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EX-31.02 - EXHIBIT 31.02 - XCEL ENERGY INCxcelex3102q22015.htm
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EX-99.01 - EXHIBIT 99.01 - XCEL ENERGY INCxcelex9901q22015.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, 2015
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 27, 2015
Common Stock, $2.50 par value
 
507,211,342 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).



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
 
2015
 
2014
 
2015
 
2014
Operating revenues
 
 
 
 
 
 
 
Electric
$
2,213,460

 
$
2,297,638

 
$
4,438,323

 
$
4,599,348

Natural gas
284,131

 
369,127

 
1,000,127

 
1,248,815

Other
17,543

 
18,331

 
38,903

 
39,537

Total operating revenues
2,515,134

 
2,685,096

 
5,477,353

 
5,887,700

 
 
 
 
 
 
 
 
Operating expenses
 
 
 
 
 
 
 
Electric fuel and purchased power
904,705

 
1,041,322

 
1,854,837

 
2,108,643

Cost of natural gas sold and transported
126,667

 
210,901

 
599,038

 
834,729

Cost of sales — other
8,164

 
7,642

 
18,213

 
16,771

Operating and maintenance expenses
594,279

 
585,604

 
1,180,109

 
1,145,747

Conservation and demand side management program expenses
54,141

 
70,834

 
107,946

 
148,380

Depreciation and amortization
274,602

 
255,307

 
547,700

 
501,250

Taxes (other than income taxes)
129,731

 
116,278

 
266,357

 
240,980

Loss on Monticello life cycle management/extended power uprate project

 

 
129,463

 

Total operating expenses
2,092,289

 
2,287,888

 
4,703,663

 
4,996,500

 
 
 
 
 
 
 
 
Operating income
422,845

 
397,208

 
773,690

 
891,200

 
 
 
 
 
 
 
 
Other income, net
961

 
82

 
4,122

 
3,283

Equity earnings of unconsolidated subsidiaries
8,422

 
7,811

 
16,198

 
15,249

Allowance for funds used during construction — equity
12,641

 
23,608

 
25,301

 
45,515

 
 
 
 
 
 
 
 
Interest charges and financing costs
 
 
 
 
 
 
 
Interest charges — includes other financing costs of $5,861,
$5,614, $11,559 and $11,406, respectively
144,222

 
139,400

 
289,162

 
278,494

Allowance for funds used during construction — debt
(6,165
)
 
(10,113
)
 
(12,309
)
 
(19,661
)
Total interest charges and financing costs
138,057

 
129,287

 
276,853

 
258,833

 
 
 
 
 
 
 
 
Income before income taxes
306,812

 
299,422

 
542,458

 
696,414

Income taxes
109,881

 
104,258

 
193,461

 
240,029

Net income
$
196,931

 
$
195,164

 
$
348,997

 
$
456,385

 
 
 
 
 
 
 
 
Weighted average common shares outstanding:
 
 
 
 
 
 
 
Basic
507,707

 
503,272

 
507,359

 
501,408

Diluted
508,074

 
503,456

 
507,747

 
501,612

 
 
 
 
 
 
 
 
Earnings per average common share:
 
 
 
 
 
 
 
Basic
$
0.39

 
$
0.39

 
$
0.69

 
$
0.91

Diluted
0.39

 
0.39

 
0.69

 
0.91

 
 
 
 
 
 
 
 
Cash dividends declared per common share
$
0.32

 
$
0.30

 
$
0.64

 
$
0.60

 
 
 
 
 
 
 
 
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
 
2015
 
2014
 
2015
 
2014
Net income
$
196,931

 
$
195,164

 
$
348,997

 
$
456,385

 
 
 
 
 
 
 
 
Other comprehensive income
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Pension and retiree medical benefits:
 
 
 
 
 
 
 
Amortization of losses included in net periodic benefit cost,
net of tax of $561, $550, $1,130 and $1,099, respectively
883

 
864

 
1,759

 
1,728

 
 
 
 
 
 
 
 
Derivative instruments:
 
 
 
 
 
 
 
Net fair value increase, net of tax of $11, $9, $4 and $6, respectively
18

 
16

 
7

 
8

Reclassification of losses to net income, net of tax of
   $382, $365, $764 and $722, respectively
600

 
574

 
1,185

 
1,135

 
618

 
590

 
1,192

 
1,143

Marketable securities:


 
 
 
 
 
 
Net fair value increase, net of tax of $1, $0, $1 and $24, respectively
1

 

 
2

 
38

 
 
 
 
 
 
 
 
Other comprehensive income
1,502

 
1,454

 
2,953

 
2,909

Comprehensive income
$
198,433

 
$
196,618

 
$
351,950

 
$
459,294

 
 
 
 
 
 
 
 
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
 
2015
 
2014
Operating activities
 
 
 
Net income
$
348,997

 
$
456,385

Adjustments to reconcile net income to cash provided by operating activities:
 
 
 
Depreciation and amortization
556,420

 
509,914

Conservation and demand side management program amortization
2,901

 
3,131

Nuclear fuel amortization
49,454

 
60,466

Deferred income taxes
191,164

 
236,479

Amortization of investment tax credits
(2,768
)
 
(2,886
)
Allowance for equity funds used during construction
(25,301
)
 
(45,515
)
Equity earnings of unconsolidated subsidiaries
(16,198
)
 
(15,249
)
Dividends from unconsolidated subsidiaries
19,754

 
18,114

Share-based compensation expense
21,420

 
10,990

Loss on Monticello life cycle management/extended power uprate project
129,463

 

Net realized and unrealized hedging and derivative transactions
13,450

 
(2,403
)
Changes in operating assets and liabilities:
 
 
 
Accounts receivable
150,283

 
1,406

Accrued unbilled revenues
145,781

 
77,557

Inventories
64,561

 
75,268

Other current assets
69,080

 
(32,157
)
Accounts payable
(132,032
)
 
(147,734
)
Net regulatory assets and liabilities
129,595

 
63,675

Other current liabilities
(92,108
)
 
(129,981
)
Pension and other employee benefit obligations
(78,681
)
 
(115,455
)
Change in other noncurrent assets
684

 
47,855

Change in other noncurrent liabilities
(36,874
)
 
(30,349
)
Net cash provided by operating activities
1,509,045

 
1,039,511

 
 
 
 
Investing activities
 
 
 
Utility capital/construction expenditures
(1,477,959
)
 
(1,575,748
)
Proceeds from insurance recoveries
27,237

 
6,000

Allowance for equity funds used during construction
25,301

 
45,515

Purchases of investments in external decommissioning fund
(640,100
)
 
(404,780
)
Proceeds from the sale of investments in external decommissioning fund
636,669

 
401,488

Investment in WYCO Development LLC
(764
)
 
(2,132
)
Other, net
(1,407
)
 
(1,568
)
Net cash used in investing activities
(1,431,023
)
 
(1,531,225
)
 
 
 
 
Financing activities
 
 
 
(Repayments of) proceeds from short-term borrowings, net
(568,500
)
 
18,800

Proceeds from issuance of long-term debt
841,534

 
838,582

Repayments of long-term debt
(454
)
 
(275,484
)
Proceeds from issuance of common stock
3,409

 
176,573

Dividends paid
(298,022
)
 
(274,361
)
Net cash (used in) provided by financing activities
(22,033
)
 
484,110

 
 
 
 
Net change in cash and cash equivalents
55,989

 
(7,604
)
Cash and cash equivalents at beginning of period
79,608

 
107,144

Cash and cash equivalents at end of period
$
135,597

 
$
99,540

 
 
 
 
Supplemental disclosure of cash flow information:
 
 
 
Cash paid for interest (net of amounts capitalized)
$
(266,840
)
 
$
(251,461
)
Cash received (paid) for income taxes, net
58,598

 
(4,704
)
 
 
 
 
Supplemental disclosure of non-cash investing and financing transactions:
 
 
 
Property, plant and equipment additions in accounts payable
$
206,540

 
$
305,447

Issuance of common stock for reinvested dividends and 401(k) plans
30,498

 
29,272

 
 
 
 
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, 2015
 
Dec. 31, 2014
Assets
 
 
 
Current assets
 
 
 
Cash and cash equivalents
$
135,597

 
$
79,608

Accounts receivable, net
676,223

 
826,506

Accrued unbilled revenues
582,711

 
728,492

Inventories
532,703

 
597,183

Regulatory assets
364,746

 
444,058

Derivative instruments
63,603

 
85,723

Deferred income taxes
429,860

 
246,210

Prepaid taxes
121,705

 
185,488

Prepayments and other
141,774

 
171,112

Total current assets
3,048,922

 
3,364,380

 
 
 
 
Property, plant and equipment, net
29,350,364

 
28,756,916

 
 
 
 
Other assets
 
 
 
Nuclear decommissioning fund and other investments
1,880,153

 
1,832,640

Regulatory assets
2,759,892

 
2,774,216

Derivative instruments
53,306

 
53,775

Other
176,172

 
175,957

Total other assets
4,869,523

 
4,836,588

Total assets
$
37,268,809

 
$
36,957,884

 
 
 
 
Liabilities and Equity
 
 
 
Current liabilities
 
 
 
Current portion of long-term debt
$
707,356

 
$
257,726

Short-term debt
451,000

 
1,019,500

Accounts payable
830,278

 
1,173,006

Regulatory liabilities
418,618

 
410,729

Taxes accrued
280,838

 
396,615

Accrued interest
160,146

 
158,536

Dividends payable
162,224

 
151,720

Derivative instruments
26,845

 
21,632

Other
499,946

 
475,119

Total current liabilities
3,537,251

 
4,064,583

 
 
 
 
Deferred credits and other liabilities
 
 
 
Deferred income taxes
6,249,511

 
5,852,988

Deferred investment tax credits
70,928

 
73,696

Regulatory liabilities
1,176,806

 
1,163,429

Asset retirement obligations
2,517,668

 
2,446,631

Derivative instruments
171,691

 
183,936

Customer advances
241,546

 
256,945

Pension and employee benefit obligations
858,450

 
936,907

Other
279,766

 
264,653

Total deferred credits and other liabilities
11,566,366

 
11,179,185

 
 
 
 
Commitments and contingencies


 


Capitalization
 
 
 
Long-term debt
11,896,126

 
11,499,634

Common stock — 1,000,000,000 shares authorized of $2.50 par value; 506,959,395 and
505,733,267 shares outstanding at June 30, 2015 and Dec. 31, 2014, respectively
1,267,398

 
1,264,333

Additional paid in capital
5,863,209

 
5,837,330

Retained earnings
3,243,645

 
3,220,958

Accumulated other comprehensive loss
(105,186
)
 
(108,139
)
Total common stockholders’ equity
10,269,066

 
10,214,482

Total liabilities and equity
$
37,268,809

 
$
36,957,884

 
 
 
 
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, 2015 and 2014
 
 
 
 
 
 
 
 
 
 
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

 
 
 
 
 
 
 
 
 
 
 
 
Balance at March 31, 2015
506,664

 
$
1,266,659

 
$
5,844,995

 
$
3,209,904

 
$
(106,688
)
 
$
10,214,870

Net income


 


 


 
196,931

 


 
196,931

Other comprehensive income


 


 


 


 
1,502

 
1,502

Dividends declared on common stock


 


 


 
(163,190
)
 


 
(163,190
)
Issuances of common stock
295

 
739

 
9,316

 


 


 
10,055

Share-based compensation


 


 
8,898

 


 


 
8,898

Balance at June 30, 2015
506,959

 
$
1,267,398

 
$
5,863,209

 
$
3,243,645

 
$
(105,186
)
 
$
10,269,066

 
 
 
 
 
 
 
 
 
 
 
 
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, 2015 and 2014
 
 
 
 
 
 
 
 
 
 
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

 
 
 
 
 
 
 
 
 
 
 
 
Balance at Dec. 31, 2014
505,733

 
$
1,264,333

 
$
5,837,330

 
$
3,220,958

 
$
(108,139
)
 
$
10,214,482

Net income
 
 
 
 
 
 
348,997

 
 
 
348,997

Other comprehensive income
 
 
 
 
 
 
 
 
2,953

 
2,953

Dividends declared on common stock
 
 
 
 
 
 
(326,310
)
 
 
 
(326,310
)
Issuances of common stock
1,226

 
3,065

 
10,209

 
 
 
 
 
13,274

Share-based compensation
 
 
 
 
15,670

 
 
 
 
 
15,670

Balance at June 30, 2015
506,959

 
$
1,267,398

 
$
5,863,209

 
$
3,243,645

 
$
(105,186
)
 
$
10,269,066

 
 
 
 
 
 
 
 
 
 
 
 
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, 2015 and Dec. 31, 2014; 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, 2015 and 2014; and its cash flows for the six months ended June 30, 2015 and 2014. All adjustments are of a normal, recurring nature, except as otherwise disclosed. Management has also evaluated the impact of events occurring after June 30, 2015 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, 2014 balance sheet information has been derived from the audited 2014 consolidated financial statements included in the Xcel Energy Inc. Annual Report on Form 10-K for the year ended Dec. 31, 2014. 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, 2014, filed with the SEC on Feb. 20, 2015. 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, 2014, appropriately represent, in all material respects, the current status of accounting policies and are incorporated herein by reference.

2.
Accounting Pronouncements

Recently Issued

Revenue Recognition In May 2014, the Financial Accounting Standards Board (FASB) issued Revenue from Contracts with Customers, Topic 606 (Accounting Standards Update (ASU) No. 2014-09), which provides a framework for the recognition of revenue, with the objective that recognized revenues properly reflect amounts an entity is entitled to receive in exchange for goods and services. The new guidance also includes additional disclosure requirements regarding revenue, cash flows and obligations related to contracts with customers. As a result of the FASB’s deferral of the standard’s required implementation date in July 2015, the guidance is effective for interim and annual reporting periods beginning after Dec. 15, 2017. Xcel Energy is currently evaluating the impact of adopting ASU 2014-09 on its consolidated financial statements.

Consolidation In February 2015, the FASB issued Amendments to the Consolidation Analysis, Topic 810 (ASU No. 2015-02), which reduces the number of consolidation models and amends certain consolidation principles related to variable interest entities. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15. 2015, and early adoption is permitted. Xcel Energy is currently evaluating the impact of adopting ASU 2015-02 on its consolidated financial statements.

Presentation of Debt Issuance Costs In April 2015, the FASB issued Simplifying the Presentation of Debt Issuance Costs, Subtopic 835-30 (ASU No. 2015-03), which amends existing guidance to require the presentation of debt issuance costs on the balance sheet as a deduction from the carrying amount of the related debt, instead of an asset. This guidance will be effective for interim and annual reporting periods beginning after Dec. 15, 2015, and early adoption is permitted. Other than the prescribed reclassification of assets to an offset of debt on the consolidated balance sheets, Xcel Energy does not expect the implementation of ASU 2015-03 to have a material impact on its consolidated financial statements.

Fair Value Measurement In May 2015, the FASB issued Disclosures for Investments in Certain Entities that Calculate Net Asset Value per Share (or Its Equivalent), Topic 820 (Accounting Standards Update (ASU) No. 2015-07), which removes the requirement to categorize within the fair value hierarchy the fair values for investments measured using a net asset value methodology. This guidance will be effective on a retrospective basis for interim and annual reporting periods beginning after Dec. 15, 2015, and early adoption is permitted. Other than the reduced disclosure requirements, Xcel Energy does not expect the implementation of ASU 2015-07 to have a material impact on its consolidated financial statements.


9


3.
Selected Balance Sheet Data
(Thousands of Dollars)
 
June 30, 2015
 
Dec. 31, 2014
Accounts receivable, net
 
 
 
 
Accounts receivable
 
$
726,732

 
$
884,225

Less allowance for bad debts
 
(50,509
)
 
(57,719
)
 
 
$
676,223

 
$
826,506

(Thousands of Dollars)
 
June 30, 2015
 
Dec. 31, 2014
Inventories
 
 
 
 
Materials and supplies
 
$
256,000

 
$
244,099

Fuel
 
203,177

 
183,249

Natural gas
 
73,526

 
169,835

 
 
$
532,703

 
$
597,183

(Thousands of Dollars)
 
June 30, 2015
 
Dec. 31, 2014
Property, plant and equipment, net
 
 
 
 
Electric plant
 
$
33,996,892

 
$
33,203,139

Natural gas plant
 
4,726,068

 
4,643,452

Common and other property
 
1,623,828

 
1,611,486

Plant to be retired (a)
 
55,397

 
71,534

Construction work in progress
 
2,092,391

 
2,005,531

Total property, plant and equipment
 
42,494,576

 
41,535,142

Less accumulated depreciation
 
(13,543,351
)
 
(13,168,418
)
Nuclear fuel
 
2,405,823

 
2,347,422

Less accumulated amortization
 
(2,006,684
)
 
(1,957,230
)
 
 
$
29,350,364

 
$
28,756,916


(a) 
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, 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, 2014 appropriately represents, in all material respects, the current status of other income tax matters, and are incorporated herein by reference.

Federal Audit  Xcel Energy files a consolidated federal income tax return. The statute of limitations applicable to Xcel Energy’s 2009 federal income tax return expires in March 2016. 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, 2015, the IRS had proposed an adjustment to the federal tax loss carryback claims that would result in $12 million of income tax expense for the 2009 through 2011 claims, the recently filed 2013 claim, and the anticipated claim for 2014. As of June 30, 2015, the IRS has begun the appeals process; however, 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, 2015, 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
 
2010

As of June 30, 2015, there were no state income tax audits in progress.


10


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

A reconciliation of the amount of unrecognized tax benefit is as follows:
(Millions of Dollars)
 
June 30, 2015
 
Dec. 31, 2014
Unrecognized tax benefit — Permanent tax positions
 
$
16.4

 
$
16.2

Unrecognized tax benefit — Temporary tax positions
 
56.9

 
50.3

Total unrecognized tax benefit
 
$
73.3

 
$
66.5


The unrecognized tax benefit amounts were reduced by the tax benefits associated with net operating loss (NOL) and tax credit carryforwards. The amounts of tax benefits associated with NOL and tax credit carryforwards are as follows:
(Millions of Dollars)
 
June 30, 2015
 
Dec. 31, 2014
NOL and tax credit carryforwards
 
$
(35.2
)
 
$
(28.5
)

It is reasonably possible that Xcel Energy’s amount of unrecognized tax benefits could significantly change in the next 12 months as the IRS appeals process progresses and state audits resume. As the IRS appeals process moves closer to completion, it is reasonably possible that the amount of unrecognized tax benefit could decrease up to approximately $10 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, 2015 and Dec. 31, 2014 were not material. No amounts were accrued for penalties related to unrecognized tax benefits as of June 30, 2015 or Dec. 31, 2014.

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, 2014 and in Note 5 to Xcel Energy Inc.’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2015, appropriately represent, in all material respects, the current status of other rate matters, and are incorporated herein by reference.

NSP-Minnesota

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

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 was 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 initially reflected a requested 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 included a proposed rate moderation plan for 2014 and 2015. In December 2013, the MPUC approved interim rates of $127 million, effective Jan. 3, 2014, subject to refund.

In 2014, NSP-Minnesota revised its requested rate increase to $115.3 million for 2014 and to $106.0 million for 2015, for a total combined unadjusted increase of $221.3 million.

In May 2015, the MPUC ordered a 2014 rate increase and a 2015 step increase. The total increase was estimated to be $166 million, or 5.9 percent, based on a 9.72 percent ROE and 52.50 percent equity ratio. The MPUC also approved a three-year, decoupling pilot with a 3 percent cap on base revenue for the residential and small commercial and industrial classes, based on actual sales, effective Jan. 1, 2016. The decoupling mechanism would eliminate the impact of changes in electric sales due to conservation and weather variability for these classes.


11


In July 2015, the MPUC deliberated on requests for reconsideration of its order. The MPUC determined the Monticello Extended Power Uprate (EPU) project is not used-and-useful until final approval related to the full EPU uprate condition is received from the Nuclear Regulatory Commission (NRC).  NSP-Minnesota expects that $13.8 million will be excluded from final rates, as approval from the NRC had not been received as of June 30, 2015. Monticello achieved the full EPU uprate level of 671 megawatts (MW) in June 2015 and received final NRC compliance approval in July 2015, thereby satisfying the used-and-useful conditions established by the MPUC. The MPUC also approved 2015 interim rates effective March 3, 2015 and stated that the 2014 interim rate refund obligation be netted against the 2015 interim rate revenue under-collections.

The MPUC’s decision resulted in an estimated 2015 annual rate increase of $149.4 million or 5.3 percent. NSP-Minnesota anticipates reducing the 2014 refund obligation by approximately $6 million for the change in the interest rate applied to interim refunds and other items.

The following tables outline NSP-Minnesota’s filed request and the impact of the MPUC’s decisions made in May and July:
2014 Rate Request (Millions of Dollars)
 
NSP-Minnesota
 
MPUC May Decision
NSP-Minnesota’s filed rate request
 
$
192.7

 
$
192.7

Sales forecast (with true-up to 12 months of actual weather-normalized sales)
 
(38.5
)
 
(37.5
)
ROE
 

 
(31.9
)
Monticello EPU cost recovery
 
(12.2
)
 
(37.6
)
Property taxes (with true-up to actual 2014 accruals)
 
(13.2
)
 
(13.2
)
Prairie Island EPU cost recovery
 
(5.1
)
 
(5.0
)
Health care, pension and other benefits
 
(1.9
)
 
(3.1
)
Other, net
 
(6.5
)
 
(5.5
)
Total 2014
 
$
115.3

 
$
58.9

2015 Rate Request (Millions of Dollars)
 
NSP-Minnesota
 
MPUC May Decision
NSP-Minnesota’s filed rate request
 
$
98.5

 
$
98.5

Monticello EPU cost recovery
 
11.7

 
35.4

Depreciation / Retirements
 

 
(0.5
)
Property taxes
 
(3.3
)
 
(3.3
)
Production tax credits to be included in base rates
 
(11.1
)
 
(11.1
)
U.S. Department of Energy (DOE) settlement proceeds
 
10.1

 
10.1

Emission chemicals
 
(1.6
)
 
(1.6
)
Other, net
 
1.7

 
(2.3
)
Total 2015 step increase - prior to Monticello Life Cycle Management (LCM)/EPU cost
disallowance
 
$
106.0

 
$
125.2

 
 
 
 
 
Total for 2014 and 2015 step increase - prior to Monticello LCM/EPU cost disallowance
 
$
221.3

 
$
184.1

Monticello LCM/EPU cost disallowance
 

 
(18.0
)
Total for 2014 and 2015 step increase - including Monticello LCM/EPU cost disallowance
 
$
221.3

 
$
166.1

(Millions of Dollars)
 
MPUC July Decision
2015 annual rate increase - based on MPUC May order
 
$
166.1

Reconsideration/clarification adjustments:
 
 
2015 Monticello EPU used-and-useful adjustment
 
(13.8
)
2014 property tax final true-up
 
(3.1
)
Other, net
 
0.2

Total 2015 annual rate increase
 
$
149.4

Impact of interim rate effective March 3, 2015
 
(3.6
)
Estimated 2015 revenue impact
 
$
145.8



12


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

In 2013, the MPUC initiated an investigation to determine whether the final costs for the Monticello LCM/EPU project were prudent.

In March 2015, the MPUC voted to allow for full recovery, including a return, on approximately $415 million of the total plant costs (inclusive of AFUDC), but only allow recovery of the remaining $333 million of costs with no return on this portion of the investment over the remaining life of the plant. Further, the MPUC determined that only 50 percent of the investment was considered used-and-useful for 2014.  As a result of these determinations and assuming the other state commissions within the NSP System jurisdictions adopt the MPUC’s decisions, Xcel Energy recorded an estimated pre-tax loss of $129 million in the first quarter of 2015. The remaining book value of the Monticello project represents the present value of the estimated future cash flows allowed for by the MPUC.

NSP-Minnesota – 2015 Transmission Cost Recovery (TCR) Rate Filing — In October 2014, NSP-Minnesota submitted its 2015 TCR filing with the MPUC, requesting recovery of $65.8 million of 2015 transmission investment costs not included in electric base rates. The request for 2015 was reduced to approximately $63.8 million, which was approved by the MPUC in May 2015, subject to future adjustments replacing forecasted amounts with actual investment costs. The MPUC also set rates so that NSP-Minnesota will recover its remaining 2015 and forecasted 2016 revenue requirements through the end of 2016. New rates were implemented in July 2015, subject to true-up.

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

NSP-Minnesota – South Dakota 2015 Electric Rate Case In June 2014, NSP-Minnesota filed a request with the SDPUC to increase electric rates by $15.6 million annually, or 8.0 percent, effective Jan. 1, 2015. Interim rates of $15.6 million, subject to refund, went into effect in January 2015.

In June 2015, the SDPUC approved a settlement agreement allowing a base rate increase of approximately $6.9 million, or 3.6 percent, and providing revisions to the existing Infrastructure rider, which will recover additional net revenue of $0.9 million. Combined, the overall revenue increase in base rates and the Infrastructure rider for 2015 is approximately $7.8 million, or 4.0 percent. New rates began in July 2015. In addition, there is a moratorium on base rate increases until Jan. 1, 2018.

The settlement also includes an earnings test with a sharing mechanism. If South Dakota’s weather normalized earnings exceed a certain level, NSP-Minnesota will refund 50 percent of the excess earnings to customers.

NSP-Wisconsin

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

Wisconsin 2016 Electric and Gas Rate Case — On May 29, 2015, NSP-Wisconsin filed a request with the PSCW to increase rates for electric and natural gas service effective Jan. 1, 2016. NSP-Wisconsin requested an overall increase in annual electric rates of $27.4 million, or 3.9 percent, and an increase in natural gas rates of $5.9 million, or 5.0 percent.

The rate filing is based on a 2016 forecast test year, a return on equity of 10.2 percent, an equity ratio of 52.5 percent and a forecasted average net investment rate base of approximately $1.2 billion for the electric utility and $111.2 million for the natural gas utility.

Key dates in the procedural schedule are as follows:

Staff and Intervenor Direct Testimony — Oct. 1, 2015;
Rebuttal Testimony — Oct. 19, 2015;
Sur-Rebuttal Testimony — Oct. 27, 2015;
Technical Hearing — Oct. 29, 2015;
Initial Brief — Nov. 12, 2015;
Reply Brief — Nov. 19, 2015; and
A PSCW decision is anticipated in December 2015.


13


PSCo

Pending Regulatory Proceedings — Colorado Public Utilities Commission (CPUC)

PSCo – Colorado 2015 Multi-Year Gas Rate Case — In March 2015, PSCo filed a multi-year request with the CPUC to increase Colorado retail natural gas base rates by $40.5 million, or 3.5 percent, in 2015, with subsequent step increases of $7.6 million, or 0.7 percent, in 2016 and $18.1 million, or 1.5 percent, in 2017.

The request is based on a historic test year (HTY) ended June 30, 2014 adjusted for known and measurable expenses and capital additions for each of the subsequent periods in the multi-year plan and an equity ratio of 56 percent. The rate case requests an ROE of 10.1 percent for 2015 and 2016 and 10.3 percent for 2017, and a rate base of $1.26 billion for 2015, $1.31 billion for 2016 and $1.36 billion for 2017.

PSCo also proposed a stay-out provision, in which PSCo would not request implementation of new rates prior to January 2018, and implementation of an earnings test for 2016 through 2017.

In addition, PSCo requested an extension of its pipeline system integrity adjustment (PSIA) rider through 2020 to recover costs associated with its pipeline integrity efforts. The request to extend and modify the PSIA rider has an expected negative revenue impact of approximately $0.1 million in 2015 and would provide incremental revenue of $21.7 million for 2016 and $21.2 million for 2017. The following table summarizes the request:
(Millions of Dollars)
 
2015
 
2016 Step
 
2017 Step
Total base rate increase
 
$
40.5

 
$
7.6

 
$
18.1

Incremental PSIA rider revenues
 
(0.1
)
 
21.7

 
21.2

Total revenue impact
 
$
40.4

 
$
29.3

 
$
39.3


In June 2015, intervenors, including the CPUC Staff (Staff) and the Office of Consumer Counsel (OCC), filed testimony.

Staff recommended a base rate decrease of $14.7 million, based on an ROE of 9.0 percent and a 47.04 percent equity ratio;
OCC recommended a base rate increase of $5.8 million, based on an ROE of 9.0 percent and a 52.70 percent equity ratio;
A multi-year plan was opposed by both the Staff and OCC;
The Staff recommended deferring costs related to incremental property taxes and safety programs which are expected to be approximately $4.2 million in 2016 and $9.0 million in 2017; and
The Staff opposed PSCo’s proposed earnings test and the stay out provision.

Regarding the PSIA:
The Staff proposed extending the PSIA rider for three years;
The Staff recommended approximately $32.6 million of PSIA costs would be transferred to base rates, effective Jan. 1, 2016, in addition to the Staff’s proposed 2015 base rate adjustment; and
The OCC recommended the PSIA rider expire on June 30, 2016 and any costs be included in base rates through a step increase.




14


The Staff and OCC’s 2015 base rate recommendations are summarized in the following table:
(Millions of Dollars)
 
Staff
 
OCC
PSCo’s filed 2015 base rate request
 
$
40.5

 
$
40.5

ROE
 
(12.8
)
 
(13.7
)
Capital structure and cost of debt
 
(12.8
)
 
(4.8
)
Cherokee pipeline adjustment
 
(11.2
)
 
4.8

Move to 2014 historical test year
 
(10.5
)
 
(16.4
)
O&M expenses
 
(3.5
)
 
(2.7
)
Other, net
 
(4.4
)
 
(1.9
)
Total adjustments
 
$
(55.2
)
 
$
(34.7
)
 
 
 
 
 
Recommended (decrease) increase
 
$
(14.7
)
 
$
5.8


The Staff’s recommendation for the PSIA rider is as follows:
(Millions of Dollars)
 
2016
 
2017
PSCo’s filed incremental PSIA request
 
$
21.7

 
$
21.2

Transfer PSIA O&M to base rates
 
(24.1
)
 
(2.0
)
ROE and capital structure
 
(8.2
)
 
(3.6
)
Transfer meter replacement program from base rates to PSIA
 
1.7

 
1.7

Total
 
$
(8.9
)
 
$
17.3


On July 20, 2015, PSCo filed rebuttal testimony, maintaining its request for a multi-year plan and requested ROEs and reflecting the most recent sales forecast. PSCo also accepts portions of the Staff’s position regarding the PSIA rider. PSCo’s rebuttal testimony, compared to its initial filed base rate and rider request are summarized as follows:
(Millions of Dollars)
 
2015
 
2016 Step
 
2017 Step
PSCo’s filed base rate request
 
$
40.5

 
$
7.6

 
$
18.1

Shift O&M expenses between PSIA and base rates
 

 
7.0

 
6.4

Rebuttal corrections and adjustments
 

 

 
(7.7
)
Total base rate request
 
$
40.5

 
$
14.6

 
$
16.8

Incremental PSIA rider revenues
 
(0.1
)
 
14.7

 
21.7

Total revenue impact from rebuttal
 
$
40.4

 
$
29.3

 
$
38.5


If PSCo’s revised request is accepted, PSIA revenue is projected to be $67.0 million in 2015, $81.7 million in 2016 and $103.4 million in 2017.

The next steps in the procedural schedule are as follows:

Sur-Rebuttal Testimony — Aug. 3, 2015;
Evidentiary Hearing — Aug. 18 - Aug. 31, 2015;
Interim Rates (subject to refund) — Oct. 1, 2015; and
Final CPUC Decision — No later than Jan. 20, 2016.

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 through 2014. On April 30, 2015, PSCo filed a tariff for the 2014 earnings test with the CPUC proposing a refund obligation of $66.5 million to electric customers, which was approved by the CPUC in July 2015.

In February 2015, in the Colorado 2014 Electric Rate Case, the CPUC approved an annual earnings test, in which PSCo shares with customers’ earnings that exceed the authorized ROE threshold of 9.83 percent for 2015 through 2017. As of June 30, 2015, PSCo has recognized management’s best estimate of the expected customer refund obligation for the 2015 earnings test, based on annual forecasted information.


15


Electric, Purchased Gas and Resource Adjustment Clauses

Demand Side Management (DSM) and the Demand Side Management Cost Adjustment (DSMCA) — The CPUC approved higher savings goals and a lower financial incentive mechanism for PSCo’s electric DSM energy efficiency programs starting in 2015. Energy efficiency and DSM costs are recovered through a combination of the DSMCA riders and base rates. DSMCA riders are adjusted biannually to capture program costs, performance incentives, and any over- or under-recoveries are trued-up in the following year. Savings goals were 384 gigawatt hours (GWh) in 2014 and are 400 GWh in 2015 with incentives awarded in the year following plan achievements. PSCo is able to earn $5 million upon reaching its annual savings goal along with an incentive on five percent of net economic benefits up to a maximum annual incentive of $30 million.

In October 2014, PSCo filed its 2015-2016 DSM plan, which proposes a 2015 DSM electric budget of $81.6 million, a 2015 DSM gas budget of $13.1 million, a 2016 DSM electric budget of $78.7 million and a 2016 DSM gas budget of $13.6 million. PSCo has reached an agreement with all parties resolving most of the contested issues in the proceeding. The remaining issues to be litigated primarily concern the avoided costs attributable to DSM measures. In July 2015, the administrative law judge (ALJ) approved the plan.

SPS

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

SPS – Texas 2015 Electric Rate Case — In December 2014, SPS filed a retail electric rate case in Texas seeking an overall increase in annual revenue of approximately $64.8 million, or 6.7 percent. The filing was based on a HTY ending June 2014, adjusted for known and measurable changes, a ROE of 10.25 percent, an electric rate base of approximately $1.6 billion and an equity ratio of 53.97 percent. In March 2015, SPS revised its requested increase to $58.9 million based on updated information.

SPS is seeking a waiver of the PUCT post-test year adjustment rule which would allow for inclusion of $392 million (SPS total company) additional capital investment for the period July 1, 2014 through Dec. 31, 2014.

In May 2015, several intervenors filed direct testimony in response to SPS’ rate request, including the Alliance of Xcel Municipalities (AXM), the Office of Public Utility Counsel (OPUC), and the PUCT Staff (Staff).

AXM recommended a rate decrease of $13.6 million, an ROE of 9.40 percent and an equity ratio of 53.97 percent.
The OPUC recommended a rate increase of $1.8 million, an ROE of 9.20 percent and an equity ratio of 52.38 percent.
The Staff recommended a rate decrease of $2.6 million, an ROE of 9.30 percent and an equity ratio of 53.97 percent.

In June 2015, SPS filed rebuttal testimony supporting a revised rate increase of approximately $42 million, or 4.4 percent.
 
 
 
 
 
 
 
 
SPS Rebuttal Testimony
(Millions of Dollars)
 
AXM
 
OPUC
 
Staff
 
SPS’ revised rate request
 
$
58.9

 
$
58.9

 
$
58.9

 
$
58.9

Investment for capital expenditures — post-test year adjustments
 
(11.3
)
 
(23.8
)
 
(23.8
)
 

Lower ROE
 
(10.9
)
 
(13.5
)
 
(12.1
)
 

Rate base adjustments (largely the removal of the prepaid pension asset)
 
(6.2
)
 
(6.8
)
 

 

O&M expense adjustments
 
(13.7
)
 
(11.0
)
 
(7.9
)
 
(1.6
)
Depreciation expense
 
(13.3
)
 

 

 

Property taxes
 

 
(1.2
)
 
(4.4
)
 
(1.8
)
Revenue adjustments
 
(2.2
)
 
(0.2
)
 

 

Wholesale load reductions
 
(13.2
)
 

 
(11.1
)
 

Southwest Power Pool (SPP) transmission expansion plan
 

 

 

 
(7.3
)
Other, net
 
(1.7
)
 
(0.6
)
 
(2.2
)
 
(1.8
)
Total recommendation
 
$
(13.6
)
 
$
1.8

 
$
(2.6
)
 
$
46.4

Adjustment to move rate case expenses to a separate docket
 

 

 

 
(4.3
)
Recommendation, excluding rate case expenses
 
$
(13.6
)
 
$
1.8

 
$
(2.6
)
 
$
42.1


New rates will be made effective retroactive to June 11, 2015 as established by the PUCT. Hearings were completed in July 2015. A PUCT decision is expected in the fourth quarter of 2015.


16


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

SPS – New Mexico 2015 Electric Rate Case — In June 2015, SPS filed an electric rate case with the NMPRC for an increase in non-fuel base rates of $31.5 million and a base fuel decrease of $30.1 million. The rate filing was based on a 2016 forecast test year (FTY), a requested return on equity of 10.25 percent, a jurisdictional electric rate base of $777.9 million and an equity ratio of 53.97 percent.

In June 2015, SPS’ rate case application was dismissed by the NMPRC.  The NMPRC determined that the filing did not comply with its new interpretation of the statute regarding FTY periods and the corresponding timing of a rate case submission in relation to the FTY used in the case. This new interpretation occurred during the recent Public Service Company of New Mexico rate case.

In July, SPS filed an appeal with the New Mexico Supreme Court. In addition, SPS plans to file a rate case later this year.

Pending and Recently Concluded Regulatory Proceedings — FERC

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

In June 2014, the FERC issued an order adopting a new ROE methodology, which requires electric utilities to use a two-step discounted cash flow analysis that incorporates both short-term and long-term growth projections to estimate the cost of equity.

The FERC set the ROE complaint against the MISO TOs for settlement and hearing procedures. The FERC directed parties to apply the new ROE methodology, but denied the complaints related to equity capital structures and ROE adders. The FERC established a Nov. 12, 2013 refund effective date. The settlement procedures were unsuccessful. In January 2015, the ROE complaint was set for full hearing procedures.

The complainants and intervenors filed testimony recommending an ROE between 8.67 percent and 9.54 percent. The FERC staff recommended an ROE of 8.68 percent. The MISO TOs recommended an ROE not less than 10.8 percent. A hearing is scheduled for August 2015, with an ALJ initial decision to be issued by November 2015 and a FERC order issued no earlier than 2016.

In November 2014, certain MISO TOs filed a request for FERC approval of a 50 basis point RTO membership ROE adder, with collection deferred until resolution of the ROE complaint. In January 2015, the FERC approved the ROE adder, subject to the outcome of the ROE complaint. The total ROE, including the RTO membership adder, may not exceed the top of the discounted cash flow range under the new ROE methodology.

In February 2015, an intervenor in the November 2013 ROE complaint filed a second complaint proposing to reduce the MISO region ROE to 8.67 percent, prior to any 50 basis point RTO adder. In June 2015, the FERC set the second ROE complaint for a hearing process, establishing a Feb. 12, 2015 refund effective date. An ALJ initial decision is expected in June 2016 with a FERC decision in late 2016 or in 2017. The FERC decision would continue the ROE refund obligation initiated under the November 2013 complaint through May 2016. On July 20, 2015, the MISO TOs sought rehearing of the FERC decision to allow back-to-back complaints involving the same issue with consecutive refund periods, arguing this ruling is contrary to the governing statute. FERC action on the rehearing request is pending.

NSP-Minnesota recorded a current liability representing the current best estimate of a refund obligation associated with the new ROE as of June 30, 2015. The new FERC ROE methodology is estimated to reduce transmission revenue, net of expense, between $7 million and $9 million annually for the NSP System.

SPS – Wholesale Rate ROE Complaints — In April 2012, Golden Spread Electric Cooperative, Inc. (Golden Spread), a wholesale cooperative customer, filed a rate complaint alleging that the base ROE included in the SPS production formula rate for Golden Spread of 10.25 percent, and the SPS transmission base formula rate ROE of 10.77 percent, are unjust and unreasonable, and asking that the ROEs be reduced to 9.15 percent and 9.65 percent, respectively, effective April 20, 2012. In July 2013, Golden Spread filed a second complaint, again asking that the ROE in the SPS production formula rate for Golden Spread and transmission formula rates be reduced to 9.15 and 9.65 percent, respectively, effective July 19, 2013. In June 2014, the FERC issued orders consolidating the Golden Spread ROE complaints and setting the complaints for settlement judge or hearing procedures.

17



A third rate complaint was filed in October 2014 by Golden Spread, certain New Mexico cooperatives and the West Texas Municipal Power Agency, requesting that the ROE in certain SPS production formula rates for Golden Spread and the New Mexico cooperatives and transmission formula rates be reduced, this time to 8.61 percent and 9.11 percent, respectively, effective Oct. 20, 2014. In January 2015, the FERC issued an order setting the third complaint for hearing procedures and granting the complainants’ requested refund effective date. The FERC established effective dates for refunds of April 20, 2012 (first refund period), July 19, 2013 (second refund period) and Oct. 20, 2014 (third refund period), respectively.

SPS sought rehearing of the FERC decisions to allow back-to-back complaints involving the same issue with consecutive 15 month refund periods, asserting this ruling is contrary to the governing statute. On May 12, 2015, FERC denied the rehearing request as it pertained to the first two rate complaints. In July 2015, SPS filed an appeal to the D.C. Circuit Court of Appeals of the FERC orders in the first two rate complaints allowing the sequential complaints and consecutive 15 month refund periods. The D.C. Circuit Court has not established a procedural schedule. FERC action on the similar SPS rehearing request related to the third complaint is pending.
 
In the first half of 2015, Golden Spread, SPS and FERC staff filed their initial testimonies recommending the following ROEs:
 
 
Refund Period
 
Production ROE
 
Transmission ROE (a)
Golden Spread (b)
 
1
 
8.78
%
 
9.28
%
 
 
2
 
8.51

 
9.01

 
 
3
 
8.45

 
8.95

SPS
 
1
 
10.25

 
10.39

 
 
2
 
10.25

 
11.20

 
 
3
(c) 
10.40

 
11.20

FERC Staff
 
1
 
8.97

 
9.47

 
 
2
 
8.64

 
9.14

 
 
3
 
8.53

 
9.03


(a) 
Includes a SPP RTO membership adder up to 50 basis points.
(b) 
For the third refund period, the recommended production and transmission ROEs are supported by Golden Spread, certain New Mexico cooperatives and the West Texas Municipal Power Agency (transmission ROE only).
(c) 
In addition to the recommended ROEs, SPS also filed testimony recommending the ROEs remain unchanged.

Hearings scheduled for July 2015 for the first two rate complaints were canceled and the parties agreed to file briefs based on pre-filed testimony. An initial ALJ decision on the first two complaints is expected to be issued by Nov. 25, 2015, and a final FERC order to be issued no earlier than 2016. A hearing for the third rate complaint is scheduled for Oct. 2015, with an ALJ initial decision expected in January 2016 and a final FERC order no earlier than later in 2016.
 
SPS recorded a current liability representing the current best estimate of a refund obligation associated with potential ROE adjustments as of June 30, 2015, and is reducing transmission and production revenues, net of expense, between $4 million and $6 million annually.

SPS – 2004 FERC Complaint Case Orders  In August 2013, the FERC issued an order related to a 2004 complaint case brought by Golden Spread and Public Service Company of New Mexico (PNM) and an Order on Initial Decision in a subsequent 2006 production rate case filed by SPS.

The original complaint included two key components: 1) PNM’s claim regarding inappropriate allocation of fuel costs and 2) a base rate complaint, including the appropriate demand-related cost allocator. The FERC previously determined that the allocation of fuel costs and the demand-related cost allocator utilized by SPS was appropriate.

In the August 2013 Orders, the FERC clarified its previous ruling on the allocation of fuel costs and reaffirmed that the refunds in question should only apply to firm requirements customers and not PNM’s contractual load. The FERC also reversed its prior demand-related cost allocator decision. The FERC stated that it had erred in its initial analysis and concluded that the SPS system was a 3 coincident peak (CP) rather than a 12 CP system.


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In September 2013, SPS filed a request for rehearing of the FERC ruling on the CP allocation and refund decisions. SPS asserted that the FERC applied an improper burden of proof and that precedent did not support retroactive refunds. PNM also requested rehearing of the FERC decision not to reverse its prior ruling. In October 2013, the FERC issued orders further considering the requests for rehearing, which are currently pending. As of Dec. 31, 2014, SPS had accrued $50.4 million related to the August 2013 Orders and an additional $1.5 million of principal and interest has been accrued during 2015.

SPS – 2015 Production Formula Rate Change Filing  In January 2015, SPS filed to revise the production formula rates for six of its wholesale customers, including Golden Spread, certain New Mexico cooperatives and West Texas Municipal Power Agency, effective Feb. 1, 2015. The filing proposes several modifications, including a reduction in wholesale depreciation rates and the use of a 12 CP demand-related cost allocator for all wholesale customers. In March 2015, the FERC accepted this filing, effective July 1, 2015, subject to refund and settlement judge or hearing procedures. The parties remain engaged in settlement judge procedures. Effective June 1, 2015, the Golden Spread contract demand quantity subject to the formula rate change declined from 500 MW to 300 MW.

6.
Commitments and Contingencies

Except to the extent noted below and in Note 5 above, the circumstances set forth in Notes 5, 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, 2014 and in Notes 5 and 6 to the consolidated financial statements included in Xcel Energy Inc.’s Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2015, appropriately represent, in all material respects, the current status of commitments and contingent liabilities, and are incorporated herein by reference. The following include commitments, contingencies and unresolved contingencies that are material to Xcel Energy’s financial position.

Purchased Power Agreements (PPAs)

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

The Xcel Energy utility subsidiaries had approximately 3,698 MW of capacity under long-term PPAs as of June 30, 2015 and Dec. 31, 2014, 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 Bond Indemnifications

Xcel Energy Inc. and its subsidiaries provide guarantees and bond indemnities under specified agreements or transactions. The guarantees and bond indemnities issued by Xcel Energy Inc. guarantee payment or performance by its subsidiaries. As a result, Xcel Energy Inc.’s exposure under the guarantees and bond indemnities is based upon the net liability of the relevant subsidiary under the specified agreements or transactions. Most of the guarantees and bond indemnities issued by Xcel Energy Inc. and its subsidiaries limit the exposure to a maximum amount stated in the guarantees and bond indemnities. As of June 30, 2015 and Dec. 31, 2014, 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, 2015
 
Dec. 31, 2014
Guarantees issued and outstanding
 
$
13.2

 
$
13.9

Current exposure under these guarantees
 
0.1

 
0.2

Bonds with indemnity protection
 
41.9

 
31.4



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Other Indemnification Agreements

Xcel Energy Inc. and its subsidiaries provide indemnifications through contracts entered into in the normal course of business. These are primarily indemnifications against adverse litigation outcomes in connection with underwriting agreements, as well as breaches of representations and warranties, including corporate existence, transaction authorization and income tax matters with respect to assets sold. Xcel Energy Inc.’s and its subsidiaries’ obligations under these agreements may be limited in terms of duration and amount. The maximum potential amount of future payments under these indemnifications cannot be reasonably estimated as the obligated amounts of these indemnifications often are not explicitly stated.

Environmental Contingencies

Ashland Manufactured Gas Plant (MGP) Site — NSP-Wisconsin has been named a potentially responsible party (PRP) for contamination at a site in Ashland, Wis. The Ashland/Northern States Power Lakefront Superfund Site (the Ashland site) includes property owned by NSP-Wisconsin, which was a site previously operated by a predecessor company as a MGP facility (the Upper Bluff), and two other properties: an adjacent city lakeshore park area (Kreher Park), on which an unaffiliated third party previously operated a sawmill and conducted creosote treating operations; and an area of Lake Superior’s Chequamegon Bay adjoining the park (the Sediments).

The U.S. Environmental Protection Agency (EPA) issued its Record of Decision (ROD) in 2010, which describes the preferred remedy the EPA has selected for the cleanup of the Ashland site. 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. 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. Fieldwork to address the Phase I Project Area at the Ashland site began at the end of 2012 and continues. Demolition activities occurred at the Ashland site in 2013. Soil, including excavation and treatment, as well as containment wall remedies were completed in early 2015. A preliminary design for the groundwater remedy was also submitted to the EPA in April 2014 and preliminary activities, including the installation of ground wells, have commenced at the site. Construction on the groundwater treatment plant is anticipated to commence in fall 2015. The current cost estimate for the cleanup of the Phase I Project Area is approximately $57 million, of which approximately $35 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.

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. It is NSP-Wisconsin’s view that 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. 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.


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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 took place in May 2015. A judicial decision is expected in the third quarter of 2015. A final settlement has been reached between NSP-Wisconsin, along with the EPA, and two of the PRPs, Wisconsin Central Ltd. and Soo Line Railroad Co. (collectively, the “Railroad PRPs”) resolving claims relating to the Railroad PRPs’ share of the costs of cleanup at the Ashland site. NSP-Wisconsin also has entered a second private party settlement agreement with LE Myers Co. Under the agreements, the Railroad PRPs contributed $10.5 million and LE Myers Co. contributed $5.4 million to the costs of the cleanup at the Ashland site. The agreements for the Railroad PRPs and LE Myers Co. were approved by the U.S. District Court for the Western District of Wisconsin in 2015 and payment has been received. As discussed below, existing PSCW policy requires that any payments received from PRPs be used to reduce the amount of the cleanup costs ultimately recovered from customers. Two additional PRPs remain in the case.

At June 30, 2015 and Dec. 31, 2014, NSP-Wisconsin had recorded a liability of $108.5 million and $107.6 million, respectively, for the Ashland site based upon potential remediation and design costs together with estimated outside legal and consultant costs; of which $23.2 million and $28.9 million, respectively, was considered a current liability. NSP-Wisconsin’s potential liability, the actual cost of remediation and the time frame over which the amounts may be paid are subject to change. NSP-Wisconsin also continues to work to identify and access state and federal funds to apply to the ultimate remediation cost of the entire site. Unresolved issues or factors that could result in higher or lower NSP-Wisconsin remediation costs for the Ashland site include the cleanup approach implemented for the Sediments, which party implements the cleanup, the timing of when the cleanup is implemented, potential contributions by other PRPs and whether federal or state funding may be directed to help offset remediation costs at the Ashland site.

NSP-Wisconsin has deferred the estimated site remediation costs, as a regulatory asset, based on an expectation that the PSCW will continue to allow NSP-Wisconsin to recover payments for environmental remediation from its customers. The PSCW has consistently authorized NSP-Wisconsin rate recovery for all remediation costs incurred at the Ashland site, and has authorized recovery of MGP remediation costs by other Wisconsin utilities. Under the established PSCW policy, once deferred MGP remediation costs are determined by the PSCW to be prudent, utilities are allowed to recover those deferred costs in natural gas rates, typically over a four- to six-year amortization period. The PSCW historically has not allowed utilities to recover their carrying costs on unamortized regulatory assets for MGP remediation.

The PSCW reviewed the existing MGP cost recovery policy as it applied to the Ashland site in the context of NSP-Wisconsin’s 2013 general rate case. In December 2012, 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 a 2014 rate case decision, the PSCW continued the cost recovery treatment with respect to the 2013 and 2014 cleanup costs for the Phase I Project Area and 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. Cost recovery will continue at the level set in the 2014 rate case though 2015.  In May 2015, NSP-Wisconsin filed its 2016 rate case, in which it requested an increase to the annual recovery for MGP clean-up costs from $4.7 million to $7.6 million. A decision is anticipated in late 2015.

Fargo, N.D. MGP Site — In May 2015, in connection with a city water main replacement and street improvement project in Fargo, N.D., underground pipes, tars, and impacted soils, which may be related to a former MGP site operated by NSP-Minnesota or a prior company, were discovered. After initial reports and discussions with the City of Fargo and the North Dakota Department of Health, NSP-Minnesota removed the impacted soils and other materials from the project area. At this time, NSP-Minnesota’s investigation of the site is considered preliminary as information is still being gathered.

As of June 30, 2015, NSP-Minnesota recorded a liability of $2.1 million related to further investigation and additional planned activities. Uncertainties include the nature and cost of the additional remediation efforts that may be necessary, the ability to recover costs from insurance carriers and the potential for contributions from entities that may be identified as PRPs. Therefore, the total cost of remediation, NSP-Minnesota’s potential liability and amounts allocable to the North Dakota and Minnesota jurisdictions related to the site cannot currently be reasonably estimated. In July 2015, NSP-Minnesota filed a request with the North Dakota Public Service Commission (NDPSC) for approval to initially defer the portion of investigation and response costs allocable to the North Dakota jurisdiction.


21


Environmental Requirements

Water
Federal Clean Water Act (CWA) Waters of the United States Rule In June 2015, the EPA and the U.S. Army Corps of Engineers published a final rule that significantly expands the types of water bodies regulated under the CWA and broadens the scope of waters subject to federal jurisdiction. The expansion of the term “Waters of the U.S.” will subject more utility projects to federal CWA jurisdiction, thereby potentially delaying the siting of new generation projects, pipelines, transmission lines and distribution lines, as well as increasing project costs and expanding permitting and reporting requirements. The rule will go into effect beginning in August 2015. Xcel Energy does not anticipate the costs of compliance with the final rule will have a material impact on the results of operations, financial position or cash flows.

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

In August 2012, the United States District Court of Appeals for the District of Columbia Circuit (D.C. Circuit) vacated the CSAPR and remanded it back to the EPA. The D.C. Circuit stated 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 were considered on remand. In July 2015, the D.C. Circuit issued an opinion which found the reduction budgets exceed what is necessary for Texas to reduce its impact on downwind states that do not meet ambient air quality standards. The D.C. Circuit remanded the matter to the EPA to reconsider the emission budgets. While the EPA reconsiders emission budgets, the D.C. Circuit left CSAPR in effect.

In October 2014, the D.C. Circuit granted the EPA’s request to begin to implement CSAPR by imposing its 2012 compliance obligations starting in January 2015. While the litigation continues, the EPA is administering the CSAPR in 2015.

Multiple changes to the SPS system since 2011 will substantially reduce estimated costs of complying with the CSAPR. These include the addition of 700 MW of wind power, the construction of Jones Units 3 and 4, reduced wholesale load, new PPAs, installation of NOx combustion controls on Tolk Units 1 and 2 and completion of certain transmission projects. As a result, SPS estimates compliance with the CSAPR in 2015 will cost approximately $7 million or less.

NSP-Minnesota can operate within its CSAPR emission allowance allocations. NSP-Wisconsin can operate within its CSAPR emission allowance allocation for SO2. NSP-Wisconsin is complying with the CSAPR for NOx in 2015 through operational changes or allowance purchases. CSAPR compliance in 2015 is not having a material impact on the results of operations, financial position or cash flows.

Electric Generating Unit (EGU) Mercury and Air Toxics Standards (MATS) Rule — The final EGU MATS rule became effective in April 2012. The EGU MATS rule sets emission limits for acid gases, mercury and other hazardous air pollutants and requires coal-fired utility facilities greater than 25 MW to demonstrate compliance within three to four years of the effective date. In 2014, the U.S. Supreme Court decided to review the D.C. Circuit’s decision that upheld the MATS standard. By April 2015, the MATS compliance deadline, Xcel Energy had met the EGU MATS rule through a combination of emission control projects and controls required by other programs preceding MATS, such as regional haze and state mercury regulations. Xcel Energy also retired two coal units at the Black Dog plant and ceased use of coal at Bay Front Unit 5. In addition, mercury controls were installed in SPS’ Tolk and Harrington plants for a capital cost of $8 million. On June 29, 2015, the U.S. Supreme Court found that the EPA acted unreasonably by not considering the cost to regulate mercury and other hazardous air pollutants. The D.C. Circuit, on remand, will decide whether to leave MATS in effect while the EPA considers such costs in making a new determination. Xcel Energy believes EGU MATS costs will be recoverable through regulatory mechanisms and does not anticipate a material impact on the results of operations, financial position or cash flows.

Regional Haze Rules — The regional haze program is designed to address widespread haze that results from emissions from a multitude of sources. In 2005, the EPA amended the best available retrofit technology (BART) requirements of its regional haze rules, which require the installation and operation of emission controls for industrial facilities emitting air pollutants that reduce visibility in certain national parks and wilderness areas. In its 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.


22


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. Installation of the emission controls at Hayden Unit 1 is scheduled for 2015 and Hayden Unit 2 is scheduled for 2016 at an estimated combined cost of $82.4 million. 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 challenged 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. In September 2014, the EPA filed a request with the Court to remand the case to the EPA for additional explanation of the EPA’s decision approving the BART determination for Comanche Units 1 and 2. In October 2014, the Court granted the EPA’s request and vacated the current briefing schedule. In May 2015, the EPA published its final rule which re-affirmed the approval of the State of Colorado’s BART determination for Comanche Units 1 and 2. The determination found that the controls currently installed on the units for NOx are BART. In July 2015, WildEarth Guardians filed a petition for review of the EPA's May 2015 final rule. The 10th Circuit will now resume litigation and a decision is anticipated in 2016.

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 were installed first and the scrubber upgrades were completed in December 2014, at a cost of $46.9 million. NSP-Minnesota anticipates these costs will be fully recoverable in rates.

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 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. 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. In December 2014, the EPA proposed to approve the BART portion of the Texas SIP, with the exception that the EPA would substitute CSAPR compliance for Texas’ reliance on CAIR. The EPA currently plans to issue its final rule in December 2015.

In May 2014, the EPA issued a request for information under the CAA related to SO2 control equipment at Tolk Units 1 and 2. In December 2014, the EPA proposed to disapprove the reasonable progress portions of the Texas SIP and instead adopt a Federal Implementation Plan. The EPA proposed to require dry scrubbers on both Tolk units to reduce SO2 emissions to help achieve reasonable progress goals for Texas and Oklahoma national parks and wilderness areas. As proposed, the dry scrubbers would need to be installed and operating within five years of the EPA’s final action, currently expected in December 2015. Whether dry scrubbers are required is dependent on the EPA’s final decision. If required, they would cost approximately $600 million, with an annual operating cost of approximately $10.4 million. Xcel Energy believes these costs would be recoverable through regulatory mechanisms and therefore does not expect a material impact on results of operations, financial position or cash flows.


23


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 determine whether there is RAVI-type impairment in these parks and identify the potential source of the impairment. 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 (Minnesota District Court) 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 May 2015, NSP-Minnesota, the EPA and the six environmental advocacy organizations filed a settlement agreement in the Minnesota District Court.  The agreement anticipates a federal rulemaking that would impose stricter SO2 emission limits on Sherco Units 1, 2 and 3, without making a RAVI attribution finding or a RAVI BART determination.  The emission limits for Units 1 and 2 reflect the success of a recently completed control project. The Unit 3 emission limits will be met through changes in the operation of the existing scrubber.  The Minnesota District Court issued an order staying the litigation for the time needed to complete the actions required by the settlement agreement.  The plaintiffs agreed to withdraw their complaint with prejudice when those actions are completed.  Plaintiffs also agreed not to request a RAVI certification for Sherco Units 1, 2 and/or 3 in the future.

As required by the CAA, the EPA published notice of the proposed settlement in the Federal Register. The EPA reviewed the public comments in July 2015 and notified the Minnesota District Court that the settlement agreement is final. The EPA has seven months to recommend and adopt a rule which will set the agreed-upon SO2 emissions. Xcel Energy does not anticipate the costs of compliance with the proposed settlement will have a material impact on the results of operations, financial position or cash flows.

Implementation of the National Ambient Air Quality Standard (NAAQS) for SO2 — The EPA adopted a more stringent NAAQS for SO2 in 2010. In 2013, the EPA designated areas as not attaining the revised NAAQS, which did not include any areas where Xcel Energy operates power plants.  However, many other areas of the country were unable to be classified by the EPA due to a lack of air monitors.

Following a lawsuit alleging that the EPA had not completed its area designations in the time required by the CAA and under a consent decree the EPA is requiring states to evaluate areas in three phases. The first phase includes areas near PSCo’s Pawnee plant and SPS’ Tolk and Harrington plants.  The Pawnee plant recently installed an SO2 scrubber and the Tolk and Harrington Plants utilize low sulfur coal to reduce SO2 emissions. The Colorado Department of Health and Environment along with the Texas Commission on Environmental Quality (TCEQ) are expected to make recommendations for nonattainment areas to the EPA in September 2015 with a decision by summer 2016. 

If an area is designated nonattainment, the respective states will need to evaluate all SO2 sources in the area. The state would then submit an implementation plan for the respective areas which would be due in 18 months, designed to achieve the NAAQS within five years. The TCEQ could require additional SO2 controls on one or more of the units at Tolk and Harrington. It is anticipated the areas near the remaining Xcel Energy power plants would be evaluated in the next designation phase, ending December 2017. Xcel Energy cannot evaluate the impacts of this ruling until the designation of nonattainment areas is made and any required state plans are developed. Xcel Energy believes that, should SO2 control systems be required for a plant, compliance costs will be recoverable through regulatory mechanisms and therefore does not expect a material impact on results of operations, financial position or cash flows.


24


Legal Contingencies

Xcel Energy is involved in various litigation matters that are being defended and handled in the ordinary course of business. The assessment of whether a loss is probable or is a reasonable possibility, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. Management maintains accruals for such losses that are probable of being incurred and subject to reasonable estimation. Management is sometimes unable to estimate an amount or range of a reasonably possible loss in certain situations, including but not limited to when (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss. For current proceedings not specifically reported herein, management does not anticipate that the ultimate liabilities, if any, arising from such current proceedings would have a material effect on Xcel Energy’s financial statements. Unless otherwise required by GAAP, legal fees are expensed as incurred.

Employment, Tort and Commercial Litigation

Pacific Northwest FERC Refund Proceeding — 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 U.S. Court of Appeals for the Ninth Circuit (Ninth Circuit).

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

The FERC issued an order on remand establishing principles for the review proceeding in October 2011. The City of Seattle filed a petition for review with the Court of Appeals for the Ninth Circuit seeking review of FERC’s order on remand.

Notwithstanding its petition for review, 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 contested the FERC ALJ’s initial decision by filing a brief on exceptions to the FERC. This matter is now pending a decision by the FERC.


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In addition, on Feb. 17, 2015, the U.S. Court of Appeals of the Ninth Circuit directed parties to the pending FERC proceeding to submit briefs addressing, among other issues, the petition for review filed by the City of Seattle seeking review of FERC’s order on remand. Parties are directed to address whether FERC’s order properly established the scope for the hearing that concluded in October 2013. Respondent-intervenors, including PSCo jointly with others, submitted briefs on May 8, 2015. Oral argument was held on June 16, 2015, and the matter is now pending before the Ninth Circuit.

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, notwithstanding 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 contracts between the United States and NSP-Minnesota. NSP-Minnesota sought contract damages in this lawsuit through Dec. 31, 2004. In September 2007, the Court awarded NSP-Minnesota $116.5 million in damages. In August 2007, NSP-Minnesota filed a second complaint; this lawsuit claimed damages for the period Jan. 1, 2005 through Dec. 31, 2008.

In July 2011, the United States and NSP-Minnesota executed a settlement agreement resolving both lawsuits, providing an initial $100 million payment from the United States to NSP-Minnesota, and providing a method by which NSP-Minnesota can recover its spent fuel storage costs through 2013, estimated to be an additional $100 million. 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 spent fuel storage after 2016; such costs could be the subject of future litigation. In December 2014, NSP-Minnesota received a settlement payment of $32.8 million. NSP-Minnesota has received a total of $214.7 million of settlement proceeds as of June 30, 2015. On May 15, 2015, NSP-Minnesota submitted a claim for an additional $13.4 million. 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.


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Commercial Paper — Xcel Energy Inc. and its utility subsidiaries meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings under their credit facilities. Commercial paper outstanding for Xcel Energy was as follows:
(Amounts in Millions, Except Interest Rates)
 
Three Months Ended  
 June 30, 2015
 
Twelve Months Ended  
 Dec. 31, 2014
Borrowing limit
 
$
2,750

 
$
2,750

Amount outstanding at period end
 
451

 
1,020

Average amount outstanding
 
780

 
841

Maximum amount outstanding
 
1,072

 
1,200

Weighted average interest rate, computed on a daily basis
 
0.48
%
 
0.33
%
Weighted average interest rate at period end
 
0.48

 
0.56


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, 2015 and Dec. 31, 2014, there were $67.8 million and $60.5 million, respectively, of letters of credit outstanding under the credit facilities. The contract amounts of these letters of credit approximate their fair value and are subject to fees.

Credit Facilities — In order to use their commercial paper programs to fulfill short-term funding needs, Xcel Energy Inc. and its utility subsidiaries must have revolving credit facilities in place at least equal to the amount of their respective commercial paper borrowing limits and cannot issue commercial paper in an aggregate amount exceeding available capacity under these credit facilities. The lines of credit provide short-term financing in the form of notes payable to banks, letters of credit and back-up support for commercial paper borrowings.

At June 30, 2015, Xcel Energy Inc. and its utility subsidiaries had the following committed credit facilities available:
(Millions of Dollars)
 
Credit Facility (a)
 
Drawn (b)
 
Available
Xcel Energy Inc.
 
$
1,000

 
$
72

 
$
928

PSCo
 
700

 
58

 
642

NSP-Minnesota
 
500

 
144

 
356

SPS
 
400

 
245

 
155

NSP-Wisconsin
 
150

 

 
150

Total
 
$
2,750

 
$
519

 
$
2,231

(a) 
These credit facilities expire in October 2019.
(b) 
Includes outstanding commercial paper and letters of credit.

All credit facility bank borrowings, outstanding letters of credit and outstanding commercial paper reduce the available capacity under the respective credit facilities. Xcel Energy Inc. and its subsidiaries had no direct advances on the credit facilities outstanding at June 30, 2015 and Dec. 31, 2014.

Long-Term Borrowings

During the six months ended June 30, 2015, Xcel Energy Inc. and its utility subsidiaries completed the following bond issuances:

In May, PSCo issued $250 million of 2.9 percent first mortgage bonds due May 15, 2025;
In June, Xcel Energy Inc. issued $250 million of 1.2 percent senior notes due June 1, 2017 and $250 million of 3.3 percent senior notes due June 1, 2025; and
In June, NSP-Wisconsin issued $100 million of 3.3 percent first mortgage bonds due June 15, 2024.


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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.

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, Electric Reliability Council of Texas, 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.


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

NSP-Minnesota recognizes the costs of funding the decommissioning of its nuclear generating plants over the lives of the plants, assuming rate recovery of all costs. Given the purpose and legal restrictions on the use of nuclear decommissioning fund assets, realized and unrealized gains on fund investments over the life of the fund are deferred as an offset of NSP-Minnesota’s regulatory asset for nuclear decommissioning costs. Consequently, any realized and unrealized gains and losses on securities in the nuclear decommissioning fund, including any other-than-temporary impairments, are deferred as a component of the regulatory asset for nuclear decommissioning.

Unrealized gains for the nuclear decommissioning fund were $335.3 million and $312.1 million at June 30, 2015 and Dec. 31, 2014, respectively, and unrealized losses and amounts recorded as other-than-temporary impairments were $31.4 million and $74.1 million at June 30, 2015 and Dec. 31, 2014, 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, 2015 and Dec. 31, 2014:
 
 
June 30, 2015
 
 
 
 
Fair Value
 
 
(Thousands of Dollars)
 
Cost
 
Level 1
 
Level 2
 
Level 3
 
Total
Nuclear decommissioning fund (a)
 
 
 
 
 
 
 
 
 
 
Cash equivalents
 
$
12,446

 
$
12,446

 
$

 
$

 
$
12,446

Commingled funds
 
451,398

 

 
499,782

 

 
499,782

International equity funds
 
123,123

 

 
121,502

 

 
121,502

Private equity investments
 
95,067

 

 

 
133,993

 
133,993

Real estate
 
49,369

 

 

 
70,834

 
70,834

Debt securities: