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MarketScreener Homepage  >  Equities  >  Nasdaq  >  Xcel Energy    XEL

XCEL ENERGY

(XEL)
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XCEL ENERGY : MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (form 10-Q)

10/29/2020 | 12:53pm EST
The following discussion and analysis by management focuses on those factors
that had a material effect on Xcel 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 of Xcel 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.
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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 calculate Xcel Energy Inc.'s diluted EPS is calculated using the
treasury stock method. Ongoing earnings reflect adjustments to GAAP earnings
(net income) for certain items.
Ongoing diluted EPS is calculated by dividing the net income or loss of each
subsidiary, adjusted for certain items, by the weighted average fully diluted
Xcel Energy Inc. common shares outstanding for the period. Ongoing diluted EPS
for each subsidiary is calculated by dividing the net income or loss of such
subsidiary, adjusted for certain items, by the weighted average fully diluted
Xcel Energy Inc. common shares outstanding for the period.
We use these non-GAAP financial measures to evaluate and provide details of Xcel
Energy's core earnings and underlying performance. We believe these measurements
are useful to investors to evaluate the actual and projected financial
performance and contribution of our subsidiaries.
For the three and nine months ended Sept. 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 of
Xcel 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 in March 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 for Xcel 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 Earnings
Xcel 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.
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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 Months

Ended 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 and Cheyenne Ridge wind facilities going into service, as well as
normal system expansion. In addition, new depreciation rates were implemented in
Colorado, New Mexico and Texas 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 ending Sept.
30, 2020 compared with 10.1% for 2019.
Public Utility Regulation


The FERC and various state and local regulatory commissions regulate Xcel Energy
Inc.'s utility subsidiaries and WGI. The electric and natural gas rates charged
to customers of Xcel Energy Inc.'s utility subsidiaries and WGI are approved by
the FERC 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 affect Xcel 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 impact Xcel 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 ended Dec. 31, 2019 and in Item 2 of Xcel Energy's Quarterly Report
on   Form 10-Q   for the quarterly period ended March 31, 2020 and   Fo    rm
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 in
November 2020, including a stay-out alternative.
TCR Electric Rider - In November 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 - In November 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.

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RES Electric Rider - In November 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 - In July 2019, NSP-Minnesota filed its
Minnesota resource plan, which runs through 2034. The plan would result in an
80% carbon reduction by 2030 (from 2005) and puts NSP-Minnesota on a path to
achieving its vision of being 100% carbon-free by 2050.
In June 2020, NSP-Minnesota filed a supplement to its resource plan, including
new modeling scenarios required by the 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 the Monticello nuclear plant from 2030 to 2040;
•Continuing to run the Prairie Island nuclear plant through current end of life
(2033 and 2034);
•Construction of the Sherco combined cycle natural gas plant;
•The addition of 3,500 MW of solar;
•The addition of 2,250 MW of wind;
•2,600 MW of firm peaking (combustion turbine, pumped hydro, battery storage,
demand response, etc.);
•Achieving 780 GWh in energy efficiency savings annually through 2034; and
•Adding 400 MW of incremental demand response by 2023, and a total of 1,500 MW
of demand response by 2034.
Initial comments are due Jan. 15, 2021 and reply comments are due March 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:
•In September 2020, NSP-Minnesota proposed to accelerate approximately $865
million of grid investment and sought approval for approximately $150 million of
incremental electric vehicle rebates;
•In September 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 - In September 2017, LSP Transmission
filed a complaint in the Minnesota District Court against the Minnesota Attorney
General, MPUC and DOC. The complaint was in response to MISO assigning
NSP-Minnesota and ITC Midwest, LLC to jointly own a new 345 kilovolt
transmission line from Mankato to Winnebago, 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 and ITC Midwest as the incumbent utilities, consistent
with a Minnesota state ROFR statute.
The complaint challenged the constitutionality of the statute and is seeking
declaratory judgment that the statute violates the Commerce Clause of the U.S.Constitution and should not be enforced. In June 2018, the Minnesota District
Court granted Minnesota state agencies and NSP-Minnesota's motions to dismiss
with prejudice. LSP Transmission filed an appeal in July 2018. In February 2020,
the Eighth Circuit Court of Appeals upheld the Minnesota District Court decision
to dismiss. In June 2020, the Eighth Circuit denied LSP Transmission's petition
for rehearing. LSP Transmission has until Nov. 5, 2020 to seek further review of
this appeal with the U.S. Supreme Court.
Nuclear Power Operations
NSP-Minnesota owns two nuclear generating plants: the Monticello plant and the
Prairie 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. In August 2020, the PSCW
approved NSP-Wisconsin's request to refund over-collections of approximately $10
million to customers.
2021 Electric Fuel Cost Recovery - In June 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 - In October 2020, NSP-Wisconsin filed for a 74 MW
solar facility build-own-transfer in Wisconsin for approximately $100 million. A
PSCW decision is expected in the third quarter of 2021.
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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 $ 17$ 24$ 29$ 32$ 34



Advanced Grid Rider - Seeks to establish a rider to recover incremental costs
associated with the AGIS initiative. In August 2020, the CPUC referred the
matter to an ALJ. In September 2020, the Office of Consumer Counsel filed a
motion to dismiss the Advanced Grid Rider.
Procedural schedule:
•Answer testimony Dec. 9, 2020;
•Rebuttal Jan. 8, 2021;
•Settlement by Jan. 20, 2021;
•Hearing Jan. 25, 2021 - Jan 28, 2021; and
•Statutory deadline April 24, 2021.
The rider is expected to be effective in May 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 $ 53$ 69$ 83$ 89$ 99



PSCo KEPCO Filing - In September 2020, PSCo filed with the CPUC for approval to
terminate a solar PPA with KEPCO Solar of Alamosa, 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.
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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. In June
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. 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.
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.
In September 2020, the City 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 on Nov. 3, 2020, whether to approve or deny the
franchise agreement.
PSCo - Natural Gas LDC and Emission Reductions - In October 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 - In August 2020, the PUCT approved a settlement
between SPS and intervening parties, which reflects the following terms,
retroactive to Sept. 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 other Texas 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 to Sept. 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 the Texas and New Mexico jurisdictions due to the
settlement reached for the Hale and Sagamore wind farms.
Texas State ROFR Litigation - In May 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. In June 2019, a complaint was filed in the United States District
Court for the Western District of Texas claiming the new ROFR law to be
unconstitutional. In February 2020, the federal court complaint was dismissed by
the district court. In March 2020, the district court ruling was appealed to the
United States Court of Appeals for the Fifth Circuit. The parties are awaiting a
decision.
Texas Fuel Refund - Fuel and purchased power costs are recoverable in Texas
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.
In August 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 - In October 2019, SPS filed an application to
the NMPRC to approve SPS' continued use of its FPPCAC and for reconciliation of
fuel costs for the period Sept. 1, 2015, through June 30, 2019, which will
determine whether all fuel costs incurred are eligible for recovery. SPS also
proposed that it annually review its average New 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 the Deferred Fuel
and Purchased Power balance within a bandwidth of plus or minus 5% of annual New
Mexico fuel and purchased power costs. A decision is pending.
                                 Environmental


Environmental Regulation
In July 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 in July 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
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On Oct. 21, 2020, the Texas 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 by Jan. 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 and Xcel
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 of Sept. 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 Sept. 30: (Millions of Dollars)

                                                        2020             2019

Fair value of commodity trading net contract (liabilities) assets outstanding at Jan. 1

                                                     $   (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 Sept. 30

                                                   $ 

(58) $ (57)



At Sept. 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. At Sept. 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 with Iran. Those sanctions may
impact the supply of enriched nuclear material supplied from Russia. 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.
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At Sept. 30, 2020 and 2019, a 100-basis-point change in the benchmark rate on
Xcel 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 of Xcel
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.
At Sept. 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. At Sept. 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 MEASUREMENTS


Xcel 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 at Sept. 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 at Sept. 30, 2020.

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