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. 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 six months endedJune 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. 22
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GAAP and ongoing diluted EPS for
Three Months Ended June 30 Six Months Ended June 30
Diluted Earnings (Loss) Per Share 2020 2019 2020 2019
PSCo $ 0.21 $ 0.20 $ 0.45 $ 0.47
NSP-Minnesota 0.22 0.19 0.43 0.41
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.
Summary of Earnings
Xcel Energy - Xcel Energy's earnings increased $0.08 per share for the second
quarter of 2020 and $0.03 per share year-to-date. Earnings reflect management's
actions to reduce O&M to offset the impact from COVID-19 and favorable weather,
partially offset by higher depreciation and interest charges. Income taxes were
lower primarily due to higher PTCs, which are credited to customers, resulting
in lower electric margin and do not materially impact earnings.
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 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.
Changes in GAAP and Ongoing Diluted EPS
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 ETR (a) 0.07 0.10
Lower O&M 0.05 0.08
Higher AFUDC 0.03 0.04
Higher electric margin (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 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.
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.
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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 June 30 Six Months Ended
2020 vs. 2019 vs. 2020 vs. 2020 vs. 2019 vs. 2020 vs.
Normal Normal 2019 Normal Normal 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. 2019 vs. 2020 vs. 2020 vs. 2019 vs. 2020 vs.
Normal Normal 2019 Normal Normal 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 C&I (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 C&I (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 C&I (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 C&I (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
Six Months Ended June 30 (Leap Year Adjusted)
PSCo (b) NSP-Minnesota SPS NSP-Wisconsin Xcel Energy
Weather-normalized (a)
Electric residential 2.8 % 2.2 % 1.3 % 2.4 % 2.3 %
Electric C&I (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) 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 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.
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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
Changes in electric margin:
Three Months Ended June 30, Six Months Ended June 30,
(Millions of Dollars) 2020 vs. 2019 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)
- (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:
Three Months Ended June 30, Six Months Ended June 30,
(Millions of Dollars) 2020 vs. 2019 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)
Non-Fuel Operating Expenses and Other Items
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:
Three Months Ended June 30, Six Months Ended June 30,
(Millions of Dollars) 2020 vs. 2019 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).
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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 endingJune 30, 2020 compared with 8.1% for the same period in 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 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 Requested Filing Mechanism Utility Service (in millions) Date Approval Additional Information MPUC In November 2019, NSP-Minnesota filed the 2020 2020 TCR Electric$82 November 2019 Pending TCR Rider. The filing included an ROE of 9.06%. Timing of an MPUC ruling is uncertain. In November 2019, NSP-Minnesota filed the 2020 2020 GUIC Natural Gas$21 November 2019 Pending GUIC Rider with the MPUC. The filing included an ROE of 9.04%. Timing of an MPUC ruling is uncertain. In November 2019, NSP-Minnesota filed the 2020 RES Rider with the MPUC. The requested amount 2020 RES Electric$102 November 2019 Pending 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 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 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 dueOct. 30, 2020 and reply comments are dueJan. 15, 2021 . The MPUC is anticipated to make a final decision in the first half of 2021. 26
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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. InJune 2020 , NSP-Minnesota filed a Relief & Recovery proposal which identified approximately$3 billion of capital investment which may assist inMinnesota'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. NSP-Minnesota - Mower Wind Facility - InAugust 2019 , NSP-Minnesota filed a petition with the MPUC to acquire the Mower wind facility from affiliates of NextEra Energy, Inc. The facility is currently contracted under a PPA with NSP-Minnesota through 2026. Mower is expected to continue to have approximately 99 MW of capacity following a planned repowering. The acquisition would occur after repowering, which is expected to be completed in 2020 and qualify for the full PTC. NSP-Minnesota will need approval from both the MPUC andFERC to complete the transaction. The MPUC is expected to rule on the request in the third quarter of 2020. 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 KV 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. 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, primarily due to increased sales to other utilities compared to the forecast used to set authorized rates. 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. InMarch 2020 , NSP-Wisconsin filed with the PSCW indicating over-collections of approximately$10 million to customers and proposed for refunds to be issued inSeptember 2020 . 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$14 million . The PSCW will decide on the application later in 2020. 27
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PSCo
Pending and Recently Concluded Regulatory Proceedings
Amount Requested Filing
Mechanism Utility Service (in millions) Date Approval Additional Information
CPUC
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
Rate Case Natural Gas $127 February 2020 Pending 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 ALJ granted an unopposed
motion to schedule a hearing for Aug. 13, 2020 to
review the settlement.
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.
Rate Case Electric $158 May 2019 Received 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.
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
Rate Case Appeal Natural Gas N/A April 2019 Pending 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 Wildfire and Advanced Grid rider requests with the 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:
(Millions of Dollars) 2021 2022 2023 2024 2025
Forecasted annual revenue requirement $ 17 $ 24 $ 29 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 thanMay 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
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 purchase power agreements. 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, theBoulder City Council passed an ordinance to establish an electric utility. PSCo challenged the formation of this utility and theColorado Court of Appeals ruled in PSCo's favor, vacating a lower court decision. InJune 2018 , theColorado Supreme Court rejected Boulder's request to dismiss the case and remanded it to theBoulder District Court . The case was then settled inJune 2019 after Boulder agreed to repeal the ordinance establishing the utility. 28
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Boulder has filed multiple separation applications with the CPUC, which have been challenged by PSCo and other intervenors. InSeptember 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, theBoulder City Council also adopted an Ordinance authorizing Boulder to begin negotiations for the acquisition of certain property or to otherwise condemn that property afterFeb. 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 theBoulder District Court inSeptember 2019 on the grounds that Boulder had not completed the pre-requisite CPUC process and filings. Boulder is currently appealing this order. InOctober 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. InDecember 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. InFebruary 2020 , Boulder filed an application under section 210 of the Federal Power Act askingFERC to order PSCo to interconnect its facilities with a future Boulder municipal utility under Boulder's preferred terms and conditions. InJuly 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 theBoulder City Council inAugust 2020 and will further require approval by the citizens of Boulder in a ballot referendum inNovember 2020 . SPS Pending and Recently Concluded Regulatory Proceedings Amount Requested Filing Mechanism Utility Service (in millions) Date Approval Additional Information NMPRC In July 2019, SPS filed an electric rate case with the NMPRC seeking an increase in retail electric base rates of approximately$51 million. The rate request was based on an ROE of 10.35%, 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. In December 2019, SPS revised its base rate increase request to approximately$47 million, based on an ROE of 10.10% and updated information. 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 January 2020, SPS and various parties filed an uncontested comprehensive stipulation. The Rate Case Electric$31 July 2019 Received stipulation includes a base rate revenue increase of$31 million , an ROE of 9.45% and an equity ratio of 54.77%. The stipulation also includes an acceleration of depreciation on the Tolk coal plant to reflect early retirement in 2037, which results in a total increase in depreciation expense of$8 million . 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. On May 11, 2020, the Hearing Examiner issued a Certification of Stipulation recommending approval of the uncontested comprehensive stipulation without modification. On May 20, 2020, the NMPRC approved the stipulation without modification. New rates and tariffs were effective beginning May 28, 2020. PUCT 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 utilizes a historic 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. On May 20, 2020, SPS, the PUCT Staff and various intervenors reached an uncontested settlement, which includes: •An electric rate increase of$88 million and a reset of the Transmission Cost Recovery Factor to zero; •ROE of 9.45% and equity ratio of 54.62% for AFUDC purposes; Rate Case Electric$141 August
2019 Pending •Depreciation rates:
•Tolk - 2037 end-of-life date;
•Hale - 25-year end-of-life date;
•All other generating units - end-of-life dates
as proposed by SPS; and
•Transmission - 35% of the incremental change
between existing depreciation rates and rates
proposed by SPS.
•Ring-fencing measures like those in other
recent PUCT settlements, including:
•Credit agreements and indentures (e.g., no
cross-default provisions);
•Financial covenants;
•Restrictions on pledging of assets and securing
debt;
•Maintaining stand-alone credit facility and
ratings; and
•Affiliate and non-affiliate limitations.
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.
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Texas State ROFR Litigation - InMay 2019 , the Governor signed into lawSenate Bill 1938, 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. SPS' 2019 total fuel and purchased power costs were over-collected by approximately$39 million . As a result, SPS filed a request with the PUCT to refund the amount to customers. InApril 2020 , interim rates were granted by a Texas ALJ. This case is pending final review and approval by the PUCT. 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 public hearing is scheduled to begin onAug. 20, 2020 . Environmental Environmental Regulation InJuly 2019 , the EPA 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 the EPA 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. 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 ofJune 30, 2020 : Futures / Forwards Maturity (Millions of Dollars) Less Than 1 Year 1 to 3 Years 4 to 5 Years Greater Than 5 Years Total Fair Value NSP-Minnesota (a) $ - $ -$ 3 $ 3 $ 6 NSP-Minnesota (b) - (2) (4) (5) (11) PSCo (b) (1) (40) (15) - (56) $ (1)$ (42) $ (16) $ (2) $ (61) Options Maturity (Millions of Dollars) Less Than 1 Year 1 to 3 Years 4 to 5 Years Greater Than 5 Years Total Fair Value NSP-Minnesota (b) $ -$ 3 $ - $ - $ 3 PSCo (b) - (1) - - (1) $ -$ 2 $ - $ - $ 2 (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 six months endedJune 30 : (Millions of Dollars) 2020 2019
Fair value of commodity trading net contract (liabilities) assets
outstanding at
$ (59) $ 17 Contracts realized or settled during the period (7) (8)
Commodity trading contract additions and changes during the period
7 7
Fair value of commodity trading net contract (liabilities) assets
outstanding at June 30 $ (59) $ 16
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AtJune 30, 2020 , a 10% increase in market prices for commodity trading contracts would increase pre-tax income from continuing operations by approximately$12 million , whereas a 10% decrease would decrease pre-tax income from continuing operations by approximately$12 million . AtJune 30, 2019 , a 10% increase in market prices for commodity trading contracts would decrease pre-tax income from continuing operations by approximately$2 million , whereas a 10% decrease would increase pre-tax income from continuing operations by approximately$2 million . 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 Value at Risk (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 June 30 VaR Limit Average High Low 2020 $ 0.8$ 3.0 $ 0.9 $ 1.1 $ 0.6 2019 1.1 3.0 0.9 1.3 0.7 Nuclear Fuel Supply - NSP-Minnesota has contracted for approximately 51% 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. AtJune 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$14 million and$17 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. AtJune 30, 2020 , a 10% increase in commodity prices would have resulted in an increase in credit exposure of$27 million , while a decrease in prices of 10% would have resulted in a decrease in credit exposure of$2 million . AtJune 30, 2019 , a 10% increase in commodity prices would have resulted in an increase in credit exposure of$14 million , while a decrease in prices of 10% would have resulted in an increase in credit exposure of$16 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 atJune 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 atJune 30, 2020 . 31
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