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Section 1: 10-Q (10-Q)

Document

 
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 June 30, 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 July 23, 2018
Common Stock, $2.50 par value
 
509,087,107 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).

2

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
 
2018
 
2017
 
2018
 
2017
Operating revenues
 
 
 
 
 
 
 
Electric
$
2,348

 
$
2,338

 
$
4,617

 
$
4,637

Natural gas
292

 
290

 
954

 
915

Other
18

 
17

 
38

 
39

Total operating revenues
2,658

 
2,645

 
5,609

 
5,591

 
 
 
 
 
 
 
 
Operating expenses
 
 
 
 
 
 
 
Electric fuel and purchased power
935

 
919

 
1,867

 
1,844

Cost of natural gas sold and transported
104

 
114

 
479

 
479

Cost of sales — other
8

 
8

 
17

 
17

Operating and maintenance expenses
578

 
572

 
1,135

 
1,152

Conservation and demand side management expenses
69

 
65

 
139

 
132

Depreciation and amortization
377

 
366

 
760

 
731

Taxes (other than income taxes)
137

 
135

 
282

 
277

Total operating expenses
2,208

 
2,179

 
4,679

 
4,632

 
 
 
 
 
 
 
 
Operating income
450

 
466

 
930

 
959

 
 
 
 
 
 
 
 
Other expense, net
(2
)
 
(4
)
 
(1
)
 
(4
)
Equity earnings of unconsolidated subsidiaries
9

 
7

 
16

 
15

Allowance for funds used during construction — equity
26

 
16

 
49

 
31

 
 
 
 
 
 
 
 
Interest charges and financing costs
 
 
 
 
 
 
 
Interest charges — includes other financing costs of $6, $6, $12 and $12, respectively
175

 
164

 
346

 
330

Allowance for funds used during construction — debt
(11
)
 
(8
)
 
(22
)
 
(15
)
Total interest charges and financing costs
164

 
156

 
324

 
315

 
 
 
 
 
 
 
 
Income before income taxes
319

 
329

 
670

 
686

Income taxes
54

 
102

 
114

 
219

Net income
$
265

 
$
227

 
$
556

 
$
467

 
 
 
 
 
 
 
 
Weighted average common shares outstanding:
 
 
 
 
 
 
 
Basic
510

 
509

 
509

 
508

Diluted
510

 
509

 
510

 
509

 
 
 
 
 
 
 
 
Earnings per average common share:
 
 
 
 
 
 
 
Basic
$
0.52

 
$
0.45

 
$
1.09

 
$
0.92

Diluted
0.52

 
0.45

 
1.09

 
0.92

 
 
 
 
 
 
 
 
Cash dividends declared per common share
$
0.38

 
$
0.36

 
$
0.76

 
$
0.72

 
 
 
 
 
 
 
 
See Notes to Consolidated Financial Statements


3

Table of Contents


XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (UNAUDITED)
(amounts in millions)

 
Three Months Ended June 30
 
Six Months Ended June 30
 
2018
 
2017
 
2018
 
2017
Net income
$
265

 
$
227

 
$
556

 
$
467

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

 
1

 
2

 
2

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

 
1

 
1

 
1

 
 
 
 
 
 
 
 
Other comprehensive income
2

 
2

 
3

 
3

Comprehensive income
$
267

 
$
229

 
$
559

 
$
470

 
 
 
 
 
 
 
 
See Notes to Consolidated Financial Statements




4

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XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
(amounts in millions)
 
Six Months Ended June 30
 
2018
 
2017
Operating activities
 
 
 
Net income
$
556

 
$
467

Adjustments to reconcile net income to cash provided by operating activities:
 
 
 
Depreciation and amortization
769

 
739

Nuclear fuel amortization
62

 
57

Deferred income taxes
110

 
309

Allowance for equity funds used during construction
(49
)
 
(31
)
Equity earnings of unconsolidated subsidiaries
(16
)
 
(15
)
Dividends from unconsolidated subsidiaries
18

 
24

Share-based compensation expense
10

 
32

Other, net
(6
)
 
(4
)
Changes in operating assets and liabilities:
 
 
 
Accounts receivable
(11
)
 
17

Accrued unbilled revenues
115

 
121

Inventories
101

 
65

Other current assets
39

 
(84
)
Accounts payable
(1
)
 
(52
)
Net regulatory assets and liabilities
143

 
1

Other current liabilities
(247
)
 
(190
)
Pension and other employee benefit obligations
(142
)
 
(140
)
Change in other noncurrent assets
10

 
(7
)
Change in other noncurrent liabilities
(24
)
 
(17
)
Net cash provided by operating activities
1,437

 
1,292

 
 
 
 
Investing activities
 
 
 
Utility capital/construction expenditures
(1,903
)
 
(1,474
)
Allowance for equity funds used during construction
49

 
31

Purchases of investment securities
(367
)
 
(368
)
Proceeds from the sale of investment securities
357

 
350

Other, net
(1
)
 
(13
)
Net cash used in investing activities
(1,865
)
 
(1,474
)
 
 
 
 
Financing activities
 
 
 
(Repayments of) proceeds from short-term borrowings, net
(132
)
 
392

Proceeds from issuances of long-term debt
1,186

 
394

Repayments of long-term debt, including reacquisition premiums
(1
)
 
(250
)
Dividends paid
(359
)
 
(355
)
Other, net
(17
)
 
(22
)
Net cash provided by financing activities
677

 
159

 
 
 
 
Net change in cash and cash equivalents
249

 
(23
)
Cash and cash equivalents at beginning of period
83

 
84

Cash and cash equivalents at end of period
$
332

 
$
61

 
 
 
 
Supplemental disclosure of cash flow information:
 
 
 
Cash paid for interest (net of amounts capitalized)
$
(313
)
 
$
(301
)
Cash paid for income taxes, net
(3
)
 
(4
)
 
 
 
 
Supplemental disclosure of non-cash investing and financing transactions:
 
 
 
Property, plant and equipment additions in accounts payable
$
262

 
$
233

Issuance of common stock for equity awards
35

 
19

 
 
 
 
See Notes to Consolidated Financial Statements

5

Table of Contents


XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (UNAUDITED)
(amounts in millions, except share and per share data)

 
June 30, 2018
 
Dec. 31, 2017
Assets
 
 
 
Current assets
 
 
 
Cash and cash equivalents
$
332

 
$
83

Accounts receivable, net
808

 
797

Accrued unbilled revenues
648

 
764

Inventories
511

 
610

Regulatory assets
440

 
424

Derivative instruments
75

 
44

Prepaid taxes
78

 
68

Prepayments and other
164

 
183

Total current assets
3,056

 
2,973

 
 
 
 
Property, plant and equipment, net
35,289

 
34,329

 
 
 
 
Other assets
 
 
 
Nuclear decommissioning fund and other investments
2,398

 
2,397

Regulatory assets
3,177

 
3,005

Derivative instruments
47

 
48

Other
273

 
278

Total other assets
5,895

 
5,728

Total assets
$
44,240

 
$
43,030

 
 
 
 
Liabilities and Equity
 
 
 
Current liabilities
 
 
 
Current portion of long-term debt
$
856

 
$
457

Short-term debt
682

 
814

Accounts payable
1,092

 
1,243

Regulatory liabilities
395

 
239

Taxes accrued
316

 
448

Accrued interest
176

 
174

Dividends payable
193

 
183

Derivative instruments
27

 
29

Other
441

 
501

Total current liabilities
4,178

 
4,088

 
 
 
 
Deferred credits and other liabilities
 
 
 
Deferred income taxes
3,973

 
3,845

Deferred investment tax credits
56

 
58

Regulatory liabilities
5,113

 
5,083

Asset retirement obligations
2,534

 
2,475

Derivative instruments
113

 
126

Customer advances
202

 
193

Pension and employee benefit obligations
884

 
1,042

Other
226

 
145

Total deferred credits and other liabilities
13,101

 
12,967

 
 
 
 
Commitments and contingencies


 


Capitalization
 
 
 
Long-term debt
15,311

 
14,520

Common stock — 1,000,000,000 shares authorized of $2.50 par value; 508,898,420 and
507,762,881 shares outstanding at June 30, 2018 and Dec. 31, 2017, respectively
1,272

 
1,269

Additional paid in capital
5,920

 
5,898

Retained earnings
4,580

 
4,413

Accumulated other comprehensive loss
(122
)
 
(125
)
Total common stockholders’ equity
11,650

 
11,455

Total liabilities and equity
$
44,240

 
$
43,030

 
 
 
 
See Notes to Consolidated Financial Statements

6

Table of Contents


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, 2018 and 2017
 
 
 
 
 
 
 
 
 
 
Balance at March 31, 2017
507,763

 
$
1,269

 
$
5,873

 
$
4,036

 
$
(109
)
 
$
11,069

Net income


 


 


 
227

 


 
227

Other comprehensive income


 


 


 


 
2

 
2

Dividends declared on common stock


 


 


 
(184
)
 


 
(184
)
Share-based compensation


 


 
9

 

 


 
9

Balance at June 30, 2017
507,763

 
$
1,269

 
$
5,882

 
$
4,079

 
$
(107
)
 
$
11,123

 
 
 
 
 
 
 
 
 
 
 
 
Balance at March 31, 2018
508,662

 
$
1,272

 
$
5,903

 
$
4,510

 
$
(124
)
 
$
11,561

Net income


 


 


 
265

 


 
265

Other comprehensive income


 


 


 


 
2

 
2

Dividends declared on common stock


 


 


 
(195
)
 


 
(195
)
Issuances of common stock
236

 

 
10

 


 


 
10

Share-based compensation


 


 
7

 

 


 
7

Balance at June 30, 2018
508,898

 
$
1,272

 
$
5,920

 
$
4,580

 
$
(122
)
 
$
11,650

 
 
 
 
 
 
 
 
 
 
 
 
See Notes to Consolidated Financial Statements


7

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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
 
 
 
Six Months Ended June 30, 2018 and 2017
 
 
 
 
 
 
 
 
 
 
Balance at Dec. 31, 2016
507,223

 
$
1,268

 
$
5,881

 
$
3,982

 
$
(110
)
 
$
11,021

Net income
 
 
 
 
 
 
467

 
 
 
467

Other comprehensive income
 
 
 
 
 
 
 
 
3

 
3

Dividends declared on common stock
 
 
 
 
 
 
(368
)
 
 
 
(368
)
Issuances of common stock
611

 
1

 
4

 
 
 
 
 
5

Repurchases of common stock
(71
)
 

 
(3
)
 
 
 
 
 
(3
)
Share-based compensation
 
 
 
 

 
(2
)
 
 
 
(2
)
Balance at June 30, 2017
507,763

 
$
1,269

 
$
5,882

 
$
4,079

 
$
(107
)
 
$
11,123

 
 
 
 
 
 
 
 
 
 
 
 
Balance at Dec. 31, 2017
507,763

 
$
1,269

 
$
5,898

 
$
4,413

 
$
(125
)
 
$
11,455

Net income
 
 
 
 
 
 
556

 
 
 
556

Other comprehensive income
 
 
 
 
 
 
 
 
3

 
3

Dividends declared on common stock
 
 
 
 
 
 
(389
)
 
 
 
(389
)
Issuances of common stock
1,157

 
3

 
24

 
 
 
 
 
27

Repurchases of common stock
(22
)
 

 
(1
)
 
 
 
 
 
(1
)
Share-based compensation
 
 
 
 
(1
)
 

 
 
 
(1
)
Balance at June 30, 2018
508,898

 
1,272

 
5,920

 
4,580

 
(122
)
 
11,650

 
 
 
 
 
 
 
 
 
 
 
 
See Notes to Consolidated Financial Statements





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Table of Contents


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 June 30, 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 and six months ended June 30, 2018 and 2017; and its cash flows for the six months ended June 30, 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 June 30, 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). On Jan. 1, 2019 agreements considered leases for the use of office space, equipment and natural gas storage assets, as well as certain purchased power agreements (PPAs) for fossil-fueled generating facilities are expected to be recognized on the consolidated balance sheet.

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 to the consolidated financial statements.

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 the 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, $12 million of pension costs were retrospectively reclassified from operating and maintenance expenses to other income, net on the consolidated income statement for the six months ended June 30, 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)
 
June 30, 2018
 
Dec. 31, 2017
Accounts receivable, net
 
 
 
 
Accounts receivable
 
$
856

 
$
849

Less allowance for bad debts
 
(48
)
 
(52
)
 
 
$
808

 
$
797

(Millions of Dollars)
 
June 30, 2018
 
Dec. 31, 2017
Inventories
 
 
 
 
Materials and supplies
 
$
312

 
$
311

Fuel
 
147

 
186

Natural gas
 
52

 
113

 
 
$
511

 
$
610

(Millions of Dollars)
 
June 30, 2018
 
Dec. 31, 2017
Property, plant and equipment, net
 
 
 
 
Electric plant
 
$
39,745

 
$
39,016

Natural gas plant
 
5,955

 
5,800

Common and other property
 
2,045

 
2,013

Plant to be retired (a)
 
10

 
11

Construction work in progress
 
2,658

 
2,087

Total property, plant and equipment
 
50,413

 
48,927

Less accumulated depreciation
 
(15,479
)
 
(15,000
)
Nuclear fuel
 
2,712

 
2,697

Less accumulated amortization
 
(2,357
)
 
(2,295
)
 
 
$
35,289

 
$
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 June 30
 
Six Months Ended June 30
 
 
2018
 
2017
 
2018
 
2017
Federal statutory rate
 
21.0
 %
 
35.0
 %
 
21.0
 %
 
35.0
 %
State tax, net of federal tax effect
 
5.1

 
4.1

 
5.0

 
4.1

Increase (decreases) in tax from:
 

 

 

 

Wind production tax credits (PTCs)
 
(5.4
)
 
(4.5
)
 
(5.8
)
 
(4.2
)
Regulatory differences - ARAM (a)
 
(5.4
)
 
(0.1
)
 
(5.6
)
 
(0.1
)
Regulatory differences - ARAM deferral (b)
 
4.0

 

 
4.8

 

Regulatory differences - other utility plant items
 
(1.0
)
 
(0.9
)
 
(1.0
)
 
(0.7
)
Other, net
 
(1.4
)
 
(2.6
)
 
(1.4
)
 
(2.2
)
Effective income tax rate
 
16.9
 %
 
31.0
 %
 
17.0
 %
 
31.9
 %

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

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 - 2014
 
October 2019
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. In the second quarter of 2018, the Joint Committee on Taxation completed its review and took no exception to the agreement. As a result, the remaining unrecognized tax benefit was released and recorded as a payable to the IRS.

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. As of June 30, 2018, the case has been forwarded to Appeals and 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 June 30, 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 June 30, 2018, Minnesota had not proposed any material adjustments;
In 2016, Wisconsin began an audit of years 2012 and 2013. As of June 30, 2018, the Company is evaluating the state’s proposed audit adjustments. No material accruals are expected; and
As of June 30, 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)
 
June 30, 2018
 
Dec. 31, 2017
Unrecognized tax benefit — Permanent tax positions
 
$
21

 
$
20

Unrecognized tax benefit — Temporary tax positions
 
13

 
19

Total unrecognized tax benefit
 
$
34

 
$
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)
 
June 30, 2018
 
Dec. 31, 2017
NOL and tax credit carryforwards
 
$
(33
)
 
$
(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 audit resumes, the Minnesota and Wisconsin audits progress, and other state audits resume. As the IRS Appeals and Minnesota and Wisconsin audits progress and the IRS audit resumes, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $29 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 June 30, 2018 and Dec. 31, 2017 were not material. No amounts were accrued for penalties related to unrecognized tax benefits as of June 30, 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 and in Note 5 to the consolidated financial statements to Xcel Energy Inc.’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2018, appropriately represent, in all material respects, the current status of other rate matters, and are incorporated herein by reference.

Tax Reform Regulatory Proceedings

The specific impacts of the 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.


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NSP-Minnesota — In April 2018, NSP-Minnesota updated 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, and made recommendations regarding the sharing of those benefits with ratepayers. 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.

In June 2018, the Minnesota Department of Commerce (DOC) recommended to implement refunds for the current tax impacts (approximately $90 million), and incorporate the deferred tax impacts (approximately $53 million) in NSP-Minnesota’s next electric and gas rate cases. A decision from the Minnesota Public Utilities Commission (MPUC) is expected in 2018.

NSP-Minnesota North and South Dakota — In February 2018, NSP-Minnesota proposed using the reduced revenue requirements from the TCJA to defer planned future rate filings in North Dakota and South Dakota. In July 2018, the South Dakota Public Utilities Commission (SDPUC) approved a settlement which proposed a one-time customer refund of $11 million for the 2018 impact of the TCJA and a two-year rate case moratorium.

NSP-Wisconsin — In May 2018, the Public Service Commission of Wisconsin (PSCW) issued its final order which requires customer refunds of $27 million and defers approximately $5 million until NSP-Wisconsin’s next rate case proceeding.

NSP-Wisconsin Michigan — In May 2018, the Michigan Public Service Commission (MPSC) approved electric and natural gas tax reform settlement agreements. Most of the electric TCJA benefits were included in NSP-Wisconsin’s recently approved Michigan 2018 electric base rate case. Natural gas TCJA benefits are to be returned to customers commencing in July 2018.

PSCo Colorado Natural Gas — In February 2018, the administrative law judge (ALJ) approved PSCo and the Colorado Public Utilities Commission (CPUC) Staff’s TCJA settlement agreement, which includes a $20 million reduction to provisional rates effective March 1, 2018. A final true-up would provide customers the full net benefit of the TCJA retroactive to January 2018.

PSCo Colorado Electric — In April 2018, PSCo, the CPUC Staff and the Office of Consumer Counsel (OCC) filed a TCJA settlement agreement that 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. In June 2018, the CPUC approved the customer refund of $42 million, effective June 1, 2018. The CPUC set the decision regarding the remainder of the $59 million for hearing before an ALJ. Revisions to the TCJA settlement will be addressed in a future electric rate case.

SPSTexas — In June 2018, SPS, the Public Utility Commission of Texas (PUCT) Staff and various intervenors reached a settlement in the Texas electric rate case which included the impacts of the TCJA. The settlement reflects no change in customer rates or refunds, and SPS’ actual capital structure, which SPS has informed the parties it intends to be a 57 percent equity ratio to offset the negative impacts on its credit metrics and potentially its credit ratings.

SPSNew Mexico — In February 2018, SPS 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.

Other Regulatory Proceedings

NSP-Minnesota

Recently Concluded Regulatory Proceedings — MPUC and the North Dakota Public Service Commission (NDPSC)

PPA Terminations and Amendments — In June 2018, NSP-Minnesota executed the terminations of the Benson and Laurentian PPAs, and purchased the Benson biomass facility. As a result, a $103 million regulatory asset was recognized for the costs of the Benson transaction, including payments to Benson of $93 million, as well as other transaction costs and future estimated facility removal costs. For Laurentian, a regulatory asset of $109 million was recognized for annual termination payments over six years. The regulatory approvals provide for recovery of the Benson regulatory asset over approximately 10 years, and for recovery of the Laurentian termination payments as they occur, through fuel and purchased energy recovery mechanisms.


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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 return on equity (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

 
 

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 through 2021 which included the impacts of TCJA. In April 2018, the CPUC denied the motion on procedural grounds and dismissed the electric rate case.

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, was 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 February 2018, the ALJ approved a TCJA settlement agreement between PSCo and the CPUC Staff, which reduced provisional rates by $20 million, based on a preliminary TCJA estimate of $29 million. The settlement remains subject to CPUC approval. The impact of the TCJA will be trued-up later in 2018. Annualized provisional rates of approximately $43 million were effective March 1, 2018.

In May 2018, the ALJ issued an interim recommended decision which would result in a 2018 overall rate increase of approximately $46 million, prior to the impact of the TCJA. The estimated rate increase reflects a 2016 HTY with a 13-month average rate base of $1.6 billion, a ROE of 9.35 percent and an equity ratio of 54.2 percent.
On July 12, 2018, the CPUC deliberated and approved several of the ALJ’s recommendations including application of a 2016 HTY, with a 13-month average rate base, and an ROE of 9.35 percent.  The CPUC adjusted the equity ratio to 54.6 percent and provided no return on the prepaid pension and retiree medical asset.  With these adjustments the total rate increase, prior to TCJA impacts, would be $47 million.

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The estimated impact of the CPUC’s decision is presented below:
(Millions of Dollars)
 
Estimated Impact of the CPUC’s Decision
Filed 2018 revenue request based on a FTY
 
$
63

Impact of the change in test year
 
5

PSCo’s deficiency based on a 2016 HTY - year-end rate base
 
68

 
 
 
Adjustments:
 
 
  ROE at 9.35 percent
 
(9
)
Equity ratio of 54.6 percent
 
(2
)
Change in amortization period for certain regulatory assets, including a debt return
 
(6
)
Loss of return on prepaid pension and retiree medical
 
(4
)
Change from 2016 year-end to average rate base
 
(5
)
Other, net
 
5

Total adjustments
 
(21
)
 
 
 
Total rate increase, prior to the TCJA impacts 
 
$
47

The CPUC is expected to issue its order on the natural gas rate case in the third quarter of 2018. The CPUC is expected to issue a final decision with the impacts of the TCJA later in 2018.

Provisional rates, subject to refund, were implemented on Jan. 1, 2018. A current liability which represents PSCo’s best estimate of a refund obligation associated with provisional rates was recorded as of June 30, 2018.

PSIA Rider
In June 2018, PSCo filed for an extension to the PSIA rider through 2020. PSCo requested an expedited decision by Nov. 15, 2018. PSCo also requested authorization to roll-in recovery of costs in the current PSIA rider into base rates effective Jan. 1, 2019, if the CPUC rejects the proposed PSIA extension or fails to rule on the request by the end of 2018.

Additionally, PSCo reduced PSIA revenues by approximately $8 million for 2018 for the impact of the TCJA, effective May 1, 2018. PSIA revenues are subject to the CPUC approved PSIA rider true-up process.

SPS

Pending Regulatory Proceedings — PUCT

Texas 2017 Electric Rate Case — In 2017, SPS filed a $54 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 request also reflects the acceleration of depreciation lives for the two generating units at the Tolk Generating Station from 2042 and 2045 to 2032.

In May 2018, SPS filed rebuttal testimony and revised its request to an overall increase in the annual base rate revenue of approximately $32 million, or 5.9 percent, net of the TCJA (approximately $32 million after adjusting for a 58 percent equity ratio) and other adjustments. This request would be equivalent to approximately $17 million after adjusting for the Transmission Cost Recovery Factor (TCRF) rider.

In June 2018, SPS, the PUCT Staff and various intervenors reached a settlement, which results in no overall change to SPS’ revenues after adjusting for the impact of the TCJA and the lower costs of long-term debt.


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The following are key terms:

The ability to use an equity ratio that reflects SPS' actual capital structure, which SPS has informed the parties it intends to be 57 percent to mitigate the impact of TCJA on credit metrics;
A 9.5 percent ROE for the calculation of allowance for funds used during construction (AFUDC);
TCRF rider will remain in effect;
SPS will accelerate depreciation rates for the Tolk Generating Station Units 1 and 2 by 50 percent of the original request; and
SPS agrees that it will file its next base rate case no later than Dec. 31, 2019.

A reconciliation of the settlement is as follows:
(Millions of Dollars)
 
 
Original base rate request
 
$
69

Base rate revenue to be recovered through TCRF 
 
(15
)
Net revenue request
 
54

Adjustment for TCJA and other items
 
(37
)
Requested incremental revenue
 
17

Unspecified settlement adjustments
 
(13
)
Accelerated depreciation (Tolk plant)
 
(4
)
   SPS' net revenue change
 
$


Under the terms of the settlement, the final rates would not change from the current rates.  However, SPS would be permitted to surcharge customers for unrecovered TCRF charges that were not billed during the period of Jan. 23, 2018 through June 10, 2018.  A PUCT decision is expected in the third 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.  In 2017, the District Court denied SPS’ appeal, and SPS appealed the District Court’s decision to the state Court of Appeals for the 7th Circuit.  In 2018, the Court of Appeals upheld the District Court’s decision on the PUCT’s order, rejecting SPS’ appeal. As part of the settlement of the 2017 Texas rate case, SPS has agreed to end its appeal.

Pending Regulatory Proceeding — (New Mexico Public Regulation Commission) NMPRC

New Mexico 2017 Electric Rate Case — In October 2017, SPS filed an electric rate case with the NMPRC seeking an increase in base rates of approximately $43 million. The request was based on a HTY ended June 30, 2017, a ROE of 10.25 percent, an equity ratio of 53.97 percent, a 35 percent federal income tax rate and a rate base of approximately $885 million, including rate base additions through Nov. 30, 2017.

In May 2018, SPS reduced its request to $27 million, net of the TCJA (approximately $11 million) and other adjustments, based on a requested ROE of 10.25 percent and an equity ratio of 58.0 percent.

In June 2018, the New Mexico Hearing Examiner issued a recommended decision proposing an increase of $12 million, based on a ROE of 9.4 percent and an equity ratio of 53.97 percent. She also denied SPS' requests to shorten depreciation lives related to Tolk Units 1 and 2 and Cunningham Unit 1. The Hearing Examiner rejected intervenor proposals to refund the impacts of the TCJA back to Jan. 1, 2018.

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The following table summarizes certain parties’ proposed modifications to SPS’ request, SPS’ revised request, and the Hearing Examiner’s recommendation:
(Millions of Dollars)
 
 NMPRC Staff Testimony
 
NMAG Testimony
 
SPS Rebuttal Testimony
 
Hearing Examiner's Recommendation
SPS request
 
$
43

 
$
43

 
$
43

 
$
43

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

 
32

 
32

 
32

 
 
 
 
 
 
 
 
 
ROE
 
(4
)
 
(6
)
 

 
(5
)
Capital structure
 
(7
)
 
(3
)
 

 
(3
)
Depreciation lives (Tolk and Cunningham plants)
 
(3
)
 
(3
)
 

 
(3
)
Disallow rate case expenses
 
(2
)
 
(3
)
 
(1
)
 

Regional transmission revenue and expense (adjustment for the impact of the TCJA):
 
 
 
 
 
 
 
 
Impact of the TCJA
 

 
(3
)
 

 
(1
)
Aligning costs with transmission plant in rate base
 

 

 

 
(1
)
Post test year plant (updated to actual)
 
(1
)
 
(2
)
 
(3
)
 

Excess generation adjustment
 

 
(1
)
 

 
(1
)
Other, net
 
(4
)
 
(4
)
 
(1
)
 
(6
)
Recommended rate increase
 
$
11

 
$
7

 
$
27

 
$
12

 
 
 
 
 
 
 
 
 
ROE
 
9.0
%
 
9.21
%
 
10.25
%
 
9.4
%
Equity ratio
 
52.0
%
 
53.97
%
 
58.0
%
 
53.97
%

SPS anticipates a decision and implementation of final rates in the third quarter 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 — Federal Energy Regulatory Commission (FERC)

Midcontinent Independent System Operator, Inc. (MISO) Return on Equity (ROE) Complaints — In November 2013, a group of customers filed a complaint at the FERC against MISO transmission owners (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.

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. 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. 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.

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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. In November 2017, the FERC denied an SPS request for rehearing. In January 2018, SPS appealed the FERC request to the D.C. Circuit Court of Appeals. SPS has filed to recover the SPP charges as part of the appeal. The appeal is currently pending.

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, and the FERC approved the rehearing request for further consideration on May 7, 2018.  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 of the consolidated financial statements, 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 and in Notes 5 and 6 to Xcel Energy Inc.’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2018, 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

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 3,470 Megawatts (MW) of capacity under long-term PPAs as of June 30, 2018 and 3,537 MW as of 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 various 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. 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 guarantee or indemnity amount. As of June 30, 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)
 
June 30, 2018
 
Dec. 31, 2017
Guarantees issued and outstanding
 
$
18.4

 
$
18.8

Current exposure under these guarantees
 

 

Bonds with indemnity protection
 
$
51.8

 
53.1



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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. 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 Ashland/Northern States Power Lakefront Superfund Site (the Site) includes NSP-Wisconsin property, previously operated as a MGP facility (the Upper Bluff), an adjacent city lakeshore park area (Kreher Park) (collectively the Phase I Area); and a sediment area of Lake Superior’s Chequamegon Bay (Phase II Area). NSP-Wisconsin initiated a wet dredge remedy of the Phase II area in 2017. NSP-Wisconsin anticipates completion of Phase II activities in 2018 with final site restoration activities in early 2019. Groundwater treatment activities at the Site will continue for many years.

The current cost estimate for the remediation of the entire site is approximately $175 million, of which approximately $146 million has been spent. As of June 30, 2018 and Dec. 31, 2017, NSP-Wisconsin recorded a total liability of $29 million and $30 million, respectively, for the entire site.

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. Remediation activities commenced in June 2018. NSP-Minnesota has also initiated insurance recovery litigation in North Dakota. The U.S. District Court for the District of North Dakota has set a trial date for Spring of 2020.

NSP-Minnesota recorded an estimated liability of $10 million as of June 30, 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 $12 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 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 in the third quarter of 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 Ashland MGP Site and the Fargo MGP Site, 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 accrued $5 million as of June 30, 2018 and $4 million as of 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.


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Environmental Requirements

Air
Revisions to the National Ambient Air Quality Standard (NAAQS) for Ozone - In 2015, the EPA revised the NAAQS for ozone by lowering the eight-hour standard from 75 parts per billion (ppb) to 70 ppb. Xcel Energy meets the 2015 ozone standard in all areas where its generating units operate, except for the Denver Metropolitan Area. PSCo’s retirement of its coal fired plants in the Denver non-attainment area helped Colorado’s plan to mitigate non-attainment. In June 2018, the EPA designated the parts of the Denver Metropolitan Area that currently do not attain the 2008 ozone standards as also not attaining the more stringent 2015 ozone standard. Colorado will continue to consider further reductions that are available in the non-attainment area as it develops plans to meet the ozone standards. The gas plants that operate in PSCo’s non-attainment area may be required to improve or add controls, implement further work practices and/or implement enhanced emissions monitoring as part of future Colorado state plans.

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.

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 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). 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, which was denied. Taking into account the decision in the Farmland case, the Sinclair plaintiffs have requested the Ninth Circuit to reverse the grant of summary judgment without hearing. Oral arguments were presented to the Ninth Circuit in July 2018 regarding this issue and the denial of class certification and it is uncertain when a decision will be issued. 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. PSCo filed a motion to dismiss this claim, which was granted in May 2018. DRC subsequently filed an appeal to the Colorado Court of Appeals. It is uncertain when a decision will be rendered regarding this appeal.
 

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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  
 June 30, 2018
 
Year Ended  
 Dec. 31, 2017
Borrowing limit
 
$
3,000

 
$
3,250

Amount outstanding at period end
 
682

 
814

Average amount outstanding
 
1,028

 
644

Maximum amount outstanding
 
1,349

 
1,247

Weighted average interest rate, computed on a daily basis
 
2.42
%
 
1.35
%
Weighted average interest rate at period end
 
2.47

 
1.90


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 June 30, 2018 and Dec. 31, 2017, there were $42 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 June 30, 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.
 
$
1,250

 
$
520

 
$
730

PSCo
 
700

 
4

 
696

NSP-Minnesota
 
500

 
36

 
464

SPS
 
400

 
134

 
266

NSP-Wisconsin
 
150

 
30

 
120

Total
 
$
3,000

 
$
724

 
$
2,276

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

In addition, Xcel Energy Inc. entered into a $500 million 364-day term loan in December 2017. As of June 30, 2018, $250 million of borrowings remain outstanding with no additional borrowing capacity.


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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 June 30, 2018 and Dec. 31, 2017.

Long-Term Borrowings

During the three months ended June 30, 2018, Xcel Energy Inc. and its utility subsidiaries issued the following:

PSCo issued $350 million of 3.70 percent first mortgage green bonds due June 15, 2028 and $350 million of 4.10 percent first mortgage green bonds due June 15, 2048; and
Xcel Energy Inc. issued $500 million of 4.00 percent senior notes due June 15, 2028.

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).

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.


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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 asset class target allocations approved by the MPUC for the 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.

Unrealized gains for the nuclear decommissioning fund were $547 million and $560 million as of June 30, 2018 and Dec. 31, 2017, respectively, and unrealized losses and amounts recorded as other-than-temporary impairments were $23 million and $7 million as of June 30, 2018 and Dec. 31, 2017, respectively.


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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 June 30, 2018 and Dec. 31, 2017:
 
 
June 30, 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
 
$
31

 
$
31

 
$

 
$

 
$

 
$
31

Commingled funds:
 
 
 
 
 
 
 
 
 
 
 
 
Non U.S. equities
 
262

 
199

 

 

 
90

 
289

Emerging market debt funds
 
158

 

 

 

 
158

 
158

Private equity investments
 
151

 

 

 

 
220

 
220

Real estate
 
128

 

 

 

 
197

 
197

Debt securities:
 
 
 
 
 
 
 
 
 
 
 
 
Government securities
 
76

 

 
75

 

 

 
75

U.S. corporate bonds
 
330

 

 
323

 

 

 
323

Non U.S. corporate bonds
 
58

 

 
56

 

 

 
56

Equity securities:
 
 
 
 
 
 
 
 
 
 
 
 
U.S. equities
 
269

 
568

 

 

 

 
568

Non U.S. equities
 
157

 
227

 

 

 

 
227

Total
 
$
1,620

 
$
1,025

 
$
454

 
$

 
$
665

 
$
2,144

(a) 
Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $138 million of equity investments in unconsolidated subsidiaries and $115 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 and six months ended June 30, 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 June 30, 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
 
$

 
$
4

 
$
2

 
$
69

 
$
75

U.S. corporate bonds
 
5

 
90

 
172

 
56

 
323