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 Sept. 30, 2017
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 October 23, 2017
Common Stock, $2.50 par value
 
507,762,881 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 thousands, except per share data)

 
Three Months Ended Sept. 30
 
Nine Months Ended Sept. 30
 
2017
 
2016
 
2017
 
2016
Operating revenues
 
 
 
 
 
 
 
Electric
$
2,783,569

 
$
2,799,964

 
$
7,420,646

 
$
7,209,225

Natural gas
214,253

 
221,956

 
1,129,795

 
1,046,544

Other
19,075

 
18,227

 
57,806

 
56,500

Total operating revenues
3,016,897

 
3,040,147

 
8,608,247

 
8,312,269

 
 
 
 
 
 
 
 
Operating expenses
 
 
 
 
 
 
 
Electric fuel and purchased power
1,006,160

 
1,037,263

 
2,850,480

 
2,755,083

Cost of natural gas sold and transported
63,998

 
67,566

 
543,452

 
469,754

Cost of sales — other
8,451

 
8,648

 
25,216

 
25,225

Operating and maintenance expenses
541,539

 
590,009

 
1,706,102

 
1,764,397

Conservation and demand side management expenses
73,728

 
63,914

 
206,121

 
177,266

Depreciation and amortization
371,091

 
328,503

 
1,102,015

 
971,057

Taxes (other than income taxes)
133,571

 
117,190

 
410,591

 
400,982

Total operating expenses
2,198,538

 
2,213,093

 
6,843,977

 
6,563,764

 
 
 
 
 
 
 
 
Operating income
818,359

 
827,054

 
1,764,270

 
1,748,505

 
 
 
 
 
 
 
 
Other income, net
5,089

 
578

 
14,143

 
6,388

Equity earnings of unconsolidated subsidiaries
7,080

 
9,701

 
22,496

 
32,500

Allowance for funds used during construction — equity
23,483

 
17,199

 
54,182

 
45,042

 
 
 
 
 
 
 
 
Interest charges and financing costs
 
 
 
 
 
 
 
Interest charges — includes other financing costs of $5,923, $6,060, $17,657 and $19,026, respectively
167,803

 
165,857

 
497,932

 
485,280

Allowance for funds used during construction — debt
(10,724
)
 
(7,532
)
 
(25,359
)
 
(20,206
)
Total interest charges and financing costs
157,079

 
158,325

 
472,573

 
465,074

 
 
 
 
 
 
 
 
Income before income taxes
696,932

 
696,207

 
1,382,518

 
1,367,361

Income taxes
204,791

 
238,412

 
423,844

 
471,459

Net income
$
492,141

 
$
457,795

 
$
958,674

 
$
895,902

 
 
 
 
 
 
 
 
Weighted average common shares outstanding:
 
 
 
 
 
 
 
Basic
508,581

 
508,941

 
508,468

 
508,840

Diluted
509,242

 
509,566

 
509,052

 
509,396

 
 
 
 
 
 
 
 
Earnings per average common share:
 
 
 
 
 
 
 
Basic
$
0.97

 
$
0.90

 
$
1.89

 
$
1.76

Diluted
0.97

 
0.90

 
1.88

 
1.76

 
 
 
 
 
 
 
 
Cash dividends declared per common share
$
0.36

 
$
0.34

 
$
1.08

 
$
1.02

 
 
 
 
 
 
 
 
See Notes to Consolidated Financial Statements


3

Table of Contents


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

 
Three Months Ended Sept. 30
 
Nine Months Ended Sept. 30
 
2017
 
2016
 
2017
 
2016
Net income
$
492,141

 
$
457,795

 
$
958,674

 
$
895,902

 
 
 
 
 
 
 
 
Other comprehensive income
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Pension and retiree medical benefits:
 
 
 
 
 
 
 
Amortization of losses included in net periodic benefit cost, net of tax of $582, $536, $1,805 and $1,635, respectively
982

 
878

 
2,886

 
1,954

 
 
 
 
 
 
 
 
Derivative instruments:
 
 
 
 
 
 
 
Net fair value increase (decrease), net of tax of $15, $(2), $32 and $3, respectively
23

 
(4
)
 
49

 
4

Reclassification of losses to net income, net of tax of $587, $588, $1,632 and $1,786, respectively
981

 
960

 
2,609

 
2,834

 
1,004

 
956

 
2,658

 
2,838

Marketable securities:


 
 
 
 
 
 
Net fair value increase, net of tax of $0, $0, $0 and $0, respectively

 

 
1

 

 
 
 
 
 
 
 
 
Other comprehensive income
1,986

 
1,834

 
5,545

 
4,792

Comprehensive income
$
494,127

 
$
459,629

 
$
964,219

 
$
900,694

 
 
 
 
 
 
 
 
See Notes to Consolidated Financial Statements




4

Table of Contents


XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
(amounts in thousands)
 
Nine Months Ended Sept. 30
 
2017
 
2016
Operating activities
 
 
 
Net income
$
958,674

 
$
895,902

Adjustments to reconcile net income to cash provided by operating activities:
 
 
 
Depreciation and amortization
1,113,418

 
982,682

Conservation and demand side management program amortization
1,927

 
3,089

Nuclear fuel amortization
87,654

 
89,475

Deferred income taxes
501,013

 
479,100

Amortization of investment tax credits
(3,835
)
 
(3,920
)
Allowance for equity funds used during construction
(54,182
)
 
(45,042
)
Equity earnings of unconsolidated subsidiaries
(22,496
)
 
(32,500
)
Dividends from unconsolidated subsidiaries
32,316

 
34,502

Share-based compensation expense
44,239

 
29,872

Net realized and unrealized hedging and derivative transactions
(62
)
 
3,307

Other, net
(2,577
)
 
(266
)
Changes in operating assets and liabilities:
 
 
 
Accounts receivable
(31,337
)
 
(29,585
)
Accrued unbilled revenues
104,175

 
87,015

Inventories
(9,158
)
 
(6,203
)
Other current assets
64,208

 
80,566

Accounts payable
(67,759
)
 
50,526

Net regulatory assets and liabilities
(26,556
)
 
3,911

Other current liabilities
(111,512
)
 
(63,524
)
Pension and other employee benefit obligations
(134,455
)
 
(96,350
)
Change in other noncurrent assets
(15,002
)
 
(11,815
)
Change in other noncurrent liabilities
(61,513
)
 
(25,401
)
Net cash provided by operating activities
2,367,180

 
2,425,341

 
 
 
 
Investing activities
 
 
 
Utility capital/construction expenditures
(2,256,452
)
 
(2,186,483
)
Proceeds from insurance recoveries

 
1,595

Allowance for equity funds used during construction
54,182

 
45,042

Purchases of investment securities
(971,469
)
 
(390,031
)
Proceeds from the sale of investment securities
948,558

 
327,378

Investments in WYCO Development LLC and other
(7,616
)
 
(3,962
)
Other, net
(5,803
)
 
204

Net cash used in investing activities
(2,238,600
)
 
(2,206,257
)
 
 
 
 
Financing activities
 
 
 
Proceeds from (repayments of) short-term borrowings, net
122,000

 
(480,000
)
Proceeds from issuances of long-term debt
1,422,163

 
1,632,642

Repayments of long-term debt, including reacquisition premiums
(1,030,099
)
 
(580,167
)
Repurchases of common stock
(2,943
)
 
(2,810
)
Dividends paid
(538,045
)
 
(507,817
)
Other
(18,291
)
 
(12,487
)
Net cash (used in) provided by financing activities
(45,215
)
 
49,361

 
 
 
 
Net change in cash and cash equivalents
83,365

 
268,445

Cash and cash equivalents at beginning of period
84,476

 
84,940

Cash and cash equivalents at end of period
$
167,841

 
$
353,385

 
 
 
 
Supplemental disclosure of cash flow information:
 
 
 
Cash paid for interest (net of amounts capitalized)
$
(488,574
)
 
$
(461,302
)
Cash received for income taxes, net
42,051

 
61,245

 
 
 
 
Supplemental disclosure of non-cash investing and financing transactions:
 
 
 
Property, plant and equipment additions in accounts payable
$
268,932

 
$
221,155

Issuance of common stock for equity awards
23,394

 
17,527

 
 
 
 
See Notes to Consolidated Financial Statements

5

Table of Contents


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

 
Sept. 30, 2017
 
Dec. 31, 2016
Assets
 
 
 
Current assets
 
 
 
Cash and cash equivalents
$
167,841

 
$
84,476

Accounts receivable, net
807,621

 
776,289

Accrued unbilled revenues
625,657

 
729,832

Inventories
616,675

 
604,226

Regulatory assets
407,639

 
363,655

Derivative instruments
74,533

 
38,224

Prepaid taxes
55,788

 
106,697

Prepayments and other
143,120

 
138,682

Total current assets
2,898,874

 
2,842,081

 
 
 
 
Property, plant and equipment, net
33,949,952

 
32,841,750

 
 
 
 
Other assets
 
 
 
Nuclear decommissioning fund and other investments
2,300,265

 
2,091,858

Regulatory assets
3,011,462

 
3,080,867

Derivative instruments
49,124

 
50,189

Other
259,117

 
248,532

Total other assets
5,619,968

 
5,471,446

Total assets
$
42,468,794

 
$
41,155,277

 
 
 
 
Liabilities and Equity
 
 
 
Current liabilities
 
 
 
Current portion of long-term debt
$
305,415

 
$
255,529

Short-term debt
514,000

 
392,000

Accounts payable
992,498

 
1,044,959

Regulatory liabilities
256,191

 
220,894

Taxes accrued
427,275

 
457,392

Accrued interest
147,860

 
172,901

Dividends payable
182,795

 
172,456

Derivative instruments
27,659

 
26,959

Other
486,713

 
503,953

Total current liabilities
3,340,406

 
3,247,043

 
 
 
 
Deferred credits and other liabilities
 
 
 
Deferred income taxes
7,362,931

 
6,784,319

Deferred investment tax credits
59,381

 
63,216

Regulatory liabilities
1,358,558

 
1,383,212

Asset retirement obligations
2,883,799

 
2,782,229

Derivative instruments
131,058

 
148,146

Customer advances
190,995

 
195,214

Pension and employee benefit obligations
984,794

 
1,112,366

Other
144,528

 
223,965

Total deferred credits and other liabilities
13,116,044

 
12,692,667

 
 
 
 
Commitments and contingencies


 


Capitalization
 
 
 
Long-term debt
14,572,967

 
14,194,718

Common stock — 1,000,000,000 shares authorized of $2.50 par value; 507,762,881 and
507,222,795 shares outstanding at Sept. 30, 2017 and Dec. 31, 2016, respectively
1,269,407

 
1,268,057

Additional paid in capital
5,888,729

 
5,881,494

Retained earnings
4,386,050

 
3,981,652

Accumulated other comprehensive loss
(104,809
)
 
(110,354
)
Total common stockholders’ equity
11,439,377

 
11,020,849

Total liabilities and equity
$
42,468,794

 
$
41,155,277

 
 
 
 
See Notes to Consolidated Financial Statements

6

Table of Contents


XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY (UNAUDITED)
(amounts 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 Sept. 30, 2017 and 2016
 
 
 
 
 
 
 
 
 
 
Balance at June 30, 2016
507,953

 
$
1,269,882

 
$
5,896,394

 
$
3,643,653

 
$
(106,795
)
 
$
10,703,134

Net income


 


 


 
457,795

 


 
457,795

Other comprehensive income


 


 


 


 
1,834

 
1,834

Dividends declared on common stock


 


 


 
(173,786
)
 


 
(173,786
)
Issuances of common stock
48

 
120

 

 


 


 
120

Repurchases of common stock
(48
)
 
(120
)
 
(2,021
)
 


 


 
(2,141
)
Share-based compensation


 


 
4,523

 
(3,537
)
 


 
986

Balance at Sept. 30, 2016
507,953

 
$
1,269,882

 
$
5,898,896

 
$
3,924,125

 
$
(104,961
)
 
$
10,987,942

 
 
 
 
 
 
 
 
 
 
 
 
Balance at June 30, 2017
507,763

 
$
1,269,407

 
$
5,881,475

 
$
4,079,068

 
$
(106,795
)
 
$
11,123,155

Net income


 


 


 
492,141

 


 
492,141

Other comprehensive income


 


 


 


 
1,986

 
1,986

Dividends declared on common stock


 


 


 
(184,061
)
 


 
(184,061
)
Share-based compensation


 


 
7,254

 
(1,098
)
 


 
6,156

Balance at Sept. 30, 2017
507,763

 
$
1,269,407

 
$
5,888,729

 
$
4,386,050

 
$
(104,809
)
 
$
11,439,377

 
 
 
 
 
 
 
 
 
 
 
 
See Notes to Consolidated Financial Statements

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Table of Contents



XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY (UNAUDITED) (Continued)
(amounts in thousands)
 
 
 
 
 
 
 
 
 
 
 
 
 
Common Stock Issued
 
Retained Earnings
 
Accumulated
Other
Comprehensive
Loss
 
Total
Common
Stockholders’
Equity
 
Shares
 
Par Value
 
Additional Paid In Capital
 
 
 
Nine Months Ended Sept. 30, 2017 and 2016
 
 
 
 
 
 
 
 
 
 
Balance at Dec. 31, 2015
507,536

 
$
1,268,839

 
$
5,889,106

 
$
3,552,728

 
$
(109,753
)
 
$
10,600,920

Net income
 
 
 
 
 
 
895,902

 
 
 
895,902

Other comprehensive income
 
 
 
 
 
 
 
 
4,792

 
4,792

Dividends declared on common stock
 
 
 
 
 
 
(520,968
)
 
 
 
(520,968
)
Issuances of common stock
486

 
1,216

 
15,110

 
 
 
 
 
16,326

Repurchases of common stock
(69
)
 
(173
)
 
(2,810
)
 
 
 
 
 
(2,983
)
Share-based compensation
 
 
 
 
(2,510
)
 
(3,537
)
 
 
 
(6,047
)
Balance at Sept. 30, 2016
507,953

 
$
1,269,882

 
$
5,898,896

 
$
3,924,125

 
$
(104,961
)
 
$
10,987,942

 
 
 
 
 
 
 
 
 
 
 
 
Balance at Dec. 31, 2016
507,223

 
$
1,268,057

 
$
5,881,494

 
$
3,981,652

 
$
(110,354
)
 
$
11,020,849

Net income
 
 
 
 
 
 
958,674

 
 
 
958,674

Other comprehensive income
 
 
 
 
 
 
 
 
5,545

 
5,545

Dividends declared on common stock
 
 
 
 
 
 
(551,614
)
 
 
 
(551,614
)
Issuances of common stock
611

 
1,527

 
3,510

 
 
 
 
 
5,037

Repurchases of common stock
(71
)
 
(177
)
 
(2,943
)
 
 
 
 
 
(3,120
)
Share-based compensation
 
 
 
 
6,668

 
(2,662
)
 
 
 
4,006

Balance at Sept. 30, 2017
507,763

 
$
1,269,407

 
$
5,888,729

 
$
4,386,050

 
$
(104,809
)
 
$
11,439,377

 
 
 
 
 
 
 
 
 
 
 
 
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 Sept. 30, 2017 and Dec. 31, 2016; the results of its operations, including the components of net income and comprehensive income, and changes in stockholders’ equity for the three and nine months ended Sept. 30, 2017 and 2016; and its cash flows for the nine months ended Sept. 30, 2017 and 2016. All adjustments are of a normal, recurring nature, except as otherwise disclosed. Management has also evaluated the impact of events occurring after Sept. 30, 2017 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, 2016 balance sheet information has been derived from the audited 2016 consolidated financial statements included in the Xcel Energy Inc. Annual Report on Form 10-K for the year ended Dec. 31, 2016. 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, 2016, filed with the SEC on Feb. 24, 2017. 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, 2016, appropriately represent, in all material respects, the current status of accounting policies and are incorporated herein by reference.

2.
Accounting Pronouncements

Recently Issued

Revenue Recognition In May 2014, the Financial Accounting Standards Board (FASB) issued Revenue from Contracts with Customers, Topic 606 (Accounting Standards Update (ASU) No. 2014-09), which provides a new framework for the recognition of revenue. Xcel Energy expects its adoption will primarily result in increased disclosures regarding revenue related to arrangements with customers, as well as separate presentation of alternative revenue programs. Xcel Energy currently expects to implement the standard on a modified retrospective basis, which requires application to contracts with customers effective Jan. 1, 2018, with the cumulative impact on contracts not yet completed as of Dec. 31, 2017 recognized as an adjustment to the opening balance of retained earnings.

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 eliminates the available-for-sale classification for marketable equity securities and also replaces 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 to be recognized in earnings. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2017. Xcel Energy expects that 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, currently classified as available-for-sale, will continue to be deferred to a regulatory asset, and that the overall impacts of the Jan. 1, 2018 adoption will not be material.

Leases — In February 2016, the FASB issued Leases, Topic 842 (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. As such, agreements entered prior to Jan. 1, 2017 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 after Dec. 31, 2016 will generally qualify as leases under the new standard, but has not yet completed its evaluation of certain other contracts, including arrangements for the secondary use of assets, such as land easements.


9

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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. Xcel Energy expects that 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 current ratemaking treatment and that the impacts of adoption will be limited to changes in classification of non-service costs in the consolidated statement of income. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2017.

Recently Adopted

Stock Compensation — In March 2016, the FASB issued Improvements to Employee Share-Based Payment Accounting, Topic 718 (ASU No. 2016-09), which simplifies accounting and financial statement presentation for share-based payment transactions. The guidance requires that the difference between the tax deduction available upon settlement of share-based equity awards and the tax benefit accumulated over the vesting period be recognized as an adjustment to income tax expense. Xcel Energy adopted the guidance in 2016, resulting in immaterial 2016 adjustments to income tax expense and changes in classification of cash flows related to tax withholding in the consolidated statements of cash flows for the years ended Dec. 31, 2016, 2015 and 2014.

3.
Selected Balance Sheet Data
(Thousands of Dollars)
 
Sept. 30, 2017
 
Dec. 31, 2016
Accounts receivable, net
 
 
 
 
Accounts receivable
 
$
859,242

 
$
827,112

Less allowance for bad debts
 
(51,621
)
 
(50,823
)
 
 
$
807,621

 
$
776,289

(Thousands of Dollars)
 
Sept. 30, 2017
 
Dec. 31, 2016
Inventories
 
 
 
 
Materials and supplies
 
$
320,195

 
$
312,430

Fuel
 
166,173

 
181,752

Natural gas
 
130,307

 
110,044

 
 
$
616,675

 
$
604,226

(Thousands of Dollars)
 
Sept. 30, 2017
 
Dec. 31, 2016
Property, plant and equipment, net
 
 
 
 
Electric plant
 
$
39,067,098

 
$
38,220,765

Natural gas plant
 
5,563,536

 
5,317,717

Common and other property
 
2,028,743

 
1,888,518

Plant to be retired (a)
 
11,412

 
31,839

Construction work in progress
 
1,861,576

 
1,373,380

Total property, plant and equipment
 
48,532,365

 
46,832,219

Less accumulated depreciation
 
(14,982,709
)
 
(14,381,603
)
Nuclear fuel
 
2,668,586

 
2,571,770

Less accumulated amortization
 
(2,268,290
)
 
(2,180,636
)
 
 
$
33,949,952

 
$
32,841,750


(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.


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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, 2016 appropriately represents, in all material respects, the current status of other income tax matters, and are incorporated herein by reference.

Federal Loss Carryback Claims — In 2012-2015, Xcel Energy identified certain expenses related to 2009, 2010, 2011, 2013, 2014 and 2015 that qualify for an extended carryback beyond the typical two-year carryback period. As a result of a higher tax rate in prior years, Xcel Energy recognized a tax benefit of approximately $5 million in 2015, $17 million in 2014, $12 million in 2013 and $15 million in 2012.

Federal Audits  Xcel Energy files a consolidated federal income tax return. The statute of limitations applicable to Xcel Energy’s 2009 through 2011 and 2012 through 2013 federal income tax returns, following extensions, expires in June 2018 and October 2018, respectively.

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 that would have resulted in $14 million of income tax expense for the 2009 through 2011 claims, and the 2013 through 2015 claims. In the fourth quarter of 2015, the IRS forwarded the issue to the Office of Appeals (Appeals). In the third quarter of 2017, Xcel Energy and Appeals reached an agreement and the benefit related to the agreed upon portions was recognized.

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 Sept. 30, 2017, 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.

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 Sept. 30, 2017, 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 Sept. 30, 2017, Minnesota had not proposed any material adjustments;
In 2016, Texas began an audit of years 2009 and 2010, and, in September 2017, began an audit of 2011. As of Sept. 30, 2017, Texas had not proposed any material adjustments;
In 2016, Wisconsin began an audit of years 2012 and 2013. As of Sept. 30, 2017, Wisconsin had not proposed any material adjustments; and
As of Sept. 30, 2017, 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)
 
Sept. 30, 2017
 
Dec. 31, 2016
Unrecognized tax benefit — Permanent tax positions
 
$
20.6

 
$
29.6

Unrecognized tax benefit — Temporary tax positions
 
22.2

 
104.1

Total unrecognized tax benefit
 
$
42.8

 
$
133.7



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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)
 
Sept. 30, 2017
 
Dec. 31, 2016
NOL and tax credit carryforwards
 
$
(29.2
)
 
$
(43.8
)

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, Texas and Wisconsin audits progress, and other state audits resume. As the IRS Appeals, Minnesota, Texas and Wisconsin audits progress, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $19 million.

The payable for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryforwards. A reconciliation of the beginning and ending amount of the payable for interest related to unrecognized tax benefits are as follows:

(Millions of Dollars)
 
Sept. 30, 2017
 
Dec. 31, 2016
Payable for interest related to unrecognized tax benefits at beginning of period
 
$
(3.4
)
 
$
(0.1
)
Interest income (expense) related to unrecognized tax benefits recorded during the period
 
1.9

 
(3.3
)
Payable for interest related to unrecognized tax benefits at end of period
 
$
(1.5
)
 
$
(3.4
)

No amounts were accrued for penalties related to unrecognized tax benefits as of Sept. 30, 2017 or Dec. 31, 2016.

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, 2016 and in Note 5 to Xcel Energy Inc.’s Quarterly Report on
Form 10-Q for the quarterly periods ended March 31, 2017 and June 30, 2017, appropriately represent, in all material respects, the current status of other rate matters, and are incorporated herein by reference.

NSP-Minnesota

Pending and Recently Concluded Regulatory Proceedings — Minnesota Public Utilities Commission (MPUC)
 
Minnesota 2016 Multi-Year Electric Rate Case — In June 2017, the MPUC issued a written order. NSP-Minnesota estimated the total rate increase to be approximately $245 million over the four-year period covering 2016-2019.

Key terms:
Four-year period covering 2016-2019;
Annual sales true-up with decoupling subject to a 3 percent cap;
Return on equity (ROE) of 9.2 percent and an equity ratio of 52.5 percent;
Nuclear related costs will not be considered provisional;
Continued use of all existing riders, however no new riders may be utilized during the four-year term;
Deferral of incremental 2016 property tax expense above a fixed threshold to 2018 and 2019;
Four-year stay-out provision for rate cases;
Property tax true-up mechanism for 2017-2019; and
Capital expenditure true-up mechanism for 2016-2019.

(Millions of Dollars, Incremental)
 
2016
 
2017
 
2018
 
2019
 
Total
Revenues
 
$
74.99

 
$
59.86

 
$

 
$
50.12

 
$
184.97

NSP-Minnesota’s sales true-up
 
59.95

 

 

 
(0.20
)
 
59.75

   Total rate impact
 
$
134.94

 
$
59.86

 
$

 
$
49.92

 
$
244.72



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In September 2017, the MPUC ordered NSP-Minnesota to collect final rates beginning March 1, 2017 (requested date was Jan. 1, 2017). As a result, NSP-Minnesota estimates the adjusted total rate increase to be approximately $240 million over the four-year period covering 2016-2019.

Annual Automatic Adjustment of Fuel Clause Charges — In May 2017, the MPUC voted to disallow approximately $4.4 million of replacement energy costs for the Prairie Island (PI) nuclear facility outages allocated to the Minnesota jurisdiction in 2015. This disallowance was recognized in the second quarter of 2017. In September 2017, the Minnesota Department of Commerce (DOC) recommended the MPUC should hold utilities responsible for incremental costs of replacement power incurred due to unplanned outages under certain circumstances. In addition, the DOC is continuing its review of nuclear costs and operations focusing on PI under the initial rate case and resource plan orders as well as the recently finalized rate case.

NSP-Wisconsin

Pending Regulatory Proceeding — Public Service Commission of Wisconsin (PSCW)

Wisconsin 2018 Electric and Natural Gas Rate Case In May 2017, NSP-Wisconsin filed a request with the PSCW to increase electric rates by $24.7 million, or 3.6 percent, and natural gas rates by $12.0 million, or 10.1 percent, effective Jan. 1, 2018. The rate filing is based on a 2018 forecast test year, a ROE of 10.0 percent, an equity ratio of 52.53 percent and a forecasted rate base of approximately $1.2 billion for the electric utility and $138.4 million for the natural gas utility.

In September 2017, the PSCW Staff and the intervenors filed testimony. The PSCW Staff recommended an electric rate increase of $10.9 million, or 1.6 percent, and a natural gas rate increase of $9.9 million, or 8.3 percent, based on a ROE of 9.8 percent and an equity ratio of 51.45 percent.

A PSCW decision is anticipated in December 2017 with new rates effective in January 2018.

PSCo

Pending Regulatory Proceedings — Colorado Public Utilities Commission (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, summarized below, is based on forecast test years (FTY) ending Dec. 31, a 10.0 percent ROE and an equity ratio of 55.25 percent.
Revenue Request (Millions of Dollars)
 
2018
 
2019
 
2020
 
2021
 
Total
Revenue request
 
$
74.6

 
$
74.9

 
$
59.7

 
$
35.7

 
$
244.9

Clean Air Clean Jobs Act (CACJA) revenue conversion to base rates (a)
 
90.4

 

 

 

 
90.4

Transmission Cost Adjustment (TCA) revenue conversion to base rates (a)
 
42.7

 

 

 

 
42.7

  Total (b)
 
$
207.7

 
$
74.9

 
$
59.7

 
$
35.7

 
$
378.0

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

 
$
7.1

 
$
7.3

 
$
7.4

 
 

(a) 
The roll-in of each of the TCA and CACJA rider revenues into base rates will not have an impact on total customer bills or total revenue as these costs are already being recovered through a rider. Transmission investments for 2019 through 2021 will be recovered through the TCA rider.

(b) 
This base rate request does not include the impacts associated with the renewable energy standard adjustment and retail electric commodity adjustment for the Rush Creek wind investments or any impacts of the proposed Colorado Energy Plan.

Final rates are expected to be effective in June 2018. PSCo also proposed a stay-out provision and earnings test through 2021.

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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
 
$
63.2

 
$
32.9

 
$
42.9

 
$
139.0

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

 
93.9

 

 
93.9

Total
 
$
63.2

 
$
126.8

 
$
42.9

 
$
232.9

 
 
 
 
 
 
 
 
 
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 total revenue as these costs are already being recovered through the rider. PSCo plans to request new PSIA rates for 2018 in November 2017. 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, several parties filed answer testimony. The CPUC Staff (Staff) and the Office of Consumer Counsel (OCC), recommended a single 2016 historic test year (HTY), based on an average 13-month rate base, and opposed a multi-year plan (MYP). The Staff and OCC recommended an equity capital structure of 48.73 percent and 51.2 percent, respectively. Both the Staff and the OCC recommended 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 base rates, subject to a future rate case.

The following represents adjustments to PSCo’s filed request made by Staff and OCC for 2018:
(Millions of Dollars)
 
Staff
 
OCC
Filed 2018 new revenue request
 
$
63.2

 
$
63.2

Impact of the change in test year
 
4.4

 
4.4

PSCo’s filed 2016 HTY
 
$
67.6

 
$
67.6

 
 
 
 
 
Recommended adjustments:
 
 
 
 
ROE (9.0 percent)
 
(13.5
)
 
(13.5
)
Capital structure and cost of debt
 
(10.2
)
 
(7.5
)
Change in amortization period
 
(5.4
)
 

Prepaid pension and retiree medical assets
 
(5.2
)
 

Change from 2016 year end to average rate base
 
(4.8
)
 
(4.8
)
Other, net
 
(5.0
)
 
(5.5
)
Total adjustments
 
$
(44.1
)
 
$
(31.3
)
 
 
 
 
 
Total recommended rate increase
 
$
23.5

 
$
36.3


The next steps in the procedural schedule are as follows:

Rebuttal testimony — Nov. 3, 2017;
Intervenor sur-rebuttal testimony — Nov. 15, 2017;
Hearings — Dec. 11 - 15 and 18 - 19, 2017; and
Statements of position — Jan. 19, 2018.

Interim rates, subject to refund, are expected to be effective Jan. 1, 2018. A final decision by the CPUC is anticipated in March 2018.

Annual Electric Earnings Test — PSCo must share with customers earnings that exceed the authorized ROE of 9.83 percent for 2015 through 2017, as part of an annual earnings test. The current estimate of the 2017 earnings test, based on annual forecasted information, did not result in the recognition of a liability as of Sept. 30, 2017.


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Table of Contents


SPS

Pending Regulatory Proceedings — Public Utility Commission of Texas (PUCT)

Appeal of the Texas 2015 Electric Rate Case Decision — In 2014, SPS had requested an overall retail electric revenue rate increase of $42.1 million. In 2015, the PUCT approved an overall rate decrease of approximately $4.0 million, net of rate case expenses. In April 2016, SPS filed an appeal, with the Texas State District Court, of 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 March 2017, the Travis County District Court denied SPS’ appeal.  In April 2017, SPS appealed the District Court’s decision to the Court of Appeals.

Texas 2017 Electric Rate Case — In August 2017, SPS filed a $66.4 million, or 7.1 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 the 12-month period ended June 30, 2017, with the final three months based on estimates, a requested ROE of 10.25 percent, a Texas retail electric rate base of approximately $1.9 billion and an equity ratio of 53.97 percent.

In October 2017, SPS revised its request to $54.6 million, or 5.8 percent, which reflects updated actual results. In addition, approximately $4.4 million of rate case expenses was bifurcated into a separate docket.

The following table summarizes SPS’ revised rate increase request:
Revenue Request (Millions of Dollars)
 
 
Incremental revenue request
 
$
69.2

Transmission Cost Recovery Factor (TCRF) revenue conversion to base rates (a)
 
(14.6
)
  Net revenue increase request
 
$
54.6


(a) 
The roll-in of the TCRF rider revenue into base rates will not have an impact on customer bills or total 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.

Key dates in the procedural schedule are as follows:

Intervenors’ direct testimony — Feb. 22, 2018;
PUCT Staff direct testimony — March 1, 2018;
PUCT Staff and intervenors’ cross-rebuttal testimony — March 22, 2018;
SPS’ rebuttal testimony — March 23, 2018;
Hearings — April 10 - 20, 2018; and
Statutory deadline — Aug. 31, 2018.

The final rates are expected to be effective retroactive to Jan. 23, 2018 through a customer surcharge. A PUCT decision is expected in the third quarter of 2018.

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

New Mexico 2016 Electric Rate Case — In November 2016, SPS filed an electric rate case with the NMPRC seeking an increase in base rates of approximately $41.4 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 April 2017, the NMPRC dismissed SPS’ rate case. In May 2017, SPS filed a notice of appeal to the New Mexico Supreme Court. A decision from the New Mexico Supreme Court is not expected until the second or third quarter of 2018.

SPS plans to file another base rate case by November 2017 utilizing a HTY ending June 2017.


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Table of Contents


Pending Regulatory Proceeding — Federal Energy Regulatory Commission (FERC)

Midcontinent Independent System Operator, Inc. (MISO) 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 December 2015, an administrative law judge (ALJ) recommended the FERC approve a base ROE of 10.32 percent for the MISO TOs. The ALJ found the existing 12.38 percent ROE to be unjust and unreasonable. The recommended 10.32 percent ROE applied a FERC ROE policy adopted in a June 2014 order (Opinion 531). The FERC approved the ALJ recommended 10.32 percent base ROE in an order issued in September 2016. 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 adder was filed with the FERC, resulting in a second period of potential refund from Feb. 12, 2015 to May 11, 2016. In June 2016, the ALJ recommended a ROE of 9.7 percent, applying the methodology adopted by the FERC in Opinion 531. A final FERC decision on the second ROE complaint was expected later in 2017, but in April 2017, the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit) by opinion, 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. The MISO TOs are evaluating the impact of the D.C. Circuit ruling on the November 2013 and February 2015 ROE complaints. In September 2017, certain MISO TOs (not including NSP-Minnesota and NSP-Wisconsin) filed a motion to dismiss the second ROE complaint. The motion to dismiss is pending FERC action.

As of Sept. 30, 2017, NSP-Minnesota has processed the refunds for the Nov. 12, 2013 to Feb. 11, 2015 complaint period based on the 10.32 percent ROE provided in the September 2016 FERC order. NSP-Minnesota has also 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 July 2016, the FERC granted SPP’s request for a waiver to allow SPP to recover the charges not billed since 2008.  In November 2016, SPP billed SPS a net amount, for the period from 2008 through August 2016, of $12.8 million for these charges, to be paid over a five-year period commencing November 2016. SPP is also billing SPS ongoing charges of approximately $0.5 million per month. On the retail level, in October 2016, SPS filed applications for deferred accounting and future recovery of related costs in New Mexico and Texas.  In December 2016, SPS’ New Mexico application was consolidated with its base rate case, but the NMPRC dismissed that rate case in April 2017. SPS will seek recovery of these SPP charges in its next New Mexico base rate case by November 2017. In March 2017, SPS withdrew its Texas application and is now seeking to recover these SPP charges in its pending rate case filed in August 2017.

In October 2017, SPS filed a complaint against SPP regarding the amounts billed on and after November 2016 asserting that SPP has assessed upgrade charges to SPS even where SPS’ transmission service was not dependent upon the upgrade as required by the SPP OATT.  If SPS’ complaint results in additional charges or refunds, SPS will seek to recover or refund the differential in future rate proceedings. Also in October 2017, SPP made adjustments to its previous calculations of upgrade charges to SPP customers, and the impact was immaterial to SPS.

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, 2016, and in Notes 5 and 6 to the
consolidated financial statements included in Xcel Energy Inc.’s Quarterly Reports on Form 10-Q for the quarterly periods ended March 31, 2017 and June 30, 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.


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Table of Contents


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 megawatts (MW) of capacity under long-term PPAs as of Sept. 30, 2017 and Dec. 31, 2016, 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 Sept. 30, 2017 and Dec. 31, 2016, 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)
 
Sept. 30, 2017
 
Dec. 31, 2016
Guarantees issued and outstanding
 
$
19.1

 
$
18.8

Current exposure under these guarantees
 

 
0.1

Bonds with indemnity protection
 
51.9

 
43.0


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 Ashland/Northern States Power Lakefront Superfund Site (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 2012, NSP-Wisconsin agreed to remediate the Phase I Project Area (which includes the Upper Bluff and Kreher Park areas of the Site), under a settlement agreement with the United States Environmental Protection Agency (EPA). In January 2017, NSP-Wisconsin agreed to remediate the Phase II Project Area (the Sediments), under a settlement agreement with the EPA. The settlement was approved by the U.S. District Court for the Western District of Wisconsin. NSP-Wisconsin initiated field activities to perform a full scale wet dredge remedy of the Sediments in 2017 and anticipates completion of restoration activities in 2018.

The current remediation cost estimate for the entire site (both the Phase I Project Area and the Sediments) is approximately $162.9 million, of which approximately $131.8 million has been spent. As of Sept. 30, 2017 and Dec. 31, 2016, NSP-Wisconsin had recorded a total liability of $31.1 million and $64.3 million, respectively, for the entire site.


17

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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 May 2017, NSP-Wisconsin filed a natural gas rate case which included recovery of additional expenses associated with remediating the Site. If approved, the annual recovery of MGP clean-up costs would increase from $12.4 million in 2017 to $18.1 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 from the right-of-way and commenced an investigation of the historic MGP and adjacent properties (the Fargo MGP Site). NSP-Minnesota has recommended that targeted source removal of impacted soils and historic MGP infrastructure should be performed. The North Dakota Department of Health approved NSP-Minnesota’s proposed cleanup plan in January 2017. It is anticipated that remediation activities will be performed in 2018, although the timing and final scope of remediation is dependent on whether reasonable access is provided to NSP-Minnesota to perform and implement the approved cleanup plan. Access agreements have been reached with a majority of the property owners in the area to perform the work. 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 January 2018.

As of Sept. 30, 2017 and Dec. 31, 2016, NSP-Minnesota had recorded a liability of $16.2 million and $11.3 million, respectively, for the Fargo MGP Site. The current cost estimate for the remediation of the site is approximately $23.0 million, of which approximately $6.8 million has been spent. In December 2015, the North Dakota Public Service Commission (NDPSC) approved NSP-Minnesota’s request to defer costs associated with the Fargo MGP Site, resulting in deferral of all investigation and response costs with the exception of approximately 12 percent allocable to the Minnesota jurisdiction. Uncertainties related to the liability recognized include obtaining access to perform the approved remediation (including the prospective purchase of the historic MGP property), and the potential for contributions from entities that may be identified as PRPs.

Other MGP and Landfill Sites — Xcel Energy is currently involved in investigating and/or remediating several other MGP and landfill sites. Xcel Energy has identified eleven sites across its service territories in addition to the sites in Ashland, Wis. and Fargo, N.D., where former MGP or landfill disposal activities have or may have resulted in site contamination and are under current investigation and/or remediation. At some or all of these sites, there are other parties that may have responsibility for some portion of any remediation. Xcel Energy anticipates that the majority of the investigation or remediation at these sites will continue through at least 2018. Xcel Energy had accrued $4.5 million and $2.0 million for these sites as of Sept. 30, 2017 and Dec. 31, 2016, respectively. There may be insurance recovery and/or recovery from other PRPs to offset any costs incurred. Xcel Energy anticipates that any significant amounts incurred will be recovered from customers.

Environmental Requirements

Water and Waste
Federal Clean Water Act (CWA) Waters of the United States Rule In 2015, the EPA and the U.S. Army Corps of Engineers (Corps) published a final rule that significantly expanded the types of water bodies regulated under the CWA and broadened the scope of waters subject to federal jurisdiction. In October 2015, the U.S. Court of Appeals for the Sixth Circuit issued a nationwide stay of the final rule and subsequently ruled that it, rather than the federal district courts, had jurisdiction over challenges to the rule.  In January 2017, the U.S. Supreme Court agreed to resolve the dispute as to which court should hear challenges to the rule. A ruling is expected in the first quarter of 2018.

In February 2017, President Trump issued an executive order requiring the EPA and the Corps to review and revise the final rule. On June 27, 2017, the agencies issued a proposed rule that rescinds the 2015 final rule and reinstates the prior 1986 definition of “Water of the U.S.” The agencies are also undertaking a rulemaking to develop a new definition of “Waters of the U.S.”

Federal CWA Effluent Limitations Guidelines (ELG) In 2015, the EPA issued a final ELG rule for power plants that use coal, natural gas, oil or nuclear materials as fuel and discharge treated effluent to surface waters as well as utility-owned landfills that receive coal combustion residuals. In September 2017, the EPA delayed the compliance date for flue gas desulfurization wastewater and bottom ash transport water until November 2020 while the agency conducts a rulemaking process to potentially revise the effluent limitations and pretreatment standards for these waste streams.


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Air
Greenhouse Gas (GHG) Emission Standard for Existing Sources (Clean Power Plan or CPP) — In 2015, the EPA issued its final rule for existing power plants.  Among other things, the rule requires that state plans include enforceable measures to ensure emissions from existing power plants achieve the EPA’s state-specific interim (2022-2029) and final (2030 and thereafter) emission performance targets. 

The CPP was challenged by multiple parties in the D.C. Circuit Court.  In February 2016, the U.S. Supreme Court issued an order staying the final CPP rule. In September 2016, the D.C. Circuit Court heard oral arguments in the consolidated challenges to the CPP. The stay will remain in effect until the D.C. Circuit Court reaches its decision and the U.S. Supreme Court either declines to review the lower court’s decision or reaches a decision of its own.

In March 2017, President Trump signed an executive order requiring the EPA Administrator to review the CPP rule and if appropriate, publish proposed rules suspending, revising or rescinding it. Accordingly, the EPA has requested that the D.C. Circuit Court hold the litigation in abeyance until the EPA completes its work under the executive order. The D.C. Circuit granted the EPA’s request and is holding the litigation in abeyance, while considering briefs by the parties on whether the court should remand the challenges to the EPA rather than holding them in abeyance, determining whether and how the court continues or ends the stay that currently applies to the CPP.

In October 2017, the EPA published a proposed rule to repeal the CPP, based on an analysis that the CPP exceeds the EPA’s statutory authority under the Clean Air Act (CAA). The EPA will take public comment on the proposal for 60 days. The EPA stated it has not yet determined whether it will promulgate a new rule to regulate GHG emissions from existing electric generating units.

Regional Haze Rules — The regional haze program is designed to address widespread haze that results from emissions from a multitude of sources. The Best Available Retrofit Technology (BART) requirements of the EPA’s regional haze rules require the installation and operation of emission controls for industrial facilities emitting air pollutants that reduce visibility in national parks and wilderness areas. Under BART, regional haze plans identify facilities that will have to reduce Sulfur Dioxide (SO2), Nitrogen Oxide (NOx) and particulate matter emissions and set emission limits for those facilities. BART requirements can also be met through participation in interstate emission trading programs such as the Clean Air Interstate Rule (CAIR) and its successor, Cross-State Air Pollution Rule (CSAPR). The requirements of the regional haze plans developed by Minnesota and Colorado that apply to NSP-Minnesota and PSCo have been fully approved and implemented in those states. States are required to revise their plans every ten years. The next plans for Minnesota and Colorado will be due in 2021. Texas’ first regional haze plan has undergone federal review as described below.
 
BART Determinations for Texas: Texas developed a State Implementation Plan (SIP) that found the CAIR equal to BART for electric generating units. As a result, no additional controls beyond CAIR compliance would have been required. In 2014, the EPA proposed to approve the BART portion of the SIP, with substitution of CSAPR compliance for Texas’ reliance on CAIR. In January 2016, the EPA adopted a final rule that deferred its approval of CSAPR compliance as BART until the EPA considered further adjustments to CSAPR emission budgets under the D.C. Circuit Court’s remand of the Texas SO2 emission budgets. The EPA then published a proposed rule in January 2017 that could have had the effect of requiring installation of dry scrubbers to reduce SO2 emissions from Harrington Units 1 and 2. Investment costs associated with dry scrubbers for Harrington Units 1 and 2 could have been approximately $400 million. In September 2017, the EPA issued a final rule adopting a Texas only SO2 trading program as a BART Alternative. The program allocated SO2 allowances to electric generating units in Texas, including all three Harrington units and both Tolk units, consistent with their allocation under CSAPR, resulting in an emissions budget for Texas that is consistent with the EPA’s 2012 rule. SPS expects the allowance allocations to be sufficient for SO2 emissions from Harrington and Tolk units in 2019 and future years. The anticipated costs of compliance are not expected to have a material impact on the results of operations, financial position or cash flows; and SPS believes that compliance costs would be recoverable through regulatory mechanisms.

Reasonable Progress Rule: In January 2016, the EPA adopted a final rule establishing a federal implementation plan for the state of Texas, which imposed SO2 emission limitations that reflect the installation of dry scrubbers on Tolk Units 1 and 2, with compliance required by February 2021. Investment costs associated with dry scrubbers could be approximately $600 million. SPS appealed the EPA’s decision and requested a stay of the final rule. The United States Court of Appeals for the Fifth Circuit (Fifth Circuit) granted the stay. In March 2017, the Fifth Circuit remanded the rule to the EPA for reconsideration, while leaving the stay in effect. The Fifth Circuit is now holding the case in abeyance until the EPA completes its reconsideration of the rule. In the final BART rule that affects Tolk and Harrington described above, the EPA noted that it will address the remanded rule in a future action. Such a rule will address whether further SO2 emission reductions are needed at Tolk to address the “reasonable progress” requirements of the regional haze program. The risk of these controls being imposed along with the risk of investments to provide additional cooling water to Tolk have caused SPS to seek to decrease the remaining depreciable life of the Tolk units.


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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. In areas where Xcel Energy operates, current monitored air quality concentrations comply with the new standard in the Twin Cities Metropolitan Area in Minnesota and meet the 70 ppb level in the Texas panhandle. In documents issued with the new standard, the EPA projects that both areas will meet the new standard. The Denver Metropolitan Area is currently not meeting the prior ozone standard and will therefore not meet the new, more stringent standard, however PSCo’s scheduled retirement of coal fired plants in Denver that began in 2011 and was completed in August 2017, should help in any plan to mitigate non-attainment. In August 2017, the EPA withdrew its prior decision delaying designations of nonattainment areas under the 2015 ozone NAAQS to October 2018. The CAA requires areas to be designated within two years after a revision to the NAAQS but allows a one year extension if the EPA has insufficient information on which to base a decision. The EPA is now re-assessing to what extent it has sufficient information to make designations in October 2017 and whether in some cases an extension is still necessary.

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 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 one 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.” A motion for class certification was denied and plaintiffs have appealed the ruling to the U.S. Court of Appeals for the Ninth Circuit (Ninth Circuit). Motions for summary judgment were granted by the MDL judge in favor of e prime and Xcel Energy in Sinclair Oil and Farmland. Plaintiffs in both cases appealed this decision to the Ninth Circuit. Motions for summary judgment were also filed by defendants, including e prime, in all of the remaining lawsuits. These motions were denied and e prime subsequently filed an appeal in September 2017. Dates for all matters pending before the Ninth Circuit have not been scheduled. 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 Denver State 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 involves claims by over fifty developers. In May 2016, the district court granted PSCo’s motion to dismiss the lawsuit, concluding that jurisdiction over this dispute resides with the CPUC. In June 2016, DRC appealed the district court’s dismissal of the lawsuit, and the Colorado Court of Appeals affirmed the lower court decision in favor of PSCo. In July 2017, DRC filed a petition to appeal the decision with the Colorado Supreme Court. It is uncertain whether the Colorado Supreme Court will grant the petition. DRC also brought a proceeding before the CPUC as assignee on behalf of two developers, Ryland Homes and Richmond Homes of Colorado.  In March 2016, the ALJ issued an order rejecting DRC’s claims for additional allowances and refunds.  In June 2016, the ALJ’s determination was approved by the CPUC.  DRC did not file a request for reconsideration before the CPUC contesting the decision, but filed an appeal in the Denver District Court in August 2016.  In July 2017, a stipulation to dismiss this lawsuit with prejudice was filed on behalf of all parties and granted by the Denver District Court.


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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.

Commercial Paper — 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. Commercial paper outstanding for Xcel Energy was as follows:
(Amounts in Millions, Except Interest Rates)
 
Three Months Ended  
 Sept. 30, 2017
 
Year Ended  
 Dec. 31, 2016
Borrowing limit
 
$
2,750

 
$
2,750

Amount outstanding at period end
 
514

 
392

Average amount outstanding
 
679

 
485

Maximum amount outstanding
 
867

 
1,183

Weighted average interest rate, computed on a daily basis
 
1.50
%
 
0.74
%
Weighted average interest rate at period end
 
1.53

 
0.95


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 Sept. 30, 2017 and Dec. 31, 2016, there were $28 million and $19 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 Sept. 30, 2017, 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.
 
$
1,000

 
$
422

 
$
578

PSCo
 
700

 
4

 
696

NSP-Minnesota
 
500

 
21

 
479

SPS
 
400

 
3

 
397

NSP-Wisconsin
 
150

 
92

 
58

Total
 
$
2,750

 
$
542

 
$
2,208

(a) 
These credit facilities expire in June 2021.
(b) 
Includes outstanding commercial paper and letters of credit.


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All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under the respective credit facilities. Xcel Energy Inc. and its subsidiaries had no direct advances on the credit facilities outstanding as of Sept. 30, 2017 and Dec. 31, 2016.

Long-Term Borrowings

During 2017, Xcel Energy Inc. and its utility subsidiaries issued the following:

PSCo issued $400 million of 3.80 percent first mortgage bonds due June 15, 2047;
SPS issued $450 million of 3.70 percent first mortgage bonds due Aug. 15, 2047; and
NSP-Minnesota issued $600 million of 3.60 percent first mortgage bonds due Sept. 15, 2047.

Debt Redemption

On Aug. 30, 2017, SPS reacquired $250 million of debt with a coupon rate of 8.75 percent and an original maturity date of Dec. 1, 2018. The redemption resulted in payment of an early redemption premium of $21.6 million which was deferred as a regulatory asset.
On Sept. 29, 2017, NSP-Minnesota reacquired $500 million of debt with a coupon rate of 5.25 percent and an original maturity date of March 1, 2018. The redemption resulted in payment of an early redemption premium of $7.9 million which was deferred as a regulatory asset.

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.


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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 PI nuclear generating plants. The fund contains cash equivalents, debt securities, equity securities and other investments – all classified as available-for-sale. 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 other-than-temporary impairments, are deferred as a component of the regulatory asset for nuclear decommissioning.

Unrealized gains for the nuclear decommissioning fund were $511.7 million and $378.6 million as of Sept. 30, 2017 and Dec. 31, 2016, respectively, and unrealized losses and amounts recorded as other-than-temporary impairments were $10.3 million and $46.9 million as of Sept. 30, 2017 and Dec. 31, 2016, 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 Sept. 30, 2017 and Dec. 31, 2016:
 
 
Sept. 30, 2017
 
 
 
 
Fair Value
(Thousands of Dollars)
 
Cost
 
Level 1
 
Level 2
 
Level 3
 
Investments Measured at NAV (b)
 
Total
Nuclear decommissioning fund (a)
 
 
 
 
 
 
 
 
 
 
 
 
Cash equivalents
 
$
32,727

 
$
32,727

 
$

 
$

 
$

 
$
32,727

Commingled funds:
 
 
 
 
 
 
 
 
 
 
 
 
Non U.S. equities
 
257,487

 
204,502

 

 

 
86,654

 
291,156

Emerging market debt funds
 
97,285

 

 

 

 
106,842

 
106,842

Private equity investments
 
139,185

 

 

 

 
192,098

 
192,098

Real estate
 
129,219

 

 

 

 
195,506

 
195,506

Other commingled funds
 
146,179

 
14,964

 

 

 
145,313

 
160,277

Debt securities:
 
 
 
 
 
 
 
 
 
 
 
 
Government securities
 
45,310

 

 
44,944

 

 

 
44,944

U.S. corporate bonds
 
251,138

 

 
252,868

 

 

 
252,868

Non U.S. corporate bonds
 
46,245

 

 
46,611

 

 

 
46,611

Equity securities:
 
 
 
 
 
 
 
 
 
 
 
 
U.S. equities
 
258,075

 
509,564

 

 

 

 
509,564

Non U.S. equities
 
152,575

 
224,139

 

 

 

 
224,139

Total
 
$
1,555,425

 
$
985,896

 
$
344,423

 
$

 
$
726,413

 
$
2,056,732

(a) 
Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $131.8 million of equity investments in unconsolidated subsidiaries and $111.7 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, 2016
 
 
 
 
Fair Value
(Thousands of Dollars)
 
Cost
 
Level 1
 
Level 2
 
Level 3
 
Investments Measured at NAV (b)
 
Total
Nuclear decommissioning fund (a)
 
 
 
 
 
 
 
 
 
 
 
 
Cash equivalents
 
$
20,379

 
$
20,379

 
$

 
$

 
$

 
$
20,379

Commingled funds:
 
 
 
 
 
 
 
 
 
 
 
 
Non U.S. equities
 
260,877

 
133,126

 

 

 
112,233

 
245,359

Emerging market debt funds
 
93,597

 

 

 

 
97,543

 
97,543

Commodity funds
 
106,571

 

 

 

 
92,091

 
92,091

Private equity investments
 
132,190

 

 

 

 
190,462

 
190,462

Real estate
 
128,630

 

 

 

 
187,647

 
187,647

Other commingled funds
 
151,048

 

 

 

 
159,489

 
159,489

Debt securities:
 
 
 
 
 
 
 
 
 
 
 
 
Government securities
 
32,764

 

 
31,965

 

 

 
31,965

U.S. corporate bonds
 
104,913

 

 
105,772

 

 

 
105,772

Non U.S. corporate bonds
 
21,751

 

 
21,672

 

 

 
21,672

Municipal bonds
 
13,609

 

 
13,786

 

 

 
13,786

Mortgage-backed securities
 
2,785

 

 
2,816

 

 

 
2,816

Equity securities:
 
 
 
 
 
 
 
 
 
 
 
 
U.S. equities
 
270,779

 
473,400

 

 

 

 
473,400

Non U.S. equities
 
189,100

 
218,381

 

 

 

 
218,381

Total
 
$
1,528,993

 
$
845,286

 
$
176,011

 
$

 
$
839,465

 
$
1,860,762

(a) 
Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $132.8 million of equity investments in unconsolidated subsidiaries and $98.3 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.

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For the three and nine months ended Sept. 30, 2017 and 2016 there were no Level 3 nuclear decommissioning fund investments and no transfers of amounts between levels.

The following table summarizes the final contractual maturity dates of the debt securities in the nuclear decommissioning fund, by asset class, as of Sept. 30, 2017:
 
 
Final Contractual Maturity
(Thousands 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
 
$

 
$
1,275

 
$
2,303

 
$
41,366

 
$
44,944

U.S. corporate bonds
 
3,834

 
64,119

 
150,741

 
34,174

 
252,868

Non U.S. corporate bonds
 

 
13,793

 
26,651

 
6,167