Table of Contents

 

 

 

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, 2009

 

or

 

o

 

TRANSITION REPORTS PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

Commission File Number: 1-3034

 

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 requirement for the past 90 days.  x Yes o 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 o 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 £
(Do not check if smaller reporting company)

 

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 Oct. 26, 2009

Common Stock, $2.50 par value

 

456,645,598 shares

 

 

 



Table of Contents

 

TABLE OF CONTENTS

 

PART I

 

FINANCIAL INFORMATION

 

 

Item 1 —

Financial Statements (unaudited)

 

 

 

CONSOLIDATED STATEMENTS OF INCOME

3

 

 

CONSOLIDATED STATEMENTS OF CASH FLOWS

4

 

 

CONSOLIDATED BALANCE SHEETS

5

 

 

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY AND COMPREHENSIVE INCOME

6

 

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

8

 

Item 2 —

Management’s Discussion and Analysis of Financial Condition and Results of Operations

38

 

Item 3 —

Quantitative and Qualitative Disclosures about Market Risk

55

 

Item 4 —

Controls and Procedures

55

PART II

 

OTHER INFORMATION

56

 

Item 1 —

Legal Proceedings

56

 

Item 1A —

Risk Factors

56

 

Item 2 —

Unregistered Sales of Equity Securities and Use of Proceeds

57

 

Item 6 —

Exhibits

58

SIGNATURES

 

 

 

 

 

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, a Colorado corporation (PSCo); and Southwestern Public Service Company, a New Mexico corporation (SPS). Additional information on the wholly owned subsidiaries is available on various filings with the Securities and Exchange Commission (SEC).

 

2



Table of Contents

 

PART I — FINANCIAL INFORMATION

Item 1 — FINANCIAL STATEMENTS

 

XCEL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

(amounts in thousands, except per share data)

 

 

 

Three Months Ended Sept. 30,

 

Nine Months Ended Sept. 30,

 

 

 

2009

 

2008

 

2009

 

2008

 

Operating revenues

 

 

 

 

 

 

 

 

 

Electric

 

$

2,128,955

 

$

2,576,467

 

$

5,749,207

 

$

6,704,164

 

Natural gas

 

169,601

 

258,961

 

1,224,161

 

1,736,701

 

Other

 

16,006

 

16,252

 

52,819

 

54,718

 

Total operating revenues

 

2,314,562

 

2,851,680

 

7,026,187

 

8,495,583

 

 

 

 

 

 

 

 

 

 

 

Operating expenses

 

 

 

 

 

 

 

 

 

Electric fuel and purchased power

 

982,103

 

1,513,935

 

2,703,952

 

3,871,437

 

Cost of natural gas sold and transported

 

71,638

 

155,804

 

809,791

 

1,298,731

 

Cost of sales — other

 

4,915

 

4,528

 

14,268

 

14,095

 

Other operating and maintenance expenses

 

466,465

 

422,560

 

1,410,760

 

1,340,362

 

Conservation and demand side management program expenses

 

47,157

 

27,483

 

133,793

 

92,278

 

Depreciation and amortization

 

198,222

 

209,131

 

609,285

 

622,512

 

Taxes (other than income taxes)

 

78,914

 

70,245

 

229,025

 

218,220

 

Total operating expenses

 

1,849,414

 

2,403,686

 

5,910,874

 

7,457,635

 

 

 

 

 

 

 

 

 

 

 

Operating income

 

465,148

 

447,994

 

1,115,313

 

1,037,948

 

 

 

 

 

 

 

 

 

 

 

Other income (expense), net

 

(977

)

9,736

 

4,394

 

27,270

 

Allowance for funds used during construction — equity

 

18,618

 

16,319

 

55,565

 

45,478

 

 

 

 

 

 

 

 

 

 

 

Interest charges and financing costs

 

 

 

 

 

 

 

 

 

Interest charges — includes other financing costs of $5,103, $5,162, $15,255 and $15,294, respectively

 

139,347

 

139,777

 

420,447

 

405,671

 

Allowance for funds used during construction — debt

 

(9,598

)

(9,625

)

(29,671

)

(28,748

)

Total interest charges and financing costs

 

129,749

 

130,152

 

390,776

 

376,923

 

 

 

 

 

 

 

 

 

 

 

Income from continuing operations before income taxes and equity earnings

 

353,040

 

343,897

 

784,496

 

733,773

 

 

 

 

 

 

 

 

 

 

 

Income taxes

 

135,610

 

121,551

 

280,581

 

252,765

 

Equity earnings of unconsolidated subsidiaries

 

4,363

 

349

 

10,760

 

1,154

 

 

 

 

 

 

 

 

 

 

 

Income from continuing operations

 

221,793

 

222,695

 

514,675

 

482,162

 

Income (loss) from discontinued operations, net of tax

 

(965

)

94

 

(2,673

)

(684

)

Net income

 

220,828

 

222,789

 

512,002

 

481,478

 

Dividend requirements on preferred stock

 

1,060

 

1,060

 

3,180

 

3,180

 

Earnings available to common shareholders

 

$

219,768

 

$

221,729

 

$

508,822

 

$

478,298

 

 

 

 

 

 

 

 

 

 

 

Weighted average common shares outstanding:

 

 

 

 

 

 

 

 

 

Basic

 

456,769

 

434,131

 

456,095

 

431,511

 

Diluted

 

457,453

 

439,397

 

456,729

 

436,716

 

 

 

 

 

 

 

 

 

 

 

Earnings per average common share:

 

 

 

 

 

 

 

 

 

Basic

 

$

0.48

 

$

0.51

 

$

1.12

 

$

1.11

 

Diluted

 

0.48

 

0.51

 

1.11

 

1.10

 

Cash dividends declared per common share

 

0.25

 

0.24

 

0.73

 

0.71

 

 

See Notes to Consolidated Financial Statements

 

3



Table of Contents

 

XCEL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

(amounts in thousands of dollars)

 

 

 

Nine Months Ended Sept. 30,

 

 

 

2009

 

2008

 

 

 

 

 

 

 

Operating activities

 

 

 

 

 

Net income

 

$

512,002

 

$

481,478

 

Remove loss from discontinued operations

 

2,673

 

684

 

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

 

 

 

 

 

Depreciation and amortization

 

644,224

 

676,691

 

Nuclear fuel amortization

 

59,520

 

46,765

 

Deferred income taxes

 

304,707

 

199,155

 

Amortization of investment tax credits

 

(5,213

)

(5,824

)

Allowance for equity funds used during construction

 

(55,565

)

(45,478

)

Equity earnings of unconsolidated subsidiaries

 

(10,760

)

(1,154

)

Dividends from equity method investees

 

20,999

 

 

Share-based compensation expense

 

13,252

 

17,961

 

Net realized and unrealized hedging and derivative transactions

 

46,298

 

(34,049

)

Changes in operating assets and liabilities:

 

 

 

 

 

Accounts receivable

 

265,655

 

128,186

 

Accrued unbilled revenues

 

272,574

 

237,358

 

Inventories

 

111,780

 

(195,722

)

Recoverable purchased natural gas and electric energy costs

 

(30,792

)

(25,752

)

Other current assets

 

(72,817

)

21,794

 

Accounts payable

 

(286,019

)

(198,877

)

Net regulatory assets and liabilities

 

20,422

 

(47,765

)

Other current liabilities

 

7,347

 

11,521

 

Change in other noncurrent assets

 

(2,014

)

407

 

Change in other noncurrent liabilities

 

(172,291

)

(44,423

)

Operating cash flows used in discontinued operations

 

(17,166

)

(11,494

)

Net cash provided by operating activities

 

1,628,816

 

1,211,462

 

 

 

 

 

 

 

Investing activities

 

 

 

 

 

Utility capital/construction expenditures

 

(1,310,686

)

(1,523,365

)

Allowance for equity funds used during construction

 

55,565

 

45,478

 

Purchase of investments in external decommissioning fund

 

(1,278,554

)

(643,497

)

Proceeds from the sale of investments in external decommissioning fund

 

1,276,417

 

610,953

 

Investment in WYCO Development LLC

 

(38,936

)

(73,038

)

Change in restricted cash

 

(1,389

)

24,132

 

Other investments

 

3,472

 

(25,678

)

Net cash used in investing activities

 

(1,294,111

)

(1,585,015

)

 

 

 

 

 

 

Financing activities

 

 

 

 

 

Proceeds (repayment) of short-term borrowings, net

 

38,750

 

(824,560

)

Proceeds from issuance of long-term debt

 

394,762

 

1,682,393

 

Repayment of long-term debt, including reacquisition premiums

 

(620,074

)

(200,041

)

Proceeds from issuance of common stock

 

4,174

 

351,357

 

Dividends paid

 

(309,320

)

(303,157

)

Net cash (used in) provided by financing activities

 

(491,708

)

705,992

 

 

 

 

 

 

 

Net increase (decrease) in cash and cash equivalents

 

(157,003

)

332,439

 

Net increase (decrease) in cash and cash equivalents — discontinued operations

 

(1,989

)

416

 

Cash and cash equivalents at beginning of period

 

249,198

 

51,120

 

Cash and cash equivalents at end of period

 

$

90,206

 

$

383,975

 

Supplemental disclosure of cash flow information:

 

 

 

 

 

Cash paid for interest (net of amounts capitalized)

 

$

(400,511

)

$

(363,439

)

Cash received (paid) for income taxes, net

 

21,857

 

(49,943

)

Supplemental disclosure of non-cash investing transactions:

 

 

 

 

 

Property, plant and equipment additions in accounts payable

 

$

33,116

 

$

27,845

 

Supplemental disclosure of non-cash financing transactions:

 

 

 

 

 

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

 

$

44,668

 

$

48,872

 

 

See Notes to Consolidated Financial Statements

 

4



Table of Contents

 

XCEL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (UNAUDITED)

(amounts in thousands of dollars)

 

 

 

Sept. 30, 2009

 

Dec. 31, 2008

 

Assets

 

 

 

 

 

Current assets

 

 

 

 

 

Cash and cash equivalents

 

$

90,206

 

$

249,198

 

Accounts receivable, net

 

635,563

 

900,781

 

Accrued unbilled revenues

 

470,905

 

743,479

 

Inventories

 

554,929

 

666,709

 

Recoverable purchased natural gas and electric energy costs

 

63,635

 

32,843

 

Derivative instruments valuation

 

136,491

 

101,972

 

Prepayments and other

 

311,028

 

263,906

 

Current assets held for sale and related to discontinued operations

 

128,040

 

56,641

 

Total current assets

 

2,390,797

 

3,015,529

 

 

 

 

 

 

 

Property, plant and equipment, net

 

18,514,792

 

17,688,720

 

 

 

 

 

 

 

Other assets

 

 

 

 

 

Nuclear decommissioning fund and other investments

 

1,365,601

 

1,232,081

 

Regulatory assets

 

2,216,473

 

2,357,279

 

Derivative instruments valuation

 

308,768

 

325,688

 

Other

 

154,486

 

157,742

 

Noncurrent assets held for sale and related to discontinued operations

 

130,291

 

181,456

 

Total other assets

 

4,175,619

 

4,254,246

 

Total assets

 

$

25,081,208

 

$

24,958,495

 

 

 

 

 

 

 

Liabilities and Equity

 

 

 

 

 

Current liabilities

 

 

 

 

 

Current portion of long-term debt

 

$

184,534

 

$

558,772

 

Short-term debt

 

494,000

 

455,250

 

Accounts payable

 

811,624

 

1,120,324

 

Taxes accrued

 

223,278

 

220,542

 

Accrued interest

 

146,107

 

168,632

 

Dividends payable

 

112,840

 

108,838

 

Derivative instruments valuation

 

59,277

 

75,539

 

Other

 

326,780

 

331,419

 

Current liabilities held for sale and related to discontinued operations

 

28,058

 

6,929

 

Total current liabilities

 

2,386,498

 

3,046,245

 

 

 

 

 

 

 

Deferred credits and other liabilities

 

 

 

 

 

Deferred income taxes

 

3,177,595

 

2,792,560

 

Deferred investment tax credits

 

100,503

 

105,716

 

Regulatory liabilities

 

1,265,541

 

1,194,596

 

Asset retirement obligations

 

1,186,690

 

1,135,182

 

Derivative instruments valuation

 

327,691

 

340,802

 

Customer advances

 

304,752

 

323,445

 

Pension and employee benefit obligations

 

902,214

 

1,030,532

 

Other

 

184,885

 

168,352

 

Noncurrent liabilities held for sale and related to discontinued operations

 

3,279

 

20,656

 

Total deferred credits and other liabilities

 

7,453,150

 

7,111,841

 

 

 

 

 

 

 

Commitments and contingent liabilities

 

 

 

 

 

Capitalization

 

 

 

 

 

Long-term debt

 

7,945,400

 

7,731,688

 

Preferred stockholders’ equity — authorized 7,000,000 shares of $100 par value; outstanding shares: 1,049,800

 

104,980

 

104,980

 

Common stockholders’ equity — authorized 1,000,000,000 shares of $2.50 par value; outstanding shares: Sept. 30, 2009 — 456,251,313; Dec. 31, 2008 — 453,791,770

 

7,191,180

 

6,963,741

 

Total liabilities and equity

 

$

25,081,208

 

$

24,958,495

 

 

See Notes to Consolidated Financial Statements

 

5


 


Table of Contents

 

XCEL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY

AND COMPREHENSIVE INCOME (UNAUDITED)

(amounts in thousands)

 

 

 

Common Stock Issued

 

 

 

Accumulated

 

Total

 

 

 

 

 

 

 

Additional

 

 

 

Other

 

Common

 

 

 

 

 

 

 

Paid In

 

Retained

 

Comprehensive

 

Stockholders’

 

 

 

Shares

 

Par Value

 

Capital

 

Earnings

 

Income (Loss)

 

Equity

 

Three Months Ended Sept. 30, 2009 and 2008

 

 

 

 

 

 

 

 

 

 

 

 

 

Balance at June 30, 2008

 

430,917

 

$

1,077,292

 

$

4,306,239

 

$

1,017,488

 

$

(26,549

)

$

6,374,470

 

Net income

 

 

 

 

 

 

 

222,789

 

 

 

222,789

 

Changes in unrecognized amounts of pension and retiree medical benefits, net of tax of $195

 

 

 

 

 

 

 

 

 

273

 

273

 

Net derivative instrument fair value changes during the period, net of tax of $(1,741)

 

 

 

 

 

 

 

 

 

(2,522

)

(2,522

)

Unrealized loss - marketable securities, net of tax of $(87)

 

 

 

 

 

 

 

 

 

(123

)

(123

)

Comprehensive income for the period

 

 

 

 

 

 

 

 

 

 

 

220,417

 

Dividends declared:

 

 

 

 

 

 

 

 

 

 

 

 

 

Cumulative preferred stock

 

 

 

 

 

 

 

(1,060

)

 

 

(1,060

)

Common stock

 

 

 

 

 

 

 

(106,545

)

 

 

(106,545

)

Issuances of common stock

 

17,699

 

44,247

 

311,340

 

 

 

 

 

355,587

 

Share-based compensation

 

 

 

 

 

5,471

 

 

 

 

 

5,471

 

Balance at Sept. 30, 2008

 

448,616

 

$

1,121,539

 

$

4,623,050

 

$

1,132,672

 

$

(28,921

)

$

6,848,340

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Balance at June 30, 2009

 

455,717

 

$

1,139,292

 

$

4,727,380

 

$

1,256,405

 

$

(49,354

)

$

7,073,723

 

Net income

 

 

 

 

 

 

 

220,828

 

 

 

220,828

 

Changes in unrecognized amounts of pension and retiree medical benefits, net of tax of $260

 

 

 

 

 

 

 

 

 

365

 

365

 

Net derivative instrument fair value changes during the period, net of tax of $(3,876)

 

 

 

 

 

 

 

 

 

(5,557

)

(5,557

)

Unrealized gain - marketable securities, net of tax of $62

 

 

 

 

 

 

 

 

 

90

 

90

 

Comprehensive income for the period

 

 

 

 

 

 

 

 

 

 

 

215,726

 

Dividends declared:

 

 

 

 

 

 

 

 

 

 

 

 

 

Cumulative preferred stock

 

 

 

 

 

 

 

(1,060

)

 

 

(1,060

)

Common stock

 

 

 

 

 

 

 

(112,255

)

 

 

(112,255

)

Issuances of common stock

 

534

 

1,337

 

7,485

 

 

 

 

 

8,822

 

Share-based compensation

 

 

 

 

 

6,224

 

 

 

 

 

6,224

 

Balance at Sept. 30, 2009

 

456,251

 

$

1,140,629

 

$

4,741,089

 

$

1,363,918

 

$

(54,456

)

$

7,191,180

 

 

See Notes to Consolidated Financial Statements

 

6



Table of Contents

 

XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY

AND COMPREHENSIVE INCOME (UNAUDITED)

(amounts in thousands)

 

 

 

Common Stock Issued

 

 

 

Accumulated

 

Total

 

 

 

 

 

 

 

Additional

 

 

 

Other

 

Common

 

 

 

 

 

 

 

Paid In

 

Retained

 

Comprehensive

 

Stockholders'

 

 

 

Shares

 

Par Value

 

Capital

 

Earnings

 

Income (Loss)

 

Equity

 

Nine Months Ended Sept. 30, 2009 and 2008

 

 

 

 

 

 

 

 

 

 

 

 

 

Balance at Dec. 31, 2007

 

428,783

 

$

1,071,957

 

$

4,286,917

 

$

963,916

 

$

(21,788

)

$

6,301,002

 

Adoption of new accounting guidance for endorsement split-dollar life insurance, net of tax of $(1,038)

 

 

 

 

 

 

 

(1,640

)

 

 

(1,640

)

Net income

 

 

 

 

 

 

 

481,478

 

 

 

481,478

 

Changes in unrecognized amounts of pension and retiree medical benefits, net of tax of $1,071

 

 

 

 

 

 

 

 

 

330

 

330

 

Net derivative instrument fair value changes during the period, net of tax of $(2,808)

 

 

 

 

 

 

 

 

 

(7,240

)

(7,240

)

Unrealized loss - marketable securities, net of tax of $(154)

 

 

 

 

 

 

 

 

 

(223

)

(223

)

Comprehensive income for the period

 

 

 

 

 

 

 

 

 

 

 

474,345

 

Dividends declared:

 

 

 

 

 

 

 

 

 

 

 

 

 

Cumulative preferred stock

 

 

 

 

 

 

 

(3,180

)

 

 

(3,180

)

Common stock

 

 

 

 

 

 

 

(307,902

)

 

 

(307,902

)

Issuances of common stock

 

19,833

 

49,582

 

318,881

 

 

 

 

 

368,463

 

Share-based compensation

 

 

 

 

 

17,252

 

 

 

 

 

17,252

 

Balance at Sept. 30, 2008

 

448,616

 

$

1,121,539

 

$

4,623,050

 

$

1,132,672

 

$

(28,921

)

$

6,848,340

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Balance at Dec. 31, 2008

 

453,792

 

$

1,134,480

 

$

4,695,019

 

$

1,187,911

 

$

(53,669

)

$

6,963,741

 

Net income

 

 

 

 

 

 

 

512,002

 

 

 

512,002

 

Changes in unrecognized amounts of pension and retiree medical benefits, net of tax of $769

 

 

 

 

 

 

 

 

 

1,106

 

1,106

 

Net derivative instrument fair value changes during the period, net of tax of $(1,736)

 

 

 

 

 

 

 

 

 

(2,226

)

(2,226

)

Unrealized gain - marketable securities, net of tax of $230

 

 

 

 

 

 

 

 

 

333

 

333

 

Comprehensive income for the period

 

 

 

 

 

 

 

 

 

 

 

511,215

 

Dividends declared:

 

 

 

 

 

 

 

 

 

 

 

 

 

Cumulative preferred stock

 

 

 

 

 

 

 

(3,180

)

 

 

(3,180

)

Common stock

 

 

 

 

 

 

 

(332,815

)

 

 

(332,815

)

Issuances of common stock

 

2,459

 

6,149

 

25,550

 

 

 

 

 

31,699

 

Share-based compensation

 

 

 

 

 

20,520

 

 

 

 

 

20,520

 

Balance at Sept. 30, 2009

 

456,251

 

$

1,140,629

 

$

4,741,089

 

$

1,363,918

 

$

(54,456

)

$

7,191,180

 

 

See Notes to Consolidated Financial Statements

 

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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 (collectively, Xcel Energy) as of Sept. 30, 2009 and Dec. 31, 2008; the results of its operations and changes in stockholders’ equity for the three and nine months ended Sept. 30, 2009 and 2008; and its cash flows for the nine months ended Sept. 30, 2009 and 2008. All adjustments are of a normal, recurring nature, except as otherwise disclosed.  Management has also evaluated the impact of events occurring after Sept. 30, 2009 up to Oct. 30, 2009, which is the date of issuance of these consolidated financial statements.  These statements contain all necessary adjustments and disclosures resulting from that evaluation.  The Dec. 31, 2008 balance sheet information has been derived from the audited 2008 financial statements.  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 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 Annual Report on Form 10-K for the year ended Dec. 31, 2008, filed with the SEC on Feb. 27, 2009.  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

 

Except to the extent updated or described below, the significant accounting policies set forth in Note 1 to the consolidated financial statements in Xcel Energy’s Annual Report on Form 10-K for the year ended Dec. 31, 2008, appropriately represent, in all material respects, the current status of accounting policies and are incorporated herein by reference.

 

Reclassifications — Equity earnings of Xcel Energy’s unconsolidated subsidiaries were reclassified from interest and other income and income tax expense into a separate line item on the consolidated statements of income.  The reclassification did not have an impact on net income or earnings per share.

 

2.              Accounting Pronouncements

 

Recently Adopted

 

Business Combinations In December 2007, the Financial Accounting Standards Board (FASB) issued new guidance on business combinations which establishes principles and requirements for how an acquirer in a business combination recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest; recognizes and measures the goodwill acquired in the business combination or a gain from a bargain purchase; and determines what information to disclose to enable users of the financial statements to evaluate the nature and financial effects of the business combination. This new guidance is to be applied prospectively to business combinations for which the acquisition date is on or after the beginning of an entity’s fiscal year that begins on or after Dec. 15, 2008.  Xcel Energy implemented the guidance on Jan. 1, 2009, and the implementation did not have a material impact on its consolidated financial statements.

 

Noncontrolling Interests — Also in December 2007, the FASB issued new guidance on noncontrolling interests in consolidated financial statements which establishes accounting and reporting standards that require the ownership interest in subsidiaries held by parties other than the parent be clearly identified and presented in the consolidated balance sheets within equity, but separate from the parent’s equity; the amount of consolidated net income attributable to the parent and the noncontrolling interest be clearly identified and presented on the face of the consolidated statement of earnings; and changes in a parent’s ownership interest while the parent retains its controlling financial interest in its subsidiary be accounted for consistently as equity transactions. This new guidance was effective for fiscal years beginning on or after Dec. 15, 2008.  Xcel Energy implemented the guidance on Jan. 1, 2009, and the implementation did not have a material impact on its consolidated financial statements.

 

Derivatives and Hedging Disclosures — In March 2008, the FASB issued new guidance on disclosures about derivative instruments and hedging activities which is intended to enhance disclosures to help users of the financial statements better understand how derivative instruments and hedging activities affect an entity’s financial position, financial performance and cash flows.  The guidance amends and expands previous disclosure requirements for derivative instruments and hedging activities, including disclosures of objectives and strategies for using derivatives, gains and losses on derivative instruments, and credit-risk-related contingent features in derivative contracts.  This new guidance was effective for fiscal years and interim periods beginning after Nov. 15, 2008.  Xcel Energy implemented the guidance on Jan. 1, 2009, and the implementation did not have a material impact on its consolidated financial statements.  For further discussion and the required disclosures, see Note 10 to the consolidated financial statements.

 

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Interim Fair Value Disclosures In April 2009, the FASB issued new guidance on interim disclosures about fair value of financial instruments which requires that disclosures regarding the fair value of financial instruments be included in interim financial statements.  This new guidance was effective for interim periods ending after June 15, 2009.  Xcel Energy implemented the guidance on April 1, 2009, and the implementation did not have a material impact on its consolidated financial statements.  For further discussion and the required disclosures, see Note 11 to the consolidated financial statements.

 

Fair Value in Inactive Markets Also in April 2009, the FASB issued new guidance for identifying market transactions that are not orderly and determining fair value when market trading activity has decreased significantly.  The new guidance emphasizes that even if there has been a significant decrease in the volume and level of market activity for an asset or liability, fair value still represents the exit price in an orderly transaction between market participants.  This new guidance was effective for interim and annual periods ending after June 15, 2009.  Xcel Energy implemented the guidance on April 1, 2009, and the implementation did not have a material impact on its consolidated financial statements.

 

Other-Than-Temporary Impairments Additionally in April 2009, the FASB issued new guidance on recognition and presentation of other-than-temporary impairments which changes the method for determining whether an other-than-temporary impairment exists for debt securities, and also requires additional disclosures regarding other-than-temporary impairments.  This new guidance was effective for interim and annual periods ending after June 15, 2009.  Xcel Energy implemented the guidance on April 1, 2009, and the implementation did not have a material impact on its consolidated financial statements.

 

Subsequent Events — In May 2009, the FASB issued new guidance on subsequent events which establishes general standards of accounting and disclosure for events that occur after the balance sheet date but before financial statements are issued.  The guidance is consistent with the auditing literature historically used for accounting and disclosure of subsequent events, however, it requires an entity to disclose the date through which subsequent events have been evaluated.  This new guidance was effective for interim and annual periods ending after June 15, 2009.  Xcel Energy implemented the guidance on April 1, 2009, and the implementation did not have a material impact on its consolidated financial statements.

 

Accounting Standards Codification — In June 2009, the FASB issued Topic 105 — Generally Accepted Accounting Principles Amendments Based on Statement of Financial Accounting Standards No. 168 — The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles (Accounting Standards Update (ASU) No. 2009-01), which updates the FASB Accounting Standards Codification (ASC or Codification) to state that the Codification is to be the single source of authoritative GAAP, other than the guidance put forth by the SEC.  All other accounting literature not included in the Codification is to be considered non-authoritative.  The updates to the Codification contained in ASU No. 2009-01 were effective for interim and annual periods ending after Sept. 15, 2009.  Xcel Energy implemented the guidance set forth by ASU No. 2009-01, recognizing the Codification as the single source of authoritative GAAP, other than the guidance put forth by the SEC, on July 1, 2009.  The implementation did not have a material impact on Xcel Energy’s consolidated financial statements.

 

Recently Issued

 

Postretirement Benefit Plans In December 2008, the FASB issued new guidance on employers’ disclosures about postretirement benefit plan assets.  The guidance will amend and expand previous disclosure requirements for plan assets of a defined benefit pension or other postretirement plan to include investment policies and strategies, major categories of plan assets, information regarding fair value measurements, and significant concentrations of credit risk.  This new guidance is effective for disclosures for fiscal years ending after Dec. 15, 2009.  Xcel Energy does not expect the implementation of the guidance to have a material impact on its consolidated financial statements.

 

Consolidation of Variable Interest Entities — In June 2009, the FASB issued new guidance on consolidation of variable interest entities.  The guidance will significantly affect various elements of consolidation under existing accounting standards, including the determination of whether an entity is a variable interest entity and whether an enterprise is a variable interest entity’s primary beneficiary.  This new guidance is effective for fiscal years beginning after Nov. 15, 2009.  Xcel Energy is currently evaluating the impact of this guidance on its consolidated financial statements.

 

Fair Value of Liabilities In August 2009, the FASB issued Fair Value Measurements and Disclosures (Topic 820) — Measuring Liabilities at Fair Value (ASU No. 2009-05), which will update the Codification with clarifications for measuring the fair value of liabilities.  The liability-specific guidance includes clarifications and guidelines for using, when available, the most observable prices in active markets for identical liabilities or similar liabilities, or the prices of identical liabilities or similar liabilities traded as assets, rather than more complex and less observable valuation techniques and inputs such as those used in a present value model.  The updates to the Codification contained in ASU No. 2009-05 are effective for interim and annual periods beginning after its August, 2009 issuance.  Xcel Energy does not expect the implementation of these changes in the Codification to have a material impact on its consolidated financial statements.

 

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3.              Selected Balance Sheet Data

 

(Thousands of Dollars)

 

Sept. 30, 2009

 

Dec. 31, 2008

 

Accounts receivable, net

 

 

 

 

 

Accounts receivable

 

$

693,419

 

$

965,020

 

Less allowance for bad debts

 

(57,856

)

(64,239

)

 

 

$

635,563

 

$

900,781

 

Inventories

 

 

 

 

 

Materials and supplies

 

$

173,674

 

$

158,709

 

Fuel

 

214,792

 

227,462

 

Natural gas

 

166,463

 

280,538

 

 

 

$

554,929

 

$

666,709

 

Property, plant and equipment, net

 

 

 

 

 

Electric plant

 

$

22,650,906

 

$

21,601,094

 

Natural gas plant

 

3,231,528

 

3,004,088

 

Common and other property

 

1,491,664

 

1,497,162

 

Construction work in progress

 

1,688,560

 

1,832,022

 

Total property, plant and equipment

 

29,062,658

 

27,934,366

 

Less accumulated depreciation

 

(10,843,820

)

(10,501,266

)

Nuclear fuel

 

1,711,047

 

1,611,193

 

Less accumulated amortization

 

(1,415,093

)

(1,355,573

)

 

 

$

18,514,792

 

$

17,688,720

 

 

4.              Discontinued Operations

 

Results of operations for divested businesses and the results of businesses held for sale are reported, for all periods presented, as discontinued operations.  In addition, the assets and liabilities of the businesses divested and held for sale have been reclassified to assets and liabilities held for sale in the consolidated balance sheets.  The majority of current and noncurrent assets related to discontinued operations are deferred tax assets associated with temporary differences and net operating loss (NOL) and tax credit carryforwards that will be deductible in future years.

 

The major classes of assets and liabilities held for sale and related to discontinued operations are as follows:

 

(Thousands of Dollars)

 

Sept. 30, 2009

 

Dec. 31, 2008

 

Cash

 

$

8,656

 

$

10,645

 

Deferred income tax benefits

 

91,174

 

39,422

 

Other current assets

 

28,210

 

6,574

 

Current assets held for sale and related to discontinued operations

 

$

128,040

 

$

56,641

 

 

 

 

 

 

 

Deferred income tax benefits

 

$

117,217

 

$

150,912

 

Other noncurrent assets

 

13,074

 

30,544

 

Noncurrent assets held for sale and related to discontinued operations

 

$

130,291

 

$

181,456

 

 

 

 

 

 

 

Accounts payable

 

$

680

 

$

760

 

Other current liabilities

 

27,378

 

6,169

 

Current liabilities held for sale and related to discontinued operations

 

$

28,058

 

$

6,929

 

 

 

 

 

 

 

Noncurrent liabilities held for sale and related to discontinued operations

 

$

3,279

 

$

20,656

 

 

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5.     Income Taxes

 

Xcel Energy files a consolidated federal income tax return and 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.

 

Federal Audit In the first quarter of 2008, the Internal Revenue Service (IRS) completed an examination of Xcel Energy’s federal income tax returns for 2004 and 2005 (and research credits for 2003).  The IRS did not propose any material adjustments for those tax years.  Tax year 2004 is the earliest open year and the statute of limitations applicable to Xcel Energy’s 2004 federal income tax return remains open until Dec. 31, 2009.  The IRS commenced an examination of tax years 2006 and 2007 in the third quarter of 2008, and this audit is expected to be completed in the first quarter of 2010.  As of Sept. 30, 2009, the IRS had not proposed any material adjustments to tax years 2006 and 2007.

 

State Audits In the first quarter of 2008, the state of Minnesota concluded an income tax audit through tax year 2001 and the state of Texas concluded an income tax audit through tax year 2005.  No material adjustments were proposed for these state audits.  As of Sept. 30, 2009, Xcel Energy’s earliest open tax years that are subject to examination by state taxing authorities in its major operating jurisdictions are as follows:

 

State

 

Earliest Open Tax Year in Which
an Audit Can Be Initiated

 

Colorado

 

2004

 

Minnesota

 

2004

 

Texas

 

2004

 

Wisconsin

 

2004

 

 

There currently are no state income tax audits in progress.

 

Unrecognized Tax Benefits The amount of unrecognized tax benefits reported in continuing operations was $40.8 million on Sept. 30, 2009 and $35.5 million on Dec. 31, 2008.  The amount of unrecognized tax benefits reported in discontinued operations was $6.6 million on both Sept. 30, 2009 and Dec. 31, 2008.  The unrecognized tax benefit amounts reported in continuing operations were reduced by the tax benefits associated with NOL and tax credit carryovers of $13.2 million on Sept. 30, 2009 and $13.1 million on Dec. 31, 2008.  The unrecognized tax benefit amounts reported in discontinued operations were reduced by the tax benefits associated with NOL and tax credit carryovers of $31.7 million on Sept. 30, 2009 and $26.5 million on Dec. 31, 2008.

 

The unrecognized tax benefit balance reported in continuing operations included $8.8 million and $9.2 million of tax positions on Sept. 30, 2009 and Dec. 31, 2008, respectively, which if recognized would affect the annual effective tax rate.  In addition, the unrecognized tax benefit balance reported in continuing operations included $32.0 million and $26.3 million of tax positions on Sept. 30, 2009 and Dec. 31, 2008, respectively, 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 effective tax rate but would accelerate the payment of cash to the taxing authority to an earlier period.

 

The increase in the unrecognized tax benefit balance reported in continuing operations of $7.3 million from June 30, 2009 to Sept. 30, 2009, was due to the addition of similar uncertain tax positions related to ongoing activity.  Xcel Energy’s amount of unrecognized tax benefits for continuing operations could significantly change in the next 12 months as the IRS audit progresses and when state audits resume.  As the IRS examination moves closer to completion, it is reasonably possible that the amount of unrecognized tax benefits in continuing operations could decrease up to approximately $20 million.

 

The liability for interest related to unrecognized tax benefits is partially offset by the interest benefit associated with NOL and tax credit carryovers.  The amount of interest expense related to unrecognized tax benefits reported within interest charges in continuing operations in the third quarter of 2009 was $0.7 million.  The amount of interest expense related to unrecognized tax benefits reported within interest charges in continuing operations in the third quarter of 2008 was $0.3 million.  The liability for interest related to unrecognized tax benefits reported in continuing operations was $2.9 million on Sept. 30, 2009 and $1.9 million on Dec. 31, 2008.  The amount reported within interest charges related to unrecognized tax benefits in discontinued operations in the third quarter of 2009 reduced interest expense by $0.6 million.  The amount reported within interest charges related to unrecognized tax benefits in discontinued operations in the third quarter of 2008 reduced interest expense by $0.2 million.  The receivable for interest related to unrecognized tax benefits reported in discontinued operations was $2.4 million on Sept. 30, 2009 and $1.5 million on Dec. 31, 2008.

 

No amounts were accrued for penalties as of Sept. 30, 2009 or Dec. 31, 2008.

 

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6.              Rate Matters

 

Except to the extent noted below, the circumstances set forth in Note 16 to the consolidated financial statements included in Xcel Energy’s Annual Report on Form 10-K for the year ended Dec. 31, 2008 appropriately represent, in all material respects, the current status of other rate matters, and are incorporated herein by reference.  The following discussion includes unresolved proceedings that are material to Xcel Energy’s financial position.

 

NSP-Minnesota

 

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

 

Base Rate

 

NSP-Minnesota Electric Rate Case  In November 2008, NSP-Minnesota filed a request with the MPUC to increase Minnesota electric rates by $156 million annually.  This request was later modified to $136 million.

 

In September 2009, the MPUC voted to approve a rate increase of approximately $91.4 million.  As part of its decision, the MPUC approved a 10-year life extension of the Prairie Island nuclear plant for purposes of determining depreciation and decommissioning expenses, effective Jan. 1, 2009.  This decision reduced NSP-Minnesota’s overall revenue deficiency by approximately $40 million, while at the same time reducing expense accruals by a corresponding amount.  A summary of the key terms is listed below:

 

 

 

Revised Request

 

Approved

 

Rate increase

 

$

136 million

 

$

91 million

 

Return on equity

 

11.0

%

10.88

%

Equity ratio

 

52.5

%

52.5

%

Electric rate base

 

$

4.1 billion

 

$

4.1 billion

 

Depreciation life extension for Prairie Island nuclear plant

 

0 years

 

10 years

 

 

As of Sept. 30, 2009, NSP-Minnesota accrued a customer refund of approximately $30.2 million to reflect the difference between interim rates that were implemented Jan. 2, 2009 and the amount approved by the MPUC.  The written order was issued Oct. 23, 2009.

 

Electric, Purchased Gas and Resource Adjustment Clauses

 

Transmission Cost Recovery (TCR) RiderThe MPUC has approved a TCR rider, which allows annual adjustments to retail electric rates to provide recovery of incremental transmission investments between rate cases.  In October 2008, NSP-Minnesota submitted its proposed revised TCR rate factors, seeking to recover $14 million in 2009.  A portion of amounts previously collected through the TCR rider prior to 2009 has been included for recovery in the NSP-Minnesota electric rate case described above.  In June 2009, the MPUC approved the rider request.  The revised TCR rate recovery factors were placed into effect in July 2009.  In September 2009, NSP-Minnesota submitted its proposed revised rate factors, seeking to recover an additional $15.6 million in TCR rates in 2010.  The request is pending MPUC action.

 

Renewable Energy Standard (RES) Rider — The MPUC has approved an RES rider to recover the costs for utility-owned projects implemented in compliance with the RES.  Under the rider, NSP-Minnesota recovered approximately $14.5 million in 2008 attributable to the Grand Meadow wind farm.  In 2008, NSP-Minnesota submitted the RES rider for recovery of approximately $22 million in 2009 attributable to the Grand Meadow wind farm.  In February 2009, the MPUC approved the rider request.  The revised RES rate recovery factors were placed into effect in March 2009.  In September 2009, NSP-Minnesota submitted its proposed revised rate factors, seeking to recover an additional $44.4 million in RES rates in 2010.  The request is pending MPUC action.

 

Metropolitan Emissions Reduction Project (MERP) Rider — In October 2008, NSP-Minnesota filed a proposed MERP rider for 2009 designed to recover costs related to MERP environmental improvement projects.  Under this rider, NSP-Minnesota proposes to recover $113.7 million in 2009, an increase of approximately $18.1 million over 2008.  New rates went into effect automatically on Jan. 1, 2009, as stipulated.  MPUC approval is still pending.  On Oct. 1, 2009, NSP-Minnesota filed its proposed MERP rider for 2010 designed to recover costs related to MERP environmental improvement projects of $116.7 million.  These new rates are expected to go into effect automatically on Jan. 1, 2010.  NSP-Minnesota received comments on its 2009 MERP rider on Oct. 19, 2009, recommending the MPUC approve the 2009 proposed rates.

 

State Energy Policy (SEP) Rider In March 2009, NSP-Minnesota filed a proposed SEP rider for 2009 designed to recover costs related to state energy policy mandates and a cast iron natural gas pipe replacement project that is intended to reduce greenhouse gas (GHG) emissions.  Under this rider, NSP-Minnesota proposes to recover approximately $2.5 million from its electric customers and

 

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$0.1 million from its natural gas customers in 2009.  In September 2009, the MPUC approved the rider request.  The revised SEP rate recovery factors were placed into effect in October 2009.

 

Annual Automatic Adjustment Report for 2007/2008 — In September 2008, NSP-Minnesota filed its annual automatic adjustment reports for July 1, 2007 through June 30, 2008.  During that time period, $848.5 million in fuel and purchased energy costs, including $258.8 million of Midwest Independent Transmission System Operator, Inc. (MISO) charges, were recovered from Minnesota electric customers through the fuel clause adjustment (FCA).  In addition, approximately $680 million of purchased natural gas and transportation costs were recovered through the purchased gas adjustment (PGA).  NSP-Minnesota received comments on its 2008 electric annual automatic adjustment report in August 2009, which sought clarifications in the areas of transmission maintenance expenses, MISO revenue neutrality uplift charges and costs, and contractor non-performance responsibility for replacement energy costs.  NSP-Minnesota received comments on its 2008 natural gas annual automatic adjustment report in June 2009, which recommends that the MPUC accept the 2008 report and PGA true up, and authorize its implementation.  MPUC approval of both reports is pending.

 

Annual Automatic Adjustment Report for 2008/2009 In September 2009, NSP-Minnesota filed its annual automatic adjustment reports for July 1, 2008 through June 30, 2009.  During that time period, $803.6 million in fuel and purchased energy costs were recovered from Minnesota electric customers through the FCA.  In addition, approximately $499.4 million of purchased natural gas and transportation costs were recovered through the PGA.  MPUC approval is pending.

 

Conservation Incentive Filing Minnesota state agencies convened a work group to review the current energy efficiency incentive mechanism.  The work group reached a consensus in the spring of 2009 that a shared savings model was the best structure for incenting cost-effective conservation.  In July 2009, NSP-Minnesota filed its proposed incentive plan for achieving significantly higher demand side management (DSM) goals.  The incentive would allow for sharing of savings of up to 15 percent of the net present value of benefits, depending on the level of savings achieved.  NSP-Minnesota received comments on its proposed incentive mechanism in September 2009, which recommended minor modifications that do not significantly impact the potential award scale.  An MPUC decision on the proposed plan is pending.

 

Gas Meter Module Failures Approximately 8,700 customers in the St. Cloud and East Grand Forks areas of Minnesota and about 4,000 customers in the Fargo, N.D. area were under billed for a period of time during the 2007-2008 heating season due to the failure of the automated meter reading (AMR) module installed on their natural gas meters.  While the modules failed to register usage, the meters continued to function.  In 2008, NSP-Minnesota rebilled approximately 5,000 of these customers for their estimated consumption and then ceased rebilling as both the MPUC and North Dakota Public Service Commission (NDPSC) opened investigations into this matter.  NSP-Minnesota has initiated dispute resolution with its provider of the AMR modules and meter reading services.

 

Pursuant to the NDPSC-approved plan, which provided customers with a $50 service quality credit for each customer experiencing a module failure NSP-Minnesota began implementing the service quality credits and the rebilling of remaining North Dakota customers in June 2009.  In total, NSP-Minnesota rebilled North Dakota customers approximately $1.5 million for the estimated gas usage during the module failure period.

 

In March 2009, NSP-Minnesota filed with the MPUC for a proposed $50 service quality credit for each customer experiencing a module failure.  On July 15, 2009, NSP-Minnesota filed an application to withdraw its request to rebill affected customers as too much time would have lapsed from the time of meter failures to the expected time (if approved) for rebilling.  Although the MPUC order is still pending, the MPUC approved NSP-Minnesota’s withdrawal of its request to rebill affected customers at its hearing in September 2009.  NSP-Minnesota has determined that a number of AMR modules designed for commercial customers are defective and as a result is broadening efforts to evaluate the performance of both gas and electric AMR modules.  As of Sept. 30, 2009, NSP-Minnesota has accrued an amount sufficient to cover the estimated impact.

 

Annual Review of Remaining Lives — In February 2009, NSP-Minnesota filed a petition with the MPUC requesting an increase in proposed service lives, salvage rates and resulting depreciation rates for its electric and gas production facilities and a depreciation study for other gas and electric assets, effective Jan 1, 2009.  The Office of Energy Security (OES) recommended a 10-year lengthening of depreciation life of the Prairie Island nuclear plant.  In July 2009, the MPUC approved the proposed service lives, salvage rates, and resulting depreciation rates effective Jan. 1, 2009, for plant in service, with the exception of the Prairie Island nuclear plant.  The MPUC deferred the determination of the appropriate depreciation rates for the Prairie Island nuclear plant to the pending NSP-Minnesota electric rate case.  In the electric rate case, the MPUC extended the depreciation life of the Prairie Island nuclear plant by 10 years beyond the current license life in light of NSP-Minnesota’s application to extend the life of its nuclear plants by 20 years.

 

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Nuclear Decommissioning Expenses — In June 2009, the MPUC issued its order in its review of NSP-Minnesota’s 2009 nuclear plant decommissioning accruals.  The order extended the decommissioning life for the Prairie Island nuclear plant by 10 years.  The order reduced the amount of future nuclear decommissioning expenses that must be collected from customers from $32 million to zero, effective Jan. 1, 2009.

 

In August 2009, NSP-Minnesota filed a proposal with the MPUC to provide one-time refunds to return to customers their contributions of $22.8 million made to the external escrow decommissioning fund for the Monticello nuclear plant.  In October 2009, NSP-Minnesota received comments on its proposed refund plan, which recommends approval with minor modifications to the proposed refund mechanics.  MPUC action is pending.

 

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

 

South Dakota Electric Rate Case — In June 2009, NSP-Minnesota filed a request with the SDPUC to increase South Dakota electric rates by $18.6 million annually, or 12.7 percent.  This proposed increase includes approximately $2.9 million in revenues currently recovered through automatic recovery mechanisms.  Thus, the requested increase, net of current automatic recovery mechanisms, is approximately $15.7 million or 10.7 percent.  The request is based on a 2008 historic test year adjusted for known and measurable changes in rate base and operating and maintenance expenses, an electric rate base of $282 million, a requested return on equity (ROE) of 11.25 percent, and an equity ratio of 51.63 percent.

 

Rates may be implemented as early as January 2010, based on statutory requirements in South Dakota.  The procedural schedule is as follows:

 

·                  Staff and intervenor testimony on Nov. 20, 2009;

·                  NSP-Minnesota rebuttal testimony on Dec. 4, 2009; and

·                  Technical and public hearings on Dec. 9 — 11, 2009.

 

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

 

Revenue Sufficiency Guarantee (RSG) Charges — The MISO tariff charges certain market participants a real-time RSG charge, which is designed to ensure that any generator scheduled or dispatched by MISO will receive no less than its offer price for start-up, no-load and incremental energy.  A proposal in 2005 by MISO to refine the RSG charge initiated protracted proceedings.  In the subsequent compliance proceeding, the FERC has issued numerous orders, attempting to refine and clarify the RSG charge.  With the issuance of these orders, the FERC has directed certain refunds to market participants, but has subsequently refined or waived various refund requirements.  The FERC granted rehearing in part of certain earlier orders directing refunds to correct a rate mismatch in the RSG charge.  Specifically, a June 2009 order waived refunds for the period from April 2005 to November 2007, and directed MISO to correct the rate mismatch (through refunds) from November 2007 to November 2008.

 

In August 2007, numerous parties filed complaints against MISO, arguing that the allocation of the RSG charge (only to certain market participants actually withdrawing energy) was unjust, unreasonable, and unduly discriminatory.  After protracted proceedings, the FERC found in November 2008 that the RSG charge was unjust and unreasonable, and directed refunds.  In May 2009, FERC granted rehearing in part regarding the applicability of refunds for the RSG charges.  Specifically, the FERC determined that the refund-effective date is November 2008, the date of the FERC order determining that the allocation to market participants of the RSG charges was unjust and unreasonable.

 

The FERC directed MISO to implement an interim RSG cost allocation to be effective starting in August 2007.  The FERC further directed MISO to submit a complete and final proposal, to be implemented on a prospective basis after the commencement of the MISO’s ancillary services markets in January 2009.  In February 2009, MISO submitted a filing to implement the new RSG rate design; however, the FERC has not yet rendered a final decision to implement the new rate design.  Moreover, disputes have arisen regarding whether or not some resources should be assessed to the RSG under the interim rate.  In August 2009, the FERC issued an order in which it invalidated numerous exemptions to the RSG that had previously been utilized by MISO through its business practice manuals.  Several parties have sought rehearing and a final FERC decision is still pending.

 

Xcel Energy is a party to each of the relevant RSG-related proceedings.  Each of the relevant RSG-related orders has been the subject of requests for rehearing at the FERC and petitions for review filed at the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit).  The separate RSG proceedings have proceeded in parallel at the FERC, and the most recent orders (May, June and August 2009), are subject to pending requests for rehearing.  The D.C. Circuit proceedings are being held in abeyance pending final action in the FERC proceedings.

 

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NSP-Wisconsin

 

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

 

Base Rate

 

2008 Electric Rate Case Nuclear Decommissioning Expenses In January 2008, the PSCW issued the final order in NSP-Wisconsin’s 2008 test year rate case.  The PSCW’s final order included recovery of $8.7 million of annual nuclear decommissioning expenses, subject to refund, in anticipation of potential decreases in NSP-Minnesota’s decommissioning expenses.  NSP-Wisconsin and NSP-Minnesota share all NSP System generation and transmission costs, including nuclear decommissioning costs, by means of a FERC-approved tariff commonly referred to as the Interchange Agreement.

 

In June 2009, the MPUC issued the final order in its review of NSP-Minnesota’s 2009 nuclear plant decommissioning accrual, and as a result of that order, the Wisconsin retail jurisdiction’s share of annual nuclear decommissioning expenses decreased to approximately $1.4 million, effective January 2009.  In accordance with the PSCW’s final order, NSP-Wisconsin has established a refund liability of $5.5 million through September 2009.

 

The MPUC order also directed NSP-Minnesota to proceed with a filing to propose a method to return to customers their contributions made to the external escrow decommissioning fund for the Monticello nuclear plant.  Once that plan is approved, NSP-Wisconsin will determine what steps are necessary to initiate a refund for its customers’ proportionate share of these funds.  NSP-Wisconsin’s share of these funds is approximately $5.8 million as of Sept. 30, 2009.

 

2010 Electric and Natural Gas Rate Case — In June 2009, NSP-Wisconsin filed an electric and gas rate case in Wisconsin seeking an increase in retail electric rates of $30.4 million, or 5.7 percent, and proposed no change in natural gas rates.  The request is based on an ROE of 10.75 percent, an equity ratio of 53.12 percent, an electric rate base of $644 million, a gas rate base of $81 million and a 2010 forecasted test year.  The request is comprised of a traditional base rate increase of $45.1 million offset by projected fuel decreases of $14.7 million.

 

On Oct. 21, 2009, PSCW staff and intervenors filed testimony.  The PSCW staff recommended an increase of $14.5 million for 2010 based on a 10.75 percent ROE and a 51.63 percent equity ratio.  The PSCW staff has proposed to apply the 2009 fuel over recovery discussed in 2009 Electric Fuel Cost Recovery below against the increase such that there would be no change in rates for 2010.  A summary of the proposed adjustments is listed below:

 

Millions of Dollars

 

Request

 

PSCW
Adjusted Request

 

Base non-fuel

 

$

45.1

 

$

36.8

 

Fuel

 

(14.7

)

(15.8

)

Prairie Island decommissioning

 

 

(6.5

)

Rate increase

 

$

30.4

 

$

14.5

 

 

The base non-fuel adjustments include: (1) an adjustment to the equity ratio from 53.12 percent to 51.63 percent on a regulatory basis; (2) a reduction to the rate base to account for appropriated retained earnings associated with certain hydro licenses; (3) reduced interchange agreement fixed charge billings and (4) a disallowance of certain employee compensation expenses.  In addition, the PSCW staff adjustments to the proposed increase include a $6.5 million reduction for Prairie Island nuclear plant decommissioning expense as a result of the 10-year life extension approved by the MPUC.

 

The Wisconsin Industrial Energy Group (WIEG) filed direct testimony objecting to NSP-Wisconsin’s class cost of service study and proposed rate design and recommended changes that would benefit its members.

 

A decision is expected by the end of 2009 with new rates in effect in January 2010.  The procedural schedule is as follows:

 

·                  NSP-Wisconsin rebuttal testimony on Nov. 6, 2009;

·                  Surrebuttal testimony on Nov. 10, 2009; and

·                  Technical and public hearing on Nov. 11, 2009.

 

Other

 

2009 Electric Fuel Cost Recovery — NSP-Wisconsin’s fuel and purchased power costs for February 2009 were lower than authorized and outside the variance ranges for monitored fuel costs established by the PSCW.  In April 2009, the PSCW opened a proceeding to

 

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determine if a rate reduction, or fuel credit factor, should be ordered.  The PSCW set NSP-Wisconsin’s electric rates subject to refund with interest at 10.75 percent, pending a full review of 2009 fuel costs.

 

NSP-Wisconsin’s actual fuel costs through September 2009 were approximately $19.1 million less than authorized, primarily due to lower load and lower market prices for fuel and purchased power.  As noted above, the PSCW staff recommended that a portion of this amount be used to offset the 2010 rate increase.  The PSCW has not yet completed its review of NSP-Wisconsin’s 2009 fuel costs.  However, based on actual fuel costs to date, NSP-Wisconsin has established a liability of $13.3 million for such amounts subject to refund collected through Sept. 30, 2009.

 

PSCo

 

Pending and Recently Concluded Regulatory Proceedings — Colorado Public Utilities Commission (CPUC)

 

Base Rate

 

PSCo 2009 Electric Rate Case — In November 2008, PSCo filed a request with the CPUC to increase Colorado electric rates by $174.7 million annually, or approximately 7.4 percent.  The rate filing was based on a 2009 forecast test year, an electric rate base of $4.2 billion, a requested ROE of 11.0 percent and an equity ratio of 58.08 percent.  PSCo’s request included a return of approximately $40 million for construction work in progress (CWIP) associated with incremental expenditures on the Comanche Unit 3 since Jan. 1, 2007.  PSCo does not record allowance for funds used during construction (AFDC) income for the months this return is actually received from customers.

 

In February 2009, parties filed answer testimony in the case.  In March 2009, PSCo filed rebuttal testimony and revised its rate increase request to $159.3 million to reflect updated data.  On April 22, 2009, a settlement agreement with the major parties was filed with the CPUC.  The settlement provides for an overall $112.2 million increase in base rates, but does not provide for the specific resolution of many of the disputed issues such as ROE and capital structure.  However, the settlement provides that incremental CWIP not included in existing rates for the Comanche Unit 3 be removed from rate base and that PSCo would be allowed to continue to record AFDC income on this balance until the Comanche Unit 3 is placed into service.

 

On May 27, 2009, the CPUC approved the settlement agreement and new rates went into effect on July 1, 2009.  On Sept. 21, 2009, a citizen intervenor, Leslie Glustrom, filed suit against the CPUC in district court for appeal of the CPUC decision.

 

PSCo 2010 Electric Rate Case — On May 1, 2009, PSCo filed with the CPUC a request to increase Colorado electric rates by $180.2 million, or 6.8 percent, effective in 2010.  The rate filing is based on a 2010 calendar year budget and includes a requested ROE of 11.25 percent, an electric net rate base of approximately $4.4 billion allocated to the Colorado electric retail jurisdiction and an equity ratio of 58.05 percent.

 

PSCo’s rate request also proposes to shift all or a portion of the costs currently being recovered through the Air Quality Improvement Rider and the DSM Cost Adjustment into base rates.  While this shift would add $108.1 million to base rates in addition to the $180.2 million annual revenue increase sought by PSCo, it would correspondingly remove $108.1 million from these riders, and result in no net increase or decrease on customer bills.

 

Intervenors have filed testimony with the following current recommendations:

 

·                  The CPUC staff has recommended an increase of approximately $70.5 million based on an adjusted 2008 historic test year and a 9.84 percent ROE.  The CPUC staff recommended adjustments to the 2008 historic test year were costs associated with a full year of 2010 expenses for the Comanche Unit 3 project and Fort St. Vrain Units 5 and 6.  The other staff adjustments were related to ROE, elimination of costs associated with PSCo’s annual incentive compensation plan and deferral of recovery of dismantling costs associated with retiring plants until those costs are known.  CPUC staff also recommended elimination of sharing for asset based energy sales (referred to as generation book sales).

 

·                  The Colorado Office of Consumer Counsel (OCC) has recommended an increase of approximately $33.2 million based on an adjusted 2008 historic test year and a 9.75 percent ROE.  The OCC recommended adjustments to the 2008 historic test year were costs associated with a full year of 2010 expenses for the Comanche Unit 3 project (including related pollution control and transmission upgrades) and Fort St. Vrain Units 5 and 6.  The other OCC adjustments are related to ROE, a lower equity ratio of 53 percent, a cash working capital cost reduction and additional revenue associated with unbilled revenue, elimination of incentive pay, lower pension and benefit costs, and no recovery of future Innovative Clean Technology (ICT) expense.  The OCC recommended an increase of $87.8 million if a forecast test year is accepted.  The OCC recommended that generation book

 

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margins be shared 95 percent to customers and 5 percent to shareholders and the inverse sharing for non-asset based or proprietary margins.

 

·                  Colorado Energy Consumers (CEC) recommended the use of an adjusted 2008 historic test year adjusted for major plant investments for the Comanche Unit 3 project and Fort St. Vrain Units 5 and 6; and an ROE of 10.0 percent, resulting in an increase of $95.4 million, which should be reduced to reflect any appropriate adjustments recommended by other intervenors.

 

·                  CF&I Steel (CF&I) and Climax Molybdenum Company (Climax) recommended the use of an adjusted 2008 historic test year adjusted for major plant investments for the Comanche Unit 3 project and Fort St. Vrain Units 5 and 6; and an adjustment for 2008 bonus depreciation, resulting in an increase of $98.4 million, which should be reduced to reflect any appropriate adjustments recommended by other intervenors.

 

In October 2009, PSCo filed rebuttal testimony and revised their request rate increase to $177.4 million and affirmed its requested ROE of 11.25 percent.  The procedural schedule is as follows.

 

·                  Hearings on the merits on Oct. 26 — Nov. 6, 2009; and

·                  Statements of Position on Nov. 16, 2009.

 

PSCo expects a decision before year end with new rates effective in January 2010.

 

Transmission Cost Adjustment (TCA) Rider — In December 2007, the CPUC approved PSCo’s application to implement a TCA rider.  PSCo filed its annual update to the TCA rider in November 2008, and new rates went into effect on Jan. 1, 2009, to recover approximately $18.0 million on an annual basis until the rates in the 2009 rate case take effect.  Coincident with the implementation of new electric rates on July 1, 2009, approximately $16.0 million from the TCA rider were included in base rates with a corresponding reduction in the TCA rider.

 

Pending and Recently Concluded Regulatory Proceedings — FERC

 

Pacific Northwest FERC Refund Proceeding — In July 2001, the FERC ordered a preliminary hearing to determine whether there may have been unjust and unreasonable charges for spot market bilateral sales in the Pacific Northwest for the period Dec. 25, 2000 through June 20, 2001.  PSCo supplied energy to the Pacific Northwest markets during this period and has been a participant in the hearings.  In September 2001, the presiding administrative law judge (ALJ) concluded that prices in the Pacific Northwest during the referenced period were the result of a number of factors, including the shortage of supply, excess demand, drought and increased natural gas prices.  Under these circumstances, the ALJ concluded that the prices in the Pacific Northwest markets were not unreasonable or unjust and no refunds should be ordered.  Subsequent to the ruling, the FERC has allowed the parties to request additional evidence.  Parties have claimed that the total amount of transactions with PSCo subject to refund is $34 million.  In June 2003, the FERC issued an order terminating the proceeding without ordering further proceedings.  Certain purchasers filed appeals of the FERC’s orders in this proceeding with the U. S. Court of Appeals for the Ninth Circuit.

 

In an order issued in August 2007, the Court of Appeals remanded the proceeding back to the FERC.  The Court of Appeals also indicated that the FERC should consider other rulings addressing overcharges in the California organized markets.  The Court of Appeals denied a petition for rehearing in April 2009, and the mandate was issued.  The FERC has yet to act on this order on remand; currently, certain motions concerning procedures on remand are pending before the FERC.

 

SPS

 

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

 

Base Rate

 

Texas Retail Base Rate Case — In June 2008, SPS filed a rate case with the PUCT seeking an annual rate increase of approximately $61.3 million, or approximately 5.9 percent.  Base revenues are proposed to increase by $94.4 million, while fuel and purchased power revenue would decline by $33.1 million, primarily due to fuel savings from the Lea Power Partners (LPP) purchase power agreement.

 

The rate filing was based on a 2007 test year adjusted for known and measurable changes, a requested ROE of 11.25 percent, an electric rate base of $989.4 million and an equity ratio of 51.0 percent.  Interim rates of $18 million for costs associated with the LPP power purchase agreement went into effect in September 2008.

 

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In January 2009, a settlement agreement was reached with various intervenors, which provided for a base rate increase of $57.4 million, a reduced depreciation expense of $5.6 million, allowed SPS to implement the transmission rider in 2009 and precludes SPS from filing to seek any other change in base rates until Feb. 15, 2010.  In January 2009, an ALJ approved interim rates effective February 2009.  On June 2, 2009, the PUCT issued its order approving the settlement.

 

John Deere Wind Complaint — In June 2007, several John Deere Wind Energy subsidiaries (JD Wind) filed a complaint against SPS disputing SPS’ payments for energy produced from the JD Wind projects.  SPS responded that the payments to JD Wind are appropriate and in accordance with SPS’ filed tariffs with the PUCT.  In March 2009, the ALJ recommended that SPS payment methodology to JD Wind is proper and that JD Wind’s complaint be denied.

 

In May 2009 the PUCT issued a final order denying JD Wind’s request for relief against SPS.  In June 2009, JD Wind filed a petition for review of the final order in Texas District Court.  In July 2009, the PUCT filed an answer to JD Wind’s petition in Texas District Court in which the PUCT denied each and every, all and singular, the allegations contained in the JD Wind petition.

 

In September 2009, JD Wind submitted a petition to the FERC, which in effect, disputed and sought to overturn the decision of the PUCT.  SPS has responded to the JD Wind petition, asserting among other things that the dispute should be resolved in Texas courts.

 

Texas Jurisdictional Fuel Allocation Methodology — In May 2009, SPS filed an application to revise the calculation of Texas retail jurisdictional fuel and purchased power expense, effective in January 2008.  SPS has determined that its current method results in a material amount of unrecovered fuel and purchased power expense.  The application seeks approval for a revised methodology, which matches the fuel and purchased power expenses in a month with the fuel factor revenue received from each kilowatt hour used that month.  In July 2009, the PUCT referred this case to the State Office of Administrative Hearings (SOAH) for a contested case hearing.

 

In August 2009, the PUCT issued a draft of the preliminary order.  The draft adopts SPS’ position that the PUCT should consider the fuel allocation methodology in this case; lists various issues for the case, most of which are the issues identified in SPS’ filing and lists certain issues that are not to be addressed in this case, specifically, SPS’ fuel factor, the formula used to set SPS’ fuel factor, and the reasonableness of SPS’ fuel and purchased power costs.  In August 2009, the PUCT approved the preliminary order as drafted.  A procedural schedule was established in September 2009, however, that schedule has been delayed to allow for settlement discussions.

 

In late October 2009, SPS filed a unanimous settlement that would allow for the change in the calculation of deferred fuel consistent with the approach proposed by SPS.  Approval by the PUCT is pending.  If approved, the estimated impact is expected to result in an approximate $5.9 million increase to fuel and purchased power expenses for the Texas retail jurisdiction for the Jan. 1, 2008 to Dec. 31, 2009 period.  SPS has agreed to reduce the new allocated portion by $3 million subsequent to adopting the new methodology going forward.

 

Texas Transmission Cost Recovery Factor (TCRF) In June 2009, SPS filed a request to implement a TCRF with proposed revenues of $7.4 million annually.  The TCRF filing is based on changes in transmission investment for the period of Jan. 1, 2008 through April 30, 2009 and increases in FERC approved transmission costs for 2008.  In 2007, the PUCT implemented rules allowing utilities to request a TCRF in between rate cases for recovery of new transmission investment costs.  This is SPS’ first filing under that rule.  In July 2009, the PUCT referred this case to the SOAH for a contested case proceeding.  SPS anticipates the PUCT will issue an order with rates effective by the end of 2009.

 

On Oct. 22, 2009, intervenors filed testimony and made the following recommendations.  The Texas Industrial Energy Consumers recommended a revenue requirement of $3.5 million and the Alliance of Xcel Municipalities recommended a revenue requirement of $3.1 million.

 

The current procedural schedule is as follows:

 

·                  PUCT staff testimony on Oct. 29, 2009;

·                  SPS rebuttal testimony on Nov. 5, 2009

·                  Settlement and rehearing conferences on Nov. 10 — Nov. 12, 2009; and

·                  Hearing on the merits on Nov. 17 — Nov. 19, 2009.

 

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

 

Base Rate

 

2008 New Mexico Retail Electric Rate Case — In December 2008, SPS filed with the NMPRC a request to increase electric rates in New Mexico by approximately $24.6 million, or 6.2 percent.  The request was based on a historic test year (split year based on the year ending June 30, 2008), an electric rate base of $321 million, and an equity ratio of 50.0 percent and a requested ROE of 12.0 percent.  SPS also requested interim rates of $7.6 million per year to recover capacity costs of the Lea Power facility, which became operational in September 2008.

 

In March 2009, the NMPRC approved a partial stipulated settlement between the parties that allows SPS to recover approximately $5.7 million of interim rates, effective May 1, 2009, through an LPP cost rider until the final rates from the remainder of the case are effective.

 

In May 2009, the parties filed an uncontested stipulation that resolves all issues in the case.  Under the stipulation, SPS receives a base rate increase of $14.2 million, effective July 1, 2009.  SPS has agreed that Dec. 1, 2010 is the earliest date it will file its next base rate case, subject to a force majeure provision triggered by additional environmental compliance costs.

 

In July 2009, the NMPRC issued an order approving the stipulation agreement.  SPS implemented the new rates on July 15, 2009.

 

Pending and Recently Concluded Regulatory Proceedings — FERC

 

Wholesale Rate Complaints — In November 2004, Golden Spread Electric, Lyntegar Electric, Farmer’s Electric, Lea County Electric, Central Valley Electric and Roosevelt County Electric, all wholesale cooperative customers of SPS, filed a rate complaint with the FERC alleging that SPS’ rates for wholesale service were excessive and that SPS had incorrectly calculated monthly fuel cost adjustment charges to such customers (the Complaint).  Among other things, the complainants asserted that SPS had inappropriately allocated average fuel and purchased power costs to other wholesale customers, effectively raising the fuel cost charges to the complainants.  Cap Rock Energy Corporation (Cap Rock), another full-requirements customer of SPS, Public Service Company of New Mexico (PNM) and Occidental Permian Ltd. and Occidental Power Marketing, L.P. (Occidental), SPS’ largest retail customer, intervened in the proceeding.

 

In May 2006, a FERC ALJ found that SPS should recalculate its fuel and purchased economic energy cost adjustment clause (FCAC) billings for the period beginning Jan. 1, 1999, to reduce the fuel and purchased power costs recovered from the complaining customers by deducting the incremental fuel costs attributed to SPS’ sales of capacity and energy to other wholesale customers served under market-based rates during this period based on the view that such sales should be treated as opportunity sales made out of temporarily excess capacity. In addition, the ALJ made recommendations on a number of base rate issues including a 9.64 percent ROE.

 

Golden Spread Complaint Settlement  In December 2007, SPS reached a settlement with Golden Spread (which now includes Lyntegar Electric) and Occidental regarding base rate and fuel issues raised in the complaint described above as well as a subsequent rate proceeding.  In December 2007, this comprehensive offer of settlement (the Settlement) was filed with the FERC.  In April 2008, the FERC approved the Settlement, which resolved all issues that were the subject of the Complaint; implemented a formula rate and extended the term of its partial requirements sale to Golden Spread beginning 2012 at 500 MW and ramping down to 200 MW at the end of the new term in 2019.  The Settlement made the extended purchase contingent on certain state approvals.  Golden Spread agreed to hold SPS harmless from any future adverse regulatory treatment regarding the proposed sale and SPS agreed to contingent payments ranging from $3 million to a maximum of $12 million, payable in 2012, in the event that there is an adverse cost assignment decision or a failure to obtain state approvals.  The approvals are currently pending before the NMPRC and the PUCT.

 

Order on Wholesale Rate Complaints In April 2008, the FERC issued its Order on the Complaint applied to the remaining non-settling parties.  The Order addresses base rate issues for the period from Jan. 1, 2005 through June 30, 2006, for SPS’ full requirements customers who pay traditional cost-based rates and requires certain refunds.

 

·                  Base Rates:  The FERC determined the ROE should be 9.33 percent and the treatment of market based rate contracts should be to credit revenues to the cost of service rather than allocating costs to the agreements.  The revenue requirement established by the FERC results are estimated to be approximately $25 million, or approximately $6.9 million below the level charged to these customers during this 18-month period.  Rates for full requirements customers, the New Mexico Cooperatives and Cap Rock, as well as an interruptible contract with PNM for the period beginning July 1, 2006, are the subject of settlements that have either been approved or are pending before the FERC.

 

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·                  Fuel Clause:  The FERC determined that the method for calculating fuel and purchased energy charges to the complaining customer is to deduct from such costs incremental fuel and purchased energy costs, which it is attributing to SPS’ market based intersystem sales on the basis that these are “opportunity” sales.  The FERC ordered that refunds of fuel cost charges based on this method of determining the FCAC should begin as of Jan. 1, 2005.  While the order is subject to interpretation with respect to the calculation of the refund obligation, SPS does not expect its refund obligation to its full requirements customers from Jan. 1, 2005 through March 31, 2008, to exceed $11 million.  PNM has filed a separate complaint that any refund obligation to PNM will be determined in that docket.

 

Several parties, including SPS, filed requests for rehearing on the order.  These requests are pending before the FERC.  In July 2008, SPS submitted its compliance report to the FERC and calculated the base rate refund for the 18-month period to be $6.1 million and the fuel refund to be $4.4 million.  Several wholesale customers have protested the calculations.  Once the final refund amounts are approved by the FERC, interest will be added to the refund due to the full requirements customers.  As of Sept. 30, 2009, SPS has accrued an amount sufficient to cover the estimated refund obligation.

 

On June 5, 2009, SPS, the New Mexico Cooperatives and Cap Rock filed a letter with FERC indicating that the parties had reached an agreement in principle regarding this matter and asked that the FERC not issue an order upon reconsideration to allow the parties an opportunity to formalize the Settlement and file it with the NMPRC.  The parties have filed subsequent letters with the FERC requesting that it not take up their reconsideration requests as the parties continue to work to finalize the terms of the agreement.

 

SPS 2008 Wholesale Rate Case — In March 2008, SPS filed a wholesale rate case seeking an annual revenue increase of $14.9 million or an overall 5.14 percent increase, based on 12.20 percent requested ROE.

 

In May 2008, the FERC conditionally accepted and suspended the rates and established hearing and settlement procedures.  The FERC granted a one-day suspension of rates instead of 180 days.  Lea Power achieved commercial operations in September 2008 and the proposed base rates of $9.9 million, based on a 10.25 percent ROE and a 12 coincident peak demand allocator, became effective, subject to refund.

 

In April 2009, the parties reached a settlement in which SPS will receive an annual revenue increase of approximately $9.6 million or an overall percentage increase of 3.3 percent.  The FERC issued an order approving the uncontested settlement in September 2009.

 

SPS 2008 Transmission Formula Rate Case — In December 2007, Xcel Energy submitted an application to implement a transmission formula rate for the SPS zone of the Xcel Energy Open Access Transmission Tariff (OATT).  The changed rates will affect all wholesale transmission service customers using the SPS transmission network under either the Southwest Power Pool, Inc. (SPP) Regional OATT or the Xcel Energy OATT.

 

As filed, SPS’ transmission rates would be updated annually each July 1 based on SPS’ prior year actual costs and loads plus the revenue requirements associated with projected current year transmission plant additions.  The proposed ROE was 12.7 percent, including a 50 basis point adder for SPS’ participation in the SPP Regional Transmission Organization (RTO).  The proposed rates would provide first year incremental annual transmission revenue for SPS of approximately $5.5 million.

 

In February 2008, the FERC accepted the proposed rates, suspending the effective date to July 6, 2008, and setting the rate filing for hearings and settlement procedures.  The FERC granted a 50 basis point adder to the ROE that it will determine in this proceeding as a result of SPS’ participation in the SPP RTO.  The filed rates were placed into effect on July 6, 2008, subject to refund.

 

In July 2009, SPS and the parties reached a settlement in principle regarding all issues except the ratemaking and rate design treatment of certain radial transmission lines under the SPP Regional OATT.  In September 2009, Xcel Energy, on behalf of SPS and the other parties to the proceeding, filed an uncontested offer of settlement and settlement agreement with the FERC which resolves all issues in the proceeding with the exception of the radial line issue.

 

The settlement provides for a formula rate using a fully forecasted test year effective Jan. 1, 2009, with a stated ROE of 11.27 percent (including the 50 basis point adder for SPP RTO participation), with rates for the locked in 2008 period established by settlement.  The settlement will result in approximately $0.8 million in additional revenues for 2008 and 2009 in aggregate and will allow SPS to update its transmission rates annually for predicted costs and loads, subject to an annual true-up.  In October 2009, the ALJ approved placing the settlement rates into effect on Oct. 1, 2009, subject to approval of the settlement, and certified the settlement for FERC approval as uncontested.  The settlement is pending FERC approval.  Additionally in October 2009, SPS announced the 2010 costs and charges pursuant to the formula rate and are expected to provide $2.7 million in additional revenue, subject to true-up.

 

On Sept. 25, 2009, the FERC set the issue of cost allocation for radial lines for hearings.  The ALJ is scheduled to issue an initial decision in August 2010.  The outcome of the litigation is not expected to have a material impact on SPS.

 

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7.              Commitments and Contingent Liabilities

 

Except to the extent noted below, the circumstances set forth in Notes 16, 17 and 18 to the consolidated financial statements included in Xcel Energy’s Annual Report on Form 10-K for the year ended Dec. 31, 2008, and Note 6 to the consolidated financial statements in this Quarterly Report on Form 10-Q appropriately represent, in all material respects, the current status of commitments and contingent liabilities, including those regarding public liability for claims resulting from any nuclear incident, and are incorporated herein by reference.  The following include contingencies and unresolved contingencies that are material to Xcel Energy’s financial position.

 

Environmental Contingencies

 

Xcel Energy and its subsidiaries have been, or are currently, involved with the cleanup of contamination from certain hazardous substances at several sites.  In many situations, the subsidiary involved believes it will recover some portion of these costs through insurance claims.  Additionally, where applicable, the subsidiary involved is pursuing, or intends to pursue, recovery from other potentially responsible parties (PRPs) and through the rate regulatory process.  New and changing federal and state environmental mandates can also create added financial liabilities for Xcel Energy and its subsidiaries, which are normally recovered through the rate regulatory process.  To the extent any costs are not recovered through the options listed above, Xcel Energy would be required to recognize an expense.

 

Site Remediation Xcel Energy must pay all or a portion of the cost to remediate sites where past activities of its subsidiaries or other parties have caused environmental contamination.  Environmental contingencies could arise from various situations, including sites of former manufactured gas plants (MGPs) operated by Xcel Energy subsidiaries, predecessors, or other entities; and third-party sites, such as landfills, to which Xcel Energy is alleged to be a PRP that sent hazardous materials and wastes.  At Sept. 30, 2009, the liability for the cost of remediating these sites was estimated to be $103.1 million, of which $7.2 million was considered to be a current liability.

 

Manufactured Gas Plant Sites

 

Ashland Manufactured Gas Plant Site NSP-Wisconsin has been named a PRP for creosote and coal tar contamination at a site in Ashland, Wis.  The Ashland/Northern States Power Lakefront Superfund Site (Ashland site) includes property owned by NSP-Wisconsin, which was previously an MGP facility and two other properties: an adjacent city lakeshore park area, on which an unaffiliated third party previously operated a sawmill, and an area of Lake Superior’s Chequamegon Bay adjoining the park.

 

In September 2002, the Ashland site was placed on the National Priorities List.  A final determination of the scope and cost of the remediation of the Ashland site is not currently expected until late 2009 or 2010.  In October 2004, the state of Wisconsin filed a lawsuit in Wisconsin state court for reimbursement of past oversight costs incurred at the Ashland site between 1994 and March 2003 in the approximate amount of $1.4 million.  The state also alleges a claim for forfeitures and interest.  This litigation was resolved in the first quarter of 2009, and all costs paid to the state are expected to be recoverable in rates.

 

In November 2005, the Environmental Protection Agency (EPA) Superfund Innovative Technology Evaluation Program (SITE) accepted the Ashland site into its program.  As part of the SITE program, NSP-Wisconsin proposed and the EPA accepted a site demonstration of an in situ, chemical oxidation technique to treat upland ground water and contaminated soil.  The fieldwork for the demonstration study was completed in February 2007.  In June 2007, the EPA modified its remedial investigation report to establish final remedial action objectives (RAOs) and preliminary remediation goals (PRGs) for the Ashland site.  In October 2007, the EPA approved the series of reports included in the remedial investigation report.  The RAOs and PRGs could potentially impact the development and evaluation of remedial options for ultimate site cleanup.

 

In 2008, NSP-Wisconsin spent $0.8 million in the development of the work plan, the operation of the existing interim response action and other matters related to the site.  In December 2008, the EPA approved the final feasibility study submitted by NSP-Wisconsin.  The final feasibility study sets forth a range of remedial options under consideration by the EPA for the site but does not select a remedy.  In 2009, the EPA issued its proposed remedial action plan (PRAP).  It is expected that the EPA will select a remedial action plan sometime in late 2009.  The estimated remediation costs for the cleanup proposed by the EPA in the PRAP range between $94.4 million and $112.8 million.

 

In July 2009, NSP-Wisconsin advised the EPA and the Wisconsin Department of Natural Resources (WDNR) that it would not implement the hybrid “dry dredging” alternative proposed in the PRAP.  NSP-Wisconsin stated that the EPA’s hybrid alternative is 1) unsafe, 2) would cost at least $37 million more than conventional, wet dredging, and 3) would provide no environmental benefits over conventional dredging.

 

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In addition to potential liability for remediation, NSP-Wisconsin may also have liability for natural resource damages at the Ashland site.  NSP-Wisconsin has recorded an estimate of its potential liability based upon its best estimate of potential exposure.

 

NSP-Wisconsin’s liability for the actual cost of remediating the Ashland site and the time frame over which the amounts may be paid out are not determinable, until the EPA and the WDNR select a remediation strategy for the entire site and determine NSP-Wisconsin’s level of responsibility.  NSP-Wisconsin continues to work with the WDNR to access state and federal funds to apply to the ultimate remediation cost of the entire site.  NSP-Wisconsin has recorded a liability of $97.5 million based upon the minimum of the range of remediation costs established by the PRAP, together with estimated outside legal, consultant and remedial design costs.  NSP-Wisconsin has deferred, as a regulatory asset, the costs accrued for the Ashland site 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 recovery in NSP-Wisconsin rates of all remediation costs incurred at the Ashland site and has authorized recovery of similar remediation costs for other Wisconsin utilities.  External MGP remediation costs are subject to deferral in the Wisconsin retail jurisdiction and are reviewed for prudence as part of the Wisconsin biennial retail rate case process.

 

In addition, in 2003, the Wisconsin Supreme Court rendered a ruling that reopens the possibility that NSP-Wisconsin may be able to recover a portion of the remediation costs from its insurance carriers.  Any insurance proceeds received by NSP-Wisconsin will be credited to ratepayers.

 

Third Party and Other Environmental Site Remediation

 

Asbestos Removal — Some of Xcel Energy’s facilities contain asbestos.  Most asbestos will remain undisturbed until the facilities that contain it are demolished or renovated.  Xcel Energy has recorded an estimate for final removal of the asbestos as an asset retirement obligation (ARO).

 

See additional discussion of AROs in Note 17 to the Xcel Energy Annual Report on Form 10-K for the year ended Dec. 31, 2008.  It may be necessary to remove some asbestos to perform maintenance or make improvements to other equipment.  The cost of removing asbestos as part of other work is immaterial and is recorded as incurred as operating expenses for maintenance projects, capital expenditures for construction projects or removal costs for demolition projects.

 

Other Environmental Requirements

 

EPA’s Proposed Greenhouse Gas Endangerment Finding — On April 17, 2009, the EPA issued a proposed finding that GHGs threaten public health and welfare.  This finding was in response to the U.S. Supreme Court’s decision in Massachusetts v. EPA, 549 U.S. 497 (2007), which held that GHGs are pollutants covered by the Clean Air Act (CAA) and required the EPA to determine whether emissions of GHGs from motor vehicles endanger public health or welfare.  The EPA’s proposed endangerment finding applies to the CAA’s mobile source program, and does not automatically trigger regulation under other provisions of the CAA that are applicable to stationary sources, such as power plants.  As such, the proposed endangerment finding, in and of itself, does not impact Xcel Energy or its operating subsidiaries.

 

Clean Air Interstate Rule (CAIR) — In March 2005, the EPA issued the CAIR to further regulate sulfur dioxide (SO2) and nitrogen oxide (NOx) emissions.  The objective of CAIR was to cap emissions of SO2 and NOx in the eastern United States, including Minnesota, Texas and Wisconsin, which are within Xcel Energy’s service territory.  In July 2008, the U. S. Court of Appeals for the District of Columbia vacated CAIR and remanded the rule to EPA. On Dec. 23, 2008, the court reinstated CAIR while the EPA develops new regulations in accordance with the court’s July opinion.  The EPA has indicated that a CAIR replacement rule will be proposed in early 2010 with finalization planned for early 2011.

 

As currently written, CAIR has a two-phase compliance schedule, beginning in 2009 for NOx and 2010 for SO2, with a final compliance deadline in 2015 for both emissions.  Under CAIR, each affected state will be allocated an emissions budget for SO2 and NOx that will result in significant emission reductions.  It will be based on stringent emission controls and forms the basis for a cap-and-trade program.  State emission budgets or caps decline over time.  States can choose to implement an emissions reduction program based on the EPA’s proposed model program, or they can propose another method, which the EPA would need to approve.

 

Under CAIR’s cap-and-trade structure, SPS can comply through capital investments in emission controls or purchase of emission allowances from other utilities making reductions on their systems.  The remaining capital investments for NOx controls in the SPS region are estimated at $4.5 million.  For 2009, the estimated NOx allowance compliance costs are $0.8 million to $1.0 million.  Annual purchases of SO2 allowances are estimated in the range of $1.7 million to $7.7 million each year, beginning in 2013, for phase I.

 

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On May 12, 2009, the EPA issued a proposed rule to stay the effectiveness of CAIR in Minnesota.  NSP-Minnesota expects the EPA to complete this regulatory action before 2009 NOx allowances must be surrendered in February 2010.  As such, cost estimates are not included at this time for NSP-Minnesota.  For 2009, the estimated NOx allowance costs for NSP-Wisconsin are $0.3 million.

 

Allowance cost estimates for SPS and NSP-Wisconsin are based on fuel quality and current market data.  Xcel Energy believes the cost of any required capital investment or allowance purchases will be recoverable from customers in rates.

 

Clean Air Mercury Rule (CAMR) — In March 2005, the EPA issued the CAMR, which regulated mercury emissions from power plants.  In February 2008, the U.S. Court of Appeals for the District of Columbia vacated CAMR, which impacts federal CAMR requirements, but not necessarily state-only mercury legislation and rules.  The EPA is in the process of developing a Maximum Achievable Control Technology (MACT) rule to replace CAMR.  The EPA is expected to propose the new MACT rule for electric generating units in 2010.  Costs to comply with the Minnesota Mercury Emissions Reduction Act of 2006 are discussed in the following sections.

 

In Colorado, the Air Quality Control Commission (AQCC) passed a mercury rule, which requires mercury emission controls capable of achieving 80 percent capture to be installed at the Pawnee Generating Station by 2012 and other specified units by 2014.  The expected cost estimate for the Pawnee Generating Station is $2.3 million for capital costs with an annual estimate of $1.4 million for absorbent expense.  PSCo is evaluating the emission controls required to meet the state rule for the remaining units and is currently unable to provide a total capital cost estimate.

 

Minnesota Mercury Legislation — In May 2006, the Minnesota legislature enacted the Mercury Emissions Reduction Act of 2006 (Act) providing a process for plans, implementation and cost recovery for utility efforts to curb mercury emissions at certain power plants.  For NSP-Minnesota, the Act covers units at the A. S. King and Sherco generating facilities.  Xcel Energy installed and is operating and maintaining continuous mercury emission monitoring systems at these generating facilities.

 

In September 2006, NSP-Minnesota filed a request with the MPUC for recovery of up to $6.3 million of certain environmental improvement costs recoverable under the Act.  In January 2007, the MPUC approved this request to defer these costs as a regulatory asset with a cap of $6.3 million.  In November 2008, NSP-Minnesota filed a request with the MPUC to reflect its requested recovery of these emission reduction compliance costs incurred through 2009 in the NSP-Minnesota electric rate case.  In June 2009, NSP-Minnesota received an order from the MPUC closing the docket to correspond with the inclusion of costs in the electric rate case.  The recovery of the costs was allowed as part of the rate case.

 

In November 2008, the MPUC approved and ordered the implementation of the Sherco Unit 3 and A. S. King mercury emission reduction plans.  The approved plans are to install a sorbent injection system at both A. S. King and Sherco Unit 3.  Implementation would occur by Dec. 31, 2009 at Sherco Unit 3 and by Dec. 31, 2010 at A. S. King.  In July 2009, NSP-Minnesota filed a petition with the MPUC requesting to establish a mercury cost recovery rider with 2010 adjustment factors that would recover the 2010 revenue requirement of $3.5 million associated with these two projects from customers.

 

In the fourth quarter of 2009, NSP-Minnesota expects to file plans for mercury control at Sherco Units 1 and 2 with the MPUC and the Minnesota Pollution Control Agency (MPCA).  Assuming these plans are approved, NSP-Minnesota expects to file for recovery of the costs to implement these plans through the mercury cost recovery rider.

 

Regional Haze Rules — In June 2005, the EPA finalized amendments to the July 1999 regional haze rules.  These amendments apply to the provisions of the regional haze rule that require emission controls, known as best available retrofit technology (BART), for industrial facilities emitting air pollutants that reduce visibility by causing or contributing to regional haze.  Xcel Energy generating facilities in several states will be subject to BART requirements.

 

States are required to identify the facilities that will have to reduce SO2, NOx and particulate matter emissions under BART and then set BART emissions limits for those facilities.  In May 2006, the Colorado AQCC promulgated BART regulations requiring certain major stationary sources to evaluate and install, operate and maintain BART to make reasonable progress toward meeting the national visibility goal.  PSCo estimates that the remaining cost for implementation of BART emission control projects is approximately $141 million in capital costs, which are included in the capital budget.

 

PSCo expects the cost of any required capital investment will be recoverable from customers.  Emissions controls are expected to be installed between 2012 and 2015.  Colorado’s BART state implementation plan has been submitted to the EPA for approval.  In January 2009, the Colorado Air Pollution Control Division (CAPCD) initiated a joint stakeholder process to evaluate what types of additional NOx controls may be necessary to meet reasonable progress goals for Colorado’s Class I areas, the new ozone standard, and Rocky Mountain National Park nitrogen deposition reduction goals.  The CAPCD has indicated that it expects to have a final plan for additional point-source NOx controls by the end of 2010.

 

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NSP-Minnesota submitted its BART alternatives analysis for Sherco Units 1 and 2 in October 2006.  The MPCA reviewed the BART analyses for all units in Minnesota and determined that overall, compliance with CAIR is better than BART.  On Nov. 13, 2008, NSP-Minnesota submitted a revised BART alternatives analysis letter to the MPCA to account for increased construction and equipment costs.  The underlying conclusions and proposed emission control equipment, however, remain unchanged from the original 2006 BART analysis.  The MPCA completed their BART determination and proposed SO2 and NOx limits in the draft state implementation plan (SIP) that are equivalent to the reductions made under CAIR.

 

In response to a petition from several environmental groups, the U.S. Department of Interior certified on Oct. 21, 2009, that a portion of the visibility impairment in Voyageurs and Isle Royal National Parks is reasonably attributable to emissions from Sherco Units 1 and 2.  The MPCA determined, however, that this certification does not alter the proposed SIP.  The SIP proposes BART controls for Sherco that are designed to improve visibility in the national parks, but does not require Selective Catalytic Reduction (SCR) on Units 1 and 2.  The MPCA concluded that the minor visibility benefits derived from SCR do not outweigh the substantial costs.  The MPCA will now work with the MPCA Citizens Board for approval of the SIP, which will then be submitted to the EPA for approval before the end of 2009.

 

Federal Clean Water Act — The federal Clean Water Act requires the EPA to regulate cooling water intake structures to assure that these structures reflect the best technology available (BTA) for minimizing adverse environmental impacts.  In July 2004, the EPA published phase II of the rule, which applies to existing cooling water intakes at steam-electric power plants.  Several lawsuits were filed against the EPA in the United States Court of Appeals for the Second Circuit (Court of Appeals) challenging the phase II rulemaking.  In January 2007, the Court of Appeals issued its decision and remanded the rule to the EPA for reconsideration.  In June 2007, the EPA suspended the deadlines and referred any implementation to each state’s best professional judgment until the EPA is able to fully respond to the remand.  In April 2008, the U.S. Supreme Court granted limited review of the Court of Appeals’ opinion to determine whether the EPA has the authority to consider costs and benefits in assessing BTA.  On April 1, 2009, the U.S. Supreme Court issued a decision in Entergy Corp. v. Riverkeeper, Inc., concluding that the EPA can consider a cost benefit analysis when establishing BTA.  The decision overturned only one aspect of the Court of Appeals’ earlier opinion, and gives the EPA the discretion to consider costs and benefits when it reconsiders its phase II rules.  Until the EPA fully responds to the Court of Appeals’ decision, the rule’s compliance requirements and associated deadlines will remain unknown.  As such, it is not possible to provide an accurate estimate of the overall cost of this rulemaking at this time.

 

The MPCA exercised its authority under best professional judgment to require the Black Dog Generating Station in its recently renewed wastewater discharge permit to create a plan by April 2010 to reduce the plant intake’s impact on aquatic wildlife.  NSP-Minnesota is discussing alternatives with the local community and regulatory agencies to address this concern.

 

PSCo Notice of Violation (NOV) — In July 2002, PSCo received an NOV from the EPA alleging violations of the New Source Review (NSR) requirements of the CAA at the Comanche Station and Pawnee Station in Colorado.  The NOV specifically alleges that various maintenance, repair and replacement projects undertaken at the plants in the mid- to late-1990s should have required a permit under the NSR process.  PSCo believes it has acted in full compliance with the CAA and NSR process.  PSCo believes that the projects identified in the NOV fit within the routine maintenance, repair and replacement exemption contained within the NSR regulations or are otherwise not subject to the NSR requirements.  PSCo disagrees with the assertions contained in the NOV and intends to vigorously defend its position.

 

Legal Contingencies

 

Lawsuits and claims arise in the normal course of business.  Management, after consultation with legal counsel, has recorded an estimate of the probable cost of settlement or other disposition of them.  The ultimate outcome of these matters cannot presently be determined.  Accordingly, the ultimate resolution of these matters could have a material adverse effect on Xcel Energy’s financial position and results of operations.

 

Gas Trading Litigation

 

e prime is a wholly owned subsidiary of Xcel Energy.  Among other things, e prime was in the business of natural gas trading and marketing.  e prime has not engaged in natural gas trading or marketing activities since 2003.  Thirteen lawsuits have been commenced against e prime and Xcel Energy (and NSP-Wisconsin, in one instance), alleging fraud and anticompetitive activities in conspiring to restrain the trade of natural gas and manipulate natural gas prices.  Xcel Energy, e prime, and NSP-Wisconsin deny these allegations and will vigorously defend against these lawsuits, including seeking dismissal and summary judgment.

 

The initial gas-trading lawsuit, a purported class action brought by wholesale natural gas purchasers, was filed in November 2003 in the United States District Court in the Eastern District of California.  e prime is one of several defendants named in the complaint.  This case is captioned Texas-Ohio Energy vs. CenterPoint Energy et al.  The other twelve cases arising out of the same or similar set of facts are captioned Fairhaven Power Company vs. EnCana Corporation et al.; Ableman Art Glass vs. EnCana Corporation et al.; Utility Savings and Refund Services LLP vs. Reliant Energy Services Inc. et al.; Sinclair Oil Corporation vs. e prime and Xcel

 

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Energy Inc.; Ever-Bloom Inc. vs. Xcel Energy Inc. and e prime et al.; Learjet, Inc. vs. e prime and Xcel Energy Inc et al.; J.P. Morgan Trust Company vs. e prime and Xcel Energy Inc. et al.; Breckenridge Brewery vs. e prime and Xcel Energy Inc. et al.; Missouri Public Service Commission vs. e prime, inc. and Xcel Energy Inc. et al.; Arandell vs. e prime, Xcel Energy, NSP-Wisconsin et al.; NewPage Wisconsin System Inc vs. e prime, Xcel Energy, NSP-Wisconsin et al. and Hartford Regional Medical Center vs. e prime, Xcel Energy et al. Many of these cases involve multiple defendants and have been transferred to Judge Phillip Pro of the United States District Court in Nevada, who is the judge assigned to the Western Area Wholesale Natural Gas Antitrust Litigation.

 

e prime and some other defendants were dismissed from the Breckenridge Brewery lawsuit in February 2008, but Xcel Energy remains a defendant in that lawsuit and e prime Energy Marketing was added as a defendant in February 2008.

 

No trial dates have been set for any of these lawsuits.  In January 2009, the parties reached a settlement agreement in principle in the Abelman Art Glass, Ever Bloom, Fairhaven Power Company, Texas-Ohio Energy, and Utility Savings and Refund Services cases.  The terms of the settlement in principle will not have a material financial effect upon Xcel Energy.  Per court order, discovery in most of the remaining cases must be completed by Dec. 5, 2009.  Trial for all cases venued in Nevada will likely be set for 2010.

 

In November 2007, the Missouri Public Service Commission case was remanded to Missouri state court.  On Jan. 13, 2009, the Missouri state court granted defendants’ motion to dismiss plaintiff’s complaint for lack of standing.  Plaintiffs have filed an appeal.

 

In late March 2009, Newpage Wisconsin System Inc. commenced a lawsuit in state court in Wood County, Wis.  The allegations are substantially similar to Arandell and name several defendants, including Xcel Energy, e prime and NSP-Wisconsin.  In September 2009, Plaintiffs moved to consolidate the Newpage and Arandell matters.  Defendants have filed motions to dismiss and, as with Arandell, Xcel Energy, e prime and NSP-Wisconsin believe the allegations asserted against them are without merit and they intend to vigorously defend against the asserted claims.

 

Environmental Litigation

 

Carbon Dioxide (CO2) Emissions Lawsuit — In July 2004, the attorneys general of eight states and New York City, as well as several environmental groups, filed lawsuits in U.S. District Court in the Southern District of New York against five utilities, including Xcel Energy, to force reductions in CO2 emissions.  The other utilities include American Electric Power Co., Southern Co., Cinergy Corp. and Tennessee Valley Authority.  The lawsuits allege that CO2 emitted by each company is a public nuisance as defined under state and federal common law because it has contributed to global warming.  The lawsuits do not demand monetary damages.  Instead, the lawsuits ask the court to order each utility to cap and reduce its CO2 emissions.  In October 2004, Xcel Energy and the other defendants filed a motion to dismiss the lawsuit.  On Sept. 19, 2005, the court granted the motion to dismiss on constitutional grounds.  Plaintiffs filed an appeal to the U.S. Court of Appeals for the Second Circuit.  In June 2007, the Court of Appeals issued an order requesting the parties to file a letter brief regarding the impact of the United States Supreme Court’s decision in Massachusetts v. EPA, 127 S. Ct. 1438 (April 2, 2007) on the issues raised by the parties on appeal.  Among other things, in its decision in Massachusetts v. EPA, the United States Supreme Court held that CO2 emissions are a “pollutant” subject to regulation by the EPA under the CAA.  In July 2007, in response to the request of the Court of Appeals, the defendant utilities filed a letter brief stating the position that the United States Supreme Court’s decision supports the arguments raised by the utilities on appeal.  On Sept. 21, 2009, the Court of Appeals issued an opinion reversing the lower court decision.  Xcel Energy intends to file a petition for rehearing or rehearing en banc on or before Nov. 5, 2009.

 

Comer vs. Xcel Energy Inc. et al. — In April 2006, Xcel Energy received notice of a purported class action lawsuit filed in U.S. District Court in the Southern District of Mississippi.  The lawsuit names more than 45 oil, chemical and utility companies, including Xcel Energy, as defendants and alleges that defendants’ CO2 emissions “were a proximate and direct cause of the increase in the destructive capacity of Hurricane Katrina.”  Plaintiffs allege in support of their claim, several legal theories, including negligence and public and private nuisance and seek damages related to the loss resulting from the hurricane.  Xcel Energy believes this lawsuit is without merit and intends to vigorously defend itself against these claims.  In August 2007, the court dismissed the lawsuit in its entirety against all defendants on constitutional grounds.  In September 2007, plaintiffs filed a notice of appeal to the U.S. Court of Appeals for the Fifth Circuit.  Oral arguments were presented to the Court of Appeals on Aug. 6, 2008.  Pursuant to the court’s order of Sept. 26, 2008, re-argument was held on Nov. 3, 2008.  On Oct. 16, 2009, the U.S. Court of Appeals for the Fifth Circuit reversed the district court decision, in part, concluding that the plaintiffs pleaded sufficient facts to overcome the constitutional challenges that formed the basis for dismissal by the district court.  It is anticipated that Xcel Energy will file a petition for rehearing or rehearing en banc.

 

Native Village of Kivalina vs. Xcel Energy Inc. et al. — In February 2008, the City and Native Village of Kivalina, Alaska, filed a lawsuit in U.S. District Court for the Northern District of California against Xcel Energy and 23 other utilities, oil, gas and coal companies.  The suit was brought on behalf of approximately 400 native Alaskans, the Inupiat Eskimo, who claim that defendants’ emission of CO2 and other GHGs contribute to global warming, which is harming their village.  Plaintiffs claim that as a consequence,

 

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the entire village must be relocated at a cost of between $95 million and $400 million.  Plaintiffs assert a nuisance claim under federal and state common law, as well as a claim asserting “concert of action” in which defendants are alleged to have engaged in tortious acts in concert with each other.  Xcel Energy was not named in the civil conspiracy claim.  Xcel Energy believes the claims asserted in this lawsuit are without merit and joined with other utility defendants in filing a motion to dismiss on June 30, 2008.  On Oct. 15, 2009, the U.S. District Court dismissed the lawsuit on constitutional grounds.  It is unknown whether plaintiffs intend to appeal this decision.

 

Comanche Unit 3 Clean Air Act Lawsuit WildEarth Guardians (WEG) has filed a lawsuit against PSCo alleging that PSCo violated the CAA by constructing Comanche Unit 3 without a final MACT determination from the Colorado Department of Public Health and Environment, Air Pollution Control Division (APCD).  PSCo disputes these claims and has filed a motion to dismiss the suit.  Comanche Unit 3 was constructed with state-of-the-art emission controls and pursuant to a valid air permit issued by the APCD.  On Oct. 28, 2009, WEG filed a motion for a preliminary injunction, seeking to enjoin PSCo from constructing, modifying, or operating Comanche Unit 3 prior to receiving a final MACT determination.  PSCo strongly opposes the injunction.  Among other issues, PSCo believes that WEG has failed to establish a substantial likelihood of prevailing on the merits of the suit and that therefore there is no valid legal basis upon which an injunction should be issued.

 

Employment, Tort and Commercial Litigation

 

Siewert vs. Xcel Energy — In June 2004, plaintiffs, the owners and operators of a Minnesota dairy farm, brought an action in Minnesota state court against NSP-Minnesota alleging negligence in the handling, supplying, distributing and selling of electrical power systems; negligence in the construction and maintenance of distribution systems; and failure to warn or adequately test such systems.  Plaintiffs allege decreased milk production, injury, and damage to a dairy herd as a result of stray voltage resulting from NSP-Minnesota’s distribution system.  Plaintiffs claim losses of approximately $7 million.  NSP-Minnesota denies all allegations.  After its motion to dismiss plaintiffs’ claims was denied, NSP-Minnesota filed a motion to certify questions for immediate appellate review.  In October 2007, the court granted NSP-Minnesota’s motion for certification, and oral arguments took place on Sept. 11, 2008.  Mediation took place on Oct. 14, 2008, but the matter was not resolved.  In December 2008, the Court of Appeals issued a decision ordering dismissal of Plaintiffs’ claims for injunctive relief, but otherwise rejecting NSP-Minnesota’s contentions and ordering the matter remanded for trial.  The Minnesota Supreme Court subsequently granted NSP-Minnesota’s petition for further review on Feb. 17, 2009.  All briefs have been filed, but the Court has not yet set a date for oral argument.

 

Qwest vs. Xcel Energy Inc. — In June 2004, an employee of PSCo was seriously injured when a pole owned by Qwest malfunctioned.  In September 2005, the employee commenced an action against Qwest in Colorado state court in Denver.  In April 2006, Qwest filed a third party complaint against PSCo based on terms in a joint pole use agreement between Qwest and PSCo.  Pursuant to this agreement, Qwest asserted PSCo had an affirmative duty to properly train and instruct its employees on pole safety, including testing the pole for soundness before climbing.  In May 2006, PSCo filed a counterclaim against Qwest asserting Qwest had a duty to PSCo and an obligation under the contract to maintain its poles in a safe and serviceable condition.  In May 2007, the matter was tried and the jury found Qwest solely liable for the accident and this determination resulted in an award of damages in the amount of approximately $90 million.  On June 16, 2008, Qwest filed its appellate brief.  On April 30, 2009, the Colorado Court of Appeals affirmed the jury verdict insofar as it relates to claims asserted by Qwest against PSCo.  Qwest subsequently filed a petition for rehearing with the Colorado Court of Appeals.  On May 28, 2009, the Colorado Court of Appeals denied Qwest’s request for rehearing.  Qwest’s petition for certiorari to the Colorado Supreme Court was filed June 26, 2009.  PSCo’s response brief was filed on July 27, 2009.  The matter has been fully briefed, and PSCo is awaiting a ruling from the Colorado Supreme Court.

 

MGP Insurance Coverage Litigation — In October 2003, NSP-Wisconsin initiated discussions with its insurers regarding the availability of insurance coverage for costs associated with the remediation of four former MGP sites located in Ashland, Chippewa Falls, Eau Claire and LaCrosse, Wis.  In lieu of participating in discussions, in October 2003, two of NSP-Wisconsin’s insurers, St. Paul Fire & Marine Insurance Co. and St. Paul Mercury Insurance Co., commenced litigation against NSP-Wisconsin in Minnesota state district court.  In November 2003, NSP-Wisconsin commenced suit in Wisconsin state court against St. Paul Fire & Marine Insurance Co. and its other insurers.  Subsequently, the Minnesota court enjoined NSP-Wisconsin from pursuing the Wisconsin litigation.  The Wisconsin action remains in abeyance.

 

NSP-Wisconsin has reached settlements with 22 insurers, and these insurers have been dismissed from both the Minnesota and Wisconsin actions.  NSP-Wisconsin has also reached settlements in principle with Ranger Insurance Company (Ranger), TIG Insurance Company (TIG), Royal Indemnity Company and Globe Indemnity Company.

 

In July 2007, the Minnesota state court issued a decision on allocation, reaffirming its prior rulings that Minnesota law on allocation should apply and ordering the dismissal, without prejudice, of 11 insurers whose coverage would not be triggered under such an allocation method.  In September 2007, NSP-Wisconsin commenced an appeal in the Minnesota Court of Appeals challenging the dismissal of these carriers.

 

On Aug. 25, 2009, the Minnesota Court of Appeals affirmed the district court decision.  NSP-Wisconsin subsequently filed a petition for review of this decision with the Minnesota Supreme Court.  It is uncertain when the Minnesota Supreme Court will rule on whether to grant review pursuant to the petition.

 

The PSCW has established a deferral process whereby clean-up costs associated with the remediation of former MGP sites are deferred and, if approved by the PSCW, recovered from ratepayers.  Carrying charges associated with these clean-up costs are not subject to the deferral process and are not recoverable from ratepayers.  Any insurance proceeds received by NSP-Wisconsin will be credited to ratepayers.  None of the aforementioned lawsuit settlements are expected to have a material effect on Xcel Energy’s consolidated financial statements.

 

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Nuclear Waste Disposal Litigation — In 1998, NSP-Minnesota filed a complaint in the U.S. Court of Federal Claims against the United States requesting breach of contract damages for the U.S. Department of Energy’s (DOE) failure to begin accepting spent nuclear fuel by Jan. 31, 1998, as required by the contract between the DOE and NSP-Minnesota.  At trial, NSP-Minnesota claimed damages in excess of $100 million through Dec. 31, 2004.  On Sept. 26, 2007, the court awarded NSP-Minnesota $116.5 million in damages.  In December 2007, the court denied the DOE’s motion for reconsideration.  In February 2008, the DOE filed an appeal to the U.S. Court of Appeals for the Federal Circuit, and NSP-Minnesota cross-appealed on the cost of capital issue.  In April 2008, the DOE asked the Court of Appeals to stay briefing until the appeals in several other nuclear waste cases have been decided, and the Court of Appeals granted the request.  In December 2008, NSP-Minnesota made a motion in the Court of Appeals to lift the stay, which was denied by the Court of Appeals in February 2009.  Results of the judgment will not be recorded in earnings until the appeal, regulatory treatment and amounts to be shared with ratepayers have been resolved.  Given the uncertainties, it is unclear as to how much, if any, of this judgment will ultimately have a net impact on earnings.

 

In August 2007, NSP-Minnesota filed a second complaint against the DOE in the U.S. Court of Federal Claims (NSP II), again claiming breach of contract damages for the DOE’s continuing failure to abide by the terms of the contract.  This lawsuit will claim damages for the period Jan. 1, 2005 through Dec. 31, 2008, which includes costs associated with the storage of spent nuclear fuel at Prairie Island and Monticello, as well as the costs of complying with state regulation relating to the storage of spent nuclear fuel.  Per the court’s scheduling order, NSP-Minnesota’s expert report on damages was submitted on April 15, 2009, and asserts damages in excess of $250 million.  In late August 2009, the Court agreed to give the DOE an unspecified extension of time to clarify issues regarding NSP-Minnesota’s claim and to file its expert report.  Trial is expected to take place in 2010.

 

Mallon vs. Xcel Energy Inc. — In August 2007, Xcel Energy, PSCo and PSR Investments, Inc. (PSRI) ( hereafter “ Plaintiffs”) commenced a lawsuit in Colorado state court against Theodore Mallon and TransFinancial Corporation seeking damages for, among other things, breach of contract and breach of fiduciary duties associated with the sale of Corporate Owned Life Insurance (COLI) policies.  In May 2008, Plaintiffs filed an amended complaint that, among other things, adds Provident Life & Accident Insurance Company (Provident) as a defendant and asserts claims for breach of contract, unjust enrichment and fraudulent concealment against the insurance company.  On June 23, 2008, Provident filed a motion to dismiss the complaint.  On Oct. 22, 2008, the court granted Provident’s motion in part, but denied the motion with respect to a majority of the core causes of action asserted by Plaintiffs.  In September 2009, Plaintiffs reached a settlement with Mallon and TransFinancial Corporation.  Pursuant to the terms of the agreement, Mallon agreed to pay Plaintiffs a specified amount and the parties agreed to mutually release each other from all claims.  Plaintiffs continue to prosecute their claims against Provident.  A trial concerning these claims is expected in early 2010.

 

Cabin Creek Hydro Generating Station Accident — In October 2007, employees of RPI Coatings Inc. (RPI), a contractor retained by PSCo, were applying an epoxy coating to the inside of a penstock at PSCo’s Cabin Creek Hydro Generating Station near Georgetown, Colo.  This work was being performed as part of a corrosion prevention effort.  A fire occurred inside the penstock, which is a 4,000-foot long, 12-foot wide pipe used to deliver water from a reservoir to the hydro facility.  Four of the nine RPI employees working inside the penstock were positioned below the fire and were able to exit the pipe.  The remaining five RPI employees were unable to exit the penstock.  Rescue crews located the five employees a few hours later and confirmed their deaths.  The accident was investigated by several state and federal agencies, including the federal Occupational Safety and Health Administration (OSHA) and the U.S. Chemical Safety Board and the Colorado Bureau of Investigations.

 

In March 2008, OSHA proposed penalties totaling $189,900 for twenty-two serious violations and three willful violations arising out of the accident.  In April 2008, Xcel Energy notified OSHA of its decision to contest all of the proposed citations.  On May 28, 2008, the Secretary of Labor filed its complaint, and Xcel Energy subsequently filed its answer on June 17, 2008.  The Court ordered this proceeding stayed until March 3, 2009 and subsequently extended the stay to October 2009.  A lawsuit was filed in Colorado state court in Denver on behalf of four of the deceased workers and four of the injured workers (Foster, et. al. v. PSCo, et. al.).  PSCo and Xcel Energy were named as defendants in that case, along with RPI Coatings and related companies and the two other contractors who also performed work in connection with the relining project at Cabin Creek.  A second lawsuit (Ledbetter et. al vs. PSCo et. al) was also filed in Colorado state court in Denver on behalf of three employees allegedly injured in the accident.  A third lawsuit was filed on behalf of one of the deceased RPI workers in the California state court (Aguirre v. RPI, et. al.), naming PSCo, RPI, and the two other contractors as defendants.  The court subsequently dismissed the Aguirre lawsuit.  Settlements were subsequently reached in all three lawsuits.  These confidential settlements are not expected to have a material effect on the financial statements of Xcel Energy or its subsidiaries.

 

On Aug. 28, 2009, the U. S. Government announced that Xcel Energy and PSCo have been charged with five misdemeanor counts in federal court in Colorado for violation of an OSHA regulation related to the accident at Cabin Creek in October 2007.  RPI Coatings, the contractor performing the work at the plant, and two individuals employed by RPI have also been indicted.  On Sept. 22, 2009, both Xcel Energy and PSCo entered a not guilty plea, and both will vigorously defend against these charges.

 

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Stone & Webster, Inc. vs. PSCo — On July 14, 2009, Stone & Webster, Inc. (Shaw) filed a complaint against PSCo in State District Court in Denver, Colo. for damages allegedly arising out of its construction work on the Comanche Unit 3 coal fired plant in Pueblo, Colo.  Shaw, a contractor retained to perform certain engineering, procurement and construction work on Comanche Unit 3, alleges, among other things, that PSCo was responsible for and mismanaged the construction of Comanche Unit 3.  Shaw further claims that this alleged mismanagement caused delays and damages in excess of $55 million.  The complaint also alleges that Xcel Energy and related entities, including PSCo, guaranteed Shaw $10 million in future profits under the terms of a 2003 settlement agreement.  Shaw alleges that it will not receive the $10 million to which it is entitled.  Accordingly, Shaw seeks an amount up to $10 million relating to the 2003 settlement agreement.  PSCo denies these allegations and believes the claims are without merit.  PSCo filed an answer and counterclaim in August 2009, denying the allegations in the complaint and alleging that Shaw has failed to discharge its contractual obligations and has caused delays, and that PSCo is entitled, among other things, to liquidated damages and excess costs incurred.  It is not anticipated that this lawsuit will affect Comanche Unit 3’s scheduled in-service date.

 

Fru-Con Construction Corporation vs. Utility Engineering Corporation (UE) et al. — In March 2005, Fru-Con Construction Corporation (Fru-Con) commenced a lawsuit in U.S. District Court in the Eastern District of California against UE and the Sacramento Municipal Utility District (SMUD) for damages allegedly suffered during the construction of a natural gas-fired, combined-cycle power plant in Sacramento County.  Fru-Con’s complaint alleges that it entered into a contract with SMUD to construct the power plant and further alleges that UE was negligent with regard to the design services it furnished to SMUD.  In August 2005, the court granted UE’s motion to dismiss.  Because SMUD remains a defendant in this action, the court has not entered a final judgment subject to an appeal with respect to its order to dismiss UE from the lawsuit.  Because this lawsuit was commenced prior to the April 2005, closing of the sale of UE to Zachry, Xcel Energy is obligated to indemnify Zachry for damages related to this case up to $17.5 million.  Pursuant to the terms of its professional liability policy, UE is insured up to $35 million.

 

Lamb County Electric Cooperative (LCEC) — In 1995, LCEC petitioned the PUCT for a cease and desist order against SPS alleging SPS was unlawfully providing service to oil field customers in LCEC’s certificated area.  In May 2003, the PUCT issued an order denying LCEC’s petition based on its determination that SPS in 1976 was granted a certificate to serve the disputed customers.  LCEC appealed the decision to the Texas state court.  In August 2004, the court affirmed the decision of the PUCT.  In September 2004, LCEC appealed the decision to the Court of Appeals for the Third Supreme Judicial District.  In November 2008, the Court of Appeals issued an opinion affirming the decision in favor of SPS.  In December 2008, LCEC filed a petition for review with the Supreme Court of Texas.  On Feb. 27, 2009, the Supreme Court of Texas denied LCEC’s request for review.

 

In 1996, LCEC filed a suit for damages against SPS in the District Court in Lamb County, Texas, based on the same facts alleged in the petition for a cease and desist order at the PUCT.  This suit has been dormant since it was filed, awaiting a final determination of the legality of SPS providing electric service to the disputed customers.  The PUCT order from May 2003, which found SPS was legally serving the disputed customers, collaterally determines the issue of liability contrary to LCEC’s position in the suit.  Because the PUCT May 2003 order has now been affirmed, on June 16, 2009, LCEC filed a motion to dismiss this case.  On Sept. 16, 2009, the District Court entered a dismissal order, disposing of all claims that have been or could have been asserted in this case.

 

8.              Short-Term Borrowings and Other Financing Instruments

 

Commercial Paper — At Sept. 30, 2009 and Dec. 31, 2008, Xcel Energy and its utility subsidiaries had commercial paper outstanding of approximately $494.0 million and $330.3 million, respectively.  The weighted average interest rates at Sept. 30, 2009 and Dec. 31, 2008 were 0.47 percent and 3.53 percent, respectively.  At Sept. 30, 2009 and Dec. 31, 2008, Xcel Energy and its utility subsidiaries had combined board approval to issue up to $2.25 billion of commercial paper.

 

Credit Facility Bank Borrowings — At Dec. 31, 2008, Xcel Energy and its subsidiaries had credit facility bank borrowings of $125.0 million with a weighted average interest rate of 1.88 percent.  At Sept. 30, 2009, Xcel Energy and its subsidiaries had no credit facility bank borrowings.

 

Money Pool Xcel Energy and its utility subsidiaries have established a money pool arrangement that allows for short-term loans between the utility subsidiaries and from the holding company to the utility subsidiaries at market-based interest rates.  The money pool arrangement does not allow loans from the subsidiaries to the holding company.  At Sept. 30, 2009 and Dec. 31, 2008, Xcel Energy and its utility subsidiaries had money pool loans outstanding of $117.0 million and $104.5 million, respectively.  The money pool loans are eliminated upon consolidation.  The weighted average interest rates at Sept. 30, 2009 and Dec. 31, 2008, were 0.50 percent and 3.48 percent, respectively.

 

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9.              Long-Term Borrowings and Other Financing Instruments

 

On March 1, 2009, NSP-Wisconsin redeemed its 7.375 percent $65.0 million first mortgage bonds due Dec. 1, 2026.  In addition to repayment of all principal amounts, NSP-Wisconsin paid accrued interest and a redemption premium totaling approximately $3.0 million.

 

On June 4, 2009, PSCo issued $400 million of 5.125 percent first mortgage bonds, series due 2019.  PSCo added the proceeds from the sale of the first mortgage bonds to its general funds and applied a portion of the net proceeds to fund the payment at maturity of $200 million of 6.875 percent unsecured senior notes due July 15, 2009.

 

In 1999, WYCO was formed as a joint venture with Colorado Interstate Gas Company (CIG) to develop and lease natural gas pipeline, storage, and compression facilities.  Xcel Energy has a 50 percent ownership interest in WYCO.  In June 2009, having achieved certain phases of construction, WYCO’s Totem gas storage facilities (Totem) were placed in service.  WYCO will lease Totem to CIG, and CIG will operate the facilities, providing natural gas storage services to PSCo under a service arrangement that commenced on July 1, 2009.

 

Xcel Energy accounts for PSCo’s service arrangement with CIG as a capital lease in accordance with the authoritative guidance on lease accounting.  As a result, Xcel Energy recorded a $67 million capital lease obligation as of Sept. 30, 2009.  WYCO is expected to incur approximately $20 million of additional construction costs to complete construction and make Totem operational at full storage capacity.

 

10.       Derivative Instruments

 

Effective Jan. 1, 2009, Xcel Energy adopted new guidance on disclosures about derivative instruments and hedging activities contained in ASC 815 Derivatives and Hedging, which requires additional disclosures regarding why an entity uses derivative instruments, the volume of an entity’s derivative activities, the fair value amounts recorded to the consolidated balance sheet for derivatives, the gains and losses on derivative instruments included in the consolidated statement of income or deferred, and information regarding certain credit-risk-related contingent features in derivative contracts.

 

Xcel Energy and its utility subsidiaries enter into derivative instruments, including forward contracts, futures, swaps and options, for trading purposes and to reduce risk in connection with changes in interest rates, utility commodity prices and vehicle fuel prices.  See additional information pertaining to the valuation of derivative instruments in Note 12 to the consolidated financial statements.

 

Interest Rate Derivatives — Xcel Energy and its utility subsidiaries enter into various instruments that effectively fix the interest payments on certain floating rate debt obligations or effectively fix the yield or price on a specified benchmark interest rate for a specific period.  These derivative instruments are generally designated as cash flow hedges for accounting purposes.

 

At Sept. 30, 2009, accumulated other comprehensive income related to interest rate derivatives included $0.8 million of net losses expected to be reclassified into earnings during the next 12 months as the related hedged interest rate transactions impact earnings.

 

At Sept. 30, 2009, Xcel Energy had an unsettled interest rate swap outstanding at SPS with a notional amount of $25 million.  The interest rate swap is not designated as a hedging instrument, and as such, changes in the fair value for the interest rate swap are recorded to earnings.

 

Commodity Derivatives — Xcel Energy’s utility subsidiaries enter into derivative instruments to manage variability of future cash flows from changes in commodity prices in their electric and natural gas operations, as well as for trading purposes.  This could include the purchase or sale of energy or energy-related products, natural gas to generate electric energy, gas for resale and vehicle fuel.

 

At Sept. 30, 2009, Xcel Energy had various utility commodity and vehicle fuel related contracts designated as cash flow hedges extending through December 2012.  Xcel Energy’s utility subsidiaries also enter into derivative instruments that mitigate commodity price risk on behalf of electric and natural gas customers but are not designated as qualifying hedging transactions.  Changes in the fair value of non-trading commodity derivative instruments are recorded in other comprehensive income or deferred as a regulatory asset or liability.  The classification as a regulatory asset or liability is based on the commission approved regulatory recovery mechanisms.  Xcel Energy recorded immaterial amounts to income related to the ineffectiveness of cash flow hedges for the nine months ended Sept. 30, 2009 and 2008.

 

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At Sept. 30, 2009, Xcel Energy had $4.9 million of net losses in accumulated other comprehensive income related to utility commodity and vehicle fuel cash flow hedges of which $4.2 million is expected to be reclassified into earnings during the next 12 months as the hedged transactions occur.

 

Additionally, Xcel Energy’s utility subsidiaries enter into commodity derivative instruments for trading purposes not directly related to commodity price risks associated with serving their electric and natural gas customers.  Changes in the fair value of these commodity derivatives are recorded in income.

 

Xcel Energy had no derivative instruments designated as fair value hedges during the nine months ended Sept. 30, 2009.  Therefore, no gains or losses from fair value hedges or related hedged transactions were recognized for the period.

 

The following table shows the major components of derivative instruments valuation in the consolidated balance sheets:

 

 

 

Sept. 30, 2009

 

Dec. 31, 2008

 

 

 

Derivative

 

Derivative

 

Derivative

 

Derivative

 

 

 

Instruments

 

Instruments

 

Instruments

 

Instruments

 

 

 

Valuation -

 

Valuation -

 

Valuation -

 

Valuation -

 

(Thousands of Dollars)

 

Assets

 

Liabilities

 

Assets

 

Liabilities

 

Long term purchased power agreements

 

$

335,634

 

$

331,659

 

$

374,692

 

$

353,531

 

Commodity derivatives

 

109,625

 

37,707

 

52,968

 

54,307

 

Interest rate derivatives

 

 

17,602

 

 

8,503

 

Total

 

$

445,259

 

$

386,968

 

$

427,660

 

$

416,341

 

 

In 2003, as a result of implementing new guidance on the normal purchase exception for derivative accounting contained in ASC 815 Derivatives and Hedging, Xcel Energy began recording several long-term purchased power agreements at fair value due to accounting requirements related to underlying price adjustments.  As these purchases are recovered through normal regulatory recovery mechanisms in the respective jurisdictions, the changes in fair value for these contracts were offset by regulatory assets and liabilities.  During 2006, Xcel Energy qualified these contracts under the normal purchase exception.  Based on this qualification, the contracts are no longer adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory assets and liabilities.

 

Financial Impact of Qualifying Cash Flow Hedges — The impact of qualifying interest rate and vehicle fuel cash flow hedges on Xcel Energy’s accumulated other comprehensive income, included in the consolidated statements of common stockholders’ equity and comprehensive income, is detailed in the following table:

 

 

 

Three Months Ended Sept. 30,

 

(Thousands of Dollars)

 

2009

 

2008

 

Accumulated other comprehensive loss related to cash flow hedges at July 1

 

$

(9,782

)

$

(6,134

)

After-tax net unrealized losses related to derivatives accounted for as hedges

 

(6,589

)

(2,589

)

After-tax net realized losses on derivative transactions reclassified into earnings

 

1,032

 

67

 

Accumulated other comprehensive loss related to cash flow hedges at Sept. 30

 

$

(15,339

)

$

(8,656

)

 

 

 

Nine Months Ended Sept. 30,

 

(Thousands of Dollars)

 

2009

 

2008

 

Accumulated other comprehensive loss related to cash flow hedges at Jan. 1

 

$

(13,113

)

$

(1,416

)

After-tax net unrealized losses related to derivatives accounted for as hedges

 

(5,770

)

(7,347

)

After-tax net realized losses on derivative transactions reclassified into earnings

 

3,544

 

107

 

Accumulated other comprehensive loss related to cash flow hedges at Sept. 30

 

$

(15,339

)

$

(8,656

)

 

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The following table details the fair value of commodity and interest rate derivatives recorded to derivative instruments valuation in the consolidated balance sheet, by category:

 

 

 

Sept. 30, 2009

 

 

 

 

 

 

 

Derivative

 

 

 

 

 

Counterparty

 

Instruments

 

(Thousands of Dollars)

 

Fair Value

 

Netting (a)

 

Valuation

 

 

 

 

 

 

 

 

 

Current derivative assets

 

 

 

 

 

 

 

Other derivative instruments:

 

 

 

 

 

 

 

Trading commodity

 

$

22,719

 

$

(14,050

)

$

8,669

 

Electric commodity

 

43,924

 

945

 

44,869

 

Natural gas commodity

 

29,747

 

1,126

 

30,873

 

Total current derivative assets

 

$

96,390

 

$

(11,979

)

$

84,411

 

 

 

 

 

 

 

 

 

Noncurrent derivative assets

 

 

 

 

 

 

 

Derivatives designated as cash flow hedges:

 

 

 

 

 

 

 

Vehicle fuel and other commodity

 

$

86

 

$

 

$

86

 

Other derivative instruments:

 

 

 

 

 

 

 

Trading commodity

 

22,457

 

(6,351

)

16,106

 

Natural gas commodity

 

8,872

 

150

 

9,022

 

 

 

31,329

 

(6,201

)

25,128

 

Total noncurrent derivative assets

 

$

31,415

 

$

(6,201

)

$

25,214

 

 

 

 

 

 

 

 

 

Current derivative liabilities

 

 

 

 

 

 

 

Derivatives designated as cash flow hedges:

 

 

 

 

 

 

 

Interest rate

 

$

2,643

 

$

 

$

2,643

 

Vehicle fuel and other commodity

 

4,428

 

 

4,428

 

 

 

7,071

 

 

7,071

 

Other derivative instruments:

 

 

 

 

 

 

 

Interest rate

 

1,522

 

 

1,522

 

Trading commodity

 

22,572

 

(18,459

)

4,113

 

Electric commodity

 

7,696

 

946

 

8,642

 

Natural gas commodity

 

8,978

 

1,124

 

10,102

 

 

 

40,768

 

(16,389

)

24,379

 

Total current derivative liabilities

 

$

47,839

 

$

(16,389

)

$

31,450

 

 

 

 

 

 

 

 

 

Noncurrent derivative liabilities

 

 

 

 

 

 

 

Derivatives designated as cash flow hedges:

 

 

 

 

 

 

 

Interest rate

 

$

8,222

 

$

 

$

8,222

 

Vehicle fuel and other commodity

 

947

 

 

947

 

 

 

9,169

 

 

9,169

 

Other derivative instruments:

 

 

 

 

 

 

 

Interest rate

 

5,215

 

 

5,215

 

Trading commodity

 

15,680

 

(6,355

)

9,325

 

Natural gas commodity

 

 

150

 

150

 

 

 

20,895

 

(6,205

)

14,690

 

Total noncurrent derivative liabilities

 

$

30,064

 

$

(6,205

)

$

23,859

 

 


(a)    ASC 815 Derivatives and Hedging permits the netting of receivables and payables for derivatives and related collateral amounts when a legally enforceable master netting agreement exists between Xcel Energy and a counterparty.  A master netting agreement is an agreement between two parties who have multiple contracts with each other that provides for the net settlement of all contracts in the event of default on or termination of any one contract.

 

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The following table details the impact of derivative activity during the three and nine months ended Sept. 30, 2009, on other comprehensive income, regulatory assets and liabilities, and income:

 

 

 

Three Months Ended Sept. 30, 2009

 

 

 

Fair Value Changes Recognized

 

Pre-Tax Amounts Reclassified into

 

 

 

 

 

During the Period in:

 

Income During the Period from:

 

Pre-Tax Gains (Losses)

 

 

 

Other

 

Regulatory

 

Other

 

Regulatory

 

Recognized

 

 

 

Comprehensive

 

Assets and

 

Comprehensive

 

Assets and

 

During the Period

 

(Thousands of Dollars)

 

Income (Loss)

 

Liabilities

 

Income

 

Liabilities

 

in Income