XCEL 6.30.13 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 June 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 July 26, 2013
Common Stock, $2.50 par value
 
497,570,936 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 June 30
 
Six Months Ended June 30
 
2013
 
2012
 
2013
 
2012
Operating revenues
 
 
 
 
 
 
 
Electric
$
2,219,877

 
$
2,036,829

 
$
4,312,073

 
$
3,973,611

Natural gas
341,321

 
221,313

 
1,010,917

 
842,348

Other
17,715

 
16,526

 
38,772

 
36,788

Total operating revenues
2,578,913

 
2,274,668

 
5,361,762

 
4,852,747

 
 
 
 
 
 
 
 
Operating expenses
 

 
 

 
 
 
 
Electric fuel and purchased power
1,011,044

 
854,373

 
1,936,087

 
1,718,353

Cost of natural gas sold and transported
188,765

 
89,759

 
628,140

 
507,705

Cost of sales — other
7,881

 
5,944

 
16,292

 
13,248

Operating and maintenance expenses
562,557

 
534,014

 
1,091,788

 
1,044,698

Conservation and demand side management program expenses
60,445

 
58,615

 
124,477

 
122,322

Depreciation and amortization
243,934

 
226,641

 
492,640

 
455,313

Taxes (other than income taxes)
102,051

 
99,632

 
215,478

 
205,256

Total operating expenses
2,176,677

 
1,868,978

 
4,504,902

 
4,066,895

 
 
 
 
 
 
 
 
Operating income
402,236

 
405,690

 
856,860

 
785,852

 
 
 
 
 
 
 
 
Other income, net
413

 
728

 
4,335

 
4,465

Equity earnings of unconsolidated subsidiaries
7,529

 
7,502

 
15,106

 
14,660

Allowance for funds used during construction — equity
22,109

 
15,194

 
41,863

 
28,644

 
 
 
 
 
 
 
 
Interest charges and financing costs
 

 
 

 
 
 
 
Interest charges — includes other financing costs of
$12,229, $6,036, $18,038 and $12,116, respectively
146,828

 
151,921

 
286,441

 
303,751

Allowance for funds used during construction — debt
(10,316
)
 
(7,683
)
 
(19,074
)
 
(14,290
)
Total interest charges and financing costs
136,512

 
144,238

 
267,367

 
289,461

 
 
 
 
 
 
 
 
Income from continuing operations before income taxes
295,775

 
284,876

 
650,797

 
544,160

Income taxes
98,893

 
101,801

 
217,327

 
177,316

Income from continuing operations
196,882

 
183,075

 
433,470

 
366,844

(Loss) income from discontinued operations, net of tax
(25
)
 
(15
)
 
(43
)
 
109

Net income
$
196,857

 
$
183,060

 
$
433,427

 
$
366,953

 
 
 
 
 
 
 
 
Weighted average common shares outstanding:
 

 
 

 
 
 
 
Basic
497,747

 
487,717

 
493,786

 
487,538

Diluted
498,036

 
488,017

 
494,303

 
488,006

 
 
 
 
 
 
 
 
Earnings per average common share:
 

 
 

 
 
 
 
Basic
$
0.40

 
$
0.38

 
$
0.88

 
$
0.75

Diluted
0.40

 
0.38

 
0.88

 
0.75

 
 
 
 
 
 
 
 
Cash dividends declared per common share
$
0.28

 
$
0.27

 
$
0.55

 
$
0.53


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 June 30
 
Six Months Ended June 30
 
2013
 
2012
 
2013
 
2012
Net income
$
196,857

 
$
183,060

 
$
433,427

 
$
366,953

 
 
 
 
 
 
 
 
Other comprehensive income (loss)
 

 
 

 
 
 
 
 
 
 
 
 
 
 
 
Pension and retiree medical benefits:
 

 
 

 
 
 
 
Amortization of losses included in net periodic benefit cost,
net of tax of $729, $647, $3,232 and $1,269, respectively
1,135

 
932

 
496

 
1,827

 
 
 
 
 
 
 
 
Derivative instruments:
 

 
 

 
 
 
 
Net fair value decrease, net of tax of $(29), $(23,164),
$(17) and $(6,673), respectively
(44
)
 
(35,727
)
 
(31
)
 
(10,335
)
Reclassification of losses to net income, net of tax of
$451, $158, $1,881 and $314, respectively
694

 
182

 
389

 
363

 
650

 
(35,545
)
 
358

 
(9,972
)
Marketable securities:
 

 
 

 
 
 
 
Net fair value increase (decrease), net of tax of
$0, $83, $(18) and $119, respectively
—

 
122

 
(36
)
 
174

 
 
 
 
 
 
 
 
Other comprehensive income (loss)
1,785

 
(34,491
)
 
818

 
(7,971
)
Comprehensive income
$
198,642

 
$
148,569

 
$
434,245

 
$
358,982


See Notes to Consolidated Financial Statements


4
Table of Contents




XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
(amounts in thousands)
 
Six Months Ended June 30
 
2013
 
2012
Operating activities
 
 
 

Net income
$
433,427

 
$
366,953

Remove loss (income) from discontinued operations
43

 
(109
)
Adjustments to reconcile net income to cash provided by operating activities:
 

 
 

Depreciation and amortization
507,658

 
464,117

Conservation and demand side management program amortization
3,425

 
3,765

Nuclear fuel amortization
49,485

 
49,765

Deferred income taxes
235,684

 
278,358

Amortization of investment tax credits
(3,314
)
 
(3,104
)
Allowance for equity funds used during construction
(41,863
)
 
(28,644
)
Equity earnings of unconsolidated subsidiaries
(15,106
)
 
(14,660
)
Dividends from unconsolidated subsidiaries
18,683

 
8,028

Share-based compensation expense
18,747

 
17,249

Net realized and unrealized hedging and derivative transactions
(2,754
)
 
7,325

Changes in operating assets and liabilities:
 

 
 

Accounts receivable
(78,940
)
 
(928
)
Accrued unbilled revenues
37,069

 
139,012

Inventories
40,684

 
145,095

Other current assets
29,700

 
(61,291
)
Accounts payable
1,625

 
(177,076
)
Net regulatory assets and liabilities
76,693

 
12,912

Other current liabilities
(83,336
)
 
(117,653
)
Pension and other employee benefit obligations
(170,162
)
 
(168,898
)
Change in other noncurrent assets
16,940

 
(40,893
)
Change in other noncurrent liabilities
(163
)
 
(14,027
)
Net cash provided by operating activities
1,074,225

 
865,296

 
 
 
 
Investing activities
 

 
 

Utility capital/construction expenditures
(1,596,778
)
 
(1,103,562
)
Proceeds from insurance recoveries
50,000

 
24,000

Allowance for equity funds used during construction
41,863

 
28,644

Purchases of investments in external decommissioning fund
(890,700
)
 
(371,361
)
Proceeds from the sale of investments in external decommissioning fund
887,500

 
371,361

Investment in WYCO Development LLC
(2,166
)
 
(379
)
Change in restricted cash
—

 
94,959

Other, net
(1,696
)
 
(24
)
Net cash used in investing activities
(1,511,977
)
 
(956,362
)
 
 
 
 
Financing activities
 
 
 
(Repayments of) proceeds from short-term borrowings, net
(248,000
)
 
262,000

Proceeds from issuance of long-term debt
1,337,045

 
111,015

Repayments of long-term debt, including reacquisition premiums
(651,516
)
 
(2,455
)
Proceeds from issuance of common stock
227,113

 
3,698

Repurchase of common stock
—

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

 
(23,307
)
Dividends paid
(250,392
)
 
(238,510
)
Net cash provided by financing activities
414,250

 
93,912

 
 
 
 
Net change in cash and cash equivalents
(23,502
)
 
2,846

Cash and cash equivalents at beginning of period
82,323

 
60,684

Cash and cash equivalents at end of period
$
58,821

 
$
63,530

 
 
 
 
Supplemental disclosure of cash flow information:
 

 
 

Cash paid for interest (net of amounts capitalized)
$
(258,124
)
 
$
(281,266
)
Cash received (paid) for income taxes, net
13,681

 
(5,875
)
Supplemental disclosure of non-cash investing and financing transactions:
 

 
 

Property, plant and equipment additions in accounts payable
$
302,434

 
$
274,350

Issuance of common stock for reinvested dividends and 401(k) plans
37,504

 
35,543


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)
 
June 30, 2013
 
Dec. 31, 2012
Assets
 
 
 
Current assets
 
 
 
Cash and cash equivalents
$
58,821

 
$
82,323

Accounts receivable, net
719,069

 
718,046

Accrued unbilled revenues
626,294

 
663,363

Inventories
494,890

 
535,574

Regulatory assets
396,308

 
352,977

Derivative instruments
100,215

 
69,013

Deferred income taxes
158,350

 
32,528

Prepayments and other
264,253

 
171,315

Total current assets
2,818,200

 
2,625,139

 
 
 
 
Property, plant and equipment, net
24,813,411

 
23,809,348

 
 
 
 
Other assets
 

 
 

Nuclear decommissioning fund and other investments
1,622,978

 
1,617,865

Regulatory assets
2,727,210

 
2,762,029

Derivative instruments
100,313

 
126,297

Other
184,150

 
200,008

Total other assets
4,634,651

 
4,706,199

Total assets
$
32,266,262

 
$
31,140,686

 
 
 
 
Liabilities and Equity
 

 
 

Current liabilities
 

 
 

Current portion of long-term debt
$
282,042

 
$
258,155

Short-term debt
354,000

 
602,000

Accounts payable
998,607

 
959,093

Regulatory liabilities
205,112

 
168,858

Taxes accrued
242,339

 
334,441

Accrued interest
156,751

 
162,494

Dividends payable
139,240

 
131,748

Derivative instruments
29,897

 
32,482

Other
288,822

 
287,802

Total current liabilities
2,696,810

 
2,937,073

 
 
 
 
Deferred credits and other liabilities
 

 
 

Deferred income taxes
4,820,650

 
4,434,909

Deferred investment tax credits
80,587

 
82,761

Regulatory liabilities
1,070,059

 
1,059,939

Asset retirement obligations
1,762,959

 
1,719,796

Derivative instruments
222,575

 
242,866

Customer advances
261,684

 
252,888

Pension and employee benefit obligations
988,773

 
1,163,265

Other
245,443

 
229,207

Total deferred credits and other liabilities
9,452,730

 
9,185,631

 
 
 
 
Commitments and contingencies


 


Capitalization
 

 
 

Long-term debt
10,816,477

 
10,143,905

Common stock — 1,000,000,000 shares authorized of $2.50 par value; 497,295,719 and
487,959,516 shares outstanding at June 30, 2013 and Dec. 31, 2012, respectively
1,243,239

 
1,219,899

Additional paid in capital
5,595,906

 
5,353,015

Retained earnings
2,572,935

 
2,413,816

Accumulated other comprehensive loss
(111,835
)
 
(112,653
)
Total common stockholders’ equity
9,300,245

 
8,874,077

Total liabilities and equity
$
32,266,262

 
$
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 June 30, 2013 and 2012
 

 
 
 
 
 
 
 
 
 
 
Balance at March 31, 2012
486,936

 
$
1,217,339

 
$
5,298,572

 
$
2,089,275

 
$
(67,515
)
 
$
8,537,671

Net income


 


 


 
183,060

 


 
183,060

Other comprehensive loss


 


 


 


 
(34,491
)
 
(34,491
)
Dividends declared:
 

 
 

 
 

 
 

 
 

 
 

Common stock


 


 


 
(131,696
)
 


 
(131,696
)
Issuances of common stock
350

 
875

 
8,482

 


 


 
9,357

Share-based compensation


 


 
9,604

 


 


 
9,604

Balance at June 30, 2012
487,286

 
$
1,218,214

 
$
5,316,658

 
$
2,140,639

 
$
(102,006
)
 
$
8,573,505

 
 
 
 
 
 
 
 
 
 
 
 
Balance at March 31, 2013
494,755

 
$
1,236,888

 
$
5,515,513

 
$
2,516,332

 
$
(113,620
)
 
$
9,155,113

Net income


 


 


 
196,857

 


 
196,857

Other comprehensive income


 


 


 


 
1,785

 
1,785

Dividends declared:
 

 
 

 
 

 
 

 
 

 
 

Common stock


 


 


 
(140,254
)
 


 
(140,254
)
Issuances of common stock
2,541

 
6,351

 
67,940

 


 


 
74,291

Share-based compensation


 


 
12,453

 


 


 
12,453

Balance at June 30, 2013
497,296

 
$
1,243,239

 
$
5,595,906

 
$
2,572,935

 
$
(111,835
)
 
$
9,300,245


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
Six Months Ended June 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
 

 
 

 
 

 
366,953

 
 

 
366,953

Other comprehensive loss
 

 
 

 
 

 
 

 
(7,971
)
 
(7,971
)
Dividends declared:
 

 
 

 
 

 
 

 
 

 
 

Common stock
 

 
 

 
 

 
(258,870
)
 
 

 
(258,870
)
Issuances of common stock
1,492

 
3,730

 
10,770

 
 

 
 

 
14,500

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
 

 
 

 
18,531

 
 

 
 

 
18,531

Balance at June 30, 2012
487,286

 
$
1,218,214

 
$
5,316,658

 
$
2,140,639

 
$
(102,006
)
 
$
8,573,505

 
 
 
 
 
 
 
 
 
 
 
 
Balance at Dec. 31, 2012
487,960

 
$
1,219,899

 
$
5,353,015

 
$
2,413,816

 
$
(112,653
)
 
$
8,874,077

Net income


 


 


 
433,427

 


 
433,427

Other comprehensive income


 


 


 


 
818

 
818

Dividends declared:
 

 
 

 
 

 
 

 
 

 
 

Common stock


 


 


 
(274,308
)
 


 
(274,308
)
Issuances of common stock
9,336

 
23,340

 
219,785

 


 


 
243,125

Share-based compensation


 


 
23,106

 


 


 
23,106

Balance at June 30, 2013
497,296

 
$
1,243,239

 
$
5,595,906

 
$
2,572,935

 
$
(111,835
)
 
$
9,300,245


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 June 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 six months ended June 30, 2013 and 2012; and its cash flows for the six months ended June 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 June 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.

3.
Selected Balance Sheet Data

(Thousands of Dollars)
 
June 30, 2013
 
Dec. 31, 2012
Accounts receivable, net
 
 
 
 
Accounts receivable
 
$
766,848

 
$
769,440

Less allowance for bad debts
 
(47,779
)
 
(51,394
)
 
 
$
719,069

 
$
718,046


9
Table of Contents

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

 
 
Materials and supplies
 
$
222,628

 
$
213,739

Fuel
 
186,009

 
189,425

Natural gas
 
86,253

 
132,410

 
 
$
494,890

 
$
535,574

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

 
 
Electric plant
 
$
29,017,319

 
$
28,285,031

Natural gas plant
 
3,903,127

 
3,836,335

Common and other property
 
1,475,534

 
1,480,558

Plant to be retired (a)
 
115,466

 
152,730

Construction work in progress
 
2,298,899

 
1,757,189

Total property, plant and equipment
 
36,810,345

 
35,511,843

Less accumulated depreciation
 
(12,344,995
)
 
(12,048,697
)
Nuclear fuel
 
2,142,145

 
2,090,801

Less accumulated amortization
 
(1,794,084
)
 
(1,744,599
)
 
 
$
24,813,411

 
$
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 June 30, 2013, the IRS had not proposed any material adjustments to tax years 2010 and 2011.

State Audits — Xcel Energy files consolidated state tax returns based on income in its major operating jurisdictions of Colorado, Minnesota, Texas, and Wisconsin, and various other state income-based tax returns.  As of June 30, 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
 
2008
Wisconsin
 
2008

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 June 30, 2013, no material adjustments had been proposed for either of these audits.  There are currently no other state income tax audits in progress.


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Table of Contents

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)
 
June 30, 2013
 
Dec. 31, 2012
Unrecognized tax benefit — Permanent tax positions
 
$
7.6

 
$
4.7

Unrecognized tax benefit — Temporary tax positions
 
31.7

 
29.8

Total unrecognized tax benefit
 
$
39.3

 
$
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)
 
June 30, 2013
 
Dec. 31, 2012
NOL and tax credit carryforwards
 
$
(38.1
)
 
$
(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 June 30, 2013 and Dec. 31, 2012 were not material.  No amounts were accrued for penalties related to unrecognized tax benefits as of June 30, 2013 or Dec. 31, 2012.

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 Report on Form 10-Q for the quarter period ended March 31, 2013, appropriately represent, in all material respects, the current status of other rate matters, and are incorporated herein by reference.

NSP-Minnesota

Pending Regulatory Proceedings — Minnesota Public Utilities Commission (MPUC)

Base Rate

NSP-Minnesota – Minnesota 2012 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 is based on a 2013 forecast test year, 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.

In March 2013, NSP-Minnesota filed rebuttal testimony and revised the requested annual revenue increase to approximately $219.7 million, or 8.23 percent, based on an ROE of 10.6 percent, a rate base of approximately $6.3 billion and an equity ratio of 52.56 percent.  The updated request reflects alternate proposals in several key areas including:

•
Deferral of depreciation expenses and property taxes related to Sherco Unit 3 for 2012 and 2013 and removal of avoided 2013 operating and maintenance (O&M) expense due to the extended outage at Sherco Unit 3.
•
Removal of Monticello 2013 license costs from plant in service and deferral of 2013 depreciation expense for the primary Monticello life cycle management (LCM) / extended power uprate (EPU) project until after an MPUC order finding the costs prudent.
•
Removal of Prairie Island EPU project costs, reflecting the MPUC decision to cancel the project in December 2012.

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•
Adjustments to compensation and benefits recovery including Annual Incentive Plan (AIP) to reflect prior MPUC decisions establishing a limitation at 15 percent of base pay using a four-year average AIP target, pension expense and active healthcare costs.
•
Adjustment of pension recoveries to reflect amortized recovery of 2008 market losses.
•
Recovery of coal pile and ash pond remediation costs at the Black Dog plant through a 15 year amortization.
•
Updated forecast for property taxes.
•
Updated forecast with 6 months of actual sales, customer and weather data through December 2012, and updated economic assumptions based on a December 2012 economic forecast, proposing a refund if sales are higher than forecast on a weather-normalized basis.
•
Correction to the original filing and other adjustments.

In April 2013, intervenors filed surrebuttal testimony, including the Minnesota Department of Commerce (DOC), Office of Attorney General (OAG), Minnesota Chamber (MCC), Xcel Large Industrials (XLI), Commercial Group, Industrial, Commercial and Institutional Customers, and Energy Cents Coalition.  The DOC recommended a revenue increase of $89.6 million, based on a 9.83 percent ROE, an average electric rate base of approximately $6.1 billion and an equity ratio of 52.56 percent.  Subsequently, the DOC’s recommendation was revised to approximately $98.6 million, largely to reflect updated information.

In its surrebuttal testimony, the OAG recommended no recovery for the Prairie Island EPU project, stating it should have been written off in 2012 when cancellation of the project was approved by the MPUC.  The DOC is also not supportive of recovery of the Prairie Island EPU cancelled EPU costs.  The OAG suggests pension recovery in rates exceeds benefit payout because of changes made to benefit plans and recommends correction for an alleged over-collection of funds to pay for future benefits which may never be paid out.  The OAG supports the DOC in adjustments to recovery of annual incentive compensation and does not find NSP-Minnesota’s Sherco Unit 3 proposal warranted.  XLI and MCC also opposed recovery of Sherco Unit 3 costs and Monticello EPU costs.

Through the hearing and briefing process, NSP-Minnesota revised its rate request to approximately $209 million to reflect updated property tax information, resolution of concerns regarding Wisconsin wholesale customers and other adjustments. The $209 million revenue requirement reflects a requested deficiency of $259 million combined with $50 million of rate mitigation through deferral mechanisms.

ALJ Recommendation

On July 3, 2013, the Minnesota Administrative Law Judge (ALJ) issued her report and recommended a rate increase of approximately $127 million, based on a ROE of 9.83 percent, an equity ratio of 52.56 percent and an electric rate base of $6.233 billion. In addition, the ALJ recommendation included approximately $51 million in deferrals of which NSP-Minnesota estimates $34 million will affect net income. The deferrals are related to Sherco Unit 3 and pension.

The ALJ indicated that Sherco Unit 3 should be considered “used and useful” for rate making purposes, but that a portion of the Monticello LCM/EPU would not be considered “used and useful” until NSP-Minnesota obtains the uprate license from the Nuclear Regulatory Commission (NRC). The ALJ also found that the prudency of the cost increases for the Monticello LCM/EPU project and cost recovery for the cancelled Prairie Island EPU project should be determined in the next Minnesota rate case. In addition, the ALJ recommended accepting NSP-Minnesota’s position on the inclusion of the pension market loss and incentive compensation and the DOC’s position on the sales forecast.


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The table below reconciles the final position of NSP-Minnesota, the DOC and the ALJ.
(Millions of Dollars)
 
NSP-Minnesota Request
 
DOC Recommendation
 
ALJ Recommendation
NSP-Minnesota original request
 
$
285

 
$
285

 
$
285

ROE
 
—

 
(43
)
 
(43
)
Sherco Unit 3
 
(35
)
 
(40
)
 
(38
)
Reduced recovery for the nuclear plants
 
(11
)
 
(9
)
 
(14
)
Incentive compensation
 
(3
)
 
(20
)
 
(4
)
Sales forecast
 
(1
)
 
(26
)
 
(26
)
Pension
 
(10
)
 
(25
)
 
(13
)
Employee benefits
 
(4
)
 
(6
)
 
(6
)
Black Dog remediation
 
(5
)
 
(5
)
 
(5
)
NSP-Wisconsin wholesale allocation
 
(7
)
 
(7
)
 
(7
)
Other, net
 
—

 
(5
)
 
(2
)
    Recommended rate increase
 
209

 
99

 
127

Preliminary estimated impact of cost deferrals
 
50

 
5

 
34

    Estimated impact on 2013 pre-tax income
 
$
259

 
$
104

 
$
161


The MPUC has scheduled deliberations for Aug. 6 and 8, 2013. The MPUC is expected to reach a decision on the issues at the deliberations and issue an order in September 2013.

NSP-Minnesota recorded a current regulatory liability representing the current best estimate of a refund obligation associated with the interim rates of approximately $16 million and $47 million, as of March 31 and June 30, 2013, respectively.

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

Base Rate

NSP-Minnesota – North Dakota 2012 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 forecast test year, 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. There were no intervenors in this proceeding.


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Table of Contents

On July 17, 2013, NDPSC Advocacy Staff filed direct testimony prepared by their rate case consultants. Staff’s testimony recommended a 9.0 percent ROE and other revenue requirement adjustments, which resulted in an overall rate reduction of approximately $2.1 million. Primary revenue requirement adjustments include:
(Millions of Dollars)
 
Revenue requirement adjustments as filed by the Staff
NSP-Minnesota revised request
 
$
16.0

Use of a one month coincident peak demand allocator for certain
rate base and operation expenses
 
(20.0
)
ROE
 
(5.2
)
Incentive compensation
 
(0.8
)
Adjustment for various O&M expenses
 
(0.7
)
Calculation of federal income taxes
 
6.3

Modified cost of capital and increased capital structure
to 53.42 percent
 
1.4

Other, net
 
0.9

Recommended rate decrease
 
$
(2.1
)

Additionally, NDPSC Staff recommends customers in NSP-Minnesota’s North Dakota jurisdiction be excluded from paying for costs of certain purchased power agreements.

Next steps in the procedural schedule are expected to be as follows:

•
Rebuttal Testimony – Aug. 12, 2013
•
Technical Hearings – Aug. 27-28, 2013
•
Initial Briefs – Sept. 20, 2013
•
Reply Briefs/Proposed Findings – October 2013

A final NDPSC decision on the case is expected in the fourth quarter of 2013.

NSP-Wisconsin

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

Base Rate

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 forecast test year, a 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.

Next steps in the procedural schedule are expected to be as follows:

•
Staff and Intervenor Direct Testimony – Oct. 4, 2013
•
Rebuttal Testimony – Oct. 18, 2013
•
Surrebuttal testimony – Oct. 28, 2013
•
Hearing – Oct. 30, 2013
•
Initial Brief – Nov. 13, 2013
•
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

Base Rate

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 forecast test year, 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.

In order to accommodate the procedural schedule, rates will go into effect as filed on Aug. 10, 2013, subject to refund.

On April 3, 2013, four parties filed answer testimony in the natural gas case.  The CPUC Staff and Office of Consumer Counsel (OCC) recommended changes to the level of integrity management costs moved from the PSIA rider to base rates.  PSCo’s 2013 deficiency based on a Forecasted Test Year (FTY) net of PSIA changes was $45 million for 2013 and the revenue deficiency was $28.3 million based on a Historic Test Year (HTY).

The CPUC Staff recommended a rate reduction of $14.4 million, based on a HTY, an ROE of 9 percent and an equity ratio of 52 percent and other adjustments.  The OCC recommended a rate increase of $0.5 million based on a HTY, an ROE of 9 percent and equity ratio of 51.03 percent and other adjustments.  While the OCC did not recommend that the CPUC set rates using a FTY, they did calculate a revenue deficiency of $12.4 million for 2013.  No other intervenor made ROE recommendations or specific recommendations regarding the revenue deficiency.  The major adjustments to the test year proposed by the CPUC Staff and OCC are presented below.

(Millions of Dollars)
 
CPUC Staff
 
OCC
PSCo deficiency based on a HTY
 
$
28.3

 
$
28.3

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

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

 
(9.0
)
Eliminate depreciation annualization
 
—

 
(1.8
)
Revenue adjustments
 
(4.1
)
 
(1.4
)
Resulting tax impacts
 
1.5

 
4.7

Other adjustments
 
(4.2
)
 
3.1

Recommendation
 
$
(14.4
)
 
$
0.5


On April 26, 2013, the CPUC Staff filed supplemental testimony recommending an additional net disallowance of $1.6 million for adjustments and corrections.

On April 29, 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.  PSCo agreed to recover approximately $3.5 million of revenue requirement in the PSIA, rather than through base rates and accepted the CPUC Staff’s recommendation to use deferred accounting to accommodate property tax increases.

Hearings were held in May 2013. An ALJ recommendation is anticipated in August 2013 and a decision is expected in the third quarter of 2013.


15
Table of Contents

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 forecast test year, a 10.5 percent ROE, a rate base of $21 million for steam and an equity ratio of 56 percent.  Final rates are expected to be effective in the fourth quarter of 2013.

On July 23, 2013, PSCo, CPUC Staff, the OCC and Colorado Energy Consumers representing the Building Owners Management Association filed an unopposed joint motion for the CPUC to vacate the current procedural schedule and to set a date of Aug. 12, 2013, by which the parties shall file either: (i) a comprehensive settlement agreement resolving all issues presented in this matter; or (ii) a consensus revised procedural schedule.

PSCo – 2011 Electric Rate Case Earnings Test — On April 1, 2013, PSCo filed a tariff implementing the earnings sharing mechanism consistent with the settlement and CPUC decision for PSCo’s 2011 electric rate case.  The 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 the April 2013 filing for 2012, PSCo indicated that its earnings did not exceed the established threshold.  CPUC Staff, the OCC and Colorado Energy Consumers each filed notices with the CPUC disputing PSCo’s assertion that earnings did not exceed the threshold. In June 2013, PSCo entered into a comprehensive settlement of issues with all parties, which was approved by the CPUC and resulted in a refund of approximately $8.2 million to customers over the next year. As of June 30, 2013, PSCo recognized a liability for the settlement amount as well as an estimated accrual representing its best estimate of any refund obligation for the 2013 test year.

Electric, Purchased Gas and Resource Adjustment Clauses

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 beginning in 2011 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 June 30, 2013 and 2012, PSCo credited the RESA regulatory asset balance $6.5 million and $6.3 million, respectively.  The cumulative credit to the RESA regulatory asset balance was $93.3 million and $82.8 million at June 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 to provide the CPUC an opportunity to review the framework and evidence regarding actual deliveries.

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. A procedural schedule has not been set.

SPS

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

Base Rate

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.


16
Table of Contents

In April 2013, the parties filed a settlement agreement in which SPS’ base rate will increase by $37 million, effective May 1, 2013, on an interim basis pending the PUCT’s approval of the settlement, 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.  On June 6, 2013, the PUCT approved the settlement without modification.

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

Base Rate

SPS – New Mexico 2012 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.  The rate filing is based on a 2014 forecast test year, a requested ROE of 10.65 percent, a jurisdictional electric rate base of $479.8 million and an equity ratio of 53.89 percent.

In March 2013, the NMPRC ruled that SPS’ case, as originally filed, was incomplete due to confidential exhibits to testimony and schedules being included in SPS’ direct case, and directed the hearing examiner to review SPS’ claims of confidentiality and to determine the date the filing is complete.  After SPS made filings to address the NMPRC’s concern about the confidential documents, the hearing examiner determined that SPS’ application was completed on April 12, 2013.  The NMPRC has suspended the tariffs for an initial nine month period beyond that date, or until Jan. 11, 2014.  The NMPRC has authority to suspend the rates for an additional three months beyond the initial nine month period, or until April 11, 2014. On June 19, 2013, SPS revised its requested rate increase to $43.3 million.

Next steps in the procedural schedule are expected to be as follows:

•
Staff/Intervenor Direct Testimony – Aug. 22, 2013
•
Rebuttal Testimony – Sept. 9, 2013
•
Evidentiary Hearings – Sept. 16-27, 2013

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 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 Federal Energy Regulatory Commission (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.

Next steps in the procedural schedules are expected to be as follows:

•
PUCT Intervenor Direct Testimony – Aug. 2, 2013
•
PUCT Staff Direct Testimony – Aug. 9, 2013
•
PUCT SPS Rebuttal Testimony – Aug. 16, 2013
•
PUCT Evidentiary Hearing – Sept. 3, 2013
•
NMPRC Staff/Intervenor Direct Testimony – Sept. 12, 2013
•
NMPRC SPS Rebuttal Testimony – Sept. 27, 2013
•
NMPRC Evidentiary Hearing – Oct. 8 - 9, 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.


17
Table of Contents

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.

The Xcel Energy utility subsidiaries had approximately 3,406 megawatts (MW) and 3,324 MW of capacity under long-term purchased power agreements as of June 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 June 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)
 
June 30, 2013
 
Dec. 31, 2012
Guarantees issued and outstanding
 
$
54.8

 
$
69.5

Current exposure under these guarantees
 
17.9

 
17.9

Bonds with indemnity protection
 
31.0

 
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.


18
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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 in 2013.

Negotiations between the EPA and NSP-Wisconsin regarding who will pay or perform the cleanup of the Sediments are ongoing.  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 scheduled for June 2014. 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 June 30, 2013 and Dec. 31, 2012, NSP-Wisconsin had recorded a liability of $101.3 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 $14.3 million and $20.1 million, respectively, was considered a current liability.  The reduction in recorded liability at June 30, 2013 reflects that cleanup has now commenced and costs are being incurred with respect to the Phase I Project Area.  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 a recent rate case decision, the PSCW recognized the potential magnitude of the future liability for the cleanup at the Ashland site.  In December 2012, the PSCW 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.

Environmental Requirements

Greenhouse Gas (GHG) New Source Performance Standard Proposal (NSPS) and Emission Guideline for Existing Sources — In April 2012, the EPA proposed a GHG NSPS for newly constructed power plants. The proposal requires that carbon dioxide (CO2) emission rates be equal to a natural gas combined-cycle plant, even if the plant is coal-fired. The EPA also proposed that NSPS not apply to modified or reconstructed existing power plants and that installation of control equipment on existing plants would not constitute a “modification” to those plants under the NSPS program. On June 25, 2013, President Obama issued a memorandum directing the EPA to re-propose GHG emission standards for new power plants and develop GHG emission standards for existing power plants. It is not possible to evaluate the impact of these regulations until the upcoming proposals and final requirements are known.


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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.  Although the D.C. Circuit had denied all requests for rehearing, 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 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 2017.  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 June 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 (CCR). 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. The EPA is also seeking comment on the interaction between the ELG proposal and its proposed CCR rule, which is another proposed rule that would also regulate surface impoundments that store coal combustion byproducts (coal ash) and whether to regulate coal ash as hazardous or nonhazardous waste. A final rule is anticipated in 2014. Under the current proposed rule, facilities would need to comply as soon as possible after July 1, 2017 but no later than July 1, 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.

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 $340.8 million.  PSCo expects the cost of any required capital investment will be recoverable from customers.


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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.

The estimated cost for meeting the BART, regional haze and other CAA requirements is approximately $50 million, of which $34 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.

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.


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New Mexico GHG Regulations — In 2010, the New Mexico Environmental Improvement Board (EIB) adopted two regulations to limit GHG emissions, including CO2 emissions from power plants and other industrial sources. The EIB repealed both regulations in the first quarter of 2012. Western Resource Advocates and New Energy Economy, Inc. filed appeals with the New Mexico Court of Appeals to challenge each of the EIB’s decisions to repeal the two GHG rules. After the appellants filed unopposed motions to dismiss, the court dismissed these appeals in July 2013.

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

Native Village of Kivalina vs. Xcel Energy Inc. et al. — In February 2008, the City and Native Village of Kivalina, Alaska, filed a lawsuit in the U.S. District Court for the Northern District of California against Xcel Energy and 23 other utility, oil, gas and coal companies.  Plaintiffs claim that defendants’ emission of CO2 and other greenhouse gases contribute to global warming, which is harming their village.  Xcel Energy believes the claims asserted in this lawsuit are without merit and joined with other utility defendants in filing a motion to dismiss in June 2008.  In October 2009, the U.S. District Court dismissed the lawsuit on constitutional grounds.  In November 2009, plaintiffs filed a notice of appeal to the U.S. Court of Appeals for the Ninth Circuit (Ninth Circuit).  In October 2012, the Ninth Circuit affirmed the U.S. District Court’s dismissal and subsequently rejected plaintiffs’ request for rehearing.  In May 2013 the U.S. Supreme Court denied plaintiffs’ request for review, which brings this litigation to a close.  No accrual has been recorded for this matter.

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. It is uncertain whether plaintiffs will seek further review of this decision. Although Xcel Energy believes the likelihood of loss is remote based upon existing case law, 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.


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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.  On Oct. 22, 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.  On April 23, 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 Administrative Law Judge (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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On April 5, 2013, the FERC issued an order on rehearing of its remand order issued for the October 2011 review proceedings.  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 scheduled to begin in August 2013.

Preliminary calculations of the City of Seattle’s claim for refunds from PSCo are approximately $28 million not including 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 third claim submission, in the amount of $42.8 million, was filed May 15, 2013 for costs incurred in 2012. The DOE has until Sept. 1, 2013 to accept or deny the claim, in whole or in part. Amounts received from the first installments were subsequently credited to customers, except for approved reductions such as legal costs, customer credit amounts still in process at June 30, 2013, 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 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  
 June 30, 2013
 
Twelve Months Ended
Dec. 31, 2012
Borrowing limit
 
$
2,450

 
$
2,450

Amount outstanding at period end
 
354

 
602

Average amount outstanding
 
255

 
403

Maximum amount outstanding
 
487

 
634

Weighted average interest rate, computed on a daily basis
 
0.29
%
 
0.35
%
Weighted average interest rate at period end
 
0.27

 
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 June 30, 2013 and Dec. 31, 2012, there were $15.7 million and $14.2 million of letters of credit outstanding, respectively, under the credit facilities.  All letters of credit outstanding were issued under the credit facilities at June 30, 2013 and Dec. 31, 2012.  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 June 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

 
$
278.0

 
$
522.0

PSCo
 
700.0

 
4.6

 
695.4

NSP-Minnesota
 
500.0

 
36.1

 
463.9

SPS
 
300.0

 
49.0

 
251.0

NSP-Wisconsin
 
150.0

 
2.0

 
148.0

Total
 
$
2,450.0

 
$
369.7

 
$
2,080.3


(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 June 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.


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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.  As of June 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 the 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.  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; 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.

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.


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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 $169.6 million and $135.8 million at June 30, 2013 and Dec. 31, 2012, respectively, and unrealized losses and amounts recorded as other-than-temporary impairments were $81.6 million and $46.4 million at June 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 June 30, 2013 and Dec. 31, 2012:
 
 
June 30, 2013
 
 
 
 
Fair Value
 
 
(Thousands of Dollars)
 
Cost
 
Level 1
 
Level 2
 
Level 3
 
Total
Nuclear decommissioning fund (a)
 
 

 
 

 
 

 
 

 
 

Cash equivalents
 
$
32,663

 
$
32,663

 
$
—

 
$
—

 
$
32,663

Commingled funds
 
415,197

 
—

 
414,899

 
—

 
414,899

International equity funds
 
66,452

 
—

 
65,606

 
—

 
65,606

Private equity investments
 
36,496

 
—

 
—

 
45,590

 
45,590

Real estate
 
30,357

 
—

 
—

 
38,140

 
38,140

Debt securities:
 
 

 
 

 
 

 
 

 
 

Government securities
 
56,017

 
—

 
49,702

 
—

 
49,702

U.S. corporate bonds
 
131,917

 
—

 
134,571

 
—

 
134,571

International corporate bonds
 
18,859

 
—

 
18,703

 
—

 
18,703

Municipal bonds
 
190,353

 
—

 
182,225

 
—

 
182,225

Equity securities:
 
 

 
 

 
 

 
 

 
 

Common stock
 
429,086

 
513,339

 
—

 
—

 
513,339

Total
 
$
1,407,397

 
$
546,002

 
$
865,706

 
$
83,730

 
$
1,495,438


(a) 
Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $88.7 million of equity investments in unconsolidated subsidiaries and $38.8 million of miscellaneous investments.
 
 
Dec. 31, 2012
 
 
 
 
Fair Value
 
 
(Thousands of Dollars)
 
Cost
 
Level 1
 
Level 2
 
Level 3
 
Total
Nuclear decommissioning fund (a)
 
 

 
 

 
 

 
 

 
 

Cash equivalents
 
$
246,904

 
$
237,938

 
$
8,966

 
$
—

 
$
246,904

Commingled funds
 
396,681

 
—

 
417,583

 
—

 
417,583

International equity funds
 
66,452

 
—

 
69,481

 
—

 
69,481

Private equity investments
 
27,943

 
—

 
—

 
33,250

 
33,250

Real estate
 
32,561

 
—

 
—

 
39,074

 
39,074

Debt securities:
 
 

 
 

 
 

 
 

 
 

Government securities
 
21,092

 
—

 
21,521

 
—

 
21,521

U.S. corporate bonds
 
162,053

 
—

 
169,488

 
—

 
169,488

International corporate bonds
 
15,165

 
—

 
16,052

 
—

 
16,052

Municipal bonds
 
21,392

 
—

 
23,650

 
—

 
23,650

Asset-backed securities
 
2,066

 
—

 
—

 
2,067

 
2,067

Mortgage-backed securities
 
28,743

 
—

 
—

 
30,209

 
30,209

Equity securities:
 
 

 
 

 
 

 
 

 
 

Common stock
 
379,093

 
420,263

 
—

 
—

 
420,263

Total
 
$
1,400,145

 
$
658,201

 
$
726,741

 
$
104,600

 
$
1,489,542


(a) 
Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $91.2 million of equity investments in unconsolidated subsidiaries and $37.1 million of miscellaneous investments.


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The following tables present the changes in Level 3 nuclear decommissioning fund investments for the three and six months ended June 30, 2013 and 2012:
(Thousands of Dollars)
 
April 1, 2013
 
Purchases
 
Settlements
 
Gains
Recognized as
Regulatory Liabilities
 
Transfers Out of Level 3
 
June 30, 2013
Private equity investments
 
$
34,506

 
$
7,298

 
$
—

 
$
3,786

 
$
—

 
$
45,590

Real estate
 
40,406

 
2,032

 
(4,723
)
 
425

 
—

 
38,140

Total
 
$
74,912

 
$
9,330

 
$
(4,723
)
 
$
4,211

 
$
—

 
$
83,730

(Thousands of Dollars)
 
April 1, 2012
 
Purchases
 
Settlements
 
Gains (Losses)
Recognized as
Regulatory Assets and Liabilities
 
Transfers Out of Level 3
 
June 30, 2012
Private equity investments
 
$
20,068

 
$
3,235

 
$
—

 
$
—

 
$
—

 
$
23,303

Real estate
 
27,905

 
2,271

 
—