UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C.  20549
FORM 10-Q
(Mark One)
x
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2018
or
¨
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission File Number: 001-3034
Xcel Energy Inc.
(Exact name of registrant as specified in its charter)
Minnesota
 
41-0448030
(State or other jurisdiction of incorporation or organization)
 
(I.R.S. 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)

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.    x Yes  ¨ No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 and 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 and post such files).    x 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 x
 
Accelerated filer ¨
Non-accelerated filer ¨
 
Smaller reporting company ¨
(Do not check if 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 x 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 April 23, 2018
Common Stock, $2.50 par value
 
508,856,950 shares
 



TABLE OF CONTENTS

PART I
FINANCIAL INFORMATION
 
Item 1 —

 

 

 

 

 

 

Item 2 —

Item 3 —

Item 4 —

 
 
 
PART II
OTHER INFORMATION
 
Item 1 —

Item 1A —

Item 2 —

Item 6 —

 
 
 

 
 
 
 
Certifications Pursuant to Section 302
1

 
Certifications Pursuant to Section 906
1

 
Statement Pursuant to Private Litigation
1


This Form 10-Q is filed by Xcel Energy Inc.  Xcel Energy Inc. wholly owns the following subsidiaries: Northern States Power Company, a Minnesota corporation (NSP-Minnesota); Northern States Power Company, a Wisconsin corporation (NSP-Wisconsin); Public Service Company of Colorado (PSCo); and Southwestern Public Service Company (SPS).  Xcel Energy Inc. and its consolidated subsidiaries are also referred to herein as Xcel Energy.  NSP-Minnesota, NSP-Wisconsin, PSCo and SPS are also referred to collectively as utility subsidiaries.  The electric production and transmission system of NSP-Minnesota and NSP-Wisconsin, which is operated on an integrated basis and is managed by NSP-Minnesota, is referred to collectively as the NSP System. Additional information on the wholly owned subsidiaries is available on various filings with the Securities and Exchange Commission (SEC).

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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 March 31
 
2018
 
2017
Operating revenues
 
 
 
Electric
$
2,270

 
$
2,299

Natural gas
662

 
626

Other
19

 
21

Total operating revenues
2,951

 
2,946

 
 
 
 
Operating expenses
 
 
 
Electric fuel and purchased power
932

 
925

Cost of natural gas sold and transported
375

 
365

Cost of sales — other
8

 
9

Operating and maintenance expenses
557

 
580

Conservation and demand side management expenses
71

 
68

Depreciation and amortization
383

 
365

Taxes (other than income taxes)
145

 
142

Total operating expenses
2,471

 
2,454

 
 
 
 
Operating income
480

 
492

 
 
 
 
Other income, net
1

 
1

Equity earnings of unconsolidated subsidiaries
6

 
8

Allowance for funds used during construction — equity
23

 
14

 
 
 
 
Interest charges and financing costs
 
 
 
Interest charges — includes other financing costs of $6 and $6, respectively
171

 
166

Allowance for funds used during construction — debt
(11
)
 
(7
)
Total interest charges and financing costs
160

 
159

 
 
 
 
Income before income taxes
350

 
356

Income taxes
59

 
117

Net income
$
291

 
$
239

 
 
 
 
Weighted average common shares outstanding:
 
 
 
Basic
509

 
508

Diluted
509

 
509

 
 
 
 
Earnings per average common share:
 
 
 
Basic
$
0.57

 
$
0.47

Diluted
0.57

 
0.47

 
 
 
 
Cash dividends declared per common share
$
0.38

 
$
0.36

 
 
 
 
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 March 31
 
2018
 
2017
Net income
$
291

 
$
239

 
 
 
 
Other comprehensive income
 
 
 
 
 
 
 
Pension and retiree medical benefits:
 
 
 
Amortization of losses included in net periodic benefit cost, net of tax of $0 and $1, respectively
1

 
1

 
 
 
 
Derivative instruments:
 
 
 
Reclassification of losses to net income, net of tax of $0 and $1, respectively

 
1

 
 
 
 
 
 
 
 
Other comprehensive income
1

 
2

Comprehensive income
$
292

 
$
241

 
 
 
 
See Notes to Consolidated Financial Statements




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XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
(amounts in millions)
 
Three Months Ended March 31
 
2018
 
2017
Operating activities
 
 
 
Net income
$
291

 
$
239

Adjustments to reconcile net income to cash provided by operating activities:
 
 
 
Depreciation and amortization
387

 
369

Nuclear fuel amortization
31

 
31

Deferred income taxes
59

 
194

Allowance for equity funds used during construction
(23
)
 
(14
)
Equity earnings of unconsolidated subsidiaries
(6
)
 
(8
)
Dividends from unconsolidated subsidiaries
9

 
12

Share-based compensation expense
6

 
18

Other, net
(1
)
 
4

Changes in operating assets and liabilities:
 
 
 
Accounts receivable
(71
)
 
3

Accrued unbilled revenues
159

 
174

Inventories
118

 
88

Other current assets
1

 
(77
)
Accounts payable
(42
)
 
(144
)
Net regulatory assets and liabilities
147

 
18

Other current liabilities
(17
)
 
(43
)
Pension and other employee benefit obligations
(146
)
 
(149
)
Change in other noncurrent assets
2

 

Change in other noncurrent liabilities
(17
)
 
3

Net cash provided by operating activities
887

 
718

 
 
 
 
Investing activities
 
 
 
Utility capital/construction expenditures
(883
)
 
(749
)
Allowance for equity funds used during construction
23

 
14

Purchases of investment securities
(185
)
 
(173
)
Proceeds from the sale of investment securities
179

 
168

Investments in unconsolidated subsidiaries and other
(3
)
 
(3
)
Other, net
(3
)
 
(5
)
Net cash used in investing activities
(872
)
 
(748
)
 
 
 
 
Financing activities
 
 
 
Proceeds from short-term borrowings, net
211

 
213

Dividends paid
(175
)
 
(173
)
Other
(18
)
 
(21
)
Net cash provided by financing activities
18

 
19

 
 
 
 
Net change in cash and cash equivalents
33

 
(11
)
Cash and cash equivalents at beginning of period
83

 
85

Cash and cash equivalents at end of period
$
116

 
$
74

 
 
 
 
Supplemental disclosure of cash flow information:
 
 
 
Cash paid for interest (net of amounts capitalized)
$
(181
)
 
$
(174
)
 
 
 
 
Supplemental disclosure of non-cash investing and financing transactions:
 
 
 
Property, plant and equipment additions in accounts payable
$
241

 
$
186

Issuance of common stock for equity awards
20

 
12

 
 
 
 
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)

 
March 31, 2018
 
Dec. 31, 2017
Assets
 
 
 
Current assets
 
 
 
Cash and cash equivalents
$
116

 
$
83

Accounts receivable, net
868

 
797

Accrued unbilled revenues
605

 
764

Inventories
492

 
610

Regulatory assets
422

 
424

Derivative instruments
28

 
44

Prepaid taxes
63

 
68

Prepayments and other
188

 
183

Total current assets
2,782

 
2,973

 
 
 
 
Property, plant and equipment, net
34,679

 
34,329

 
 
 
 
Other assets
 
 
 
Nuclear decommissioning fund and other investments
2,404

 
2,397

Regulatory assets
2,965

 
3,005

Derivative instruments
49

 
48

Other
280

 
278

Total other assets
5,698

 
5,728

Total assets
$
43,159

 
$
43,030

 
 
 
 
Liabilities and Equity
 
 
 
Current liabilities
 
 
 
Current portion of long-term debt
$
457

 
$
457

Short-term debt
1,025

 
814

Accounts payable
1,027

 
1,243

Regulatory liabilities
270

 
239

Taxes accrued
544

 
448

Accrued interest
147

 
174

Dividends payable
193

 
183

Derivative instruments
30

 
29

Other
429

 
501

Total current liabilities
4,122

 
4,088

 
 
 
 
Deferred credits and other liabilities
 
 
 
Deferred income taxes
3,905

 
3,845

Deferred investment tax credits
57

 
58

Regulatory liabilities
5,141

 
5,083

Asset retirement obligations
2,504

 
2,475

Derivative instruments
120

 
126

Customer advances
200

 
193

Pension and employee benefit obligations
884

 
1,042

Other
143

 
145

Total deferred credits and other liabilities
12,954

 
12,967

 
 
 
 
Commitments and contingencies


 


Capitalization
 
 
 
Long-term debt
14,522

 
14,520

Common stock — 1,000,000,000 shares authorized of $2.50 par value; 508,661,859 and
507,762,881 shares outstanding at March 31, 2018 and Dec. 31, 2017, respectively
1,272

 
1,269

Additional paid in capital
5,903

 
5,898

Retained earnings
4,510

 
4,413

Accumulated other comprehensive loss
(124
)
 
(125
)
Total common stockholders’ equity
11,561

 
11,455

Total liabilities and equity
$
43,159

 
$
43,030

 
 
 
 
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 March 31, 2018 and 2017
 
 
 
 
 
 
 
 
 
 
Balance at Dec. 31, 2016
507,223

 
$
1,268

 
$
5,881

 
$
3,982

 
$
(110
)
 
$
11,021

Net income


 


 


 
239

 


 
239

Other comprehensive income


 


 


 


 
2

 
2

Dividends declared on common stock


 


 


 
(184
)
 


 
(184
)
Issuances of common stock
611

 
1

 
4

 


 


 
5

Repurchases of common stock
(71
)
 

 
(3
)
 


 


 
(3
)
Share-based compensation


 


 
(9
)
 
(1
)
 


 
(10
)
Balance at March 31, 2017
507,763

 
$
1,269

 
$
5,873

 
$
4,036

 
$
(108
)
 
$
11,070

 
 
 
 
 
 
 
 
 
 
 
 
Balance at Dec. 31, 2017
507,763

 
$
1,269

 
$
5,898

 
$
4,413

 
$
(125
)
 
$
11,455

Net income


 


 


 
291

 


 
291

Other comprehensive income


 


 


 


 
1

 
1

Dividends declared on common stock


 


 


 
(194
)
 


 
(194
)
Issuances of common stock
921

 
3

 
14

 


 


 
17

Repurchases of common stock
(22
)
 

 
(1
)
 


 


 
(1
)
Share-based compensation


 


 
(8
)
 

 


 
(8
)
Balance at March 31, 2018
508,662

 
$
1,272

 
$
5,903

 
$
4,510

 
$
(124
)
 
$
11,561

 
 
 
 
 
 
 
 
 
 
 
 
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 accounting principles generally accepted in the United States of America (GAAP), the financial position of Xcel Energy Inc. and its subsidiaries as of March 31, 2018 and Dec. 31, 2017; the results of its operations, including the components of net income and comprehensive income, and changes in stockholders’ equity for the three months ended March 31, 2018 and 2017; and its cash flows for the three months ended March 31, 2018 and 2017. All adjustments are of a normal, recurring nature, except as otherwise disclosed. Management has also evaluated the impact of events occurring after March 31, 2018 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, 2017 balance sheet information has been derived from the audited 2017 consolidated financial statements included in the Xcel Energy Inc. Annual Report on Form 10-K for the year ended Dec. 31, 2017. These 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, 2017, filed with the SEC on Feb. 23, 2018. 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, 2017, appropriately represent, in all material respects, the current status of accounting policies and are incorporated herein by reference.

2.
Accounting Pronouncements

Recently Issued

Leases — In February 2016, the Financial Accounting Standards Board (FASB) issued Leases, Topic 842 (Accounting Standards Update (ASU) No. 2016-02), which for lessees requires balance sheet recognition of right-of-use assets and lease liabilities for most leases. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2018. Xcel Energy has not yet fully determined the impacts of implementation. However, adoption is expected to occur on Jan. 1, 2019 utilizing the practical expedients provided by the standard and proposed in Targeted Improvements, Topic 842 (Proposed ASU 2018-200). As such, agreements entered into prior to Jan. 1, 2019 that are currently considered leases are expected to be recognized on the consolidated balance sheet, including contracts for use of office space, equipment and natural gas storage assets, as well as certain purchased power agreements (PPAs) for natural gas-fueled generating facilities. Xcel Energy expects that similar agreements entered into after Dec. 31, 2018 will generally qualify as leases under the new standard.

Recently Adopted

Revenue Recognition In May 2014, the FASB issued Revenue from Contracts with Customers, Topic 606 (ASU No. 2014-09), which provides a new framework for the recognition of revenue. Xcel Energy implemented the guidance on a modified retrospective basis on Jan. 1, 2018. Results for reporting periods beginning after Dec. 31, 2017 are presented in accordance with Topic 606, while prior period results have not been adjusted and continue to be reported in accordance with prior accounting guidance. Other than increased disclosures regarding revenues related to contracts with customers, the implementation did not have a significant impact on Xcel Energy’s consolidated financial statements. For related disclosures, see Note 14.

Classification and Measurement of Financial Instruments — In January 2016, the FASB issued Recognition and Measurement of Financial Assets and Financial Liabilities, Subtopic 825-10 (ASU No. 2016-01), which eliminated the available-for-sale classification for marketable equity securities and also replaced the cost method of accounting for non-marketable equity securities with a model for recognizing impairments and observable price changes. Under the new standard, other than when the consolidation or equity method of accounting is utilized, changes in the fair value of equity securities are recognized in earnings. Xcel Energy implemented the guidance on Jan. 1, 2018. As a result of application of accounting principles for rate regulated entities, changes in the fair value of the securities in the nuclear decommissioning fund, historically classified as available-for-sale, continue to be deferred to a regulatory asset, and the overall adoption impacts were not material.

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Presentation of Net Periodic Benefit Cost — In March 2017, the FASB issued Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost, Topic 715 (ASU No. 2017-07), which establishes that only the service cost element of pension cost may be presented as a component of operating income in the income statement. Also under the guidance, only the service cost component of pension cost is eligible for capitalization. As a result of application of accounting principles for rate regulated entities, a similar amount of pension cost, including non-service components, will be recognized consistent with the historical ratemaking treatment, and the impacts of adoption will be limited to changes in classification of non-service costs in the consolidated statement of income. Xcel Energy implemented the new guidance on Jan. 1, 2018, and as a result, $6 million of pension costs were retrospectively reclassified from operating and maintenance expenses to other income, net on the consolidated income statement for the three months ended March 31, 2017. Under a practical expedient permitted by the standard, Xcel Energy used benefit cost amounts disclosed for prior periods as the basis for retrospective application.

3.
Selected Balance Sheet Data
(Millions of Dollars)
 
March 31, 2018
 
Dec. 31, 2017
Accounts receivable, net
 
 
 
 
Accounts receivable
 
$
921

 
$
849

Less allowance for bad debts
 
(53
)
 
(52
)
 
 
$
868

 
$
797

(Millions of Dollars)
 
March 31, 2018
 
Dec. 31, 2017
Inventories
 
 
 
 
Materials and supplies
 
$
311

 
$
311

Fuel
 
144

 
186

Natural gas
 
37

 
113

 
 
$
492

 
$
610

(Millions of Dollars)
 
March 31, 2018
 
Dec. 31, 2017
Property, plant and equipment, net
 
 
 
 
Electric plant
 
$
39,348

 
$
39,016

Natural gas plant
 
5,855

 
5,800

Common and other property
 
2,027

 
2,013

Plant to be retired (a)
 
11

 
11

Construction work in progress
 
2,339

 
2,087

Total property, plant and equipment
 
49,580

 
48,927

Less accumulated depreciation
 
(15,276
)
 
(15,000
)
Nuclear fuel
 
2,701

 
2,697

Less accumulated amortization
 
(2,326
)
 
(2,295
)
 
 
$
34,679

 
$
34,329


(a) 
In the third quarter of 2017, PSCo early retired Valmont Unit 5 and converted Cherokee Unit 4 from a coal-fueled generating facility to natural gas. PSCo also expects Craig Unit 1 to be early retired in approximately 2025. Amounts are presented net of accumulated depreciation.

4.
Income Taxes

Except to the extent noted below, Note 6 to the consolidated financial statements included in Xcel Energy Inc.’s Annual Report on Form 10-K for the year ended Dec. 31, 2017 appropriately represents, in all material respects, the current status of other income tax matters, and is incorporated herein by reference.

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Total income tax expense from operations differs from the amount computed by applying the statutory federal income tax rate to income before income tax expense. The following reconciles such differences:
 
 
Three Months Ended March 31
 
 
2018
 
2017
Federal statutory rate
 
21.0
 %
 
35.0
 %
State tax, net of federal tax effect
 
4.9
 %
 
4.0
 %
Increases (decreases) in tax from:
 
 
 
 
Wind production tax credits
(6.0
)
 
(4.0
)
Regulatory differences - ARAM (a)
(5.8
)
 
(0.1
)
Regulatory differences - ARAM deferral (b)
5.4

 

Regulatory differences - other utility plant items
(1.0
)
 
(0.5
)
Other, net
(1.6
)
 
(1.5
)
Effective income tax rate
 
16.9
 %
 
32.9
 %

(a)  
The average rate assumption method (ARAM); a method to flow back excess deferred taxes to customers.
(b)
As we receive direction from our regulatory commissions regarding the return of excess deferred taxes (to our customers resulting from the TCJA), the ARAM deferral may decrease during the year, which would result in a reduction to tax expense with a corresponding reduction to revenue.

Federal Audits  Xcel Energy files a consolidated federal income tax return. The statute of limitations applicable to Xcel Energy’s federal income tax returns expire as follows:
Tax Year(s)
 
Expiration
2009 - 2011
 
December 2018
2012 - 2013
 
October 2018
2014
 
September 2018
2015
 
September 2019
2016
 
September 2020

In 2012, the Internal Revenue Service (IRS) commenced an examination of tax years 2010 and 2011, including the 2009 carryback claim. The IRS proposed an adjustment to the federal tax loss carryback claims and in 2015, the IRS forwarded the issue to the Office of Appeals (Appeals). In 2017, Xcel Energy and Appeals reached an agreement and the benefit related to the agreed upon portions was recognized. As of March 31, 2018, the case has been forwarded to the Joint Committee on Taxation.

In the third quarter of 2015, the IRS commenced an examination of tax years 2012 and 2013. In the third quarter of 2017, the IRS concluded the audit of tax years 2012 and 2013 and proposed an adjustment that would impact Xcel Energy’s net operating loss (NOL) and effective tax rate (ETR). After evaluating the proposed adjustment, Xcel Energy filed a protest with the IRS. Xcel Energy anticipates the issue will be forwarded to Appeals. As of March 31, 2018, Xcel Energy has recognized its best estimate of income tax expense that will result from a final resolution of this issue; however, the outcome and timing of a resolution is unknown.


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State Audits  Xcel Energy files consolidated state tax returns based on income in its major operating jurisdictions of Colorado, Minnesota, Texas, and Wisconsin, and various other state income-based tax returns. As of March 31, 2018, Xcel Energy’s earliest open tax years that are subject to examination by state taxing authorities in its major operating jurisdictions were as follows:
State
 
Year
Colorado
 
2009
Minnesota
 
2009
Texas
 
2009
Wisconsin
 
2012

In 2016, Minnesota began an audit of years 2010 through 2014. As of March 31, 2018, Minnesota had not proposed any material adjustments;
In 2016, Wisconsin began an audit of years 2012 and 2013. As of March 31, 2018, Wisconsin had not proposed any material adjustments; and
As of March 31, 2018, there were no other state income tax audits in progress.

Unrecognized Benefits — The 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 the 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 of cash to the taxing authority to an earlier period.

A reconciliation of the amount of unrecognized tax benefit is as follows:
(Millions of Dollars)
 
March 31, 2018
 
Dec. 31, 2017
Unrecognized tax benefit — Permanent tax positions
 
$
21

 
$
20

Unrecognized tax benefit — Temporary tax positions
 
19

 
19

Total unrecognized tax benefit
 
$
40

 
$
39


The unrecognized tax benefit amounts were reduced by the tax benefits associated with NOL and tax credit carryforwards. The amounts of tax benefits associated with NOL and tax credit carryforwards are as follows:
(Millions of Dollars)
 
March 31, 2018
 
Dec. 31, 2017
NOL and tax credit carryforwards
 
$
(32
)
 
$
(31
)

It is reasonably possible that Xcel Energy’s amount of unrecognized tax benefits could significantly change in the next 12 months as the IRS Appeals progresses and audits resume, the Minnesota and Wisconsin audits progress, and other state audits resume. As the IRS Appeals and Minnesota and Wisconsin audits progress, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $26 million.

The payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards. The payables for interest related to unrecognized tax benefits at March 31, 2018 and Dec. 31, 2017 were not material. No amounts were accrued for penalties related to unrecognized tax benefits as of March 31, 2018 or Dec. 31, 2017.

5.
Rate Matters

Except to the extent noted below, the circumstances set forth in Note 12 to the consolidated financial statements included in Xcel Energy Inc.’s Annual Report on Form 10-K for the year ended Dec. 31, 2017, appropriately represent, in all material respects, the current status of other rate matters, and are incorporated herein by reference.


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Tax Reform Regulatory Proceedings

The specific impacts of the Tax Cuts and Jobs Act (TCJA) on customer rates are subject to regulatory approval. Each of the states in Xcel Energy’s service areas have opened dockets to address the impacts of the TCJA. Xcel Energy has made filings and is working with various stakeholders in its jurisdictions to determine the appropriate treatment for the TCJA.

NSP-Minnesota — The Minnesota Public Utility Commission (MPUC) opened a TCJA docket and issued a request for information on the impacts of the TCJA in January 2018. In March 2018, the Minnesota Department of Commerce (DOC) recommended adjusting rates or implementing refunds for the current tax impacts and incorporating the deferred tax impacts in each utility’s next rate case.

In April 2018, NSP-Minnesota filed an update of the estimated impact of the TCJA, which reflected an overall reduction in 2018 revenue requirements of approximately $136 million for electric and $7 million for natural gas. The filing also proposed recommended options for delivering tax reform benefits to customers. The proposed electric options included: customer refunds and rider impacts of $68 million, deferral of $44 million to allow for a rate case stay-out for 2020, acceleration of depreciation for the King coal plant of $22 million and low income program funding of $2 million. The proposed natural gas options included customer refunds and rider impacts of $3 million, with the remaining TCJA benefits deferred to mitigate increased costs in the next natural gas rate case. A MPUC decision is expected later in 2018.

Dockets have also been opened in North Dakota and South Dakota. In February 2018, NSP-Minnesota proposed using the reduced revenue requirements from the TCJA to defer planned future rate filings in both jurisdictions.

NSP-Wisconsin — In January 2018, the Public Service Commission of Wisconsin (PSCW) issued an order requiring public utilities to apply deferred accounting for the impacts of the TCJA. In March 2018, NSP-Wisconsin filed recommended plans for Wisconsin, which for electric operations included an option for an immediate bill credit for a portion of the tax savings in 2018 and 2019, while deferring the remainder until NSP-Wisconsin’s 2020 electric rate case. For the natural gas operations, NSP-Wisconsin proposed using the TCJA to reduce the unamortized regulatory asset for the Ashland/Northern States Power Lakefront Superfund Site (the Site) clean-up. A PSCW decision on the regulatory treatment of the TCJA is anticipated later in 2018.

For Michigan, NSP-Wisconsin has reached settlement in its electric rate case, which reflects the impacts of the TCJA, and has proposed customer refunds for natural gas operations.

PSCo — In January 2018, the Colorado Public Utilities Commission (CPUC) opened a statewide TCJA proceeding and ordered deferred accounting for all investor-owned utilities.

Colorado 2017 Multi-Year Natural Gas Rate Case - In February 2018, the administrative law judge (ALJ) approved PSCo and the CPUC Staff’s settlement agreement addressing the TCJA, which includes a $20 million reduction to provisional rates effective March 1, 2018. A final true-up, including any outcomes associated with the statewide proceeding, would provide customers the full net benefit of the TCJA effective January 2018. A CPUC decision is pending.

Colorado Electric - In April 2018, PSCo, the CPUC Staff and the OCC filed a TCJA settlement agreement with the CPUC that identified a reduction in electric revenue requirements of approximately $101 million for the TCJA in 2018.  The settlement recommended a customer refund of $42 million in 2018, with the remainder of $59 million be used to accelerate the amortization of an existing prepaid pension asset.  With the dismissal of the 2017 rate case, revisions to the TCJA settlement are required to address the impacts of the TCJA for 2019 until new base rates go into effect in connection with a future electric rate case that PSCo anticipates filing later this summer. A CPUC decision is pending.

SPS — In January 2018, the Public Utility Commission of Texas (PUCT) issued an order requiring utilities to apply deferred accounting for the impacts of the TCJA. In February 2018, SPS filed with the PUCT supplemental testimony, which indicated that the TCJA would reduce revenue requirements by approximately $32 million and recommended increasing its equity ratio to 58 percent to offset the negative impact of the TCJA on its credit metrics and potentially its credit ratings. The impact of the TCJA is expected to be addressed as part of SPS’ pending Texas electric rate case, as discussed below.

In February 2018, SPS filed with the New Mexico Public Regulation Commission (NMPRC) a preliminary quantification of the impacts of the TCJA on its ongoing New Mexico 2017 electric rate case, which indicated that the TCJA would reduce revenue requirements by approximately $11 million and recommended increasing its equity ratio to 58 percent to offset the negative impact of the TCJA on its credit metrics and potentially its credit ratings. The impact of the TCJA is expected to be addressed as part of SPS’ pending New Mexico electric rate case, as discussed below.


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Federal Energy Regulatory Commission (FERC) Formula Rates — The FERC has not yet issued guidance on how or when electric utilities should reflect the impacts of the TCJA in FERC jurisdictional wholesale rates. The FERC issued a Notice of Inquiry (NOI) in March 2018 seeking comments on how to reflect the TCJA impacts in wholesale rates, in particular changes to accumulated deferred income taxes and bonus depreciation. Comments for the NOI are due in May 2018. However, FERC-approved formula rates for wholesale customers are generally adjusted on an annual basis for certain changes in rate base and actual operating expenses, including income taxes. As a result, these revenues would be subject to an automatic reduction for the effect of the TCJA corporate tax rate change through the annual true-up process, absent specific FERC action.

NSP-Minnesota and NSP-Wisconsin were parties to a February 2018 FERC filing by certain transmission owner (TO) members of the Midcontinent Independent System Operator, Inc. (MISO) proposing to commence early reductions to transmission formula rates in 2018 for the corporate tax rate impacts of the TCJA. Also in February 2018, PSCo made a filing with FERC similarly requesting early reductions in its transmission and production formula rates in 2018 for corporate tax rate impacts of the TCJA. In March 2018, the FERC issued orders granting MISO TOs and PSCo’s waiver requests so that 2018 rates will reflect the lower federal corporate tax rate. For SPS, as a portion of the TCJA tax rate change largely offsets a depreciation rate change that was effective Jan. 1, 2018 in its wholesale production rates, SPS has notified FERC that it will continue to charge production rates established in 2017, subject to refund. SPS’ wholesale transmission rates continue to be calculated at the pre-TCJA corporate tax rate, subject to true-up in 2019.

NSP-Minnesota

Pending Regulatory Proceedings — MPUC

GUIC Rider — In February 2018, the MPUC approved a 2017 revenue requirement of approximately $20 million for GUIC investments. New rates went into effect in March 2018. In November 2017, NSP-Minnesota filed the 2018 GUIC rider with the MPUC requesting recovery of approximately $28 million from Minnesota gas utility customers. In March 2018, NSP-Minnesota filed a supplement to the 2018 GUIC rider filing to provide an updated capital forecast and address the impact of the TCJA. The net result decreased NSP-Minnesota’s 2018 GUIC revenue requirement to approximately $24 million. The MPUC is currently considering the 2018 petition.

Renewable Energy Standard (RES) Rider — In 2017, NSP-Minnesota filed the 2017 and 2018 RES rider petition with the MPUC, requesting approval of a 2017 over-recovery of approximately $10 million and a 2018 revenue requirement of approximately $11 million. The petition was based on a requested return on equity (ROE) of 10.0 percent and includes costs associated with the Courtenay wind farm and the 1,550 megawatt (MW) wind portfolio, which are offset by production tax credits (PTCs) and proceeds from renewable energy credit (REC) sales. The increase in revenue requirements in 2018 is due to new wind projects entering the construction phase. In February and March 2018, NSP-Minnesota filed supplements to the 2017 and 2018 RES rider petition to provide updated actual results and address TCJA impacts. NSP-Minnesota’s revised 2017 refund is approximately $13 million, and the revised 2018 revenue requirement is approximately $23 million. The increase in 2018 revenue requirements from the original request is primarily driven by the TCJA impact on PTCs earned on existing wind asset-related costs. A decision from the MPUC is expected later in 2018.

PSCo

Pending Regulatory Proceedings — CPUC

Colorado 2017 Multi-Year Electric Rate Case — In October 2017, PSCo filed a multi-year request with the CPUC seeking to increase electric rates approximately $245 million over four years. The request was based on forecast test years (FTY), a 10.0 percent ROE and an equity ratio of 55.25 percent. Interim rates, subject to refund and interest, were to be effective on June 1, 2018.
Revenue Request (Millions of Dollars)
 
2018
 
2019
 
2020
 
2021
 
Total
Revenue request
 
$
74

 
$
75

 
$
60

 
$
36

 
$
245

Clean Air Clean Jobs Act (CACJA) rider conversion to base rates
 
90

 

 

 

 
90

Transmission Cost Adjustment (TCA) rider conversion to base rates
 
43

 

 

 

 
43

  Total
 
$
207

 
$
75

 
$
60

 
$
36

 
$
378

 
 
 
 
 
 
 
 
 
 
 
Expected year-end rate base (billions of dollars)
 
$
6.8

 
$
7.1

 
$
7.3

 
$
7.4

 
 


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In March 2018, PSCo, CPUC Staff and OCC reached a settlement and filed a motion with the CPUC requesting changes to the procedural schedule and scope of the electric case, which included delaying the implementation of provisional rates from June 2018 to January 2019 and requiring PSCo to file updated test year information for 2019-2021 which included the impacts of TCJA. In April 2018, the CPUC denied the motion on procedural grounds and dismissed the electric rate case. PSCo anticipates filing a new electric rate case in the summer of 2018 with new rates expected to be effective in the first quarter of 2019.

Colorado 2017 Multi-Year Natural Gas Rate Case — In June 2017, PSCo filed a multi-year request with the CPUC seeking to increase retail natural gas rates approximately $139 million over three years. The request, detailed below, is based on FTYs, a 10.0 percent ROE and an equity ratio of 55.25 percent.
Revenue Request (Millions of Dollars)
 
2018
 
2019
 
2020
 
Total
Revenue request
 
$
63

 
$
33

 
$
43

 
$
139

Pipeline System Integrity Adjustment (PSIA) rider conversion to base rates (a)
 

 
94

 

 
94

Total
 
$
63

 
$
127

 
$
43

 
$
233

 
 
 
 
 
 
 
 
 
Expected year-end rate base (billions of dollars) (b)
 
$
1.5

 
$
2.3

 
$
2.4

 


 
(a)  
The roll-in of PSIA rider revenue into base rates will not have an impact on customer bills or revenue as these costs are already being recovered through the rider. The recovery of incremental PSIA related investments in 2019 and 2020 are included in the base rate request.

(b)  
The additional rate base in 2019 predominantly reflects the roll-in of capital associated with the PSIA rider.

In October 2017, the CPUC Staff and the OCC recommended a single 2016 historic test year (HTY) based on an average 13-month rate base, and opposed a multi-year request. In addition, they recommended an equity ratio of 48.73 percent and 51.2 percent, respectively, and the existing PSIA rider expire with the 2018 rates rolled into base rates beginning Jan. 1, 2019. Planned investments in 2019 and 2020 would be recoverable through a future rate case. The Staff and OCC provide for a recommended 2018 rate increase of approximately $30 million and $39 million, respectively.

Provisional rates, subject to refund, of $63 million were implemented on Jan. 1, 2018.

On Jan. 31, 2018, the CPUC ordered deferred accounting for the impacts of TCJA and opened a statewide TCJA proceeding, as discussed below. In February 2018, the ALJ approved a settlement agreement between PSCo and the CPUC, which reduced provisional rates by $20 million to address the impacts of the TCJA. The CPUC is expected to rule on the regulatory treatment of the TCJA and the natural gas rate case later in 2018.

On April 20, 2018, PSCo filed for a PSIA extension through 2020 in the event that the CPUC does not adopt its multi-year plan proposal.

SPS

Pending Regulatory Proceedings — PUCT

Texas 2017 Electric Rate Case — In 2017, SPS filed a $55 million, or 5.8 percent, retail electric, non-fuel base rate increase case in Texas with each of its Texas municipalities and the PUCT. The request was based on a HTY ended June 30, 2017, a requested ROE of 10.25 percent, an electric rate base of approximately $1.9 billion and an equity ratio of 53.97 percent.

The following table summarizes SPS’ rate increase request:
Revenue Request (Millions of Dollars)
 
 
Incremental revenue request
 
$
69

Transmission Cost Recovery Factor (TCRF) rider conversion to base rates (a)
 
(14
)
  Net revenue increase request
 
$
55


(a) 
The roll-in of the TCRF rider revenue into base rates will not have an impact on customer bills or revenue as these costs are already being recovered through the rider. SPS can request another TCRF rider after the conclusion of this rate case to recover transmission investments subsequent to June 30, 2017.


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Key dates in the revised procedural schedule are as follows:

PUCT Staff direct testimony — May 2, 2018;
PUCT Staff and intervenors’ cross-rebuttal testimony — May 14, 2018;
SPS’ rebuttal testimony — May 23, 2018; and
Hearings — June 4 - 14, 2018.

As discussed above, the PUCT has opened a docket on the impact of the TCJA, which may have an impact on this rate case. In February 2018, SPS filed supplemental testimony with the PUCT, which indicated that TCJA would reduce revenue requirements by approximately $32 million and recommended increasing its equity ratio to 58 percent to offset the negative impact of the TCJA on its credit metrics and potentially its credit ratings. The final rates are expected to be effective retroactive to Jan. 23, 2018 through a customer surcharge. A PUCT decision is expected in the fourth quarter of 2018.

Appeal of the Texas 2015 Electric Rate Case Decision — In 2014, SPS had requested an overall retail electric revenue rate increase of $42 million. In 2015, the PUCT approved an overall rate decrease of approximately $4 million, net of rate case expenses. In April 2016, SPS filed an appeal with the Texas State District Court (District Court) challenging the PUCT’s order that had denied SPS’ request for rehearing on certain items in SPS’ Texas 2015 electric rate case related to capital structure, incentive compensation and wholesale load reductions. In 2017, the District Court denied SPS’ appeal, and SPS appealed the District Court’s decision to the Court of Appeals. A decision is pending.

Pending Regulatory Proceeding — NMPRC

New Mexico 2017 Electric Rate Case — In October 2017, SPS filed an electric rate case with the NMPRC seeking an increase in retail electric base rates of approximately $43 million. The request is based on a HTY ended June 30, 2017, a ROE of 10.25 percent, an equity ratio of 53.97 percent and a rate base of approximately $885 million, including rate base additions through Nov. 30, 2017. This rate case also takes into account the decline in sales of 380 MW in 2017 from certain wholesale customers and seeks to adjust the life of SPS’ Tolk power plant (Unit 1 from 2042 to 2032 and Unit 2 from 2045 to 2032).

In February 2018, SPS filed supplemental information, which indicated that the TCJA would reduce revenue requirements by approximately $11 million. In addition, SPS requested an increase in the equity ratio of 58 percent and an adjustment to regional transmission revenue for the impacts of TCJA.

On April 13, 2018, the NMPRC Staff, the New Mexico Attorney General (NMAG), and several other parties filed testimony. The recommended ROE’s ranged from 9.0 percent to of 9.21 percent, and the recommended equity ratios were 51.0 percent to 53.97 percent.


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The following table summarizes certain parties’ recommendations from SPS’ request:
Millions of Dollars
 
 NMPRC Staff Testimony
 
NMAG Testimony
SPS request
 
$
43

 
$
43

Reduction to request for the impact of the TCJA
 
(11
)
 
(11
)
SPS request, including the impact of the TCJA
 
32

 
32

 
 
 
 
 
ROE (9.0 percent and 9.21 percent, respectively)
 
(4
)
 
(6
)
Capital structure (52.0 percent and 53.97 percent, respectively)
 
(7
)
 
(3
)
Accelerated depreciation (Tolk plant)
 
(3
)
 
(3
)
Disallow rate case expenses
 
(2
)
 
(3
)
Regional transmission revenue (adjustment for the impact of the TCJA)
 


(3
)
Post test year plant (estimated numbers were updated to actual)
 
(1
)
 
(2
)
Other, net
 
(4
)
 
(5
)
Recommended rate increase
 
$
11

 
$
7


Key dates in the procedural schedule are as follows:

SPS’ rebuttal testimony — May 2, 2018; and
Hearings — May 15 - 25, 2018.

SPS anticipates a decision and implementation of final rates in the second half of 2018.

Appeal of the New Mexico 2016 Electric Rate Case Dismissal — In November 2016, SPS filed an electric rate case with the NMPRC seeking an increase in base rates of approximately $41 million, representing a total revenue increase of approximately 10.9 percent. The rate filing was based on a requested ROE of 10.1 percent, an equity ratio of 53.97 percent, an electric rate base of approximately $832 million and a future test year ending June 30, 2018. In 2017, the NMPRC dismissed SPS’ rate case. SPS filed a notice of appeal in the New Mexico Supreme Court. A decision is not expected until the second half of 2019.

Pending Regulatory Proceeding — FERC

MISO ROE Complaints — In November 2013, a group of customers filed a complaint at the FERC against MISO TOs, including NSP-Minnesota and NSP-Wisconsin. The complaint argued for a reduction in the ROE in transmission formula rates in the MISO region from 12.38 percent to 9.15 percent, and the removal of ROE adders (including those for Regional Transmission Organization (RTO) membership), effective Nov. 12, 2013.


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In September 2016, the FERC approved an ALJ recommendation that MISO TOs be granted a 10.32 percent base ROE using the methodology adopted by FERC in June 2014 (Opinion 531). This ROE would be applicable for the 15-month refund period from Nov. 12, 2013 to Feb. 11, 2015, and prospectively from the date of the FERC order. The total prospective ROE would be 10.82 percent, including a 50 basis point adder for RTO membership. Various parties requested rehearing of the September 2016 order. The requests are pending FERC action.

In February 2015, a second complaint seeking to reduce the MISO ROE from 12.38 percent to 8.67 percent prior to any RTO adder was filed, resulting in a second period of potential refunds from Feb. 12, 2015 to May 11, 2016. In June 2016, an ALJ recommended a base ROE of 9.7 percent, applying the FERC Opinion 531 methodology. Various parties filed exceptions to the ALJ recommendation, and FERC action is pending. In April 2017, the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit) vacated and remanded Opinion 531. It is unclear how the D.C. Circuit’s opinion to vacate and remand Opinion 531 will affect the September 2016 FERC order or the timing and outcome of the second ROE complaint.

NSP-Minnesota has recognized a current refund liability consistent with the best estimate of the final ROE for the Feb. 12, 2015 to May 11, 2016 complaint period.

Southwest Power Pool, Inc. (SPP) Open Access Transmission Tariff (OATT) Upgrade Costs — Under the SPP OATT, costs of participant-funded, or “sponsored,” transmission upgrades may be recovered from other SPP customers whose transmission service depends on capacity enabled by the upgrade.  The SPP OATT has allowed SPP to charge for these upgrades since 2008, but SPP had not been charging its customers for these upgrades.  In 2016, the FERC granted SPP’s request to recover the charges not billed since 2008.  SPP subsequently billed SPS approximately $13 million for these charges. SPP is also billing SPS ongoing charges of approximately $0.5 million per month. SPS is currently seeking recovery of these SPP charges in its pending Texas and New Mexico base rate cases.

In October 2017, SPS filed a complaint against SPP regarding the amounts billed asserting that SPP has assessed upgrade charges to SPS in violation of the SPP OATT. In March 2018, the FERC denied SPS’ complaint. SPS sought rehearing in April 2018, which is pending FERC action.  If SPS’ complaint results in additional charges or refunds, SPS will seek to recover or refund the differential in future rate proceedings.

6.
Commitments and Contingencies

Except to the extent noted below and in Note 5 above, the circumstances set forth in Notes 12, 13 and 14 to the consolidated financial statements included in Xcel Energy Inc.’s Annual Report on Form 10-K for the year ended Dec. 31, 2017, appropriately represent, in all material respects, the current status of commitments and contingent liabilities and are incorporated herein by reference. The following include commitments, contingencies and unresolved contingencies that are material to Xcel Energy’s financial position.

PPAs

Under certain PPAs, NSP-Minnesota, PSCo and SPS purchase power from independent power producing entities for which the utility subsidiaries are required to reimburse natural gas or biomass 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 associated independent power producing entity.

The Xcel Energy utility subsidiaries had approximately 3,537 MW of capacity under long-term PPAs as of March 31, 2018 and Dec. 31, 2017, with entities that have been determined to be variable interest entities. Xcel Energy has 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. These agreements have expiration dates through 2041.

Guarantees and Bond Indemnifications

Xcel Energy Inc. and its subsidiaries provide guarantees and bond indemnities under specified agreements or transactions. The guarantees and bond indemnities issued by Xcel Energy Inc. guarantee payment or performance by its subsidiaries. As a result, Xcel Energy Inc.’s exposure under the guarantees and bond indemnities is based upon the net liability of the relevant subsidiary 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 guarantee or indemnity amount. As of March 31, 2018 and Dec. 31, 2017, Xcel Energy Inc. and its subsidiaries had no assets held as collateral related to their guarantees, bond indemnities and indemnification agreements.

The following table presents guarantees and bond indemnities issued and outstanding for Xcel Energy:
(Millions of Dollars)
 
March 31, 2018
 
Dec. 31, 2017
Guarantees issued and outstanding
 
$
18.6

 
$
18.8

Current exposure under these guarantees
 

 

Bonds with indemnity protection
 
51.7

 
53.1


Other Indemnification Agreements

Xcel Energy Inc. and its subsidiaries provide indemnifications through contracts entered into in the normal course of business. 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. The maximum future payments under these indemnifications cannot be reasonably estimated as the dollar amounts are often not explicitly stated.

Environmental Contingencies

Ashland Manufactured Gas Plant (MGP) Site — NSP-Wisconsin was named a potentially responsible party (PRP) for contamination at a site in Ashland, Wis. The Site includes NSP-Wisconsin property, previously operated as a MGP facility (the Upper Bluff), and two other properties: an adjacent city lakeshore park area (Kreher Park); and an area of Lake Superior’s Chequamegon Bay adjoining the park.

In January 2017, NSP-Wisconsin agreed to remediate the Phase II Project Area (the Sediments), under a settlement agreement with the Environmental Protection Agency. The settlement agreements were approved by the U.S. District Court for the Western District of Wisconsin. NSP-Wisconsin initiated a full scale wet dredge remedy of the Sediments in 2017. Under the current plan, NSP-Wisconsin anticipates completion of restoration activities of the Sediments in 2018 with finalization of Phase I Project Area (which includes the Upper Bluff and Kreher Park areas of the Site) construction and restoration activities in early 2019 although April weather may challenge that schedule. Groundwater treatment activities at the Site will continue.

The current cost estimate for the remediation of the entire site (both Phase I Project Area and the Sediments) is approximately $172 million, of which approximately $139 million has been spent. As of March 31, 2018 and Dec. 31, 2017, NSP-Wisconsin had recorded a total liability of $33 million and $30 million, respectively, for the entire site.


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NSP-Wisconsin has deferred the unrecovered portion of the estimated Site remediation costs as a regulatory asset. The PSCW has authorized NSP-Wisconsin rate recovery for all remediation costs incurred at the Site. In 2012, the PSCW agreed to allow NSP-Wisconsin to pre-collect certain costs, to amortize costs over a ten-year period and to apply a three percent carrying cost to the unamortized regulatory asset. In December 2017, the PSCW approved an NSP-Wisconsin natural gas rate case, which included recovery of additional expenses associated with remediating the Site. The annual recovery of MGP clean-up costs increased from $12 million in 2017 to $18 million in 2018.

Fargo, N.D. MGP Site — In May 2015, underground pipes, tars and impacted soils were discovered in a right-of-way in Fargo, N.D. that appeared to be associated with a former MGP operated by NSP-Minnesota or prior companies. NSP-Minnesota removed impacted soils and other materials and commenced an investigation of the historic MGP and adjacent properties (the Fargo MGP Site). The North Dakota Department of Health approved NSP-Minnesota’s proposed cleanup plan in January 2017, which involves targeted source removal of impacted soils and historic MGP infrastructure. It is anticipated that remediation activities will be performed in 2018. NSP-Minnesota has also initiated insurance recovery litigation in North Dakota. The U.S. District Court for the District of North Dakota agreed to the parties’ request for a stay of the litigation until May 31, 2018.

NSP-Minnesota had recorded an estimated liability of $15 million as of March 31, 2018 and $16 million as of Dec. 31, 2017, for the Fargo MGP Site. The current cost estimate for the remediation of the site is approximately $22 million, of which approximately $7 million has been spent. NSP-Minnesota has deferred Fargo MGP Site costs allocable to the North Dakota jurisdiction, or approximately 88 percent of all remediation costs, as approved by the North Dakota Public Service Commission (NDPSC). In December 2017, NSP-Minnesota filed a request with the MPUC to defer post-2017 MGP remediation expenditures allocable to the Minnesota jurisdiction, including the Fargo MGP site. In March 2018, the DOC recommended that the MPUC deny NSP-Minnesota’s deferral request. A MPUC decision is expected mid-2018.

Other MGP, Landfill or Disposal Sites — Xcel Energy is currently involved in investigating and/or remediating several MGP, landfill or other disposal sites. Xcel Energy has identified eleven sites across its service territories in addition to the sites in Ashland and Fargo, where contamination is present and where investigation and/or remediation activities are currently underway. Other parties may have responsibility for some portion of the investigation and/or remediation activities. Xcel Energy anticipates that these investigation or remediation activities will continue through at least 2018. Xcel Energy had accrued $4 million as of March 31, 2018 and Dec. 31, 2017 for all of these sites. There may be insurance recovery and/or recovery from other PRPs that will offset any costs incurred. Xcel Energy anticipates that any amounts spent will be fully recovered from customers.

Legal Contingencies

Xcel Energy is involved in various litigation matters that are being defended and handled 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 such losses that are 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 herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Xcel Energy’s financial statements. Unless otherwise required by GAAP, legal fees are expensed as incurred.

Employment, Tort and Commercial Litigation

Gas Trading Litigation — e prime, inc. (e prime) is a wholly owned subsidiary of Xcel Energy. 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.  Thirteen lawsuits were commenced against e prime and Xcel Energy (and NSP-Wisconsin, in two instances) between 2003 and 2009 alleging fraud and anticompetitive activities in conspiring to restrain the trade of natural gas and manipulate natural gas prices.

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e prime, Xcel Energy Inc. and its other affiliates were sued along with several other gas marketing companies. These cases were all consolidated in the U.S. District Court in Nevada. Six of the cases remain active, which includes a multi-district litigation (MDL) matter consisting of a Colorado class (Breckenridge), a Wisconsin class (Arandell Corp.), a Missouri class, a Kansas class, and two other cases identified as “Sinclair Oil” and “Farmland.” In March 2017, summary judgment was granted by the MDL judge in favor of Xcel Energy and e prime in the Sinclair Oil and Farmland cases. In November 2017, the U.S District Court in Nevada granted summary judgment against two plaintiffs in the Arandell Corp. case in favor of Xcel Energy and NSP-Wisconsin, leaving only three individual plaintiffs remaining in the litigation. In addition, the plaintiffs’ motions for class certification and remand back to originating courts in these cases were denied in March 2017. Plaintiffs have appealed the summary judgment motions granted in the Farmland and Sinclair Oil cases and the denial of class certification and remand to the U.S. Court of Appeals for the Ninth Circuit (Ninth Circuit). Oral arguments were heard before the Ninth Circuit in February 2018. In March 2018, the Ninth Circuit reversed and remanded the summary judgment in the Farmland case. The Farmland defendants subsequently filed a request for further review by the Ninth Circuit. In light of the decision in the Farmland case, the Sinclair plaintiffs have requested the Ninth Circuit to reverse the grant of summary judgment without hearing. Final rulings on all pending motions and appeals are expected by the end of 2018. Xcel Energy, NSP-Wisconsin and e prime have concluded that a loss is remote.

Line Extension Disputes — In December 2015, Development Recovery Company (DRC) filed a lawsuit in the Denver District Court, stating PSCo failed to award proper allowances and refunds for line extensions to new developments pursuant to the terms of electric and gas service agreements entered into by PSCo and various developers. The dispute involved claims by over fifty developers. In February 2018, the Colorado Supreme Court denied DRC’s petition to appeal the Denver District Court’s dismissal of the lawsuit, effectively terminating this litigation. However, in January 2018, DRC filed a new lawsuit in Boulder County District Court, asserting a single claim that PSCo was required to file its line extension agreements with the CPUC but failed to do so. This claim is substantially similar to the arguments previously raised by DRC. In February 2018, PSCo filed a motion to dismiss. Dates for this proceeding have not been scheduled.

PSCo has concluded that a loss is remote with respect to this matter as the service agreements were developed to implement CPUC approved tariffs and PSCo has complied with the tariff provisions. Also, if a loss were sustained, PSCo believes it would be allowed to recover these costs through traditional regulatory mechanisms. The amount or range in dispute is presently unknown and no accrual has been recorded for this matter.

7.
Borrowings and Other Financing Instruments

Short-Term Borrowings

Money Pool  Xcel Energy Inc. and its utility subsidiaries have established a money pool arrangement that allows for short-term investments in and borrowings between the utility subsidiaries. NSP-Wisconsin does not participate in the money pool. 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.

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  
 March 31, 2018
 
Year Ended  
 Dec. 31, 2017
Borrowing limit
 
$
3,250

 
$
3,250

Amount outstanding at period end
 
1,025

 
814

Average amount outstanding
 
1,000

 
644

Maximum amount outstanding
 
1,197

 
1,247

Weighted average interest rate, computed on a daily basis
 
1.93
%
 
1.35
%
Weighted average interest rate at period end
 
2.34

 
1.90



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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 March 31, 2018 and Dec. 31, 2017, there were $31 million and $30 million, respectively, 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.

Credit Facilities — In order to use their 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 March 31, 2018, Xcel Energy Inc. and its utility subsidiaries had the following committed credit facilities available:
(Millions of Dollars)
 
Credit Facility (a)
 
Drawn (b)
 
Available
Xcel Energy Inc.
 
$
1,500

 
$
898

 
$
602

PSCo
 
700

 
99

 
601

NSP-Minnesota
 
500

 
25

 
475

SPS
 
400

 
12

 
388

NSP-Wisconsin
 
150

 
22

 
128

Total
 
$
3,250

 
$
1,056

 
$
2,194

(a) 
These credit facilities expire in June 2021, with the exception of Xcel Energy Inc.’s $500 million 364-day term loan agreement entered into in December 2017.
(b) 
Includes outstanding commercial paper, term loan borrowings and letters of credit.

All credit facility bank borrowings, outstanding letters of credit, term loan borrowings 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 March 31, 2018 and Dec. 31, 2017.

8.
Fair Value of Financial Assets and Liabilities

Fair Value Measurements

The accounting guidance for fair value measurements and disclosures provides a single definition of fair value and requires certain 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. The three levels in the hierarchy are as follows:

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.

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 the following:

Cash equivalents The fair values of cash equivalents are generally based on cost plus accrued interest; money market funds are measured using quoted net asset value (NAV).


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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, which take into consideration the value of underlying fund investments, as well as the other accrued assets and liabilities of a fund, in order to determine a per-share market value. The investments in commingled funds may be redeemed for NAV with proper notice. Proper notice varies by fund and can range from daily with one or two days notice to annually with 90 days notice. Private equity 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 investments may be redeemed with proper notice, which is typically quarterly with 45-90 days notice; however, withdrawals from real estate investments may be delayed or discounted as a result of fund illiquidity.

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 The fair values of interest rate derivatives are based on broker quotes that utilize current market interest rate forecasts.

Commodity derivatives The 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 extend to periods beyond those readily observable on active exchanges or quoted by brokers, the significance of the use of less observable forecasts of long-term 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 financial transmission rights (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. The valuation process for FTRs utilizes the cleared prices for each FTR for the most recent auction.

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 transparency in the auction process, 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, the limited transparency associated with the valuation of FTRs are insignificant to the consolidated financial statements of Xcel Energy.

Non-Derivative Instruments Fair Value Measurements

Nuclear Decommissioning Fund

The Nuclear Regulatory Commission (NRC) requires NSP-Minnesota to maintain a portfolio of investments to fund the costs of decommissioning its nuclear generating plants. Together with all accumulated earnings or losses, the assets of the nuclear decommissioning fund are legally restricted for the decommissioning the Monticello and Prairie Island (PI) nuclear generating plants. The fund contains cash equivalents, debt securities, equity securities and other investments. NSP-Minnesota plans to reinvest matured securities until decommissioning begins. 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 of its nuclear generating plants over the lives of the plants, assuming rate recovery of all costs. Given the purpose and legal restrictions on the use of nuclear decommissioning fund assets, 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, including any impairments, are deferred as a component of the regulatory asset for nuclear decommissioning.


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Unrealized gains for the nuclear decommissioning fund were $543 million and $560 million as of March 31, 2018 and Dec. 31, 2017, respectively, and unrealized losses and amounts recorded as other-than-temporary impairments were $18 million and $7 million as of March 31, 2018 and Dec. 31, 2017, respectively.

The following tables present the cost and fair value of Xcel Energy’s non-derivative instruments with recurring fair value measurements in the nuclear decommissioning fund as of March 31, 2018 and Dec. 31, 2017:
 
 
March 31, 2018
 
 
 
 
Fair Value
(Millions of Dollars)
 
Cost
 
Level 1
 
Level 2
 
Level 3
 
Investments Measured at NAV (b)
 
Total
Nuclear decommissioning fund (a)
 
 
 
 
 
 
 
 
 
 
 
 
Cash equivalents
 
$
41

 
$
41

 
$

 
$

 
$

 
$
41

Commingled funds:
 
 
 
 
 
 
 
 
 
 
 
 
Non U.S. equities
 
270

 
226

 

 

 
90

 
316

Emerging market debt funds
 
157

 

 

 

 
164

 
164

Private equity investments
 
142

 

 

 

 
198

 
198

Real estate
 
118

 

 

 

 
186

 
186

Other commingled funds
 
4

 
1

 

 

 
3

 
4

Debt securities:
 
 
 
 
 
 
 
 
 
 
 
 
Government securities
 
78

 

 
77

 

 

 
77

U.S. corporate bonds
 
325

 

 
321

 

 

 
321

Non U.S. corporate bonds
 
55

 

 
53

 

 

 
53

Equity securities:
 
 
 
 
 
 
 
 
 
 
 
 
U.S. equities
 
278

 
557

 

 

 

 
557

Non U.S. equities
 
153

 
229

 

 

 

 
229

Total
 
$
1,621

 
$
1,054

 
$
451

 
$

 
$
641

 
$
2,146

(a) 
Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $141 million of equity investments in unconsolidated subsidiaries and $117 million of rabbi trust assets and miscellaneous investments.
(b) 
Due to limited availability of published pricing and a lack of immediate redeemability, certain fund investments measured at NAV are not required to be categorized within the fair value hierarchy.
 
 
Dec. 31, 2017
 
 
 
 
Fair Value
(Millions of Dollars)
 
Cost
 
Level 1
 
Level 2
 
Level 3
 
Investments Measured at NAV (b)
 
Total
Nuclear decommissioning fund (a)
 
 
 
 
 
 
 
 
 
 
 
 
Cash equivalents
 
$
29

 
$
29

 
$

 
$

 
$

 
$
29

Commingled funds:
 
 
 
 
 
 
 
 
 
 
 
 
Non U.S. equities
 
264

 
217

 

 

 
90

 
307

Emerging market debt funds
 
156

 

 

 

 
166

 
166

Private equity investments
 
141

 

 

 

 
198

 
198

Real estate
 
131

 

 

 

 
202

 
202

Other commingled funds
 
9

 
6

 

 

 
3

 
9

Debt securities:
 
 
 
 
 
 
 
 
 
 
 
 
Government securities
 
68

 

 
69

 

 

 
69

U.S. corporate bonds
 
320

 

 
322

 

 

 
322

Non U.S. corporate bonds
 
50

 

 
50

 

 

 
50

Equity securities:
 
 
 
 
 
 
 
 
 
 
 
 
U.S. equities
 
271

 
557

 

 

 

 
557

Non U.S. equities
 
152

 
234

 

 

 

 
234

Total
 
$
1,591

 
$
1,043

 
$
441

 
$

 
$
659

 
$
2,143

(a) 
Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $140 million of equity investments in unconsolidated subsidiaries and $114 million of rabbi trust assets and miscellaneous investments.
(b) 
Due to limited availability of published pricing and a lack of immediate redeemability, certain fund investments measured at NAV are not required to be categorized within the fair value hierarchy.
For the three months ended March 31, 2018 and 2017 there were no Level 3 nuclear decommissioning fund investments and no transfers of amounts between levels.


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The following table summarizes the final contractual maturity dates of the debt securities in the nuclear decommissioning fund, by asset class, as of March 31, 2018:
 
 
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
Government securities
 
$

 
$
9

 
$
2

 
$
66

 
$
77

U.S. corporate bonds
 
3

 
87

 
174

 
57

 
321

Non U.S. corporate bonds
 

 
16

 
33

 
4

 
53

Debt securities
 
$
3

 
$
112

 
$
209

 
$
127

 
$
451


Rabbi Trusts

In 2016, Xcel Energy established rabbi trusts to provide partial funding for future distributions of its supplemental executive retirement plan and deferred compensation plan. The following tables present the cost and fair value of the assets held in rabbi trusts as of March 31, 2018 and Dec. 31, 2017:
 
 
March 31, 2018
 
 
 
 
Fair Value
(Millions of Dollars)
 
Cost
 
Level 1
 
Level 2
 
Level 3
 
Total
Rabbi Trusts (a)
 
 
 
 
 
 
 
 
 
 
Cash equivalents
 
$
11

 
$
11

 
$

 
$

 
$
11

Mutual funds
 
48

 
50

 

 

 
50

Total
 
$
59

 
$
61

 
$

 
$

 
$
61


 
 
Dec. 31, 2017
 
 
 
 
Fair Value
(Millions of Dollars)
 
Cost
 
Level 1
 
Level 2
 
Level 3
 
Total
Rabbi Trusts (a)
 
 
 
 
 
 
 
 
 
 
Cash equivalents
 
$
12

 
$
12

 
$

 
$

 
$
12

Mutual funds
 
47

 
50

 

 

 
50

Total
 
$
59

 
$
62

 
$

 
$

 
$
62

(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 interest payments on certain floating rate debt obligations or 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.

As of March 31, 2018, accumulated other comprehensive losses related to interest rate derivatives included $3 million of net losses expected to be reclassified into earnings during the next 12 months as the related hedged interest rate transactions impact earnings, including forecasted amounts for unsettled hedges, as applicable.

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’s risk management policy allows management to conduct these activities within guidelines and limitations as approved by its risk management committee, which is made up of management personnel not directly involved in the activities governed by this policy.


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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.

As of March 31, 2018, Xcel Energy had various vehicle fuel contracts designated as cash flow hedges extending through December 2018. Xcel Energy enters 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 in other comprehensive income or deferred as a regulatory asset or liability. The classification as a regulatory asset or liability is based on commission approved regulatory recovery mechanisms. Xcel Energy recorded immaterial amounts to income related to the ineffectiveness of cash flow hedges for the three months ended March 31, 2018 and 2017.

As of March 31, 2018, net gains related to commodity derivative cash flow hedges recorded as a component of accumulated other comprehensive losses included immaterial net gains expected to be reclassified into earnings during the next 12 months as the hedged transactions occur.

Additionally, 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.

The following table details the gross notional amounts of commodity forwards, options and FTRs as of March 31, 2018 and Dec. 31, 2017:
(Amounts in Millions) (a)(b)
 
March 31, 2018
 
Dec. 31, 2017
Megawatt hours of electricity
 
60

 
68

Million British thermal units of natural gas
 
30

 
37

(a) 
Amounts are not reflective of net positions in the underlying commodities.
(b) 
Notional amounts for options are included on a gross basis, but are weighted for the probability of exercise.

The following tables detail the impact of derivative activity during the three months ended March 31, 2018 and 2017 on accumulated other comprehensive loss, regulatory assets and liabilities, and income:
 
 
Three Months Ended March 31, 2018
 
 
 
Pre-Tax Fair Value Gains (Losses) Recognized During the Period in:
 
Pre-Tax 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
 
Accumulated Other
Comprehensive Loss
 
Regulatory
Assets and (Liabilities)
 
 
Other derivative instruments
 
 
 
 
 
 
 
 
 
 
 
Commodity trading
 
$

 
$

 
$

 
$

 
$
3

(b) 
Electric commodity
 

 
(4
)
 

 
3

(c) 

 
Natural gas commodity
 

 
1

 

 
2

(d) 
(2
)
(d) 
Total
 
$

 
$
(3
)
 
$

 
$
5

 
$
1

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 

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Three Months Ended March 31, 2017
 
 
 
Pre-Tax Fair Value Gains (Losses) Recognized During the Period in:
 
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
 
Accumulated Other
Comprehensive Loss
 
Regulatory
Assets and (Liabilities)
 
 
Derivatives designated as cash flow hedges
 
 
 
 
 
 
 
 
 
 
 
Interest rate
 
$

 
$

 
$
1

(a) 
$

 
$

 
Total
 
$

 
$

 
$
1

 
$

 
$

 
Other derivative instruments
 
 
 
 
 
 
 
 
 
 
 
Commodity trading
 
$

 
$

 
$

 
$

 
$
1

(b) 
Electric commodity
 

 
1

 

 
(4
)
(c) 

 
Natural gas commodity
 

 
(6
)
 

 
1

(d) 
(4
)
(d) 
Total
 
$

 
$
(5
)
 
$

 
$
(3
)
 
$
(3
)
 

(a) 
Amounts are recorded to interest charges.
(b) 
Amounts are 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) 
Amounts are 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) 
Certain derivatives are utilized to mitigate natural gas price risk for electric generation and are recorded to electric fuel and purchased power, subject to cost-recovery mechanisms and reclassified to a regulatory asset, as appropriate. Amounts for the three months ended March 31, 2018 and 2017 included $1 million of settlement losses and $0.9 million of settlement gains, respectively. The remaining derivative settlement gains and losses for the three months ended March 31, 2018 and 2017 relate to natural gas operations and are recorded to cost of natural gas sold and transported. These gains and losses are subject to cost-recovery and reclassified out of income to a regulatory asset or liability, as appropriate.

Xcel Energy had no derivative instruments designated as fair value hedges during the three months ended March 31, 2018 and 2017. Therefore, no gains or losses from fair value hedges or related hedged transactions were recognized for these periods.

Consideration of Credit Risk and Concentrations — Xcel Energy continuously monitors the creditworthiness of the 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. Given this assessment, as well as an assessment of the impact of Xcel Energy’s own credit risk when determining the fair value of derivative liabilities, the impact of credit risk was immaterial to the fair value of unsettled commodity derivatives presented in the consolidated balance sheets.

Xcel Energy Inc. and its subsidiaries employ additional credit risk control mechanisms when appropriate, such as letters of credit, parental guarantees, standardized master netting agreements and termination provisions that allow for offsetting of positive and negative exposures. Credit exposure is monitored and, when necessary, the activity with a specific counterparty is limited until credit enhancement is provided.

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 March 31, 2018, five of Xcel Energy’s 10 most significant counterparties for these activities, comprising $70 million or 35 percent of this credit exposure, had investment grade credit ratings from Standard & Poor’s, Moody’s or Fitch Ratings. Four of the 10 most significant counterparties, comprising $27 million or 14 percent 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. The one remaining significant counterparty, comprising of $7 million or 4 percent of this credit exposure, had credit quality less than investment grade based on ratings from external analysis. Nine of these significant counterparties are municipal or cooperative electric entities or other utilities.

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 balance sheet, 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 that could result in the settlement of such contracts if there was a failure under other financing arrangements related to payment terms or other covenants. As of March 31, 2018 and Dec. 31, 2017, there were no derivative instruments in a material liability position with such underlying contract provisions.


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Certain derivative instruments are also subject to contract provisions that contain adequate assurance clauses. These 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 March 31, 2018 and Dec. 31, 2017.

Recurring Fair Value Measurements — The following table presents for each of the fair value hierarchy levels, Xcel Energy’s derivative assets and liabilities measured at fair value on a recurring basis as of March 31, 2018:
 
 
March 31, 2018
 
 
Fair Value
 
Fair Value Total
 
Counterparty Netting (b)
 
Total
(Millions of Dollars)
 
Level 1
 
Level 2
 
Level 3
 
 
 
Current derivative assets
 
 
 
 
 
 
 
 
 
 
 
 
Other derivative instruments:
 
 
 
 
 
 
 
 
 
 
 
 
Commodity trading
 
$
1

 
$
22

 
$

 
$
23

 
$
(12
)
 
$
11

Electric commodity
 

 

 
13

 
13

 
(2
)
 
11

Total current derivative assets
 
$
1

 
$
22

 
$
13

 
$
36

 
$
(14
)
 
22

PPAs (a)
 
 
 
 
 
 
 
 
 
 
 
6

Current derivative instruments
 
 
 
 
 
 
 
 
 
 
 
$
28

Noncurrent derivative assets
 
 
 
 
 
 
 
 
 
 
 
 
Other derivative instruments:
 
 
 
 
 
 
 
 
 
 
 
 
Commodity trading
 
$
1

 
$
37

 
$
8

 
$
46

 
$
(15
)
 
$
31

Total noncurrent derivative assets
 
$
1

 
$
37

 
$
8

 
$
46

 
$
(15
)