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EXCEL - IDEA: XBRL DOCUMENT - XCEL ENERGY INCFinancial_Report.xls
EX-99.01 - EXHIBIT 99.01 - XCEL ENERGY INCxcel10-qex9901q22014.htm
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EX-31.02 - EXHIBIT 31.02 - XCEL ENERGY INCxcelex3102q22014.htm
EX-31.01 - EXHIBIT 31.01 - XCEL ENERGY INCxcelex3101q22014.htm

 
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, 2014
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 25, 2014
Common Stock, $2.50 par value
 
505,370,152 shares

 




TABLE OF CONTENTS

PART I
FINANCIAL INFORMATION
 
Item 1 —

 

 

 

 

 

 

Item 2 —

Item 3 —

Item 4 —

 
 
 
PART II
OTHER INFORMATION
 
Item 1 —

Item 1A —

Item 2 —

Item 4 —

Item 5 —

Item 6 —

 
 
 

 
 
 
 
Certifications Pursuant to Section 302
1

 
Certifications Pursuant to Section 906
1

 
Statement Pursuant to Private Litigation
1


This Form 10-Q is filed by Xcel Energy Inc.  Xcel Energy Inc. wholly owns the following subsidiaries: Northern States Power Company, a Minnesota corporation (NSP-Minnesota); Northern States Power Company, a Wisconsin corporation (NSP-Wisconsin); Public Service Company of Colorado (PSCo); and Southwestern Public Service Company (SPS).  Xcel Energy Inc. and its consolidated subsidiaries are also referred to herein as Xcel Energy.  NSP-Minnesota, NSP-Wisconsin, PSCo and SPS are also referred to collectively as utility subsidiaries.  The electric production and transmission system of NSP-Minnesota and NSP-Wisconsin, which is operated on an integrated basis and is managed by NSP-Minnesota, is referred to collectively as the NSP System. Additional information on the wholly owned subsidiaries is available on various filings with the Securities and Exchange Commission (SEC).

2


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
 
2014
 
2013
 
2014
 
2013
Operating revenues
 
 
 
 
 
 
 
Electric
$
2,297,638

 
$
2,219,877

 
$
4,599,348

 
$
4,312,073

Natural gas
369,127

 
341,321

 
1,248,815

 
1,010,917

Other
18,331

 
17,715

 
39,537

 
38,772

Total operating revenues
2,685,096

 
2,578,913

 
5,887,700

 
5,361,762

 
 
 
 
 
 
 
 
Operating expenses
 
 
 
 
 
 
 
Electric fuel and purchased power
1,041,322

 
1,011,044

 
2,108,643

 
1,936,087

Cost of natural gas sold and transported
210,901

 
188,765

 
834,729

 
628,140

Cost of sales — other
7,642

 
7,881

 
16,771

 
16,292

Operating and maintenance expenses
585,604

 
562,557

 
1,145,747

 
1,091,788

Conservation and demand side management program expenses
70,834

 
60,445

 
148,380

 
124,477

Depreciation and amortization
255,307

 
243,934

 
501,250

 
492,640

Taxes (other than income taxes)
116,278

 
102,051

 
240,980

 
215,478

Total operating expenses
2,287,888

 
2,176,677

 
4,996,500

 
4,504,902

 
 
 
 
 
 
 
 
Operating income
397,208

 
402,236

 
891,200

 
856,860

 
 
 
 
 
 
 
 
Other income, net
82

 
413

 
3,283

 
4,335

Equity earnings of unconsolidated subsidiaries
7,811

 
7,529

 
15,249

 
15,106

Allowance for funds used during construction — equity
23,608

 
22,109

 
45,515

 
41,863

 
 
 
 
 
 
 
 
Interest charges and financing costs
 
 
 
 
 
 
 
Interest charges — includes other financing costs of
$5,614, $12,229, $11,406 and $18,038, respectively
139,400

 
146,853

 
278,494

 
286,484

Allowance for funds used during construction — debt
(10,113
)
 
(10,316
)
 
(19,661
)
 
(19,074
)
Total interest charges and financing costs
129,287

 
136,537

 
258,833

 
267,410

 
 
 
 
 
 
 
 
Income before income taxes
299,422

 
295,750

 
696,414

 
650,754

Income taxes
104,258

 
98,893

 
240,029

 
217,327

Net income
$
195,164

 
$
196,857

 
$
456,385

 
$
433,427

 
 
 
 
 
 
 
 
Weighted average common shares outstanding:
 
 
 
 
 
 
 
Basic
503,272

 
497,747

 
501,408

 
493,786

Diluted
503,456

 
498,036

 
501,612

 
494,303

 
 
 
 
 
 
 
 
Earnings per average common share:
 
 
 
 
 
 
 
Basic
$
0.39

 
$
0.40

 
$
0.91

 
$
0.88

Diluted
0.39

 
0.40

 
0.91

 
0.88

 
 
 
 
 
 
 
 
Cash dividends declared per common share
$
0.30

 
$
0.28

 
$
0.60

 
$
0.55

 
 
 
 
 
 
 
 
See Notes to Consolidated Financial Statements


3


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

 
Three Months Ended June 30
 
Six Months Ended June 30
 
2014
 
2013
 
2014
 
2013
Net income
$
195,164

 
$
196,857

 
$
456,385

 
$
433,427

 
 
 
 
 
 
 
 
Other comprehensive income (loss)
 

 
 

 
 
 
 
 
 
 
 
 
 
 
 
Pension and retiree medical benefits:
 

 
 

 
 
 
 
Amortization of losses included in net periodic benefit cost,
net of tax of $550, $729, $1,099 and $3,232, respectively
864

 
1,135

 
1,728

 
496

 
 
 
 
 
 
 
 
Derivative instruments:
 

 
 

 
 
 
 
Net fair value increase (decrease), net of tax of $9, $(29), $6, and $(17), respectively
16

 
(44
)
 
8

 
(31
)
Reclassification of losses to net income, net of tax of
$365, $451, $722 and $1,881, respectively
574

 
694

 
1,135

 
389

 
590

 
650

 
1,143

 
358

Marketable securities:
 

 
 

 
 
 
 
Net fair value increase (decrease), net of tax of
$0, $0, $24 and $(18), respectively

 

 
38

 
(36
)
 
 
 
 
 
 
 
 
Other comprehensive income
1,454

 
1,785

 
2,909

 
818

Comprehensive income
$
196,618

 
$
198,642

 
$
459,294

 
$
434,245

 
 
 
 
 
 
 
 
See Notes to Consolidated Financial Statements




4


XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
(amounts in thousands)
 
Six Months Ended June 30
 
2014
 
2013
Operating activities
 
 
 

Net income
$
456,385

 
$
433,427

Adjustments to reconcile net income to cash provided by operating activities:
 

 
 

Depreciation and amortization
509,914

 
507,658

Conservation and demand side management program amortization
3,131

 
3,425

Nuclear fuel amortization
60,466

 
49,485

Deferred income taxes
236,479

 
235,684

Amortization of investment tax credits
(2,886
)
 
(3,314
)
Allowance for equity funds used during construction
(45,515
)
 
(41,863
)
Equity earnings of unconsolidated subsidiaries
(15,249
)
 
(15,106
)
Dividends from unconsolidated subsidiaries
18,114

 
18,683

Share-based compensation expense
10,990

 
18,747

Net realized and unrealized hedging and derivative transactions
(2,403
)
 
(2,754
)
Changes in operating assets and liabilities:
 

 
 

Accounts receivable
1,406

 
(78,940
)
Accrued unbilled revenues
77,557

 
37,069

Inventories
75,268

 
40,684

Other current assets
(32,157
)
 
29,700

Accounts payable
(147,734
)
 
1,625

Net regulatory assets and liabilities
63,675

 
76,693

Other current liabilities
(129,981
)
 
(83,336
)
Pension and other employee benefit obligations
(115,455
)
 
(170,162
)
Change in other noncurrent assets
47,855

 
16,983

Change in other noncurrent liabilities
(30,349
)
 
(163
)
Net cash provided by operating activities
1,039,511

 
1,074,225

 
 
 
 
Investing activities
 

 
 

Utility capital/construction expenditures
(1,575,748
)
 
(1,596,778
)
Proceeds from insurance recoveries
6,000

 
50,000

Allowance for equity funds used during construction
45,515

 
41,863

Purchases of investments in external decommissioning fund
(404,780
)
 
(890,700
)
Proceeds from the sale of investments in external decommissioning fund
401,488

 
887,500

Investment in WYCO Development LLC
(2,132
)
 
(2,166
)
Other, net
(1,568
)
 
(1,696
)
Net cash used in investing activities
(1,531,225
)
 
(1,511,977
)
 
 
 
 
Financing activities
 
 
 
Proceeds from (repayments of) short-term borrowings, net
18,800

 
(248,000
)
Proceeds from issuance of long-term debt
838,582

 
1,337,045

Repayments of long-term debt, including reacquisition premiums
(275,484
)
 
(651,516
)
Proceeds from issuance of common stock
176,573

 
227,113

Dividends paid
(274,361
)
 
(250,392
)
Net cash provided by financing activities
484,110

 
414,250

 
 
 
 
Net change in cash and cash equivalents
(7,604
)
 
(23,502
)
Cash and cash equivalents at beginning of period
107,144

 
82,323

Cash and cash equivalents at end of period
$
99,540

 
$
58,821

 
 
 
 
Supplemental disclosure of cash flow information:
 

 
 

Cash paid for interest (net of amounts capitalized)
$
(251,461
)
 
$
(258,124
)
Cash (paid) received for income taxes, net
(4,704
)
 
13,681

 
 
 
 
Supplemental disclosure of non-cash investing and financing transactions:
 

 
 

Property, plant and equipment additions in accounts payable
$
305,447

 
$
302,434

Issuance of common stock for reinvested dividends and 401(k) plans
29,272

 
37,504

 
 
 
 
See Notes to Consolidated Financial Statements

5


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

 
June 30, 2014
 
Dec. 31, 2013
Assets
 
 
 
Current assets
 
 
 
Cash and cash equivalents
$
99,540

 
$
107,144

Accounts receivable, net
742,730

 
744,160

Accrued unbilled revenues
609,673

 
687,230

Inventories
501,270

 
576,538

Regulatory assets
462,185

 
417,801

Derivative instruments
154,940

 
91,707

Deferred income taxes
282,765

 
341,202

Prepayments and other
270,717

 
252,258

Total current assets
3,123,820

 
3,218,040

 
 
 
 
Property, plant and equipment, net
27,070,377

 
26,122,159

 
 
 
 
Other assets
 
 
 
Nuclear decommissioning fund and other investments
1,838,648

 
1,755,990

Regulatory assets
2,451,558

 
2,509,218

Derivative instruments
59,732

 
84,842

Other
173,509

 
217,241

Total other assets
4,523,447

 
4,567,291

Total assets
$
34,717,644

 
$
33,907,490

 
 
 
 
Liabilities and Equity
 
 
 
Current liabilities
 
 
 
Current portion of long-term debt
$
7,522

 
$
280,763

Short-term debt
777,800

 
759,000

Accounts payable
967,251

 
1,261,238

Regulatory liabilities
366,579

 
274,769

Taxes accrued
269,020

 
378,766

Accrued interest
158,663

 
159,372

Dividends payable
151,097

 
139,432

Derivative instruments
20,874

 
23,382

Other
341,123

 
377,776

Total current liabilities
3,059,929

 
3,654,498

 
 
 
 
Deferred credits and other liabilities
 
 
 
Deferred income taxes
5,551,537

 
5,331,046

Deferred investment tax credits
76,353

 
79,239

Regulatory liabilities
1,107,253

 
1,059,395

Asset retirement obligations
1,897,942

 
1,815,390

Derivative instruments
194,553

 
209,224

Customer advances
268,690

 
275,555

Pension and employee benefit obligations
650,596

 
769,222

Other
237,241

 
237,217

Total deferred credits and other liabilities
9,984,165

 
9,776,288

 
 
 
 
Commitments and contingencies


 


Capitalization
 
 
 
Long-term debt
11,752,778

 
10,910,754

Common stock — 1,000,000,000 shares authorized of $2.50 par value; 505,105,562 and
497,971,508 shares outstanding at June 30, 2014 and Dec. 31, 2013, respectively
1,262,764

 
1,244,929

Additional paid in capital
5,799,968

 
5,619,313

Retained earnings
2,961,406

 
2,807,983

Accumulated other comprehensive loss
(103,366
)
 
(106,275
)
Total common stockholders’ equity
9,920,772

 
9,565,950

Total liabilities and equity
$
34,717,644

 
$
33,907,490

 
 
 
 
See Notes to Consolidated Financial Statements

6


XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY (UNAUDITED)
(amounts in thousands)

 
Common Stock Issued
 
Retained Earnings
 
Accumulated
Other
Comprehensive
Loss
 
 Total
Common
Stockholders’
Equity
 
Shares
 
Par Value
 
Additional Paid In Capital
 
 
 
Three Months Ended June 30, 2014 and 2013
 
 
 
 
 
 
 
 
 
 
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 on 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

 
 
 
 
 
 
 
 
 
 
 
 
Balance at March 31, 2014
501,152

 
$
1,252,879

 
$
5,681,150

 
$
2,918,215

 
$
(104,820
)
 
$
9,747,424

Net income
 
 
 
 
 
 
195,164

 
 
 
195,164

Other comprehensive income
 
 
 
 
 
 
 
 
1,454

 
1,454

Dividends declared on common stock
 
 
 
 
 
 
(151,973
)
 
 
 
(151,973
)
Issuances of common stock
3,954

 
9,885

 
111,053

 
 
 
 
 
120,938

Share-based compensation
 
 
 
 
7,765

 
 
 
 
 
7,765

Balance at June 30, 2014
505,106

 
$
1,262,764

 
$
5,799,968

 
$
2,961,406

 
$
(103,366
)
 
$
9,920,772

 
 
 
 
 
 
 
 
 
 
 
 
See Notes to Consolidated Financial Statements

7


XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY (UNAUDITED) (Continued)
(amounts in thousands)

 
Common Stock Issued
 
Retained Earnings
 
Accumulated
Other
Comprehensive
Loss
 
 Total
Common
Stockholders’
Equity
 
Shares
 
Par Value
 
Additional Paid In Capital
 
 
 
Six Months Ended June 30, 2014 and 2013
 
 
 
 
 
 
 
 
 
 
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 on 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

 
 
 
 
 
 
 
 
 
 
 
 
Balance at Dec. 31, 2013
497,972

 
$
1,244,929

 
$
5,619,313

 
$
2,807,983

 
$
(106,275
)
 
$
9,565,950

Net income
 
 
 
 
 
 
456,385

 
 
 
456,385

Other comprehensive income
 
 
 
 
 
 
 
 
2,909

 
2,909

Dividends declared on common stock
 
 
 
 
 
 
(302,962
)
 
 
 
(302,962
)
Issuances of common stock
7,134

 
17,835

 
166,825

 
 
 
 
 
184,660

Share-based compensation
 
 
 
 
13,830

 
 
 
 
 
13,830

Balance at June 30, 2014
505,106

 
$
1,262,764

 
$
5,799,968

 
$
2,961,406

 
$
(103,366
)
 
$
9,920,772

 
 
 
 
 
 
 
 
 
 
 
 
See Notes to Consolidated Financial Statements


8


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, 2014 and Dec. 31, 2013; 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, 2014 and 2013; and its cash flows for the six months ended June 30, 2014 and 2013. All adjustments are of a normal, recurring nature, except as otherwise disclosed. Management has also evaluated the impact of events occurring after June 30, 2014 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, 2013 balance sheet information has been derived from the audited 2013 consolidated financial statements included in the Xcel Energy Inc. Annual Report on Form 10-K for the year ended Dec. 31, 2013. 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, 2013, filed with the SEC on Feb. 21, 2014. 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, 2013, appropriately represent, in all material respects, the current status of accounting policies and are incorporated herein by reference.

2.
Accounting Pronouncements

Recently Issued

Revenue Recognition In May 2014, the Financial Accounting Standards Board issued Revenue from Contracts with Customers, Topic 606 (Accounting Standards Update (ASU) No. 2014-09), which provides a framework for the recognition of revenue, with the objective that recognized revenues properly reflect amounts an entity is entitled to receive in exchange for goods and services. This guidance, which includes additional disclosure requirements regarding revenue, cash flows and obligations related to contracts with customers, will be effective for interim and annual reporting periods beginning after Dec. 15, 2016. Xcel Energy is currently evaluating the impact of adopting ASU 2014-09 on its consolidated financial statements.

3.
Selected Balance Sheet Data
(Thousands of Dollars)
 
June 30, 2014
 
Dec. 31, 2013
Accounts receivable, net
 
 
 
 
Accounts receivable
 
$
793,537

 
$
797,267

Less allowance for bad debts
 
(50,807
)
 
(53,107
)
 
 
$
742,730

 
$
744,160

(Thousands of Dollars)
 
June 30, 2014
 
Dec. 31, 2013
Inventories
 
 
 
 
Materials and supplies
 
$
234,212

 
$
225,308

Fuel
 
168,314

 
189,485

Natural gas
 
98,744

 
161,745

 
 
$
501,270

 
$
576,538


9


(Thousands of Dollars)
 
June 30, 2014
 
Dec. 31, 2013
Property, plant and equipment, net
 
 
 
 
Electric plant
 
$
31,360,194

 
$
30,341,310

Natural gas plant
 
4,211,851

 
4,086,651

Common and other property
 
1,467,336

 
1,485,547

Plant to be retired (a)
 
85,808

 
101,279

Construction work in progress
 
2,502,721

 
2,371,566

Total property, plant and equipment
 
39,627,910

 
38,386,353

Less accumulated depreciation
 
(12,854,913
)
 
(12,608,305
)
Nuclear fuel
 
2,200,534

 
2,186,799

Less accumulated amortization
 
(1,903,154
)
 
(1,842,688
)
 
 
$
27,070,377

 
$
26,122,159


(a) 
As a result of the 2010 Colorado Public Utilities Commission (CPUC) approval of PSCo’s Clean Air Clean Jobs Act (CACJA) compliance plan and the December 2013 approval of PSCo’s preferred plans for applicable generating resources, PSCo has received approval for early retirement of Cherokee Unit 3 and Valmont Unit 5 between 2015 and 2017. 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, 2013 appropriately represent, in all material respects, the current status of other income tax matters, and are incorporated herein by reference.

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

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, including the 2009 carryback claim. As of June 30, 2014, the IRS had proposed an adjustment to the federal tax loss carryback claims that would result in $10 million of income tax expense for the 2009 through 2011 claims and the anticipated claim for 2013. Xcel Energy is continuing to work through the audit process, but the outcome and timing of a resolution is uncertain.

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, 2014, Xcel Energy’s earliest open tax years that are subject to examination by state taxing authorities in its major operating jurisdictions were as follows:
State
 
Year
Colorado
 
2009
Minnesota
 
2009
Texas
 
2009
Wisconsin
 
2009

In the first quarter of 2014, the state of Wisconsin completed an examination of tax years 2009 through 2011. No material adjustments were proposed for those tax years. As of June 30, 2014, there were no state income tax audits in progress.

Unrecognized Tax Benefits — The unrecognized tax benefit balance includes permanent tax positions, which if recognized would affect the annual effective tax rate (ETR). In addition, the unrecognized tax benefit balance includes temporary tax positions for which the ultimate deductibility is highly certain but for which there is uncertainty about the timing of such deductibility. A change in the period of deductibility would not affect the ETR but would accelerate the payment of cash to the taxing authority to an earlier period.


10


A reconciliation of the amount of unrecognized tax benefit is as follows:
(Millions of Dollars)
 
June 30, 2014
 
Dec. 31, 2013
Unrecognized tax benefit — Permanent tax positions
 
$
7.5

 
$
12.9

Unrecognized tax benefit — Temporary tax positions
 
30.3

 
28.3

Total unrecognized tax benefit
 
$
37.8

 
$
41.2


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, 2014
 
Dec. 31, 2013
NOL and tax credit carryforwards
 
$
(25.6
)
 
$
(27.1
)

It is reasonably possible that Xcel Energy’s amount of unrecognized tax benefits could significantly change in the next 12 months as the IRS audit progresses and state audits resume. As the IRS examination moves closer to completion, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $8 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, 2014 and Dec. 31, 2013 were not material. No amounts were accrued for penalties related to unrecognized tax benefits as of June 30, 2014 or Dec. 31, 2013.

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, 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)

NSP Minnesota – Minnesota 2014 Multi-Year Electric Rate Case  In November 2013, NSP-Minnesota filed a two-year electric rate case with the MPUC. The rate case is based on a requested return on equity (ROE) of 10.25 percent, a 52.5 percent equity ratio, a 2014 average electric rate base of $6.67 billion and an additional average rate base of $412 million in 2015.

The NSP-Minnesota electric rate case reflects an increase in revenues of approximately $193 million or 6.9 percent in 2014 and an additional $98 million or 3.5 percent in 2015. The request includes a proposed rate moderation plan for 2014 and 2015. After reflecting interim rate adjustments, NSP-Minnesota requested a rate increase of $127 million or 4.6 percent in 2014 and an incremental rate increase of $164 million or 5.6 percent in 2015.

NSP-Minnesota’s moderation plan includes the acceleration of the eight-year amortization of the excess depreciation reserve and the use of expected funds from the U.S. Department of Energy (DOE) for settlement of certain claims. These DOE refunds would be in excess of amounts needed to fund NSP-Minnesota’s decommissioning expense. The interim rate adjustments are primarily associated with ROE, Monticello life cycle management (LCM)/extended power uprate (EPU) project costs and NSP-Minnesota’s request to amortize amounts associated with the canceled Prairie Island (PI) EPU project.

In December 2013, the MPUC approved interim rates of $127 million effective Jan. 3, 2014, subject to refund. The MPUC determined that the costs of Sherco Unit 3 would be allowed in interim rates, and that NSP-Minnesota’s request to accelerate the depreciation reserve amortization was a permissible adjustment to its interim rate request.

In June 2014, intervening parties filed direct testimony proposing modifications to NSP-Minnesota’s rate request. The Minnesota Department of Commerce (DOC) recommended an increase of approximately $61.6 million in 2014 and a step increase of $54.9 million for 2015, based on a recommended ROE of 9.8 percent and an equity ratio of 52.5 percent. The DOC also recommended adoption of a full decoupling pilot for the residential and small commercial and industrial (C&I) class, based on actual results (not weather-normalized) for three years and made rate design and cost allocation recommendations.


11


Several other intervenors also filed testimony and included the following recommendations:
One or more of these parties made recommendations seeking modifications to rate design, supporting, modifying or opposing decoupling, and proposing inclining block rates and advocating for modification and application of the excess nuclear depreciation reserve.
One or more of these parties also made revenue requirement adjustments, including some of the same adjustments recommended by the DOC, such as the exclusion of the Monticello EPU, sales forecast and modifying or eliminating PI EPU amortization.
Other key revenue adjustments include:
Amortization of excess depreciation reserve for nuclear plant;
Seeking to exclude two owned wind projects from the step rate increase;
Denial of the Multi-Year Plan step rate increase;
An ROE recommendation of 9 percent;
Modification to the capital structure; and
Exclusion of construction work in progress and allowance for funds used during construction (AFUDC) from rates and adjustments to AFUDC rates and application.

In July 2014, NSP-Minnesota filed rebuttal testimony and reduced its request to an increase in revenues of approximately $169.5 million or 6.2 percent in 2014 and an additional $95 million or 3.5 percent in 2015. The revision reflects an update to NSP-Minnesota’s 2014 sales forecast and narrowed the number of disputed issues in the case by agreeing to or partially agreeing to an outcome on several smaller issues. NSP-Minnesota continues to support its initial filed position, including cost recovery of the Monticello LCM/EPU project, an ROE of 10.25 percent and property taxes. For the 2015 increase, NSP-Minnesota reduced its request by $3.5 million in order to focus the request on specific capital projects.

The following table summarizes the DOC’s recommendations from NSP-Minnesota’s filed request:
(Millions of Dollars)
 
DOC Direct Testimony
2014
 
NSP-Minnesota Rebuttal Testimony
2014
Filed rate request
 
$
192.7

 
$
192.7

Monticello EPU cost recovery
 
(31.3
)
 

Sales forecast
 
(29.5
)
 
(15.8
)
ROE
 
(26.9
)
 

Health care, pension and other benefits
 
(21.9
)
 
(0.8
)
Property taxes
 
(13.5
)
 

PI EPU
 
(5.8
)
 
(3.8
)
Other, net
 
(2.2
)
 
(2.8
)
Total recommendation 2014
 
$
61.6


$
169.5

(Millions of Dollars)
 
DOC Direct Testimony
2015 Step
 
NSP-Minnesota Rebuttal Testimony
2015 Step
Filed rate request
 
$
98.5

 
$
98.5

Depreciation
 
(17.5
)
 

Property taxes
 
(14.5
)
 
(3.3
)
Production tax credits to be included in base rates
 
(11.1
)
 
(11.1
)
DOE settlement proceeds
 
(10.8
)
 
10.1

Capital changes and disallowances
 
(5.6
)
 

Nuclear outage amortization
 
(5.5
)
 

Emission chemicals
 
(3.0
)
 
(0.2
)
Excess depreciation reserve adjustment
 
22.7

 

Other, net
 
1.7

 
1.0

Total recommendation 2015 step increase
 
54.9

 
95.0

Cumulative total for 2014 and 2015 step increase
 
$
116.5

 
$
264.5



12


NSP-Minnesota’s rebuttal rate request, moderation plan, interim rate adjustments and certain impacts on expenses are detailed in the table below:
(Millions of Dollars)
 
2014
 
Percentage
Increase
 
2015
 
Percentage
Increase
Rebuttal pre-moderation deficiency
 
$
250

 
 
 
$
68

 
 
Moderation change compared to prior year:
 
 
 
 
 
 
 
 
  Depreciation reserve
 
(81
)
 
 
 
53

 
 
  DOE settlement proceeds
 

 
 
 
(26
)
 
 
Rebuttal rate request
 
169

 
6.2%
 
95

 
3.5%
Interim rate adjustments
 
(66
)
 
 
 
66

 
 
PI EPU
 
4

 
 
 
(4
)
 
 
Revenue impact(a)
 
107

 
 
 
157

 
 
Depreciation expense - decrease/(increase)
 
81

 
 
 
(46
)
 
 
Recognition of DOE settlement proceeds
 

 
 
 
26

 
 
Rebuttal pre-tax impact on operating income
 
$
188

 
 
 
$
137

 
 

(a) 
NSP-Minnesota’s total revenue for 2014 is capped at the interim rate level of $127 million and pre-tax operating income is capped at $208 million. This table demonstrates the impact of reducing NSP-Minnesota’s rebuttal request.

NSP-Minnesota recorded a current regulatory liability representing the current best estimate of a refund obligation associated with interim rates of approximately $12.5 million as of June 30, 2014.

The next steps in the procedural schedule are expected to be as follows:
Surrebuttal Testimony — Aug. 4, 2014;
Evidentiary Hearing — Aug. 11-18, 2014;
Initial Brief — Sept. 23, 2014;
Reply Brief — Oct. 14, 2014; and
Administrative Law Judge (ALJ) Report — Dec. 22, 2014.

A final MPUC decision is anticipated in March 2015.

NSP-Minnesota – Nuclear Project Prudence Investigation — In 2013, the MPUC initiated an investigation to determine whether the final costs for the Monticello LCM/EPU project were prudent. Monticello LCM/EPU project expenditures were approximately $665 million. Total capitalized costs were approximately $748 million, which includes AFUDC. Project expenditures were initially estimated at approximately $320 million, excluding AFUDC, in 2008 in NSP-Minnesota’s EPU certificate of need (CON) and plant life extension filings.

In October 2013, NSP-Minnesota filed a report to further support the change and prudence of the incurred costs. The filing indicated the increase in costs was primarily attributable to three factors: (1) the original estimate was based on a high level conceptual design and the project scope increased as the actual conditions of the plant were incorporated into the design; (2) implementation difficulties, including the amount of work that occurred in confined and radioactive or electrically sensitive spaces and NSP-Minnesota’s and its vendors’ ability to attract and retain experienced workers; and (3) additional Nuclear Regulatory Commission (NRC) licensing related requests over the five-plus year application process. NSP-Minnesota has provided information that the cost deviation is in line with similar upgrade projects undertaken by other utilities and the project remains economically beneficial to customers. NSP-Minnesota has received all necessary licenses from the NRC for the Monticello EPU, and has begun the process to comply with the license requirements for higher power levels, subject to NRC oversight and review.

On July 2, 2014, the DOC filed testimony and recommended a disallowance of recovery of approximately $71.5 million of project costs, including expenditures and associated AFUDC, on a Minnesota jurisdictional basis. This equates to a total NSP System amount of approximately $94 million.

The DOC’s recommendation indicated that although the combined LCM/EPU project is cost effective, NSP-Minnesota should have done a better job of estimating initial project costs of the investments required to achieve 71 megawatts (MW) of additional capacity (i.e., EPU costs) as opposed to investments required to extend the life of the plant. They asserted that approximately 85 percent of the total $665 million in costs were associated with project components required solely to achieve the EPU.


13


The DOC’s recommendation, NSP-Minnesota’s response and comments of other parties are expected to be considered by an ALJ later this year, who in turn will make a report of recommendations to the MPUC. The results and any recommendations from the conclusion of this prudence proceeding are expected to be considered by the MPUC in NSP-Minnesota’s pending Minnesota 2014 Multi-Year electric rate case.

The next steps in the procedural schedule are expected to be as follows:
Rebuttal Testimony — Aug. 26, 2014;
Surrebuttal Testimony — Sept. 19, 2014;
Hearing — Sept. 25 - Sept. 30, 2014;
Reply Brief — Nov. 21, 2014; and
ALJ Report — Dec. 31, 2014.

A final MPUC decision is anticipated in the first quarter of 2015.

Electric, Purchased Gas and Resource Adjustment Clauses

NSP-Minnesota - Gas Utility Infrastructure Cost (GUIC) Rider — In August 2014, NSP-Minnesota plans to file a GUIC rider with the MPUC for approval to recover the cost of natural gas infrastructure investments in Minnesota to improve safety and reliability. Costs include funding for pipeline assessment and system upgrades in 2015 and beyond, as well as deferred costs from NSP-Minnesota’s existing sewer separation and pipeline integrity management programs. Sewer separation costs stem from the inspection of sewer lines and the redirection of gas pipes in the event their paths are in conflict. NSP-Minnesota is requesting recovery of approximately $14.9 million from Minnesota gas utility customers beginning Jan.1, 2015, including $4.8 million of deferred sewer separation and integrity management costs. An MPUC decision is anticipated by the end of 2014.

Pending Regulatory Proceedings — South Dakota Public Utilities Commission (SDPUC)

South Dakota 2015 Electric Rate Case In June 2014, NSP-Minnesota filed a request with the SDPUC to increase South Dakota electric rates by $15.6 million annually, or 8.0 percent, effective Jan. 1, 2015. The request is based on a 2013 historic test year (HTY) adjusted for certain known and measurable changes for 2014 and 2015, a requested ROE of 10.25 percent, an average rate base of $433.2 million and an equity ratio of 53.86 percent. This request reflects NSP-Minnesota’s proposal to move recovery of approximately $9.0 million for certain Transmission Cost Recovery (TCR) rider and Infrastructure rider projects to base rates.

The major components of the request are as follows:
(Millions of Dollars)
 
Request
Nuclear investments and operating costs
 
$
13.4

Other production, transmission and distribution
 
5.0

Technology improvements
 
2.1

Pension and operating and maintenance (O&M) expenses
 
1.6

Wind generation facilities
 
1.4

Capital structure
 
1.1

Incremental increase to base rates
 
$
24.6

 
 
 
Infrastructure rider to be included in base rates
 
$
(8.4
)
TCR rider to be included in base rates
 
(0.6
)
Net request
 
$
15.6


A procedural schedule is anticipated to be established in the second half of 2014. Final rates are expected to be effective in the first quarter of 2015.


14


NSP-Wisconsin

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

NSP-Wisconsin 2015 Electric Rate Case — In May 2014, NSP-Wisconsin filed a request with the PSCW to increase electric rates by $20.6 million, or 3.2 percent, effective Jan. 1, 2015. The request is for the limited purpose of updating 2015 electric rates to reflect anticipated increases in the production and transmission fixed charges and the fuel and purchased power components of the interchange agreement with NSP-Minnesota. No changes are being requested to the capital structure or the 10.2 percent ROE authorized by the PSCW in the 2014 rate case. As part of an agreement with stakeholders to limit the size and scope of the case, NSP-Wisconsin also agreed to an earnings cap for 2015 only, in which 100 percent of the earnings above the authorized ROE would be refunded to customers.

The major cost components of the requested increase are summarized below:
(Millions of Dollars)
 
Request
Production and transmission fixed charges
 
$
28.1

Fuel and purchased power
 
13.9

Sub-Total
 
$
42.0

 
 
 
NSP-Minnesota transmission depreciation reserve
 
$
(16.2
)
Monticello EPU deferral
 
(5.2
)
Total
 
$
20.6


The next steps in the procedural schedule are expected to be as follows:
Direct Testimony (PSCW staff and intervenors) — Oct. 3, 2014;
Rebuttal Testimony — Oct. 17, 2014;
Surrebuttal Testimony — Oct. 24, 2014; and
Evidentiary Hearing — Oct. 28, 2014.

A final PSCW decision is anticipated by the end of the year with final rates implemented in January 2015.

Pending Regulatory Proceedings — Federal Energy Regulatory Commission (FERC)

Midcontinent Independent System Operator, Inc. (MISO) ROE Complaint — In November 2013, a group of customers filed a complaint at the FERC against MISO transmission owners, including NSP-Minnesota and NSP-Wisconsin. The complaint argues for a reduction in the ROE applicable to transmission formula rates in the MISO region from 12.38 percent to 9.15 percent, a prohibition on capital structures in excess of 50 percent equity, and the removal of ROE adders (including those for regional transmission organization (RTO) membership and being an independent transmission company), effective Nov. 12, 2013.

In January 2014, Xcel Energy filed an answer to the complaint asserting that the 9.15 percent ROE would be unreasonable and that the complainants failed to demonstrate the NSP System equity capital structure was unreasonable. The MISO transmission owners separately answered the complaint, arguing the complainants do not have standing to challenge the MISO Tariff provisions, have not met their burden of proof to demonstrate that the current FERC-approved ROE, capital structure and other incentives are unjust and unreasonable, and the complaint should be dismissed. Other parties filed comments supporting a reduction in the MISO regional ROE, the equity capital structure limitations, and limits on ROE incentives, and supported the proposed effective date. In January 2014, the complainants filed an answer to the MISO transmission owners’ motion to dismiss. The complaint is pending FERC action.

In June 2014, the FERC issued an order in a different ROE proceeding adopting a new ROE methodology for electric utilities. The new ROE methodology requires electric utilities to use a two-step discounted cash flow analysis to estimate cost of equity that incorporates both short-term and long-term growth projections, instead of only short-term growth. The FERC set the issue of the appropriate long-term growth rate for further hearing procedures. The FERC could order settlement judge procedures, and if necessary a hearing, to apply the new methodology to MISO transmission owners. The new FERC ROE methodology is expected to reduce transmission revenue, net of expense, between $5 million and $7 million annually for NSP-Minnesota and NSP-Wisconsin.


15


PSCo

Pending and Recently Concluded Regulatory Proceedings — CPUC

PSCo – Colorado 2014 Electric Rate Case In June 2014, PSCo filed an electric rate case in Colorado with the CPUC requesting an increase in annual revenue of approximately $137.7 million, or 4.89 percent. The request includes the initiation of a CACJA rider as part of the overall 2015 rate case request of approximately $95 million, as well as additional amounts for calendar years 2016 and 2017. The CACJA rider is anticipated to increase revenue recovery by approximately $40 million in 2016 and then decline to approximately $36 million in 2017. PSCo’s objective is to establish a multi-year regulatory plan that provides certainty for PSCo and its customers.

The rate filing is based on a 2015 test year, a requested ROE of 10.35 percent, an electric rate base of $6.39 billion and an equity ratio of 56 percent. As part of the filing, PSCo will transfer approximately $19.9 million from the transmission rider to base rates. This transfer will not impact customer bills. The CACJA rider is projected to recover incremental investment and expenses, based on a comprehensive plan to retire certain coal plants, add pollution control equipment to other existing coal units and add natural gas generation. The CACJA project investment is expected to be completed by 2017.

In July 2014, the CPUC set hearings for early December 2014. A decision as well as implementation of final rates are anticipated in the first quarter of 2015.

PSCo – Manufacturer’s Sales Tax Refund Pursuant to the multi-year settlement agreement with the CPUC, PSCo defers 2012-2014 annual property taxes in excess of $76.7 million. To the extent that PSCo was successful in the manufacturer’s sales tax refund lawsuit against the Colorado Department of Revenue, PSCo was to credit such refunds first against certain legal fees, and then against the unamortized deferred property tax balance at the end of 2014. 

After PSCo’s initial successes in the District Court and Court of Appeals, the Colorado Supreme Court on June 30, 2014 ruled against PSCo’s claim that it was due refunds for the payment of sales taxes on purchases of certain equipment from December 1998 to December 2001.  Under the multi-year settlement agreement, as a result of the adverse ruling, PSCo is required to reduce its 2014 property tax deferral by $10 million, as this amount will not be recovered in electric rates.  This impact is reflected in PSCo’s pending electric rate case before the CPUC.

PSCo – Annual Electric Earnings Test — As part of an annual earnings test, PSCo must share with customers a portion of any annual earnings that exceed PSCo’s authorized ROE threshold of 10 percent for 2012-2014. In April 2014, PSCo filed its 2013 earnings test with the CPUC proposing a refund obligation of $45.7 million to electric customers to be returned between August 2014 and July 2015. This tariff was approved by the CPUC in July 2014 to be effective Aug. 1, 2014. As of June 30, 2014, PSCo has also recognized management’s best estimate of an accrual for the 2014 earnings test.

2012 Pipeline System Integrity Adjustment (PSIA) Report — In April 2013, PSCo filed its 2012 PSIA report, requesting $43.5 million for recovery of expenditures. In February 2014, PSCo, the CPUC Staff and the Office of Consumer Counsel (OCC) agreed to a settlement amount of $43.4 million for recovery of 2012 expenditures, subject to final approval. This includes a one-time disallowance of approximately $0.1 million of O&M expenditures and an agreement not to disallow capital expenditures related to a pipeline replacement project. In July 2014, the ALJ issued a final decision approving the settlement agreement.

Electric, Purchased Gas and Resource Adjustment Clauses

Renewable Energy Credit (REC) Sharing — In 2011, the CPUC approved margin sharing on stand-alone REC transactions at 10 percent to PSCo and 90 percent to customers for 2014. In 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 renewable energy standard adjustment (RESA) regulatory asset balance. PSCo’s credit to the RESA regulatory asset balance was not material for the three months ended June 30, 2014. For the three months ended June 30, 2013, PSCo credited the RESA regulatory asset balance $6.5 million. The cumulative credit to the RESA regulatory asset balance was $104.6 million and $104.5 million at June 30, 2014 and Dec. 31, 2013, respectively. The credits include the customers’ share of REC trading margins and the unspent share of carbon offset funds.


16


The current sharing mechanism will be effective through 2014. In May 2014, PSCo filed with the CPUC to continue this sharing mechanism for 2015 and beyond, but remove the step increase in the sharing allocation of hybrid REC trades on margins in excess of $20 million. In July 2014, the CPUC sent the proceeding to an ALJ. A decision is anticipated later in 2014.

Pending Regulatory Proceedings — FERC

PSCo – Production Formula Rate ROE Complaint — In August 2013, PSCo’s wholesale production customers filed a complaint with the FERC, and requested it reduce the stated ROEs ranging from 10.1 percent through 10.4 percent to 9.04 percent in the PSCo power sales formula rates effective Sept. 1, 2013. In June 2014, PSCo and its wholesale customers reached a confidential settlement in principle to resolve the complaint. The settlement is expected to be filed with the FERC in September 2014. As of June 30, 2014, PSCo has recorded a refund accrual based on the settlement terms.

PSCo Transmission Formula Rate Cases — In April 2012, PSCo filed with the FERC to revise the wholesale transmission formula rates from an HTY formula rate to a forecast transmission formula rate and to establish formula ancillary services rates. PSCo proposed that the formula rates be updated annually to reflect changes in costs, subject to a true-up. The request would increase PSCo’s wholesale transmission and ancillary services revenue by approximately $2.0 million annually. Various transmission customers protested the filing. In June 2012, the FERC issued an order accepting the proposed transmission and ancillary services formula rates, suspending the increase to November 2012, subject to refund, and setting the case for settlement judge or hearing procedures.

In June 2012, several wholesale customers filed a complaint with the FERC seeking to have the transmission formula rate ROE reduced from 10.25 to 9.15 percent effective July 1, 2012. In October 2012, the FERC consolidated this complaint with the April 2012 formula rate change filing.

In December 2013, the FERC approved a partial settlement resolving all issues related to the April 2012 transmission rate filing and June 2012 complaint other than ROE. The settlement is not expected to materially increase 2014 transmission revenues.

In March 2014, the FERC Staff filed testimony supporting an ROE of 8.91 percent for July 2012 to November 2012, and an ROE of 8.70 percent thereafter. In June 2014, PSCo and its transmission customers reached a confidential settlement in principle to resolve the ROE issue in the transmission rate filing and complaint. The settlement is expected to be filed with the FERC in September 2014. As of June 30, 2014, PSCo has recorded a refund accrual based on the settlement terms.

SPS

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

SPS – Texas 2014 Electric Rate Case — In January 2014, SPS filed a retail electric rate case in Texas with each of its Texas municipalities and the PUCT for a net increase in annual revenue of approximately $52.7 million, or 5.8 percent. The net increase reflected a base rate increase, revenue credits transferred from base rates to rate riders or the fuel clause, and resetting the Transmission Cost Recovery Factor (TCRF) to zero when the final base rates become effective. In April 2014, SPS revised its request to a net increase of $48.1 million, based on updated information.

The rate filing is based on a HTY ending June 2013, a requested ROE of 10.40 percent, an electric rate base of approximately $1.27 billion and an equity ratio of 53.89 percent. The requested rate increase reflected an increase in depreciation expense of approximately $16 million.

SPS, intervenors, and other parties have commenced settlement negotiations. A final settlement is anticipated to be filed with the PUCT in the third quarter of 2014. A final decision is anticipated later this year and final rates are expected to be effective retroactive to June 1, 2014.

Electric, Purchased Gas and Resource Adjustment Clauses

TCRF Rider — In November 2013, SPS filed with the PUCT to implement the TCRF for Texas retail customers. The requested increase in revenues was $13 million. The PUCT issued an order allowing the TCRF to go into effect on an interim basis effective Jan. 1, 2014. In July 2014, the PUCT approved a settlement agreement between the parties allowing SPS to recover $4 million annually through the TCRF. As of June 30, 2014, SPS had recorded an accrual for estimated refunds.


17


Recently Concluded Regulatory Proceedings — New Mexico Public Regulation Commission (NMPRC)

SPS – New Mexico 2014 Electric Rate Case — In December 2012, SPS filed an electric rate case in New Mexico with the NMPRC for an increase in annual revenue of approximately $45.9 million effective in 2014. The rate filing was based on a 2014 forecast test year, a requested ROE of 10.65 percent, an electric rate base of $479.8 million and an equity ratio of 53.89 percent.

In September 2013, SPS filed rebuttal testimony, revising its requested rate increase to $32.5 million, based on updated information and an ROE of 10.25 percent. The request reflected a base and fuel increase of $20.9 million, an increase of rider revenue of $12.1 million and a decrease to other of $0.5 million.

In March 2014, the NMPRC approved an overall increase of approximately $33.1 million. The increase reflects a base rate increase of $12.7 million and rider recovery of $18.1 million for renewable energy costs, both based on an ROE of 9.96 percent and an equity ratio of 53.89 percent. Final rates were effective April 5, 2014. In April 2014, the New Mexico Attorney General (NMAG) filed a request for rehearing. The rehearing request was denied by the NMPRC. In June 2014, the NMAG filed an appeal of the NMPRC’s denial to the New Mexico Supreme Court. A decision is expected in 2015.

The following table summarizes the NMPRC’s approval from SPS’ revised request:
(Millions of Dollars)
 
NMPRC Approval
SPS revised request, September 2013
 
$
32.5

Fuel clause adjustment credit — non-renewable energy costs
 
2.3

SPS revised request, fuel adjusted
 
34.8

ROE (9.96 percent)
 
(1.2
)
Rate rider adjustment — renewable energy costs
 
6.0

Base rate reduction for rate rider — renewable energy costs
 
(6.0
)
Other, net
 
(0.5
)
Approved increase, March 2014
 
$
33.1

 
 
 
Means of recovery:
 
 
Base revenue
 
$
12.7

Rider revenue
 
18.1

Fuel clause
 
2.3

 
 
$
33.1


Pending Regulatory Proceedings — FERC

SPS Wholesale Rate Complaints — In April 2012, Golden Spread Electric Cooperative, Inc. (Golden Spread) filed a rate complaint alleging that the base ROE included in the SPS production formula rate of 10.25 percent, and the SPS transmission base formula rate ROE of 10.77 percent, are unjust and unreasonable. In July 2013, Golden Spread filed a second complaint, again asking that the base ROE in the SPS production and transmission formula rates be reduced to 9.15 and 9.65 percent, respectively.

In June 2014, the FERC issued an order in a different ROE proceeding adopting a new ROE methodology for electric utilities. The new ROE methodology requires electric utilities to use a two-step discounted cash flow analysis to estimate cost of equity that incorporates both short-term and long-term growth projections, instead of only short-term growth. The FERC also issued orders consolidating the Golden Spread complaints and setting them for settlement judge procedures and hearings and indicated the parties should apply the new ROE methodology to this proceeding. The effective dates of the refunds are April 20, 2012 and July 19, 2013. The first settlement conference was held in July 2014 and further settlement conferences are anticipated. SPS continues to evaluate the impact of the new FERC ROE methodology. In July 2014, SPS requested rehearing of the June 2014 orders.

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, 2013, 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.


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Purchased Power Agreements (PPAs)

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

The Xcel Energy utility subsidiaries had approximately 3,698 MW and 3,338 MW of capacity under long-term PPAs as of June 30, 2014 and Dec. 31, 2013, 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 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, 2014 and Dec. 31, 2013, 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, 2014
 
Dec. 31, 2013
Guarantees issued and outstanding
 
$
14.6

 
$
19.4

Current exposure under these guarantees
 
0.2

 
0.3

Bonds with indemnity protection
 
32.5

 
32.1


Indemnification Agreements

In connection with the sale of certain Texas electric transmission assets to Sharyland Distribution and Transmission Services, LLC in 2013, SPS agreed to indemnify the purchaser for losses arising out of any breach of the representations, warranties and covenants under the related asset purchase agreement and for losses arising out of certain other matters, including pre-closing liabilities. SPS’ indemnification obligation is capped at $37.1 million, in the aggregate. The indemnification provisions for most representations and warranties expire in December 2014. The remaining representations and warranties, which relate to due organization and transaction authorization, survive indefinitely. As of June 30, 2014 and Dec. 31, 2013, SPS has recorded a $0.4 million liability related to this indemnity.

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).


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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. For the Sediments at the Ashland Site, the ROD preferred remedy is a hybrid remedy involving both dry excavation and wet conventional dredging methodologies (the Hybrid Remedy). The ROD also identifies the possibility of a wet conventional dredging only remedy for the Sediments (the Wet Dredge), contingent upon the completion of a successful Wet Dredge pilot study.

In 2011, the EPA issued special notice letters identifying several entities, including NSP-Wisconsin, as PRPs, for future remediation at the Ashland 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 settlement negotiations with NSP-Wisconsin, 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.

In October 2012, a settlement among the EPA, the Wisconsin Department of Natural Resources, 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 cleanup of the Phase I Project Area of $40 million. Demolition activities occurred at the Ashland site in 2013. The final design for the soil, including excavation and treatment, as well as containment wall remedies was submitted to the EPA in April 2014 and work commenced in May 2014. A preliminary design for the groundwater remedy was also submitted to the EPA in April 2014 and those activities are expected to commence in 2015. Based on these updated designs, the updated cost estimate for the cleanup of the Phase I Project Area is approximately $52 million, of which $12 million has already been spent. The settlement also resolves claims by the federal, state and tribal trustees against NSP-Wisconsin for alleged natural resource damages at the Ashland site, including both the Phase I Project Area and the Sediments. As part of the settlement, NSP-Wisconsin has conveyed approximately 1,390 acres of land to the State of Wisconsin and tribal trustees. Fieldwork to address the Phase I Project Area at the Ashland site began at the end of 2012 and continues.

Negotiations are ongoing between the EPA and NSP-Wisconsin regarding who will pay for or perform the cleanup of the Sediments and what remedy will be implemented at the site to address the Sediments. In August and September 2013, NSP-Wisconsin performed field studies in the Sediments to gather more data about site conditions. The data from that investigation was received and reported to the EPA at the end of 2013. It is NSP-Wisconsin’s view that this data demonstrates the Hybrid Remedy is not safe or feasible to implement. The EPA’s ROD for the Ashland site includes estimates that the cost of the Hybrid Remedy 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. Also, in September 2013, the EPA requested NSP-Wisconsin consider re-submitting another proposal to perform a Wet Dredge pilot study for a portion of the Sediments. NSP-Wisconsin previously submitted a proposal for a Wet Dredge pilot study in 2011. In November 2013, NSP-Wisconsin submitted a revised Wet Dredge pilot study work plan proposal to the EPA. In May 2014, NSP-Wisconsin entered into a final administrative order on consent for the Wet Dredge pilot study with the EPA. Implementation of the pilot is anticipated in late summer or early fall of 2014.

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 is scheduled for April 2015. Negotiations between the EPA, NSP-Wisconsin and several of the other PRPs regarding the PRPs’ fair share of the cleanup costs for the Ashland site are also ongoing.

At June 30, 2014 and Dec. 31, 2013, NSP-Wisconsin had recorded a liability of $113.3 million and $104.6 million, respectively, for the Ashland site based upon potential remediation and design costs together with estimated outside legal and consultant costs; of which $33.4 million and $25.2 million, respectively, was considered a current liability. NSP-Wisconsin’s potential liability, the actual cost of remediation and the time frame over which the amounts may be paid are subject to change. NSP-Wisconsin also continues to work to identify and access state and federal funds to apply to the ultimate remediation cost of the entire site. Unresolved issues or factors that could result in higher or lower NSP-Wisconsin remediation costs for the Ashland site include the cleanup approach implemented for the Sediments, which party implements the cleanup, the timing of when the cleanup is implemented, potential contributions by other PRPs and whether federal or state funding may be directed to help offset remediation costs at the Ashland site.


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

In the 2013 rate case decision, the PSCW recognized the potential magnitude of the future liability for the cleanup at the Ashland site and granted an exception to its existing policy at the request of NSP-Wisconsin. The elements of this exception include: (1) approval to begin recovery of estimated Phase 1 Project costs beginning on Jan. 1, 2013; (2) approval to amortize these estimated costs over a ten-year period; and (3) approval to apply a three percent carrying cost to the unamortized regulatory asset. In the 2014 rate case decision, the PSCW continued the cost recovery treatment established in the 2013 rate case, with respect to the 2013 and 2014 cleanup costs for the Phase I Project Area. The PSCW determined the timing of the cleanup of the Sediments was uncertain and declined NSP-Wisconsin’s request to begin cost recovery for this portion of the cleanup in 2014 rates. However, the PSCW allowed NSP-Wisconsin to increase its 2014 amortization expense related to the cleanup by an additional $1.1 million to offset the need for a rate decrease for the natural gas utility. The cost recovery treatment granted by the PSCW in the 2013 and 2014 rate cases will help mitigate the rate impact to natural gas customers and the risk to NSP-Wisconsin from a longer amortization period.

Environmental Requirements

Water and waste
Federal Clean Water Act (CWA) 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. The final rule is now expected in September 2015. Under the current proposed rule, facilities would need to comply as soon as possible after July 2017 but no later than July 2022. The impact of this rule on Xcel Energy is uncertain at this time.

Federal CWA Section 316 (b) — The federal CWA requires the EPA to regulate cooling water intake structures to assure that these structures reflect the best technology available for minimizing adverse environmental impacts to aquatic species. In 2011, the EPA published the proposed rule that sets standards for minimization of aquatic species impingement, but leaves entrainment reduction requirements at the discretion of the permit writer and the regional EPA office. A final rule was signed by the EPA in May 2014. NSP-Minnesota service territories will be the most impacted by the requirements. The timing of compliance with the requirements will vary from plant-to-plant since the new rules do not have a final compliance deadline. Since some of the compliance requirements depend on site-specific determinations by state regulators, the exact cost is somewhat uncertain. Xcel Energy estimates the most likely cost for compliance is approximately $48 million with the majority needed for compliance in NSP-Minnesota. Xcel Energy anticipates these costs will be fully recoverable in rates.

Federal CWA Waters of the United States Rule — In April 2014, the EPA and the U.S. Army Corps of Engineers issued a proposed rule that significantly expands the types of water bodies regulated under the CWA. If finalized as proposed, this rule could delay the siting of new pipelines, transmission lines and distribution lines, increase project costs and expand permitting and reporting requirements. The ultimate impact of the proposed rule will depend on the specific requirements of the final rule and cannot be determined at this time. A final rule is not anticipated before the first quarter of 2015.

Air
EPA Greenhouse Gas (GHG) Permitting — In 2011, new EPA permitting requirements became effective for GHG emissions of new and modified large stationary sources, which were applicable to the construction of new power plants or power plant modifications that increase emissions above a certain threshold. These rules were upheld by the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit), but in June 2014 the U.S. Supreme Court reversed the EPA’s GHG emission thresholds for this program. The Supreme Court decided the EPA could not adopt GHG thresholds that would require permitting for new and modified large stationary sources. However, the Supreme Court also decided if a new or modified stationary source becomes subject to the permitting requirements by exceeding emission thresholds for other pollutants, then GHG emissions may be evaluated as part of the permitting process. Xcel Energy is unable to determine the cost of compliance with these new EPA requirements as it is not clear whether these requirements will apply to future changes at Xcel Energy’s power plants.


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GHG Emission Standard for Existing Sources — In June 2014, the EPA published its proposed rule on GHG emission standards for existing power plants. Comments are due to the EPA on Oct. 16, 2014 and a final rule is anticipated in June 2015. Following adoption of the final rule, states must develop implementation plans by June 2016, with the possibility of an extension to June 2017 (June 2018 if submitting a joint plan with other states). Among other things, the proposed rule would require that state plans include enforceable measures to ensure emissions from existing power plants in the state achieve the EPA’s state-specific interim (2020-2029) and final (2030 and thereafter) emission performance targets. The plan will likely require additional emission reductions in states in which Xcel Energy operates. It is not possible to evaluate the impact of existing source standards until the EPA promulgates a final rule and states have adopted their applicable state plans.

GHG New Source Performance Standard (NSPS) Proposal — In January 2014, the EPA re-proposed a GHG NSPS for newly constructed power plants which would set performance standards (maximum carbon dioxide emission rates) for coal- and natural gas-fired power plants. For coal power plants, the NSPS requires an emissions level equivalent to partial carbon capture and storage (CCS) technology; for gas-fired power plants, the NSPS reflects emissions levels from combined cycle technology with no CCS. The EPA continues to propose that the NSPS not apply to modified or reconstructed existing power plants. In addition, installation of control equipment on existing plants would not constitute a “modification” to those plants under the NSPS program. It is not possible to evaluate the impact of the re-proposed NSPS until its final requirements are known.

GHG NSPS for Modified and Reconstructed Power Plants — In June 2014, the EPA published a proposed NSPS that would apply to GHG emissions from power plants that are modified or reconstructed. Comments are due to the EPA on Oct. 16, 2014 and a final rule is anticipated in June 2015. A modification is a change to an existing source that increases the maximum achievable hourly rate of emissions. A reconstruction involves the replacement of components at a unit to the extent that the capital cost of the new components exceeds 50 percent of the capital cost of an entirely new comparable unit. The proposed standards are not based on and would not require installation of CCS technology. Instead, the proposed standard for coal-fired power plants would require a combination of best operating practices and equipment upgrades. The proposal for gas-fired power plants would require emissions standards based on efficient combined cycle technology. It is not possible to evaluate the impact of these proposed standards until the final requirements are known. In addition, it is not clear whether these requirements, once adopted, would apply to future changes at Xcel Energy’s power plants.

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 nitrous oxide (NOx) from utilities in the eastern half of the United States. For Xcel Energy, the rule would apply in Minnesota, Wisconsin and Texas. The CSAPR would set more stringent requirements than the proposed Clean Air Transport Rule and require plants in Texas to reduce their SO2 and annual NOx emissions. The rule would also create an emissions trading program.

In August 2012, the D.C. Circuit vacated the CSAPR and remanded it back to the EPA. The D.C. Circuit stated the EPA must continue administering the Clean Air Interstate Rule (CAIR) pending adoption of a valid replacement. In April 2014, the U.S. Supreme Court reversed and remanded the case to the D.C. Circuit. The Supreme Court held that the EPA’s rule design did not violate the Clean Air Act (CAA) and that states had received adequate opportunity to develop their own plans. Because the D.C. Circuit overturned the CSAPR on two over-arching issues, there are many other issues the D.C. Circuit did not rule on that will now need to be considered on remand. In June 2014, the EPA filed a motion with the D.C. Circuit asking it to lift the stay of the CSAPR. The EPA requested CSAPR’s 2012 compliance obligations be imposed starting in January 2015. The D.C. Circuit has not yet ruled on the motion to lift the stay. Because it is not yet known how the litigation over the remaining issues will be resolved or how the D.C. Circuit will rule on the motion to lift the stay, it is not yet known what requirements may be imposed in the future, or their timing.

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 currently 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 2013 and plans to continue to purchase allowances in 2014 to comply with the CAIR. In the SPS region, installation of low-NOx combustion control technology was completed in 2012 on Tolk Unit 1 and in 2014 on Tolk Unit 2. These installations will reduce or eliminate SPS’ need to purchase NOx emission allowances. SPS had sufficient SO2 allowances to comply with the CAIR in 2013 and has sufficient allowances through 2015. At June 30, 2014, 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.


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Regional Haze Rules — The regional haze program is designed to address widespread, regionally homogeneous haze that results from emissions from a multitude of sources. In 2005, the EPA amended the best available retrofit technology (BART) requirements of its regional haze rules, which require the installation and operation of emission controls for industrial facilities emitting air pollutants that reduce visibility in certain national parks and wilderness areas. In their first regional haze state implementation plan (SIP), Colorado, Minnesota and Texas identified the Xcel Energy facilities that will have to reduce SO2, NOx and PM emissions under BART and set emissions limits for those facilities.

PSCo
In 2011, the Colorado Air Quality Control Commission approved a SIP (the Colorado SIP) that included the CACJA emission reduction plan as satisfying regional haze requirements for the facilities included in the CACJA plan. In addition, the Colorado SIP included a BART determination for Comanche Units 1 and 2. The EPA approved the Colorado SIP in 2012. Emission controls at the Hayden and Pawnee plants are projected to cost $359.7 million and are expected to be installed between 2014 and 2017. PSCo anticipates these costs will be fully recoverable in rates.

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 it will challenge the BART determination made for Comanche Units 1 and 2. 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 intervened in the case. The 10th Circuit is anticipated to hear argument in January 2015, following completion of the briefs in November 2014.

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 the Colorado BART rule is inadequate to satisfy the 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 a SIP (the Minnesota SIP) and submitted it to the EPA for approval. The MPCA’s source-specific BART limits for Sherco Units 1 and 2 require combustion controls for NOx and scrubber upgrades for SO2. The MPCA concluded SCRs should not be required because the minor visibility benefits derived from SCRs do not outweigh the substantial costs. The combustion controls have been installed and the scrubber upgrades, to be completed by January 2015, are underway. These emission controls are projected to cost approximately $50 million, of which $44.4 million has already been spent. NSP-Minnesota anticipates these costs will be fully recoverable in rates.

After the CSAPR was adopted in 2011, the MPCA supplemented its Minnesota SIP, determining that CSAPR meets BART requirements, but also implementing its source-specific BART determination for Sherco Units 1 and 2 from the 2009 Minnesota SIP. In June 2012, 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 (Eighth Circuit). NSP-Minnesota and other regulated parties were denied intervention. In June 2013, the Eighth Circuit ordered this case to be held in abeyance until the U.S. Supreme Court decided the CSAPR case. It is not yet known how the U.S. Supreme Court’s April 2014 decision on the CSAPR, or the EPA’s June 2014 motion requesting the D.C. Circuit lift its stay of the CSAPR, will impact the Eighth Circuit’s proceedings on the Minnesota SIP. Since the Court’s ruling on CSAPR, the parties to this case have filed motions that continue to hold the case in abeyance while they determine how to proceed. The Eighth Circuit granted these motions and the case is in abeyance until at least Aug. 15, 2014. If this litigation ultimately results in further EPA proceedings concerning the Minnesota SIP, such proceedings may consider whether SCRs should be required for Sherco Units 1 and 2.

SPS
Harrington Units 1 and 2 are potentially subject to BART. Texas 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 U.S. Supreme Court’s April 2014 decision on the CSAPR, or the EPA’s June 2014 motion requesting the D.C. Circuit lift its stay of the CSAPR, may impact the EPA’s approval of the BART requirements in the Texas SIP.


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In May 2014, the EPA issued a request for information under the CAA related to SO2 control equipment at Tolk Units 1 and 2. The EPA stated it is conducting an analysis of the cost and feasibility of SO2 controls on certain sources, including the Tolk facility, as part of its review of the Texas SIP. The EPA has preliminarily identified Tolk as a contributor to haze in the Wichita Mountains Wildlife Refuge in Oklahoma, and is planning further analysis of SO2 control options. The EPA plans to make a proposal in November 2014 that could include SO2 emission controls at Tolk and anticipates issuing a final decision in August 2015. The costs and timing of potential additional SO2 controls at Tolk are dependent on the EPA’s proposal and final decision, neither of which is yet known.

Reasonably Attributable Visibility Impairment (RAVI) RAVI is intended to address observable impairment from a specific source such as distinct, identifiable plumes from a source’s stack to a national park. 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 whether there is RAVI-type impairment in these parks and examine which sources may cause or contribute to any RAVI impact that is identified. After studying the national parks and evaluating multiple sources, if the EPA finds that Sherco Units 1 and 2 cause or contribute to RAVI in the national parks, the EPA would then evaluate whether the level of controls required by the MPCA is appropriate. The EPA has stated it plans to issue a separate notice on the issue of BART for Sherco Units 1 and 2 under the RAVI program.

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 the EPA has failed to perform a nondiscretionary duty to determine BART for Sherco Units 1 and 2 under the RAVI program. The EPA filed an answer denying the allegations. The District Court denied NSP-Minnesota’s motion to intervene in July 2013. NSP-Minnesota appealed this decision to the Eighth Circuit, which on July 23, 2014, reversed the District Court and found that NSP-Minnesota has standing and a right to intervene.

In June 2014, the EPA and the plaintiffs lodged a consent decree with the District Court. The consent decree recites it will be subject to public comment. The EPA will then evaluate comments and determine whether to enter the consent decree with the District Court. The consent decree establishes a schedule whereby the EPA would issue a proposal on Feb. 27, 2015, determining whether visibility impairment in the national parks is reasonably attributable to Sherco Units 1 and 2. If the EPA determines that it is, the consent decree requires the EPA to make a final RAVI BART determination for these units by Aug. 31, 2015. If the EPA determines that it is not, the EPA would not determine BART for Sherco Units 1 and 2. NSP-Minnesota will contest the proposed consent decree and object to its entry given NSP-Minnesota’s right to intervene in the litigation and thus participate in the negotiation of any purported settlement of the case.

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.


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Employment, Tort and Commercial Litigation

Merricourt Wind Project Litigation — In April 2011, NSP-Minnesota terminated its agreements with enXco Development Corporation (enXco) for the development of a 150 MW wind project in southeastern North Dakota. NSP-Minnesota’s decision to terminate the agreements was based in large part on the adverse impact this project could have on endangered or threatened species protected by federal law and the uncertainty in cost and timing in mitigating this impact. NSP-Minnesota also terminated the agreements due to enXco’s nonperformance of certain other conditions, including failure to obtain a Certificate of Site Compatibility and the failure to close on the contracts by an agreed upon date of March 31, 2011. NSP-Minnesota recorded a $101 million deposit in the first quarter of 2011, which was collected in April 2011. In May 2011, NSP-Minnesota filed a declaratory judgment action in the U.S. District Court in Minnesota to obtain a determination that it acted properly in terminating the agreements. enXco also filed a separate lawsuit in the same court seeking approximately $240 million for an alleged breach of contract. NSP-Minnesota believes enXco’s lawsuit is without merit. In October 2012, NSP-Minnesota filed a motion for summary judgment. In April 2013, the U.S. District Court granted NSP-Minnesota’s motion and entered judgment in its favor. In April 2013, enXco filed a notice of appeal to the Eighth Circuit. In July 2014, the Eighth Circuit issued a decision that affirmed the U.S. District Court’s dismissal of the lawsuit filed by enXco. It is uncertain at this time whether enXco will challenge this decision. 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, including a pending appeal by SPS in the Fifth Circuit Court of Appeals. SPS believes the likelihood of loss in these lawsuits and proceedings is remote based primarily on existing case law and while it is not possible to estimate the amount or range of reasonably possible loss in the event of an adverse outcome, SPS believes such loss would not be material based upon its belief that it would be permitted to recover such costs, if needed, through its various fuel clause mechanisms. No accrual has been recorded for this matter.

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


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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.

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

A hearing in this case was held before a FERC ALJ and concluded in October 2013. On March 28, 2014, the FERC ALJ issued an initial decision which rejected all of the City of Seattle’s claims against PSCo and other respondents. With respect to the period Jan. 1, 2000 through Dec. 24, 2000, the FERC ALJ rejected the City of Seattle’s assertion that any of the sales made to the City of Seattle resulted in an excessive burden to the City of Seattle, the applicable legal standard for the City of Seattle’s challenges during this period. With respect to the period Dec. 25, 2000 through June 20, 2001, the FERC ALJ concluded that the City of Seattle had failed to establish a causal link between any contracts and any claimed unlawful market activity, the standard required by the FERC in its remand order. The City of Seattle may contest the FERC ALJ’s initial decision by filing a brief on exceptions to the FERC.

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

Biomass Fuel Handling Reimbursement — NSP-Minnesota has a PPA through which it procures energy from Fibrominn, LLC (Fibrominn). Under this agreement, NSP-Minnesota is charged for certain costs of transporting biomass fuels that are delivered to Fibrominn’s generation facility.  Fibrominn has demanded additional cost reimbursement for certain transportation costs incurred since 2007, as well as reimbursement for similar costs in future periods. Fibrominn claims that it is entitled to reimbursement from NSP-Minnesota for past transportation costs of approximately $20 million. NSP-Minnesota has evaluated Fibrominn’s claim and based on the terms of the PPA with Fibrominn and its current understanding of the facts, NSP-Minnesota disputes the validity of Fibrominn’s claim, on the ground that, among other things, it seeks to impose contractual obligations on NSP-Minnesota that are neither supported by the terms nor the intent of the PPA. NSP-Minnesota has concluded that a loss is reasonably possible with respect to this matter; however, given the surrounding uncertainties, NSP-Minnesota is currently unable to determine the amount of reasonably possible loss. If a loss were sustained, NSP-Minnesota would attempt to recover these fuel-related costs in rates. 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 DOE’s 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.


26


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. In January 2014, the United States proposed, and NSP-Minnesota accepted, an extension to the settlement agreement which will allow NSP-Minnesota to recover spent fuel storage costs through 2016. The extension does not address costs for used fuel storage after 2016; such costs could be the subject of future litigation. NSP-Minnesota has received a total of $181.9 million of settlement proceeds as of June 30, 2014. NSP-Minnesota’s next claim submission, in the amount of $33.6 million, was filed May 15, 2014, for costs incurred in 2013. The DOE has until Sept. 1, 2014 to accept or deny the claim, in whole or in part. Amounts received from the installments, except for approved reductions such as legal costs, will be subsequently returned to customers through a reduction of future rate increases or credited through another regulatory mechanism.

7.
Borrowings and Other Financing Instruments

Short-Term Borrowings

Money Pool  Xcel Energy Inc. and its utility subsidiaries have established a money pool arrangement that allows for short-term investments in and borrowings between the utility subsidiaries. NSP-Wisconsin does not participate in the money pool. Xcel Energy Inc. may make investments in the utility subsidiaries at market-based interest rates; however, the money pool arrangement does not allow the utility subsidiaries to make investments in Xcel Energy Inc. The money pool balances are eliminated in consolidation.

Commercial Paper — Xcel Energy Inc. and its utility subsidiaries meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under their credit facilities. Commercial paper outstanding for Xcel Energy was as follows:
(Amounts in Millions, Except Interest Rates)
 
Three Months Ended  
 June 30, 2014
 
Twelve Months Ended  
 Dec. 31, 2013
Borrowing limit
 
$
2,450

 
$
2,450

Amount outstanding at period end
 
778

 
759

Average amount outstanding
 
910

 
481

Maximum amount outstanding
 
1,186

 
1,160

Weighted average interest rate, computed on a daily basis
 
0.32
%
 
0.31
%
Weighted average interest rate at period end
 
0.35

 
0.25


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, 2014 and Dec. 31, 2013, there were $71.4 million and $47.8 million of letters of credit outstanding, respectively, under the credit facilities. The contract amounts of these letters of credit approximate their fair value and are subject to fees.

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, 2014, 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

 
$
384.0

 
$
416.0

PSCo
 
700.0

 
263.3

 
436.7

NSP-Minnesota
 
500.0

 
50.9

 
449.1

SPS
 
300.0

 
140.0

 
160.0

NSP-Wisconsin
 
150.0

 
11.0

 
139.0

Total
 
$
2,450.0

 
$
849.2

 
$
1,600.8

(a) 
These credit facilities expire in July 2017.
(b) 
Includes outstanding commercial paper and letters of credit.


27


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, 2014 and Dec. 31, 2013.

During the second quarter of 2014, Xcel Energy began working with its bank group to amend and extend the existing revolving credit agreements for Xcel Energy Inc. and each of the regulated subsidiaries. Xcel Energy expects to finalize these agreements during the third quarter of 2014.

Long-Term Borrowings and Other Financing Instruments

During the six months ended June 30, 2014, Xcel Energy Inc. and its utility subsidiaries completed the following bond issuances:

In March 2014, PSCo issued $300 million of 4.30 percent first mortgage bonds due March 15, 2044;
In May 2014, NSP-Minnesota issued $300 million of 4.125 percent first mortgage bonds due May 15, 2044;
In June 2014, SPS issued $150 million of 3.30 percent first mortgage bonds due June 15, 2024; and
In June 2014, NSP-Wisconsin issued $100 million of 3.30 percent first mortgage bonds due June 15, 2024.

In connection with SPS’ issuance of $150 million of 3.30 percent first mortgage bonds due June 15, 2024, SPS issued $250 million of collateral 8.75 percent first mortgage bonds due Dec. 1, 2018 to the trustee under its senior unsecured indenture in order to secure its previously issued Series G Senior Notes, 8.75 percent due Dec. 1, 2018, equally and ratably with SPS’ first mortgage bonds as required by the terms of such Series G Senior Notes.

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 (ATM) program. During the six months ended June 30, 2014, Xcel Energy Inc. issued approximately 5.7 million shares of common stock through this program and received cash proceeds of $172.7 million net of $1.9 million in fees and commissions. During the year ended Dec. 31, 2013, Xcel Energy Inc. issued approximately 7.7 million shares of common stock through this program and received cash proceeds of $222.7 million net of $2.7 million in fees and commissions. As a result, Xcel Energy has completed its ATM program. 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.
 
8.
Fair Value of Financial Assets and Liabilities

Fair Value Measurements

The accounting guidance for fair value measurements and disclosures provides a single definition of fair value and requires certain disclosures about assets and liabilities measured at fair value. A hierarchical framework for disclosing the observability of the inputs utilized in measuring assets and liabilities at fair value is established by this guidance. The three levels in the hierarchy are as follows:

Level 1 Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. The types of assets and liabilities included in Level 1 are highly liquid and actively traded instruments with quoted prices.

Level 2 Pricing inputs are other than quoted prices in active markets, but are either directly or indirectly observable as of the reporting date. The types of assets and liabilities included in Level 2 are typically either comparable to actively traded securities or contracts, or priced with models using highly observable inputs.

Level 3 Significant inputs to pricing have little or no observability as of the reporting date. The types of assets and liabilities included in Level 3 are those valued with models requiring significant management judgment or estimation.

Specific valuation methods include the following:

Cash equivalents The fair values of cash equivalents are generally based on cost plus accrued interest; money market funds are measured using quoted net asset values.


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Investments in equity securities and other funds Equity securities are valued using quoted prices in active markets. The fair values for commingled funds, international equity funds, private equity investments and real estate investments are measured using net asset values, which take into consideration the value of underlying fund investments, as well as the other accrued assets and liabilities of a fund, in order to determine a per-share market value. The investments in commingled funds and international equity funds may be redeemed for net asset value with proper notice. Proper notice varies by fund and can range from daily with one or two days notice to annually with 90 days notice. Private equity investments require approval of the fund for any unscheduled redemption, and such redemptions may be approved or denied by the fund at its sole discretion. Unscheduled distributions from real estate investments may be redeemed with proper notice, which is typically quarterly with 45-90 days notice; however, withdrawals from real estate investments may be delayed or discounted as a result of fund illiquidity. Based on Xcel Energy’s evaluation of its redemption rights, 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.

Electric commodity derivatives held by NSP-Minnesota include transmission congestion instruments purchased from MISO, PJM Interconnection, LLC (PJM), Electric Reliability Council of Texas (ERCOT), Southwest Power Pool, Inc. (SPP) and New York Independent System Operator, generally referred to as financial transmission rights (FTRs). Electric commodity derivatives held by SPS include FTRs purchased from SPP. FTRs purchased from a RTO are financial instruments that entitle or obligate the holder to monthly revenues or charges based on transmission congestion across a given transmission path. The value of an FTR is derived from, and designed to offset, the cost of energy congestion, which is caused by 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. The valuation process for FTRs utilizes complex iterative modeling to predict the impacts of forecasted changes in these drivers of transmission system congestion on the historical pricing of FTR purchases.

If forecasted costs of electric transmission congestion increase or decrease for a given FTR path, the value of that particular FTR instrument will likewise increase or decrease. Given the limited observability of management’s forecasts for several of the inputs to this complex valuation model – 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 and purchased energy cost recovery mechanisms as applicable in each jurisdiction, and therefore changes in the fair value of the yet to be settled portions of most FTRs are deferred as a regulatory asset or liability. Given this regulatory treatment and the limited magnitude of FTRs relative to the electric utility operations of NSP-Minnesota and SPS, the numerous unobservable quantitative inputs to the complex model used for valuation of FTRs are insignificant to the consolidated financial statements of Xcel Energy.

Non-Derivative Instruments Fair Value Measurements

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 PI nuclear generating plants. The fund contains cash equivalents, debt securities, equity securities and other investments – all classified as available-for-sale. NSP-Minnesota plans to reinvest matured securities until decommissioning begins. NSP-Minnesota uses the MPUC approved asset allocation for the escrow and investment targets by asset class for both the escrow and qualified trust.


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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 $295.7 million and $240.3 million at June 30, 2014 and Dec. 31, 2013, respectively, and unrealized losses and amounts recorded as other-than-temporary impairments were $39.3 million and $58.5 million at June 30, 2014 and Dec. 31, 2013, respectively.

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, 2014 and Dec. 31, 2013:
 
 
June 30, 2014
 
 
 
 
Fair Value
 
 
(Thousands of Dollars)
 
Cost
 
Level 1
 
Level 2
 
Level 3
 
Total
Nuclear decommissioning fund (a)
 
 
 
 
 
 
 
 
 
 
Cash equivalents
 
$
26,344

 
$
26,344

 
$

 
$

 
$
26,344

Commingled funds
 
469,692

 

 
483,482

 

 
483,482

International equity funds
 
78,812

 

 
87,748

 

 
87,748

Private equity investments
 
63,096

 

 

 
81,123

 
81,123

Real estate
 
49,421

 

 

 
65,658

 
65,658

Debt securities:
 


 


 


 


 


Government securities
 
34,393

 

 
30,545

 

 
30,545

U.S. corporate bonds
 
80,647

 

 
84,230

 

 
84,230

International corporate bonds
 
15,919

 

 
16,432

 

 
16,432

Municipal bonds
 
225,508

 

 
228,506

 

 
228,506

Asset-backed securities
 
9,218

 

 
9,334

 

 
9,334

Mortgage-backed securities
 
24,097

 

 
24,250

 

 
24,250

Equity securities:
 


 


 


 


 


Common stock
 
376,214

 
572,065

 

 

 
572,065

Total
 
$
1,453,361

 
$
598,409

 
$
964,527

 
$
146,781

 
$
1,709,717

(a) 
Reported in nuclear decommissioning fund and other investments on the consolidated balance sheet, which also includes $85.5 million of equity investments in unconsolidated subsidiaries and $43.4 million of miscellaneous investments.
 
 
Dec. 31, 2013
 
 
 
 
Fair Value
 
 
(Thousands of Dollars)
 
Cost
 
Level 1
 
Level 2
 
Level 3
 
Total
Nuclear decommissioning fund (a)
 
 
 
 
 
 
 
 
 
 
Cash equivalents
 
$
33,281

 
$
33,281

 
$

 
$

 
$
33,281

Commingled funds
 
457,986

 

 
452,227

 

 
452,227

International equity funds
 
78,812

 

 
81,671

 

 
81,671

Private equity investments
 
52,143

 

 

 
62,696

 
62,696

Real estate
 
45,564

 

 

 
57,368

 
57,368

Debt securities:
 
 
 
 
 
 
 
 
 
 
Government securities
 
34,304

 

 
27,628

 

 
27,628

U.S. corporate bonds
 
80,275

 

 
83,538

 

 
83,538

International corporate bonds
 
15,025

 

 
15,358

 

 
15,358

Municipal bonds
 
241,112

 

 
232,016

 

 
232,016

Equity securities:
 


 


 


 


 


Common stock
 
406,695

 
581,243