XCEL 9.30.13 10-Q

 
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, 2013
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 18, 2013
Common Stock, $2.50 par value
 
497,639,485 shares
 




TABLE OF CONTENTS

PART I
 

 
Item 1 —

 
 
 

 
 
 

 
 
 

 
 
 

 
 
 

 
 
 

 
Item 2 —

 
Item 3 —

 
Item 4 —

PART II
 

 
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.  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
 
2013
 
2012
 
2013
 
2012
Operating revenues
 
 
 
 
 
 
 
Electric
$
2,599,925

 
$
2,532,709

 
$
6,911,998

 
$
6,506,320

Natural gas
205,358

 
174,513

 
1,216,275

 
1,016,861

Other
17,055

 
17,119

 
55,827

 
53,907

Total operating revenues
2,822,338

 
2,724,341

 
8,184,100

 
7,577,088

 
 
 
 
 
 
 
 
Operating expenses
 

 
 

 
 
 
 
Electric fuel and purchased power
1,097,944

 
1,006,830

 
3,034,031

 
2,725,183

Cost of natural gas sold and transported
74,847

 
49,739

 
702,987

 
557,444

Cost of sales — other
7,540

 
7,251

 
23,832

 
20,499

Operating and maintenance expenses
575,305

 
531,480

 
1,667,093

 
1,576,178

Conservation and demand side management program expenses
67,811

 
68,920

 
192,288

 
191,242

Depreciation and amortization
228,491

 
239,051

 
721,131

 
694,364

Taxes (other than income taxes)
105,287

 
100,636

 
320,765

 
305,892

Total operating expenses
2,157,225

 
2,003,907

 
6,662,127

 
6,070,802

 
 
 
 
 
 
 
 
Operating income
665,113

 
720,434

 
1,521,973

 
1,506,286

 
 
 
 
 
 
 
 
Other (expense) income, net
(404
)
 
488

 
3,931

 
4,953

Equity earnings of unconsolidated subsidiaries
7,273

 
7,490

 
22,379

 
22,150

Allowance for funds used during construction — equity
21,284

 
15,860

 
63,147

 
44,504

 
 
 
 
 
 
 
 
Interest charges and financing costs
 

 
 

 
 
 
 
Interest charges — includes other financing costs of
$6,020, $6,010, $24,058 and $18,126, respectively
144,758

 
153,719

 
431,199

 
457,470

Allowance for funds used during construction — debt
(9,377
)
 
(10,439
)
 
(28,451
)
 
(24,729
)
Total interest charges and financing costs
135,381

 
143,280

 
402,748

 
432,741

 
 
 
 
 
 
 
 
Income from continuing operations before income taxes
557,885

 
600,992

 
1,208,682

 
1,145,152

Income taxes
193,349

 
202,845

 
410,676

 
380,161

Income from continuing operations
364,536

 
398,147

 
798,006

 
764,991

Income (loss) from discontinued operations, net of tax
216

 
(41
)
 
173

 
68

Net income
$
364,752

 
$
398,106

 
$
798,179

 
$
765,059

 
 
 
 
 
 
 
 
Weighted average common shares outstanding:
 

 
 

 
 
 
 
Basic
498,149

 
488,084

 
495,256

 
487,722

Diluted
498,641

 
488,578

 
495,767

 
488,198

 
 
 
 
 
 
 
 
Earnings per average common share:
 

 
 

 
 
 
 
Basic
$
0.73

 
$
0.82

 
$
1.61

 
$
1.57

Diluted
0.73

 
0.81

 
1.61

 
1.57

 
 
 
 
 
 
 
 
Cash dividends declared per common share
$
0.28

 
$
0.27

 
$
0.83

 
$
0.80


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
 
2013
 
2012
 
2013
 
2012
Net income
$
364,752

 
$
398,106

 
$
798,179

 
$
765,059

 
 
 
 
 
 
 
 
Other comprehensive income (loss)
 

 
 

 
 
 
 
 
 
 
 
 
 
 
 
Pension and retiree medical benefits:
 

 
 

 
 
 
 
Amortization of losses included in net periodic benefit cost,
net of tax of $686, $636, $3,918 and $1,905, respectively
1,179

 
911

 
1,675

 
2,738

 
 
 
 
 
 
 
 
Derivative instruments:
 

 
 

 
 
 
 
Net fair value increase (decrease), net of tax of $14, $(5,913),
$(2) and $(12,586), respectively
22

 
(8,853
)
 
(9
)
 
(19,188
)
Reclassification of losses to net income, net of tax of
$266, $296, $2,145 and $610, respectively
539

 
393

 
928

 
756

 
561

 
(8,460
)
 
919

 
(18,432
)
Marketable securities:
 

 
 

 
 
 
 
Net fair value increase (decrease), net of tax of
$73, $(30), $56 and $89, respectively
115

 
(45
)
 
79

 
129

 
 
 
 
 
 
 
 
Other comprehensive income (loss)
1,855

 
(7,594
)
 
2,673

 
(15,565
)
Comprehensive income
$
366,607

 
$
390,512

 
$
800,852

 
$
749,494


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
 
2013
 
2012
Operating activities
 
 
 

Net income
$
798,179

 
$
765,059

Remove income from discontinued operations
(173
)
 
(68
)
Adjustments to reconcile net income to cash provided by operating activities:
 

 
 

Depreciation and amortization
740,623

 
707,630

Conservation and demand side management program amortization
5,024

 
5,511

Nuclear fuel amortization
76,447

 
79,171

Deferred income taxes
409,662

 
440,413

Amortization of investment tax credits
(4,973
)
 
(4,656
)
Allowance for equity funds used during construction
(63,147
)
 
(44,504
)
Equity earnings of unconsolidated subsidiaries
(22,379
)
 
(22,150
)
Dividends from unconsolidated subsidiaries
27,503

 
24,922

Share-based compensation expense
28,362

 
20,886

Net realized and unrealized hedging and derivative transactions
(12,011
)
 
(90,123
)
Changes in operating assets and liabilities:
 

 
 

Accounts receivable
(108,488
)
 
(125,803
)
Accrued unbilled revenues
87,652

 
166,857

Inventories
(69,918
)
 
55,511

Other current assets
6,060

 
(30,289
)
Accounts payable
(3,297
)
 
(118,276
)
Net regulatory assets and liabilities
100,648

 
1,848

Other current liabilities
129,984

 
(35,283
)
Pension and other employee benefit obligations
(159,592
)
 
(181,281
)
Change in other noncurrent assets
26,710

 
(38,790
)
Change in other noncurrent liabilities
10,032

 
(4,664
)
Net cash provided by operating activities
2,002,908

 
1,571,921

 
 
 
 
Investing activities
 

 
 

Utility capital/construction expenditures
(2,454,198
)
 
(1,805,843
)
Proceeds from insurance recoveries
90,000

 
56,892

Allowance for equity funds used during construction
63,147

 
44,504

Purchases of investments in external decommissioning fund
(1,177,398
)
 
(501,009
)
Proceeds from the sale of investments in external decommissioning fund
1,172,597

 
501,009

Investment in WYCO Development LLC
(3,418
)
 
(779
)
Change in restricted cash

 
95,287

Other, net
(1,524
)
 
343

Net cash used in investing activities
(2,310,794
)
 
(1,609,596
)
 
 
 
 
Financing activities
 
 
 
(Repayments of) proceeds from short-term borrowings, net
(300,000
)
 
85,000

Proceeds from issuance of long-term debt
1,434,989

 
1,691,322

Repayments of long-term debt, including reacquisition premiums
(654,864
)
 
(653,532
)
Proceeds from issuance of common stock
229,420

 
5,878

Repurchase of common stock

 
(18,529
)
Purchase of common stock for settlement of equity awards

 
(23,307
)
Dividends paid
(382,148
)
 
(362,568
)
Net cash provided by financing activities
327,397

 
724,264

 
 
 
 
Net change in cash and cash equivalents
19,511

 
686,589

Cash and cash equivalents at beginning of period
82,323

 
60,684

Cash and cash equivalents at end of period
$
101,834

 
$
747,273

 
 
 
 
Supplemental disclosure of cash flow information:
 

 
 

Cash paid for interest (net of amounts capitalized)
$
(411,130
)
 
$
(436,296
)
Cash received (paid) for income taxes, net
16,851

 
(6,257
)
Supplemental disclosure of non-cash investing and financing transactions:
 

 
 

Property, plant and equipment additions in accounts payable
$
299,209

 
$
229,847

Issuance of common stock for reinvested dividends and 401(k) plans
54,963

 
51,350


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, 2013
 
Dec. 31, 2012
Assets
 
 
 
Current assets
 
 
 
Cash and cash equivalents
$
101,834

 
$
82,323

Accounts receivable, net
786,874

 
718,046

Accrued unbilled revenues
575,711

 
663,363

Inventories
604,628

 
535,574

Regulatory assets
396,271

 
352,977

Derivative instruments
92,687

 
69,013

Deferred income taxes
325,972

 
32,528

Prepayments and other
236,764

 
171,315

Total current assets
3,120,741

 
2,625,139

 
 
 
 
Property, plant and equipment, net
25,342,578

 
23,809,348

 
 
 
 
Other assets
 

 
 

Nuclear decommissioning fund and other investments
1,679,987

 
1,617,865

Regulatory assets
2,709,283

 
2,762,029

Derivative instruments
95,894

 
126,297

Other
178,169

 
200,008

Total other assets
4,663,333

 
4,706,199

Total assets
$
33,126,652

 
$
31,140,686

 
 
 
 
Liabilities and Equity
 

 
 

Current liabilities
 

 
 

Current portion of long-term debt
$
280,538

 
$
258,155

Short-term debt
302,000

 
602,000

Accounts payable
965,572

 
959,093

Regulatory liabilities
208,943

 
168,858

Taxes accrued
335,846

 
334,441

Accrued interest
134,612

 
162,494

Dividends payable
139,333

 
131,748

Derivative instruments
26,729

 
32,482

Other
445,488

 
287,802

Total current liabilities
2,839,061

 
2,937,073

 
 
 
 
Deferred credits and other liabilities
 

 
 

Deferred income taxes
5,186,944

 
4,434,909

Deferred investment tax credits
79,609

 
82,761

Regulatory liabilities
1,052,726

 
1,059,939

Asset retirement obligations
1,785,319

 
1,719,796

Derivative instruments
217,027

 
242,866

Customer advances
266,676

 
252,888

Pension and employee benefit obligations
998,212

 
1,163,265

Other
239,519

 
229,207

Total deferred credits and other liabilities
9,826,032

 
9,185,631

 
 
 
 
Commitments and contingencies


 


Capitalization
 

 
 

Long-term debt
10,914,273

 
10,143,905

Common stock — 1,000,000,000 shares authorized of $2.50 par value; 497,625,709 and
487,959,516 shares outstanding at Sept. 30, 2013 and Dec. 31, 2012, respectively
1,244,064

 
1,219,899

Additional paid in capital
5,615,716

 
5,353,015

Retained earnings
2,797,486

 
2,413,816

Accumulated other comprehensive loss
(109,980
)
 
(112,653
)
Total common stockholders’ equity
9,547,286

 
8,874,077

Total liabilities and equity
$
33,126,652

 
$
31,140,686


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
 
 
 
 
 
 
 
Shares
 
Par Value
 
Additional Paid
In Capital
 
Retained
Earnings
 
Accumulated
Other
Comprehensive
Loss
 
 Total
Common
Stockholders’
Equity
Three Months Ended Sept. 30, 2013 and 2012
 

 
 
 
 
 
 
 
 
 
 
Balance at June 30, 2012
487,286

 
$
1,218,214

 
$
5,316,658

 
$
2,140,639

 
$
(102,006
)
 
$
8,573,505

Net income


 


 


 
398,106

 


 
398,106

Other comprehensive loss


 


 


 


 
(7,594
)
 
(7,594
)
Dividends declared:
 

 
 

 
 

 
 

 
 

 
 

Common stock


 


 


 
(132,729
)
 


 
(132,729
)
Issuances of common stock
327

 
818

 
8,679

 


 


 
9,497

Share-based compensation


 


 
9,378

 


 


 
9,378

Balance at Sept. 30, 2012
487,613

 
$
1,219,032

 
$
5,334,715

 
$
2,406,016

 
$
(109,600
)
 
$
8,850,163

 
 
 
 
 
 
 
 
 
 
 
 
Balance at June 30, 2013
497,296

 
$
1,243,239

 
$
5,595,906

 
$
2,572,935

 
$
(111,835
)
 
$
9,300,245

Net income


 


 


 
364,752

 


 
364,752

Other comprehensive income


 


 


 


 
1,855

 
1,855

Dividends declared:
 

 
 

 
 

 
 

 
 

 
 

Common stock


 


 


 
(140,201
)
 


 
(140,201
)
Issuances of common stock
330

 
825

 
8,966

 


 


 
9,791

Share-based compensation


 


 
10,844

 


 


 
10,844

Balance at Sept. 30, 2013
497,626

 
$
1,244,064

 
$
5,615,716

 
$
2,797,486

 
$
(109,980
)
 
$
9,547,286


See Notes to Consolidated Financial Statements










7

Table of Contents

XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY (UNAUDITED)
(amounts in thousands)
 
Common Stock Issued
 
 
 
 
 
 
 
Shares
 
Par Value
 
Additional Paid
In Capital
 
Retained
Earnings
 
Accumulated
Other
Comprehensive
Loss
 
 Total
Common
Stockholders’
Equity
Nine Months Ended Sept. 30, 2013 and 2012
 

 
 
 
 
 
 
 
 
 
 
Balance at Dec. 31, 2011
486,494

 
$
1,216,234

 
$
5,327,443

 
$
2,032,556

 
$
(94,035
)
 
$
8,482,198

Net income
 

 
 

 
 

 
765,059

 
 

 
765,059

Other comprehensive loss
 

 
 

 
 

 
 

 
(15,565
)
 
(15,565
)
Dividends declared:
 

 
 

 
 

 
 

 
 

 
 

Common stock
 

 
 

 
 

 
(391,599
)
 
 

 
(391,599
)
Issuances of common stock
1,819

 
4,548

 
19,449

 
 

 
 

 
23,997

Repurchase of common stock
(700
)
 
(1,750
)
 
(16,779
)
 
 

 
 

 
(18,529
)
Purchase of common stock for
settlement of equity awards
 

 
 

 
(23,307
)
 
 

 
 

 
(23,307
)
Share-based compensation
 

 
 

 
27,909

 
 

 
 

 
27,909

Balance at Sept. 30, 2012
487,613

 
$
1,219,032

 
$
5,334,715

 
$
2,406,016

 
$
(109,600
)
 
$
8,850,163

 
 
 
 
 
 
 
 
 
 
 
 
Balance at Dec. 31, 2012
487,960

 
$
1,219,899

 
$
5,353,015

 
$
2,413,816

 
$
(112,653
)
 
$
8,874,077

Net income


 


 


 
798,179

 


 
798,179

Other comprehensive income


 


 


 


 
2,673

 
2,673

Dividends declared:
 

 
 

 
 

 
 

 
 

 
 

Common stock


 


 


 
(414,509
)
 


 
(414,509
)
Issuances of common stock
9,666

 
24,165

 
228,751

 


 


 
252,916

Share-based compensation


 


 
33,950

 


 


 
33,950

Balance at Sept. 30, 2013
497,626

 
$
1,244,064

 
$
5,615,716

 
$
2,797,486

 
$
(109,980
)
 
$
9,547,286


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, 2013 and Dec. 31, 2012; 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, 2013 and 2012; and its cash flows for the nine months ended Sept. 30, 2013 and 2012.  All adjustments are of a normal, recurring nature, except as otherwise disclosed.  Management has also evaluated the impact of events occurring after Sept. 30, 2013 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, 2012 balance sheet information has been derived from the audited 2012 consolidated financial statements included in the Xcel Energy Inc. Annual Report on Form 10-K for the year ended Dec. 31, 2012.  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, 2012, filed with the SEC on Feb. 22, 2013.  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, 2012, appropriately represent, in all material respects, the current status of accounting policies and are incorporated herein by reference.

2.
Accounting Pronouncements

Recently Adopted

Balance Sheet Offsetting — In December 2011, the Financial Accounting Standards Board (FASB) issued Balance Sheet (Topic 210) — Disclosures about Offsetting Assets and Liabilities (Accounting Standards Update (ASU) No. 2011-11), which requires disclosures regarding netting arrangements in agreements underlying derivatives, certain financial instruments and related collateral amounts, and the extent to which an entity’s financial statement presentation policies related to netting arrangements impact amounts recorded to the financial statements.  In January 2013, the FASB issued Balance Sheet (Topic 210) – Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities (ASU No. 2013-01) to clarify the specific instruments that should be considered in these disclosures.  These disclosure requirements do not affect the presentation of amounts in the consolidated balance sheets, and were effective for annual reporting periods beginning on or after Jan. 1, 2013, and interim periods within those annual reporting periods.  Xcel Energy implemented the disclosure guidance effective Jan. 1, 2013, and the implementation did not have a material impact on its consolidated financial statements.  See Note 8 for the required disclosures.

Comprehensive Income Disclosures — In February 2013, the FASB issued Comprehensive Income (Topic 220) — Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income (ASU No. 2013-02), which requires detailed disclosures regarding changes in components of accumulated other comprehensive income and amounts reclassified out of accumulated other comprehensive income.  These disclosure requirements do not change how net income or comprehensive income are presented in the consolidated financial statements.  These disclosure requirements were effective for annual reporting periods beginning on or after Dec. 15, 2012, and interim periods within those annual reporting periods.  Xcel Energy implemented the disclosure guidance effective Jan. 1, 2013, and the implementation did not have a material impact on its consolidated financial statements.  See Note 13 for the required disclosures.


9

Table of Contents

3.
Selected Balance Sheet Data

(Thousands of Dollars)
 
Sept. 30, 2013
 
Dec. 31, 2012
Accounts receivable, net
 
 
 
 
Accounts receivable
 
$
838,271

 
$
769,440

Less allowance for bad debts
 
(51,397
)
 
(51,394
)
 
 
$
786,874

 
$
718,046

(Thousands of Dollars)
 
Sept. 30, 2013
 
Dec. 31, 2012
Inventories
 
 

 
 
Materials and supplies
 
$
228,302

 
$
213,739

Fuel
 
201,728

 
189,425

Natural gas
 
174,598

 
132,410

 
 
$
604,628

 
$
535,574

(Thousands of Dollars)
 
Sept. 30, 2013
 
Dec. 31, 2012
Property, plant and equipment, net
 
 

 
 
Electric plant
 
$
29,550,871

 
$
28,285,031

Natural gas plant
 
3,942,182

 
3,836,335

Common and other property
 
1,467,811

 
1,480,558

Plant to be retired (a)
 
115,753

 
152,730

Construction work in progress
 
2,391,783

 
1,757,189

Total property, plant and equipment
 
37,468,400

 
35,511,843

Less accumulated depreciation
 
(12,462,716
)
 
(12,048,697
)
Nuclear fuel
 
2,157,940

 
2,090,801

Less accumulated amortization
 
(1,821,046
)
 
(1,744,599
)
 
 
$
25,342,578

 
$
23,809,348


(a) 
In 2010, in response to the Clean Air Clean Jobs Act (CACJA), the Colorado Public Utilities Commission (CPUC) approved the early retirement of Cherokee Units 1, 2 and 3, Arapahoe Unit 3 and Valmont Unit 5 between 2011 and 2017.  In 2011, Cherokee Unit 2 was retired and in 2012, Cherokee Unit 1 was retired.  Amounts are presented net of accumulated depreciation.

4.
 Income Taxes

Except to the extent noted below, the circumstances set forth in 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, 2012 appropriately represent, in all material respects, the current status of other income tax matters, and are incorporated herein by reference.

Federal Audit  Xcel Energy files a consolidated federal income tax return.  The statute of limitations applicable to Xcel Energy’s 2008 federal income tax return expired in September 2012.  The statute of limitations applicable to Xcel Energy’s 2009 federal income tax return expires in June 2015.  In the third quarter of 2012, the Internal Revenue Service (IRS) commenced an examination of tax years 2010 and 2011.  As of Sept. 30, 2013, the IRS had not proposed any material adjustments to tax years 2010 and 2011.


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Table of Contents

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, 2013, 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
 
2006
Minnesota
 
2009
Texas
 
2009
Wisconsin
 
2009

In the fourth quarter of 2012, the state of Colorado commenced an examination of tax years 2006 through 2009.  In the first quarter of 2013, the state of Wisconsin commenced an examination of tax years 2009 through 2011.  As of Sept. 30, 2013, no material adjustments had been proposed for either of these audits.  There are currently no other state income tax audits in progress.

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, 2013
 
Dec. 31, 2012
Unrecognized tax benefit — Permanent tax positions
 
$
8.8

 
$
4.7

Unrecognized tax benefit — Temporary tax positions
 
32.4

 
29.8

Total unrecognized tax benefit
 
$
41.2

 
$
34.5


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, 2013
 
Dec. 31, 2012
NOL and tax credit carryforwards
 
$
(40.1
)
 
$
(33.5
)

It is reasonably possible that Xcel Energy’s amount of unrecognized tax benefits could significantly change in the next 12 months as the IRS and state audits progress.  As the IRS examination moves closer to completion, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $35 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, 2013 and Dec. 31, 2012 were not material.  No amounts were accrued for penalties related to unrecognized tax benefits as of Sept. 30, 2013 or Dec. 31, 2012.

Tangible Property Regulations — In September 2013, the U.S. Treasury issued final regulations addressing the tax consequences associated with the acquisition, production and improvement of tangible property. As Xcel Energy had adopted certain utility-specific guidance previously issued by the IRS, the issuance is not expected to have a material impact on its consolidated financial statements.

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, 2012 and in Note 5 to Xcel Energy Inc.’s Quarterly Reports on Form 10-Q for the quarter periods ended March 31, 2013 and June 30, 2013, appropriately represent, in all material respects, the current status of other rate matters, and are incorporated herein by reference.


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NSP-Minnesota

Recently Concluded Regulatory Proceedings — Minnesota Public Utilities Commission (MPUC)

NSP-Minnesota – Minnesota 2013 Electric Rate Case  In November 2012, NSP-Minnesota filed a request with the MPUC for an increase in annual revenues of approximately $285 million, or 10.7 percent.  The rate filing was based on a 2013 forecast test year (FTY), a requested return on equity (ROE) of 10.6 percent, an average electric rate base of approximately $6.3 billion and an equity ratio of 52.56 percent.  In January 2013, interim rates of approximately $251 million became effective, subject to refund.

NSP-Minnesota subsequently revised the requested annual revenue increase to approximately $209 million, or 7.8 percent, based on an ROE of 10.6 percent, a rate base of approximately $6.3 billion an equity ratio of 52.56 percent. The revenue requirement reflected a requested deficiency of $259 million combined with $50 million of rate mitigation through deferral mechanisms.

On Sept. 3, 2013, the MPUC issued an order approving a rate increase of approximately $103 million, or 3.8 percent, based on a 9.83 percent ROE and 52.56 percent equity ratio. In addition, the MPUC authorized approximately $20 million in deferrals, as well as a $24 million reduction in revenue and depreciation expense.

The table below reconciles NSP-Minnesota’s original request to the final MPUC order:
(Millions of Dollars)
 
NSP-Minnesota Request
 
Administrative Law Judge (ALJ) Recommendation
 
MPUC Order
NSP-Minnesota original request
 
$
285

 
$
285

 
$
285

ROE
 

 
(43
)
 
(43
)
Sherco Unit 3
 
(35
)
 
(38
)
 
(34
)
Reduced recovery for nuclear plants
 
(11
)
 
(14
)
 
(15
)
Incentive compensation
 
(3
)
 
(4
)
 
(4
)
Sales forecast
 
(1
)
 
(26
)
 
(26
)
Pension
 
(10
)
 
(13
)
 
(13
)
Employee benefits
 
(4
)
 
(6
)
 
(6
)
Black Dog remediation
 
(5
)
 
(5
)
 
(5
)
Estimated impact of the theoretical depreciation reserve
 

 

 
(24
)
NSP-Wisconsin wholesale allocation
 
(7
)
 
(7
)
 
(7
)
Other, net
 

 
(2
)
 
(5
)
    Recommended rate increase
 
209

 
127

 
103

Estimated impact of cost deferrals
 
50

 
34

 
20

Estimated impact of the theoretical depreciation reserve
 

 

 
24

    Impact on pre-tax income
 
$
259

 
$
161

 
$
147


NSP-Minnesota filed its final rate implementation and interim rate refund compliance filing on Sept. 19, 2013, requesting final rates be implemented Dec. 1, 2013, with interim rate refunds of approximately $132.2 million, including interest, to begin by January 2014. The Office of the Attorney General requested the MPUC to reconsider its Sept. 3, 2013 order with respect to the calculation of AFUDC. NSP-Minnesota has filed a response opposing the motion. Both items are pending MPUC action.

In the third quarter of 2013, NSP-Minnesota increased the reserve for revenue subject to refund by $30 million, and also recorded a reduction to depreciation expense and other operating expenses in the same amount, to implement the cost deferral and depreciation requirements of the final MPUC order. Adjustments to the reserve in the third quarter of 2013 related to revenue recognized in the first and second quarters of 2013 were not material.


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NSP-Minnesota Nuclear Project Prudence Investigation — In the NSP-Minnesota 2013 Minnesota electric rate case final order, the MPUC initiated an investigation to determine whether the costs in excess of those included in the Certificate of Need (CON) for NSP-Minnesota’s Monticello life cycle management (LCM)/extended power uprate (EPU) project were prudently incurred. In October 2013, NSP-Minnesota filed a summary report and witness testimony to further support the change in and prudence of the incurred costs. The filing indicated the increase in costs was primarily attributable to three factors: (1) the original estimate was based on a high level conceptual design and the project scope increased as the actual conditions of the plant were incorporated into the design; (2) implementation difficulties, including the amount of work that occurred in confined and radioactive or electrically sensitive spaces and NSP-Minnesota’s and its vendors’ ability to attract and retain experienced workers; and (3) additional Nuclear Regulatory Commission (NRC) licensing related requests over the five-plus year application process. In September 2013, the Advisory Committee to the NRC on Reactor Safety recommended approval of the EPU license. The EPU license is expected to be granted by the end of 2013 and the complementary MELLA Plus fuel license is anticipated to be received in March 2014. NSP-Minnesota has provided information that the cost deviation is in line with similar upgrade projects undertaken and the project remains economically beneficial to customers. The results and any recommendations from the conclusion of this prudence proceeding are expected to be considered by the MPUC in NSP-Minnesota’s 2014 Minnesota electric rate case.

Pending Regulatory Proceedings — North Dakota Public Service Commission (NDPSC)

NSP-Minnesota – North Dakota 2013 Electric Rate Case — In December 2012, NSP-Minnesota filed a request with the NDPSC to increase annual retail electric rates approximately $16.9 million, or 9.25 percent.  The rate filing is based on a 2013 FTY, a requested ROE of 10.6 percent, an electric rate base of approximately $377.6 million and an equity ratio of 52.56 percent.  In January 2013, the NDPSC approved an interim electric increase of $14.7 million, effective Feb. 16, 2013, subject to refund. In June 2013, NSP-Minnesota revised its rate increase to $16 million, reflecting updated information.

On Aug. 12, 2013, NSP-Minnesota filed rebuttal testimony revising the requested increase in retail electric rates to approximately $14.9 million, based on a revised ROE of 10.25 percent and incorporating the updated information from June 2013.

On Aug. 22, 2013, NDPSC Staff filed supplemental testimony revising their recommendation by removing a positive adjustment for federal taxes and adjusting depreciation to reflect longer asset lives. In total, the NDPSC Staff’s filed position was modified to a $10 million rate reduction. The recommendation reflects a 9.0 percent ROE.

Primary revenue requirement adjustments include:
(Millions of Dollars)
 
NSP-Minnesota Rebuttal Testimony
 
NDPSC Position
as Supplemented
NSP-Minnesota revised request
 
$
16.0

 
$
16.0

Use of a one month coincident peak demand allocator for certain rate base and operation expenses
 

 
(20.4
)
ROE
 
(1.2
)
 
(5.2
)
Incentive compensation
 

 
(0.8
)
Adjustment for various O&M expenses
 

 
(0.7
)
Modified cost of capital and increased capital structure to 53.42 percent
 
0.1

 
1.3

Depreciation/remaining life study
 

 
(1.1
)
Other, net
 

 
0.9

Recommended rate increase (decrease)
 
$
14.9

 
$
(10.0
)

Evidentiary hearings were conducted in late August 2013. A final NDPSC decision on the case is anticipated in the fourth quarter of 2013 or the first quarter of 2014.


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Table of Contents

Recently Concluded Regulatory Proceedings — South Dakota Public Utilities Commission (SDPUC)

NSP-Minnesota – South Dakota 2012 Electric Rate Case — In March 2013, NSP-Minnesota and the SDPUC Staff reached a settlement agreement that provides for a base rate increase of approximately $11.6 million and the implementation of a new rider. On Oct. 1, 2013, NSP-Minnesota filed its compliance report consistent with the settlement to recover the revenue requirement on the specific major capital additions and incremental property tax resulting in recovery of $8.7 million for 2014.

NSP-Wisconsin

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

NSP-Wisconsin – Wisconsin 2014 Electric and Gas Rate Case  On May 31, 2013, NSP-Wisconsin filed a request with the PSCW to increase rates for electric and natural gas service effective Jan. 1, 2014. NSP-Wisconsin requested an overall increase in annual electric rates of $40.0 million, or 6.5 percent, and an increase in natural gas rates of $4.7 million, or 3.8 percent.

The rate filing is based on a 2014 FTY, an ROE of 10.4 percent, an equity ratio of 52.5 percent and a forecasted average net investment rate base of approximately $895.3 million for the electric utility and $89.8 million for the natural gas utility.

On Oct. 4, 2013, the PSCW Staff filed their direct testimony and recommended an electric rate increase of $23.8 million, or 3.8 percent, and a natural gas rate decrease of $1.1 million, or 0.9 percent. PSCW Staff’s recommendations were based on a 10.2 percent ROE and a 52.5 percent equity ratio. 

The most significant adjustments proposed by the PSCW Staff are shown in the table below:
(Millions of Dollars)
 
Electric
Staff Testimony
October 2013
 
Natural Gas
Staff Testimony
October 2013
Rate request
 
$
40.0

 
$
4.7

Electric fuel and purchased power
 
(5.1
)
 

Sales forecast
 
(4.8
)
 

Incentive compensation and merit pay
 
(3.0
)
 
(0.6
)
ROE
 
(1.6
)
 
(0.2
)
Conservation funding transfer
 
0.7

 
(0.7
)
Depreciation expense
 
(0.7
)
 
(1.3
)
Ashland site amortization expense
 

 
(2.3
)
Other, net
 
(1.7
)
 
(0.7
)
Recommended rate increase (decrease)
 
$
23.8

 
$
(1.1
)

The majority of the adjustment to electric fuel and purchased power is the result of the PSCW Staff’s proposal to discontinue using the New York Mercantile Exchange (NYMEX) futures prices as a basis for setting the fuel price forecast and instead using a discounted percentage of the NYMEX futures prices. PSCW Staff’s sales forecast adjustment is based on the assumption that the strong sales growth trend from 2010 through 2012, primarily in the large commercial/industrial sector, will continue through 2013 and 2014, while NSP-Wisconsin’s forecast shows moderating growth.

On Oct. 18, 2013, NSP-Wisconsin filed rebuttal testimony, revising the requested electric rate increase to $34.0 million and natural gas rate increase to zero, based on a 10.4 percent ROE and other adjustments.

Next steps in the procedural schedule are as follows:

Surrebuttal testimony - Oct. 28, 2013;
Hearing - Oct. 30, 2013;
Initial brief - Nov. 13, 2013; and
Reply brief - Nov. 20, 2013.

A PSCW decision is anticipated in December 2013, with final rates going into effect in January 2014.


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Table of Contents

PSCo

Pending and Recently Concluded Regulatory Proceedings — CPUC

PSCo – Colorado 2013 Gas Rate Case In December 2012, PSCo filed a multi-year request with the CPUC to increase Colorado retail natural gas rates by $48.5 million in 2013 with subsequent step increases of $9.9 million in 2014 and $12.1 million in 2015.  The request is based on a 2013 FTY, a 10.5 percent ROE, a rate base of $1.3 billion and an equity ratio of 56 percent.  PSCo is requesting an extension of its Pipeline System Integrity Adjustment (PSIA) rider mechanism to collect the costs associated with its pipeline integrity efforts, including accelerated system renewal projects.  PSCo estimates that the PSIA will increase by $26.8 million in 2014 with a subsequent step increase of $24.7 million in 2015 in addition to the proposed changes in base rate revenue.  In conjunction with the multi-year base rate step increases, PSCo is proposing a stay-out provision and an earnings test through the end of 2015 with a commitment to file a rate case to implement revised rates on Jan. 1, 2016. Interim rates, subject to refund, went into effect in August 2013.

In April 2013, four parties filed answer testimony in the natural gas case.  The CPUC Staff recommended an incremental base revenue decrease of $1.1 million, based on a historic test year (HTY), an ROE of 9 percent and an equity ratio of 52 percent. The Office of Consumer Counsel (OCC) recommended an incremental base revenue increase of $15.4 million based on an HTY, an ROE of 9 percent and equity ratio of 51.03 percent and other adjustments.  The recommended incremental base revenues are inclusive of proposed changes to the level of integrity management costs moved from the PSIA rider to base rates.  

In April 2013, PSCo filed rebuttal testimony and revised its requested annual rate increase to $44.8 million for 2013, with subsequent step increases of $9.0 million for 2014 and $10.9 million for 2015, based on an ROE of 10.3 percent.  This requested increase includes amounts to be transferred from the PSIA rider mechanism. The deficiency, based on an FTY, was $30.6 million.

In October 2013, the ALJ issued her recommendation. As part of this decision, she recommended the use of an HTY, an ROE of 9.72 percent and an equity ratio of 56 percent. The ALJ also recommended to reject PSCo’s proposed changes to the PSIA, instead leaving the current rider in effect and suggested that changes be presented in a separate application. The recommended incremental base revenue increase was approximately $15.0 million.

The following table summarizes the CPUC Staff, OCC and ALJ’s recommendations:
(Millions of Dollars)
 
CPUC Staff
 
OCC
 
ALJ
PSCo deficiency based on a FTY
 
$
44.8

 
$
44.8

 
$
44.8

Move to HTY
 
(1.6
)
 
(1.6
)
 
(1.6
)
ROE and capital structure adjustments
 
(20.8
)
 
(20.0
)
 
(7.7
)
Move to a 13 month average from year end rate base
 
(5.7
)
 
(3.2
)
 
(3.3
)
Remove pension asset
 
(5.9
)
 

 

Reduce pension expense net of corrections
 
(1.6
)
 

 

Remove incentive compensation
 
(3.5
)
 
(0.2
)
 
(0.2
)
Challenge known and measurable
 

 
(9.0
)
 

Eliminate depreciation annualization
 

 
(1.8
)
 

Revenue adjustments
 
(4.1
)
 
(1.4
)
 
(1.4
)
Resulting tax impacts
 
1.5

 
4.7

 
(0.2
)
Other adjustments
 
(4.2
)
 
3.1

 
(1.2
)
Remove PSIA from base rates
 
(14.2
)
 
(14.2
)
 

Recommendation
 
$
(15.3
)
 
$
1.2

 
$
29.2

 
 
 
 
 
 
 
Neutralize PSIA - base rate transfer
 
14.2

 
14.2

 
(14.2
)
Incremental base revenue
 
$
(1.1
)
 
$
15.4

 
$
15.0


Exceptions and corresponding responses are due to be filed in November 2013 and a CPUC decision is expected in December 2013.


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PSCo – Colorado 2013 Steam Rate Case In December 2012, PSCo filed a request to increase Colorado retail steam rates by $1.6 million in 2013 with subsequent step increases of $0.9 million in 2014 and $2.3 million in 2015.  The request is based on a 2013 FTY, a 10.5 percent ROE, a rate base of $21 million for steam and an equity ratio of 56 percent.  

In October 2013, PSCo, the CPUC Staff, the OCC and Colorado Energy Consumers representing the Buildings Owners Management Association filed a comprehensive settlement which ties the outcome of the steam rate case to key issues to be decided in the natural gas rate case, including ROE and capital structure and allows the filed rates to be effective on Jan. 1, 2014, subject to refund for 60 days, resulting in a minimum 2014 annual rate increase of $1.2 million. The settlement withdraws the rate relief request for 2015 pending the outcome of the certificate of public convenience and necessity (CPCN) proceeding for the construction of the Sun Valley Steam Center. A decision on the settlement is expected at the end of 2013.

PSCo – Annual Electric Earnings Test — An earnings sharing mechanism is used to apply prospective electric rate adjustments for earnings in the prior year over PSCo’s authorized ROE threshold of 10 percent.  In June 2013, PSCo entered into a comprehensive settlement of issues with all parties associated with the 2012 earnings test, resulting in a refund obligation of approximately $8.2 million to be refunded through June 2014. As of Sept. 30, 2013, PSCo has also recognized management’s best estimate of an accrual for the 2013 test year.

PSCo – Production Formula Rate ROE Complaint — On Aug. 30, 2013, PSCo’s wholesale production customers filed a complaint with the Federal Energy Regulatory Commission (FERC), and requested it reduce the stated ROEs ranging from 10.1 percent through 10.4 percent to 9.04 percent in the PSCo power sales formula rates, which could reduce revenues approximately $2 million per year prospectively. The matter is currently pending the FERC’s action.

Renewable Energy Credit (REC) Sharing — In May 2011, the CPUC determined that margin sharing on stand-alone REC transactions would be shared 20 percent to PSCo and 80 percent to customers and ultimately becoming 10 percent to PSCo and 90 percent to customers by 2014.  The CPUC also approved a change to the treatment of hybrid REC trading margins (RECs that are bundled with energy) that allows the customers’ share of the margins to be netted against the renewable energy standard adjustment (RESA) regulatory asset balance.

In March 2012, the CPUC approved an annual margin sharing on the first $20 million of margins on hybrid REC trades of 80 percent to the customers and 20 percent to PSCo.  Margins in excess of the $20 million are to be shared 90 percent to the customers and 10 percent to PSCo.  The CPUC authorized PSCo to return to customers unspent carbon offset funds by crediting the RESA regulatory asset balance.  For the three months ended Sept. 30, 2013 and 2012, PSCo credited the RESA regulatory asset balance $6.1 million and $6.2 million, respectively.  The cumulative credit to the RESA regulatory asset balance was $99.4 million and $82.8 million at Sept. 30, 2013 and Dec. 31, 2012, respectively.  The credits include the customers’ share of REC trading margins and the customers’ share of carbon offset funds.

This sharing mechanism will be effective through 2014. The CPUC is then expecting to review the framework and evidence regarding actual deliveries before determining to continue the sharing mechanism.

Electric Commodity Adjustment (ECA) / RESA Adjustment — In July 2013, PSCo advised the CPUC that it had inadvertently allocated purchased power expense between the deferred accounts for the ECA and the RESA from 2010 to 2012. In order to be in compliance with a series of CPUC orders, PSCo proposed to transfer from the RESA deferred account to the ECA deferred account approximately $26.2 million and to amortize the recovery of this amount over 12 months. The transfer, if approved, would mainly impact the timing of recovery. In addition, interest of $2.6 million was accrued on the amount related to the RESA. The PSCo application to change the ECA tariff to address this issue has been set for hearing in December 2013 by the CPUC.

ECA Prudence Review — In September 2013, the CPUC Staff requested that the 2012 annual ECA prudence review be set for hearing. The prudence review, as determined by the ALJ, will primarily consider if replacement power costs during the outage of jointly owned facilities were properly allocated between wholesale and retail customers. A hearing is expected in January 2014.

2012 PSIA Report — In April 2013, PSCo filed its 2012 PSIA report. The OCC and CPUC Staff requested the CPUC set the matter for hearing to review in detail the information provided, including a review of the prudence of expenditures in 2012, and to develop standards for future filings. The CPUC approved the request on July 10, 2013 and assigned the matter to an ALJ.


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Table of Contents

Next steps in the procedural schedule are as follows:

Direct testimony - Nov. 5, 2013;
Intervenor testimony - Jan. 7, 2014;
Rebuttal testimony - Feb. 6, 2014;
Evidentiary hearing - March 3 - March 7, 2014;
Initial brief - March 28, 2014; and
Reply brief - April 11, 2014.

SPS

Recently Concluded Regulatory Proceedings — Public Utility Commission of Texas (PUCT)

SPS – Texas 2012 Electric Rate Case — In November 2012, SPS filed an electric rate case in Texas with the PUCT for an increase in annual revenue of approximately $90.2 million.  The rate filing is based on a historic twelve month test year ended June 30, 2012 (adjusted for known and measurable changes), a requested ROE of 10.65 percent, an electric rate base of $1.15 billion and an equity ratio of 52 percent.

In June 2013, the PUCT approved a settlement agreement in which SPS’ base rate increased by $37 million, effective May 1, 2013 and by an additional $13.8 million on Sept. 1, 2013.  In addition, the settlement allows SPS to file a transmission cost recovery adjustment rider in the fourth quarter of 2013 and for those rates to become effective on an interim basis in January 2014.  Under the settlement, SPS cannot file another base rate case in 2013, but there are no restrictions on SPS filing a base rate case in 2014.  

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

SPS – New Mexico 2014 Electric Rate Case — In December 2012, SPS filed an electric rate case in New Mexico with the NMPRC for an increase in annual revenue of approximately $45.9 million effective in 2014.  The rate filing is based on a 2014 FTY, a requested ROE of 10.65 percent, a jurisdictional electric rate base of $479.8 million and an equity ratio of 53.89 percent. On June 19, 2013, SPS revised its requested rate increase to $43.3 million.

In August 2013, the NMPRC Staff (Staff), the New Mexico Attorney General (NMAG), the Federal Executive Agencies, the Coalition of Clean Affordable Energy, Occidental Permian, Ltd. and New Mexico Gas Company filed testimony.


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Table of Contents

The following table summarizes certain parties’ recommendations from SPS’ revised request:
(Millions of Dollars)
 
Staff
Testimony
August 2013
 
NMAG
Testimony
August 2013
SPS revised request
 
$
43.3

 
$
43.3

Rate rider for renewable energy costs (a)
 
(14.5
)
 
(8.5
)
Present revenues (sales growth and weather)
 
(4.4
)
 
(6.4
)
ROE (9.8 percent and 8.63 percent, respectively)
 
(3.2
)
 
(8.1
)
Capital structure
 
(1.5
)
 
(1.1
)
Employee benefits
 
(2.8
)
 
(1.8
)
Reduced recovery for payroll expense
 
(0.1
)
 
(0.1
)
Gain on sale of transmission assets
 

 
(1.7
)
Fuel clause revenue
 
6.0

 

Other, net
 
(5.0
)
 
(6.6
)
Recommended rate increase
 
$
17.8

 
$
9.0

 
 
 
 
 
Means of recovery:
 
 
 
 
Base revenue
 
$
8.8

 
$
(6.0
)
Rider revenue
 
7.3

 
13.3

Fuel cost adjustment revenue
 
1.7

 
1.7

 
 
$
17.8

 
$
9.0


(a) 
Adjustments represent recommended deferrals, extended amortizations and moving costs from rider to fuel in base rates.

On Sept. 9, 2013, SPS filed rebuttal testimony, revising its requested rate increase to $32.5 million, based on updated information and an ROE of 10.25 percent. This reflects a base and fuel increase of $20.9 million, an increase of rider revenue of $12.1 million and a decrease to other of $0.5 million.

The hearings on the merits of the case concluded in September 2013. Next steps in the procedural schedule are expected to be as follows:

A recommended decision is anticipated from the hearing examiner in November 2013;
An NMPRC decision is anticipated in the first quarter of 2014; and
Final rates are expected to be effective in the first quarter of 2014.

SPS – 2004 FERC Complaint Case Orders  In August 2013, the FERC issued an order on rehearing and clarification related to a 2004 Complaint case brought by Golden Spread (a wholesale cooperative customer) and Public Service Company of New Mexico (PNM) and an Order on Initial Decision in a subsequent 2006 rate case filed by SPS. The original Complaint included two key components; the first was the appropriateness of the allocations of system average fuel costs and the second was a base rate complaint, including the appropriate demand-related cost allocator.

The first issue related to PNM’s claim regarding inappropriate allocation of fuel costs. The FERC clarified its initial order and granted SPS’ request for clarification that PNM was not entitled to refunds based on the FERC’s April 2008 Order in the Complaint case. The FERC determined that refunds should apply only to firm requirements customers and not PNM’s contractual load.

The second issue related to the use of a 12 coincident peak (CP) vs. 3CP demand allocator. This issue first arose in the base rate revenue requirements portion of Golden Spread’s 2004 Complaint as well as SPS’ 2006 rate case. In December 2007, SPS reached a settlement of all fuel issues with Golden Spread, and entered a formula rate agreement for its production costs. That agreement indicated that all issues from the complaint period were resolved and that all base rate issues from the 2006 rate case were resolved other than the 12CP vs. 3CP issue and the formula rate tariff allows this issue to be resolved.


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In April 2008, the FERC issued an order resolving the remaining rate issues and found in favor of SPS on the disputed rate issue, concluding that SPS was a 12CP system. Golden Spread asked for rehearing of this issue in May of 2008. Also in May 2008, in a subsequent SPS rate case involving all requirements customers (other than Golden Spread), the FERC granted the motion of the full requirements customers and SPS reaffirming that SPS was a 12CP system. As a result of these FERC actions, SPS considered the issued to be resolved and the risk of loss to be remote.

In the orders issued in August 2013, the FERC reversed itself, stating that it erred in its initial analysis and determined that the SPS system was a 3CP rather than a 12CP system. As a result, SPS estimates that the combination of the order and the December 2007 settlement creates a refund liability of approximately $42 million including interest. This would be partially offset by a reserve that had been established for the PNM decision and the amounts for which the New Mexico Cooperatives had agreed to refund in the event of this outcome. The pre-tax impact to 2013 earnings from these orders is approximately $35 million, which was recorded in the third quarter of 2013. Pending the timing and resolution of this matter, the annual impact to revenues through 2014 could be up to $6 million and decreasing to $4 million on June 1, 2015.

In September 2013, SPS filed a request for rehearing of the FERC ruling on the CP allocation and refund decisions. SPS asserted that the FERC applied an improper burden of proof in reversing the 2008 ruling and that precedent did not support retroactive refunds. PNM also requested rehearing of the FERC decision not to reverse its prior ruling. In October 2013, the FERC issued orders further considering the requests for rehearing. These matters are currently pending the FERC’s action. If unsuccessful in its rehearing request, SPS will have the opportunity to file rate cases with the FERC and its retail jurisdictions in attempt to change all customers to a 3CP allocation method.

Purchase and Sale Agreement for Certain Texas Transmission Assets — On March 29, 2013, SPS entered into a purchase and sale agreement with Sharyland Distribution and Transmission Services, LLC (Sharyland) for the sale of certain segments of SPS’ transmission lines and two related substations for a base purchase price of $37 million, subject to adjustments for unplanned capital expenditures.  The transaction is subject to various regulatory approvals including that of the FERC.

On April 29, 2013, SPS made filings regarding the planned transaction with the PUCT, the NMPRC and the FERC.  If approved, the sale is expected to close by the end of 2013. The FERC approved the transaction in August 2013 and on Sept. 20, 2013 SPS filed an unopposed stipulation at the PUCT resolving all issues related to the SPS items in the joint application SPS filed together with Sharyland. In the proposed settlement to the PUCT, the Texas retail jurisdiction would be allocated 45 percent of the net pre-tax gain on sale and this amount would be shared 60 percent with customers and 40 percent would be retained by SPS.

On Sept. 12, 2013, the NMPRC Staff and the NMAG filed testimony in support of the sale of the transmission assets. Both parties proposed that SPS’ New Mexico retail customers should retain 100 percent of any New Mexico jurisdictional share of the gain on sale. On Sept. 27, 2013, SPS filed rebuttal testimony before the NMPRC disputing the positions presented by the NMPRC Staff and the NMAG. An evidentiary hearing was held on Oct. 8, 2013.

Decisions are expected from the NMPRC and PUCT in the fourth quarter of 2013.

6.
Commitments and Contingencies

Except to the extent noted below and in Note 5, 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, 2012, appropriately represent, in all material respects, the current status of commitments and contingent liabilities, including those regarding public liability for claims resulting from any nuclear incident, 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

Under certain purchased power agreements, 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 purchased power agreements create a variable interest in the associated independent power producing entity.


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The Xcel Energy utility subsidiaries had approximately 3,338 megawatts (MW) and 3,324 MW of capacity under long-term purchased power agreements as of Sept. 30, 2013 and Dec. 31, 2012, respectively, 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 the year 2033.

Guarantees and 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 limit the exposure to a maximum amount stated in the guarantees and bond indemnities.  As of Sept. 30, 2013 and Dec. 31, 2012, 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 Inc.:
(Millions of Dollars)
 
Sept. 30, 2013
 
Dec. 31, 2012
Guarantees issued and outstanding
 
$
54.8

 
$
69.5

Current exposure under these guarantees
 
17.8

 
17.9

Bonds with indemnity protection
 
31.9

 
29.6


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 potential amount of future payments under these indemnifications cannot be reasonably estimated as the obligated amounts of these indemnifications often are not explicitly stated.

Environmental Contingencies

Ashland Manufactured Gas Plant (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 Ashland site) includes property owned by NSP-Wisconsin, which was a site previously operated by a predecessor company as a MGP facility (the Upper Bluff), and two other properties: an adjacent city lakeshore park area (Kreher Park), on which an unaffiliated third party previously operated a sawmill and conducted creosote treating operations; and an area of Lake Superior’s Chequamegon Bay adjoining the park (the Sediments).

The U.S. Environmental Protection Agency (EPA) issued its Record of Decision (ROD) in 2010, which describes the preferred remedy the EPA has selected for the cleanup of the Ashland site.  In 2011, the EPA issued special notice letters identifying several entities, including NSP-Wisconsin, as PRPs, for future remediation at the site.  The special notice letters requested that those PRPs participate in negotiations with the EPA regarding how the PRPs intended to conduct or pay for the remediation at the Ashland site.  As a result of those settlement negotiations, the EPA agreed to segment the Ashland site into separate areas.  The first area (Phase I Project Area) includes soil and groundwater in Kreher Park and the Upper Bluff.  The second area includes the Sediments.


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In October 2012, a settlement among the EPA, the Wisconsin Department of Natural Resources (WDNR), the Bad River and Red Cliff Bands of the Lake Superior Tribe of Chippewa Indians and NSP-Wisconsin was approved by the U.S. District Court for the Western District of Wisconsin.  This settlement resolves claims against NSP-Wisconsin for its alleged responsibility for the remediation of the Phase I Project Area.  Under the terms of the settlement, NSP-Wisconsin agreed to perform the remediation of the Phase I Project Area, but does not admit any liability with respect to the Ashland site.  The settlement reflects a cost estimate for the clean up of the Phase I Project Area of $40 million.  The settlement also resolves claims by the federal, state and tribal trustees against NSP-Wisconsin for alleged natural resource damages at the Ashland site, including both the Phase I Project Area and the Sediments.  As part of the settlement, NSP-Wisconsin has conveyed approximately 1,390 acres of land to the State of Wisconsin and tribal trustees.  Fieldwork to address the Phase I Project Area at the Ashland site began at the end of 2012 and continues.

Negotiations between the EPA and NSP-Wisconsin regarding who will pay or perform the cleanup of the Sediments are ongoing.  In August and September 2013, NSP-Wisconsin performed field studies in the Sediments to gather more data about site conditions. The data from that investigation will be received and reported in November 2013. Also, in September 2013, the EPA requested NSP-Wisconsin consider re-submitting another proposal to perform a wet dredge pilot study for a portion of the Sediments. NSP-Wisconsin previously submitted a proposal for a wet dredge pilot study in 2011. The EPA’s ROD for the Ashland site includes estimates that the cost of the preferred remediation related to the Sediments is between $63 million and $77 million, with a potential deviation in such estimated costs of up to 50 percent higher to 30 percent lower.

In August 2012, NSP-Wisconsin also filed litigation against other PRPs for their share of the cleanup costs for the Ashland site.  Trial for this matter has been rescheduled for April 2015. Negotiations between the EPA, NSP-Wisconsin and several of the other PRPs regarding the PRPs’ fair share of the cleanup costs for the Ashland site are also ongoing.

At Sept. 30, 2013 and Dec. 31, 2012, NSP-Wisconsin had recorded a liability of $101.2 million and $103.7 million, respectively, for the Ashland site based upon potential remediation and design costs together with estimated outside legal and consultant costs; of which $19.5 million and $20.1 million, respectively, was considered a current liability.  NSP-Wisconsin’s potential liability, the actual cost of remediation and the time frame over which the amounts may be paid are subject to change.  NSP-Wisconsin also continues to work to identify and access state and federal funds to apply to the ultimate remediation cost of the entire site.  Unresolved issues or factors that could result in higher or lower NSP-Wisconsin remediation costs for the Ashland site include the cleanup approach implemented for the Sediments, which party implements the cleanup, the timing of when the cleanup is implemented, potential contributions by other PRPs and whether federal or state funding may be directed to help offset remediation costs at the Ashland site.

NSP-Wisconsin has deferred the estimated site remediation costs, as a regulatory asset, based on an expectation that the PSCW will continue to allow NSP-Wisconsin to recover payments for environmental remediation from its customers.  The PSCW has consistently authorized in NSP-Wisconsin rates recovery of all remediation costs incurred at the Ashland site, and has authorized recovery of MGP remediation costs by other Wisconsin utilities.  External MGP remediation costs are subject to deferral in the Wisconsin retail jurisdiction and are reviewed for prudence as part of the Wisconsin retail rate case process.  Under an existing PSCW policy, utilities have recovered remediation costs for MGPs in natural gas rates, amortized over a four- to six-year period.  The PSCW historically has not allowed utilities to recover their carrying costs on unamortized regulatory assets for MGP remediation.

In the last rate case decision, the PSCW recognized the potential magnitude of the future liability for the cleanup at the Ashland site and granted an exception to its existing policy at the request of NSP-Wisconsin.  The elements of this exception include: 1) approval to begin recovery of estimated Phase 1 Project costs beginning on Jan. 1, 2013; 2) approval to amortize these estimated costs over a ten-year period; and 3) approval to apply a three percent carrying cost to the unamortized regulatory asset.  Implementation of this exception will help mitigate the rate impact to natural gas customers and the risk to NSP-Wisconsin from a longer amortization period.


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Environmental Requirements

Greenhouse Gas (GHG) New Source Performance Standard (NSPS) Proposal and Emission Guideline for Existing Sources — In September 2013, the EPA re-proposed a GHG NSPS for newly constructed power plants which seeks to establish carbon dioxide (CO2) emission rates for coal-fired power plants that reflect emission reductions using partial carbon capture and storage technology (CCS). The EPA’s proposed CO2 emission limits for gas-fired power plants reflect emissions levels from combined cycle technology with no CCS. The EPA continues to propose that the NSPS not apply to modified or reconstructed existing power plants. In addition, installation of control equipment on existing plants would not constitute a “modification” to those plants under the NSPS program. It is not possible to evaluate the impact of the re-proposed NSPS until its final requirements are known.

In June 2013, President Obama issued a memorandum directing the EPA to develop GHG emission standards for existing power plants. The memorandum anticipates the EPA will issue a proposed GHG emission standard for existing power plants in June 2014. It is not possible to evaluate the impact of existing source standards until the upcoming proposal and final requirements are known.

Cross-State Air Pollution Rule (CSAPR) — In 2011, the EPA issued the CSAPR to address 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.  For Xcel Energy, the rule would have applied in Minnesota, Wisconsin and Texas.  The CSAPR would have set more stringent requirements than the proposed Clean Air Transport Rule and specifically would have required plants in Texas to reduce their SO2 and annual NOx emissions.  The rule also would have created an emissions trading program.

In August 2012, the U.S. Court of Appeals for the District of Columbia Circuit (D.C. Circuit) vacated the CSAPR and remanded it back to the EPA.  The D.C. Circuit stated that the EPA must continue administering the Clean Air Interstate Rule (CAIR) pending adoption of a valid replacement.  In June 2013, the U.S. Supreme Court elected to review the D.C. Circuit’s 2012 decision to vacate the CSAPR. The Court has ordered the parties to file briefs in the appeal this fall and will hear arguments in December 2013. The Court will likely issue a decision by June 2014.

As the EPA continues administering the CAIR while the CSAPR or a replacement rule is pending, Xcel Energy expects to comply with the CAIR as described below.

CAIR — In 2005, the EPA issued the CAIR to further regulate SO2 and NOx emissions.  The CAIR applies to Texas and Wisconsin.  The CAIR does not apply to Minnesota.

Under the CAIR’s cap and trade structure, companies can comply through capital investments in emission controls or purchase of emission allowances from other utilities making reductions on their systems.  NSP-Wisconsin purchased allowances in 2012 and plans to continue to purchase allowances in 2013 to comply with the CAIR.  In the SPS region, installation of low-NOx combustion control technology was completed in 2012 on Tolk Unit 1.  SPS plans to install the same combustion control technology on Tolk Unit 2 in 2014.  These installations will reduce or eliminate SPS’ need to purchase NOx emission allowances.  In addition, SPS has sufficient SO2 allowances to comply with the CAIR in 2013.  At Sept. 30, 2013, the estimated annual CAIR NOx allowance cost for Xcel Energy did not have a material impact on the results of operations, financial position or cash flows.

Federal Clean Water Act - Effluent Limitations Guidelines (ELG) — In June 2013, the EPA published a proposed 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. Refuse derived fuel, biomass and other alternatively fueled power plants are not addressed by the proposed revisions. The proposed rule identifies four potential regulatory options and invites comments on those regulatory approaches. The options differ in the number of waste streams covered, size of the units controlled and stringency of controls. A final rule is anticipated in 2014. Under the current proposed rule, facilities would need to comply as soon as possible after July 2017 but no later than July 2022. The impact of this rule on Xcel Energy is uncertain at this time.

Regional Haze Rules — In 2005, the EPA finalized amendments to its regional haze rules, known as best available retrofit technology (BART), which require the installation and operation of emission controls for industrial facilities emitting air pollutants that reduce visibility in certain national parks and wilderness areas.  Xcel Energy generating facilities in several states are subject to BART requirements.  Individual states were required to identify the facilities located in their states that will have to reduce SO2, NOx and PM emissions under BART and then set emissions limits for those facilities.


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PSCo
In 2011, the Colorado Air Quality Control Commission approved a BART state implementation plan (SIP) incorporating the Colorado CACJA emission reduction plan, which will satisfy regional haze requirements.  The Colorado legislature enacted a statute approving the SIP (the Colorado SIP), which was signed into law in 2011.  Subsequently, the Colorado Mining Association (CMA) challenged the Colorado SIP in a Colorado District Court.  In June 2012, the CMA’s appeal was dismissed.  The CMA appealed this decision, which is now pending in the Colorado Court of Appeals.

In September 2012, the EPA granted final approval of the Colorado SIP, including the CACJA emission reduction plan for PSCo, as satisfying BART requirements.  The emission controls are expected to be installed between 2014 and 2017.  Projected costs for emission controls at the Hayden and Pawnee plants are $343.0 million.  PSCo expects the cost of any required capital investment will be recoverable from customers.

In March 2013, WildEarth Guardians petitioned the U.S. Court of Appeals for the 10th Circuit to review the EPA’s decision approving the Colorado SIP.  WildEarth Guardians has stated that it will challenge the BART determination made for Comanche Units 1 and 2, which was a separate determination that was not part of the CACJA emission reduction plan.  In comments before the EPA, WildEarth Guardians urged that current emission limitations be made more stringent, or that Selective Catalytic Reduction (SCR) be added to the units.  PSCo has intervened in the case.

In 2010, two environmental groups petitioned the U.S. Department of the Interior (DOI) to certify that 12 coal-fired boilers and one coal-fired cement kiln in Colorado are contributing to visibility problems in Rocky Mountain National Park.  The following PSCo plants are named in the petition:  Cherokee, Hayden, Pawnee and Valmont.  The groups allege that the Colorado BART rule is inadequate to satisfy the Clean Air Act (CAA) mandate of ensuring reasonable further progress towards restoring natural visibility conditions in the park.  It is not known when the DOI will rule on the petition.

NSP-Minnesota
In 2009, the Minnesota Pollution Control Agency (MPCA) approved the SIP for Minnesota (the Minnesota SIP), and submitted it to the EPA for approval.  The MPCA selected the BART controls for Sherco Units 1 and 2 to improve visibility in the national parks.  The MPCA concluded SCRs should not be required because the minor visibility benefits derived from SCRs do not outweigh the substantial costs.  The MPCA’s source-specific BART controls for Sherco Units 1 and 2 consist of combustion controls for NOx and scrubber upgrades for SO2.  The combustion controls have been installed on Sherco Units 1 and 2.  The scrubber upgrades are underway and scheduled to be completed by January 2015.

The EPA’s preliminary review of the Minnesota SIP in 2011 indicated that SCR controls should be added to Sherco Units 1 and 2.  Subsequently, the EPA and MPCA both determined that CSAPR meets BART requirements for purposes of the Minnesota SIP.  In addition, the MPCA retained its source-specific BART determination for Sherco Units 1 and 2 from the 2009 Minnesota SIP. The EPA approved the Minnesota SIP for electric generating units (EGUs), and also approved the source-specific emission limits for Sherco Units 1 and 2 as strengthening the Minnesota SIP, but avoided characterizing them as BART limits.

In August 2012, the National Parks Conservation Association, Sierra Club, Voyageurs National Park Association, Friends of the Boundary Waters Wilderness, Minnesota Center for Environmental Advocacy and Fresh Energy appealed the EPA’s approval of the Minnesota SIP to the U.S. Court of Appeals for the Eighth Circuit.  The Court denied intervention in the case to NSP-Minnesota and other regulated parties who petitioned to intervene.  In June 2013, the Court ordered this case to be held in abeyance until the U.S. Supreme Court decides the CSAPR case.

NSP-Minnesota’s estimated cost for meeting the BART, regional haze and other CAA requirements is approximately $50 million, of which $37 million has already been spent on projects to reduce NOx emissions on Sherco Units 1 and 2.  Xcel Energy anticipates that all costs associated with BART compliance will be fully recoverable through regulatory recovery mechanisms.  If the above litigation results in further EPA proceedings concerning the Minnesota SIP, such proceedings may consider whether SCRs should be required for Sherco Units 1 and 2.


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In addition to the regional haze rules, there are other visibility rules related to a program called the Reasonably Attributable Visibility Impairment (RAVI) program.  In 2009, the DOI certified that a portion of the visibility impairment in Voyageurs and Isle Royale National Parks is reasonably attributable to emissions from NSP-Minnesota’s Sherco Units 1 and 2.  The EPA is required to make its own determination as to whether Sherco Units 1 and 2 cause or contribute to RAVI and, if so, whether the level of controls required by the MPCA is appropriate.  The EPA plans to issue a separate notice on the issue of BART for Sherco Units 1 and 2 under the RAVI program.  It is not yet known when the EPA will publish a proposal under RAVI or what that proposal will entail.  In December 2012, a lawsuit against the EPA was filed in the U.S. District Court for the District of Minnesota by the following organizations: National Parks Conservation Association, Minnesota Center for Environmental Advocacy, Friends of the Boundary Waters Wilderness, Voyageurs National Park Association, Fresh Energy and Sierra Club.  The lawsuit alleges that the EPA has failed to perform a nondiscretionary duty to determine BART for the Sherco Units 1 and 2 under the RAVI program.  The EPA filed an answer denying the allegations and asserting that it did not have a nondiscretionary duty under the RAVI program.  The Court denied NSP-Minnesota’s motion to intervene in July 2013. NSP-Minnesota appealed this decision to the U.S. Court of Appeals for the Eighth Circuit.

SPS
Harrington Units 1 and 2 are potentially subject to BART.  Texas has developed a SIP (the Texas SIP) that finds the CAIR equal to BART for EGUs.  As a result, no additional controls beyond CAIR compliance would be required.  In May 2012, the EPA deferred its review of the Texas SIP in its final rule allowing states to find that CSAPR compliance meets BART requirements for EGUs.  It is not yet known how the D.C. Circuit’s reversal of the CSAPR may impact the EPA’s approval of the Texas SIP.

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.

Environmental Litigation

Comer vs. Xcel Energy Inc. et al. — In May 2011, less than a year after their initial lawsuit was dismissed, plaintiffs in this purported class action lawsuit filed a second lawsuit against more than 85 utility, oil, chemical and coal companies in the U.S. District Court in Mississippi.  The complaint alleges defendants’ CO2 emissions intensified the strength of Hurricane Katrina and increased the damage plaintiffs purportedly sustained to their property.  Plaintiffs base their claims on public and private nuisance, trespass and negligence.  Among the defendants named in the complaint are Xcel Energy Inc., SPS, PSCo, NSP-Wisconsin and NSP-Minnesota.  The amount of damages claimed by plaintiffs is unknown.  The defendants believe this lawsuit is without merit and filed a motion to dismiss the lawsuit.  In March 2012, the U.S. District Court granted this motion for dismissal.  In April 2012, plaintiffs appealed this decision to the U.S. Court of Appeals for the Fifth Circuit.  In May 2013, the Fifth Circuit affirmed the district court’s dismissal of this lawsuit. Plaintiffs elected not to seek further review of this decision, which brings this litigation to a close.  No accrual was recorded for this matter.


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Employment, Tort and Commercial Litigation

Merricourt Wind Project Litigation — In April 2011, NSP-Minnesota terminated its agreements with enXco Development Corporation (enXco) for the development of a 150 MW wind project in southeastern North Dakota.  NSP-Minnesota’s decision to terminate the agreements was based in large part on the adverse impact this project could have on endangered or threatened species protected by federal law and the uncertainty in cost and timing in mitigating this impact.  NSP-Minnesota also terminated the agreements due to enXco’s nonperformance of certain other conditions, including failure to obtain a Certificate of Site Compatibility and the failure to close on the contracts by an agreed upon date of March 31, 2011.  NSP-Minnesota recorded a $101 million deposit in the first quarter of 2011, which was collected in April 2011.  In May 2011, NSP-Minnesota filed a declaratory judgment action in the U.S. District Court in Minnesota to obtain a determination that it acted properly in terminating the agreements.  enXco also filed a separate lawsuit in the same court seeking approximately $240 million for an alleged breach of contract.  NSP-Minnesota believes enXco’s lawsuit is without merit.  In October 2012, NSP-Minnesota filed a motion for summary judgment.  In April 2013, the U.S. District Court granted NSP-Minnesota’s motion and entered judgment in its favor.  In April 2013, enXco filed a notice of appeal to the Eighth Circuit.  It is uncertain when the Eighth Circuit will decide this appeal.  Although Xcel Energy believes the likelihood of loss is remote based on existing case law and the U.S. District Court’s April 2013 decision, it is not possible to estimate the amount or range of reasonably possible loss in the event of an adverse outcome of this matter.  No accrual has been recorded for this matter.

Exelon Wind (formerly John Deere Wind) Complaint  Several lawsuits in Texas state and federal courts and regulatory proceedings have arisen out of a dispute concerning SPS’ payments for energy and capacity produced from the Exelon Wind subsidiaries’ projects.  There are two main areas of dispute.  First, Exelon Wind claims that it established legally enforceable obligations (LEOs) for each of its 12 wind facilities in 2005 through 2008 that require SPS to buy power based on SPS’ forecasted avoided cost as determined in 2005 through 2008.  Although SPS has refused to accept Exelon Wind’s LEOs, SPS accepts that it must take energy from Exelon Wind under SPS’ PUCT-approved Qualifying Facilities (QF) Tariff.  Second, Exelon Wind has raised various challenges to SPS’ PUCT-approved QF Tariff, which became effective in August 2010. The state and federal lawsuits and regulatory proceedings are in various stages of litigation.  SPS believes the likelihood of loss in these lawsuits and proceedings is remote based primarily on existing case law and while it is not possible to estimate the amount or range of reasonably possible loss in the event of an adverse outcome, SPS believes such loss would not be material based upon its belief that it would be permitted to recover such costs, if needed, through its various fuel clause mechanisms.  No accrual has been recorded for this matter.

Pacific Northwest FERC Refund Proceeding — In July 2001, the FERC ordered a preliminary hearing to determine whether there were unjust and unreasonable charges for spot market bilateral sales in the Pacific Northwest for December 2000 through June 2001.  PSCo supplied energy to the Pacific Northwest markets during this period and has been a participant in the hearings.  In September 2001, the presiding ALJ concluded that prices in the Pacific Northwest during the referenced period were the result of a number of factors, including the shortage of supply, excess demand, drought and increased natural gas prices.  Under these circumstances, the ALJ concluded that the prices in the Pacific Northwest markets were not unreasonable or unjust and no refunds should be ordered.  Subsequent to the ruling, the FERC has allowed the parties to request additional evidence.  Parties have claimed that the total amount of transactions with PSCo subject to refund is $34 million.  In June 2003, the FERC issued an order terminating the proceeding without ordering further proceedings.  Certain purchasers filed appeals of the FERC’s orders in this proceeding with the Ninth Circuit.

In an order issued in August 2007, the Ninth Circuit remanded the proceeding back to the FERC and indicated that the FERC should consider other rulings addressing overcharges in the California organized markets.  The Ninth Circuit denied a petition for rehearing in April 2009, and the mandate was issued.

The FERC issued an order on remand establishing principles for the review proceeding in October 2011.  In September 2012, the City of Seattle filed its direct case against PSCo and other Pacific Northwest sellers claiming refunds for the period January 2000 through June 2001.  The City of Seattle indicated that for the period June 2000 through June 2001 PSCo had sales to the City of Seattle of approximately $50 million.  The City of Seattle did not identify specific instances of unlawful market activity by PSCo, but rather based its claim for refunds on market dysfunction in the Western markets.  PSCo submitted its answering case in December 2012.


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In April 2013, the FERC issued an order on rehearing.  The FERC confirmed that the City of Seattle would be able to attempt to obtain refunds back from January 2000, but reaffirmed the transaction-specific standard that the City of Seattle and other complainants would have to comply with to obtain refunds.  In addition, the FERC rejected the imposition of any market-wide remedies.  Although the FERC order on rehearing established the period for which the City of Seattle could seek refunds as January 2000 through June 2001, it is unclear what claim the City of Seattle has against PSCo prior to June 2000. In the proceeding, The City of Seattle does not allege specific misconduct or tariff violations by PSCo but instead asserts generally that the rates charged by PSCo and other sellers were excessive. A FERC hearing on the issue is presently in progress. An ALJ initial decision is expected in December 2013.

Preliminary calculations of the City of Seattle’s claim for refunds from PSCo are approximately $28 million excluding interest.  PSCo has concluded that a loss is reasonably possible with respect to this matter; however, given the surrounding uncertainties, PSCo is currently unable to estimate the amount or range of reasonably possible loss in the event of an adverse outcome of this matter.  In making this assessment, PSCo considered two factors.  First, not withstanding PSCo’s view that the City of Seattle has failed to apply the standard that the FERC has established in this proceeding, and the recognition that this case raises a novel issue and the FERC’s standard has been challenged on appeal to the Ninth Circuit, the outcome of such an appeal cannot be predicted with any certainty.  Second, PSCo would expect to make equitable arguments against refunds even if the City of Seattle were to establish that it was overcharged for transactions.  If a loss were sustained, PSCo would attempt to recover those losses from other PRPs.  No accrual has been recorded for this matter.

Nuclear Power Operations and Waste Disposal

Nuclear Waste Disposal Litigation — In 1998, NSP-Minnesota filed a complaint in the U.S. Court of Federal Claims against the United States requesting breach of contract damages for the U.S. Department of Energy’s (DOE) failure to begin accepting spent nuclear fuel by Jan. 31, 1998, as required by the contract between the United States and NSP-Minnesota.  NSP-Minnesota sought contract damages in this lawsuit through Dec. 31, 2004.  In September 2007, the court awarded NSP-Minnesota $116.5 million in damages.  In August 2007, NSP-Minnesota filed a second complaint; this lawsuit claimed damages for the period Jan. 1, 2005 through Dec. 31, 2008.

In July 2011, the United States and NSP-Minnesota executed a settlement agreement resolving both lawsuits, providing an initial $100 million payment from the United States to NSP-Minnesota, and providing a method by which NSP-Minnesota can recover its spent fuel storage costs through 2013, estimated to be an additional $100 million.  The settlement does not address costs for used fuel storage after 2013; such costs could be the subject of future litigation.  NSP-Minnesota received the initial $100 million payment in August 2011, the second installment of $18.6 million in March 2012, and the third installment of $20.7 million in October 2012. NSP-Minnesota’s claim submission for the fourth installment, in the amount of $42.8 million, was filed May 15, 2013 for costs incurred in 2012. The DOE recommended payment of $42.6 million for this claim in August 2013. Amounts received from the installments were subsequently credited to customers, except for approved reductions such as legal costs and amounts set aside to be credited through another regulatory mechanism.

In NSP-Wisconsin’s 2012 Electric and Gas Rate Case, the PSCW authorized NSP-Wisconsin to utilize the proceeds from the second and third installments to be included as a reduction of the 2013 electric rate increase.  In December 2012, the MPUC approved NSP-Minnesota’s triennial nuclear decommissioning filing which required NSP-Minnesota to place the Minnesota retail portion of the DOE settlement payments for the third installment of $15.3 million and the anticipated fourth installment in 2013 into the nuclear decommissioning fund when received.  NSP-Minnesota proposed to contribute the North Dakota retail portion of the second, third and fourth installments to the nuclear decommissioning fund to offset the increase in the decommissioning accrual that was included in the 2012 North Dakota electric rate case.  That filing is pending NDPSC action.

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.


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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, 2013
 
Twelve Months Ended
Dec. 31, 2012
Borrowing limit
 
$
2,450

 
$
2,450

Amount outstanding at period end
 
302

 
602

Average amount outstanding
 
347

 
403

Maximum amount outstanding
 
491

 
634

Weighted average interest rate, computed on a daily basis
 
0.27
%
 
0.35
%
Weighted average interest rate at period end
 
0.25

 
0.36


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, 2013 and Dec. 31, 2012, there were $18.8 million and $14.2 million of letters of credit outstanding, respectively, under the credit facilities.  The contract amounts of these letters of credit approximate their fair value and are subject to fees determined in the marketplace.

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.

At Sept. 30, 2013, 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.
 
$
800.0

 
$
258.0

 
$
542.0

PSCo
 
700.0

 
6.9

 
693.1

NSP-Minnesota
 
500.0

 
44.9

 
455.1

SPS
 
300.0

 

 
300.0

NSP-Wisconsin
 
150.0

 
11.0

 
139.0

Total
 
$
2,450.0

 
$
320.8

 
$
2,129.2


(a) 
These credit facilities expire in July 2017.
(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, 2013 and Dec. 31, 2012.

Long-Term Borrowings and Other Financing Instruments

PSCo In March 2013, PSCo issued $250 million of 2.50 percent first mortgage bonds due March 15, 2023 and $250 million of 3.95 percent first mortgage bonds due March 15, 2043.

Xcel Energy Inc. In May 2013, Xcel Energy Inc. issued $450 million of 0.75 percent senior unsecured notes due May 9, 2016.

NSP-Minnesota In May 2013, NSP-Minnesota issued $400 million of 2.60 percent first mortgage bonds due May 15, 2023.

SPS — In August 2013, SPS issued $100 million of 4.50 percent first mortgage bonds due Aug. 15, 2041. Including the $300 million of this series previously issued, total principal outstanding for this series is $400 million.


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Issuances of Common Stock — In March 2013, Xcel Energy Inc. filed a prospectus supplement under which it may sell up to $400 million of its common stock through an at-the-market offering program. No shares of common stock were issued through this program during the third quarter of 2013.  As of Sept. 30, 2013, Xcel Energy Inc. had issued 7.7 million shares of common stock through this program and received cash proceeds of $223.1 million, net of $2.3 million in fees and commissions. The proceeds from the issuances of common stock were used to repay short-term debt, infuse equity into the utility subsidiaries and for other general corporate purposes.

Debt Redemption — On May 31, 2013, Xcel Energy Inc. redeemed the entire $400 million principal amount of its 7.60 percent junior subordinated notes. Upon redemption, Xcel Energy Inc. recognized $6.3 million of related unamortized debt issuance costs as interest charges.

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 discounted cash flow or option pricing 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 values.

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 net asset values, 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 and international equity funds may be redeemed for net asset value 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.  Based on Xcel Energy’s evaluation of its ability to redeem private equity and real estate investments, fair value measurements for private equity and real estate investments have been assigned a Level 3.

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.


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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 include financial transmission rights (FTRs) purchased from Midcontinent Independent Transmission System Operator, Inc. (MISO).  FTRs purchased from MISO 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 overall transmission load and other transmission constraints.  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.  NSP-Minnesota’s 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 – including expected plant operating schedules and retail and wholesale demand, fair value measurements for FTRs have been assigned a Level 3.  Non-trading monthly FTR settlements are included in the fuel clause adjustment, and therefore changes in the fair value of the yet to be settled portions of FTRs are deferred as a regulatory asset or liability.  Given this regulatory treatment and the limited magnitude of NSP-Minnesota’s FTRs relative to its electric utility operations, 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

The 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 Prairie Island 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.  The MPUC approved NSP-Minnesota’s proposed change in escrow fund investment strategy in September 2012.  The MPUC approved an 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 $202.4 million and $135.8 million at Sept. 30, 2013 and Dec. 31, 2012, respectively, and unrealized losses and amounts recorded as other-than-temporary impairments were $65.3 million and $46.4 million at Sept. 30, 2013 and Dec. 31, 2012, 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, 2013 and Dec. 31, 2012:
 
 
Sept. 30, 2013
 
 
 
 
Fair Value
 
 
(Thousands of Dollars)
 
Cost
 
Level 1
 
Level 2
 
Level 3
 
Total
Nuclear decommissioning fund (a)
 
 

 
 

 
 

 
 

 
 

Cash equivalents
 
$
74,103

 
$
74,103

 
$

 
$

 
$
74,103

Commingled funds
 
436,533

 

 
438,906

 

 
438,906

International equity funds
 
65,529

 

 
68,164

 

 
68,164

Private equity investments
 
43,286

 

 

 
52,474

 
52,474

Real estate
 
41,645

 

 

 
51,356

 
51,356

Debt securities:
 
 

 
 

 
 

 
 

 
 

Government securities
 
34,475

 

 
28,946

 

 
28,946

U.S. corporate bonds
 
86,719

 

 
88,561

 

 
88,561

International corporate bonds
 
15,999

 

 
15,976

 

 
15,976

Municipal bonds
 
207,417

 

 
197,917

 

 
197,917

Equity securities:
 
 

 
 

 
 

 
 

 
 

Common stock
 
410,820

 
537,189

 

 

 
537,189

Total
 
$
1,416,526

 
$
611,292

 
$
838,470

 
$
103,830

 
$
1,553,592


(a) 
Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $87.8 million of equity investments in unconsolidated subsidiaries and $38.6 million of miscellaneous investments.
 
 
Dec. 31, 2012
 
 
 
 
Fair Value
 
 
(Thousands of Dollars)
 
Cost
 
Level 1
 
Level 2
 
Level 3
 
Total
Nuclear decommissioning fund (a)
 
 

 
 

 
 

 
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