Attached files

file filename
EX-32.01 - EXHIBIT 32.01 - XCEL ENERGY INCxcelex3201q32015.htm
EX-99.01 - EXHIBIT 99.01 - XCEL ENERGY INCxcelex9901q32015.htm
EX-31.01 - EXHIBIT 31.01 - XCEL ENERGY INCxcelex3101q32015.htm
EX-31.02 - EXHIBIT 31.02 - XCEL ENERGY INCxcelex3102q32015.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 Sept. 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 October 26, 2015
Common Stock, $2.50 par value
 
507,496,978 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 Sept. 30
 
Nine Months Ended Sept. 30
 
2015
 
2014
 
2015
 
2014
Operating revenues
 
 
 
 
 
 
 
Electric
$
2,667,480

 
$
2,616,351

 
$
7,105,803

 
$
7,215,699

Natural gas
216,019

 
236,649

 
1,216,146

 
1,485,464

Other
17,813

 
16,807

 
56,716

 
56,344

Total operating revenues
2,901,312

 
2,869,807

 
8,378,665

 
8,757,507

 
 
 
 
 
 
 
 
Operating expenses
 
 
 
 
 
 
 
Electric fuel and purchased power
1,014,726

 
1,079,855

 
2,869,563

 
3,188,498

Cost of natural gas sold and transported
66,071

 
99,344

 
665,109

 
934,073

Cost of sales — other
8,203

 
8,012

 
26,416

 
24,783

Operating and maintenance expenses
565,984

 
568,391

 
1,746,093

 
1,714,138

Conservation and demand side management program expenses
57,314

 
75,172

 
165,260

 
223,552

Depreciation and amortization
280,121

 
255,395

 
827,821

 
756,645

Taxes (other than income taxes)
123,081

 
117,958

 
389,438

 
358,938

Loss on Monticello life cycle management/extended power uprate project

 

 
129,463

 

Total operating expenses
2,115,500

 
2,204,127

 
6,819,163

 
7,200,627

 
 
 
 
 
 
 
 
Operating income
785,812

 
665,680

 
1,559,502

 
1,556,880

 
 
 
 
 
 
 
 
Other income, net
1,626

 
1,404

 
5,748

 
4,687

Equity earnings of unconsolidated subsidiaries
8,162

 
7,401

 
24,360

 
22,650

Allowance for funds used during construction — equity
15,427

 
23,337

 
40,728

 
68,852

 
 
 
 
 
 
 
 
Interest charges and financing costs
 
 
 
 
 
 
 
Interest charges — includes other financing costs of $6,260,
$5,737, $17,819 and $17,144, respectively
152,566

 
143,219

 
441,728

 
421,713

Allowance for funds used during construction — debt
(7,031
)
 
(9,948
)
 
(19,340
)
 
(29,609
)
Total interest charges and financing costs
145,535

 
133,271

 
422,388

 
392,104

 
 
 
 
 
 
 
 
Income before income taxes
665,492

 
564,551

 
1,207,950

 
1,260,965

Income taxes
239,029

 
195,969

 
432,490

 
435,998

Net income
$
426,463

 
$
368,582

 
$
775,460

 
$
824,967

 
 
 
 
 
 
 
 
Weighted average common shares outstanding:
 
 
 
 
 
 
 
Basic
508,031

 
506,082

 
507,585

 
502,983

Diluted
508,427

 
506,365

 
507,976

 
503,213

 
 
 
 
 
 
 
 
Earnings per average common share:
 
 
 
 
 
 
 
Basic
$
0.84

 
$
0.73

 
$
1.53

 
$
1.64

Diluted
0.84

 
0.73

 
1.53

 
1.64

 
 
 
 
 
 
 
 
Cash dividends declared per common share
$
0.32

 
$
0.30

 
$
0.96

 
$
0.90

 
 
 
 
 
 
 
 
See Notes to Consolidated Financial Statements


3


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

 
Three Months Ended Sept. 30
 
Nine Months Ended Sept. 30
 
2015
 
2014
 
2015
 
2014
Net income
$
426,463

 
$
368,582

 
$
775,460

 
$
824,967

 
 
 
 
 
 
 
 
Other comprehensive income
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Pension and retiree medical benefits:
 
 
 
 
 
 
 
Amortization of losses included in net periodic benefit cost,
net of tax of $559, $567, $1,689 and $1,666, respectively
884

 
847

 
2,643

 
2,575

 
 
 
 
 
 
 
 
Derivative instruments:
 
 
 
 
 
 
 
Net fair value decrease, net of tax of $(28), $(27), $(24)
   and $(22), respectively
(42
)
 
(42
)
 
(35
)
 
(34
)
Reclassification of losses to net income, net of tax of
   $446, $393, $1,210 and $1,115, respectively
706

 
558

 
1,891

 
1,693

 
664

 
516

 
1,856

 
1,659

Marketable securities:


 
 
 
 
 
 
Net fair value (decrease) increase, net of tax of $0, $1, $1
  and $26, respectively
(1
)
 
2

 
1

 
40

 
 
 
 
 
 
 
 
Other comprehensive income
1,547

 
1,365

 
4,500

 
4,274

Comprehensive income
$
428,010

 
$
369,947

 
$
779,960

 
$
829,241

 
 
 
 
 
 
 
 
See Notes to Consolidated Financial Statements




4


XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
(amounts in thousands)
 
Nine Months Ended Sept. 30
 
2015
 
2014
Operating activities
 
 
 
Net income
$
775,460

 
$
824,967

Adjustments to reconcile net income to cash provided by operating activities:
 
 
 
Depreciation and amortization
841,360

 
769,706

Conservation and demand side management program amortization
4,063

 
4,582

Nuclear fuel amortization
82,627

 
92,278

Deferred income taxes
429,091

 
433,224

Amortization of investment tax credits
(4,151
)
 
(4,329
)
Allowance for equity funds used during construction
(40,728
)
 
(68,852
)
Equity earnings of unconsolidated subsidiaries
(24,360
)
 
(22,650
)
Dividends from unconsolidated subsidiaries
29,434

 
27,130

Share-based compensation expense
29,765

 
16,536

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

 

Net realized and unrealized hedging and derivative transactions
18,808

 
(1,354
)
Changes in operating assets and liabilities:
 
 
 
Accounts receivable
85,276

 
(16,080
)
Accrued unbilled revenues
182,425

 
112,406

Inventories
(47,659
)
 
(57,677
)
Other current assets
72,445

 
(25,901
)
Accounts payable
(116,137
)
 
(155,788
)
Net regulatory assets and liabilities
116,068

 
162,134

Other current liabilities
60,293

 
14,683

Pension and other employee benefit obligations
(82,013
)
 
(111,463
)
Change in other noncurrent assets
2,374

 
44,009

Change in other noncurrent liabilities
(53,982
)
 
(33,220
)
Net cash provided by operating activities
2,489,922

 
2,004,341

 
 
 
 
Investing activities
 
 
 
Utility capital/construction expenditures
(2,186,369
)
 
(2,301,339
)
Proceeds from insurance recoveries
27,237

 
6,000

Allowance for equity funds used during construction
40,728

 
68,852

Purchases of investments in external decommissioning fund
(773,260
)
 
(499,493
)
Proceeds from the sale of investments in external decommissioning fund
753,924

 
494,554

Investment in WYCO Development LLC
(832
)
 
(2,220
)
Other, net
(676
)
 
(1,110
)
Net cash used in investing activities
(2,139,248
)
 
(2,234,756
)
 
 
 
 
Financing activities
 
 
 
Repayments of short-term borrowings, net
(955,500
)
 
(62,000
)
Proceeds from issuance of long-term debt
1,627,190

 
837,794

Repayments of long-term debt
(250,644
)
 
(275,708
)
Proceeds from issuance of common stock
5,298

 
178,639

Dividends paid
(452,217
)
 
(417,586
)
Net cash (used in) provided by financing activities
(25,873
)
 
261,139

 
 
 
 
Net change in cash and cash equivalents
324,801

 
30,724

Cash and cash equivalents at beginning of period
79,608

 
107,144

Cash and cash equivalents at end of period
$
404,409

 
$
137,868

 
 
 
 
Supplemental disclosure of cash flow information:
 
 
 
Cash paid for interest (net of amounts capitalized)
$
(424,878
)
 
$
(407,186
)
Cash received (paid) for income taxes, net
57,632

 
(4,950
)
 
 
 
 
Supplemental disclosure of non-cash investing and financing transactions:
 
 
 
Property, plant and equipment additions in accounts payable
$
284,864

 
$
407,706

Issuance of common stock for reinvested dividends and 401(k) plans
39,169

 
42,772

 
 
 
 
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)

 
Sept. 30, 2015
 
Dec. 31, 2014
Assets
 
 
 
Current assets
 
 
 
Cash and cash equivalents
$
404,409

 
$
79,608

Accounts receivable, net
741,230

 
826,506

Accrued unbilled revenues
546,067

 
728,492

Inventories
644,963

 
597,183

Regulatory assets
347,122

 
444,058

Derivative instruments
48,110

 
85,723

Deferred income taxes
352,712

 
246,210

Prepaid taxes
117,012

 
185,488

Prepayments and other
142,797

 
171,112

Total current assets
3,344,422

 
3,364,380

 
 
 
 
Property, plant and equipment, net
29,828,609

 
28,756,916

 
 
 
 
Other assets
 
 
 
Nuclear decommissioning fund and other investments
1,807,692

 
1,832,640

Regulatory assets
2,812,172

 
2,774,216

Derivative instruments
54,743

 
53,775

Other
182,058

 
175,957

Total other assets
4,856,665

 
4,836,588

Total assets
$
38,029,696

 
$
36,957,884

 
 
 
 
Liabilities and Equity
 
 
 
Current liabilities
 
 
 
Current portion of long-term debt
$
457,474

 
$
257,726

Short-term debt
64,000

 
1,019,500

Accounts payable
924,260

 
1,173,006

Regulatory liabilities
365,853

 
410,729

Taxes accrued
379,103

 
396,615

Accrued interest
143,124

 
158,536

Dividends payable
162,324

 
151,720

Derivative instruments
27,303

 
21,632

Other
561,579

 
475,119

Total current liabilities
3,085,020

 
4,064,583

 
 
 
 
Deferred credits and other liabilities
 
 
 
Deferred income taxes
6,390,162

 
5,852,988

Deferred investment tax credits
69,545

 
73,696

Regulatory liabilities
1,169,294

 
1,163,429

Asset retirement obligations
2,550,930

 
2,446,631

Derivative instruments
173,588

 
183,936

Customer advances
228,479

 
256,945

Pension and employee benefit obligations
863,645

 
936,907

Other
263,452

 
264,653

Total deferred credits and other liabilities
11,709,095

 
11,179,185

 
 
 
 
Commitments and contingencies


 


Capitalization
 
 
 
Long-term debt
12,690,751

 
11,499,634

Common stock — 1,000,000,000 shares authorized of $2.50 par value; 507,267,264 and
505,733,267 shares outstanding at Sept. 30, 2015 and Dec. 31, 2014, respectively
1,268,168

 
1,264,333

Additional paid in capital
5,873,440

 
5,837,330

Retained earnings
3,506,861

 
3,220,958

Accumulated other comprehensive loss
(103,639
)
 
(108,139
)
Total common stockholders’ equity
10,544,830

 
10,214,482

Total liabilities and equity
$
38,029,696

 
$
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 Sept. 30, 2015 and 2014
 
 
 
 
 
 
 
 
 
 
Balance at June 30, 2014
505,106

 
$
1,262,764

 
$
5,799,968

 
$
2,961,406

 
$
(103,366
)
 
$
9,920,772

Net income


 


 


 
368,582

 


 
368,582

Other comprehensive income


 


 


 


 
1,365

 
1,365

Dividends declared on common stock


 


 


 
(152,601
)
 


 
(152,601
)
Issuances of common stock
318

 
796

 
9,135

 


 


 
9,931

Share-based compensation


 


 
6,611

 


 


 
6,611

Balance at Sept. 30, 2014
505,424

 
$
1,263,560

 
$
5,815,714

 
$
3,177,387

 
$
(102,001
)
 
$
10,154,660

 
 
 
 
 
 
 
 
 
 
 
 
Balance at June 30, 2015
506,959

 
$
1,267,398

 
$
5,863,209

 
$
3,243,645

 
$
(105,186
)
 
$
10,269,066

Net income


 


 


 
426,463

 


 
426,463

Other comprehensive income


 


 


 


 
1,547

 
1,547

Dividends declared on common stock


 


 


 
(163,247
)
 


 
(163,247
)
Issuances of common stock
308

 
770

 
8,665

 


 


 
9,435

Share-based compensation


 


 
1,566

 


 


 
1,566

Balance at Sept. 30, 2015
507,267

 
$
1,268,168

 
$
5,873,440

 
$
3,506,861

 
$
(103,639
)
 
$
10,544,830

 
 
 
 
 
 
 
 
 
 
 
 
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
 
 
 
Nine Months Ended Sept. 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
 
 
 
 
 
 
824,967

 
 
 
824,967

Other comprehensive income
 
 
 
 
 
 
 
 
4,274

 
4,274

Dividends declared on common stock
 
 
 
 
 
 
(455,563
)
 
 
 
(455,563
)
Issuances of common stock
7,452

 
18,631

 
175,960

 
 
 
 
 
194,591

Share-based compensation
 
 
 
 
20,441

 
 
 
 
 
20,441

Balance at Sept. 30, 2014
505,424

 
$
1,263,560

 
$
5,815,714

 
$
3,177,387

 
$
(102,001
)
 
$
10,154,660

 
 
 
 
 
 
 
 
 
 
 
 
Balance at Dec. 31, 2014
505,733

 
$
1,264,333

 
$
5,837,330

 
$
3,220,958

 
$
(108,139
)
 
$
10,214,482

Net income
 
 
 
 
 
 
775,460

 
 
 
775,460

Other comprehensive income
 
 
 
 
 
 
 
 
4,500

 
4,500

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

 
3,835

 
18,874

 
 
 
 
 
22,709

Share-based compensation
 
 
 
 
17,236

 
 
 
 
 
17,236

Balance at Sept. 30, 2015
507,267

 
$
1,268,168

 
$
5,873,440

 
$
3,506,861

 
$
(103,639
)
 
$
10,544,830

 
 
 
 
 
 
 
 
 
 
 
 
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 Sept. 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 nine months ended Sept. 30, 2015 and 2014; and its cash flows for the nine months ended Sept. 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 Sept. 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 does not expect the implementation of ASU 2015-02 to have a material impact on its consolidated financial statements.

Presentation of Debt Issuance Costs In April 2015, the FASB issued Simplifying the Presentation of Debt Issuance Costs, Subtopic 835-30 (ASU No. 2015-03), which 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 (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)
 
Sept. 30, 2015
 
Dec. 31, 2014
Accounts receivable, net
 
 
 
 
Accounts receivable
 
$
793,188

 
$
884,225

Less allowance for bad debts
 
(51,958
)
 
(57,719
)
 
 
$
741,230

 
$
826,506

(Thousands of Dollars)
 
Sept. 30, 2015
 
Dec. 31, 2014
Inventories
 
 
 
 
Materials and supplies
 
$
291,301

 
$
244,099

Fuel
 
212,728

 
183,249

Natural gas
 
140,934

 
169,835

 
 
$
644,963

 
$
597,183

(Thousands of Dollars)
 
Sept. 30, 2015
 
Dec. 31, 2014
Property, plant and equipment, net
 
 
 
 
Electric plant
 
$
35,022,960

 
$
33,203,139

Natural gas plant
 
4,818,049

 
4,643,452

Common and other property
 
1,615,290

 
1,611,486

Plant to be retired (a)
 
42,336

 
71,534

Construction work in progress
 
1,679,178

 
2,005,531

Total property, plant and equipment
 
43,177,813

 
41,535,142

Less accumulated depreciation
 
(13,724,333
)
 
(13,168,418
)
Nuclear fuel
 
2,414,986

 
2,347,422

Less accumulated amortization
 
(2,039,857
)
 
(1,957,230
)
 
 
$
29,828,609

 
$
28,756,916


(a)
PSCo’s Cherokee Unit 3 was retired in August 2015. In 2017, PSCo expects to both early retire Valmont Unit 5 and convert Cherokee Unit 4 from a coal-fueled generating facility to natural gas, as approved by the Colorado Public Utilities Commission (CPUC). 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. 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 Sept. 30, 2015, the IRS had proposed an adjustment to the federal tax loss carryback claims that would result in $13 million of income tax expense for the 2009 through 2011 claims, the recently filed 2013 claim, and the anticipated claim for 2014. As of Sept. 30, 2015, the IRS had begun the appeals process; however, the outcome and timing of a resolution is uncertain. The statute of limitations applicable to Xcel Energy’s 2009-2011 federal income tax returns expires in December 2016 following an extension to allow additional time for the appeals process. In the third quarter of 2015, the IRS commenced an examination of tax years 2012 and 2013. As of Sept. 30, 2015, the IRS had not proposed any material adjustments to tax years 2012 and 2013.

State Audits  Xcel Energy files consolidated state tax returns based on income in its major operating jurisdictions of Colorado, Minnesota, Texas, and Wisconsin, and various other state income-based tax returns. As of Sept. 30, 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
 
2011


10


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

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

A reconciliation of the amount of unrecognized tax benefit is as follows:
(Millions of Dollars)
 
Sept. 30, 2015
 
Dec. 31, 2014
Unrecognized tax benefit — Permanent tax positions
 
$
15.8

 
$
16.2

Unrecognized tax benefit — Temporary tax positions
 
60.6

 
50.3

Total unrecognized tax benefit
 
$
76.4

 
$
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)
 
Sept. 30, 2015
 
Dec. 31, 2014
NOL and tax credit carryforwards
 
$
(39.2
)
 
$
(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 and audit progress 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 Sept. 30, 2015 and Dec. 31, 2014 were not material. No amounts were accrued for penalties related to unrecognized tax benefits as of Sept. 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 the consolidated financial statements included in Xcel Energy Inc.’s Quarterly Reports on Form 10-Q for the quarterly periods ended March 31, 2015 and June 30, 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 $166.1 million, or 5.9 percent, consisting of $58.9 million and $125.2 million in 2014 and 2015, respectively, and an $18.0 million adjustment related to disallowance of certain Monticello Life Cycle Management (LCM)/Extended Power Uprate (EPU) costs. 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 and determined the Monticello EPU project was not yet used-and-useful, as final approval related to the full EPU uprate condition had not been received from the Nuclear Regulatory Commission (NRC) as of June 30, 2015.  As a result, $13.8 million was excluded from final rates. Monticello subsequently received final NRC compliance approval in July 2015. 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 decisions resulted in a total estimated 2014 and 2015 annual rate increase of $149.4 million, or 5.3 percent.

The following table outlines the impact of the MPUC’s July decision:
(Millions of Dollars)
 
MPUC July Decision
2014 and 2015 step 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 2014 and 2015 step increase
 
$
149.4

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


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 megawatts (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 – 2016 Transmission Cost Recovery (TCR) Rate Filing — In October 2015, NSP-Minnesota submitted its 2016 TCR filing with the MPUC, requesting recovery of $19.2 million of 2016 transmission investment costs not included in electric base rates. The 2016 TCR rider filing includes an option to keep within the TCR rider approximately $59.1 million of revenue requirements associated with two CapX2020 projects completed in 2015 or to include these revenue requirements in electric base rates during the interim rate implementation of the next electric rate case. If the MPUC opts to maintain the projects in the rider, the TCR rider revenue requirements would increase to $78.3 million.

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

NSP-Minnesota – South Dakota Infrastructure Rider — In October 2015, NSP-Minnesota filed its 2016 infrastructure rider filing with the SDPUC, requesting approval for recovery of $10.3 million in 2016 revenue requirements for rates effective Jan. 1, 2016. As part of the South Dakota 2015 electric rate case, the infrastructure rider was refreshed with new projects and was also expanded as a mechanism to allow for possible recovery of other investments related to generation, transmission, and distribution. A SDPUC decision is expected in the fourth quarter of 2015.


12


NSP-Wisconsin

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

Wisconsin 2016 Electric and Gas Rate Case — In May 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 ROE 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.

On Oct. 1, 2015, the PSCW Staff and other intervenors, including the Citizens Utility Board, filed their direct testimony in the case. The PSCW Staff recommended an electric rate increase of $10.4 million, or 1.5 percent, and a gas rate increase of $3.0 million, or 2.5 percent, based on a ROE of 10.0 percent and an equity ratio of 52.5 percent. The Citizens Utility Board recommended a ROE of 8.75 percent. None of the intervenors presented a complete revenue requirements analysis. The majority of the PSCW Staff adjustments relate to ROE, compensation issues and capital related forecast disputes.

Key dates in the procedural schedule are as follows:

Initial Brief — Nov. 12, 2015;
Reply Brief — Nov. 19, 2015;
A PSCW decision is anticipated in December 2015; and
New rates effective on or about Jan. 1, 2016.

PSCo

Pending Regulatory Proceedings — 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 (MYP) and an equity ratio of 56 percent. The rate case requests a 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



13


In June 2015, the CPUC Staff (Staff) and the Office of Consumer Counsel (OCC) issued their 2015 base rate recommendations. The following table reflects the current positions of Staff and OCC:
(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 HTY
 
(10.5
)
 
(16.4
)
Operating and maintenance (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


In July 2015, PSCo filed rebuttal testimony, maintaining its request for a multi-year plan and requested ROEs and reflecting the most recent sales forecast. 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.

Interim rates, subject to refund, were also implemented, effective Oct. 1, 2015, based on PSCo’s direct testimony. PSCo is expecting the ALJ’s Recommended Decision in November 2015. The final CPUC decision is expected no later than January 2016.

PSCo Annual Electric Earnings Test — 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 Sept. 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.


14


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. For the years 2015 through 2020, the annual electric energy savings goal is 400 GWh per year with an annual earnings limit of $84.3 million.

In July 2015, the CPUC approved PSCo’s 2015-2016 DSM plan:

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.

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 June 2015, SPS filed rebuttal testimony supporting a revised rate increase of approximately $42.1 million, or 4.4 percent.

On Oct. 12, 2015, the administrative law judges (ALJs) issued their Proposal for Decision (PFD) and recommended a rate increase of approximately $1.2 million, based on a ROE of 9.70 percent and an equity ratio of 53.97 percent.

The following table reflects the positions of Alliance of Xcel Municipalities (AXM), the Office of Public Utility Counsel (OPUC), the PUCT Staff (Staff), SPS as well as the estimated recommendation of the ALJs:
 
 
 
 
 
 
 
 
SPS Rebuttal Testimony
 
ALJs’ PFD (a)
(Millions of Dollars)
 
AXM
 
OPUC
 
Staff
 
 
SPS’ revised rate request
 
$
58.9

 
$
58.9

 
$
58.9

 
$
58.9

 
$
42.1

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

 
(16.7
)
Lower ROE
 
(10.9
)
 
(13.5
)
 
(12.1
)
 

 
(6.3
)
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
)
 
(5.3
)
Depreciation expense
 
(13.3
)
 

 

 

 
(3.9
)
Property taxes
 

 
(1.2
)
 
(4.4
)
 
(1.8
)
 
(3.7
)
Revenue adjustments
 
(2.2
)
 
(0.2
)
 

 

 

Wholesale load reductions
 
(13.2
)
 

 
(11.1
)
 

 

Southwest Power Pool (SPP) transmission expansion plan
 

 

 

 
(7.3
)
 
(4.2
)
Other, net
 
(1.7
)
 
(0.6
)
 
(2.2
)
 
(1.8
)
 
(0.6
)
Total recommendation
 
$
(13.6
)
 
$
1.8

 
$
(2.6
)
 
$
46.4

 
$
1.4

Adjustment to move rate case expenses to a separate docket
 

 

 

 
(4.3
)
 
(0.2
)
Recommendation, excluding rate case expenses
 
$
(13.6
)
 
$
1.8

 
$
(2.6
)
 
$
42.1

 
$
1.2


(a) The ALJs’ recommendation reflects proposed adjustments to SPS’ rebuttal testimony, as of Oct. 12, 2015, which supports a $42.1 million rate increase.


15


SPS subsequently filed a letter notifying the PUCT it had concerns regarding the calculation. On Oct. 28, 2015, the Staff issued a revised calculation reflecting corrections to the PFD. The ALJs’ revised recommended rate increase is $14.4 million.

New rates will be made effective retroactive to June 11, 2015 as established by the PUCT. A PUCT decision is expected in December 2015.

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

SPS – New Mexico 2015 Electric Rate Case — In October 2015, SPS filed an electric rate case with the NMPRC for a net increase in base rates of approximately $24.3 million for the New Mexico retail jurisdiction. The proposed net amount reflects an increase in non-fuel base rates of $45.4 million and a decrease in base fuel revenue of approximately $21.1 million. The decrease in base fuel revenue will be reflected in adjustments collected through the fuel and purchased power adjustment clause. The rate filing is based on a June 30, 2015 HTY adjusted for known and measurable changes, a requested ROE of 10.25 percent, an electric jurisdictional rate base of approximately$734 million and an equity ratio of 53.97 percent.

The major components of the requested rate increase are summarized below:
(Millions of Dollars)
 
Request
2015 base period deficiency
 
$
19.7

Capital expenditures  post-test year adjustments
 
12.3

Depreciation, higher rates reflecting changes in depreciable lives, interim retirements and net salvage
 
3.7

Transmission revenue and expense, including charges paid to SPP for construction of regionally shared transmission projects
 
2.0

ROE, reflecting an increase from 9.96 percent to 10.25 percent
 
1.6

Rider revenue adjustments - gross receipts tax
 
1.3

Other, net
 
4.8

Requested rate increase
 
$
45.4


A NMPRC decision and implementation of final rates is anticipated in the second half of 2016. In June 2015, the NMPRC dismissed a rate case filing using a future test year based on new precedent. SPS has appealed that decision to the New Mexico Supreme Court.

Pending and Recently Concluded Regulatory Proceedings — Federal Energy Regulatory Commission (FERC)

Midcontinent Independent System Operator, Inc. (MISO) ROE Complaints/ROE Adder — In November 2013, a group of customers filed a complaint at the FERC against certain 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.

Subsequently, the FERC issued and upheld 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 ROE complaint was set for full hearing procedures. The complainants and intervenors filed testimony recommending a ROE between 8.67 percent and 9.54 percent. The FERC staff recommended a ROE of 8.68 percent. The MISO TOs recommended a ROE not less than 10.8 percent. An ALJ initial decision is anticipated to be issued by November 2015 and a FERC order is expected to be issued no earlier than 2016.

Certain MISO TOs requested FERC approval of a 50 basis point RTO membership ROE adder, which was approved effective Jan. 6, 2015, 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. Certain intervenors sought rehearing of the FERC order granting the ROE adder; FERC action is pending.


16


Certain intervenors filed a second complaint in February 2015 to reduce the MISO region ROE to 8.67 percent, prior to an adder.  A hearing has been set, and a refund effective date of Feb. 12, 2015 was established. The complainants and intervenors filed direct testimony in September 2015 recommending ROEs between 8.72 percent and 9.13 percent. The MISO TOs filed answering testimony on Oct. 20, 2015, recommending a ROE of not less than 10.75 percent. FERC staff is expected to file testimony in November 2015, and a hearing is scheduled for February 2016. An ALJ initial decision is expected in June 2016 with a FERC decision in late 2016 or in 2017. Currently, the ROE refund obligation initiated under the November 2013 complaint is effective through May 2016. The MISO TOs sought rehearing of the FERC decision to allow back-to-back complaints. NSP-Minnesota and NSP-Wisconsin sought rehearing of the FERC’s decision not to order changes to the ROE used by non-jurisdictional MISO transmission owners (more than 20 municipal, cooperative and other utilities who are not respondents to the ROE complaints), which equals the ROE presently used by the jurisdictional MISO TOs. FERC action is pending.

NSP-Minnesota recorded a current liability representing the current best estimate of a refund obligation associated with the new ROE as of Sept. 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 – Global Settlement Agreement — In August 2015, SPS, Golden Spread Electric Cooperative, Inc. (Golden Spread), four New Mexico Cooperatives, West Texas Municipal Power Agency (WTMPA), Public Service Company of New Mexico (PNM) and Tri-County Electric Cooperative, Inc. (Tri-County) filed a settlement agreement with the FERC that would provide a comprehensive resolution of nine pending matters in dispute between SPS and these wholesale production and transmission customers, including the 2004 FERC Complaint Case, the Wholesale Rate Complaints, the 2015 Formula Rate Change Filing and the Sale of Texas Transmission Assets as discussed below. Key terms of the settlement agreement include:

A settlement payment to Golden Spread for $44.9 million and withdrawal of the SPS and the New Mexico Cooperatives’ requests for rehearing of the August 2013 FERC order ruling that SPS is a 3 coincident peak (CP) system;
A settlement payment to PNM of $4.2 million and the withdrawal of the PNM request for rehearing of the August 2013 FERC order denying PNM’s challenge to the 2008 FERC ruling regarding SPS’ fuel cost adjustment practices;
Withdrawal of the Golden Spread Wholesale Rate Complaints, resulting in no change to the then-effective production and transmission ROEs for the period April 20, 2012 through Oct. 19, 2014, and withdrawal of the SPS appeal of the FERC orders in those proceedings to the United States District Court of Appeals for the District of Columbia Circuit (D.C. Circuit);
A reduction in the SPS transmission ROE to 10.5 percent (including the 50 basis point SPP regional transmission organization membership adder) and the production ROE in the Golden Spread and New Mexico Cooperatives production formula rates to 10.0 percent effective Oct. 20, 2014, and establishment of a limited moratorium that precludes any increase or decrease in these effective ROEs through 2019;
Utilization of the 12 CP production cost allocation methodology in the Golden Spread, New Mexico Cooperatives and WTMPA production formula rates and a moratorium precluding all settlement parties from seeking to change from the 12 CP methodology during the remaining term of the Golden Spread production contract (currently scheduled to expire in May 2019);
SPS agrees to reduce its production formula rates retroactive to Jan. 1, 2015 to reflect full year implementation of reduced depreciation and certain other costs; the FERC had allowed these reductions to be effective July 1, 2015;
SPS agrees to make certain revisions to its transmission formula rate, effective Jan. 1, 2016, to provide for a sharing of the wholesale portion of any gain on a future sale of transmission assets; other parties agree not to challenge the non-sharing of the gain SPS recorded on prior and current transmission asset transactions with Sharyland Distribution and Transmission Services, LLC (Sharyland) and Oncor Electric Delivery Company LLC;
SPS agrees not to file with FERC to increase transmission depreciation rate rates effective prior to Jan. 1, 2017; and
SPS agrees not to transfer Tri-County from its current stated rate production service agreement to a production formula rate effective prior to Jan. 1, 2017. Tri-County agrees that it will not contest implementation of the formula rate as of that date.

On Oct. 29, 2015, the FERC issued an order approving the settlement agreement. The terms are effective 30 days after issuance. As a result of the settlement, SPS expects to recognize a net gain of approximately $7.9 million in the fourth quarter of 2015. The settlement also resolves the following:

2004 FERC Complaint Case Orders — In August 2013, the FERC issued an order related to a 2004 complaint case brought by Golden Spread, a wholesale cooperative customer, and PNM, a former wholesale customer, and also issued an Order on Initial Decision in a subsequent 2006 production rate case filed by SPS.

The original complaints included two key components: 1) a base rate complaint, including the appropriate demand-related CP cost allocator; and 2) a claim regarding alleged inappropriate fuel cost adjustment practices. The FERC had determined in April 2008 that the demand-related cost allocator and fuel cost adjustment practices utilized by SPS were appropriate.


17


In the August 2013 Orders, the FERC 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 CP rather than a 12 CP system. The FERC also clarified its previous ruling on fuel cost adjustment practices and reaffirmed that the refunds in question should only apply to firm requirements customers.

In September 2013, SPS, the New Mexico Cooperatives and PNM each filed requests for rehearing of the FERC ruling on the CP allocation and/or refund decision. As of Dec. 31, 2014, SPS had accrued $50.4 million related to the August 2013 Orders and an additional $1.9 million of principal and interest has been accrued during 2015.

Wholesale Rate Complaints — In April 2012, Golden Spread 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 formula rate ROE of 11.27 percent are unjust and unreasonable, and requested that the base 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 base ROE in the SPS production formula rate for Golden Spread and transmission formula rates be reduced to 9.15 percent and 9.65 percent, respectively, effective July 19, 2013. In June 2014, the FERC issued orders consolidating these ROE complaints, setting the complaints for hearing procedures and granting the complainant’s requested refund effective dates. SPS subsequently sought rehearing. In May 2015, FERC denied rehearing. In July 2015, SPS appealed the FERC orders to the D.C. Circuit.

A third ROE rate complaint was filed in October 2014 by Golden Spread, along with the New Mexico Cooperatives and WTMPA, requesting that the ROE in the SPS production formula rates for Golden Spread and the New Mexico Cooperatives and SPS transmission formula rate, be reduced 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. SPS subsequently sought rehearing. FERC has not acted on the SPS rehearing request.

2015 Formula Rate Change Filing — In January 2015, SPS filed to revise the production formula rates for Golden Spread, the four New Mexico Cooperatives and WTMPA, effective Feb. 1, 2015. The filing proposed several modifications, including a reduction in wholesale depreciation rates and the use of a 12 CP demand-related cost allocator for all wholesale customers. On March 31, 2015, the FERC accepted this filing, effective July 1, 2015, subject to refund and settlement judge or hearing procedures.

Sale of Texas Transmission Assets — In March 2013, SPS reached an agreement to sell certain segments of SPS’ transmission lines and two related substations to Sharyland. In 2013, SPS received all necessary regulatory approvals for the transaction. In December 2013, SPS received $37.1 million and recognized a pre-tax gain of $13.6 million and regulatory liabilities for retail jurisdictional gain sharing of $7.2 million. The gain is reflected in the consolidated statement of income as a reduction to O&M expenses. In December 2014, Golden Spread submitted a preliminary challenge under the SPS transmission formula rate procedures asserting the gain should be shared with wholesale transmission customers. SPS disputed this claim. In October 2015, the FERC denied rehearing on the matter.

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 Reports on Form 10-Q for the quarterly periods ended March 31, 2015 and June 30, 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 Sept. 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.


18


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 Sept. 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)
 
Sept. 30, 2015
 
Dec. 31, 2014
Guarantees issued and outstanding
 
$
12.9

 
$
13.9

Current exposure under these guarantees
 
0.1

 
0.2

Bonds with indemnity protection
 
42.5

 
31.4


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 where NSP-Wisconsin believes wood treating operations were conducted; 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.


19


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. In fall 2015, the ground water remedy was initiated at the site with the installation of groundwater wells and the start of construction on the groundwater treatment plant. The final design for the Phase I remedy was approved by the EPA in September 2015. The current cost estimate for the cleanup of the Phase I Project Area is approximately $57 million, of which approximately $39 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 (AOC) for the Wet Dredge pilot study with the EPA. In early 2015, NSP-Wisconsin entered into an AOC to construct a breakwater at the site to serve as wave attenuation and containment for a wet dredge pilot study and full scale sediment remedy at the site. Construction of the breakwater is underway with anticipated completion in early 2016. A wet dredge pilot study is anticipated to commence in summer 2016.

In August 2012, NSP-Wisconsin also filed litigation against other PRPs for their share of the cleanup costs for the Ashland site. 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 entered into 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. Trial with the remaining PRPs for this matter, County of Ashland and City of Ashland, took place in May 2015. In September 2015, the Court ruled that the County of Ashland is not a liable party and the City of Ashland, although a liable party, is not required to contribute any funds to the cleanup of the site. NSP-Wisconsin filed a notice of appeal with the Seventh Circuit Court of Appeals in October 2015.

At Sept. 30, 2015 and Dec. 31, 2014, NSP-Wisconsin had recorded a liability of $95.7 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 $16.6 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 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.


20


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 through 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 December 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. NSP-Minnesota is undertaking further investigation of the location of the historic MGP site and nearby properties. At this time, NSP-Minnesota’s investigation of the site is considered preliminary as information is still being gathered.

As of Sept. 30, 2015, NSP-Minnesota had recorded a liability of $1.4 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.

Environmental Requirements

Water
Federal Clean Water Act (CWA) Effluent Limitations Guidelines (ELG) — In September 2015, the EPA issued a final ELG rule for power plants that use coal, natural gas, oil or nuclear materials as fuel and discharge treated effluent to surface waters as well as utility-owned landfills that receive coal combustion residuals. Xcel Energy is currently reviewing the final rule and cannot predict, at this time, whether the costs of compliance with the final rule will have a material impact on the results of operations, financial position or cash flows. Xcel Energy believes that compliance costs would be recoverable through regulatory mechanisms.

Federal 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 went into effect in August 2015. On Oct. 9, 2015, the U.S. Court of Appeals for the Sixth Circuit issued a nationwide stay of the final rule, pending further legal proceedings.

Air
Green House Gas (GHG) Emission Standard for Existing Sources — In June 2014, the EPA published its proposed rule on GHG emission standards for existing power plants. A final rule was published in October 2015. States must develop implementation plans by September 2016, with the possibility of an extension to September 2018. If a state decides not to submit a plan, the EPA will prepare a federal plan for the state. In addition, the EPA published a proposed model federal plan and will provide a 90-day public comment period on the federal plan once it has been published in the Federal Register. Among other things, the rule requires that state plans include enforceable measures to ensure emissions from existing power plants in the state achieve the EPA’s state-specific interim (2022-2029) and final (2030 and thereafter) emission performance targets. The plan will likely require additional emission reductions in states in which Xcel Energy operates. Until Xcel Energy has reviewed the final rule and has more information about state implementation plans (SIPs), Xcel Energy cannot predict whether the costs of compliance with the final rule will have a material impact on the results of operations, financial position or cash flows. Xcel Energy believes that compliance costs will be recoverable through regulatory mechanisms.


21


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

GHG NSPS for Modified and Reconstructed Power Plants — In June 2014, the EPA published a proposed NSPS that would apply to GHG emissions from power plants that are modified or reconstructed. A final rule was published in October 2015. A modification is a change to an existing source that increases the maximum achievable hourly rate of emissions. A reconstruction involves the replacement of components at a unit to the extent that the capital cost of the new components exceeds 50 percent of the capital cost of an entirely new comparable unit. The standards do not require installation of CCS technology. Instead, the standard for coal-fired power plants requires a combination of best operating practices and equipment upgrades. The standards for natural gas-fired power plants require emissions standards based on efficient combined cycle technology. These requirements would only apply if Xcel Energy were to modify or reconstruct an existing power plant in the future in a way that triggers applicability of this rule.

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 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 not have a material impact on the results of operations, financial position or cash flows.

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. In June 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.


22


Industrial Boiler (IB) Maximum Achievable Control Technology (MACT) Rules — In 2011, the EPA finalized IB MACT rules to regulate boilers and process heaters fueled with coal, biomass and liquid fuels, which would apply to NSP-Wisconsin’s Bay Front Units 1 and 2. The project to meet the requirements was completed in September 2015 with an estimated cost of approximately $20 million.

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 their first regional haze SIPs, Colorado, Minnesota and Texas identified the Xcel Energy facilities that will have to reduce SO2, NOx and PM emissions under BART and set emissions limits for those facilities.

PSCo
In 2011, the Colorado Air Quality Control Commission approved a SIP (the Colorado SIP) that included the Clean Air Clean Jobs Act (CACJA) emission reduction plan as satisfying regional haze requirements for the facilities included in the CACJA plan. In addition, the Colorado SIP included a BART determination for Comanche Units 1 and 2. The EPA approved the Colorado SIP in 2012. Emission controls at Hayden Unit 1 and Hayden Unit 2 will be placed into service in late 2015 and late 2016, respectively, at an estimated combined cost of $82.4 million. PSCo anticipates these costs will be fully recoverable through regulatory mechanisms.

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. In September 2015, in response to a motion filed by WildEarth Guardians and the EPA, the 10th Circuit issued an order dismissing the case.

In 2010, two environmental groups petitioned the U.S. Department of the Interior (DOI) to certify that 12 coal-fired boilers and one coal-fired cement kiln in Colorado are contributing to visibility problems in Rocky Mountain National Park. The following PSCo plants are named in the petition: Cherokee, Hayden, Pawnee and Valmont. The groups allege 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. In October 2014, the Eighth Circuit set a briefing schedule that was completed in February 2015. The Eighth Circuit heard arguments in September 2015 and a decision is anticipated in early 2016. 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.


23


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 has indicated that it expects 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.

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. In October 2015, the EPA proposed a rule that would set the agreed-upon SO2 emission limits, which public comments due in November 2015. 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) made recommendations for unclassified and nonattainment areas to the EPA in September 2015. The EPA’s final decision is expected by summer 2016. 


24


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.

Revisions to the NAAQS for Ozone — In October 2015, the EPA revised the NAAQS for ozone by lowering the eight-hour standard from 75 parts per billion (ppb) to 70 ppb. In areas where Xcel Energy operates, current monitored air quality concentrations comply with the new standard in the Twin Cities Metropolitan Area in Minnesota and meet the 70 ppb level in the Texas panhandle. In documents issued with the new standard, the EPA projects that both areas will meet the new standard. Current monitored air quality concentrations in areas of Wisconsin, where Xcel Energy operates, are also below the new standard. The Denver Metropolitan Area is currently not meeting the prior ozone standard and will therefore not meet the new, more stringent, standard. If not in attainment, impacted areas would study the sources of nonattainment and make emission reduction plans to attain the new standards. These plans would be due to the EPA in 2020. In conjunction with CACJA, Xcel Energy has or plans to shut down coal-fired plants in the Denver area, has installed NOx controls on Pawnee and Hayden Unit 1 and will finish installing NOx controls on Hayden Unit 2 in 2016. The final designation of nonattainment areas will be made in late 2017 based on air quality data years 2014-2016. Xcel Energy cannot evaluate the impacts of this ruling in Colorado until the designation of nonattainment areas is made and any required state plan has been developed. Xcel Energy believes that, should NOx 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.

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.


25


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.

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 Benson Power, LLC (Benson Power), as assignee of Fibrominn, LLC. Under this agreement, NSP-Minnesota is charged for certain costs of transporting biomass fuels that are delivered to Benson Power’s generation facility.  Benson Power also sought additional cost reimbursement for certain transportation, handling and other costs incurred since 2007 totaling approximately $20 million. In August 2015, a settlement was reached regarding this dispute. No loss was recorded related to the terms of the settlement agreement.

Gas Trading Litigation — e prime, inc. (e prime) is a wholly owned subsidiary of Xcel Energy.  e prime was in the business of natural gas trading and marketing, but has not engaged in natural gas trading or marketing activities since 2003.  Thirteen lawsuits were commenced against e prime and Xcel Energy (and NSP-Wisconsin, in two instances) between 2003 and 2009 alleging fraud and anticompetitive activities in conspiring to restrain the trade of natural gas and manipulate natural gas prices. The cases were consolidated in U.S. District Court in Nevada.  In 2009, five of the cases were settled and one was dismissed.  The U.S. District Court in 2011 issued an order dismissing entirely six of the remaining seven lawsuits, and partially dismissing the seventh. Plaintiffs appealed the dismissals to the U.S. Court of Appeals for the Ninth Circuit, which reversed the District Court. The matter was ultimately heard by the U.S. Supreme Court in early 2015, which agreed with the Ninth Circuit and remanded the matter to the U.S. District Court. In September 2015, the District Court held a status conference and set deadlines for certain litigation related activities in 2016. A trial date has not yet been set, but is not expected to occur prior to late 2016 or early 2017. Xcel Energy and e prime have concluded that a loss is remote with respect to this matter.


26


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 Department of Energy’s (DOE) 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. 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 Sept. 30, 2015. In May 2015, NSP-Minnesota submitted a claim for an additional $13.2 million, and the DOE subsequently determined that NSP-Minnesota is entitled to reimbursement of $13.1 million. Payment of this amount is expected by the end of 2015. 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.

Other Commitments

Limited Partnership Investment — In October 2015, Energy Impact Fund Investment, LLC (Energy Impact LLC), a wholly-owned non-utility subsidiary of Xcel Energy Inc., entered into a subscription agreement for a limited partnership interest, committing Energy Impact LLC to up to $50 million of total future investments in the newly formed Energy Impact Fund Limited Partnership (Energy Impact Fund LP) over the next five years.  Along with the capital contributions of the other limited partners, who are primarily investor-owned utilities or their affiliates, the funding is expected to be used to make private equity investments in entities that are active developers and producers of new and emerging energy technologies applicable to utility operations, products and services.  Xcel Energy expects to use the equity method to account for its interest in Energy Impact Fund LP.

7.
Borrowings and Other Financing Instruments

Short-Term Borrowings

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

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

 
$
2,750

Amount outstanding at period end
 
64

 
1,020

Average amount outstanding
 
272

 
841

Maximum amount outstanding
 
478

 
1,200

Weighted average interest rate, computed on a daily basis
 
0.46
%
 
0.33
%
Weighted average interest rate at period end
 
0.38

 
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 Sept. 30, 2015 and Dec. 31, 2014, there were $39 million and $61 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.


27


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

At Sept. 30, 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

 
$
64

 
$
936

PSCo
 
700

 
5

 
695

NSP-Minnesota
 
500

 
24

 
476

SPS
 
400

 
10

 
390

NSP-Wisconsin
 
150

 

 
150

Total
 
$
2,750

 
$
103

 
$
2,647

(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 Sept. 30, 2015 and Dec. 31, 2014.

Long-Term Borrowings

During the nine months ended Sept. 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;
In June, NSP-Wisconsin issued $100 million of 3.3 percent first mortgage bonds due June 15, 2024;
In August, NSP-Minnesota issued $300 million of 2.2 percent first mortgage bonds due Aug. 15, 2020 and $300 million of 4.0 percent first mortgage bonds due Aug. 15, 2045; and
In September, SPS issued $200 million of 3.3 percent first mortgage bonds due June 15, 2024.

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.


28


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.

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.


29


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 $298.4 million and $312.1 million at Sept. 30, 2015 and Dec. 31, 2014, respectively, and unrealized losses and amounts recorded as other-than-temporary impairments were $87.3 million and $74.1 million at Sept. 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 Sept. 30, 2015 and Dec. 31, 2014:
 
 
Sept. 30, 2015
 
 
 
 
Fair Value
 
 
(Thousands of Dollars)
 
Cost
 
Level 1
 
Level 2
 
Level 3
 
Total
Nuclear decommissioning fund (a)
 
 
 
 
 
 
 
 
 
 
Cash equivalents
 
$
33,681

 
$
33,681

 
$

 
$

 
$
33,681

Commingled funds
 
351,676

 

 
381,230

 

 
381,230

International equity funds
 
217,003

 

 
188,853

 

 
188,853

Private equity investments
 
98,133

 

 

 
145,695

 
145,695

Real estate
 
49,151

 

 

 
71,976

 
71,976

Debt securities:
 


 


 


 


 


Government securities
 
24,557

 

 
21,423

 

 
21,423

U.S. corporate bonds
 
70,311

 

 
61,874

 

 
61,874

International corporate bonds
 
14,099

 

 
13,059

 

 
13,059

Municipal bonds
 
210,728

 

 
215,014

 

 
215,014

Asset-backed securities
 
2,834

 

 
2,836

 

 
2,836

Mortgage-backed securities
 
11,734

 

 
12,077

 

 
12,077

Equity securities:
 


 


 


 


 


Common stock
 
386,176

 
533,431

 

 

 
533,431

Total
 
$
1,470,083

 
$
567,112

 
$
896,366

 
$
217,671</