota . The project is estimated to cost$140 million and projected to be in-service by the end of 2021. It was assigned to NSP-Minnesota andITC Midwest as the incumbent utilities, consistent with aMinnesota state ROFR statute. The complaint challenged the constitutionality of the statute and is seeking declaratory judgment that the statute violates the Commerce Clause of theU.S. Constitution and should not be enforced. InJune 2018 , theMinnesota District Court grantedMinnesota state agencies and NSP-Minnesota's motions to dismiss with prejudice. LSP Transmission filed an appeal inJuly 2018 . InFebruary 2020 , theEighth Circuit Court of Appeals upheld theMinnesota District Court decision to dismiss. InJune 2020 , the Eighth Circuit denied LSP Transmission's petition for rehearing. LSP Transmission has untilNov. 5, 2020 to seek further review of this appeal with theU.S. Supreme Court . Nuclear Power Operations NSP-Minnesota owns two nuclear generating plants: theMonticello plant and thePrairie Island plant. See Note 12 to the consolidated financial statements of Xcel Energy's Annual Report on Form 10-K for the year ended Dec. 31, 2019, for further information. The circumstances set forth in Nuclear Power Operations and Waste Disposal included in Item 1 of Xcel Energy's Annual Report on Form 10-K for the year ended Dec. 31, 2019, appropriately represent, in all material respects, the current status of nuclear power operations, and are incorporated by reference. NSP-Wisconsin 2019 Electric Fuel Cost Recovery - NSP-Wisconsin's electric fuel costs for 2019 were lower than authorized in rates and outside the 2% annual tolerance band. Under the fuel cost recovery rules, NSP-Wisconsin may retain approximately$3 million of fuel costs and defer the amount of over-recovery in excess of the 2% annual tolerance band for future refund to customers. InAugust 2020 , the PSCW approved NSP-Wisconsin's request to refund over-collections of approximately$10 million to customers. 2021 Electric Fuel Cost Recovery - InJune 2020 , NSP-Wisconsin filed an application with the PSCW to update its 2021 fuel costs and return biomass fuel savings, which would decrease retail electric rates for 2021 by approximately$12 million . NSP-Wisconsin expects a PSCW decision on the application in the fourth quarter of 2020. NSP-Wisconsin Solar Proposal - InOctober 2020 , NSP-Wisconsin filed for a 74 MW solar facility build-own-transfer inWisconsin for approximately$100 million . A PSCW decision is expected in the third quarter of 2021. 26
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PSCo
Pending and Recently Concluded Regulatory Proceedings
Amount Filing
Proceeding (in millions) Date Approval
2020 Natural Gas Rate Case $127 February 2020 Received
2019 Electric Rate Case $158 May 2019 Received
2019 Natural Gas Rate Case Appeal N/A April 2019 Pending
Wildfire Protection Rider $325 July 2020 Pending
Advanced Grid Rider $850 July 2020 Pending
Additional Information:
2020 Natural Gas Rate Case - In October 2020 , the CPUC accepted a recommended
decision by the ALJ to approve a comprehensive settlement without modification
between PSCo, the CPUC Staff and various intervenors. The rate outcome results
in a net increase to retail gas rates of $77 million , reflecting a $94 million
increase in base rate revenue, partially offset by $17 million of costs
previously authorized through the Pipeline Integrity rider. Rates will be
implemented on April 1, 2021 and will be retroactively effective back to
November 2020 . 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.
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%.
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 . In October 2020 , the CPUC initiated a non-adjudicatory review of
Comanche Unit 3's performance to be handled by the CPUC Staff, consistent with
what was signaled during the 2019 Electric Rate Case rehearing. A report is
expected to be issued in the first half of 2021.
2019 Natural Gas Rate Case Appeal - In April 2019 , PSCo filed an appeal seeking
judicial review of the CPUC's prior ruling regarding PSCo's last natural gas
rate case (approved in December 2018 ). The appeal requested review of the
following: denial of a return on the prepaid pension and retiree medical
assets; the use of a capital structure not based on the actual historical test
year; and use of an average rate base methodology rather than a year-end rate
base methodology.
In March 2020 , The District Court of Denver County ruled in favor of allowing
the prepaid pension assets to be included in rate base; but it upheld the CPUC
treatment of the retiree medical assets and capital structure methodology. The
CPUC did not appeal the decision allowing inclusion of the prepaid pension
assets in rate base.
PSCo 2020 Rider Filings
In July 2020 , PSCo filed rider requests with the CPUC instead of filing a
comprehensive electric rate case in 2020.
Wildfire Protection Rider - Seeks to establish a rider to recover incremental
costs associated with system investments to reduce wildfire risk. In August
2020 , the CPUC referred it to an ALJ.
Procedural schedule:
•Answer testimony Nov. 20, 2020 ;
•Rebuttal testimony Dec. 18, 2020 ;
•Settlement by Jan. 8, 2021 ;
•Hearing Jan. 14, 2021 - Jan. 15, 2021 ; and
•Statutory deadline March 24, 2021 .
The rider is expected to be effective in June 2021 and continue through 2025.
Wildfire Protection capital investment is projected to be approximately $325
million . Forecasted annual revenue requirements from 2021 through 2025 are as
follows:
(Millions of Dollars) 2021 2022 2023
2024 2025
Forecasted annual revenue requirement
Advanced Grid Rider - Seeks to establish a rider to recover incremental costs associated with the AGIS initiative. InAugust 2020 , the CPUC referred the matter to an ALJ. InSeptember 2020 , theOffice of Consumer Counsel filed a motion to dismiss the Advanced Grid Rider. Procedural schedule: •Answer testimonyDec. 9, 2020 ; •RebuttalJan. 8, 2021 ; •Settlement byJan. 20, 2021 ; •HearingJan. 25, 2021 -Jan 28, 2021 ; and •Statutory deadlineApril 24, 2021 . The rider is expected to be effective inMay 2021 and continue through 2025. The PSCo portion of the AGIS capital investment is projected to be approximately$850 million . Forecasted annual revenue requirements from 2021 through 2025 are as follows: (Millions of Dollars) 2021 2022 2023
2024 2025
Forecasted annual revenue requirement
PSCo KEPCO Filing - InSeptember 2020 , PSCo filed with the CPUC for approval to terminate a solar PPA with KEPCO Solar ofAlamosa, Inc. and establish a regulatory asset to recover transaction costs of approximately$41 million . By terminating the PPA, customers would save approximately$38 million over an 11-year period. A CPUC decision is expected in the second quarter of 2021. 27
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PSCo - Comanche Unit 3 PSCo is part owner of Comanche Unit 3, a 750 MW, coal-fueled electric generating unit. PSCo is the operating agent under the joint ownership agreement. InJune 2020 , the unit experienced loss of turbine oil during start-up which damaged the plant. It is currently anticipated that Comanche Unit 3 will recommence operations in the fourth quarter of 2020. Replacement and repair of damaged systems in excess of a$2 million deductible are expected to be recovered through insurance policies. PSCo has obtained replacement power for a portion of the unit's output through PPAs. InOctober 2020 , the CPUC initiated a non-adjudicatory review of Comanche Unit 3's performance to be handled by the CPUC Staff, consistent with what was signaled during the 2019 Electric Rate Case rehearing. A report is expected to be issued in the first half of 2021. 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. InSeptember 2020 , theCity Council voted to approve a settlement between PSCo and Boulder officials to end the city's municipalization effort. The settlement would result in a 20-year franchise arrangement (with multiple opt-out conditions), an energy partnership and an undergrounding agreement. It also established the municipalization process if Boulder exercised an opt-out. The citizens of Boulder will vote onNov. 3, 2020 , whether to approve or deny the franchise agreement. PSCo - Natural Gas LDC and Emission Reductions - InOctober 2020 , the CPUC opened a docket to investigate topics related to natural gas emissions in relation to statewide emission reduction goals. The first meeting will be scheduled in the fourth quarter of 2020, in which subject matter experts will discuss greenhouse emission reductions required from the natural gas industry in regard to the statewide goals. SPS Pending and Recently Concluded Regulatory Proceedings Amount Filing Proceeding (in millions) Date
Approval
2019 Texas Electric Rate Case$88 August 2019
Received
2020 New Mexico Electric Rate Case TBD January 2021 Pending Filing 2020 Texas Electric Rate Case TBD February 2021
Pending Filing
Additional Information: 2019 Texas Electric Rate Case - InAugust 2020 , the PUCT approved a settlement between SPS and intervening parties, which reflects the following terms, retroactive toSept. 12, 2019 : •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-fencing measures, similar to otherTexas utilities. SPS expects to submit a filing in the fourth quarter of 2020 to surcharge the final under-recovered amount, which is estimated to be approximately$70 million , offset by the recognition of previously deferred costs. The impact of the retroactive amounts (related to period prior toSept. 1, 2020 ) is as follows: (Millions of Dollars) Nine Months Ended Sept. 30, 2020 Revenue surcharge accrual $ 70 Depreciation and amortization (37) O&M expense (15) Interest expense (11) Taxes other than income taxes (7) 2020 Electric Rate Cases - In the first quarter of 2021, SPS intends to file electric rate cases for both theTexas andNew Mexico jurisdictions due to the settlement reached for the Hale and Sagamore wind farms. Texas State ROFR Litigation - InMay 2019 , the Governor signed into law a ROFR Bill, which grants incumbent utilities a ROFR to build transmission infrastructure when it directly interconnects to the utility's existing facility. InJune 2019 , a complaint was filed in theUnited States District Court for the Western District of Texas claiming the new ROFR law to be unconstitutional. InFebruary 2020 , the federal court complaint was dismissed by the district court. InMarch 2020 , the district court ruling was appealed to theUnited States Court of Appeals for the Fifth Circuit . The parties are awaiting a decision. Texas Fuel Refund - Fuel and purchased power costs are recoverable inTexas through a fixed fuel factor, which is part of SPS' rates. The PUCT rule requires refunding or surcharging of under and over-recovered amounts, including interest, when they exceed 4% of the utility's annual fuel costs. InAugust 2020 , the PUCT approved SPS' request to refund approximately$39 million to customers for over-collected fuel and purchased power costs. New Mexico FPPCAC Continuation - InOctober 2019 , SPS filed an application to the NMPRC to approve SPS' continued use of its FPPCAC and for reconciliation of fuel costs for the periodSept. 1, 2015 , throughJune 30, 2019 , which will determine whether all fuel costs incurred are eligible for recovery. SPS also proposed that it annually review its averageNew Mexico Deferred Fuel and Purchased Power balance and requests the NMPRC approve an Annual Deferred Fuel Balance True-Up. The proposed true-up is designed to maintain theDeferred Fuel and Purchased Power balance within a bandwidth of plus or minus 5% of annualNew Mexico fuel and purchased power costs. A decision is pending. Environmental Environmental Regulation InJuly 2019 , theEPA adopted the Affordable Clean Energy rule, which requires states to develop plans for greenhouse gas reductions from coal-fired power plants. The state plans, due to theEPA inJuly 2022 , will evaluate and potentially require heat rate improvements at existing coal-fired plants. It is not yet known how these state plans will affect our existing coal plants, but they could require substantial additional investment, even in plants slated for retirement.Xcel Energy believes, based on prior state commission practice, the cost of these initiatives or replacement generation would be recoverable through rates. 28 -------------------------------------------------------------------------------- OnOct. 21, 2020 , theTexas Commission on Environmental Quality approved the Harrington Station Power Plant agreement, which ensures SPS will cease coal-fired operations and convert the plant to natural gas byJan. 1, 2025 . This conversion is necessary to attain Federal Clean Air Act standards for emissions of sulfur dioxide. Derivatives, Risk Management and Market Risk We are exposed to a variety of market risks in the normal course of business. Market risk is the potential loss that may occur as a result of adverse changes in the market or fair value of a particular instrument or commodity. All financial and commodity-related instruments, including derivatives, are subject to market risk. See Note 8 to the consolidated financial statements for further discussion of market risks associated with derivatives.Xcel Energy is exposed to the impact of adverse changes in price for energy and energy-related products, which is partially mitigated by the use of commodity derivatives. In addition to ongoing monitoring and maintaining credit policies intended to minimize overall credit risk, management takes steps to mitigate changes in credit and concentration risks associated with its derivatives and other contracts, including parental guarantees and requests of collateral. While we expect that the counterparties will perform under the contracts underlying its derivatives, the contracts expose us to some credit and non-performance risk. Distress in the financial markets may impact counterparty risk, the fair value of the securities in the nuclear decommissioning fund and pension fund andXcel Energy's ability to earn a return on short-term investments. Commodity Price Risk - We are exposed to commodity price risk in our electric and natural gas operations. Commodity price risk is managed by entering into long- and short-term physical purchase and sales contracts for electric capacity, energy and energy-related products and fuels used in generation and distribution activities. Commodity price risk is also managed through the use of financial derivative instruments. Our risk management policy allows it to manage commodity price risk within each rate-regulated operation per commission approved hedge plans. Wholesale and Commodity Trading Risk -Xcel Energy conducts various wholesale and commodity trading activities, including the purchase and sale of electric capacity, energy, energy-related instruments and natural gas-related instruments, including derivatives. Our risk management policy allows management to conduct these activities within guidelines and limitations as approved by its risk management committee. Fair value of net commodity trading contracts as ofSept. 30, 2020 :
Futures / Forwards Maturity
Greater Than 5
(Millions of Dollars) Less Than 1 Year 1 to 3 Years 4 to 5 Years Years Total Fair Value
NSP-Minnesota (a) $ (4) $ (1) $ 2 $ 3 $ -
NSP- Minnesota (b) 2 (1) (2) (6) (7)
PSCo (a) - 1 - - 1
PSCo (b) (14) (31) (19) - (64)
$ (16) $ (32) $ (19) $ (3) $ (70)
Options Maturity
Greater Than 5
(Millions of Dollars) Less Than 1 Year 1 to 3 Years 4 to 5 Years Years Total Fair Value
NSP-Minnesota (b) $ 1 $ - $ - $ 1 $ 2
PSCo (b) 5 4 1 - 10
$ 6 $ 4 $ 1 $ 1 $ 12
(a) Prices actively quoted or based on actively quoted prices.
(b) Prices based on models and other valuation methods.
Changes in the fair value of commodity trading contracts before the impacts of
margin-sharing for the nine months ended
2020 2019
Fair value of commodity trading net contract (liabilities) assets
outstanding at
$ (59) $ 17 Contracts realized or settled during the period (9) (13)
Commodity trading contract additions and changes during the period
10 (61)
Fair value of commodity trading net contract (liabilities) assets
outstanding at
$
(58)
AtSept. 30, 2020 , a 10% increase in market prices for commodity trading contracts through the forward curve would increase pre-tax income from continuing operations by approximately$14 million , whereas a 10% decrease would decrease pre-tax income from continuing operations by approximately$14 million . Market price movements can exceed 10% under abnormal circumstances. AtSept. 30, 2019 , a 10% increase or decrease in market prices for commodity trading contracts would increase or decrease pre-tax income from continuing operations by an immaterial amount. The utility subsidiaries' commodity trading operations measure the outstanding risk exposure to price changes on contracts and obligations that have been entered into, but not closed, using an industry standard methodology known as VaR. VaR expresses the potential change in fair value on the outstanding contracts and obligations over a particular period of time under normal market conditions. The VaRs for the NSP-Minnesota and PSCo commodity trading operations, excluding both non-derivative transactions and derivative transactions designated as normal purchase, normal sales, calculated on a consolidated basis using a Monte Carlo simulation with a 95% confidence level and a one-day holding period, were as follows: (Millions of Dollars) Three Months Ended Sept. 30 VaR Limit Average High Low 2020 $ 1.2$ 3.0 $ 1.0 $ 1.3 $ 0.8 2019 0.5 3.0 1.0 1.3 0.5 Nuclear Fuel Supply - NSP-Minnesota has contracted for approximately 55% of its 2020 enriched nuclear material requirements from sources that could be impacted by sanctions against entities doing business withIran . Those sanctions may impact the supply of enriched nuclear material supplied fromRussia . Long-term, through 2030, NSP-Minnesota is scheduled to take delivery of approximately 30% of its average enriched nuclear material requirements from these sources. Alternate potential sources provide the flexibility to manage NSP-Minnesota's nuclear fuel supply. NSP-Minnesota periodically assesses if further actions are required to assure a secure supply of enriched nuclear material. Interest Rate Risk -Xcel Energy is subject to interest rate risk. Our risk management policy allows interest rate risk to be managed through the use of fixed rate debt, floating rate debt and interest rate derivatives such as swaps, caps, collars and put or call options. 29
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AtSept. 30, 2020 and 2019, a 100-basis-point change in the benchmark rate onXcel Energy's variable rate debt would impact pre-tax interest expense annually by approximately$6 million and$9 million , respectively. See Note 8 to the consolidated financial statements for a discussion ofXcel Energy Inc. and its subsidiaries' interest rate derivatives. NSP-Minnesota maintains a nuclear decommissioning fund, as required by the NRC. The nuclear decommissioning fund is subject to interest rate risk and equity price risk. The fund is invested in a diversified portfolio of cash equivalents, debt securities, equity securities, and other investments. These investments may be used only for purpose of decommissioning NSP-Minnesota's nuclear generating plants. Realized and unrealized gains on the decommissioning fund investments are deferred as an offset of NSP-Minnesota's regulatory asset for nuclear decommissioning costs. Fluctuations in equity prices or interest rates affecting the nuclear decommissioning fund do not have a direct impact on earnings due to the application of regulatory accounting. Changes in discount rates and expected return on plan assets impact the value of pension and postretirement plan assets and/or benefit costs. Credit Risk -Xcel Energy is also exposed to credit risk. Credit risk relates to the risk of loss resulting from counterparties' nonperformance on their contractual obligations.Xcel Energy maintains credit policies intended to minimize overall credit risk and actively monitor these policies to reflect changes and scope of operations. AtSept. 30, 2020 , a 10% increase in commodity prices would have resulted in an increase in credit exposure of$29 million , while a decrease in prices of 10% would have resulted in a decrease in credit exposure of$3 million . AtSept. 30, 2019 , a 10% increase in commodity prices would have resulted in an increase in credit exposure of$30 million , while a decrease in prices of 10% would have resulted in an increase in credit exposure of$12 million .Xcel Energy conducts credit reviews for all counterparties and employs credit risk control, such as letters of credit, parental guarantees, master netting agreements and termination provisions. Credit exposure is monitored and when necessary, the activity with a specific counterparty is limited until credit enhancement is provided. Distress in the financial markets could increase our credit risk. FAIR VALUE MEASUREMENTSXcel Energy uses derivative contracts such as futures, forwards, interest rate swaps, options and FTRs to manage commodity price and interest rate risk. Derivative contracts, with the exception of those designated as normal purchase-normal sale contracts, are reported at fair value. The Company's investments held in the nuclear decommissioning fund, rabbi trusts, pension and other postretirement funds are also subject to fair value accounting. See Note 8 to the consolidated financial statements for further discussion of the fair value hierarchy and the amounts of assets and liabilities measured at fair value that have been assigned to Level 3. Commodity Derivatives -Xcel Energy monitors the creditworthiness of the counterparties to its commodity derivative contracts and assesses each counterparty's ability to perform on the transactions. The impact of discounting commodity derivative assets for counterparty credit risk was not material to the fair value of commodity derivative assets atSept. 30, 2020 . Adjustments to fair value for credit risk of commodity trading instruments are recorded in electric revenues. Credit risk adjustments for other commodity derivative instruments are deferred as other comprehensive income or deferred as regulatory assets and liabilities. Classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms. The impact of discounting commodity derivative liabilities for credit risk was immaterial atSept. 30, 2020 .
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