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XEL-20200630_G1.JPG
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C.  20549
FORM 10-Q
(Mark One)
☒ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2020 or
☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Xcel Energy Inc.
(Exact name of registrant as specified in its charter)
Minnesota 001-3034 41-0448030
(State or Other Jurisdiction of Incorporation or Organization)
(Commission File Number)


(IRS Employer Identification No.)
414 Nicollet Mall Minneapolis Minnesota 55401
(Address of Principal Executive Offices)
(Zip Code)
612 330-5500
(Registrant’s Telephone Number, Including Area Code)
N/A
(Former Name, Former Address and Former Fiscal Year, if Changed Since Last Report)

Securities registered pursuant to Section 12(b) of the Act:
Title of each class Trading Symbol Name of each exchange on which registered
Common Stock, $2.50 par value XEL Nasdaq Stock Market LLC

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    ☒ Yes  ☐ No
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).    ☒ Yes  ☐ No
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company or an emerging growth company.  See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer ☒ Accelerated filer ☐
Non-accelerated filer ☐ Smaller reporting company ☐
Emerging growth company ☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). ☐ Yes ☒ No
Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.
Class Outstanding at July 28, 2020
Common Stock, $2.50 par value 525,342,304 shares


TABLE OF CONTENTS
PART I FINANCIAL INFORMATION
Item 1 —
4
4
5
6
7
8
9
Item 2 —
22
Item 3 —
35
Item 4 —
35
PART II OTHER INFORMATION
Item 1 —
35
Item 1A —
36
Item 2 —
36
Item 6 —
36
37
Certifications Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
Certifications Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
This Form 10-Q is filed by Xcel Energy Inc. Additional information is available on various filings with the Securities and Exchange Commission (SEC).
2

Definitions of Abbreviations
Xcel Energy Inc.’s Subsidiaries and Affiliates (current and former)
e prime e prime inc.
NSP-Minnesota Northern States Power Company, a Minnesota corporation
NSP System The electric production and transmission system of NSP-Minnesota and NSP-Wisconsin operated on an integrated basis and managed by NSP-Minnesota
NSP-Wisconsin Northern States Power Company, a Wisconsin corporation
PSCo Public Service Company of Colorado
SPS Southwestern Public Service Co.
Utility subsidiaries NSP-Minnesota, NSP-Wisconsin, PSCo and SPS
WGI West Gas Interstate
Xcel Energy Xcel Energy Inc. and its subsidiaries
Federal and State Regulatory Agencies
CPUC Colorado Public Utilities Commission
D.C. Circuit United States Court of Appeals for the District of Columbia Circuit
DOC Department of Commerce
EPA United States Environmental Protection Agency
FERC Federal Energy Regulatory Commission
IRS Internal Revenue Service
MPUC Minnesota Public Utilities Commission
NMPRC New Mexico Public Regulation Commission
NRC Nuclear Regulatory Commission
OAG Minnesota Office of the Attorney General
PSCW Public Service Commission of Wisconsin
PUCT Public Utility Commission of Texas
SEC Securities and Exchange Commission
Electric, Purchased Gas and Resource Adjustment Clauses
DSM Demand side management
FCA Fuel clause adjustment
FPPCAC Fuel and purchased power cost adjustment clause
GUIC Gas utility infrastructure cost rider
RES Renewable energy standard
TCR Transmission cost recovery adjustment
Other
AFUDC Allowance for funds used during construction
ALJ Administrative Law Judge
ASC FASB Accounting Standards Codification
C&I Commercial and Industrial
CCR Coal combustion residual
CCR Rule Final rule (40 CFR 257.50 - 257.107) published by the EPA regulating the management, storage and disposal of CCRs as a nonhazardous waste
CDD Cooling degree-days
CEO Chief executive officer
CFO Chief financial officer
COVID-19 Novel coronavirus
CWIP Construction work in progress
DRIP Dividend Reinvestment and Stock Purchase Program
EPS Earnings per share
ETR Effective tax rate
FASB Financial Accounting Standards Board
FTR Financial transmission right
GAAP Generally accepted accounting principles
GE General Electric
HDD Heating degree-days
IPP Independent power producing entity
LLC Limited liability company
MDL Multi district litigation
MEC Mankato Energy Center
MGP Manufactured gas plant
MISO Midcontinent Independent System Operator, Inc.
NAV Net asset value
NOL Net operating loss
O&M Operating and maintenance
OATT Open Access Transmission Tariff
PPA Power purchase agreement
PTC Production tax credit
ROE Return on equity
ROFR Right-of-first refusal
RTO Regional Transmission Organization
SMMPA Southern Minnesota Municipal Power Agency
SPP Southwest Power Pool, Inc.
THI Temperature-humidity index
TOs Transmission owners
VIE Variable interest entity
Measurements
KV Kilovolts
MW Megawatts
Forward-Looking Statements
Except for the historical statements contained in this report, the matters discussed herein are forward-looking statements that are subject to certain risks, uncertainties and assumptions. Such forward-looking statements, including the 2020 EPS guidance, long-term EPS and dividend growth rate objectives, future sales, future bad debt expense, and future operating performance, as well as assumptions and other statements are intended to be identified in this document by the words “anticipate,” “believe,” “could,” “estimate,” “expect,” “intend,” “may,” “objective,” “outlook,” “plan,” “project,” “possible,” “potential,” “should,” “will,” “would” and similar expressions. Actual results may vary materially. Forward-looking statements speak only as of the date they are made, and we expressly disclaim any obligation to update any forward-looking information. The following factors, in addition to those discussed elsewhere in this Quarterly Report on Form 10-Q and in other securities filings (including Xcel Energy’s Annual Report on Form 10-K for the fiscal year ended Dec. 31, 2019, and subsequent securities filings), could cause actual results to differ materially from management expectations as suggested by such forward-looking information: uncertainty around the impacts and duration of the COVID-19 pandemic; operational safety, including our nuclear generation facilities; successful long-term operational planning; commodity risks associated with energy markets and production; rising energy prices and fuel costs; qualified employee work force and third-party contractor factors; ability to recover costs, changes in regulation and subsidiaries’ ability to recover costs from customers; reductions in our credit ratings and the cost of maintaining certain contractual relationships; general economic conditions, including inflation rates, monetary fluctuations and their impact on capital expenditures and the ability of Xcel Energy Inc. and its subsidiaries to obtain financing on favorable terms; availability or cost of capital; our customers’ and counterparties’ ability to pay their debts to us; assumptions and costs relating to funding our employee benefit plans and health care benefits; our subsidiaries’ ability to make dividend payments; tax laws; effects of geopolitical events, including war and acts of terrorism; cyber security threats and data security breaches; seasonal weather patterns; changes in environmental laws and regulations; climate change and other weather; natural disaster and resource depletion, including compliance with any accompanying legislative and regulatory changes; and costs of potential regulatory penalties.
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Table of Contents


PART I — FINANCIAL INFORMATION
ITEM 1 — FINANCIAL STATEMENTS

XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)
(amounts in millions, except per share data)
Three Months Ended June 30 Six Months Ended June 30
2020 2019 2020 2019
Operating revenues
Electric $ 2,286    $ 2,249    $ 4,489    $ 4,574   
Natural gas 280    308    863    1,102   
Other 20    20    45    42   
Total operating revenues 2,586    2,577    5,397    5,718   
Operating expenses
Electric fuel and purchased power 833    813    1,630    1,727   
Cost of natural gas sold and transported 86    112    371    591   
Cost of sales — other 8    10    17    19   
Operating and maintenance expenses 550    586    1,129    1,184   
Conservation and demand side management expenses 68    65    142    137   
Depreciation and amortization 473    439    936    872   
Taxes (other than income taxes) 146    142    295    292   
Total operating expenses 2,164    2,167    4,520    4,822   
Operating income 422    410    877    896   
Other income (expense), net 5    2    (7)   6   
Equity earnings of unconsolidated subsidiaries 6    9    17    19   
Allowance for funds used during construction — equity 37    20    61    40   
Interest charges and financing costs
Interest charges — includes other financing costs of $7, $6, $14 and $13, respectively
208    189    407    379   
Allowance for funds used during construction — debt (12)   (10)   (22)   (20)  
Total interest charges and financing costs 196    179    385    359   
Income before income taxes 274    262    563    602   
Income tax (benefit) expense (13)   24    (19)   49   
Net income $ 287    $ 238    $ 582    $ 553   
Weighted average common shares outstanding:
Basic 527    516    526    515   
Diluted 527    518    527    517   
Earnings per average common share:
Basic $ 0.54    $ 0.46    $ 1.10    $ 1.07   
Diluted 0.54    0.46    1.10    1.07   
See Notes to Consolidated Financial Statements

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XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
(amounts in millions)
Three Months Ended June 30 Six Months Ended June 30
2020 2019 2020 2019
Net income $ 287    $ 238    $ 582    $ 553   
Other comprehensive income (loss)
Pension and retiree medical benefits:
Net pension and retiree medical gains arising during the period, net of tax of $—, $—, $— and $1, respectively
—    1    —    3   
Reclassifications of loss to net income, net of tax of $1, $—, $1 and $—, respectively
2    —    3    1   
Derivative instruments:
Net fair value decrease, net of tax of $—, $(3), $(3) and $(5), respectively
—    (10)   (10)   (17)  
Reclassification of loss to net income, net of tax of $1, $—, $1 and $—, respectively
1    1    3    2   
Total other comprehensive income (loss) 3    (8)   (4)   (11)  
Total comprehensive income $ 290    $ 230    $ 578    $ 542   
See Notes to Consolidated Financial Statements



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XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
(amounts in millions)
  Six Months Ended June 30
  2020 2019
Operating activities
Net income $ 582    $ 553   
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization 942    881   
Nuclear fuel amortization 65    58   
Deferred income taxes —    47   
Allowance for equity funds used during construction (61)   (40)  
Equity earnings of unconsolidated subsidiaries (17)   (19)  
Dividends from unconsolidated subsidiaries 21    20   
Provision for bad debts 26    17   
Share-based compensation expense 41    35   
Changes in operating assets and liabilities:
Accounts receivable 19    105   
Accrued unbilled revenues 97    115   
Inventories 15    25   
Other current assets 7    19   
Accounts payable (160)   (157)  
Net regulatory assets and liabilities 12    25   
Other current liabilities (241)   (195)  
Pension and other employee benefit obligations (146)   (139)  
Other, net (54)   (16)  
Net cash provided by operating activities 1,148    1,334   
Investing activities
Capital/construction expenditures (2,569)   (1,689)  
Purchases of investment securities (1,160)   (488)  
Proceeds from the sale of investment securities 1,150    478   
Other, net (1)   (9)  
Net cash used in investing activities (2,580)   (1,708)  
Financing activities
Proceeds from short-term borrowings, net 815    559   
Proceeds from issuances of long-term debt 2,447    819   
Repayments of long-term debt, including reacquisition premiums —    (400)  
Dividends paid (421)   (387)  
Other, net (23)   (11)  
Net cash provided by financing activities 2,818    580   
Net change in cash, cash equivalents and restricted cash 1,386    206   
Cash, cash equivalents and restricted cash at beginning of period 248    147   
Cash, cash equivalents and restricted cash at end of period (a)
$ 1,634    $ 353   
Supplemental disclosure of cash flow information:
Cash paid for interest (net of amounts capitalized) $ (364)   $ (344)  
Cash (paid) received for income taxes, net (10)   54   
Supplemental disclosure of non-cash investing and financing transactions:
Accrued property, plant and equipment additions $ 436    $ 304   
Inventory transfers to property, plant and equipment 194    40   
Operating lease right-of-use assets 8    1,843   
Allowance for equity funds used during construction 61    40   
Issuance of common stock for equity awards 35    32   
(a) As of June 30, 2020, $9 million of cash was recorded in Prepayments and other current assets related to MEC.
See Notes to Consolidated Financial Statements
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XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (UNAUDITED)
(amounts in millions, except share and per share data)
June 30, 2020 Dec. 31, 2019
Assets
Current assets
Cash and cash equivalents $ 1,625    $ 248   
Accounts receivable, net 799    837   
Accrued unbilled revenues 613    713   
Inventories 487    544   
Regulatory assets 513    488   
Derivative instruments 72    55   
Prepaid taxes 73    43   
Prepayments and other 208    185   
Total current assets 4,390    3,113   
Property, plant and equipment, net 41,124    39,483   
Other assets
Nuclear decommissioning fund and other investments 2,683    2,731   
Regulatory assets 2,973    2,935   
Derivative instruments 38    22   
Operating lease right-of-use assets 1,229    1,672   
Other 1,019    492   
Total other assets 7,942    7,852   
Total assets $ 53,456    $ 50,448   
Liabilities and Equity
Current liabilities
Current portion of long-term debt $ 1,101    $ 702   
Short-term debt 1,410    595   
Accounts payable 1,188    1,294   
Regulatory liabilities 420    407   
Taxes accrued 343    466   
Accrued interest 200    192   
Dividends payable 226    212   
Derivative instruments 40    38   
Operating lease liabilities 149    194   
Other 396    468   
Total current liabilities 5,473    4,568   
Deferred credits and other liabilities
Deferred income taxes 4,569    4,509   
Deferred investment tax credits 47    49   
Regulatory liabilities 5,310    5,077   
Asset retirement obligations 2,881    2,701   
Derivative instruments 181    175   
Customer advances 201    203   
Pension and employee benefit obligations 636    785   
Operating lease liabilities 1,125    1,549   
Other 185    186   
Total deferred credits and other liabilities 15,135    15,234   
Commitments and contingencies
Capitalization
Long-term debt 19,463    17,407   
Common stock — 1,000,000,000 shares authorized of $2.50 par value; 525,204,978
and 524,539,000 shares outstanding at June 30, 2020 and Dec. 31, 2019, respectively
1,313    1,311   
Additional paid in capital 6,679    6,656   
Retained earnings 5,538    5,413   
Accumulated other comprehensive loss (145)   (141)  
Total common stockholders’ equity 13,385    13,239   
Total liabilities and equity $ 53,456    $ 50,448   
See Notes to Consolidated Financial Statements
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XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY (UNAUDITED)
(amounts in millions, shares in thousands)
Common Stock Issued Retained Earnings Accumulated
Other
Comprehensive
Loss 		Total
Common
Stockholders’
Equity
Shares Par Value Additional Paid In Capital
Three Months Ended June 30, 2020 and 2019
Balance at March 31, 2019 514,668    $ 1,287    $ 6,173    $ 4,996    $ (127)   $ 12,329   
Net income 238    238   
Other comprehensive loss (8)   (8)  
Dividends declared on common stock ($0.41 per share)
(209)   (209)  
Issuances of common stock 197    —    10    10   
Share-based compensation 7    (1)   6   
Balance at June 30, 2019 514,865    $ 1,287    $ 6,190    $ 5,024    $ (135)   $ 12,366   
Balance at March 31, 2020 525,034    $ 1,313    $ 6,659    $ 5,478    $ (148)   $ 13,302   
Net income 287    287   
Other comprehensive income 3    3   
Dividends declared on common stock ($0.43 per share)
(226)   (226)  
Issuances of common stock 171    —    11    11   
Share-based compensation 9    (1)   8   
Balance at June 30, 2020 525,205    $ 1,313    $ 6,679    $ 5,538    $ (145)   $ 13,385   
Common Stock Issued Retained Earnings Accumulated
Other
Comprehensive
Loss 		Total
Common
Stockholders’
Equity
Shares Par Value Additional Paid In Capital
Six Months Ended June 30, 2020 and 2019            
Balance at Dec. 31, 2018 514,037    $ 1,285    $ 6,168    $ 4,893    $ (124)   $ 12,222   
Net income 553    553   
Other comprehensive loss (11)   (11)  
Dividends declared on common stock ($0.81 per share)
(419)   (419)  
Issuances of common stock 834    2    20    22   
Repurchases of common stock (6)   —    —    —   
Share-based compensation 2    (3)   (1)  
Balance at June 30, 2019 514,865    $ 1,287    $ 6,190    $ 5,024    $ (135)   $ 12,366   
Balance at Dec. 31, 2019 524,539    $ 1,311    $ 6,656    $ 5,413    $ (141)   $ 13,239   
Net income 582    582   
Other comprehensive loss (4)   (4)  
Dividends declared on common stock ($0.86 per share)
(453)   (453)  
Issuances of common stock 666    2    21    23   
Share-based compensation 2    (2)   —   
Adoption of ASC Topic 326 (2)   (2)  
Balance at June 30, 2020 525,205    $ 1,313    $ 6,679    $ 5,538    $ (145)   $ 13,385   
See Notes to Consolidated Financial Statements

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XCEL ENERGY INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements (UNAUDITED)
In the opinion of management, the accompanying unaudited consolidated financial statements contain all adjustments necessary to present fairly, in accordance with U.S. GAAP, the financial position of Xcel Energy Inc. and its subsidiaries as of June 30, 2020 and Dec. 31, 2019; the results of its operations, including the components of net income and comprehensive income, and changes in stockholders’ equity for the three and six months ended June 30, 2020 and 2019; and its cash flows for the six months ended June 30, 2020 and 2019.
All adjustments are of a normal, recurring nature, except as otherwise disclosed. Management has also evaluated the impact of events occurring after June 30, 2020, up to the date of issuance of these consolidated financial statements. These statements contain all necessary adjustments and disclosures resulting from that evaluation. The Dec. 31, 2019, balance sheet information has been derived from the audited 2019 consolidated financial statements included in the Xcel Energy Inc. Annual Report on Form 10-K for the year ended Dec. 31, 2019.
Notes to the consolidated financial statements have been prepared pursuant to the rules and regulations of the SEC for Quarterly Reports on Form 10-Q. Certain information and note disclosures normally included in financial statements prepared in accordance with GAAP on an annual basis have been condensed or omitted pursuant to such rules and regulations. For further information, refer to the consolidated financial statements and notes thereto, included in the Xcel Energy Inc. Annual Report on Form 10-K for the year ended Dec. 31, 2019, filed with the SEC on Feb. 21, 2020. Due to the seasonality of Xcel Energy’s electric and natural gas sales, interim results are not necessarily an appropriate base from which to project annual results.
1. Summary of Significant Accounting Policies
The significant accounting policies set forth in Note 1 to the consolidated financial statements in the Xcel Energy Inc. Annual Report on Form 10-K for the year ended Dec. 31, 2019, appropriately represent, in all material respects, the current status of accounting policies and are incorporated herein by reference.
2. Accounting Pronouncements
Recently Adopted
Credit Losses — In 2016, the FASB issued Financial Instruments - Credit Losses, Topic 326 (ASC Topic 326), which changes how entities account for losses on receivables and certain other assets. The guidance requires use of a current expected credit loss model, which may result in earlier recognition of credit losses than under previous accounting standards.
Xcel Energy implemented the guidance using a modified-retrospective approach, recognizing a cumulative effect charge of $2 million (after tax) to retained earnings on Jan. 1, 2020. Other than first-time recognition of an allowance for doubtful accounts on accrued unbilled revenues, the Jan. 1, 2020, adoption of ASC Topic 326 did not have a significant impact on Xcel Energy’s consolidated financial statements.


3. Selected Balance Sheet Data
(Millions of Dollars) June 30, 2020 Dec. 31, 2019
Accounts receivable, net
Accounts receivable $ 859    $ 892   
Less allowance for bad debts (60)   (55)  
Accounts receivable, net $ 799    $ 837   

(Millions of Dollars) June 30, 2020 Dec. 31, 2019
Inventories
Materials and supplies $ 277    $ 270   
Fuel 173    191   
Natural gas 37    83   
Total inventories $ 487    $ 544   

(Millions of Dollars) June 30, 2020 Dec. 31, 2019
Property, plant and equipment, net
Electric plant $ 45,413    $ 44,355   
Natural gas plant 6,747    6,560   
Common and other property 2,385    2,341   
Plant to be retired (a)
292    259   
CWIP 3,060    2,329   
Total property, plant and equipment 57,897    55,844   
Less accumulated depreciation (17,097)   (16,735)  
Nuclear fuel 2,925    2,909   
Less accumulated amortization (2,601)   (2,535)  
Property, plant and equipment, net $ 41,124    $ 39,483   
(a)In 2018, the CPUC approved early retirement of PSCo’s Comanche Units 1 and 2 in approximately 2022 and 2025, respectively. PSCo also expects Craig Unit 1 to be retired early in 2025. Amounts are presented net of accumulated depreciation.
4. Borrowings and Other Financing Instruments
Short-Term Borrowings
Short-Term Debt — Xcel Energy Inc. and its utility subsidiaries meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under their credit facilities and term loan agreements.
Commercial paper and term loan borrowings outstanding for Xcel Energy were as follows:
(Amounts in Millions, Except Interest Rates) Three Months Ended June 30, 2020 Year Ended Dec. 31, 2019
Borrowing limit $ 4,300    $ 3,600   
Amount outstanding at period end 1,410    595   
Average amount outstanding 1,496    1,115   
Maximum amount outstanding 1,770    1,780   
Weighted average interest rate, computed on a daily basis 1.65  % 2.72  %
Weighted average interest rate at period end 0.76    2.34   
Letters of Credit — Xcel Energy Inc. and its subsidiaries use letters of credit, generally with terms of one year, to provide financial guarantees for certain operating obligations. At both June 30, 2020 and Dec. 31, 2019, there were $20 million of letters of credit outstanding under the credit facilities. The contract amounts of these letters of credit approximate their fair value and are subject to fees.
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Revolving Credit Facilities — In order to use commercial paper programs to fulfill short-term funding needs, Xcel Energy Inc. and its utility subsidiaries must have revolving credit facilities in place at least equal to the amount of their respective commercial paper borrowing limits and cannot issue commercial paper in an aggregate amount exceeding available capacity under these credit facilities. The lines of credit provide short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings.
As of June 30, 2020, Xcel Energy Inc. and its utility subsidiaries had the following committed revolving credit facilities available:
(Millions of Dollars)
Credit Facility (a)
Outstanding (b)
Available
Xcel Energy Inc. $ 1,250    $ 210    $ 1,040   
PSCo 700    8    692   
NSP-Minnesota 500    2    498   
SPS 500    10    490   
NSP-Wisconsin 150    —    150   
Total $ 3,100    $ 230    $ 2,870   
(a)Expires in June 2024.
(b)Includes outstanding commercial paper and letters of credit.
Xcel Energy Inc., NSP-Minnesota, PSCo, and SPS each have the right to request an extension of the revolving credit facility termination date for two additional one-year periods. NSP-Wisconsin has the right to request an extension of the revolving credit facility termination date for an additional one-year period. All extension requests are subject to majority bank group approval.
All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under the respective credit facilities. Xcel Energy Inc. and its subsidiaries had no direct advances on the credit facilities outstanding as of June 30, 2020 and Dec. 31, 2019.
Term Loan Agreements — In December 2019, Xcel Energy Inc. entered into a $500 million 364-Day Term Loan Agreement that matures Dec. 1, 2020. Xcel Energy has an option to request an extension through Nov. 30, 2021. In March 2020, Xcel Energy Inc. entered into a $700 million, 364-Day Term Loan Agreement. The loan is unsecured and matures March 22, 2021. Xcel Energy has an option to request an extension through March 21, 2022. The term loans include one financial covenant, requiring Xcel Energy’s consolidated funded debt to total capitalization ratio to be less than or equal to 65 percent. Interest is at a rate equal to either the Eurodollar rate, plus 60.0 basis points, or an alternate base rate.
As of June 30, 2020, Xcel Energy Inc.’s term loan borrowings were as follows:
(Millions of Dollars) Limit Amount Used Available
Xcel Energy Inc. $ 1,200    $ 1,200    $ —   
Bilateral Credit Agreement
In March 2019, NSP-Minnesota entered into a one year uncommitted bilateral credit agreement. The credit agreement is limited in use to support letters of credit. In March 2020, NSP-Minnesota renewed its bilateral credit agreement for an additional one year term.
As of June 30, 2020, NSP-Minnesota’s outstanding letters of credit under the bilateral credit agreement were as follows:
(Millions of Dollars) Limit Amount Outstanding Available
NSP-Minnesota $ 75    $ 31    $ 44   
Long-Term Borrowings
During the six months ended June 30, 2020, Xcel Energy Inc. and its utility subsidiaries issued the following:
•Xcel Energy Inc. issued $600 million of 3.40% senior unsecured notes due June 1, 2030;
•PSCo issued $375 million of 2.70% first mortgage bonds due Jan. 15, 2051 and $375 million of 1.90% first mortgage bonds due Jan. 15, 2031;
•SPS issued $350 million of 3.15% first mortgage bonds due May 1, 2050;
•NSP-Wisconsin issued $100 million of 3.05% first mortgage bonds due May 1, 2051; and
•NSP-Minnesota issued $700 million of 2.60% first mortgage bonds due June 1, 2051.
Forward Equity Agreements — In November 2019, Xcel Energy Inc. entered into forward sale agreements in connection with a completed $743 million public offering of 11.8 million shares of Xcel Energy common stock. The initial forward agreement was for 10.3 million shares with an additional agreement for 1.5 million shares that was exercised at the option of the banking counterparty.
At June 30, 2020, the forward agreements could have been settled with physical delivery of 11.8 million common shares to the banking counterparty in exchange for cash of $728 million. The forward instruments could also have been settled at June 30, 2020, with delivery of approximately $24 million of cash or approximately 0.4 million shares of common stock to the counterparty, if Xcel Energy unilaterally elected net cash or net share settlement, respectively.
The forward price used to determine amounts due at settlement is calculated based on the November 2019 public offering price for Xcel Energy’s common stock of $62.69, increased for the overnight bank funding rate, less a spread of 0.75% and less expected dividends on Xcel Energy’s common stock during the period the instruments are outstanding.
Xcel Energy may settle the agreements at any time up to the maturity date of Dec. 31, 2020. Depending on settlement timing, cash proceeds are expected to be approximately $720 million to $730 million.
Forward equity instruments were recognized within stockholders’ equity at fair value at execution of the agreements and will not be subsequently adjusted until settlement.
Other Equity — Xcel Energy Inc. issued $20 million and $19 million of equity through the DRIP during the six months ended June 30, 2020 and 2019, respectively. The program allows shareholders to elect dividend reinvestment in Xcel Energy Inc. common stock through a non-cash transaction.
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5. Revenues
Revenue is classified by the type of goods/services rendered and market/customer type. Xcel Energy’s operating revenues consists of the following:
Three Months Ended June 30, 2020
(Millions of Dollars) Electric Natural Gas All Other Total
Major revenue types
Revenue from contracts with customers:
Residential $ 718    $ 167    $ 10    $ 895   
C&I 1,075    73    6    1,154   
Other 31    —    1    32   
Total retail 1,824    240    17    2,081   
Wholesale 160    —    —    160   
Transmission 153    —    —    153   
Other 21    26    —    47   
Total revenue from contracts with customers 2,158    266    17    2,441   
Alternative revenue and other 128    14    3    145   
Total revenues $ 2,286    $ 280    $ 20    $ 2,586   
Three Months Ended June 30, 2019
(Millions of Dollars) Electric Natural Gas All Other Total
Major revenue types
Revenue from contracts with customers:
Residential $ 624    $ 182    $ 10    $ 816   
C&I 1,201    90    6    1,297   
Other 31    —    1    32   
Total retail 1,856    272    17    2,145   
Wholesale 154    —    —    154   
Transmission 127    —    —    127   
Other 11    26    —    37   
Total revenue from contracts with customers 2,148    298    17    2,463   
Alternative revenue and other 101    10    3    114   
Total revenues $ 2,249    $ 308    $ 20    $ 2,577   
Six Months Ended June 30, 2020
(Millions of Dollars) Electric Natural Gas All Other Total
Major revenue types
Revenue from contracts with customers:
Residential $ 1,394    $ 522    $ 21    $ 1,937   
C&I 2,141    253    15    2,409   
Other 60    —    2    62   
Total retail 3,595    775    38    4,408   
Wholesale 326    —    —    326   
Transmission 285    —    —    285   
Other 38    58    —    96   
Total revenue from contracts with customers 4,244    833    38    5,115   
Alternative revenue and other 245    30    7    282   
Total revenues $ 4,489    $ 863    $ 45    $ 5,397   
Six Months Ended June 30, 2019
(Millions of Dollars) Electric Natural Gas All Other Total
Major revenue types
Revenue from contracts with customers:
Residential $ 1,351    $ 677    $ 19    $ 2,047   
C&I 2,341    345    15    2,701   
Other 63    —    2    65   
Total retail 3,755    1,022    36    4,813   
Wholesale 343    —    —    343   
Transmission 258    —    —    258   
Other 29    60    —    89   
Total revenue from contracts with customers 4,385    1,082    36    5,503   
Alternative revenue and other 189    20    6    215   
Total revenues $ 4,574    $ 1,102    $ 42    $ 5,718   

6. Income Taxes
Note 7 to the consolidated financial statements included in Xcel Energy’s Annual Report on Form 10-K for the year ended Dec. 31, 2019, represents, in all material respects, the current status of other income tax matters except to the extent noted below, and are incorporated herein by reference.
The following table reconciles the difference between the statutory rate and the ETR:
Three Months Ended June 30 Six Months Ended June 30
2020 2019 2020 2019
Federal statutory rate 21.0  % 21.0  % 21.0  % 21.0  %
State tax (net of federal tax effect) 5.1    5.0    5.0    5.0   
Decreases in tax from:
Wind PTCs (21.1)   (11.9)   (19.1)   (10.0)  
Plant regulatory differences (a)
(7.1)   (5.5)   (7.8)   (5.6)  
Other tax credits, net NOL & tax credit allowances (1.9)   (0.6)   (1.4)   (1.8)  
Other (net) (0.7)   1.2    (1.1)   (0.5)  
Effective income tax rate (4.7) % 9.2  % (3.4) % 8.1  %
(a)  Regulatory differences for income tax primarily relate to the credit of excess deferred taxes to customers through the average rate assumption method. Income tax benefits associated with the credit of excess deferred credits are offset by corresponding revenue reductions.
Federal Audits — Statute of limitations applicable to Xcel Energy’s consolidated federal income tax returns expire as follows:
Tax Years Expiration
2009 — 2013
September 2020
2014 — 2016
June 2021
In 2017, the IRS concluded the audit of tax years 2012 and 2013 and proposed an adjustment that would impact Xcel Energy’s NOL and ETR. Xcel Energy filed a protest with the IRS. In April 2020, Xcel Energy and Appeals reached an agreement and no material adjustments were required.
In 2018, the IRS began an audit of tax years 2014 - 2016. As of June 30, 2020, no adjustments have been proposed.
State Audits — Xcel Energy files consolidated state tax returns based on income in its major operating jurisdictions and various other state income-based tax returns.
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As of June 30, 2020, Xcel Energy’s earliest open tax years (subject to examination by state taxing authorities in its major operating jurisdictions) were as follows:
State Year
Colorado 2009
Minnesota 2009
Texas 2009
Wisconsin 2014
•In 2018, Wisconsin began an audit of tax years 2014 - 2016. As of June 30, 2020, no material adjustments have been proposed.
•No other state income tax audits were in progress as of June 30, 2020.
Unrecognized Benefits — Unrecognized tax benefit balance includes permanent tax positions, which if recognized would affect the annual ETR. In addition, the unrecognized tax benefit balance includes temporary tax positions for which ultimate deductibility is highly certain, but for which there is uncertainty about the timing of such deductibility. A change in the period of deductibility would not affect the ETR but would accelerate the payment to the taxing authority to an earlier period.
Unrecognized tax benefits — permanent vs. temporary:
(Millions of Dollars) June 30, 2020 Dec. 31, 2019
Unrecognized tax benefit — Permanent tax positions $ 36    $ 35   
Unrecognized tax benefit — Temporary tax positions 10    9   
Total unrecognized tax benefit $ 46    $ 44   
Unrecognized tax benefits were reduced by tax benefits associated with NOL and tax credit carryforwards:
(Millions of Dollars) June 30, 2020 Dec. 31, 2019
NOL and tax credit carryforwards $ (41)   $ (40)  
Net deferred tax liability associated with the unrecognized tax benefit amounts and related NOLs and tax credits carryforwards were $31 million at June 30, 2020 and $29 million at Dec. 31, 2019.
As the IRS and state audits progress, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $23 million in the next 12 months.
Payables for interest related to unrecognized tax benefits were not material and no amounts were accrued for penalties related to unrecognized tax benefits as of June 30, 2020 or Dec. 31, 2019.
7. Earnings Per Share
Basic EPS was computed by dividing the earnings available to common shareholders by the weighted average number of common shares outstanding. Diluted EPS was computed by dividing the earnings available to common shareholders by the diluted weighted average number of common shares outstanding.
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 diluted EPS is calculated using the treasury stock method.
Common Stock Equivalents — Xcel Energy Inc. has common stock equivalents related to forward equity agreements and time-based equity compensation awards.
Stock equivalent units granted to Xcel Energy Inc.’s Board of Directors are included in common shares outstanding upon grant date as there is no further service, performance or market condition associated with these awards. Restricted stock issued to employees is included in common shares outstanding when granted.
Share-based compensation arrangements for which there is currently no dilutive impact to EPS include the following:
•Equity awards subject to a performance condition; included in common shares outstanding when all necessary conditions for settlement have been satisfied by the end of the reporting period; and
•Liability awards subject to a performance condition; any portions settled in shares are included in common shares outstanding upon settlement.
Diluted common shares outstanding included common stock equivalents of 0.5 million and 0.7 million for the three and six months ended June 30, 2020, respectively, and 1.8 million and 1.5 million for the three and six months ended June 30, 2019, respectively.
8. Fair Value of Financial Assets and Liabilities
Fair Value Measurements
Accounting guidance for fair value measurements and disclosures provides a single definition of fair value and requires disclosures about assets and liabilities measured at fair value. A hierarchical framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value is established by this guidance.
•Level 1 — Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. The types of assets and liabilities included in Level 1 are highly liquid and actively traded instruments with quoted prices;
•Level 2 — Pricing inputs are other than quoted prices in active markets, but are either directly or indirectly observable as of the reporting date. The types of assets and liabilities included in Level 2 are typically either comparable to actively traded securities or contracts, or priced with models using highly observable inputs; and
•Level 3 — Significant inputs to pricing have little or no observability as of the reporting date. The types of assets and liabilities included in Level 3 are those valued with models requiring significant management judgment or estimation.
Specific valuation methods include:
Cash equivalents — The fair values of cash equivalents are generally based on cost plus accrued interest; money market funds are measured using quoted NAV.
Investments in equity securities and other funds — Equity securities are valued using quoted prices in active markets. The fair values for commingled funds are measured using NAVs. The investments in commingled funds may be redeemed for NAV with proper notice. Private equity commingled fund investments require approval of the fund for any unscheduled redemption, and such redemptions may be approved or denied by the fund at its sole discretion. Unscheduled distributions from real estate commingled funds investments may be redeemed with proper notice, however, withdrawals may be delayed or discounted as a result of fund illiquidity.
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Investments in debt securities — Fair values for debt securities are determined by a third party pricing service using recent trades and observable spreads from benchmark interest rates for similar securities.
Interest rate derivatives — Fair values of interest rate derivatives are based on broker quotes that utilize current market interest rate forecasts.
Commodity derivatives — Methods used to measure the fair value of commodity derivative forwards and options utilize forward prices and volatilities, as well as pricing adjustments for specific delivery locations and are generally assigned a Level 2 classification. When contractual settlements relate to inactive delivery locations or extend to periods beyond those readily observable on active exchanges or quoted by brokers, the significance of the use of less observable forecasts of forward prices and volatilities on a valuation is evaluated and may result in Level 3 classification.
Electric commodity derivatives held by NSP-Minnesota and SPS include transmission congestion instruments, generally referred to as FTRs. FTRs purchased from a RTO are financial instruments that entitle or obligate the holder to monthly revenues or charges based on transmission congestion across a given transmission path.
The value of an FTR is derived from, and designed to offset, the cost of transmission congestion. In addition to overall transmission load, congestion is also influenced by the operating schedules of power plants and the consumption of electricity pertinent to a given transmission path. Unplanned plant outages, scheduled plant maintenance, changes in the relative costs of fuels used in generation, weather and overall changes in demand for electricity can each impact the operating schedules of the power plants on the transmission grid and the value of an FTR.
If forecasted costs of electric transmission congestion increase or decrease for a given FTR path, the value of that particular FTR instrument will likewise increase or decrease. Given the limited observability of certain inputs to the value of FTRs between auction processes, including expected plant operating schedules and retail and wholesale demand, fair value measurements for FTRs have been assigned a Level 3.
Non-trading monthly FTR settlements are included in fuel and purchased energy cost recovery mechanisms as applicable in each jurisdiction and therefore changes in the fair value of the yet to be settled portions of most FTRs are deferred as a regulatory asset or liability. Given this regulatory treatment and the limited magnitude of FTRs relative to the electric utility operations of NSP-Minnesota and SPS, the numerous unobservable quantitative inputs pertinent to the value of FTRs are insignificant to the consolidated financial statements.
Non-Derivative Fair Value Measurements
The NRC requires NSP-Minnesota to maintain a portfolio of investments to fund the costs of decommissioning its nuclear generating plants. Assets of the nuclear decommissioning fund are legally restricted for the purpose of decommissioning these facilities. The fund contains cash equivalents, debt securities, equity securities and other investments. NSP-Minnesota uses the MPUC approved asset allocation for the escrow and investment targets by asset class for both the escrow and qualified trust.
NSP-Minnesota recognizes the costs of funding the decommissioning over the lives of the nuclear plants, assuming rate recovery of all costs. Realized and unrealized gains on fund investments over the life of the fund are deferred as an offset of NSP-Minnesota’s regulatory asset for nuclear decommissioning costs. Consequently, any realized and unrealized gains and losses on securities in the nuclear decommissioning fund are deferred as a component of the regulatory asset.
Unrealized gains for the nuclear decommissioning fund were $637 million and $706 million as of June 30, 2020 and Dec. 31, 2019, respectively, and unrealized losses were $16 million and $6 million as of June 30, 2020 and Dec. 31, 2019, respectively.
Non-derivative instruments with recurring fair value measurements in the nuclear decommissioning fund:
June 30, 2020
Fair Value
(Millions of Dollars) Cost Level 1 Level 2 Level 3 NAV Total
Nuclear decommissioning fund (a)
Cash equivalents $ 22    $ 22    $ —    $ —    $ —    $ 22   
Commingled funds 766    —    —    —    897    897   
Debt securities 513    —    531    10    —    541   
Equity securities 473    934    1    —    —    935   
Total $ 1,774    $ 956    $ 532    $ 10    $ 897    $ 2,395   
(a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $155 million of equity investments in unconsolidated subsidiaries and $133 million of rabbi trust assets and miscellaneous investments.
Dec. 31, 2019
Fair Value
(Millions of Dollars) Cost Level 1 Level 2 Level 3 NAV Total
Nuclear decommissioning fund (a)
Cash equivalents $ 33    $ 33    $ —    $ —    $ —    $ 33   
Commingled funds 733    —    —    —    935    935   
Debt securities 489    —    495    13    —    508   
Equity securities 485    962    2    —    —    964   
Total $ 1,740    $ 995    $ 497    $ 13    $ 935    $ 2,440   
(a)Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $155 million of equity investments in unconsolidated subsidiaries and $136 million of rabbi trust assets and miscellaneous investments.
For the three and six months ended June 30, 2020 and 2019, there were immaterial Level 3 nuclear decommissioning fund investments or transfer of amounts between levels.
Contractual maturity dates of debt securities in the nuclear decommissioning fund as of June 30, 2020:
Final Contractual Maturity
(Millions of Dollars) Due in 1 Year
or Less 		Due in 1 to 5
Years 		Due in 5 to 10
Years 		Due after 10
Years 		Total
Debt securities $ (4)   $ 98    $ 212    $ 235    $ 541   
Rabbi Trusts
Xcel Energy has established rabbi trusts to provide partial funding for future distributions of its supplemental executive retirement plan and deferred compensation plan.
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Cost and fair value of assets held in rabbi trusts:
June 30, 2020
Fair Value
(Millions of Dollars) Cost Level 1 Level 2 Level 3 Total
Rabbi Trusts (a)
Cash equivalents $ 17    $ 17    $ —    $ —    $ 17   
Mutual funds 57    61    —    —    61   
Total $ 74    $ 78    $ —    $ —    $ 78   
Dec. 31, 2019
Fair Value
(Millions of Dollars) Cost Level 1 Level 2 Level 3 Total
Rabbi Trusts (a)
Cash equivalents $ 17    $ 17    $ —    $ —    $ 17   
Mutual funds 57    65    —    —    65   
Total $ 74    $ 82    $ —    $ —    $ 82   
(a) Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet.
Derivative Instruments Fair Value Measurements
Xcel Energy enters into derivative instruments, including forward contracts, futures, swaps and options, for trading purposes and to manage risk in connection with changes in interest rates, utility commodity prices and vehicle fuel prices.
Interest Rate Derivatives — Xcel Energy enters into various instruments that effectively fix the yield or price on a specified benchmark interest rate for an anticipated debt issuance for a specific period. These derivative instruments are generally designated as cash flow hedges for accounting purposes, with changes in fair value prior to settlement recorded as other comprehensive income.
As of June 30, 2020, accumulated other comprehensive loss related to settled interest rate derivatives included $5 million of net losses expected to be reclassified into earnings during the next 12 months as the hedged transactions impact earnings. As of June 30, 2020. Xcel Energy had no unsettled interest rate derivatives.
Wholesale and Commodity Trading Risk — Xcel Energy Inc.’s utility subsidiaries conduct 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. Xcel Energy is allowed to conduct these activities within guidelines and limitations as approved by its risk management committee, comprised of management personnel not directly involved in activities governed by this policy.
Commodity Derivatives — Xcel Energy enters into derivative instruments to manage variability of future cash flows from changes in commodity prices in its electric and natural gas operations, as well as for trading purposes. This could include the purchase or sale of energy or energy-related products, natural gas to generate electric energy, natural gas for resale, FTRs, vehicle fuel and weather derivatives.



Xcel Energy may enter into derivative instruments that mitigate commodity price risk on behalf of electric and natural gas customers, but may not be designated as qualifying hedging transactions. Changes in the fair value of non-trading commodity derivative instruments are recorded as other comprehensive income or deferred as a regulatory asset or liability. The classification as a regulatory asset or liability is based on approved regulatory recovery mechanisms.
As of June 30, 2020, Xcel Energy had no commodity contracts designated as cash flow hedges.
Xcel Energy enters into commodity derivative instruments for trading purposes not directly related to commodity price risks associated with serving its electric and natural gas customers. Changes in the fair value of these commodity derivatives are recorded in electric operating revenues, net of amounts credited to customers under margin-sharing mechanisms.
Gross notional amounts of commodity forwards, options and FTRs:
(Amounts in Millions) (a)(b)
June 30, 2020 Dec. 31, 2019
Megawatt hours of electricity 127    95   
Million British thermal units of natural gas 153    110   
(a)Not reflective of net positions in the underlying commodities.
(b)Notional amounts for options included on a gross basis but weighted for the probability of exercise.
Consideration of Credit Risk and Concentrations — Xcel Energy continuously monitors the creditworthiness of counterparties to its interest rate derivatives and commodity derivative contracts prior to settlement, and assesses each counterparty’s ability to perform on the transactions set forth in the contracts. Impact of credit risk was immaterial to the fair value of unsettled commodity derivatives presented in the consolidated balance sheets. Xcel Energy’s utility subsidiaries’ most significant concentrations of credit risk with particular entities or industries are contracts with counterparties to their wholesale, trading and non-trading commodity activities.
As of June 30, 2020, six of Xcel Energy’s 10 most significant counterparties for these activities, comprising $152 million, or 57%, of this credit exposure, had investment grade credit ratings from S&P Global Ratings, Moody’s Investor Services or Fitch Ratings. Three of the 10 most significant counterparties, comprising $36 million, or 14%, of this credit exposure, were not rated by these external agencies, but based on Xcel Energy’s internal analysis, had credit quality consistent with investment grade. One of these significant counterparties, comprising $13 million or 5% of this credit exposure, had credit quality less than investment grade, based on internal analysis. Eight of these significant counterparties are municipal or cooperative electric entities, RTOs or other utilities.
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Impact of derivative activity:
Pre-Tax Fair Value
Gains (Losses) Recognized
During the Period in:
(Millions of Dollars) Accumulated
Other
Comprehensive Loss 		Regulatory
(Assets) and Liabilities
Three Months Ended June 30, 2020
Other derivative instruments
Natural gas commodity $ —    $ (3)  
Total $ —    $ (3)  
Six Months Ended June 30, 2020
Derivatives designated as cash flow hedges
Interest rate $ (13)   $ —   
Total $ (13)   $ —   
Other derivative instruments
Natural gas commodity $ —    $ (3)  
Total $ —    $ (3)  
Three Months Ended June 30, 2019
Derivatives designated as cash flow hedges
Interest rate $ (13)   $ —   
Total $ (13)   $ —   
Other derivative instruments
Electric commodity $ —    $ 26   
Natural gas commodity —    (2)  
Total $ —    $ 24   
Six Months Ended June 30, 2019
Derivatives designated as cash flow hedges
Interest rate $ (22)   $ —   
Total $ (22)   $ —   
Other derivative instruments
Electric commodity $ —    $ 4   
Natural gas commodity —    (2)  
Total $ —    $ 2   
Pre-Tax (Gains) Losses
Reclassified into Income
During the Period from: 		Pre-Tax Gains
(Losses) Recognized
During the Period in Income
(Millions of Dollars) Accumulated
Other
Comprehensive Loss 		Regulatory
Assets and (Liabilities)
Three Months Ended June 30, 2020
Derivatives designated as cash flow hedges
Interest rate $ 2   
(a)
$ —    $ —   
Total $ 2    $ —    $ —   
Other derivative instruments
Commodity trading $ —    $ —    $ (3)  
(b)
Electric commodity —    (3)  
(c)
—   
Total $ —    $ (3)   $ (3)  
Six Months Ended June 30, 2020
Derivatives designated as cash flow hedges
Interest rate $ 4   
(a)
$ —    $ —   
Total $ 4    $ —    $ —   
Other derivative instruments
Commodity trading $ —    $ —    $ (5)  
(b)
Electric commodity —    (7)  
(c)
—   
Natural gas commodity —    5   
(d)
(6)  
(d)
Total $ —    $ (2)   $ (11)  
Three Months Ended June 30, 2019
Derivatives designated as cash flow hedges
Interest rate $ 1   
(a)
$ —    $ —   
Total $ 1    $ —    $ —   
Other derivative instruments
Commodity trading $ —    $ —    $ 5   
(b)
Total $ —    $ —    $ 5   
Six Months Ended June 30, 2019
Derivatives designated as cash flow hedges
Interest rate $ 2   
(a)
$ —    $ —   
Total $ 2    $ —    $ —   
Other derivative instruments
Commodity trading $ —    $ —    $ 4   
(b)
Electric commodity —    1   
(c)
—   
Natural gas commodity —    (1)  
(d)
(4)  
(d)
Total $ —    $ —    $ —   
(a)Recorded to interest charges.
(b)Recorded to electric operating revenues. Portions of these gains and losses are subject to sharing with electric customers through margin-sharing mechanisms and deducted from gross revenue, as appropriate.
(c)Recorded to electric fuel and purchased power. These derivative settlement gains and losses are shared with electric customers through fuel and purchased energy cost-recovery mechanisms, and reclassified out of income as regulatory assets or liabilities, as appropriate.
(d)Amounts for both the three and six months ended June 30, 2020 and 2019 included no settlement gains or losses on derivatives entered to mitigate natural gas price risk for electric generation recorded to electric fuel and purchased power, subject to cost-recovery mechanisms and reclassified to a regulatory asset, as appropriate. Remaining settlement losses for both the three and six months ended June 30, 2020 and 2019 related to natural gas operations and were recorded to cost of natural gas sold and transported. These gains and losses are subject to cost-recovery mechanisms and reclassified out of income to a regulatory asset or liability, as appropriate.


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Xcel Energy had no derivative instruments designated as fair value hedges during the three and six months ended June 30, 2020 and 2019.
Credit Related Contingent Features — Contract provisions for derivative instruments that the utility subsidiaries enter, including those accounted for as normal purchase-normal sale contracts and therefore not reflected on the consolidated balance sheets, may require the posting of collateral or settlement of the contracts for various reasons, including if the applicable utility subsidiary’s credit ratings are downgraded below its investment grade credit rating by any of the major credit rating agencies, or for cross default contractual provisions if there was a failure under other financing arrangements related to payment terms or other covenants.
As of June 30, 2020 and Dec. 31, 2019, there were $8 million and $7 million derivative instruments in a liability position with such underlying contract provisions, respectively. Certain derivative instruments are also subject to contract provisions that contain adequate assurance clauses. Provisions allow counterparties to seek performance assurance, including cash collateral, in the event that a given utility subsidiary’s ability to fulfill its contractual obligations is reasonably expected to be impaired. Xcel Energy had no collateral posted related to adequate assurance clauses in derivative contracts as of June 30, 2020 and Dec. 31, 2019.
Recurring Fair Value Measurements — Derivative assets and liabilities measured at fair value on a recurring basis:
June 30, 2020 Dec. 31, 2019
Fair Value Fair Value Total
Netting (a)
Total Fair Value Fair Value Total
Netting (a)
Total
(Millions of Dollars) Level 1 Level 2 Level 3 Level 1 Level 2 Level 3
Current derivative assets
Other derivative instruments:
Commodity trading $ 5    $ 52    $ 11    $ 68    $ (50)   $ 18    $ 3    $ 51    $ 24    $ 78    $ (52)   $ 26   
Electric commodity —    —    46    46    (2)   44    —    —    21    21    (1)   20   
Natural gas commodity —    7    —    7    —    7    —    6    —    6    —    6   
Total current derivative assets $ 5    $ 59    $ 57    $ 121    $ (52)   69    $ 3    $ 57    $ 45    $ 105    $ (53)   52   
PPAs (b)
3    3   
Current derivative instruments $ 72    $ 55   
Noncurrent derivative assets
Other derivative instruments:
Commodity trading $ 11    $ 42    $ 23    $ 76    $ (49)   $ 27    $ 9    $ 38    $ 7    $ 54    $ (45)   $ 9   
Total noncurrent derivative assets $ 11    $ 42    $ 23    $ 76    $ (49)   27    $ 9    $ 38    $ 7    $ 54    $ (45)   9   
PPAs (b)
11    13   
Noncurrent derivative instruments $ 38    $ 22   
June 30, 2020 Dec. 31, 2019
Fair Value Fair Value Total
Netting (a)
Total Fair Value Fair Value Total
Netting (a)
Total
(Millions of Dollars) Level 1 Level 2 Level 3 Level 1 Level 2 Level 3
Current derivative liabilities
Other derivative instruments:
Commodity trading $ 6    $ 54    $ 8    $ 68    $ (50)   $ 18    $ 4    $ 59    $ 15    $ 78    $ (63)   $ 15   
Electric commodity —    —    2    2    (2)   —    —    —    1    1    (1)   —   
Natural gas commodity —    5    —    5    —    5    —    5    —    5    —    5   
Total current derivative liabilities
$ 6    $ 59    $ 10    $ 75    $ (52)   23    $ 4    $ 64    $ 16    $ 84    $ (64)   20   
PPAs (b)
17    18   
Current derivative instruments $ 40    $ 38   
Noncurrent derivative liabilities
Other derivative instruments:
Commodity trading $ 4    $ 95    $ 36    $ 135    $ (20)   $ 115    $ 2    $ 79    $ 32    $ 113    $ (13)   $ 100   
Total noncurrent derivative liabilities
$ 4    $ 95    $ 36    $ 135    $ (20)   115    $ 2    $ 79    $ 32    $ 113    $ (13)   100   
PPAs (b)
66    75   
Noncurrent derivative instruments
$ 181    $ 175   
(a)Xcel Energy nets derivative instruments and related collateral in its consolidated balance sheet when supported by a legally enforceable master netting agreement, and all derivative instruments and related collateral amounts were subject to master netting agreements at June 30, 2020 and Dec. 31, 2019. At both June 30, 2020 and Dec. 31, 2019, derivative assets and liabilities include $32 million of obligations to return cash collateral and rights to reclaim cash collateral of $4 million and $11 million, respectively. Counterparty netting amounts presented exclude settlement receivables and payables and non-derivative amounts that may be subject to the same master netting agreements.
(b)During 2006, Xcel Energy qualified these contracts under the normal purchase exception. Based on this qualification, contracts are no longer adjusted to fair value and the previous carrying value of these contracts is being amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.
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Changes in Level 3 commodity derivatives:
Three Months Ended June 30
(Millions of Dollars) 2020 2019
Balance at April 1 $ 4    $ (7)  
Purchases 37    34   
Settlements (25)   (16)  
Net transactions recorded during the period:  
Gains recognized in earnings (a)
9    7   
Net gains recognized as regulatory assets and liabilities 9    10   
Balance at June 30 $ 34    $ 28   
Six Months Ended June 30
(Millions of Dollars) 2020 2019
Balance at Jan. 1 $ 4    $ 29   
Purchases 49    38   
Settlements (42)   (27)  
Net transactions recorded during the period:
Gains (losses) recognized in earnings (a)
14    (11)  
Net gains (losses) recognized as regulatory assets and liabilities 9    (1)  
Balance at June 30 $ 34    $ 28   
(a)Amounts relate to commodity derivatives held at the end of the period.
Xcel Energy recognizes transfers between levels as of the beginning of each period. There were no transfers of amounts between levels for derivative instruments for the three and six months ended June 30, 2020 and 2019.
Fair Value of Long-Term Debt
Other financial instruments which the carrying amount did not equal fair value:
June 30, 2020 Dec. 31, 2019
(Millions of Dollars) Carrying Amount Fair Value Carrying Amount Fair Value
Long-term debt, including current portion $ 20,564    $ 24,327    $ 18,109    $ 20,227   
Fair value of Xcel Energy’s long-term debt is estimated based on recent trades and observable spreads from benchmark interest rates for similar securities. Fair value estimates are based on information available to management as of June 30, 2020 and Dec. 31, 2019, and given the observability of the inputs, fair values presented for long-term debt were assigned as Level 2.
9. Benefit Plans and Other Postretirement Benefits
Components of Net Periodic Benefit Cost (Credit)
Three Months Ended June 30
2020 2019 2020 2019
(Millions of Dollars) Pension Benefits Postretirement Health
Care Benefits
Service cost $ 24    $ 22    $ —    $ —   
Interest cost (a)
31    36    5    6   
Expected return on plan assets (a)
(52)   (51)   (5)   (5)  
Amortization of prior service credit (a)
(1)   (1)   (2)   (3)  
Amortization of net loss (a)
25    22    1    1   
Net periodic benefit cost (credit) 27    28    (1)   (1)  
Credits not recognized due to effects
of regulation 		1    1    1    —   
Net benefit cost (credit) recognized for financial reporting $ 28    $ 29    $ —    $ (1)  
Six Months Ended June 30
2020 2019 2020 2019
(Millions of Dollars) Pension Benefits Postretirement Health
Care Benefits
Service cost $ 45    $ 43    $ 1    $ 1   
Interest cost (a)
68    72    9    11   
Expected return on plan assets (a)
(103)   (102)   (10)   (11)  
Amortization of prior service credit (a)
(2)   (2)   (4)   (5)  
Amortization of net loss (a)
47    44    2    3   
Net periodic benefit cost (credit) 55    55    (2)   (1)  
Credits not recognized due to effects
of regulation 		2    2    1    1   
Net benefit cost (credit) recognized for financial reporting $ 57    $ 57    $ (1)   $ —   
(a)  Components of net periodic cost other than the service cost component are included in the line item “other (expense) income, net” in the consolidated statement of income or capitalized on the consolidated balance sheet as a regulatory asset.
In January 2020, contributions of $150 million were made across four of Xcel Energy’s pension plans. Xcel Energy does not expect additional pension contributions during 2020.
10. Commitments and Contingencies
The following include commitments, contingencies and unresolved contingencies that are material to Xcel Energy’s financial position.
Legal
Xcel Energy is involved in various litigation matters in the ordinary course of business. The assessment of whether a loss is probable or is a reasonable possibility, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. Management maintains accruals for losses probable of being incurred and subject to reasonable estimation. Management is sometimes unable to estimate an amount or range of a reasonably possible loss in certain situations, including but not limited to when (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories.
In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss. For current proceedings not specifically reported, management does not anticipate that the ultimate liabilities would have a material effect on Xcel Energy’s financial statements. Unless otherwise required by GAAP, legal fees are expensed as incurred.
Gas Trading Litigation — e prime is a wholly owned subsidiary of Xcel Energy Inc. e prime was in the business of natural gas trading and marketing but has not engaged in natural gas trading or marketing activities since 2003. Multiple lawsuits seeking monetary damages were commenced against e prime and its affiliates, including Xcel Energy, between 2003 and 2009 alleging fraud and anticompetitive activities in conspiring to restrain the trade of natural gas and manipulate natural gas prices. Cases were all consolidated in the U.S. District Court in Nevada. Two cases remain active which include an MDL matter consisting of a Colorado purported class (Breckenridge) and a Wisconsin purported class (Arandell Corp.).
Breckenridge/Colorado — In February 2019, the MDL panel remanded Breckenridge back to the U.S. District Court in Colorado.
Arandell Corp. — In February 2019, the case was remanded back to the U.S. District Court in Wisconsin. Plaintiffs are seeking class certification. It is uncertain when the court will rule on this issue.
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Xcel Energy has concluded that a loss is remote for both remaining lawsuits.
Rate Matters
MEC Transactions — In January 2020, Xcel Energy, Inc. purchased MEC, a 760 MW natural gas combined cycle facility, for approximately $650 million from Southern Power Company (a subsidiary of Southern Company).
In July 2020, Xcel Energy sold MEC to Southwest Generation for $680 million, subject to working capital adjustments. Proceeds from the sale will primarily be used to reduce Xcel Energy’s overall financing needs.
The assets and liabilities of MEC, including plant assets and working capital, were classified as held for sale at June 30, 2020 pending the sale of the facility in July 2020. Amounts included in the consolidated balance sheet were classified as follows:
(Millions of Dollars) June 30, 2020
Prepayments and other current assets $ 24   
Other assets 644   
Total assets 668   
Other current liabilities 2   
Other deferred credits and other liabilities 9   
Total liabilities $ 11   

NSP-Minnesota — Sherco — In NSP-Minnesota’s 2013 fuel reconciliation filing, the MPUC made recovery of replacement power costs associated with the 2011 incident at its Sherco Unit 3 plant provisional and subject to further review following conclusion of litigation commenced by NSP-Minnesota, SMMPA (Co-owner of Sherco Unit 3) and insurance companies against GE.
In 2018, NSP-Minnesota and SMMPA reached a settlement with GE. NSP-Minnesota notified the MPUC of its proposal to refund the GE settlement proceeds back to customers through the FCA. The insurance providers continued their litigation against GE and the case went to trial.
In 2018, GE prevailed in the lawsuit with the insurance companies, however, the jury found comparable fault, finding that GE was 52% and NSP-Minnesota was 48% at fault. At that point in the litigation, NSP-Minnesota was no longer involved in the case and was not present to make arguments about its role in the event. The specific issue leading to the fault apportionment was also not before the jury and not relevant to the outcome of the trial.
In January 2019, the DOC recommended that NSP-Minnesota refund $20 million of previously recovered purchased power costs to its customers, based on the jury’s apportionment of fault. The OAG recommended the MPUC withhold any decision until the underlying litigation by the insurance providers (currently under appeal) is concluded. The DOC subsequently filed comments agreeing with the OAG’s recommendation to withhold a decision pending the outcome of any appeals. NSP-Minnesota filed reply comments arguing that the DOC recommendations are without merit and that it acted prudently in operating the plant and its settlement with GE was reasonable.
In March 2019, MPUC approved NSP-Minnesota’s proposal to refund the GE settlement proceeds back to customers through the FCA. It also decided to withhold any decision as to NSP-Minnesota’s prudence in connection with the incident at Sherco Unit 3 until after conclusion of the pending litigation between GE and NSP-Minnesota’s insurers. The lower court’s decision was affirmed on appeal. In March 2020, NSP-Minnesota’s insurers filed a petition seeking additional review by the Minnesota Supreme Court.
On April 28, 2020, the Minnesota Supreme Court denied the insurers’ petition for further review, ending the litigation. In accordance with a prior MPUC order, NSP-Minnesota will now make a compliance filing on Aug. 21, 2020, detailing all costs that resulted from the outage and all insurance recoveries received by NSP-Minnesota in connection with the outage. The MPUC has indicated it intends to review the prudence of the Company’s actions and costs in connection with the outage now that the ligation is complete. The MPUC, however, has not specified what process it will use to complete that review.
Westmoreland Arbitration — On Nov. 14, 2014, certain insurers for Westmoreland Coal Company filed an arbitration demand against NSP-Minnesota and other entities (SMMPA and Western Fuels Association), seeking recovery of alleged business losses following the Nov. 19, 2011 incident involving a failure of a low-pressure turbine in Sherco Unit 3. The Westmoreland insurers claim NSP-Minnesota’s invocation of the force majeure clause of the applicable coal supply agreement to stop the supply of coal was improper because the incident was allegedly caused by NSP-Minnesota’s failure to conform to industry maintenance standards. Westmoreland’s insurers quantified their losses as approximately $36 million.
All parties tolled the arbitration pending resolution of a separate lawsuit brought by NSP-Minnesota, SMMPA, and their insurers against various GE entities based on the inspection and maintenance advice GE provided for Sherco Unit 3. That litigation has been resolved and notice of resolution was served July 6, 2020, triggering the arbitration to resume. NSP-Minnesota denies the claims asserted by the Westmoreland insurers, believes it properly stopped the supply of coal based upon the force majeure provision in the coal supply agreement and intends to defend the matter. It is uncertain when a final resolution will occur, but it is unlikely that an arbitration hearing will take place before 2021. At June 30, 2020, a reasonable estimate of the damages or range of damages cannot be determined.
MISO ROE Complaints — In November 2013 and February 2015, customers filed complaints against MISO TOs including NSP-Minnesota and NSP-Wisconsin.
The first complaint argued for a reduction in the base ROE in MISO transmission formula rates from 12.38% to 9.15%, and removal of ROE adders (including those for RTO membership). The second complaint sought to reduce base ROE from 12.38% to 8.67%. In September 2016, the FERC issued an order granting a 10.32% base ROE (10.82% with the RTO adder) effective for the first complaint period of Nov. 12, 2013 to Feb. 11, 2015 and subsequent to the date of the order. The D.C. Circuit subsequently vacated and remanded FERC Opinion No. 531, which had established the ROE methodology on which the September 2016 FERC order was based.
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In November 2019, the FERC issued Opinion No. 569 adopting a new ROE methodology and settling the MISO base ROE at 9.88% (10.38% with the RTO adder), effective Sept. 28, 2016 and for the refund period in the first complaint. The FERC also dismissed the second complaint. In December 2019, MISO TOs filed a request for rehearing. Customers also filed requests for rehearing, claiming among other points, that the FERC erred by dismissing the second complaint without refunds.
FERC accepted the requests for rehearing in January 2020.
In March 2020, the FERC issued a Notice of Proposed Rulemaking regarding changes to its policies for transmission incentives, including a proposal to increase the RTO participation adder from 50 to 100 basis points and to make the adder available regardless of whether a utility’s ongoing participation in the RTO is voluntary or required by legislation or a regulator.
In May 2020, the FERC issued Opinion No. 569-A, which granted rehearing in part to Opinion 569 and further refined the FERC’s ROE methodology, most significantly to incorporate the risk premium model (in addition to the discounted cash flow and capital asset pricing models), resulting in a new base ROE of 10.02%, effective Sept. 28, 2016 and for the refund period in the first complaint. The FERC also affirmed its decision in Opinion 569 to dismiss the second complaint.
Although the May 2020 Order remains subject to pending requests for rehearing, as well as the pending judicial review, NSP-Minnesota has recognized a liability for its best estimate of final refunds to customers.
SPP OATT Upgrade Costs — Under the SPP OATT, costs of transmission upgrades may be recovered from other SPP customers whose transmission service depends on capacity enabled by the upgrade. SPP had not been charging its customers for these upgrades, even though the SPP OATT had allowed SPP to do so since 2008. In 2016, the FERC granted SPP’s request to recover these previously unbilled charges SPP subsequently billed SPS approximately $13 million.
In July 2018, SPS’ appeal to the D.C. Circuit over the FERC rulings granting SPP the right to recover these previously unbilled charges was remanded to the FERC. In February 2019, the FERC reversed its 2016 decision and ordered SPP to refund the charges retroactively collected from its transmission customers, including SPS, related to periods before September 2015.
In March 2020, SPP and Oklahoma Gas & Electric separately filed petitions for review of FERC’s orders at the D.C. Circuit. SPS has intervened in both appeals in support of FERC. Any refunds received by SPS are expected to be given back to SPS customers through future rates.
In October 2017, SPS filed a separate related complaint against SPP asserting that SPP has assessed upgrade charges to SPS in violation of the SPP OATT. In March 2018, FERC issued an order denying the SPS complaint in its entirety, and finding SPP’s calculations to be consistent with the SPS Tariff. SPS filed a request for rehearing in April 2018. The FERC issued a tolling order granting a rehearing for further consideration in May 2018. If SPS’ complaint results in additional charges or refunds, SPS will seek to recover or refund the amounts through future SPS customer rates.
In June 2020, the D.C. Circuit issued a decision in an unrelated proceeding (Allegheny Defense Project v. FERC), which held that FERC’s longstanding use of tolling orders to extend FERC’s deadline to act on the merits of requests for rehearing is improper. The effect on this decision on tolling orders previously issued by FERC is unclear.
Environmental
MGP, Landfill and Disposal Sites
Ashland MGP Site — NSP-Wisconsin was named a responsible party for contamination at the Ashland/Northern States Power Lakefront Superfund Site (the Site) in Ashland, Wisconsin. Remediation was completed in 2019 and restoration activities were completed in 2020. Groundwater treatment activities will continue for many years.
The cost estimate for remediation and restoration of the entire site is approximately $199 million. At June 30, 2020 and Dec. 31, 2019, NSP-Wisconsin had a total liability of $21 million and $23 million, respectively, for the entire site.
NSP-Wisconsin has deferred the unrecovered portion of the estimated Site remediation and restoration costs as a regulatory asset. The PSCW has authorized NSP-Wisconsin rate recovery for all remediation and restoration costs incurred at the Site and application of a 3% carrying charge to the regulatory asset.
Rice Yards (Denver) MGP Site — PSCo is cooperating with the City of Denver on an environmental investigation of the Rice Yards Site in Denver, Colorado, which had various historic industrial uses by multiple parties, including railroad, maintenance shop, scrap metal yard and MGP operations.
In June 2020, PSCo resolved claims by the current property owner and agreed to contribute up to a maximum of $9 million towards future environmental investigation, remediation and mitigation measures over the next 15 years.
In addition to the Rice Yards and Ashland Sites, Xcel Energy is currently investigating, remediating or performing post-closure actions at 12 other MGP, landfill or other disposal sites across its service territories.
Xcel Energy has recognized its best estimate of costs/liabilities that will result from final resolution of these issues, however, the outcome and timing is unknown. In addition, there may be insurance recovery and/or recovery from other potentially responsible parties, offsetting a portion of costs incurred.
Environmental Requirements — Water and Waste
Coal Ash Regulation — Xcel Energy’s operations are subject to federal and state regulations that impose requirements for handling, storage, treatment and disposal of solid waste. Under the CCR Rule, utilities are required to complete groundwater sampling around their CCR landfills and surface impoundments. Currently, Xcel Energy has nine regulated ash units in operation.
Xcel Energy is conducting groundwater sampling and, where appropriate, implementing assessment of corrective measures at certain CCR landfills and surface impoundments. In 2019, groundwater monitoring consistent with the CCR Rule was conducted. In NSP-Minnesota, no results above the groundwater protection standards in the rule were identified. In PSCo, statistically significant levels above background concentrations were detected at four locations. Subsequently, assessment monitoring samples were collected at these locations and, based on the results, PSCo is evaluating options for corrective action at two locations. At one location, monitoring results indicate potential offsite impacts to groundwater. Until PSCo completes its assessment, it is uncertain what impact, if any, there will be on the operations, financial condition or cash flows.
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In August 2018, the D.C. Circuit ruled that the EPA cannot allow utilities to continue to use unlined impoundments (including clay lined impoundments) for the storage or disposal of coal ash. In November 2019, the EPA proposed rules in response to this decision. If finalized in their current form, these rules would require NSP-Minnesota to expedite closure plans for one impoundment at an estimated cost of $4 million and the construction of a new impoundment at the cost of $9 million. In 2019, NSP-Minnesota initiated the construction of this new impoundment, an ash pond, expected to be in service in 2020. Upon placing the new ash pond in service, the existing ash pond will be taken out of service, and closure activities as prescribed by the CCR Rule and the facility’s National Pollutant Discharge Elimination System permit will be initiated.
In addition, the rules proposed by the EPA under the D.C. Circuit ruling may require PSCo to expedite the closure of one coal ash impoundment that was not previously required to close. In March 2020, the EPA published a proposed CCR Rule amendment that, if adopted, would allow unlined impoundments that ‘perform as effectively’ as lined ones to continue to operate under a state or federal CCR permit program. PSCo is pursuing options to provide alternative storage capacity consistent with the CCR Rule until the generating units are retired in 2025.
Closure costs for existing impoundments are included in the calculation of the asset retirement obligation liability.
Leases
Operating lease liabilities at Dec. 31, 2019 include a present value of remaining lease payments of approximately $400 million for the MEC PPAs. At June 30, 2020, NSP-Minnesota operating lease liabilities and related right-of-use assets are eliminated from Xcel Energy’s consolidated balance sheet following the completed January 2020 purchase of MEC by Xcel Energy.

VIEs
Under certain PPAs, NSP-Minnesota, PSCo and SPS purchase power from IPPs for which the utility subsidiaries are required to reimburse fuel costs, or to participate in tolling arrangements under which the utility subsidiaries procure the natural gas required to produce the energy that they purchase. These specific PPAs create a variable interest in the IPP.
The utility subsidiaries had approximately 3,342 MW and 3,986 MW of capacity under long-term PPAs at June 30, 2020 and Dec. 31, 2019, respectively, with entities that have been determined to be VIEs. Xcel Energy concluded that these entities are not required to be consolidated in its consolidated financial statements because it does not have the power to direct the activities that most significantly impact the entities’ economic performance. Agreements have expiration dates through 2041.
Other
Guarantees and Bond Indemnifications — Xcel Energy Inc. and its subsidiaries provide guarantees and bond indemnities, which guarantee payment or performance. Xcel Energy Inc.’s exposure is based upon the net liability under the specified agreements or transactions. Most of the guarantees and bond indemnities issued by Xcel Energy Inc. and its subsidiaries have a stated maximum amount. As of June 30, 2020 and Dec. 31, 2019, Xcel Energy Inc. and its subsidiaries had no assets held as collateral related to their guarantees, bond indemnities and indemnification agreements. Guarantees and bond indemnities issued and outstanding for Xcel Energy were $62 million at June 30, 2020 and Dec. 31, 2019.
Other Indemnification Agreements — Xcel Energy Inc. and its subsidiaries provide indemnifications through various contracts. These are primarily indemnifications against adverse litigation outcomes in connection with underwriting agreements, as well as breaches of representations and warranties, including corporate existence, transaction authorization and income tax matters with respect to assets sold. Xcel Energy Inc.’s and its subsidiaries’ obligations under these agreements may be limited in terms of duration and amount. Maximum future payments under these indemnifications cannot be reasonably estimated as the dollar amounts are often not explicitly stated.
11. Other Comprehensive Income (Loss)
Changes in accumulated other comprehensive loss, net of tax, for the three and six months ended June 30, 2020 and 2019:
Three Months Ended June 30, 2020 Three Months Ended June 30, 2019
(Millions of Dollars) Gains and Losses
on Cash Flow Hedges 		Defined Benefit Pension and
Postretirement Items 		Total Gains and Losses
on Cash Flow Hedges 		Defined Benefit Pension and
Postretirement Items 		Total
Accumulated other comprehensive loss at April 1 $ (88)   $ (60)   $ (148)   $ (66)   $ (61)   $ (127)  
Other comprehensive (loss) gain before reclassifications (net of taxes of $—, $—, $(3) and $—, respectively)
—    —    —    (10)   1    (9)  
Losses reclassified from net accumulated other comprehensive loss:
Interest rate derivatives (net of taxes of $1, $—, $— and $—, respectively) (a)
1    —    1    1    —    1   
Amortization of net actuarial loss (net of taxes of $—, $1, $— and $—, respectively) (b)
—    2    2    —    —    —   
Net current period other comprehensive income (loss) 1    2    3    (9)   1    (8)  
Accumulated other comprehensive loss at June 30 $ (87)   $ (58)   $ (145)   $ (75)   $ (60)   $ (135)  
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Six Months Ended June 30, 2020 Six Months Ended June 30, 2019
(Millions of Dollars) Gains and Losses
on Cash Flow Hedges 		Defined Benefit Pension and
Postretirement Items 		Total Gains and Losses
on Cash Flow Hedges 		Defined Benefit Pension and
Postretirement Items 		Total
Accumulated other comprehensive loss at Jan. 1 $ (80)   $ (61)   $ (141)   $ (60)   $ (64)   $ (124)  
Other comprehensive (loss) gain before reclassifications (net of taxes of $(3), $—, $(5) and $1, respectively)
(10)   —    (10)   (17)   3    (14)  
Losses reclassified from net accumulated other comprehensive loss:
Interest rate derivatives (net of taxes of $1, $—, $— and $—, respectively) (a)
3    —    3    2    —    2   
Amortization of net actuarial loss (net of taxes of $—, $1, $— and $—, respectively) (b)
—    3    3    —    1    1   
Net current period other comprehensive (loss) income (7)   3    (4)   (15)   4    (11)  
Accumulated other comprehensive loss at June 30 $ (87)   $ (58)   $ (145)   $ (75)   $ (60)   $ (135)  
(a)Included in interest charges.
(b)Included in the computation of net periodic pension and postretirement benefit costs.
12. Segment Information
Xcel Energy evaluates performance by each utility subsidiary based on profit or loss generated from the product or service provided, including the regulated electric utility operating results of NSP-Minnesota, NSP-Wisconsin, PSCo and SPS, as well as the regulated natural gas utility operating results of NSP-Minnesota, NSP-Wisconsin and PSCo. These segments are managed separately because the revenue streams are dependent upon regulated rate recovery, which is separately determined for each segment.
Xcel Energy has the following reportable segments:
•Regulated Electric — The regulated electric utility segment generates, transmits and distributes electricity in Minnesota, Wisconsin, Michigan, North Dakota, South Dakota, Colorado, Texas and New Mexico. In addition, this segment includes sales for resale and provides wholesale transmission service to various entities in the United States. The regulated electric utility segment also includes wholesale commodity and trading operations; and
•Regulated Natural Gas — The regulated natural gas utility segment transports, stores and distributes natural gas primarily in portions of Minnesota, Wisconsin, North Dakota, Michigan and Colorado.
Xcel Energy presents Other, which includes operating segments with revenues below the necessary quantitative thresholds. Those operating segments primarily include steam revenue, appliance repair services, non-utility real estate activities, revenues associated with processing solid waste into refuse-derived fuel and investments in rental housing projects that qualify for low-income housing tax credits and the operations of MEC.
Xcel Energy had equity investments in unconsolidated subsidiaries of $155 million as of June 30, 2020 and Dec. 31, 2019 included in the natural gas utility and all other segments.
Asset and capital expenditure information is not provided for Xcel Energy’s reportable segments. As an integrated electric and natural gas utility, Xcel Energy operates significant assets that are not dedicated to a specific business segment. Reporting assets and capital expenditures by business segment would require arbitrary and potentially misleading allocations which may not necessarily reflect the assets that would be required for the operation of the business segments on a stand-alone basis.
Certain costs, such as common depreciation, common O&M expenses and interest expense are allocated based on cost causation allocators across each segment. In addition, a general allocator is used for certain general and administrative expenses, including office supplies, rent, property insurance and general advertising.
Xcel Energy’s segment information for the three and six months ended June 30:
Three Months Ended June 30
(Millions of Dollars) 2020 2019
Regulated Electric
Operating revenues from external customers
$ 2,286    $ 2,249   
Intersegment revenue 1    1   
Total revenues $ 2,287    $ 2,250   
Net income 289    249   
Regulated Natural Gas
Operating revenues from external customers
$ 280    $ 308   
Net income 20    23   
All Other
Total operating revenue
$ 20    $ 20   
Net loss (22)   (34)  
Consolidated Total
Total revenue
$ 2,587    $ 2,578   
Reconciling eliminations (1)   (1)  
Total operating revenues
$ 2,586    $ 2,577   
Net income 287    238   
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Six Months Ended June 30
(Millions of Dollars) 2020 2019
Regulated Electric
Operating revenues from external customers $ 4,489    $ 4,574   
Intersegment revenue 1    1   
Total revenues $ 4,490    $ 4,575   
Net income 516    482   
Regulated Natural Gas
Operating revenues from external customers $ 863    $ 1,102   
Intersegment revenue 1    1   
Total revenues $ 864    $ 1,103   
Net income 111    128   
All Other
Total operating revenue $ 45    $ 42   
Net loss (45)   (57)  
Consolidated Total
Total revenue $ 5,399    $ 5,720   
Reconciling eliminations (2)   (2)  
Total operating revenues $ 5,397    $ 5,718   
Net income 582    553   
ITEM 2 — MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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.
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 six months ended June 30, 2020 and 2019, there were no such adjustments to GAAP earnings and therefore GAAP earnings equal ongoing earnings for these periods.
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.
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GAAP and ongoing diluted EPS for Xcel Energy:
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 June 30
2020 vs.
Normal 		2019 vs.
Normal 		2020 vs.
2019 		2020 vs.
Normal 		2019 vs.
Normal 		2020 vs.
2019
HDD 2.2  % 16.9  % (11.8) % (4.1) % 12.8  % (14.4) %
CDD 22.4    (45.2)   191.2    22.5    (45.5)   139.9   
THI 15.0    (26.7)   63.6    14.7    (26.9)   63.6   
Weather — Estimated impact of temperature variations on EPS compared with normal weather conditions:
Three Months Ended June 30 Six Months Ended June 30
2020 vs.
Normal 		2019 vs.
Normal 		2020 vs.
2019 		2020 vs.
Normal 		2019 vs.
Normal 		2020 vs.
2019
Retail electric $ 0.028    $ (0.024)   $ 0.052    $ 0.017    $ (0.005)   $ 0.022   
Decoupling and sales true-up (0.014)   0.006    (0.020)   (0.009)   0.001    (0.010)  
Electric total $ 0.014    $ (0.018)   $ 0.032    $ 0.008    $ (0.004)   $ 0.012   
Firm natural gas 0.001    0.004    (0.003)   (0.006)   0.022    (0.028)  
Total $ 0.015    $ (0.014)   $ 0.029    $ 0.002    $ 0.018    $ (0.016)  
Sales Growth (Decline) — Sales growth (decline) for actual and weather-normalized sales in 2020 compared to the same period in 2019:
Three Months Ended June 30
PSCo NSP-Minnesota   SPS NSP-Wisconsin Xcel Energy
Actual (a)
Electric residential 13.5  % 10.2  % 13.4  % 10.8  % 11.9  %
Electric 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:
(Millions of Dollars) Three Months Ended June 30,
2020 vs. 2019 		Six Months Ended June 30,
2020 vs. 2019
Regulatory rate outcomes (Colorado, Wisconsin and New Mexico) $ 21    $ 34   
Wholesale transmission revenue (net) 20    25   
Non-fuel riders 11    24   
Estimated impact of weather (net of decoupling/sales true-up) 21    8   
PTCs flowed back to customers (offset by a lower ETR) (31)   (53)  
Sales and demand (a)
(47)   (46)  
New Mexico tax reform related regulatory settlement (2019) —    (10)  
Other (net) 22    30   
Total increase in electric margin $ 17    $ 12   
(a)  Sales decline excludes weather impact, net of decoupling/sales true-up and decrease in demand revenue is net of sales true-up.
Natural Gas Margin
Natural gas expense varies with changing sales and the cost of natural gas. However, fluctuations in the cost of natural gas has minimal impact on natural gas margin due to cost recovery mechanisms.
Natural gas revenues and margin:
Three Months Ended June 30 Six Months Ended June 30
(Millions of Dollars) 2020 2019 2020 2019
Natural gas revenues $ 280    $ 308    $ 863    $ 1,102   
Cost of natural gas sold and transported (86)   (112)   (371)   (591)  
Natural gas margin $ 194    $ 196    $ 492    $ 511   
Changes in natural gas margin:
(Millions of Dollars) Three Months Ended June 30,
2020 vs. 2019 		Six Months Ended June 30,
2020 vs. 2019
Estimated impact of weather $ (2)   $ (19)  
Transport sales —    (2)  
Regulatory rate outcomes (Wisconsin) —    (2)  
Retail sales decline (2)   (1)  
Infrastructure and integrity riders 4    5   
Conservation revenue (offset in expenses) 2    3   
Other (net) (4)   (3)  
Total decrease in natural gas margin $ (2)   $ (19)  
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:
(Millions of Dollars) Three Months Ended June 30,
2020 vs. 2019 		Six Months Ended June 30,
2020 vs. 2019
Distribution $ (20)   $ (30)  
Employee benefits 6    (10)  
Transmission (5)   (6)  
Generation (4)   (6)  
Strategic initiatives —    6   
Other (net) (13)   (9)  
Total decrease in O&M expenses $ (36)   $ (55)  
•Distribution expenses declined due to cost mitigation efforts including allocation of workforce, material and supply management, performance of maintenance and other items;
•Employee benefits were lower year-to-date primarily due to change in deferred compensation liability, offset in Other Income (Expense);
•Transmission expenses declined due to a reduction in labor related amounts and cost mitigation initiatives;
•Generation expenses were lower from timing of maintenance and overhauls at power plants and cost mitigation efforts, partially offset by an increase in wind related amounts;
•Strategic initiative amounts were higher year-to-date due to increased spending on customer experience transformation program expenses and advanced grid infrastructure; and
•Other primarily includes deferred amounts associated with the Texas 2019 electric rate case and the outcome of the CPUC’s rehearing of the Colorado 2019 electric rate case.
Depreciation and Amortization — Depreciation and amortization increased $34 million, or 7.7%, for the second quarter and $64 million, or 7.3%, year-to-date. Increase was primarily driven by the Hale, Lake Benton, Foxtail and Blazing Star I wind facilities going into service, as well as normal system expansion. In addition, depreciation rates were increased in Colorado and New Mexico as part of regulatory outcomes in 2020.
Other Income (Expense) — Other income (expense) increased $3 million for the second quarter and decreased $13 million year-to-date. Decrease is due to the performance of rabbi trust investments, which is offset in O&M expense (deferred compensation).


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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 ending June 30, 2020 compared with 8.1% for the same period in 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 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
Mechanism Utility Service Amount Requested (in millions) Filing
Date 		Approval Additional Information
MPUC
2020 TCR Electric $82 November 2019 Pending In November 2019, NSP-Minnesota filed the 2020 TCR Rider. The filing included an ROE of 9.06%. Timing of an MPUC ruling is uncertain.
2020 GUIC Natural Gas $21 November 2019 Pending In November 2019, NSP-Minnesota filed the 2020 GUIC Rider with the MPUC. The filing included an ROE of 9.04%. Timing of an MPUC ruling is uncertain.
2020 RES
Electric
$102
November 2019
Pending
In November 2019, NSP-Minnesota filed the 2020 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 the early retirement of the King coal plant (511 MW) in 2028 and the Sherco 3 coal plant (517 MW) in 2030;
•Extending the life of the Monticello nuclear plant from 2030 to 2040;
•Continuing to run the Prairie Island nuclear plant through current end of life (2033 and 2034);
•Construction of the Sherco combined cycle natural gas plant;
•The addition of 3,500 MW of solar;
•The addition of 2,250 MW of wind;
•2,600 MW of firm peaking (combustion turbine, pumped hydro, battery storage, demand response etc.);
•Achieving 780 GWh in energy efficiency savings annually through 2034; and
•Adding 400 MW of incremental demand response by 2023, and a total of 1,500 MW of demand response by 2034.
Initial comments are due Oct. 30, 2020 and reply comments are due Jan. 15, 2021. The MPUC is anticipated to make a final decision in the first half of 2021.

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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. In June 2020, NSP-Minnesota filed a Relief & Recovery proposal which identified approximately $3 billion of capital investment which may assist in Minnesota’s economic recovery from COVID-19. The filing included the following components:
•A wind repowering solicitation that could result in 800 to 1,000 MW with an estimated incremental investment of $1.0 to $1.4 billion;
•A 460 MW solar facility with an incremental investment of approximately $650 million;
•Incremental electric vehicle investment and rebates with an estimated cost of $155 million;
•Accelerated transmission investment of $180 million;
•Accelerated distribution investment of $615 million; and
•Accelerated natural gas investment of $50 million.
The MPUC scheduled a planning meeting to determine the procedural process and next steps.
NSP-Minnesota — Mower Wind Facility — In August 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 and FERC to complete the transaction. The MPUC is expected to rule on the request in the third quarter of 2020.
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 KV 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.
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, 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. In March 2020, NSP-Wisconsin filed with the PSCW indicating over-collections of approximately $10 million to customers and proposed for refunds to be issued in September 2020.
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 $14 million. The PSCW will decide on the application later in 2020.
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PSCo
Pending and Recently Concluded Regulatory Proceedings
Mechanism Utility Service Amount Requested (in millions) Filing
Date 		Approval Additional Information
CPUC
Rate Case Natural Gas $127 February 2020 Pending
In February 2020, PSCo filed a rate case with the CPUC seeking a net increase to retail gas rates of $126.8 million, reflecting a $144.5 million increase in base rate revenue, partially offset by $17.7 million of costs previously authorized through the Pipeline Integrity rider. The request was based on a 9.95% ROE, an equity ratio of 55.81% and a historic test year as of Sept. 30, 2019, adjusted for known and measurable differences for the 12-month period ended Sept. 30, 2020. In June 2020, PSCo revised its net increase to $121 million.
In July 2020, PSCo, the CPUC Staff and various intervenors filed a comprehensive unopposed settlement, which results in a net increase to retail gas rates of $77.3 million, reflecting a $94.1 million increase in base rate revenue, partially offset by $16.8 million of costs previously authorized through the Pipeline Integrity rider. The settlement is based on:
•A ROE of 9.20%;
•An equity ratio of 55.62%; and
•A historic test year as of Sept. 30, 2019, utilizing a year-end rate base, and incorporating a known and measurable adjustment for the Tungsten to Black Hawk pipeline as of April 30, 2020.
Rates will be implemented on April 1, 2021 and will be retroactively effective back to November 2020. In July 2020, the ALJ granted an unopposed motion to schedule a hearing for Aug. 13, 2020 to review the settlement.
Rate Case Electric $158 May 2019 Received
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, 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.
Rate Case Appeal Natural Gas N/A April 2019 Pending
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 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    $ 32    $ 34   

Advanced Grid Rider — Seeks to establish an Advanced Grid Rider to recover incremental costs associated with the Advanced Grid Intelligence and Security Initiative (AGIS). The rider would be effective no later than May 2021 and continue through 2025. The PSCo portion of the AGIS initiative is projected to total approximately $850 million of capital additions. Forecasted annual revenue requirements from 2021 through 2025 are as follows:
(Millions of Dollars) 2021 2022 2023 2024 2025
Forecasted annual revenue requirement $ 53    $ 69    $ 83    $ 89    $ 99   
PSCo — 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 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, the Boulder City Council passed an ordinance to establish an electric utility. PSCo challenged the formation of this utility and the Colorado Court of Appeals ruled in PSCo’s favor, vacating a lower court decision. In June 2018, the Colorado Supreme Court rejected Boulder’s request to dismiss the case and remanded it to the Boulder District Court. The case was then settled in June 2019 after Boulder agreed to repeal the ordinance establishing the utility.

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Boulder has filed multiple separation applications with the CPUC, which have been challenged by PSCo and other intervenors. In September 2017, the CPUC issued a written decision, agreeing with several key aspects of PSCo’s position. The CPUC has approved the designation of some electrical distribution assets for transfer, subject to Boulder completing certain filings.
In the fourth quarter of 2018, the Boulder City Council also adopted an Ordinance authorizing Boulder to begin negotiations for the acquisition of certain property or to otherwise condemn that property after Feb. 1, 2019. In the first quarter of 2019, Boulder sent PSCo a notice of intent to acquire certain electric distribution assets. In the third quarter of 2019, Boulder filed its condemnation litigation, which was later dismissed by the Boulder District Court in September 2019 on the grounds that Boulder had not completed the pre-requisite CPUC process and filings. Boulder is currently appealing this order. In October 2019, the CPUC approved the subsequent filings regarding asset transfers outside of substations, reaffirmed its 2017 decision on assets outside of substations and closed the CPUC proceeding.
In December 2019, Boulder filed a new condemnation action despite its ongoing appeal of the last condemnation case. PSCo subsequently filed a motion to dismiss or stay the new condemnation action. In February 2020, Boulder filed an application under section 210 of the Federal Power Act asking FERC to order PSCo to interconnect its facilities with a future Boulder municipal utility under Boulder’s preferred terms and conditions.
In July 2020, PSCo reached a settlement with certain Boulder officials that would end the city’s effort to municipalize. The settlement, if approved, would result in a 20-year franchise arrangement (with multiple opt-out conditions), an energy partnership, an undergrounding agreement and establish how the municipalization would move forward if Boulder exercised an opt-out. The settlement will require approval by the Boulder City Council in August 2020 and will further require approval by the citizens of Boulder in a ballot referendum in November 2020.
SPS
Pending and Recently Concluded Regulatory Proceedings
Mechanism Utility Service Amount Requested (in millions) Filing
Date 		Approval Additional Information
NMPRC
Rate Case Electric $31 July 2019 Received 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 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
Rate Case Electric $141 August 2019 Pending
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;
•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 — In May 2019, the Governor signed into law Senate Bill 1938, 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.
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. In April 2020, interim rates were granted by a Texas ALJ. This case is pending final review and approval by the PUCT. 
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 public hearing is scheduled to begin on Aug. 20, 2020.
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.
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 June 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 ended June 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 (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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At June 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. At June 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 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.
At June 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 $14 million and $17 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 June 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. At June 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 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 June 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 June 30, 2020.
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LIQUIDITY AND CAPITAL RESOURCES
Cash Flows
Six Months Ended June 30
(Millions of Dollars) 2020 2019
Cash provided by operating activities $ 1,148    $ 1,334   
Net cash provided by operating activities decreased $186 million for the six months ended June 30, 2020 compared with the prior year. Decrease (excluding amounts related to non-cash operating activities (e.g., depreciation and amortization and deferred tax expenses) was primarily due to lower collections on accounts receivable as a result of the COVID-19 pandemic and reduced O&M expenditures.
Six Months Ended June 30
(Millions of Dollars) 2020 2019
Cash used in investing activities $ (2,580)   $ (1,708)  
Net cash used in investing activities increased $872 million for the six months ended June 30, 2020 compared with the prior year. Increase was driven by capital expenditures (primarily for wind projects) as well as the purchase of MEC in January 2020.
Six Months Ended June 30
(Millions of Dollars) 2020 2019
Cash provided by financing activities $ 2,818    $ 580   
Net cash provided by financing activities increased $2,238 million for the six months ended June 30, 2020 compared with the prior year. Increase was primarily attributable to proceeds from issuances of long-term debt.
Capital Requirements
Xcel Energy expects to meet future financing requirements by periodically issuing short-term debt, long-term debt, common stock, hybrid and other securities to maintain desired capitalization ratios.
Pension Fund — Xcel Energy’s pension assets are invested in a diversified portfolio of domestic and international equity securities, short-term to long-duration fixed income securities, and alternative investments, including private equity, real estate and hedge funds.
•In January 2020, contributions of $150 million were made across four of Xcel Energy’s pension plans.
•In 2019, contributions of $154 million were made across four of Xcel Energy’s pension plans.
•For future years, contributions will be made as deemed appropriate based on evaluation of various factors including the funded status of the plans, minimum funding requirements, interest rates and expected investment returns.
Capital Sources
Short-Term Funding Sources — Xcel Energy uses a number of sources to fulfill short-term funding needs, including operating cash flow, notes payable, commercial paper and bank lines of credit. The amount and timing of short-term funding needs depend on financing needs for construction expenditures, working capital and dividend payments.
Short-Term Investments — Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS maintain cash operating and short-term investment accounts.
Revolving Credit Facilities — Xcel Energy Inc., NSP-Minnesota, PSCo and SPS each have the right to request an extension of the revolving credit facility for two additional one-year periods beyond the June 2024 termination date. NSP-Wisconsin has the right to request an extension of the revolving credit facility termination date for an additional one-year period. All extension requests are subject to majority bank group approval.
As of July 27, 2020, Xcel Energy Inc. and its utility subsidiaries had the following committed credit facilities available to meet liquidity needs:
(Millions of Dollars)
Credit Facility (a)
Drawn (b)
Available Cash Liquidity
Xcel Energy Inc. $ 1,250    $ 76    $ 1,174    $ 621    $ 1,795   
PSCo 700    8    692    9    701   
NSP-Minnesota 500    10    490    682    1,172   
SPS 500    2    498    186    684   
NSP-Wisconsin 150    —    150    10    160   
Total $ 3,100    $ 96    $ 3,004    $ 1,508    $ 4,512   
(a)Credit facilities expire in June 2024.
(b)Includes outstanding commercial paper and letters of credit.
Bilateral Credit Agreement
In March 2019, NSP-Minnesota entered into a one-year uncommitted bilateral credit agreement. The credit agreement is limited in use to support letters of credit. In March 2020, NSP-Minnesota renewed its bilateral credit agreement for an additional one-year term.
As of June 30, 2020, NSP-Minnesota’s outstanding letters of credit under the Bilateral Credit Agreement were as follows:
(Millions of Dollars) Limit Amount Outstanding Available
NSP-Minnesota $ 75    $ 31    $ 44   
Short-Term Debt — Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS each have individual commercial paper programs. The authorized levels for these commercial paper programs are:
•$1.25 billion for Xcel Energy Inc.;
•$700 million for PSCo;
•$500 million for NSP-Minnesota;
•$500 million for SPS; and
•$150 million for NSP-Wisconsin.
In addition, in December 2019, Xcel Energy Inc. entered into a $500 million 364-Day Term Loan Agreement that matures Dec. 1, 2020. Xcel Energy has an option to request an extension through Nov. 30, 2021. In March 2020, Xcel Energy Inc. entered into a $700 million, 364-Day Term Loan Agreement that matures March 22, 2021. Xcel Energy has an option to request an extension through March 21, 2022.
Short-term debt outstanding for Xcel Energy was as follows:
(Amounts in Millions, Except Interest Rates) Three Months Ended June 30, 2020 Year Ended Dec. 31, 2019
Borrowing limit $ 4,300    $ 3,600   
Amount outstanding at period end 1,410    595   
Average amount outstanding 1,496    1,115   
Maximum amount outstanding 1,770    1,780   
Weighted average interest rate, computed on a daily basis 1.65  % 2.72  %
Weighted average interest rate at period end 0.76    2.34   
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Money Pool — Xcel Energy received FERC approval to establish a utility money pool arrangement with the utility subsidiaries, subject to receipt of required state regulatory approvals. The utility money pool allows for short-term investments in and borrowings between the utility subsidiaries. Xcel Energy Inc. may make investments in the utility subsidiaries at market-based interest rates; however, the money pool arrangement does not allow the utility subsidiaries to make investments in Xcel Energy Inc. The money pool balances are eliminated in consolidation. NSP-Minnesota, PSCo and SPS participate in the money pool pursuant to approval from their respective state regulatory commissions. NSP-Wisconsin currently does not participate in the money pool, however, in July 2020, an application to participate was filed.
2020 Financing Activity — During 2020, Xcel Energy plans to issue approximately $75 to $80 million of equity through the DRIP and benefit programs. In addition, Xcel Energy Inc. and its utility subsidiaries issued the following debt securities:
Issuer Security Amount Status Tenor Coupon
Xcel Energy Inc. Senior Unsecured Notes $ 600   million Completed 10 Year 3.40  %
PSCo First Mortgage Bonds 375   million Completed 31 Year 2.70   
PSCo First Mortgage Bonds 375   million Completed 11 Year 1.90   
SPS First Mortgage Bonds 350   million Completed 30 Year 3.15   
NSP-Wisconsin First Mortgage Bonds 100   million Completed 31 Year 3.05   
NSP-Minnesota First Mortgage Bonds 700   million Completed 31 Year 2.60   
Financing plans are subject to change, depending on capital expenditures, internal cash generation, market conditions and other factors.
Forward Equity Agreements — In November 2019 Xcel Energy Inc. entered into forward equity agreements in connection with a completed $743 million public offering of 11.8 million shares of common stock.
Off-Balance-Sheet Arrangements
Xcel Energy does not have any off-balance-sheet arrangements, other than those currently disclosed, that have or are reasonably likely to have a current or future effect on financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors.
Earnings Guidance and Long-Term EPS and Dividend Growth Rate Objectives
Xcel Energy 2020 Earnings Guidance — Xcel Energy reaffirms 2020 EPS earnings guidance of $2.73 to $2.83 per share (a) (b), which assumes the implementation of contingency plans will be sufficient to offset the negative impacts of COVID-19 under the base case scenario. However, these contingency plans would not be sufficient to offset the negative impacts of COVID-19 under the severe scenario, which would likely result in earnings below the guidance range.
Key assumptions as compared with 2019 levels unless noted:
•Constructive outcomes in all rate case and regulatory proceedings.
•Normal weather patterns for the remainder of the year.
•Weather-normalized retail electric sales are projected to decline ~4%, under the base case scenario.
•Weather-normalized retail firm natural gas sales are projected to decline ~1%, under the base case scenario.
•Capital rider revenue is projected to increase $40 million to $45 million (net of PTCs). PTCs are credited to customers, through capital riders and reductions to electric margin.
•O&M expenses are projected to decline approximately 4% to 5% under the base case scenario.
•Depreciation expense is projected to increase approximately $180 million to $190 million, reflecting updated depreciation rates in regulatory proceedings which are offset by revenue increases.
•Property taxes are projected to increase approximately $35 million to $45 million.
•Interest expense (net of AFUDC - debt) is projected to increase $45 million to $55 million.
•AFUDC - equity is projected to increase approximately $35 million to $45 million.
•The ETR is projected to be ~0%. The ETR reflects benefits of PTCs which are credited to customers through electric margin and will not have a material impact on net income.
(a)  Ongoing earnings is calculated using net income and adjusting for certain nonrecurring or infrequent items that are, in management’s view, not reflective of ongoing operations. Ongoing earnings could differ from those prepared in accordance with GAAP for unplanned and/or unknown adjustments. Xcel Energy is unable to forecast if any of these items will occur or provide a quantitative reconciliation of the guidance for ongoing EPS to corresponding GAAP EPS.
(b)  The global outbreak of COVID-19 is currently impacting countries, communities, supply chains and markets. The ultimate severity of this event is uncertain and could have a material impact on our liquidity, financial condition, or results of operations.
Long-Term EPS and Dividend Growth Rate Objectives — Xcel Energy expects to deliver an attractive total return to our shareholders through a combination of earnings growth and dividend yield, based on the following long-term objectives:
•  Deliver long-term annual EPS growth of 5% to 7% based off of a 2019 base of $2.60 per share, which represents the mid-point of the original 2019 guidance range of $2.55 to $2.65 per share;
• Deliver annual dividend increases of 5% to 7%;
•  Target a dividend payout ratio of 60% to 70%; and
•  Maintain senior secured debt credit ratings in the A range.
COVID-19
Although COVID-19 represents an unprecedented event that has led to numerous challenges, Xcel Energy believes its risk management program, including business continuity and disaster recovery planning, will allow us to proactively manage and successfully navigate the challenges, risks and uncertainties associated with the pandemic. In addition, we have implemented O&M contingency plans to reduce costs and seek regulatory deferral mechanisms to offset the negative impact of COVID-19 on sales, bad debt and other aspects of our business.
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A high degree of uncertainty exists regarding COVID-19, the duration and magnitude of business restrictions, re-shut downs, if any, and the level and pace of recovery of the economy. Also, while we are implementing contingency plans, there are no guarantees these plans will be sufficient to offset the impact of COVID-19. The ultimate impact of this pandemic could have a material impact on Xcel Energy’s operations, financial results and cash flow.
An overview of certain risk considerations or areas which have or could significantly impact us, is as follows.
Sales — In the first half of 2020, Xcel Energy experienced a decline in weather and leap year adjusted sales. The decline in sales was primarily due to pandemic related mandates implemented in March 2020 involving the closure of non-essential businesses and state directives for individuals to stay-at-home. The stay-at-home directives and business closures moderated in May 2020.
Xcel Energy has decoupling and sales true-up mechanisms in Minnesota (all electric classes) and Colorado (residential and non-demand small C&I electric classes), which mitigate the impact of changes to sales levels as compared to a base line.
The following scenarios outline the potential impact of the pandemic on electric and natural gas sales and EPS, based on various assumptions of the duration of the stay-at-home provisions and economic recovery:
•Mild Scenario (severe impact through May with a V-shaped economic recovery).
◦Impact on weather-adjusted electric sales for 2020: an increase of ~1% in residential sales; a decline of ~4% in C&I sales; and a decline in total retail electric sales of ~2%.
◦Impact on 2020 natural gas sales: ~0%.
◦This sales decline would reduce EPS by approximately $0.11.
•Base Case Scenario (severe impact through the second quarter with slower U-shaped recovery with lingering effects).
◦Impact on weather-adjusted electric sales for 2020: an increase of ~1% in residential sales; a decline of 6% in C&I sales; and a decline in total retail electric sales of ~4%.
◦Impact on 2020 natural gas sales: a decline of ~1%.
◦This sales decline would reduce EPS by approximately $0.17.
•Severe Scenario (severe impact through the third quarter followed by protracted challenged L-shaped recovery).
◦Impact on weather-adjusted electric sales for 2020: an increase of ~1% in residential sales; a decline of ~12% in C&I sales; and a decline in total retail electric sales of ~8%.
◦Impact on 2020 natural gas sales: a decline of ~2%.
◦This sales decline would reduce EPS by approximately $0.37.
•Potential impacts due to other items could have negative EPS impact of $0.02 to $0.05, assuming constructive regulatory treatment.
The estimated impact on our monthly weather-adjusted electric sales in the second quarter (primarily COVID-19) is as follows:
Month Residential C&I Total Electric Sales
April 3.2% (13.7)% (9.6)%
May 5.1 (10.6) (6.7)
June 8.9 (10.0) (4.7)
Xcel Energy incorporated the base case scenario into our 2020 guidance assumptions. The second quarter sales results came in better than anticipated in our base case scenario, however there still is substantial uncertainty on the adverse impact of COVID-19 for the remainder of the year.
Bad Debt — In March 2020, Xcel Energy announced it would not disconnect residential customers’ electric or natural gas service during the virus outbreak. Certain states have issued additional limitations on charging late fees and extended protection to other customer classes. Bad debt expense could significantly increase due to regulatory orders, pandemic related economic impacts and customers hardship.
However, several of our commissions are allowing the deferral of incremental COVID-19 related expense, including bad debt expense as discussed further under Regulatory.
Regulatory — Xcel Energy has received orders in Minnesota, Wisconsin, Texas, New Mexico and Michigan, allowing regulatory deferral of incremental COVID-19 costs as a regulatory asset subject to future determination of amount and timing of recovery. Costs include, but are not limited to, bad debt expense, suspension of disconnections, waived late fees and other costs and/or foregone revenues.
Xcel Energy has also filed requests in North Dakota and South Dakota to record a regulatory asset and defer all incremental expenses related to the pandemic. In July 2020, PSCo reached an agreement with Staff and the Office of Consumer Counsel on the deferral of COVID-19 related bad debt expense. These requests are pending regulatory approval.
Xcel Energy serves the majority of its wholesale customers under formula transmission and production rates which true-up rates to actual costs to serve.
Xcel Energy deferred approximately $3 million of related expenses as of June 30, 2020. We will continue to monitor these costs and assess whether the actions of the regulator provide the evidence necessary to defer amounts as regulatory assets.
Contingency Plan — Xcel Energy has implemented contingency plans to reduce costs to offset the negative impact of COVID-19. Actions include reductions of employee expenses, consulting, variable compensation, delays of certain work activities, attrition and implementation of a hiring freeze. Based on these actions, our base case assumption is that 2020 O&M expenses will decline 4% to 5% compared with 2019. The ultimate level of O&M expenses will be dependent on actual sales levels.
We believe we can deliver earnings within our 2020 guidance range based on implementing contingency plans to offset the impact of the pandemic on sales and expense levels under the base case scenario. However, our contingency plans may not be able to offset the negative impact of COVID-19 under a severe scenario.
Supply Chain and Capital Expenditures — Xcel Energy’s ability to meet customer energy requirements, respond to storm-related disruptions and maintain our capital expenditure program are dependent on maintaining an efficient supply chain. During the first half of 2020, Xcel Energy did not experience any material supply chain, contractor or employee disruptions that prevented us from performing maintenance or construction activity. As a result, we have not significantly adjusted our 2020 capital expenditure plan.
However, in April 2020, we were informed of supply chain disruptions, which will likely result in delays in the completion of two of our wind farms into 2021. In May 2020, the U.S. Treasury provided a one-year extension of the continuity PTC safe harbor for renewable projects, including wind and solar, that began construction in 2016 or 2017. Thus, we believe these wind farms will meet the IRS continuity requirements if ultimately placed in service in 2021. As a result, we expect these wind projects will qualify for 100% PTC benefit.
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Pension — The funded status of the Xcel Energy pension plans was approximately 90% in January 2020. The funded status of the pension plan is estimated to be approximately 83%, based on market conditions as of June 2020.
Xcel Energy does not expect any material changes to its pension funding requirement at this time. In addition, Xcel Energy has pension trackers in Colorado and Texas, which allow us to defer amounts that are above or below a baseline.
Liquidity — Xcel Energy has taken steps to enhance its liquidity and believes it has more than adequate liquidity. We have completed our debt issuance plans for Xcel Energy and its operating companies for 2020. In July 2020, we completed the sale of the MEC facility which provided an additional $650 million of funds. As a result of these actions, Xcel Energy had approximately $4.5 billion of available liquidity as of July 27, 2020.
Furthermore, Xcel Energy has an outstanding forward equity agreement in connection with a $743 million public offering of 11.8 million shares. These shares have not been issued and we expect to settle this equity forward later in 2020, which will further enhance liquidity. Finally, Xcel Energy continues to have access to the capital markets on favorable terms.
Customer Service & Reliability — Xcel Energy remains committed to continuing to safely deliver reliable services to our customers as families and communities face the COVID-19 pandemic. We have exercised our business continuity plans to safely serve our customers, protect our employees and ensure critical positions remain staffed.
Key actions include:
•Executing work-from-home practices for employees who can do their work remotely;
•Enhancing cleaning practices within our facilities;
•Providing proper personal protective equipment and following CDC and state guidelines;
•Conducting employee temperature checks;
•Changing work practices to promote social distancing;
•Splitting crews and staggering work times;
•Limiting employee entry into customer homes to emergency situations only; and
•Reminding customers of increased risks of scam activity.
Employees — The health and safety of our workforce is one of our core values and we have taken several actions that reflect that during this pandemic:
•Continued pay for employees who have been quarantined and provide training to employees on how to stay safe and social distance;
•Expanded medical plan coverage for employees and their families to include 100% of COVID-19 medical costs;
•Offered up to an additional 80 hours of paid time off to employees for pandemic related illness;
•Expanded eligibility for our paid time off donation program to employees who have or are caring for a family member who has been diagnosed with the virus;
•Offered new anxiety and stress management tools, in addition to our existing Employee Assistance Program;
•Provided resources and educational materials to support employees adjusting to distance learning with their children; and
•Implemented an employee part-time and voluntary leave of absence program for pandemic-related needs.
Communities — Xcel Energy is committed to the communities in which we operate. Actions include the following:
•Plan to donate approximately $20 million in corporate giving, including COVID-19 relief in 2020. 
•Donated over 300,000 masks to hospitals in the communities we serve; and launched a special $300,000 COVID-19 two-to-one matching campaign, which provides a match for employee donations to impacted non-profit organizations, in addition to our standard employee matching gift programs;
•Donating over 2.5 million high efficiency light bulbs;
•Submitted a proposal to reduce our approved 2020 Fuel Forecast by $25 million to provide immediate relief to our Minnesota customers, which will be implemented across the three summer months equally. Additionally, we proposed temporary relief to certain businesses in Minnesota through the Business Incentive and Sustainability Rider (approximately $6 million); and
•See Public Utility Regulation - NSP-Minnesota above for discussion of the Minnesota Relief and Recovery filing.
ITEM 3 — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
There have been no material changes from Derivatives, Risk Management and Market Risk from our 2019 Form 10-K.
ITEM 4 — CONTROLS AND PROCEDURES
Disclosure Controls and Procedures
Xcel Energy maintains a set of disclosure controls and procedures designed to ensure that information required to be disclosed in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized, and reported within the time periods specified in SEC rules and forms. In addition, the disclosure controls and procedures ensure that information required to be disclosed is accumulated and communicated to management, including the CEO and CFO, allowing timely decisions regarding required disclosure.
As of June 30, 2020, based on an evaluation carried out under the supervision and with the participation of Xcel Energy’s management, including the CEO and CFO, of the effectiveness of its disclosure controls and the procedures, the CEO and CFO have concluded that Xcel Energy’s disclosure controls and procedures were effective.
Internal Control Over Financial Reporting
No changes in Xcel Energy’s internal control over financial reporting occurred during the most recent fiscal quarter that materially affected, or are reasonably likely to materially affect, Xcel Energy’s internal control over financial reporting.
Part II — OTHER INFORMATION
ITEM 1 — LEGAL PROCEEDINGS
Xcel Energy is involved in various litigation matters in the ordinary course of business. The assessment of whether a loss is probable or is a reasonable possibility, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. Management maintains accruals for losses probable of being incurred and subject to reasonable estimation. Management is sometimes unable to estimate an amount or range of a reasonably possible loss in certain situations, including but not limited to when (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories.
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In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss. For current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, would have a material effect on Xcel Energy’s financial statements. Unless otherwise required by GAAP, legal fees are expensed as incurred.
See Note 10 to the consolidated financial statements and Part I Item 2 for further information.
ITEM 1A — RISK FACTORS
There have been no material changes from the risk factors disclosed in our Form 10-K for the year ended Dec. 31, 2019 except as follows:
We face risks related to health epidemics and other outbreaks, which may have a material effect on our financial condition, results of operations and cash flows.
The global outbreak of COVID-19 is currently impacting countries, communities, supply chains and markets. A high degree of uncertainty continues to exist regarding COVID-19, the duration and magnitude of business restrictions, re-shut downs, if any, and the level and pace of economic recovery. While we are implementing contingency plans, there are no guarantees these plans will be sufficient to offset the impact of COVID-19.
We cannot ultimately predict whether it will have a material impact on our liquidity, financial condition, or results of operations. Nor can we predict the impact of the virus on the health of our employees, our supply chain or our ability to recover higher costs associated with managing through the pandemic.
Xcel Energy’s risk factors are documented in Item 1A of Part I of its Annual Report on Form 10-K for the year ended Dec. 31, 2019, which is incorporated herein by reference, as well as other information set forth in this report, which could have a material impact on our financial condition, results of operations and cash flows.
ITEM 2 — UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
Purchases of Equity Securities by the Issuer and Affiliated Purchasers
For the quarter ended June 30, 2020, no equity securities that are registered by Xcel Energy Inc. pursuant to Section 12 of the Securities Exchange Act of 1934 were purchased by or on behalf of us or any of our affiliated purchasers.
ITEM 6 — EXHIBITS
* Indicates incorporation by reference
+ Executive Compensation Arrangements and Benefit Plans Covering Executive Officers and Directors
Exhibit Number Description Report or Registration Statement SEC File or Registration Number Exhibit Reference
3.01*
Xcel Energy Inc. Form 8-K dated May 16, 2012 001-03034 3.01
3.02*
Xcel Energy Inc Form 8-K dated April 3, 2020 001-03034 3.01
4.01*
Xcel Energy Inc. Form 8-K dated April 1, 2020 001-03034 4.01
4.02*
PSCo Form 8-K dated May 15, 2020 001-03280 4.01
4.03*
SPS Form 8-K dated May 18, 2020 001-03789 4.02
4.04*
NSP-Wisconsin 8-K dated May 26, 2020 001-03140 4.01
4.05*
NSP-Minnesota 8-K dated June 15, 2020 001-31387 4.01
101.INS Inline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.
101.SCH Inline XBRL Schema
101.CAL Inline XBRL Calculation
101.DEF Inline XBRL Definition
101.LAB Inline XBRL Label
101.PRE Inline XBRL Presentation
104 Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)
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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
XCEL ENERGY INC.
July 31, 2020 By: /s/ JEFFREY S. SAVAGE
Jeffrey S. Savage
Senior Vice President, Controller
(Principal Accounting Officer)
/s/ BRIAN J. VAN ABEL
Brian J. Van Abel
Executive Vice President, Chief Financial Officer
(Principal Financial Officer)
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Exhibit 10.01
Ninth Amendment
to the
Xcel Energy Senior Executive Severance and Change-In-Control Policy

THIS NINTH AMENDMENT is made this 22nd day of May, 2020, by Xcel Energy Inc. (the “Principal Sponsor”).

WITNESSETH:

WHEREAS, the Principal Sponsor maintains the Xcel Energy Senior Executive Severance and Change-In-Control Policy (the “Policy”), and

WHEREAS, the Board of Directors of the Principal Sponsor (the “Board”) has reserved the right to make amendments to the Policy, and

WHEREAS, the Governance, Compensation and Nominating Committee of the Board of Directors of the Principal Sponsor (the “Committee”) has reserved the right to appoint or remove Participants under the Policy, and

WHEREAS, the Committee wishes to amend the Policy in certain respects to add a Participant to Schedule I to be effective June 1, 2020.

NOW, THEREFORE, the Policy is hereby amended as follows:

1.Schedule I - Participants: Schedule I to the Policy is hereby amended to add those noted below to the Schedule as a Tier I Participants:

Name Tier Severance Multiple Change-in-Control Multiple
Darla Figoli 1 1 3
Amanda Rome 1 1 3

2.Savings Clause. Except as hereinabove set forth, the Xcel Energy Senior Executive Severance and Change-In-Control Policy shall continue in full force and effect.

IN WITNESS WHEREOF, Xcel Energy Inc. has caused this instrument to be enacted by its duly authorized officer as of the date set forth to be effective June 1, 2020.
XCEL ENERGY INC.
By: /s/ BEN FOWKE
Its: Chairman and Chief Executive Officer
         



Exhibit 31.01

CERTIFICATION

I, Ben Fowke, certify that:
1.I have reviewed this report on Form 10-Q of Xcel Energy Inc. (a Minnesota corporation);
2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
Date: July 31, 2020
  /s/ BEN FOWKE
  Ben Fowke
  Chairman, Chief Executive Officer and Director
(Principal Executive Officer)
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Exhibit 31.02

CERTIFICATION

I, Brian J. Van Abel, certify that:
1.I have reviewed this report on Form 10-Q of Xcel Energy Inc. (a Minnesota corporation);
2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
Date: July 31, 2020
  /s/ BRIAN J. VAN ABEL
  Brian J. Van Abel
  Executive Vice President, Chief Financial Officer
(Principal Financial Officer)

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Exhibit 32.01

OFFICER CERTIFICATION

CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Quarterly Report of Xcel Energy Inc. (Xcel Energy) on Form 10-Q for the quarter ended June 30, 2020, as filed with the SEC on the date hereof (Form 10-Q), each of the undersigned officers of Xcel Energy certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to such officer’s knowledge:

(1)The Form 10-Q fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)The information contained in the Form 10-Q fairly presents, in all material respects, the financial condition and results of operations of Xcel Energy as of the dates and for the periods expressed in the Form 10-Q.

Date: July 31, 2020
  /s/ BEN FOWKE
  Ben Fowke
  Chairman, Chief Executive Officer and Director
  (Principal Executive Officer)
  /s/ BRIAN J. VAN ABEL
  Brian J. Van Abel
  Executive Vice President, Chief Financial Officer
(Principal Financial Officer)
The foregoing certification is being furnished solely pursuant to 18 U.S.C. Section 1350 and is not being filed as part of the Report or as a separate disclosure document.
A signed original of this written statement required by Section 906, or other document authenticating, acknowledging or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to Xcel Energy and will be retained by Xcel Energy and furnished to the SEC or its staff upon request.
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