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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 Sept. 30, 2016
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, or a smaller reporting company.  See the definitions of “large accelerated filer”, “accelerated filer” and “smaller reporting 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)
 
 

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 24, 2016
Common Stock, $2.50 par value
 
507,952,795 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 4 —

Item 5 —

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).


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
 
2016
 
2015
 
2016
 
2015
Operating revenues
 
 
 
 
 
 
 
Electric
$
2,799,964

 
$
2,667,480

 
$
7,209,225

 
$
7,105,803

Natural gas
221,956

 
216,019

 
1,046,544

 
1,216,146

Other
18,227

 
17,813

 
56,500

 
56,716

Total operating revenues
3,040,147

 
2,901,312

 
8,312,269

 
8,378,665

 
 
 
 
 
 
 
 
Operating expenses
 
 
 
 
 
 
 
Electric fuel and purchased power
1,037,263

 
1,014,726

 
2,755,083

 
2,869,563

Cost of natural gas sold and transported
67,566

 
66,071

 
469,754

 
665,109

Cost of sales — other
8,648

 
8,203

 
25,225

 
26,416

Operating and maintenance expenses
590,009

 
565,984

 
1,764,397

 
1,746,093

Conservation and demand side management program expenses
63,914

 
57,314

 
177,266

 
165,260

Depreciation and amortization
328,503

 
280,121

 
971,057

 
827,821

Taxes (other than income taxes)
117,190

 
123,081

 
400,982

 
389,438

Loss on Monticello life cycle management/extended power uprate project

 

 

 
129,463

Total operating expenses
2,213,093

 
2,115,500

 
6,563,764

 
6,819,163

 
 
 
 
 
 
 
 
Operating income
827,054

 
785,812

 
1,748,505

 
1,559,502

 
 
 
 
 
 
 
 
Other income, net
578

 
1,626

 
6,388

 
5,748

Equity earnings of unconsolidated subsidiaries
9,701

 
8,162

 
32,500

 
24,360

Allowance for funds used during construction — equity
17,199

 
15,427

 
45,042

 
40,728

 
 
 
 
 
 
 
 
Interest charges and financing costs
 
 
 
 
 
 
 
Interest charges — includes other financing costs of $6,060
$6,260, $19,026 and $17,819, respectively
165,857

 
152,566

 
485,280

 
441,728

Allowance for funds used during construction — debt
(7,532
)
 
(7,031
)
 
(20,206
)
 
(19,340
)
Total interest charges and financing costs
158,325

 
145,535

 
465,074

 
422,388

 
 
 
 
 
 
 
 
Income before income taxes
696,207

 
665,492

 
1,367,361

 
1,207,950

Income taxes
238,412

 
239,029

 
471,459

 
432,490

Net income
$
457,795

 
$
426,463

 
$
895,902

 
$
775,460

 
 
 
 
 
 
 
 
Weighted average common shares outstanding:
 
 
 
 
 
 
 
Basic
508,941

 
508,031

 
508,840

 
507,585

Diluted
509,566

 
508,427

 
509,396

 
507,976

 
 
 
 
 
 
 
 
Earnings per average common share:
 
 
 
 
 
 
 
Basic
$
0.90

 
$
0.84

 
$
1.76

 
$
1.53

Diluted
0.90

 
0.84

 
1.76

 
1.53

 
 
 
 
 
 
 
 
Cash dividends declared per common share
$
0.34

 
$
0.32

 
$
1.02

 
$
0.96

 
 
 
 
 
 
 
 
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
 
2016
 
2015
 
2016
 
2015
Net income
$
457,795

 
$
426,463

 
$
895,902

 
$
775,460

 
 
 
 
 
 
 
 
Other comprehensive income
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Pension and retiree medical benefits:
 
 
 
 
 
 
 
Amortization of losses included in net periodic benefit cost,
net of tax of $536, $559, $1,635 and $1,689, respectively
878

 
884

 
1,954

 
2,643

 
 
 
 
 
 
 
 
Derivative instruments:
 
 
 
 
 
 
 
Net fair value (decrease) increase, net of tax of $(2), $(28), $3 and $(24), respectively
(4
)
 
(42
)
 
4

 
(35
)
Reclassification of losses to net income, net of tax of
   $588, $446, $1,786 and $1,210, respectively
960

 
706

 
2,834

 
1,891

 
956

 
664

 
2,838

 
1,856

Marketable securities:


 
 
 
 
 
 
Net fair value (decrease) increase, net of tax of $0, $0, $0 and $1, respectively

 
(1
)
 

 
1

 
 
 
 
 
 
 
 
Other comprehensive income
1,834

 
1,547

 
4,792

 
4,500

Comprehensive income
$
459,629

 
$
428,010

 
$
900,694

 
$
779,960

 
 
 
 
 
 
 
 
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
 
2016
 
2015
Operating activities
 
 
 
Net income
$
895,902

 
$
775,460

Adjustments to reconcile net income to cash provided by operating activities:
 
 
 
Depreciation and amortization
982,682

 
841,360

Conservation and demand side management program amortization
3,089

 
4,063

Nuclear fuel amortization
89,475

 
82,627

Deferred income taxes
479,100

 
429,091

Amortization of investment tax credits
(3,920
)
 
(4,151
)
Allowance for equity funds used during construction
(45,042
)
 
(40,728
)
Equity earnings of unconsolidated subsidiaries
(32,500
)
 
(24,360
)
Dividends from unconsolidated subsidiaries
34,502

 
29,434

Share-based compensation expense
29,872

 
29,765

Loss on Monticello life cycle management/extended power uprate project

 
129,463

Net realized and unrealized hedging and derivative transactions
3,307

 
18,808

Other
(266
)
 

Changes in operating assets and liabilities:
 
 
 
Accounts receivable
(29,585
)
 
85,276

Accrued unbilled revenues
87,015

 
182,425

Inventories
(6,203
)
 
(47,659
)
Other current assets
80,566

 
72,445

Accounts payable
50,526

 
(116,137
)
Net regulatory assets and liabilities
3,911

 
116,068

Other current liabilities
(76,011
)
 
60,293

Pension and other employee benefit obligations
(96,350
)
 
(82,013
)
Change in other noncurrent assets
(11,815
)
 
2,374

Change in other noncurrent liabilities
(25,401
)
 
(53,982
)
Net cash provided by operating activities
2,412,854

 
2,489,922

 
 
 
 
Investing activities
 
 
 
Utility capital/construction expenditures
(2,186,483
)
 
(2,186,369
)
Proceeds from insurance recoveries
1,595

 
27,237

Allowance for equity funds used during construction
45,042

 
40,728

Purchases of investment securities
(390,031
)
 
(773,260
)
Proceeds from the sale of investment securities
327,378

 
753,924

Investments in WYCO Development LLC and other
(3,962
)
 
(832
)
Other, net
204

 
(676
)
Net cash used in investing activities
(2,206,257
)
 
(2,139,248
)
 
 
 
 
Financing activities
 
 
 
Repayments of short-term borrowings, net
(480,000
)
 
(955,500
)
Proceeds from issuance of long-term debt
1,632,642

 
1,627,190

Repayments of long-term debt
(580,167
)
 
(250,644
)
Proceeds from issuance of common stock

 
5,298

Purchase of common stock for settlement of equity awards
(2,810
)
 

Dividends paid
(507,817
)
 
(452,217
)
Net cash provided by (used in) financing activities
61,848

 
(25,873
)
 
 
 
 
Net change in cash and cash equivalents
268,445

 
324,801

Cash and cash equivalents at beginning of period
84,940

 
79,608

Cash and cash equivalents at end of period
$
353,385

 
$
404,409

 
 
 
 
Supplemental disclosure of cash flow information:
 
 
 
Cash paid for interest (net of amounts capitalized)
$
(461,302
)
 
$
(424,878
)
Cash received for income taxes, net
61,245

 
57,632

 
 
 
 
Supplemental disclosure of non-cash investing and financing transactions:
 
 
 
Property, plant and equipment additions in accounts payable
$
221,155

 
$
284,864

Issuance of common stock for reinvested dividends and equity awards
17,527

 
39,169

 
 
 
 
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, 2016
 
Dec. 31, 2015
Assets
 
 
 
Current assets
 
 
 
Cash and cash equivalents
$
353,385

 
$
84,940

Accounts receivable, net
754,248

 
724,606

Accrued unbilled revenues
567,852

 
654,867

Inventories
614,908

 
608,584

Regulatory assets
317,611

 
344,630

Derivative instruments
42,860

 
33,842

Deferred income taxes
195,303

 
140,219

Prepaid taxes
107,210

 
163,023

Prepayments and other
122,786

 
155,734

Total current assets
3,076,163

 
2,910,445

 
 
 
 
Property, plant and equipment, net
32,206,696

 
31,205,851

 
 
 
 
Other assets
 
 
 
Nuclear decommissioning fund and other investments
2,048,455

 
1,902,995

Regulatory assets
2,874,351

 
2,858,741

Derivative instruments
51,369

 
51,083

Other
67,716

 
32,581

Total other assets
5,041,891

 
4,845,400

Total assets
$
40,324,750

 
$
38,961,696

 
 
 
 
Liabilities and Equity
 
 
 
Current liabilities
 
 
 
Current portion of long-term debt
$
709,567

 
$
657,021

Short-term debt
366,000

 
846,000

Accounts payable
916,534

 
960,982

Regulatory liabilities
228,721

 
306,830

Taxes accrued
422,437

 
438,189

Accrued interest
155,005

 
166,829

Dividends payable
172,704

 
162,410

Derivative instruments
25,201

 
29,839

Other
457,803

 
490,197

Total current liabilities
3,453,972

 
4,058,297

 
 
 
 
Deferred credits and other liabilities
 
 
 
Deferred income taxes
6,851,873

 
6,293,661

Deferred investment tax credits
64,499

 
68,419

Regulatory liabilities
1,367,557

 
1,332,889

Asset retirement obligations
2,703,396

 
2,608,562

Derivative instruments
154,650

 
168,311

Customer advances
216,978

 
228,999

Pension and employee benefit obligations
843,739

 
941,002

Other
277,561

 
261,756

Total deferred credits and other liabilities
12,480,253

 
11,903,599

 
 
 
 
Commitments and contingencies


 


Capitalization
 
 
 
Long-term debt
13,402,583

 
12,398,880

Common stock — 1,000,000,000 shares authorized of $2.50 par value; 507,952,795 and
507,535,523 shares outstanding at Sept. 30, 2016 and Dec. 31, 2015, respectively
1,269,882

 
1,268,839

Additional paid in capital
5,898,896

 
5,889,106

Retained earnings
3,924,125

 
3,552,728

Accumulated other comprehensive loss
(104,961
)
 
(109,753
)
Total common stockholders’ equity
10,987,942

 
10,600,920

Total liabilities and equity
$
40,324,750

 
$
38,961,696

 
 
 
 
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, 2016 and 2015
 
 
 
 
 
 
 
 
 
 
Balance at June 30, 2015
506,959

 
$
1,267,398

 
$
5,863,209

 
$
3,243,645

 
$
(105,186
)
 
$
10,269,066

Net income


 


 


 
426,463

 


 
426,463

Other comprehensive income


 


 


 


 
1,547

 
1,547

Dividends declared on common stock


 


 


 
(163,247
)
 


 
(163,247
)
Issuances of common stock
308

 
770

 
8,665

 


 


 
9,435

Share-based compensation


 


 
1,566

 


 


 
1,566

Balance at Sept. 30, 2015
507,267

 
$
1,268,168

 
$
5,873,440

 
$
3,506,861

 
$
(103,639
)
 
$
10,544,830

 
 
 
 
 
 
 
 
 
 
 
 
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

Purchase of common stock for settlement of equity awards
(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

 
 
 
 
 
 
 
 
 
 
 
 
See Notes to Consolidated Financial Statements

7

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, 2016 and 2015
 
 
 
 
 
 
 
 
 
 
Balance at Dec. 31, 2014
505,733

 
$
1,264,333

 
$
5,837,330

 
$
3,220,958

 
$
(108,139
)
 
$
10,214,482

Net income
 
 
 
 
 
 
775,460

 
 
 
775,460

Other comprehensive income
 
 
 
 
 
 
 
 
4,500

 
4,500

Dividends declared on common stock
 
 
 
 
 
 
(489,557
)
 
 
 
(489,557
)
Issuances of common stock
1,534

 
3,835

 
18,874

 
 
 
 
 
22,709

Share-based compensation
 
 
 
 
17,236

 
 
 
 
 
17,236

Balance at Sept. 30, 2015
507,267

 
$
1,268,168

 
$
5,873,440

 
$
3,506,861

 
$
(103,639
)
 
$
10,544,830

 
 
 
 
 
 
 
 
 
 
 
 
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

Purchase of common stock for settlement of equity awards
(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

 
 
 
 
 
 
 
 
 
 
 
 
See Notes to Consolidated Financial Statements


8

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, 2016 and Dec. 31, 2015; 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, 2016 and 2015; and its cash flows for the nine months ended Sept. 30, 2016 and 2015. All adjustments are of a normal, recurring nature, except as otherwise disclosed. Management has also evaluated the impact of events occurring after Sept. 30, 2016 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, 2015 balance sheet information has been derived from the audited 2015 consolidated financial statements included in the Xcel Energy Inc. Annual Report on Form 10-K for the year ended Dec. 31, 2015. 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, 2015, filed with the SEC on Feb. 19, 2016. 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, 2015, 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 framework for the recognition of revenue, with the objective that recognized revenues properly reflect amounts an entity is entitled to receive in exchange for goods and services. The new guidance also includes additional disclosure requirements regarding revenue, cash flows and obligations related to contracts with customers. The guidance is effective for interim and annual reporting periods beginning after Dec. 15, 2017. Xcel Energy is currently evaluating the impact of adopting ASU 2014-09 on its consolidated financial statements.

Presentation of Deferred Taxes — In November 2015, the FASB issued Balance Sheet Classification of Deferred Taxes, Topic 740 (ASU No 2015-17), which eliminates the requirement to present deferred tax assets and liabilities as current and noncurrent on the balance sheet based on the classification of the related asset or liability, and instead requires classification of all deferred tax assets and liabilities as noncurrent. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2016, and early adoption is permitted. Other than the prescribed classification of all deferred tax assets and liabilities as noncurrent, Xcel Energy does not expect the implementation of ASU 2015-17 to have a material impact on its 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 among other changes in accounting and disclosure requirements, replaces the cost method of accounting for non-marketable equity securities with a model for recognizing impairments and observable price changes, and also eliminates the available-for-sale classification for marketable equity securities. Under the new guidance, 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 is currently evaluating the impact of adopting ASU 2016-01 on its consolidated financial statements.


9

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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 all leases. Additionally, for leases that qualify as finance leases, the guidance requires expense recognition consisting of amortization of the right-of-use asset as well as interest on the related lease liability using the effective interest method. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2018, and early adoption is permitted. Xcel Energy is currently evaluating the impact of adopting ASU 2016-02 on its consolidated financial statements.

Stock Compensation — In March 2016, the FASB issued Improvements to Employee Share-Based Payment Accounting, Topic 718 (ASU 2016-09), which amends existing guidance to simplify several aspects of accounting and presentation for share-based payment transactions, including the accounting for income taxes and forfeitures, as well as presentation in the statement of cash flows. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2016, and early adoption is permitted. Xcel Energy does not expect the implementation of ASU 2016-09 to have a material impact on its consolidated financial statements.

Recently Adopted

Consolidation In February 2015, the FASB issued Amendments to the Consolidation Analysis, Topic 810 (ASU No. 2015-02), which reduces the number of consolidation models and amends certain consolidation principles related to variable interest entities. Xcel Energy implemented the guidance on Jan. 1, 2016, and other than the classification of certain real estate investments held within the Nuclear Decommissioning Trust as non-consolidated variable interest entities, the implementation did not have a significant impact on its consolidated financial statements.

Presentation of Debt Issuance Costs In April 2015, the FASB issued Simplifying the Presentation of Debt Issuance Costs, Subtopic 835-30 (ASU No. 2015-03), which requires the presentation of debt issuance costs on the balance sheet as a deduction from the carrying amount of the related debt, instead of presentation as an asset. Xcel Energy implemented the new guidance as required on Jan. 1, 2016, and as a result, $94.5 million of deferred debt issuance costs were presented as a deduction from the carrying amount of long-term debt on the consolidated balance sheet as of March 31, 2016, and $91.8 million of such deferred costs were retrospectively reclassified from other non-current assets to long-term debt on the consolidated balance sheet as of Dec. 31, 2015.

Fair Value Measurement In May 2015, the FASB issued Disclosures for Investments in Certain Entities that Calculate Net Asset Value per Share (or Its Equivalent), Topic 820 (ASU No. 2015-07), which eliminates the requirement to categorize fair value measurements using a net asset value (NAV) methodology in the fair value hierarchy. Xcel Energy implemented the guidance on Jan. 1, 2016, and the implementation did not have a material impact on its consolidated financial statements. For related disclosures, see Note 8 to the consolidated financial statements.

3.
Selected Balance Sheet Data
(Thousands of Dollars)
 
Sept. 30, 2016
 
Dec. 31, 2015
Accounts receivable, net
 
 
 
 
Accounts receivable
 
$
802,827

 
$
776,494

Less allowance for bad debts
 
(48,579
)
 
(51,888
)
 
 
$
754,248

 
$
724,606

(Thousands of Dollars)
 
Sept. 30, 2016
 
Dec. 31, 2015
Inventories
 
 
 
 
Materials and supplies
 
$
306,544

 
$
290,690

Fuel
 
181,265

 
202,271

Natural gas
 
127,099

 
115,623

 
 
$
614,908

 
$
608,584



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(Thousands of Dollars)
 
Sept. 30, 2016
 
Dec. 31, 2015
Property, plant and equipment, net
 
 
 
 
Electric plant
 
$
37,335,785

 
$
36,464,050

Natural gas plant
 
5,149,959

 
4,944,757

Common and other property
 
1,741,615

 
1,709,508

Plant to be retired (a)
 
36,852

 
38,249

Construction work in progress
 
1,844,525

 
1,256,949

Total property, plant and equipment
 
46,108,736

 
44,413,513

Less accumulated depreciation
 
(14,218,683
)
 
(13,591,259
)
Nuclear fuel
 
2,469,772

 
2,447,251

Less accumulated amortization
 
(2,153,129
)
 
(2,063,654
)
 
 
$
32,206,696

 
$
31,205,851


(a) 
In 2017, PSCo expects to both early retire Valmont Unit 5 and convert 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, 2015 appropriately represents, in all material respects, the current status of other income tax matters, and are incorporated herein by reference.

Federal Tax 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 Audit  Xcel Energy files a consolidated federal income tax return. In 2012, the Internal Revenue Service (IRS) commenced an examination of tax years 2010 and 2011, including the 2009 carryback claim. As of Sept. 30, 2016, the IRS had proposed an adjustment to the federal tax loss carryback claims that would result in $14 million of income tax expense for the 2009 through 2011 claims, the 2013 and 2014 claims and the anticipated claim for 2015. In the fourth quarter of 2015, the IRS forwarded the issue to the Office of Appeals (Appeals). In 2016 the IRS audit team and Xcel Energy presented their cases to Appeals; however, the outcome and timing of a resolution is uncertain. The statute of limitations applicable to Xcel Energy’s 2009 through 2011 federal income tax returns, following extensions, expires in June 2017. Xcel Energy has recognized its best estimate of income tax expense that will result from a final resolution of the IRS’s proposed adjustment of the carryback claims. In the third quarter of 2015, the IRS commenced an examination of tax years 2012 and 2013. As of Sept. 30, 2016, the IRS had not proposed any material adjustments to tax years 2012 and 2013.

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, 2016, 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 February 2016, Texas began an audit of years 2009 and 2010. As of Sept. 30, 2016, Texas had not proposed any adjustments.

In June 2016, Minnesota began an audit of years 2010 through 2014. As of Sept. 30, 2016, Minnesota had not proposed any adjustments.

In August 2016, Wisconsin began an audit of years 2012 and 2013. As of Sept. 30, 2016, Wisconsin had not proposed any adjustments. As of Sept. 30, 2016, there were no other state income tax audits in progress.


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Unrecognized Tax Benefits — The unrecognized tax benefit balance includes permanent tax positions, which if recognized would affect the annual effective tax rate (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, 2016
 
Dec. 31, 2015
Unrecognized tax benefit — Permanent tax positions
 
$
27.7

 
$
25.8

Unrecognized tax benefit — Temporary tax positions
 
103.1

 
94.9

Total unrecognized tax benefit
 
$
130.8

 
$
120.7


The unrecognized tax benefit amounts were reduced by the tax benefits associated with net operating loss (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, 2016
 
Dec. 31, 2015
NOL and tax credit carryforwards
 
$
(42.1
)
 
$
(36.7
)

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 and audit progress, the Minnesota, Texas and Wisconsin audits progress, and other state audits resume. As the IRS Appeals and IRS, Minnesota, Texas and Wisconsin audits progress, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $58 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 Sept. 30, 2016 and Dec. 31, 2015 were not material. No amounts were accrued for penalties related to unrecognized tax benefits as of Sept. 30, 2016 or Dec. 31, 2015.

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, 2015 and in Note 5 to Xcel Energy Inc.’s Quarterly Reports on
Form 10-Q for the quarterly periods ended March 31, 2016 and June 30, 2016, 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 November 2015, NSP-Minnesota filed a three-year electric rate case with the MPUC. The rate case is based on a requested return on equity (ROE) of 10.0 percent and a 52.50 percent equity ratio. The request is detailed in the table below:
Request (Millions of Dollars)
 
2016
 
2017
 
2018
Rate request
 
$
194.6

 
$
52.1

 
$
50.4

Increase percentage
 
6.4
%
 
1.7
%
 
1.7
%
Interim request
 
$
163.7

 
$
44.9

 
N/A

Rate base
 
$
7,800

 
$
7,700

 
$
7,700


In December 2015, the MPUC approved interim rates for 2016.

Settlement Agreement
In August 2016, NSP-Minnesota reached a settlement with the Minnesota Department of Commerce (DOC), Xcel Large Industrials, the Minnesota Chamber of Commerce, the Commercial Group, the Suburban Rate Authority, the City of Minneapolis, the Industrial, Commercial, and Institutional Group, and the Energy CENTS Coalition, which resolves all revenue requirement issues in dispute. The settlement agreement requires the approval of the MPUC.


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Key terms of the settlement are listed below:
The agreement reflects a four-year period covering 2016-2019;
The stated revenue increases in the table below are based on the DOC’s sales forecast;
Annual sales true-up to weather-normalized actuals all years, all classes:
2016 weather-normalized actuals used to set final 2016 rates, no cap;
2016-2019 full decoupling for decoupled classes (residential, non-demand metered commercial) with 3 percent cap; and
2017-2019 annual true-up for non-decoupled classes with 3 percent cap.
An ROE of 9.2 percent and an equity ratio of 52.5 percent;
The nuclear related costs in this rate case will not be considered provisional;
Continued use of all existing riders during the four-year term, however no new riders or legislative additions would be utilized during the four-year term;
Deferral of incremental 2016 property tax expense above a fixed threshold to 2018 and 2019; and
A four-year stay out provision for rate cases.

Compliance steps recommended by the settling parties to implement the settlement:
A property tax true-up mechanism for 2017-2019; and
A capital expenditure true-up mechanism for 2016-2019.
(Millions of Dollars, incremental)
 
2016
 
2017
 
2018
 
2019
 
Total
Settlement revenues (a)
 
$
74.99

 
$
59.86

 
$

 
$
50.12

 
$
184.97

NSP-Minnesota’s sales forecast (b)
 
37.40

 

 

 

 
37.40

   Total rate impact
 
$
112.39

 
$
59.86

 
$

 
$
50.12

 
$
222.37

(a) 
The settlement revenue increase reflects an increase of 2.47 percent in 2016; 1.97 percent in 2017; 0 percent in 2018 and 1.65 percent in 2019.
(b) 
The table reflects the estimated rate impact of this agreement, using NSP-Minnesota’s original sales forecast as filed in the Minnesota rate case. The settlement agreement includes a provision to true-up estimated sales to the actual sales for 2016.

The revised schedule for the Minnesota rate case is listed below:

Administrative law judge (ALJ) report — March 3, 2017; and
MPUC decision — June 2017.

A current liability that is consistent with the settlement and represents NSP-Minnesota’s best estimate of a refund obligation for 2016 associated with interim rates was recorded as of Sept. 30, 2016.

NSP-Minnesota – Gas Utility Infrastructure Costs (GUIC) Rider In August 2016, the MPUC approved NSP-Minnesota’s request to recover approximately $15.5 million in natural gas infrastructure costs through the GUIC Rider, based on NSP-Minnesota’s proposed capital structure and a ROE of 9.64 percent. Recovery was approved for the 15-month period from January 2016 to March 2017.

Annual Automatic Adjustment (AAA) of Charges — In June 2016, the DOC recommended the MPUC should hold utilities responsible for incremental costs of replacement power incurred due to unplanned outages at nuclear facilities under certain circumstances. The DOC’s recommendation could impact replacement power cost recovery for the Prairie Island (PI) nuclear facility outages allocated to the Minnesota jurisdiction during the AAA fiscal year ended June 30, 2015. NSP-Minnesota expects a MPUC decision in mid-2017.

Nuclear Project Prudence Investigation — In 2013, NSP-Minnesota completed the Monticello life cycle management (LCM)/extended power uprate (EPU) project. The multi-year project extended the life of the facility and increased the capacity from 600 to 671 megawatts (MW) in 2015. The Monticello LCM/EPU project expenditures were approximately $665 million. Total capitalized costs were approximately $748 million, which includes allowance for funds used during construction (AFUDC). In 2008, project expenditures were initially estimated at approximately $320 million, excluding AFUDC.


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In 2013, the MPUC initiated an investigation to determine whether the final costs for the Monticello LCM/EPU project were prudent. In March 2015, the MPUC voted to allow for full recovery, including a return, on $415 million of the total plant costs (inclusive of AFUDC), but only allow recovery of the remaining $333 million of costs with no return on this portion of the investment over the remaining life of the plant. As a result of these determinations, Xcel Energy recorded an estimated pre-tax loss of $129 million in the first quarter of 2015, after which the remaining book value of the Monticello project represented the present value of the estimated future cash flows.

NSP-Wisconsin

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

Wisconsin 2017 Electric and Gas Rate Case — In April 2016, NSP-Wisconsin filed a request with the PSCW for an increase in annual electric rates of $17.4 million, or 2.4 percent, and an increase in natural gas rates by $4.8 million, or 3.9 percent, effective January 2017.

The electric rate request is for the limited purpose of recovering increases in (1) generation and transmission fixed charges and fuel and purchased power expenses related to the interchange agreement with NSP-Minnesota, and (2) costs associated with forecasted average rate base of $1.188 billion in 2017.

The natural gas rate request is for the limited purpose of recovering expenses related to the ongoing environmental remediation of a former manufactured gas plant (MGP) site and adjacent area in Ashland, Wis.

No changes are being requested to the capital structure or the 10.0 percent ROE authorized by the PSCW in the 2016 rate case. As part of an agreement with stakeholders to limit the size and scope of the case, NSP-Wisconsin also agreed to an earnings cap, solely for 2017, in which 100 percent of the earnings in excess of the authorized ROE would be refunded to customers.

In August 2016, the PSCW Staff (Staff) and the intervenors filed their direct testimony in the case. The Staff recommended an electric rate increase of $19.5 million, or 2.7 percent and a natural gas rate increase of $4.8 million, or 3.9 percent. The Staff adjustments reflect revisions to previously forecasted rate base as well as fuel and purchased power expense. The Staff’s recommended rate increase also encompasses the PSCW’s July 2016 decision to remove the $9.5 million fuel refund credit from the rate case and refund that amount directly to customers in 2016. Adjusting for the treatment of the fuel refund, the Staff’s recommendation is $7.4 million less than NSP-Wisconsin’s request.

On Oct. 26, 2016, the PSCW verbally approved an electric rate increase of approximately $22.5 million, or 3.2 percent, and a natural gas rate increase of $4.8 million, or 3.9 percent. The difference between the Staff’s recommendation and the PSCW’s approved electric increase is attributable to an increase in forecasted fuel and purchased power expense. Consistent with long-standing PSCW policy, these costs were updated prior to the PSCW’s decision to reflect current market forecasts. The PSCW approved NSP-Wisconsin’s requested natural gas rate increase consistent with the Staff’s recommendation.

The major components of the retail electric rate increase, the Staff’s recommendation, and the PSCW’s approval are summarized below:
Electric Rate Request (Millions of Dollars)
 
NSP-Wisconsin Request
 
Staff Recommendation
 
Final Decision
Rate base investments
 
$
11.0

 
$
7.6

 
7.6

Generation and transmission expenses (excluding fuel and purchased power) (a)
 
6.8

 
6.1

 
6.1

Fuel and purchased power expenses
 
11.0

 
7.7

 
10.7

Subtotal
 
28.8

 
21.4

 
24.4

2015 fuel refund (b)
 
(9.5
)
 

 

Department of Energy settlement refund
 
(1.9
)
 
(1.9
)
 
(1.9
)
Total electric rate increase
 
$
17.4

 
$
19.5

 
$
22.5


(a) 
Includes Interchange Agreement billings. The Interchange Agreement is a Federal Energy Regulatory Commission (FERC) tariff under which NSP-Wisconsin and its affiliate, NSP-Minnesota, own and operate a single integrated electric generation and transmission system and both companies pay a pro-rata share of system capital and operating costs. For financial reporting purposes, these expenses are included in operating and maintenance (O&M).
(b) 
In July 2016, the PSCW required NSP-Wisconsin to return the 2015 fuel refund directly to customers, rather than using it to offset the proposed 2017 rate increase, as originally proposed by NSP-Wisconsin. This decision, when combined with the increase in forecasted fuel and purchased power expense, effectively increases NSP-Wisconsin’s requested electric rate increase to $29.9 million, or 4.2 percent.

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NSP-Wisconsin anticipates a final written order later this year, with new rates effective on Jan. 1, 2017.

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 $64.8 million, which it subsequently revised to $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. The hearing in the appeal is scheduled for February 2017.

Texas 2016 Electric Rate Case — In February 2016, SPS filed a retail electric, non-fuel rate case in Texas with each of its Texas municipalities and the PUCT requesting an overall increase in annual base rate revenue of approximately $71.9 million, or 14.4 percent. The filing is based on a historic test year (HTY) ended Sept. 30, 2015, a requested ROE of 10.25 percent, an electric rate base of approximately $1.7 billion, and an equity ratio of 53.97 percent. In SPS’ required update filing in April 2016, SPS revised its requested rate increase to $68.6 million.

Pursuant to legislation passed in Texas in 2015, the final rates established in the case will be effective retroactive to July 20, 2016.

In August 2016, several intervenors filed direct testimony in response to SPS’ rate request, including: PUCT Staff (Staff), the Alliance of Xcel Municipalities (AXM), the Office of Public Utility Counsel (OPUC), Texas Industrial Energy Consumers (TIEC), and the State of Texas’ agencies.

The Staff recommended a rate increase of approximately $32.9 million, based on a ROE of 9.30 percent and an equity ratio of 51 percent. The Staff’s proposed rate increase reflects imputed revenues for power factor adjustment charges and weather normalization;
AXM recommended a rate increase of approximately $25.2 million, based on a ROE of 9.40 percent and an equity ratio of 51 percent; and
The other intervenors did not present a complete revenue requirement analysis. The majority of the direct testimony focused on specific cost allocation and rate design issues. However, OPUC and TIEC recommended ROEs of 9.20 percent and 9.15 percent, respectively.

In October 2016, SPS and various parties reached an agreement in principle in the Texas rate case. SPS and the parties are documenting the settlement, and expect to file with the PUCT in the fourth quarter of 2016.  Any settlement would require approval of the PUCT, with a decision expected by the end of 2016 or early 2017.

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

New Mexico 2015 Electric Rate Case In October 2015, SPS filed an electric rate case with the NMPRC seeking an increase in non-fuel base rates of $45.4 million. The proposed increase would be offset by a decrease in base fuel revenue of approximately $21.1 million. The rate filing was based on a June 30, 2015 HTY adjusted for known and measurable changes, a requested ROE of 10.25 percent, an electric rate base of approximately $734 million and an equity ratio of 53.97 percent.

In August 2016, the NMPRC approved a black-box stipulation that resulted in a non-fuel base rate increase of $23.5 million and a decrease in base fuel revenue of approximately $21.1 million. The decrease in base fuel revenue will be reflected in adjustments to the fuel and purchased power cost adjustment clause.

SPS plans to file another base rate case in November 2016 utilizing a future test year ending June 2018.

Pending Regulatory Proceedings — FERC

Midcontinent Independent System Operator, Inc. (MISO) ROE Complaints/ROE Adder — 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, a prohibition on capital structures in excess of 50 percent equity, and the removal of ROE adders (including those for regional transmission organization (RTO) membership and for being an independent transmission company), effective Nov. 12, 2013.


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In December 2015, an ALJ initial decision recommended the FERC approve a ROE of 10.32 percent, which the FERC upheld in an order issued on Sept. 28, 2016. This ROE is 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 is 10.82 percent, which includes a previously approved 50 basis point adder for RTO membership.

In February 2015, a second complaint seeking to reduce the MISO region ROE from 12.38 percent to 8.67 percent prior to any adder was filed, which the FERC set for hearings, resulting in a second period of potential refund from Feb. 12, 2015 to May 11, 2016. The MPUC, the North Dakota Public Service Commission (NDPSC), the South Dakota Public Utilities Commission and the DOC joined a joint complainant/intervenor initial brief recommending an ROE of approximately 8.81 percent. FERC staff recommended a ROE of 8.78 percent. The MISO TOs recommended a ROE of 10.92 percent. On June 30, 2016, the ALJ recommended a ROE of 9.7 percent, the midpoint of the upper half of the discounted cash flow range. A FERC decision is expected in 2017.

As of Sept. 30, 2016, NSP-Minnesota has recognized a current liability for the Nov. 12, 2013 to Feb. 11, 2015 complaint period based on the 10.32 percent ROE provided in the FERC order, as well as a current liability representing the best estimate of the final ROE for the second 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, in part, from other SPP customers whose transmission service depends on capacity enabled by the upgrade.  The SPP OATT has allowed SPP to collect charges since 2008, but to date SPP has not charged its customers any amounts attributable to these upgrades. 

In April 2016, SPP filed a request with the FERC for a waiver that would allow SPP to recover the charges not billed since 2008.  The FERC approved the waiver request in July 2016.  SPS and certain other parties requested rehearing of the FERC order.  In September 2016, SPP provided further information regarding additional costs, primarily due to the system-wide claw back of point to point revenues previously distributed to SPS and other entities. Amounts due to SPP are expected to be paid over a five-year period commencing November 2016 under an optional payment plan that was approved by the FERC in September 2016 and elected by SPS in October 2016. Based on SPP’s most recent calculation in October 2016, estimated costs would be approximately $12 million to $14 million, and SPS anticipates these costs would be recoverable through regulatory mechanisms.

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, 2015, 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, 2016 and June 30, 2016, 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.

Purchased Power Agreements (PPAs)

Under certain PPAs, NSP-Minnesota, PSCo and SPS purchase power from independent power producing entities for which the utility subsidiaries are required to reimburse natural gas or biomass fuel costs, or to participate in tolling arrangements under which the utility subsidiaries procure the natural gas required to produce the energy that they purchase. These specific PPAs create a variable interest in the associated independent power producing entity.

The Xcel Energy utility subsidiaries had approximately 3,537 MW and 3,698 MW of capacity under long-term PPAs as of Sept. 30, 2016 and Dec. 31, 2015, 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.


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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, 2016 and Dec. 31, 2015, 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, 2016
 
Dec. 31, 2015
Guarantees issued and outstanding
 
$
19.0

 
$
12.5

Current exposure under these guarantees
 
0.1

 
0.1

Bonds with indemnity protection
 
43.0

 
41.3


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 MGP Site — NSP-Wisconsin has been 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 (the Sediments).

In 2012, under a settlement agreement with the United States Environmental Protection Agency (EPA), NSP-Wisconsin agreed to remediate the Phase I Project Area (which includes the Upper Bluff and Kreher Park areas of the Site). The current cost estimate for the cleanup of the Phase I Project Area is approximately $71.4 million, of which approximately $52.6 million has been spent.

NSP-Wisconsin performed a wet dredge pilot study in the summer of 2016 and demonstrated that a wet dredge remedy can meet the performance standards for remediation of the Sediments. As a result, the EPA authorized NSP-Wisconsin to extend the wet dredge pilot to additional areas of the Site. Settlement negotiations are ongoing between the EPA and NSP-Wisconsin regarding the performance of the full scale cleanup of the Sediments. If a court-approved settlement can be reached with the EPA, NSP-Wisconsin anticipates a full scale wet dredge remedy of the Sediments could be performed beginning as early as 2017, and potentially conclude by 2018.

At Sept. 30, 2016 and Dec. 31, 2015, NSP-Wisconsin had recorded a total liability of $84.6 million and $94.4 million, respectively, for the entire site. NSP-Wisconsin’s potential liability, the actual cost of remediation and the timing of expenditures are subject to change. NSP-Wisconsin also continues to work to identify and access state and federal funds to apply to the remediation cost.

NSP-Wisconsin has deferred the unrecovered portion of the estimated Site remediation costs as a regulatory asset. The PSCW has consistently 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 April 2016, NSP-Wisconsin filed a limited natural gas rate case for recovery of additional expenses associated with remediating the Site. If approved, the annual recovery of MGP clean-up costs would increase from $7.6 million in 2016 to $12.4 million in 2017.


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Table of Contents


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 at that time and commenced an investigation of the historic MGP and adjacent properties (the Fargo MGP Site). Based on the investigation that concluded in the third quarter of 2016, NSP-Minnesota has recommended that targeted source removal of impacted soils and historic MGP infrastructure should be performed, subject to further input from the North Dakota Department of Health, the City of Fargo, N.D., current property owners and other stakeholders.

NSP-Minnesota has 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 November 2016 to allow NSP-Minnesota time to investigate site conditions. NSP-Minnesota intends to seek an additional stay of the litigation.

As of Sept. 30, 2016 and Dec. 31, 2015, NSP-Minnesota had recorded a liability of $12.2 million and $2.7 million, respectively, for the Fargo MGP Site, with the increase due to the remediation activities proposed by NSP-Minnesota. In December 2015, the 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 12 percent allocable to the Minnesota jurisdiction. Uncertainties related to the liability recognized include obtaining access and approvals from stakeholders to perform the proposed remediation and the potential for contributions from entities that may be identified as PRPs.

Environmental Requirements

Water and Waste
Coal Ash Regulation — Xcel Energy’s operations are subject to federal and state laws that impose requirements for handling, storage, treatment and disposal of solid waste. In April 2015, the EPA published a final rule regulating the management and disposal of coal combustion byproducts (coal ash) as a nonhazardous waste. Under the final rule, Xcel Energy’s costs to manage and dispose of coal ash has not significantly increased.

In 2015, industry and environmental non-governmental organizations sought judicial review of the final rule. In June 2016, the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit) issued an order remanding and vacating certain elements of the rule as a result of partial settlements with these parties. Oral arguments are expected to be heard in early 2017 and a final decision is anticipated in the first half of 2017. Until a final decision is reached in the case, it is uncertain whether the litigation or partial settlements will have any significant impact on results of operations, financial position or cash flows on Xcel Energy.

Air
Cross-State Air Pollution Rule (CSAPR) — CSAPR addresses long range transport of particulate matter (PM) and ozone by requiring reductions in sulfur dioxide (SO2) and nitrogen oxide (NOx) from utilities in the eastern half of the United States using an emissions trading program. For Xcel Energy, the rule applies in Minnesota, Wisconsin and Texas.

CSAPR was adopted to address interstate emissions impacting downwind states’ attainment of the 1997 ozone National Ambient Air Quality Standard (NAAQS) and the 1997 and 2006 particulate NAAQS. As the EPA revises the NAAQS, it will consider whether to make any further reductions to CSAPR emission budgets and whether to change which states are included in the emissions trading program. In December 2015, the EPA proposed adjustments to CSAPR emission budgets which address attainment of the more stringent 2008 ozone NAAQS. In September 2016 the EPA adopted a final rule that reduced the ozone season emission budget for NOx in Texas by approximately 22 percent, which is expected to lead to increased costs to purchase emission allowances. Xcel Energy does not anticipate these increased costs to purchase emission allowances will have a material impact on the results of operations, financial position or cash flows.

Regional Haze Rules — The regional haze program is designed to address widespread haze that results from emissions from a multitude of sources. In 2005, the EPA amended the best available retrofit technology (BART) requirements of its regional haze rules, which 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 SO2, NOx and PM 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, CSAPR.

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Texas developed a state implementation plan (SIP) that finds the CAIR equal to BART for electric generating units (EGUs). As a result, no additional controls beyond CAIR compliance would be required. In December 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 defers its approval of CSAPR compliance as BART until the EPA considers further adjustments to CSAPR emission budgets under the D.C. Circuit’s remand of the Texas SO2 emission budgets. In March 2016, the EPA requested information under the Clean Air Act related to EGUs at SPS’ plants. SPS identified Harrington Units 1 and 2, Jones Units 1 and 2, Nichols Unit 3 and Plant X Unit 4 as BART-eligible units. These units will be evaluated based on their impact on visibility. Additional emission control equipment under the EPA’s BART guidelines for PM, SO2 and NOx could be required if a unit is determined to “cause or contribute” to visibility impairment. SPS cannot evaluate the impact of additional emission controls until the EPA concludes its evaluation of BART. In June 2016, the EPA issued a memorandum which allows Texas to voluntarily adopt the CSAPR emission budgets limiting annual SO2 and NOx emissions and rely on those emission budgets to satisfy Texas’ BART obligations under the regional haze rules. It is not yet known whether the Texas Commission on Environmental Quality (TCEQ) intends to utilize this option. If Texas does not opt into the CSAPR rule, the EPA is expected to issue a proposed rule in December 2016 that could impact Harrington Units 1 and 2.

In December 2014, the EPA proposed to disapprove portions of the SIP and instead adopt a federal implementation plan (FIP). In January 2016, the EPA adopted a final rule establishing a FIP 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. In March 2016, SPS appealed the EPA’s decision and asked for a stay of the final rule while it is being reviewed. In July 2016, the United States Court of Appeals for the Fifth Circuit (Fifth Circuit) granted the stay motion and decided that the Fifth Circuit, not the D.C. Circuit, is the appropriate venue for this case. In addition, SPS filed a petition with the EPA requesting reconsideration of the final rule. SPS believes these costs or the costs of alternative cost-effective generation would be recoverable through regulatory mechanisms if required, and therefore does not expect a material impact on results of operations, financial position or cash flows.

Implementation of the NAAQS for SO2 — The EPA adopted a more stringent NAAQS for SO2 in 2010. The EPA is requiring states to evaluate areas in three phases. The first phase includes areas near PSCo’s Pawnee plant and SPS’ Tolk and Harrington plants.  The Pawnee plant recently installed an SO2 scrubber and the Tolk and Harrington Plants utilize low sulfur coal to reduce SO2 emissions. In June 2016, the EPA issued final designations which found the area near the Tolk plant to be meeting the NAAQS and the areas near the Harrington and Pawnee plants as “unclassifiable.” The area near the Harrington plant is to be monitored for three years and a final designation is expected to be made by December 2020. It is anticipated that the area near the Pawnee plant will be able to show compliance with the NAAQS through air dispersion modeling performed by the Colorado Department of Public Health and Environment.

If an area is designated nonattainment in 2020, the states will need to evaluate all SO2 sources in the area. The state would then submit an implementation plan, which would be due by 2022, designed to achieve the NAAQS by 2025. The TCEQ could require additional SO2 controls at Harrington as part of such a plan. The areas near the remaining Xcel Energy power plants will be evaluated in the next designation phase, ending December 2017. The remaining plants, PSCo’s Comanche and Hayden plants along with NSP-Minnesota’s King and Sherco plants, utilize scrubbers to control SO2 emissions. Xcel Energy cannot evaluate the impacts until the designation of nonattainment areas is made, and any required state plans are developed. Xcel Energy believes that should SO2 control systems be required for a plant, compliance costs or the costs of alternative cost-effective generation will be recoverable through regulatory mechanisms and therefore does not expect a material impact on results of operations, financial position or cash flows.

In light of the continuing development of environmental regulatory requirements, as well as the more favorable long term outlook for alternative resources, SPS is undertaking analysis to determine the most cost-effective means to meet the needs of its customers, given a low natural gas price environment, the need to make additional investments to provide water to the Tolk facility and the potential need to make major investments in air pollution control equipment.


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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

Pacific Northwest FERC Refund Proceeding — A complaint with the FERC posed that sales made in the Pacific Northwest in 2000 and 2001 through bilateral contracts were unjust and unreasonable under the Federal Power Act. The City of Seattle (the City) alleges between $34 million to $50 million in sales with PSCo is subject to refund. In 2003, the FERC terminated the proceeding, although it was later remanded back to the FERC in 2007 by the U.S. Court of Appeals for the Ninth Circuit (Ninth Circuit).

In May 2015, the FERC issued an order rejecting the City’s claim that any of the sales made resulted in an excessive burden and concluded that the City failed to establish a causal link between any contracts and any claimed unlawful market activity. In February 2016, the City appealed this decision to the Ninth Circuit. This appeal is pending review by the Ninth Circuit.

In December 2015, the Ninth Circuit held that the standard of review applied by the FERC to the contracts which the City was challenging is appropriate. The Ninth Circuit dismissed questions concerning whether the FERC properly established the scope of the hearing, and determined that the challenged orders are preliminary and that the Ninth Circuit lacks jurisdiction to review evidentiary decisions until after the FERC’s proceedings are final. The City joined the State of California in its request seeking rehearing of this order, which the Ninth Circuit denied. The FERC proceedings are now final with respect to the City’s claims and are subject to review in the pending Ninth Circuit appeal.

In October 2016, a settlement was reached that resolves all outstanding claims between and among the City and the respondents, including PSCo. Settlement terms required PSCo to pay the City $15,000 and the City to withdraw its pending appeal with the Ninth Circuit. This brings this matter to a close.

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.

The cases were consolidated in U.S. District Court in Nevada. Five of the cases have since been settled and seven have been dismissed. One multi-district litigation (MDL) matter remains and it consists of a Colorado class (Breckenridge), a Wisconsin class (NSP-Wisconsin), a Kansas class, and two other cases identified as “Sinclair Oil” and “Farmland.” In May 2016, the MDL judge granted summary judgment dismissing defendants from the Farmland lawsuit. e prime and Xcel Energy have filed a motion seeking clarification that this order includes them. This motion is currently pending and is expected to be heard in December 2016. The e prime defendants filed a summary judgment motion in the Colorado class lawsuit (Breckenridge) and oppositions to class certifications in all the class actions, which is also expected to be heard in December 2016. Trial dates are not expected to occur prior to early 2017. Xcel Energy, NSP-Wisconsin and e prime have concluded that a loss is remote.


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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 service agreements entered into by PSCo and various developers. The dispute involves assigned interests in those 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 Colorado Public Utilities Commission (CPUC). In June 2016, DRC filed a notice of appeal. DRC filed its opening brief on Oct. 20, 2016 and PSCo’s answer brief is due Nov. 24, 2016. 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 Denver District Court in August 2016.

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, 2016
 
Year Ended  
 Dec. 31, 2015
Borrowing limit
 
$
2,750

 
$
2,750

Amount outstanding at period end
 
366

 
846

Average amount outstanding
 
477

 
601

Maximum amount outstanding
 
609

 
1,360

Weighted average interest rate, computed on a daily basis
 
0.77
%
 
0.48
%
Weighted average interest rate at period end
 
0.77

 
0.82


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, 2016 and Dec. 31, 2015, there were $19 million and $29 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, Xcel Energy Inc. and its utility subsidiaries must have credit facilities in place at least equal to the amount of their commercial paper borrowing limits and cannot issue commercial paper in an aggregate amount exceeding available credit facility capacity. 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.


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At Sept. 30, 2016, 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

 
$
362

 
$
638

PSCo
 
700

 
3

 
697

NSP-Minnesota
 
500

 
11

 
489

SPS
 
400

 
5

 
395

NSP-Wisconsin
 
150

 
4

 
146

Total
 
$
2,750

 
$
385

 
$
2,365

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

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 at Sept. 30, 2016 and Dec. 31, 2015.

Amended Credit Agreements - In June 2016, Xcel Energy Inc., NSP-Minnesota, NSP-Wisconsin, PSCo and SPS entered into amended five-year credit agreements with a syndicate of banks. The total borrowing limit under the amended credit agreements remained at $2.75 billion. The amended credit agreements have substantially the same terms and conditions as the prior credit agreements with the following exceptions:
The maturity extended from October 2019 to June 2021.
The Eurodollar borrowing margins on these lines of credit were reduced to a range of 75 to 150 basis points per year, from a range of 87.5 to 175 basis points per year, based upon applicable long-term credit ratings.
The commitment fees, calculated on the unused portion of the lines of credit, were reduced to a range of 6 to 22.5 basis points per year, from a range of 7.5 to 27.5 basis points per year, also based on applicable long-term credit ratings.

Xcel Energy Inc., NSP-Minnesota, PSCo and SPS each have the right to request an extension of the revolving credit facility termination date for two additional one-year periods. NSP-Wisconsin has the right to request an extension of the revolving credit facility termination date for an additional one-year period. All extension requests are subject to majority bank group approval.

Long-Term Borrowings

During the nine months ended Sept. 30, 2016, Xcel Energy Inc. and its utility subsidiaries completed the following bond issuances:

In March, Xcel Energy Inc. issued $400 million of 2.4 percent senior notes due March 15, 2021 and $350 million of 3.3 percent senior notes due June 1, 2025;
In May, NSP-Minnesota issued $350 million of 3.6 percent first mortgage bonds due May 15, 2046;
In June, PSCo issued $250 million of 3.55 percent first mortgage bonds due June 15, 2046; and
In August, SPS issued $300 million of 3.4 percent first mortgage bonds due Aug. 15, 2046.

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 measurement 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.


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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 prices.

Investments in equity securities and other funds Equity securities are valued using quoted prices in active markets. The fair values for commingled funds, international equity funds, private equity investments and real estate investments are measured using a NAV methodology, which takes 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 and international equity 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.


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Investments in debt securities Fair values for debt securities are determined by a third party pricing service using recent trades and observable spreads from benchmark interest rates for similar securities.

Interest rate derivatives 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. 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, 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 energy congestion, which is caused by transmission load and transmission constraints. Congestion is also influenced by the operating schedules of power plants and the consumption of electricity. Unplanned plant outages, scheduled plant maintenance, changes in the costs of fuels used in generation, weather and changes in demand for electricity can each impact the operating schedules of the power plants and the value of an FTR. The valuation process for FTRs utilizes complex iterative modeling to predict the impacts of forecasted changes in these drivers of transmission system congestion on the historical pricing of FTR purchases.

If forecasted costs of electric transmission congestion increase or decrease for a given FTR path, the value of that particular FTR instrument will likewise increase or decrease. Given the limited observability of management’s forecasts for several of the inputs to this complex valuation model fair value measurements for FTRs have been assigned a Level 3. Monthly settlements for non-trading FTRs are included in fuel and purchased energy cost recovery mechanisms as applicable in each jurisdiction, and therefore changes in the fair value of the yet to be settled portions of most FTRs are deferred as a regulatory asset or liability. Given this regulatory treatment and the limited magnitude of FTRs relative to the electric utility operations of NSP-Minnesota and SPS, the numerous unobservable quantitative inputs to the complex model used for 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 purpose of 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. 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, given the purpose and legal restrictions on the use of nuclear decommissioning fund assets. 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 $355.3 million and $328.8 million at Sept. 30, 2016 and Dec. 31, 2015, respectively, and unrealized losses and amounts recorded as other-than-temporary impairments were $65.8 million and $100.2 million at Sept. 30, 2016 and Dec. 31, 2015, 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 at Sept. 30, 2016 and Dec. 31, 2015:
 
 
Sept. 30, 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
 
$
15,055

 
$
15,055

 
$

 
$

 
$

 
$
15,055

Commingled funds:
 
 
 
 
 
 
 
 
 
 
 
 
Non U.S. equities
 
254,362

 

 

 

 
245,481

 
245,481

Emerging market debt funds
 
92,472

 

 

 

 
101,387

 
101,387

Commodity funds
 
99,771

 

 

 

 
82,139

 
82,139

Private equity investments
 
130,848

 

 

 

 
178,768

 
178,768

Real estate
 
121,271

 

 

 

 
174,552

 
174,552

Other commingled funds
 
151,048

 

 

 

 
159,230

 
159,230

Debt securities:
 
 
 
 
 
 
 
 
 
 
 
 
Government securities
 
34,853

 

 
35,723

 

 

 
35,723

U.S. corporate bonds
 
95,828

 

 
93,981

 

 

 
93,981

International corporate bonds
 
19,877

 

 
19,860

 

 

 
19,860

Municipal bonds
 
13,906

 

 
14,638

 

 

 
14,638

Asset-backed securities
 
2,847

 

 
2,948

 

 

 
2,948

Mortgage-backed securities
 
10,118

 

 
10,582

 

 

 
10,582

Equity securities:
 
 
 
 
 
 
 
 
 
 
 
 
U.S. equities
 
270,137

 
455,035

 

 

 

 
455,035

Non U.S. equities
 
213,291

 
225,782

 

 

 

 
225,782

Total
 
$
1,525,684

 
$
695,872

 
$
177,732

 
$

 
$
941,557

 
$
1,815,161

(a) 
Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $134.5 million of equity investments in unconsolidated subsidiaries and $98.8 million of rabbi trust assets and miscellaneous investments.
(b) 
Based on the requirements of ASU 2015-07, investments measured at fair value using a NAV methodology have not been classified in the fair value hierarchy. See Note 2 for further information on the adoption of ASU 2015-07.
 
 
Dec. 31, 2015
 
 
 
 
Fair Value
(Thousands of Dollars)
 
Cost
 
Level 1
 
Level 2
 
Level 3
 
Investments Measured at NAV (b)
 
Total
Nuclear decommissioning fund (a)
 
 
 
 
 
 
 
 
 
 
 
 
Cash equivalents
 
$
27,484

 
$
27,484

 
$

 
$

 
$

 
$
27,484

Commingled funds:
 
 
 
 
 
 
 
 
 
 
 
 
Non U.S. equities
 
259,114

 

 

 

 
231,122

 
231,122

Emerging market debt funds
 
88,987

 

 

 

 
88,467

 
88,467

Commodity funds
 
99,771

 

 

 

 
77,338

 
77,338

Private equity investments
 
105,965

 

 

 

 
157,528

 
157,528

Real estate
 
115,019

 

 

 

 
165,190

 
165,190

Other commingled funds
 
150,877

 

 

 

 
164,389

 
164,389

Debt securities:
 
 
 
 
 
 
 
 
 
 
 
 
Government securities
 
24,444

 

 
21,356

 

 

 
21,356

U.S. corporate bonds
 
73,061

 

 
65,276

 

 

 
65,276

International corporate bonds
 
13,726

 

 
12,801

 

 

 
12,801

Municipal bonds
 
49,255

 

 
51,589

 

 

 
51,589

Asset-backed securities
 
2,837

 

 
2,830

 

 

 
2,830

Mortgage-backed securities
 
11,444

 

 
11,621

 

 

 
11,621

Equity securities:
 
 
 
 
 
 
 
 
 
 
 
 
U.S. equities
 
273,106

 
432,495

 

 

 

 
432,495

Non U.S. equities
 
200,509

 
214,664

 

 

 

 
214,664

Total
 
$
1,495,599

 
$
674,643

 
$
165,473

 
$

 
$
884,034

 
$
1,724,150

(a) 
Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $130.0 million of equity investments in unconsolidated subsidiaries and $48.9 million of miscellaneous investments.
(b) 
Based on the requirements of ASU 2015-07, investments measured at fair value using a NAV methodology have not been classified in the fair value hierarchy. See Note 2 for further information on the adoption of ASU 2015-07.

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For the nine months ended Sept. 30, 2016 and 2015 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, at Sept. 30, 2016:
 
 
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
 
$

 
$
10,583

 
$
971

 
$
24,169

 
$
35,723

U.S. corporate bonds
 
257

 
28,245

 
59,451

 
6,028

 
93,981

International corporate bonds
 

 
5,043

 
11,606

 
3,211

 
19,860

Municipal bonds
 

 
210

 
5,773

 
8,655

 
14,638

Asset-backed securities
 

 

 
2,948

 

 
2,948

Mortgage-backed securities
 

 

 

 
10,582