UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-Q

 

x

QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

For the quarterly period ended Sept. 30, 2007

 

or

 

 

o

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

 

For the transition period from               to              

 

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

 

(I.R.S. Employer Identification No.)

incorporation or organization)

 

 

 

 

 

414 Nicollet Mall, Minneapolis, Minnesota

 

55401

(Address of principal executive offices)

 

(Zip Code)

 

Registrant’s telephone number, including area code (612) 330-5500

 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.   x Yes o No

 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

 

Large Accelerated Filer x

 

Accelerated Filer o

 

Non-Accelerated Filer o

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). o 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. 19, 2007

Common Stock, $2.50 par value

 

419,930,078 shares

 

 



 

TABLE OF CONTENTS

 

PART I — FINANCIAL INFORMATION

 

Item 1. Financial Statements (unaudited)

 

CONSOLIDATED STATEMENTS OF INCOME

 

CONSOLIDATED STATEMENTS OF CASH FLOWS

 

CONSOLIDATED BALANCE SHEETS

 

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY AND COMPREHENSIVE INCOME

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

 

Item 3. Quantitative and Qualitative Disclosures about Market Risk

 

Item 4. Controls and Procedures

 

Part II — OTHER INFORMATION

 

Item 1. Legal Proceedings

 

Item 1A.Risk Factors

 

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

 

Item 6. Exhibits

 

SIGNATURES

 

Certifications Pursuant to Section 302

 

Certifications Pursuant to Section 906

 

Statement Pursuant to Private Litigation

 

 

2



 

PART I — FINANCIAL INFORMATION

Item 1. Financial Statements

 

XCEL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME (UNAUDITED)

 

 

 

Three Months Ended Sept. 30,

 

Nine Months Ended Sept. 30,

 

(Thousands of Dollars, Except Per Share Data)

 

2007

 

2006

 

2007

 

2006

 

Operating revenues

 

 

 

 

 

 

 

 

 

Electric utility

 

$

2,199,533

 

$

2,159,844

 

$

5,935,031

 

$

5,792,287

 

Natural gas utility

 

184,161

 

230,293

 

1,442,451

 

1,519,423

 

Nonregulated and other

 

16,303

 

21,454

 

53,469

 

61,858

 

Total operating revenues

 

2,399,997

 

2,411,591

 

7,430,951

 

7,373,568

 

 

 

 

 

 

 

 

 

 

 

Operating expenses

 

 

 

 

 

 

 

 

 

Electric fuel and purchased power — utility

 

1,101,844

 

1,160,896

 

3,113,314

 

3,106,804

 

Cost of natural gas sold and transported — utility

 

89,245

 

136,795

 

1,049,601

 

1,156,042

 

Cost of sales — nonregulated and other

 

4,452

 

4,096

 

14,179

 

16,763

 

Other operating and maintenance expenses — utility

 

443,599

 

410,063

 

1,338,934

 

1,286,426

 

Other operating and maintenance expenses — nonregulated

 

7,403

 

8,292

 

19,434

 

20,470

 

Depreciation and amortization

 

191,663

 

208,657

 

619,770

 

614,982

 

Taxes (other than income taxes)

 

66,021

 

71,551

 

210,432

 

221,410

 

Total operating expenses

 

1,904,227

 

2,000,350

 

6,365,664

 

6,422,897

 

Operating income

 

495,770

 

411,241

 

1,065,287

 

950,671

 

 

 

 

 

 

 

 

 

 

 

Interest and other income, net (see Note 10)

 

6,448

 

5,582

 

15,503

 

15,975

 

Allowance for funds used during construction - equity

 

9,023

 

8,300

 

25,294

 

16,752

 

 

 

 

 

 

 

 

 

 

 

Interest charges and financing costs

 

 

 

 

 

 

 

 

 

Interest charges — includes other financing costs of $4,924, $6,165, $16,518 and $18,770, respectively

 

137,432

 

121,715

 

390,407

 

360,297

 

Allowance for funds used during construction - debt

 

(8,481

)

(8,363

)

(24,129

)

(22,245

)

Total interest charges and financing costs

 

128,951

 

113,352

 

366,278

 

338,052

 

 

 

 

 

 

 

 

 

 

 

Income from continuing operations before income taxes

 

382,290

 

311,771

 

739,806

 

645,346

 

Income taxes

 

135,945

 

97,923

 

255,178

 

190,289

 

Income from continuing operations

 

246,345

 

213,848

 

484,628

 

455,057

 

Income (loss) from discontinued operations, net of tax (see Note 3)

 

5,369

 

10,614

 

(37,202

)

18,978

 

Net income

 

251,714

 

224,462

 

447,426

 

474,035

 

Dividend requirements on preferred stock

 

1,060

 

1,060

 

3,180

 

3,180

 

Earnings available to common shareholders

 

$

250,654

 

$

223,402

 

$

444,246

 

$

470,855

 

 

 

 

 

 

 

 

 

 

 

Weighted average common shares outstanding (thousands)

 

 

 

 

 

 

 

 

 

Basic

 

419,822

 

406,123

 

413,555

 

405,234

 

Diluted

 

433,387

 

430,000

 

432,811

 

429,095

 

Earnings per share — basic

 

 

 

 

 

 

 

 

 

Income from continuing operations

 

$

0.58

 

$

0.52

 

$

1.16

 

$

1.12

 

Income (loss) from discontinued operations

 

0.02

 

0.03

 

(0.09

)

0.04

 

Earnings per share — basic

 

$

0.60

 

$

0.55

 

$

1.07

 

$

1.16

 

Earnings per share — diluted

 

 

 

 

 

 

 

 

 

Income from continuing operations

 

$

0.57

 

$

0.50

 

$

1.13

 

$

1.08

 

Income (loss) from discontinued operations

 

0.01

 

0.03

 

(0.08

)

0.04

 

Earnings per share — diluted

 

$

0.58

 

$

0.53

 

$

1.05

 

$

1.12

 

 

 

 

 

 

 

 

 

 

 

Cash dividends declared per common share

 

$

0.23

 

$

0.22

 

$

0.68

 

$

0.66

 

 

See Notes to Consolidated Financial Statements

 

3



 

XCEL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

(Thousands of Dollars)

 

 

 

Nine Months Ended
Sept. 30,

 

 

 

2007

 

2006

 

Operating activities

 

 

 

 

 

Net income

 

$

447,426

 

$

474,035

 

Remove loss (income) from discontinued operations

 

37,202

 

(18,978

)

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

 

 

 

 

 

Depreciation and amortization

 

645,007

 

643,520

 

Nuclear fuel amortization

 

38,570

 

35,359

 

Deferred income taxes

 

189,334

 

(117,707

)

Amortization of investment tax credits

 

(7,282

)

(7,354

)

Allowance for equity funds used during construction

 

(25,294

)

(16,752

)

Undistributed equity in earnings of unconsolidated affiliates

 

(1,632

)

(2,171

)

Share-based compensation expense

 

14,996

 

19,044

 

Net realized and unrealized hedging and derivative transactions

 

(16,269

)

(57,327

)

Changes in operating assets and liabilities (net of effects of consolidation of NMC, see Note 14):

 

 

 

 

 

Accounts receivable

 

104,876

 

242,288

 

Accrued unbilled revenues

 

19,655

 

208,359

 

Inventories

 

(25,223

)

(6,620

)

Recoverable purchased natural gas and electric energy costs

 

207,586

 

273,239

 

Other current assets

 

3,289

 

4,505

 

Accounts payable

 

(249,371

)

(341,283

)

Net regulatory assets and liabilities

 

(34,127

)

36,246

 

Other current liabilities

 

197

 

166,918

 

Change in other noncurrent assets

 

(19,374

)

(18,583

)

Change in other noncurrent liabilities

 

(9,435

)

(72,014

)

Operating cash flows provided by discontinued operations

 

84,242

 

151,590

 

Net cash provided by operating activities

 

1,404,373

 

1,596,314

 

 

 

 

 

 

 

Investing activities

 

 

 

 

 

Utility capital and construction expenditures

 

(1,481,693

)

(1,165,807

)

Allowance for equity funds used during construction

 

25,294

 

16,752

 

Purchase of investments in external decommissioning fund

 

(499,991

)

(699,593

)

Proceeds from the sale of investments in external decommissioning fund

 

467,447

 

665,814

 

Nonregulated capital expenditures and asset acquisitions

 

(958

)

(1,614

)

Proceeds from sale of assets

 

 

24,670

 

Cash obtained from consolidation of NMC (see Note 14)

 

38,950

 

 

Change in restricted cash

 

(4,881

)

(3,085

)

Other investments

 

2,438

 

9,238

 

Investing cash flows provided by discontinued operations

 

 

42,377

 

Net cash used in investing activities

 

(1,453,394

)

(1,111,248

)

 

 

 

 

 

 

Financing activities

 

 

 

 

 

Short-term repayments — net

 

(206,075

)

(396,120

)

Proceeds from issuance of long-term debt

 

1,162,404

 

882,578

 

Repayment of long-term debt, including reacquisition premiums

 

(290,243

)

(773,901

)

Early participation payments on debt exchange (see Note 8)

 

(4,859

)

 

Proceeds from issuance of common stock

 

8,970

 

7,747

 

Dividends paid

 

(281,249

)

(267,228

)

Net cash provided by (used in) financing activities

 

388,948

 

(546,924

)

 

 

 

 

 

 

Net increase (decrease) in cash and cash equivalents

 

339,927

 

(61,858

)

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

 

(16,517

)

22,660

 

Cash and cash equivalents at beginning of year

 

37,458

 

71,382

 

Cash and cash equivalents at end of quarter

 

$

360,868

 

$

32,184

 

 

 

 

 

 

 

Supplemental disclosure of cash flow information:

 

 

 

 

 

Cash paid for interest (net of amounts capitalized)

 

$

309,620

 

$

307,922

 

Cash paid for income taxes (net of refunds received)

 

(11,163

)

(773

)

Supplemental disclosure of non-cash investing transactions:

 

 

 

 

 

Property, plant and equipment additions in accounts payable

 

$

69,192

 

$

43,068

 

Supplemental disclosure of non-cash financing transactions:

 

 

 

 

 

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

 

$

45,791

 

$

44,338

 

Issuance of common stock for senior convertible notes

 

125,632

 

 

 

See Notes to Consolidated Financial Statements

 

4



 

XCEL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (UNAUDITED)

(Thousands of Dollars)

 

 

 

Sept. 30, 2007

 

Dec. 31, 2006

 

ASSETS

 

 

 

 

 

Current assets:

 

 

 

 

 

Cash and cash equivalents

 

$

360,868

 

$

37,458

 

Accounts receivable, net of allowance for bad debts of $41,918 and $36,689, respectively

 

750,131

 

816,093

 

Accrued unbilled revenues

 

494,645

 

514,300

 

Materials and supplies inventories

 

164,258

 

158,721

 

Fuel inventories

 

118,270

 

95,651

 

Natural gas inventories

 

248,841

 

251,818

 

Recoverable purchased natural gas and electric energy costs

 

51,014

 

258,600

 

Derivative instruments valuation

 

116,319

 

101,562

 

Prepayments and other

 

189,135

 

189,658

 

Current assets held for sale and related to discontinued operations

 

161,470

 

229,633

 

Total current assets

 

2,654,951

 

2,653,494

 

Property, plant and equipment, at cost:

 

 

 

 

 

Electric utility plant

 

20,140,069

 

19,367,671

 

Natural gas utility plant

 

2,925,672

 

2,846,435

 

Common utility and other property

 

1,476,783

 

1,439,020

 

Construction work in progress

 

1,715,364

 

1,425,484

 

Total property, plant and equipment

 

26,257,888

 

25,078,610

 

Less accumulated depreciation

 

(10,090,852

)

(9,670,104

)

Nuclear fuel, net of accumulated amortization: $1,276,488 and $1,237,917, respectively

 

179,101

 

140,152

 

Net property, plant and equipment

 

16,346,137

 

15,548,658

 

Other assets:

 

 

 

 

 

Nuclear decommissioning fund and other investments

 

1,346,946

 

1,271,362

 

Regulatory assets

 

1,182,927

 

1,189,145

 

Prepaid pension asset

 

618,397

 

586,712

 

Derivative instruments valuation

 

399,198

 

437,520

 

Other

 

127,674

 

135,746

 

Noncurrent assets held for sale and related to discontinued operations

 

147,969

 

162,586

 

Total other assets

 

3,823,111

 

3,783,071

 

Total assets

 

$

22,824,199

 

$

21,985,223

 

LIABILITIES AND EQUITY

 

 

 

 

 

Current liabilities:

 

 

 

 

 

Current portion of long-term debt

 

$

306,997

 

$

336,411

 

Short-term debt

 

420,225

 

626,300

 

Accounts payable

 

873,200

 

1,100,600

 

Taxes accrued

 

234,609

 

271,691

 

Dividends payable

 

97,644

 

91,685

 

Derivative instruments valuation

 

86,910

 

83,944

 

Other

 

397,747

 

347,809

 

Current liabilities held for sale and related to discontinued operations

 

63,332

 

26,149

 

Total current liabilities

 

2,480,664

 

2,884,589

 

Deferred credits and other liabilities:

 

 

 

 

 

Deferred income taxes

 

2,458,052

 

2,264,164

 

Deferred investment tax credits

 

114,312

 

121,594

 

Asset retirement obligations

 

1,301,083

 

1,361,951

 

Regulatory liabilities

 

1,401,863

 

1,364,657

 

Pension and employee benefit obligations

 

657,560

 

704,913

 

Derivative instruments valuation

 

436,562

 

483,077

 

Customer advances

 

303,929

 

302,168

 

Other liabilities

 

128,575

 

119,633

 

Noncurrent liabilities held for sale and related to discontinued operations

 

22,012

 

5,477

 

Total deferred credits and other liabilities

 

6,823,948

 

6,727,634

 

Minority interest in subsidiaries

 

307

 

1,560

 

Commitments and contingent liabilities (see Note 6)

 

 

 

 

 

Capitalization:

 

 

 

 

 

Long-term debt

 

7,252,800

 

6,449,638

 

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, 2007 — 419,925,576; Dec. 31, 2006 — 407,296,907

 

6,161,500

 

5,816,822

 

Total liabilities and equity

 

$

22,824,199

 

$

21,985,223

 

 

See Notes to Consolidated Financial Statements

 

5



 

XCEL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY

AND COMPREHENSIVE INCOME

(UNAUDITED)

(Thousands)

 

 

 

Common Stock Issued

 

 

 

 

 

 

 

 

 

Shares

 

Par Value

 

Additional
Paid In
Capital

 

Retained
Earnings

 

Accumulated
Other
Comprehensive
Income (Loss)

 

Total Common
Stockholders’
Equity

 

Three months ended Sept. 30, 2007 and 2006

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Balance at June 30, 2006

 

405,560

 

$

1,013,901

 

$

4,012,799

 

$

632,263

 

$

(103,713

)

$

5,555,250

 

Net income

 

 

 

 

 

 

 

224,462

 

 

 

224,462

 

Minimum pension liability adjustment, net of tax of $21

 

 

 

 

 

 

 

 

 

(21

)

(21

)

Net derivative instrument fair value changes during the period, net of tax of $(11,309) (see Note 9)

 

 

 

 

 

 

 

 

 

(15,966

)

(15,966

)

Unrealized gain - marketable securities, net of tax of $8

 

 

 

 

 

 

 

 

 

15

 

15

 

Comprehensive income for the period

 

 

 

 

 

 

 

 

 

 

 

208,490

 

Dividends declared:

 

 

 

 

 

 

 

 

 

 

 

 

 

Cumulative preferred stock

 

 

 

 

 

 

 

(1,060

)

 

 

(1,060

)

Common stock

 

 

 

 

 

 

 

(90,451

)

 

 

(90,451

)

Issuances of common stock

 

965

 

2,411

 

13,551

 

 

 

 

 

15,962

 

Share-based compensation

 

 

 

 

 

(1,286

)

 

 

 

 

(1,286

)

Balance at Sept. 30, 2006

 

406,525

 

$

1,016,312

 

$

4,025,064

 

$

765,214

 

$

(119,685

)

$

5,686,905

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Balance at June 30, 2007

 

419,510

 

$

1,048,774

 

$

4,175,833

 

$

779,603

 

$

(9,294

)

$

5,994,916

 

Net income

 

 

 

 

 

 

 

251,714

 

 

 

251,714

 

Changes in unrecognized amounts of pension and retiree medical benefits, net of tax of $115 (see Note 12)

 

 

 

 

 

 

 

 

 

446

 

446

 

Net derivative instrument fair value changes during the period, net of tax of $1,042 (see Note 9)

 

 

 

 

 

 

 

 

 

(2,235

)

(2,235

)

Comprehensive income for the period

 

 

 

 

 

 

 

 

 

 

 

249,925

 

Dividends declared:

 

 

 

 

 

 

 

 

 

 

 

 

 

Cumulative preferred stock

 

 

 

 

 

 

 

(1,060

)

 

 

(1,060

)

Common stock

 

 

 

 

 

 

 

(96,582

)

 

 

(96,582

)

Issuances of common stock

 

416

 

1,040

 

7,644

 

 

 

 

 

8,684

 

Share-based compensation

 

 

 

 

 

5,617

 

 

 

 

 

5,617

 

Balance at Sept. 30, 2007

 

419,926

 

$

1,049,814

 

$

4,189,094

 

$

933,675

 

$

(11,083

)

$

6,161,500

 

 

See Notes to Consolidated Financial Statements

 

6



 

XCEL ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS’ EQUITY

AND COMPREHENSIVE INCOME

(UNAUDITED)

(Thousands)

 

 

 

Common Stock Issued

 

 

 

 

 

 

 

 

 

Shares

 

Par Value

 

Additional
Paid In
Capital

 

Retained
Earnings

 

Accumulated
Other
Comprehensive
Income (Loss)

 

Total Common
Stockholders’
Equity

 

Nine months ended Sept. 30, 2007 and 2006

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Balance at Dec. 31, 2005

 

403,387

 

$

1,008,468

 

$

3,956,710

 

$

562,138

 

$

(132,061

)

$

5,395,255

 

Net income

 

 

 

 

 

 

 

474,035

 

 

 

474,035

 

Minimum pension liability adjustment, net of tax of $21

 

 

 

 

 

 

 

 

 

(21

)

(21

)

Net derivative instrument fair value changes during the period, net of tax of $6,779 (see Note 9)

 

 

 

 

 

 

 

 

 

12,354

 

12,354

 

Unrealized gain - marketable securities, net of tax of $25

 

 

 

 

 

 

 

 

 

43

 

43

 

Comprehensive income for the period

 

 

 

 

 

 

 

 

 

 

 

486,411

 

Dividends declared:

 

 

 

 

 

 

 

 

 

 

 

 

 

Cumulative preferred stock

 

 

 

 

 

 

 

(3,180

)

 

 

(3,180

)

Common stock

 

 

 

 

 

 

 

(267,779

)

 

 

(267,779

)

Issuances of common stock

 

3,138

 

7,844

 

48,841

 

 

 

 

 

56,685

 

Share-based compensation

 

 

 

 

 

19,513

 

 

 

 

 

19,513

 

Balance at Sept. 30, 2006

 

406,525

 

$

1,016,312

 

$

4,025,064

 

$

765,214

 

$

(119,685

)

$

5,686,905

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Balance at Dec. 31, 2006

 

407,297

 

$

1,018,242

 

$

4,043,657

 

$

771,249

 

$

(16,326

)

$

5,816,822

 

FIN 48 adoption

 

 

 

 

 

 

 

2,207

 

 

 

2,207

 

Net income

 

 

 

 

 

 

 

447,426

 

 

 

447,426

 

Changes in unrecognized amounts of pension and retiree medical benefits, net of tax of $345 (see Note 12)

 

 

 

 

 

 

 

 

 

1,339

 

1,339

 

Net derivative instrument fair value changes during the period, net of tax of $2,926 (see Note 9)

 

 

 

 

 

 

 

 

 

3,900

 

3,900

 

Unrealized gain - marketable securities, net of tax of $2

 

 

 

 

 

 

 

 

 

4

 

4

 

Comprehensive income for the period

 

 

 

 

 

 

 

 

 

 

 

452,669

 

Dividends declared:

 

 

 

 

 

 

 

 

 

 

 

 

 

Cumulative preferred stock

 

 

 

 

 

 

 

(3,180

)

 

 

(3,180

)

Common stock

 

 

 

 

 

 

 

(284,027

)

 

 

(284,027

)

Issuances of common stock

 

12,629

 

31,572

 

129,072

 

 

 

 

 

160,644

 

Share-based compensation

 

 

 

 

 

16,365

 

 

 

 

 

16,365

 

Balance at Sept. 30, 2007

 

419,926

 

$

1,049,814

 

$

4,189,094

 

$

933,675

 

$

(11,083

)

$

6,161,500

 

 

See Notes to Consolidated Financial Statements

 

7



 

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 the financial position of Xcel Energy Inc. and its subsidiaries (collectively, Xcel Energy) as of Sept. 30, 2007, and Dec. 31, 2006; the results of its operations and changes in stockholders’ equity for the three and nine months ended Sept. 30, 2007 and 2006; and its cash flows for the nine months ended Sept. 30, 2007 and 2006. Due to the seasonality of Xcel Energy’s electric and natural gas sales, such interim results are not necessarily an appropriate base from which to project annual results.

 

On Aug. 8, 2007, Xcel Energy filed a Current Report on form 8-K to update historical financial information included in Xcel Energy’s Annual Report on form 10-K for the year ended Dec. 31, 2006 to present PSR Investments, Inc. (PSRI), a wholly-owned subsidiary of Public Service Company of Colorado (PSCo) as a discontinued operation.

 

1.              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 Current Report on Form 8-K filed on Aug. 8, 2007, appropriately represent, in all material respects, the current status of accounting policies and are incorporated herein by reference.

 

Income Taxes — Consistent with prior periods and upon adoption of Financial Accounting Standard Board (FASB) Interpretation No. 48 — “Accounting for Uncertainty in Income Taxes — an interpretation of FASB Statement No. 109”, Xcel Energy records interest and penalties related to income taxes as interest charges in the Consolidated Statements of Income.

 

Reclassifications — Certain amounts in the Consolidated Statements of Cash Flows have been reclassified from prior-period presentation to conform to the 2007 presentation. The reclassifications reflect the presentation of unbilled revenues, recoverable purchased natural gas and electric energy costs and regulatory assets and liabilities and share-based compensation expense as separate items rather than components of other assets and other liabilities within net cash provided by operating activities. In addition, activity related to derivative transactions have been combined into net realized and unrealized hedging and derivative transactions. These reclassifications did not affect total net cash provided by (used in) operating, investing or financing activities within the Consolidated Statements of Cash Flows.

 

As a result of a settlement in principle with the United States government and management’s decision to surrender all corporate-owned life insurance (COLI) policies following acceptance in writing of the offer by the government, all the amounts related to PSRI have been classified as discontinued operations. See Notes 3 and 4 for additional disclosure related to discontinued operations and the COLI settlement. Financial data for PSRI has been presented as discontinued operations as outlined in Note 3. The financial statements have been recast for all periods presented herein.

 

2.          Recently Issued Accounting Pronouncements

 

Fair Value Measurements (Statement of Financial Accounting Standards (SFAS) 157) — In September 2006, the FASB issued SFAS 157, which provides a single definition of fair value, together with a framework for measuring it, and requires additional disclosure about the use of fair value to measure assets and liabilities. SFAS 157 also emphasizes that fair value is a market-based measurement, and sets out a fair value hierarchy with the highest priority being quoted prices in active markets. Fair value measurements are disclosed by level within that hierarchy. SFAS 157 is effective for financial statements issued for fiscal years beginning after Nov. 15, 2007. Xcel Energy is evaluating the impact of SFAS 157 on its financial condition and results of operations.

 

The Fair Value Option for Financial Assets and Financial Liabilities - Including an Amendment of FASB Statement No. 115 (SFAS 159) —  In February 2007, the FASB issued SFAS 159, which provides companies with an option to measure, at specified election dates, many financial instruments and certain other items at fair value that are not currently measured at fair value. A company that adopts SFAS 159 will report unrealized gains and losses on items, for which the fair value option has been elected, in earnings at each subsequent reporting date. This statement also establishes presentation and disclosure requirements designed to facilitate comparisons between entities that choose different measurement attributes for similar types of assets and liabilities. This statement is effective for fiscal years beginning after Nov. 15, 2007. Xcel Energy is evaluating the impact of SFAS 159 on its financial condition and results of operations.

 

3.              Discontinued Operations

 

A summary of the subsidiaries presented as discontinued operations is discussed below. 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 in 2007 and 2006 have been reclassified to assets and liabilities held for sale in the Consolidated Balance Sheets.

 

8



 

Assets held for sale are valued on an asset-by-asset basis at the lower of carrying amount or fair value less costs to sell. In applying those provisions, management considered cash flow analyses, bids and offers related to those assets and businesses. Assets held for sale are not depreciated.

 

PSRI

 

PSRI, a wholly owned subsidiary of PSCo, owns and manages life insurance policies on some of PSCo’s employees, known as COLI policies. On June 19, 2007, a settlement in principle was reached between Xcel Energy and the Internal Revenue Service (IRS) in regards to the tax deductibility of interest expense associated with PSCo’s COLI policies. Xcel Energy started to report earnings from PSRI and the settlement costs as discontinued operations in the second quarter of 2007, as a result of the settlement in principle and management’s decision to surrender the COLI policies, following acceptance in writing of the offer by the government.

 

On Sept. 20, 2007, Xcel Energy submitted its formal offer in compromise to settle the dispute relating to the proper tax treatment of the COLI policies beginning with tax year 1993 and for all years thereafter. On Sept. 21, 2007, the United States accepted the terms of that settlement offer. The terms of the final settlement are essentially the same as the settlement in principle reached on June 19, 2007. The government’s letter terminates the tax litigation pending between the parties for tax years 1993-2002 and also specifies the agreed tax treatment for certain aspects of those policies for subsequent tax years. See Note 4 for additional disclosure related to the COLI settlement.

 

Regulated Utility Segments

 

Cheyenne Light, Fuel and Power Company (Cheyenne), which was sold in 2005, had an impact on Xcel Energy’s financial statements in 2006 relating to tax adjustments.

 

Nonregulated Subsidiaries — All Other Segment

 

Seren Innovations Inc., NRG Energy, Inc., e prime, Xcel Energy International, Utility Engineering, and Quixx, which were all sold in 2006 or earlier, continue to have activity and balances reflected on Xcel Energy’s financial statements as reported in the tables below.

 

Summarized Financial Results of Discontinued Operations

 

(Thousands of dollars)

 

PSRI

 

Utility
Segments

 

All Other

 

Total

 

 

 

 

 

 

 

 

 

 

 

Three months ended Sept. 30, 2007

 

 

 

 

 

 

 

 

 

Operating revenues

 

$

 

$

 

$

 

$

 

Operating expense (income), interest and other income, net

 

6,579

 

 

(1,172

)

5,407

 

Pretax (loss) income from discontinued operations

 

(6,579

)

 

1,172

 

(5,407

)

Income tax expense (benefit)

 

(11,851

)

(79

)

1,154

 

(10,776

)

Net income from discontinued operations

 

$

5,272

 

$

79

 

$

18

 

$

5,369

 

 

 

 

 

 

 

 

 

 

 

Three months ended Sept. 30, 2006

 

 

 

 

 

 

 

 

 

Operating revenues

 

$

 

$

 

$

1,374

 

$

1,374

 

Operating expense, interest and other income, net

 

4,571

 

 

2,583

 

7,154

 

Pretax loss from discontinued operations

 

(4,571

)

 

(1,209

)

(5,780

)

Income tax benefit

 

(14,898

)

(1,068

)

(428

)

(16,394

)

Net income (loss) from discontinued operations

 

$

10,327

 

$

1,068

 

$

(781

)

$

10,614

 

 

9



 

(Thousands of dollars)

 

PSRI

 

Utility
Segments

 

All Other

 

Total

 

 

 

 

 

 

 

 

 

 

 

Nine months ended Sept. 30, 2007

 

 

 

 

 

 

 

 

 

Operating revenues

 

$

 

$

 

$

36

 

$

36

 

Operating expense (income), interest and other income, net

 

58,910

 

 

(2,971

)

55,939

 

Pretax (loss) income from discontinued operations

 

(58,910

)

 

3,007

 

(55,903

)

Income tax expense (benefit)

 

(19,332

)

(81

)

712

 

(18,701

)

Net (loss) income from discontinued operations

 

$

(39,578

)

$

81

 

$

2,295

 

$

(37,202

)

 

 

 

 

 

 

 

 

 

 

Nine months ended Sept. 30, 2006

 

 

 

 

 

 

 

 

 

Operating revenues

 

$

 

$

 

$

6,212

 

$

6,212

 

Operating expense (income), interest and other income, net

 

16,524

 

(18

)

8,748

 

25,254

 

Pretax (loss) income from discontinued operations

 

(16,524

)

18

 

(2,536

)

(19,042

)

Income tax benefit

 

(33,390

)

(2,233

)

(2,397

)

(38,020

)

Net income (loss) from discontinued operations

 

$

16,866

 

$

2,251

 

$

(139

)

$

18,978

 

 

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

 

(Thousands of dollars)

 

Sept. 30, 2007

 

Dec. 31, 2006

 

 

 

 

 

 

 

Cash

 

$

9,212

 

$

25,729

 

Accounts receivables, net

 

4,414

 

2,998

 

Deferred income tax benefits

 

104,884

 

160,456

 

Other current assets

 

42,960

 

40,450

 

Current assets held for sale and related to discontinued operations

 

$

161,470

 

$

229,633

 

Net property, plant and equipment

 

$

 

$

174

 

Deferred income tax benefits

 

126,525

 

152,133

 

Other noncurrent assets

 

21,444

 

10,279

 

Noncurrent assets held for sale and related to discontinued operations

 

$

147,969

 

$

162,586

 

Accounts payable

 

$

3,636

 

$

2,230

 

Other current liabilities

 

59,696

 

23,919

 

Current liabilities held for sale and related to discontinued operations

 

$

63,332

 

$

26,149

 

Other noncurrent liabilities

 

$

22,012

 

$

5,477

 

Noncurrent liabilities held for sale and related to discontinued operations

 

$

22,012

 

$

5,477

 

 

4.              Income Taxes

 

COLI — In April 2004, Xcel Energy filed a lawsuit against the U.S. government in the U.S. District Court for the District of Minnesota to establish its right to deduct the interest expense that had accrued during tax years 1993 and 1994 on policy loans related to its COLI policies that insured the lives of certain PSCo employees. These policies are owned by PSRI, a wholly owned subsidiary of PSCo.

 

After Xcel Energy filed this suit, the IRS sent three statutory notices of deficiency of tax, penalty and interest for 1995 through 2002. Xcel Energy filed U.S. Tax Court petitions challenging those notices. PSRI also continued to take deductions for interest expense on policy loans for subsequent years. The total exposure for the tax years 1993 through 2007 was approximately $583 million, which included income tax, interest and potential penalties.

 

On June 19, 2007, Xcel Energy and the United States reached a settlement in principle regarding this dispute.

 

On Sept. 20, 2007, Xcel Energy submitted its formal offer in compromise and by letter dated Sept. 21, 2007, the United States accepted the terms of that settlement offer. The terms of the final settlement are essentially the same as the settlement in principle reached on June 19, 2007. The U.S. government’s letter terminates the tax litigation pending between the parties for tax years 1993-2002 and also specifies the agreed tax treatment for certain aspects of those policies for subsequent tax years.

 

The essential financial terms of the final settlement, as accepted, are as follows:

 

1.                  Xcel Energy will pay the government a total of $64.4 million in full settlement of the government’s claims for tax, penalty, and interest for tax years 1993-2007.

 

10



 

2.                  Xcel Energy will pay that settlement amount as follows:

 

                  $32.2 million of that amount will be satisfied by tax and interest amounts that Xcel Energy has paid or is deemed under the terms of the settlement to have made to the government with respect to tax years 1993 and 1994.

                  Xcel Energy will satisfy the remaining settlement amount owed by paying the government $32.2 million by Oct. 31, 2007.

 

3.                  The total settlement amount will be allocated toward specified amounts of tax, penalty, and interest owed for 1993 and 1994 and other amounts of tax and interest owed for 1995.

 

4.                  Except as stated above, Xcel Energy will be entitled to claim COLI-related interest deductions for tax years 1995-2007.

 

5.               Xcel Energy will surrender the policies to its insurer by Oct. 31, 2007 without having to recognize a taxable gain on the surrender.

 

Accounting for Uncertainty in Income Taxesan interpretation of FASB Statement No. 109 (FIN 48) — In July 2006, the FASB issued FIN 48, which prescribes how a company should recognize, measure, present and disclose uncertain tax positions that such company has taken or expects to take in its income tax returns. FIN 48 requires that only income tax benefits that meet the “more likely than not” recognition threshold be recognized or continue to be recognized on its effective date. As required, Xcel Energy adopted FIN 48 as of Jan. 1, 2007 and the initial derecognition amounts were reported as a cumulative effect of a change in accounting principle. The cumulative effect of the change, which was reported as an adjustment to the beginning balance of retained earnings, was not material. Following implementation, the ongoing recognition of changes in measurement of uncertain tax positions will be reflected as a component of income tax expense.

 

Xcel Energy files a consolidated federal income tax return, 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.

 

Xcel Energy has been audited by the IRS through tax year 2003, with a limited exception for 2003 research tax credits. The IRS commenced an examination of Xcel Energy’s federal income tax returns for 2004 and 2005 (and research credits for 2003) in the third quarter of 2006, and that examination is anticipated to be complete by March 31, 2008. As of Sept. 30, 2007, the IRS had not proposed any material adjustments to tax years 2003 through 2005. The statute of limitations applicable to Xcel Energy’s 2000 through 2002 federal income tax returns expired as of June 30, 2007.

 

As previously disclosed, Xcel Energy has been in litigation with the federal government to establish its right to deduct interest expense on COLI policy loans incurred since 1993. Xcel Energy and the IRS have reached a final settlement regarding this litigation (see above discussion of COLI).

 

Xcel Energy is also currently under examination by the state of Colorado for years 2002 through 2005, the state of Minnesota for years 1998 through 2000, the state of Texas for years 2003 through 2005, and the state of Wisconsin for years 2002 through 2005. No material adjustments have been proposed as of Sept. 30, 2007 in the states of Colorado, Minnesota, Texas and Wisconsin. As of Sept. 30, 2007, Xcel Energy’s earliest open tax years in which an audit can be initiated by state taxing authorities in its major operating jurisdictions are as follows:  Colorado-2002, Minnesota-1998, Texas-2003, and Wisconsin-2002.

 

The amount of unrecognized tax benefits was $47.3 million on Jan. 1, 2007 (including $4.7 million reported as discontinued operations) and $42.5 million (including $4.3 million reported as discontinued operations) on Sept. 30, 2007. These amounts were offset against the tax benefits associated with net operating loss and tax credit carryovers of $43.2 million on Jan. 1, 2007 (including $30.7 million reported as discontinued operations) and $38.3 million on Sept. 30, 2007 (including $29.4 million reported as discontinued operations).

 

Included in the unrecognized tax benefit balance for continuing operations was $12.7 million and $6.1 million of tax positions on Jan. 1, 2007 and Sept. 30, 2007, respectively, which if recognized would affect the annual effective tax rate. In addition, the unrecognized tax benefit balance for continuing operations included $29.9 million and $32.1 million of tax positions on Jan. 1, 2007 and Sept. 30, 2007, 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 change in the unrecognized tax benefit balance for continuing operations of $5.7 million from July 1, 2007 to Sept. 30, 2007, was due to the addition of similar uncertain tax positions relating to third quarter activity, and the resolution of certain federal audit matters. Xcel Energy’s amount of unrecognized tax benefits for continuing operations could significantly change in the next 12 months as the IRS and state audits progress. However, at this time due to the nature of the audit process, it is not reasonably possible to estimate a range of the possible change.

 

Interventions and comments regarding the Aug. 1, 2007 cost allocation filings were submitted on Sept. 17, 2007.

 

11



 

The change in the unrecognized tax benefit balance for discontinued operations of $12.4 million from July 1, 2007 to Sept. 30, 2007 was due to the final settlement of the COLI litigation. Xcel Energy’s amount of unrecognized tax benefits for discontinued operations could significantly change in the next 12 months as state audits progress. However, at this time due to the nature of the audit process, it is not reasonably possible to estimate a range of the potential change.

 

The interest expense liability related to unrecognized tax benefits on Jan. 1, 2007, was not material due to net operating loss and tax credit carryovers. The change in the interest expense liability from Jan. 1, 2007, to Sept. 30, 2007, was not material. No amounts were accrued for penalties as of Sept. 30, 2007.

 

5. Rate Matters

 

NSP-Minnesota

 

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

 

Midwest Independent Transmission System Operator, Inc. (MISO) Long-Term Transmission Pricing In October 2005, MISO filed a proposed change to its Open Access Transmission and Energy Markets Tariff (TEMT) to regionalize future cost recovery of certain high voltage transmission projects to be constructed for reliability improvements. The proposal, called the Regional Expansion Criteria Benefits phase I (RECB I) proposal, would recover 20 percent of eligible reliability transmission costs from all transmission service customers in the MISO 15 state region, with 80 percent recovered on a sub-regional basis for projects 345 kilovolt (KV) and above. Projects above 100 KV but less than 345 KV will be recovered 100 percent on a sub-regional basis. The proposal would exclude certain projects that had been planned prior to the October 2005 filing, and would require new generators to fund 50 percent of the cost of network upgrades associated with their interconnection. In February 2006, the FERC generally approved the RECB I proposal, but set the 20 percent limitation on regionalization for additional proceedings.. On Nov. 29, 2006, the FERC issued an order upholding the February 2006 order and approving the 20 percent limitation. On Dec. 13, 2006, the Public Service Commission of Wisconsin (PSCW) filed an appeal of the RECB I order. The appeal remains pending.

 

In addition, in October 2006, MISO filed additional changes to its TEMT to regionalize future recovery of certain economic transmission projects (345 KV and above) constructed to provide access to lower cost generation supplies. The filing, known as Regional Expansion Criteria Benefits phase II (RECB II), would provide regional recovery of 20 percent of the project costs and sub-regional recovery of 80 percent, based on a benefits analysis. MISO proposed that the RECB II tariff be effective April 1, 2007.

 

On March 15, 2007, the FERC issued orders separately upholding the Nov. 29, 2006 order, accepting the RECB I pricing proposal, and approving most aspects of the RECB II proposal. Various parties filed requests for rehearing of the RECB II order in April 2007.

 

Transmission service rates in the MISO region presently use a rate design in which the transmission cost depends on the location of the load being served (referred to as “license plate” rates). Costs of existing transmission facilities are thus not regionalized. MISO and its transmission owners filed a successor rate methodology in Aug. 1, 2007, to be effective Feb. 1, 2008, as required by the 1998 agreement among transmission owners creating the MISO.

 

MISO and most vertically integrated transmission owners proposed to continue license plate rates for existing facilities. The March 15, 2007 FERC orders regarding RECBI and RECBII also require MISO to re-examine the cost allocation for new reliability improvements and economic projects in the Aug. 1, 2007 filing. MISO and most transmission owners proposed continued use of RECB I and RECB II for new facilities. Certain parties proposed to modify RECB I and RECBII to regionalize the cost of all new transmission facilities 345 KV and above. Interventions and comments regarding the Aug. 1, 2007 cost allocation filings were submitted on Sept. 17, 2007.

 

In addition, on Sept. 17, 2007, American Electric Power (AEP) filed a complaint asking FERC to order regionalized cost recovery of certain existing 500 KV and 765 KV facilities located in the PJM Interconnection, Inc. (PJM), another Regional Transmission Organization (RTO), and the cost of new facilities 345 KV and above in PJM and MISO over both the PJM and MISO regions effective Oct. 1, 2007. Interventions and protests to the AEP complaint will be filed by Oct. 29, 2007.

 

Proposals to regionalize transmission costs could shift the costs of transmission investments by Northern States Power Co., a Minnesota corporation (NSP-Minnesota) and Northern States Power Co., a Wisconsin corporation (NSP-Wisconsin)  to other MISO transmission service customers, but would also shift the costs of transmission investments of other participants in MISO or PJM to the combined systems of NSP-Minnesota and NSP-Wisconsin, which are managed as an integrated system and jointly referred to as the NSP System. Xcel Energy has estimated the regional rate design proposed by AEP for existing facilities would shift approximately $2.5 million in annual transmission costs to the NSP System. The impact of the regionalization of future facilities would depend on the specific facilities placed in service. NSP-Wisconsin and NSP-Minnesota intend to oppose certain aspects of the AEP proposal.

 

MISO Ancillary Services Market – On Sept. 14, 2007, MISO filed an application with FERC to establish a regional ancillary services market (ASM), whereby MISO would provide bid-based-regulation and contingency operating reserve markets as an expansion of the regionalized wholesale energy sales market. The ASM is proposed to be effective in June 2008. Xcel Energy generally supports implementation of the ASM, since it is expected to allow NSP System generation to be used more efficiently because certain

 

12



 

generation will not always need to be held in reserve, and the ASM is expected to facilitate the operation of wind generation on the NSP System required to achieve state-mandated renewable energy supply standards. The ASM proposal is pending FERC action.

 

Revenue Sufficiency Guarantee Charges On April 25, 2006, the FERC issued an order determining that MISO had incorrectly applied its TEMT regarding the application of the revenue sufficiency guarantee (RSG) charge to certain transactions. The FERC ordered MISO to resettle all affected transactions retroactive to April 1, 2005. The RSG charges are collected from  MISO customers and paid to generators. On Oct. 26, 2006, the FERC issued an order granting rehearing in part and reversed the prior ruling requiring MISO to issue retroactive refunds and ordered MISO to submit a compliance filing to implement prospective changes.

 

On March 15, 2007, the FERC issued orders separately denying rehearing of the Oct. 26, 2006, order and rejecting certain aspects of the MISO compliance filings submitted in November 2006. The FERC ordered MISO to submit a revised compliance filing. As of Sept. 30, 2007, Xcel Energy has recorded an accrual of $1.8 million for this matter.

 

Five parties have filed separate Petitions for Review at the United States Court of Appeals for the District of Columbia Circuit (D.C. Circuit) seeking judicial review of the FERC’s determinations of the allocation of RSG costs among MISO market participants. Xcel Energy has intervened in each of these proceedings. On Aug. 16, 2007, the D.C. Circuit dismissed two of these Petitions for Review as incurably premature because the relevant petitioners also had pending requests for rehearing before the FERC. The remaining appeals are currently being held in abeyance subject to the resolution of the FERC proceedings.

 

On Aug. 10, 2007, Ameren Services Company (Ameren) and the Northern Indiana Public Service Company (NIPSCO) filed a joint complaint against MISO at FERC, challenging the MISO’s current FERC-approved methodology for the recovery of RSG costs. Subsequently, on Aug. 17, 2007 and Aug. 24, 2007, Great Lakes Utilities, Indiana Municipal Power Agency, Missouri Joint Municipal Electric Utility Commission, Missouri River Energy Services, Prairie Power, Inc., Southern Minnesota Municipal Power Agency and Wisconsin Public Power Inc. (collectively, Midwest TDUs), and Wabash Valley Power Association, Inc. (Wabash), respectively, filed complaints at the FERC effectively adopting the substantive arguments raised by Ameren and NIPSCO. The Midwest TDUs and Wabash explained that they filed their complaints to protect their own interests in the event that the complaint filed by Ameren and NIPSCO was dismissed by the FERC. Xcel Energy has moved to intervene in each of these proceedings. All three of these complaints are currently pending at FERC.

 

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

 

NSP-Minnesota Electric Rate Case — In November 2005, NSP-Minnesota requested an electric rate increase of $168 million or 8.05 percent. This increase was based on a requested 11 percent return on common equity (ROE), a projected common equity to total capitalization ratio of 51.7 percent and a projected electric rate base of $3.2 billion. On Dec. 15, 2005, the MPUC authorized an interim rate increase of $147 million, subject to refund, which became effective on Jan. 1, 2006.

 

On Sept. 1, 2006, the MPUC issued a written order granting an electric revenue increase of approximately $131 million for 2006 based on an authorized ROE of 10.54 percent. The scheduled rate increase has been reduced in 2007 to $115 million to reflect the return of Flint Hills Resources, a large industrial customer, to the NSP-Minnesota system. The MPUC Order became effective in November 2006, and final rates were implemented on Feb. 1, 2007.

 

On March 13, 2007, a citizen intervenor submitted a brief asking that the Minnesota Court of Appeals remand to the MPUC with direction to determine the correct amount of income tax collected in rates but not paid to taxing authorities, order the refund or credit to ratepayers for taxes collected in rates but not paid, order the refund to ratepayers of the amount of interim rates collected in January and February of 2006 in violation of the previous merger order and provide other equitable relief. The citizen intervenor passed away on May 15, 2007. The estate has filed a request with the Minnesota Court of Appeals that the appeal continue with the estate listed as the appellant. The Count of Appeals will hold a non-oral conference on the appeal on Dec. 4, 2007. No oral argument will be heard and the parties are not allowed to attend the conference. Unless an extension is granted, a decision will be issued by the count within ninety days from the date of the non-oral conference.

 

NSP-Minnesota Natural Gas Rate Case — In November 2006, NSP-Minnesota filed a request with the MPUC to increase Minnesota natural gas rates by $18.5 million annually, which represented an increase of 2.4 percent. The request was based on 11.0 percent ROE, a projected equity ratio of 51.98 percent and a natural gas rate base of $439 million. Interim rates, subject to refund, were set at a $15.9 million increase and went into effect on Jan. 8, 2007.

 

On Aug. 16, 2007, the MPUC voted to approve a rate increase of approximately $11.9 million, based on an authorized ROE of 9.71 percent and an equity ratio of 51.98 percent. The written order was issued on Sept. 10, 2007.

 

On Oct. 1, 2007, NSP-Minnesota sought rehearing on the ROE issue, asking that the MPUC award a higher return consistent with precedent. The Minnesota Office of the Attorney General (MOAG) opposed this request. Rehearing is pending MPUC action. The MPUC has until Nov. 29, 2007, to reconsider its order, or NSP-Minnesota's petition for rehearing will be deemed denied and the Sept. 10, 2007, order will be final.

 

MISO Day 2 Market Cost Recovery — On Dec. 20, 2006, the MPUC issued an order ruling that NSP-Minnesota may recover all MISO Day 2 costs, except Schedules 16 and 17 administraitive charges, through its fuel clause adjustment (FCA) effective April 1, 2005.

 

13



 

                     NSP-Minnesota is refunding Schedule 16 and 17 costs recovered through the FCA in 2005 ($4.4 million) to customers through the FCA in equal monthly installments beginning March 2007.

                     NSP-Minnesota is recovering 50 percent of Schedule 16 and 17 costs starting in 2006 in the final rates established in the 2005 electric rate case.

                     NSP-Minnesota is allowed to defer 100 percent of the Schedule 16 and 17 costs not included in rates for a three-year period before starting the amortization.

                     The MPUC ruling on Schedules 16 and 17 costs will have no impact on net income in 2007.

 

On April 9, 2007, the MOAG filed an appeal of the MPUC order to the Minnesota Court of Appeals. NSP-Minnesota and the other affected utilities intervened in the appeal and filed briefs urging the court to uphold the MPUC order. The date for a court decision in the appeal is not known.

 

Transmission Cost Recovery  In November 2006, the MPUC approved  a Transmission Cost Recovery (TCR) rider pursuant to 2005 legislation. The TCR mechanism would allow recovery of incremental transmission investments between rate cases.

 

On Oct. 27, 2006, NSP-Minnesota filed for approval of recovery of $14.7 million in 2007 under the TCR tariff. On March 8, 2007, the MPUC voted to approve the recommendation of the Minnesota Department of Commerce (MDOC) to allow recovery of $11.5 million in 2007.

 

On Aug. 31, 2007, NSP-Minnesota filed for approval of recovery of $19.7 million in Minnesota retail electric rates in 2008 under the TCR tariff. The Aug. 31, 2007 filing is pending written comments and MPUC action.

 

On Feb. 28, 2007, NSP-Minnesota filed for South Dakota Public Utilities Commission (SDPUC) approval of a Transmission Cost Recovery Rider (TCRR). NSP-Minnesota proposed to recover $0.8 million in transmission related costs in 2007 outside a general rate case. The Feb. 28, 2007 filing is pending SDPUC action.

 

On Sept. 28, 2007, NSP-Minnesota and NSP-Wisconsin jointly filed proposed changes to the MISO TEMT to modify the wholesale formula transmission rate applicable to the NSP System to change from a historic test year to a forward-looking test year and provide for current recovery of a return on construction work in progress (CWIP) on certain new transmission investments. The proposed rate change would be effective Jan. 1, 2008. If approved by FERC, the change would not affect 2007 results, but would be expected to generate approximately $2.7 million of additional wholesale transmission service revenues in 2008 and additional annual increases in future years as NSP-Minnesota and NSP-Wisconsin work to complete their planned investment of approximately $1 billion in additional transmission plant by 2012. The filing is pending intervenor comments and FERC action.

 

Renewable Energy Standard Rider – In June 2007, NSP-Minnesota filed an application for a new  rate rider to recover the costs associated with utility-owned projects implemented in compliance with the Renewable Energy Standard adopted by the 2007 Minnesota Legislature. The proposed rate adjustment would recover the costs associated with the Grand Meadow wind farm, a 100-MW wind project proposed by NSP-Minnesota. The rate rider would recover the 2008 revenue requirements associated with the project of approximately $14.6 million. MPUC consideration of the certificate of need and site certificate needed for the Grand Meadow project is expected before year end. On Oct. 2, 2007, the MDOC filed comments recommending approval of the certificate of need, and no party has filed opposing comments as of this time.

 

Fixed Bill Complaint In January 2007, the MOAG filed a complaint with the MPUC regarding the fixed monthly gas payment programs of NSP-Minnesota and another unaffiliated natural gas utility. This program generally allows customers to elect a fixed monthly payment for natural gas service that will not change for one year regardless of changes in natural gas costs or consumption due to weather. The complaint seeks termination of the program or modification, and seeks interim relief that would allow customers to exit the program.

 

On July 16, 2007, the MPUC issued its order suspending the program until the MPUC determines it is in the public interest. Other terms of the order include allowing low income housing energy assistance program customers to immediately exit the fixed monthly gas payment program retroactive to the start of the current program year without incurring an exit fee. NSP-Minnesota has filed  to terminate the program after the current year, and is informing the appropriate customers of their ability to exit the program. In addition, NSP-Minnesota was directed to attempt to resolve all stranded cost issues with the MOAG. If a settlement with the MOAG was not reached, NSP-Minnesota could submit a proposal to the MPUC for resolution. A settlement was not reached. On July 6, 2007, NSP-Minnesota filed its proposal to resolve the phase out of the program, which includes allowing early exit to an identified group of customers whose actual usage varied significantly from that assumed in the fixed bill quote and recovery of all stranded costs associated with both early termination of the program and the exit of the affected low-income and low usage customers. The MOAG disputes recovery of stranded costs and recommends continued investigation. This matter is still pending before the MPUC with a decision expected later this year. Xcel Energy does not expect the complaint to have a material impact on the consolidated financial statements.

 

14



 

Mercury Cost Recovery On Dec. 29, 2006, NSP-Minnesota requested approval of a Mercury Emissions Reduction Rider  . The request is designed to recover approximately $5.4 million during 2007 from Minnesota electric retail customers for costs associated with implementing both the mercury and other environmental improvement portions of the Mercury Emissions Reduction Act of 2006. It was the MDOC's position that NSP-Minnesota must file the environmental improvement plans required in compliance with the 2006 Mercury Reduction Act before this filing could be approved. NSP-Minnesota subsequently withdrew the filing and obtained approval to defer costs associated with its compliance with the 2006 Mercury Reduction Act as a regulatory asset for potential future recovery.

 

Annual Automatic Adjustment Report for 2006 — On Sept. 2, 2006, NSP-Minnesota filed its annual automatic adjustment report for the period from July 1, 2005 through June 30, 2006, which is the basis for the MPUC review of charges that flow through the FCA mechanism. The MDOC filed comments on April 18, 2007, asserting that NSP-Minnesota had not demonstrated the reasonableness of its cost assignment of certain market energy charges from the MISO Day 2 market between daily sales of excess generation and native energy needs. The MDOC indicated that NSP-Minnesota should provide additional support for its methodology. NSP-Minnesota filed reply comments arguing the cost assignment is consistent with the methodology approved in both a 2000 MPUC investigation of FCA cost allocations and the Dec. 20, 2006 MPUC order authorizing FCA recovery of most MISO Day 2 charges. The MDOC filed reply comments on Oct. 19, 2007 indicating that the cost assignment issues raised in initial comments have been resolved but raising other issues. NSP-Minnesota anticipates filing reply comments responding to the MDOC's new recommendations. The 2006 annual automatic adjustment report is pending final MPUC action.

 

Annual Automatic Adjustment Report for 2007 — On Sept. 4, 2007, NSP-Minnesota filed its annual automatic adjustment report for the period from July 1, 2006 through June 30, 2007, which is the basis for the MPUC review of charges that flow through the FCA mechanism. During that time period, $1.16 billion in fuel and purchased energy costs, including $384 million of MISO Day 2 energy market charges were recovered from customers. The 2007 annual automatic adjustment report is pending MDOC comments and MPUC action.

 

Annual Review of Remaining Lives Depreciation Filing — On June 4, 2007, NSP-Minnesota recommended lengthening the life of the Monticello nuclear plant by 20 years, effective Jan. 1, 2007 as well as certain other smaller life adjustments, as part of its annual review of remaining lives depreciation filing.

 

On Sept. 20, 2007, the MPUC approved NSP-Minnesota’s remaining lives depreciation filing lengthening the life of the Monticello nuclear plant by 20 years, effective Jan. 1, 2007, as well as certain other smaller life adjustments. These adjustments, of approximately $31 million, have been reflected in NSP-Minnesota’s consolidated financial statements for the quarter and period ended Sept. 30, 2007, as a reduction of depreciation expense. The MPUC also approved an adjustment to rate base to be used in the next electric rate case that will hold ratepayers indifferent to this change in remaining lives between rate cases. NSP-Minnesota calculated the revenue requirement associated with this adjustment to be approximately $1.4 - $2.8 million, depending on the timing of the next electric rate case. In addition, the lengthening of the remaining life for the Monticello nuclear plant decreased the related asset retirement obligation by $121 million in the third quarter of 2007.

 

NSP-Wisconsin

 

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

 

Electric and Gas Rate Case — On June 1, 2007, NSP-Wisconsin filed with the PSCW a request to increase retail electric rates by $67.4 million and retail natural gas rates by $5.3 million, representing overall increases of 14.3 percent and 3.3 percent, respectively. The request assumes a common equity ratio of 53.86 percent, a return on equity of 11.00 percent and a combined electric and natural gas rate base of approximately $640 million.

 

On Oct. 15, 2007, the PSCW staff and intervenors filed testimony in response to NSP-Wisconsin’s requested increase. The PSCW staff recommended an electric rate increase of approximately $44.1 million and a natural gas rate increase of $4.3 million, based on a return on equity of 10.75 percent and a common equity ratio of 53.58 percent. The PSCW staff testimony recommended adjustments that would decrease NSP-Wisconsin’s electric request by approximately $23.3 million. Approximately half of the PSCW staff’s adjustments are based on new or revised data since the filing was prepared. Specifically, PSCW staff increased 2008 forecast electric revenues based on a more recent forecast of electric sales and energy losses and also recognized the increased revenues generated by the electric fuel surcharge approved by the PSCW on Oct. 11, 2007. These adjustments, if accepted by the PSCW, are not expected to have an earnings impact on NSP-Wisconsin. The remaining adjustments, discussed in PSCW staff testimony, relate to reductions in rate base, operating and maintenance expenses and amortization expenses.

 

The Wisconsin Industrial Energy Group (WIEG) and the Wisconsin Paper Council (WPC) also filed testimony in opposition to the rate increase on behalf of their members. WIEG proposed an electric rate increase of approximately $40.1 million, based on a 10.0 percent return on equity and a common equity ratio of 50.93 percent. WIEG disputed certain costs related to power production that are billed to NSP-Wisconsin through the interchange agreement with NSP-Minnesota, also a wholly owned subsidiary of Xcel Energy Inc. Specifically, WIEG contends that NSP-Minnesota nuclear decommissioning costs are overstated due to planned life extension at the Monticello and Prairie Island plants. WIEG is also disputing increasing costs associated with the Nuclear Management Company. Finally, WIEG contends fuel and purchased power costs are overstated because forced outage rates assumed for certain power plants

 

15



 

are too high. WIEG’s total proposed reduction to the electric request is approximately $27.3 million. WIEG did not specifically address the proposed natural gas increase. The WPC did not propose any specific adjustments, but generally requested the PSCW minimize the size of the rate increase in light of difficult economic conditions facing the paper industry.

 

Additional staff and intervenor testimony on rate design issues was filed on Oct. 22, 2007, and all rebuttal testimony is due on Oct. 29, 2007. Technical and public hearings are scheduled for Nov. 8, 2007, and Nov. 12, 2007, respectively. The PSCW is expected to act upon the request in December 2007, and new rates are expected to be implemented in early 2008.

 

Electric Fuel Surcharge Application – On Aug. 20, 2007, NSP-Wisconsin filed an application with the PSCW requesting authorization to implement an electric fuel surcharge under the provisions of the Wisconsin fuel rules. The requested surcharge would  increase electric rates by $5.9 million or 1.3 percent on an annual basis. On Oct. 11, 2007, the PSCW issued an order approving interim rates at the requested level that became effective Oct. 15, 2007. This surcharge is expected to generate an estimated $1.3 million in additional revenue for NSP-Wisconsin in 2007. Under the provisions of the Wisconsin fuel rules, any difference between interim rates and final rates is subject to refund. The PSCW is expected to review NSP-Wisconsin’s actual 2007 fuel costs in the first quarter of 2008 to determine whether any refund of interim rates is necessary.

 

MISO Cost Recovery On June 29, 2006, the PSCW opened a proceeding to address the proper amount of MISO Day 2 deferrals that the state’s electric utilities should be allowed to recover and the proper method of rate recovery.

 

On Sept. 1, 2006, NSP-Wisconsin detailed its calculation methodology and reported that, as of June 30, 2006, it had deferred approximately $6.2 million.

 

On Aug. 30, 2007, the PSCW issued its written order in this case approving NSP-Wisconsin’s deferral methodology with two exceptions. The PSCW ruled that NSP-Wisconsin had incorrectly calculated the deferral associated with incremental transmission line losses in 2005 and that MISO’s subsequent billing correction related to over collected losses. These two exceptions would have reduced the June 30, 2006 deferral by $5.0 million. The PSCW also decided that the ultimate decision on the amount of deferred costs eligible for recovery would be addressed in each utility’s next rate case and extended the authorization to defer MISO Day 2 costs through Dec. 31, 2007. In the order, the PSCW also included a provision that allows NSP-Wisconsin to contest a portion of the disallowance relating to transmission line losses in its current rate case.

 

As of Sept. 30, 2007, NSP-Wisconsin has deferred approximately $6.0 million of MISO Day 2 costs, which fully reflects the PSCW’s decisions in this case.

 

In the electric rate case filed June 1, 2007, NSP-Wisconsin requested recovery over a two year period of the MISO Day 2 charges and credits that were deferred from April 1, 2005 through Dec. 31, 2006. Rebuttal testimony will be filed on Oct. 29, 2007 in the electric rate case, NSP-Wisconsin intends to request recovery of an additional $0.5 million of MISO Day 2 costs related to the disallowance for transmission line losses.

 

Fuel Cost Recovery Rulemaking — On June 22, 2006, the PSCW opened a rulemaking docket to address potential revisions to the electric fuel cost recovery rules. Wisconsin statutes prohibit the use of automatic adjustment clauses by large investor-owned electric public utilities. Instead, the statutes authorize the PSCW to approve, after a hearing, a rate increase for these utilities to allow for the recovery of costs caused by an emergency or extraordinary increase in the cost of fuel.

 

On Aug. 24, 2007, the PSCW staff issued its draft revisions to the fuel rules and requested comments. The draft rules are based largely on the original proposal submitted by the joint utilities, but incorporate the modifications requested by the PSCW. The proposed rules incorporate a plan year fuel cost forecast, deferred accounting for differences between actual and forecast costs (if the difference is greater than 2 percent), and an after the fact reconciliation proceeding to allow the opportunity to recover or refund the deferred balance. On Sept. 11, 2007, the utilities and the customer intervenor group filed comments on the PSCW staff ‘s proposed revisions to the rules. The utilities generally supported the draft rules but provided comments on legal issues and policy concerns surrounding the proposed rules. In their comments, the customer intervenor group asserted that the proposed rule changes are in conflict with the statutory prohibition on automatic fuel cost adjustment and constitute retroactive ratemaking.

 

The PSCW is expected to consider the draft rule and filed comments at an open meeting in the fourth quarter of 2007. At this time it is not certain what changes, if any, to the existing rules will be recommended by the PSCW.

 

PSCo

 

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

 

Natural Gas Rate Case On Dec. 1, 2006, PSCo filed with the CPUC, a request to increase natural gas rates by $41.9 million, representing an overall increase of 2.96 percent, primarily related to capital investments and rising operating costs. The request assumed a common equity ratio of 60.17 percent and a ROE of 11 percent. The jurisdictional rate base is approximately $1.1 billion.

 

16



 

On July 3, 2007, the CPUC approved with modifications a comprehensive settlement between PSCo, the CPUC staff, the Colorado Office of Consumer Counsel (OCC) and Seminole Energy Services, LLC, providing for, among other things, the following:

 

                     An annual revenue increase of $32.3 million, based on a 10.25 percent ROE and a 60.17 percent equity ratio.

                     A modification to the partial decoupling mechanism to allow PSCo recovery of additional revenues in future years to compensate for the portion of the decline in weather normalized residential use per customer that exceeds the first 1.3 percent in annual decline in use (to be reflective of 50 percent of the historic average annual decline in use).

 

Final rates were implemented effective July 30, 2007.

 

Transmission Cost Adjustment Rider - On Sept. 7, 2007, PSCo filed with the CPUC a request to implement a transmission cost adjustment rider, which would recover approximately $18.2 million in 2008. This filing is pursuant to recently enacted legislation which entitled public utilities to recover, through a separate rate adjustment clause, the costs that it prudently incurs in planning, developing, and completing the construction or expansion of transmission  This legislation further encourages utilities to invest in transmission facilities by allowing the recovery of the total balance of construction work in progress related to those transmission investments at PSCo’s weighted average cost of capital including its most recently authorized rate of ROE. The CPUC staff and certain other parties are challenging the scope of PSCo’s requested cost recovery under the rider during 2008 and have asked the CPUC to set PSCo’s application for hearing. The Company expects the CPUC to rule on its application prior to Dec. 31, 2007.

 

SPS

 

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, wholesale cooperative customers of Southwestern Public Service Co., a New Mexico corporation (SPS), filed a rate complaint at the FERC. The complaint alleged that SPS’ rates for wholesale service were excessive and that SPS had incorrectly calculated monthly fuel cost adjustments contained in SPS’ wholesale rate schedules. Among other things, the complainants asserted that SPS was not properly calculating the fuel costs that are eligible for recovery  and that SPS had inappropriately allocated average fuel and purchased power costs to its other wholesale customers, effectively raising the fuel costs charges to complainants. Cap Rock Energy Corporation (Cap Rock), a full-requirements customer, Public Service Company of New Mexico (PNM) and Occidental Permian Ltd. and Occidental Power Marketing, L.P. (Occidental) intervened in the proceeding.

 

On May 24, 2006, a FERC administrative law judge (ALJ) issued an initial recommended decision in the proceeding. The FERC will review the initial recommendation and issue a final order. SPS and others have filed exceptions to the ALJ’s initial recommendation. The FERC’s order may or may not follow any of the ALJ’s recommendation. In the recommended decision, the ALJ found that SPS should recalculate its wholesale 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 allocating incremental fuel costs incurred by SPS in making wholesale sales of system firm capacity and associated energy to other firm customers served under market-based rates during this period based on the view that such sales should be treated as opportunity sales.

 

SPS believes the ALJ erred on significant and material issues that contradict FERC policy or rules of law. Specifically, SPS believes, based on FERC rules and precedent, that it has appropriately applied its FCAC tariff to the proper classes of customers. These firm market-based sales were of a long-term duration under FERC precedent and were made from SPS’ entire system. Accordingly, SPS believes that the ALJ erred in concluding that these transactions were opportunity sales, which require the assignment of incremental costs.

 

The FERC has approved system average cost allocation treatment in previous filings by SPS for sales having similar service characteristics and previously accepted for filing certain of the challenged agreements with average fuel cost pricing.

 

Moreover, SPS believes that the ALJ’s recommendation constituted a violation of the filed rate doctrine in that it effectively results in a retroactive amendment to the SPS FERC-approved FCAC tariff provisions. Under existing regulations, the FERC may modify a previously approved FCAC on a prospective basis. Accordingly, SPS believes it has applied its FCAC correctly and has sought review of the recommended decision by the FERC by filing a brief on the exceptions.

 

SPS believes it should ultimately prevail in this proceeding, however, if the FERC were to adopt the majority of the ALJ’s recommendations, SPS’ refund exposure could be approximately $50 million, based on an evaluation of all sales made from Jan. 1, 1999 to Dec. 31, 2006. SPS has entered into settlement discussions with the wholesale cooperative customers. As of Sept. 30, 2007, based upon management’s estimate of this potential liability, SPS believes the appropriate accrual has been recorded for this matter.

 

Additionally, SPS has entered into settlement discussions with the wholesale cooperative customers. As of Sept. 30, 2007, based upon management’s estimate of this potential liability, SPS believes the appropriate accrual has been recorded for this matter.

 

17



 

In July and September 2007, Golden Spread and SPS filed a joint motion requesting the FERC to defer the final order while the cooperative customers negotiate the complaint case. The case is still pending final FERC action.

 

Wholesale Power Base Rate Application On Dec. 1, 2005, SPS filed for a $2.5 million increase in wholesale power rates to certain electric cooperatives. On Jan. 31, 2006, the FERC conditionally accepted the proposed rates for filing, and the $2.5 million power rate increase became effective on July 1, 2006, subject to refund. The FERC also set the rate increase request for hearing and settlement judge procedures. On Sept. 7, 2006, an offer of settlement with respect to the five full-requirements customers was filed for approval and on Sept. 19, 2006, the offer of settlement with respect to PNM was filed for approval. On Sept. 20, 2007, the FERC accepted the settlement with the full-requirements customers. The PNM settlement is still pending before the FERC.

 

Golden Spread Electric Cooperative, SPS’ partial requirements wholesale customer, did not settle and hearings were set for the rate disputes raised by Golden Spread. Subsequent to filing rebuttal testimony, on March 29, 2007, SPS and Golden Spread entered into additional settlement negotiations. The current hearing schedule has been postponed . The FERC has appointed a settlement judge to facilitate negotiations.

 

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

 

Texas Retail Base Rate And Fuel Reconciliation Case — On May 31, 2006, SPS filed a Texas retail electric rate case requesting an increase in annual revenues of approximately $48 million. The rate filing was based on a historical test year, an electric rate base of $943 million, a requested ROE of 11.6 percent and a common equity ratio of 51.1 percent.

 

In addition, SPS submitted a fuel reconciliation filing, which requested approval of approximately $957 million of Texas-jurisdictional fuel and purchased power costs for 2004 through 2005. As a part of the fuel reconciliation case, fuel and purchased energy costs were reviewed.

 

On March 27, 2007, SPS and various intervenors filed a unanimous stipulation agreement related to the Texas retail rate case as well as the fuel reconciliation portion of the proceeding. The agreement includes the following terms:

 

                     The settlement provides for an annual base rate increase of $23 million, or approximately 3 percent.

                     The settlement disallows approximately $27 million of SPS’ 2004 and 2005 fuel expense.

                     An additional $2.3 million will be deducted from SPS’ next fuel reconciliation filing to be made in 2008, associated with the 2006-2007 fuel reconciliation period.

                     All of SPS’ existing long-term firm and interruptible capacity wholesale sales are assigned system average costs for purposes of Texas retail ratemaking, except for sales to El Paso Electric (EPE), which is determined by the PUCT separately.

                     The settlement also creates standards for cost assignment that would apply to future wholesale sale transactions, and establishes margin sharing of market based wholesale demand revenues.

                     If SPS files a general rate case in 2008, the settlement would allow for an interim rate increase associated with a purchased power agreement with Lea Power Partners of approximately $1.5 million per month from the date of commercial operations. Interim rates would be subject to a true-up based on the outcome of the rate case proceeding and actual capacity costs incurred.

 

An estimated settlement allowance and reserve was established in 2006 and prior periods, which approximated the settled amounts of previously deferred or recovered fuel expense.

 

On March 27, 2007, the ALJ approved SPS’ request to implement the $23 million base rate increase, effective April 2007, on an interim basis until the PUCT acts on the stipulation. The $23 million base rate increase includes approximately $14 million of coal cost that was previously recovered through the fuel cost recovery mechanism, and approximately $6.2 million that results from interruptible customers converting to firm service.

 

On July 27, 2007, the PUCT issued a written order adopting the settlement and assigning incremental costs to the EPE sale. The effect of this decision under the terms of the settlement is an additional $3 million in fuel costs assigned to EPE, which SPS will not recover either through its FCA or its contract. For 2008, this amount will reach $6.3 million. SPS has previously given notice to EPE to terminate the agreement based on a regulatory provision and Xcel Energy expects that the termination will be effective in 2009.

 

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

 

New Mexico Fuel Factor Continuation Filing — On Aug. 18, 2005, SPS filed with the NMPRC requesting continuation of the use of SPS’ fuel and purchased power cost adjustment clause (FPPCAC) and current monthly factor cost recovery methodology. This filing was required by NMPRC rule.

 

18



 

Testimony was filed in the case by staff and intervenors objecting to SPS’ assignment of system average fuel costs to certain wholesale sales and the inclusion of certain purchased power capacity and energy payments in the FPPCAC. The testimony also proposed limits on SPS’ future use of the FPPCAC. Related to these issues some intervenors requested disallowances for past periods, which in the aggregate total approximately $45 million. This claim was for the period from Oct. 1, 2001 through May 31, 2005 and does not include the value of incremental cost assigned for wholesale transactions from that date forward. Other issues in the case include the treatment of renewable energy certificates and sulfur dioxide (SO2)allowance credit proceeds in relation to SPS’ New Mexico retail fuel and purchased power recovery clause.

 

On May 2, 2007, the hearing examiner issued his recommended decision in which he determined the following:

 

                     The NMPRC is barred from granting the retroactive refunds or financial penalties requested by the parties.

                     The issues related to the assignment of system average fuel cost to SPS’ firm wholesale sales, subsequent to March 7, 2006, should be litigated in SPS’ next rate case, which was filed in July 2007, or in a separate parallel proceeding with the results to be incorporated into the next rate case.

                     The NMPRC lacked legal authority to apply any change in cost assignment methodology retroactively until such date that SPS was put on notice of any concern with its longstanding assignment practice.

                     March 7, 2006 was the first time that SPS was put on notice with respect to any change in New Mexico’s assignment practice.

                     The future litigation recommendation would determine both the proper allocation and assignment of fixed and fuel costs and examine the prudence of SPS’ firm wholesale contracts and affiliate transactions related to those wholesale sales.

                     Charges collected through the FPPCAC since March 7, 2006, should be subject to refund pending further order of the NMPRC.  The hearing examiner also noted that specific allegations regarding affiliate transactions could also be resolved in these proceedings.

 

Under the recommended decision, SPS would also be ordered to refund approximately $1.6 million of long-term purchased power capacity costs that it acknowledged were erroneously collected through the FPPCAC.  SPS would be authorized to continue its use of the FPPCAC pending a final order in the next rate case.  The hearing examiner also determined that no action was required on renewable energy certificates and that SPS should seek a determination of proper treatment of SO2 allowances in a separate proceeding.  Although there is no deadline for NMPRC action, SPS expects the NMPRC will act during the fourth quarter of 2007. As of Sept. 30, 2007, based upon management’s estimate of this potential liability, SPS believes the appropriate accrual has been recorded for this matter.

 

New Mexico Electric Rate Case - On July 30, 2007, SPS filed with the NMPRC requesting a New Mexico retail electric general rate increase of $17.3 million annually, or a 6.6 percent increase. The rate filing is based on a 2006 calendar year base period adjusted for known and measurable changes and includes a requested rate of return on equity of 11.0 percent, an electric rate base of approximately $307.3 million allocated to the New Mexico retail jurisdiction and an equity ratio of 51.2 percent. The NMPRC suspended the requested effective date for an additional nine months beyond the requested effective date. Intervenor testimony is due Dec. 21, 2007 and hearings are scheduled for Jan. 28-Feb. 1, 2008. A decision on the request is expected in the second quarter of 2008, and final rates are expected to be implemented in mid-2008.

 

Investigation of SPS Participation in SPP - On Oct. 16, 2007, the PRC issued an order initiating an investigation to consider the prudence and reasonableness of SPS’ participation in the Southwest Power Pool, Inc. (SPP) RTO. The investigation will consider the costs and benefits of RTO participation to SPS customers in New Mexico. The order required SPS to file direct testimony no later than 75 days after the completion of the hearing in the New Mexico electric rate case.

 

6.              Commitments and Contingent Liabilities

 

Except to the extent noted below, the circumstances set forth in Notes 13, 14 and 15 to the consolidated financial statements included in Xcel Energy’s Current Report on Form 8-K filed on Aug. 8, 2007, and Notes 4 and 5 to the consolidated financial statements in this Quarterly Report on Form 10-Q appropriately represent, in all material respects, the current status of other 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 unresolved contingencies that are material to Xcel Energy’s financial position.

 

Operating Leases During the second and third quarters of 2007, PSCo commenced purchased power agreements that are being accounted for as operating leases in accordance with Emerging Issues Task Force 01-8, “Determining Whether an Arrangement Contains a Lease” and SFAS 13 –”Accounting for Leases”. These agreements require capacity payments of $30.2 million, $35.7 million, $32.0 million, $21.3 million, $17.1 million and $355.6 million for 2007, 2008, 2009, 2010, 2011 and thereafter, respectively.

 

19



 

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 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 and some other parties have caused environmental contamination. Environmental contingencies could arise from various situations, including the following categories of sites:

 

                     Sites of former manufactured gas plants (MGPs) operated by Xcel Energy subsidiaries or predecessors; and

 

                     Third-party sites, such as landfills, to which Xcel Energy is alleged to be a potentially responsible party (PRP) that sent hazardous materials and wastes.

 

Xcel Energy records a liability when enough information is obtained to develop an estimate of the cost of environmental remediation and revises the estimate as information is received. The estimated remediation cost may vary materially.

 

To estimate the cost to remediate these sites, assumptions are made when facts are not fully known. For instance, assumptions may be made about the nature and extent of site contamination, the extent of required cleanup efforts, costs of alternative cleanup methods and pollution-control technologies, the period over which remediation will be performed and paid for, changes in environmental remediation and pollution-control requirements, the potential effect of technological improvements, the number and financial strength of other PRPs and the identification of new environmental cleanup sites.

 

Estimates are revised as facts become known. At Sept. 30, 2007, the liability for the cost of remediating these sites was estimated to be $28.2 million, of which $2.9 million was considered to be a current liability. Some of the cost of remediation may be recovered from:

 

                     Insurance coverage;

                     Other parties that have contributed to the contamination; and

                     Customers.

 

Neither the total remediation cost nor the final method of cost allocation among all PRPs of the unremediated sites has been determined. Estimates have been recorded for Xcel Energy’s future costs for these sites.

 

Manufactured Gas Plant Sites

 

Ashland Manufactured Gas Plant Site — NSP-Wisconsin was 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 Chequemegon Bay adjoining the park.

 

On Sept. 5, 2002, the Ashland site was placed on the National Priorities List. A determination of the scope and cost of the remediation of the Ashland site is not currently expected until late 2007 or 2008 following the submission of the remedial investigation report and feasibility study in 2007. NSP-Wisconsin continues to work with the Wisconsin Department of Natural Resources (WDNR) to access state and federal funds to apply to the ultimate remediation cost of the entire site. In November 2005, the Environmental Protection Agency (EPA) Superfund Innovative Technology Evaluation Program (SITE) Program 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, and the EPA is scheduled to complete its assessment in the fourth quarter of 2007. In 2006, NSP-Wisconsin spent $2.0 million in the development of the work plan, the operation of the existing interim response action and other matters related to the site. 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. The RAOs and PRGs could potentially impact the development and evaluation of remedial options for ultimate site cleanup. In September 2007, the EPA approved the series of reports included in the remedial investigation (RI) report. The draft feasibility study, which develops and assesses the alternatives for cleaning up the site, will be prepared by NSP-Wisconsin and is expected to be submitted to the EPA during the fourth quarter 2007.

 

The WDNR and NSP-Wisconsin have each developed several estimates of the ultimate cost to remediate the Ashland site. The estimates vary significantly, between $4 million and $93 million, because different methods of remediation and different results are

 

20



 

assumed in each. The EPA and WDNR have not yet selected the method of remediation to use at the site. Until the EPA and the WDNR select a remediation strategy for the entire site and determine NSP-Wisconsin’s level of responsibility, NSP-Wisconsin’s liability for the cost of remediating the Ashland site is not determinable. NSP-Wisconsin has recorded a liability of $25.0 million for its potential liability for remediating the Ashland site and for external legal and consultant costs. Since NSP-Wisconsin cannot currently estimate the cost of remediating the Ashland site, that portion of the recorded liability related to remediation is based upon the minimum of the estimated range of remediation costs, using information available to date and reasonably effective remedial methods.

 

On Oct. 19, 2004, the WDNR 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 lawsuit has been stayed. NSP-Wisconsin has recorded an estimate of its potential liability. All costs paid to the WDNR are expected to be recoverable in rates.

 

In addition to potential liability for remediation and WDNR oversight costs, NSP-Wisconsin may also have liability for natural resource damages (NRD) at the Ashland site. NSP-Wisconsin has indicated to the relevant natural resource trustees its interest in engaging in discussions concerning the assessment of natural resources injuries and in proposing various restoration projects in an effort to fully and finally resolve all NRD claims. NSP-Wisconsin is not able to estimate its potential exposure for NRD at the site, but has recorded an estimate of its potential liability based upon the minimum of its estimated range of potential exposure.

 

NSP-Wisconsin has deferred, as a regulatory asset, the costs accrued for the Ashland site based upon an expectation that the PSCW will continue to allow NSP-Wisconsin to recover payments for MGP-related 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 are expected to operate as a credit to ratepayers.

 

Fort Collins Manufactured Gas Plant Site — Prior to 1926, Poudre Valley Gas Co., a predecessor of PSCo, operated an MGP in Fort Collins, Colo., not far from the Cache la Poudre River. In 1926, after acquiring the Poudre Valley Gas Co., PSCo shut down the MGP site and has sold most of the property. An oily substance similar to MGP byproducts was discovered in the Cache la Poudre River. On Nov. 10, 2004, PSCo entered into an agreement with the EPA, the city of Fort Collins and Schrader Oil Co., under which PSCo performed remediation and monitoring work. PSCo has substantially completed work at the site, with the exception of ongoing maintenance and monitoring.

 

In May 2005, PSCo filed a natural gas rate case with the CPUC requesting recovery of cleanup costs at the Fort Collins MGP site spent through March 2005, which amounted to $6.2 million, to be amortized over four years. PSCo reached a settlement agreement with the parties in the case. The CPUC approved the settlement agreement on Jan. 19, 2006 and the final order became effective on Feb. 3, 2006, with rates effective Feb. 6, 2006.

 

In November 2006, PSCo filed a natural gas rate case with the CPUC requesting recovery of additional clean-up costs at the Fort Collins MGP site spent through September 2006, plus unrecovered amounts previously authorized from the last rate case, which amounted to $10.8 million to be amortized over four years. In June 2007, PSCo entered into a settlement agreement that included recovery of the full $10.8 million, but with a five year amortization period. The CPUC approved the agreement on June 18, 2007. The total amount to be recovered from customers is $13.1 million. Estimated future project costs, based upon an assumed 30-year system operating life, including EPA oversight costs, are approximately $3.9 million.

 

In April 2005, PSCo brought a contribution action against Schrader Oil Co. and related parties alleging Schrader Oil Co. released hazardous substances into the environment and these releases caused MGP byproducts to migrate to the Cache La Poudre River, thereby substantially increasing the scope and cost of remediation. PSCo requested damages, including a portion of the costs PSCo incurred to investigate and remove contaminated sediments from the Cache la Poudre River. On Dec. 14, 2005, the court denied Schrader’s request to dismiss the PSCo suit. On Jan. 3, 2006, Schrader filed a response to the PSCo complaint and a counterclaim against PSCo for its response costs under the Comprehensive Environmental Response Compensation and Liability Act (CERCLA) and under the Resource Conservation and Recovery Act (RCRA). Schrader alleged as part of its counterclaim an “imminent and substantial endangerment” of its property as defined by RCRA. PSCo filed a motion for partial summary judgment to dismiss Schrader’s RCRA claim. Oral argument on PSCo’s motion was held  Sept. 12, 2007, and on Oct. 10, 2007 the court granted PSCo’s motion for partial summary judgment and dismissed Schrader’s RCRA claim. Schrader also recently filed a motion for summary judgment seeking to dismiss PSCo’s CERCLA claim. PSCo believes this motion is without merit and will vigorously defend its claim.

 

Third Party and Other Environmental Site Remediation

 

Asbestos Removal — Some of our 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.

 

21



 

See additional discussion of asset retirement obligations in Note 14 in the consolidated financial statements included in Xcel Energy’s Current Report on Form 8-K filed on Aug. 8, 2007. 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.

 

Cunningham and Maddox Station Groundwater  — Cunningham Station is a natural gas-fired power plant constructed in the 1960s by SPS and has 28 water wells installed on its water rights. The well field provides water for boiler makeup, cooling water and potable water. Following an acid release in 2002, groundwater samples revealed elevated concentrations of inorganic salt compounds not related to the release. The contamination was identified in wells located near the plant buildings. The source of contamination is thought to be leakage from ponds that receive blow down water from the plant.

 

In response to a request by the New Mexico Environment Department (NMED), SPS prepared a corrective action plan to address the groundwater contamination. Under the plan submitted to the NMED, SPS agreed to control leakage from the plant blow down ponds through construction of a new lined pond, additional irrigation areas to minimize percolation, and installation of additional wells to monitor groundwater quality. On June 23, 2005, NMED issued a letter approving the corrective action plan. The action plan was subject to continued compliance with New Mexico regulations and oversight by the NMED. The Cunningham wastewater management project has been completed at a final cost of $3.5 million. Upon completion of the project, NMED finalized the wastewater permit. SPS began the implementation of a similar process at the Maddox Station in 2007. The permitting process for Maddox Station has begun and is estimated to cost approximately $1.3 million through 2008 and will be capitalized or expensed as incurred.

 

Other Environmental Requirements

 

Clean Air Interstate Rule In March 2005, the EPA issued the Clean Air Interstate Rule (CAIR)  to further regulate SO2 and nitrogen oxide (NOx) emissions. The objective of CAIR is 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. Xcel Energy generating facilities in other states are not affected. CAIR addresses the transportation of fine particulates, ozone and emission precursors to nonattainment downwind states. 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.

 

On July 11, 2005, SPS, the City of Amarillo, Texas and Occidental Permian LTD filed a lawsuit against the EPA and a request for reconsideration with the agency to exclude West Texas from the CAIR. El Paso Electric Co. joined in the request for reconsideration. Xcel Energy and SPS advocated that West Texas should be excluded from CAIR because it does not contribute significantly to nonattainment with the fine particulate matter standards in any downwind jurisdiction.

 

On March 15, 2006, the EPA denied the petition for reconsideration. On June 27, 2006, Xcel Energy and the other parties filed a petition for review of the denial of the petition for reconsideration, as well as a petition for review of the Federal Implementation Plan, with the D.C. Court of Appeals. Pursuant to the court’s scheduling order, briefing has been finalized, but no court date has been set to hear oral arguments.

 

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. Based on the preliminary analysis of various scenarios of capital investment and allowance purchase, Xcel Energy currently believes that with the installation of low NOx burners on Harrington 3 in 2006, there are capital investments estimated at $12 million remaining for NOx controls in the SPS region. Purchases of NOx allowances in the first phase are estimated at $1.4 million. Annual purchases of SO2 allowances are estimated in the range of $13 million to $25 million each year, beginning in 2012, for phase I, based on allowance costs and fuel quality as of March 2007.

 

In addition, Minnesota and Wisconsin will be included in CAIR, and Xcel Energy has generating facilities in these states that will be impacted. Preliminary estimates of capital expenditures associated with compliance with CAIR in Minnesota and Wisconsin range from $30 million to $40 million. Xcel Energy is not challenging CAIR in these states.

 

These cost estimates represent one potential scenario on complying with CAIR, if West Texas is not excluded. There is uncertainty concerning implementation of CAIR. States are required to develop implementation plans within 18 months of the issuance of the new rules and have a significant amount of discretion in the implementation details. Legal challenges to CAIR rules could alter their requirements and/or schedule. The uncertainty associated with the final CAIR rules makes it difficult to project the ultimate amount and timing of capital expenditures and operating expenses.

 

22



 

While Xcel Energy expects to comply with the new rules through a combination of additional capital investments in emission controls at various facilities and purchases of emission allowances, it is continuing to review the alternatives. Xcel Energy believes the cost of any required capital investment or allowance purchases will be recoverable from customers.

 

Clean Air Mercury Rule — In March 2005, the EPA issued the Clean Air Mercury Rule (CAMR), which regulates mercury emissions from power plants for the first time. The EPA’s CAMR uses a national cap-and-trade system, where compliance may be achieved by either adding mercury controls or purchasing allowances or a combination of both and is designed to achieve a 70 percent reduction in mercury emissions. It affects all coal- and oil-fired generating units across the country that are greater than 25 megawatts (MW). Compliance with this rule occurs in two phases, with the first phase beginning in 2010 and the second phase in 2018. States will be allocated mercury allowances based on coal type and their baseline heat input relative to other states. Each electric generating unit will be allocated mercury allowances based on its percentage of total coal heat input for the state. Similar to CAIR, 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.

 

NSP-Minnesota currently estimates that it can comply through capital investments in emission controls or purchase of emission “allowances” from other utilities making reductions on their systems. Estimating the cost of compliance with CAMR is difficult because technologies specifically designed for control of mercury are in the early stages of development and there is no established market on which to base the cost of mercury allowances. NSP-Minnesota’s preliminary analysis for phase I compliance suggests capital costs of approximately $22.7 million for the mercury control equipment and continuous monitoring equipment at the King, Sherburne County (Sherco) and Black Dog generating facilities. The analysis indicates increased operating and maintenance expenses of approximately $22.6 million, beginning in 2010. Additional costs will be incurred to meet phase II requirements in 2018. To date NSP-Minnesota has spent approximately $1.2 million on mercury monitoring implementation.

 

Testing indicates that NSP-Wisconsin facilities will be low mass mercury emitters: therefore, compliance with CAMR is not expected to require mercury controls or purchases of allowances.

 

In February 2007, the Colorado Air Quality Control Commission passed a mercury rule. The rule was based on a negotiated rule that was agreed upon by participating environmental groups, utilities, local government coalitions, and the Colorado Air Pollution Control Division (CAPCD). The rule requires mercury emission controls capable of achieving 80 percent capture to be installed at Pawnee Station in 2012 and all other Colorado units by 2014. Xcel Energy is in the process of installing mercury monitors on seven Colorado units at an estimated aggregate cost of approximately $2.6 million. Xcel Energy is evaluating the emission controls required to meet the new rule and is currently unable to provide a capital cost estimate. The EPA has expressed concerns with allowance restrictions after reviewing the Colorado mercury rule.

 

In the SPS region, the Texas Commission on Environmental Quality (TCEQ) has adopted by reference the EPA model program. SPS continues to evaluate the strategy for complying with CAMR and estimates capital costs of $14.5 million and increased operating and maintenance expenses of approximately $7.9 million for mercury control equipment beginning in 2010.

 

Minnesota Mercury Legislation — On May 2, 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 Xcel Energy, the Act covers units at the A. S. King and Sherco generating facilities. Under the Act, Xcel Energy has installed, and will maintain and operate continuous mercury emission monitoring systems or other monitoring methods approved by the Minnesota Pollution Control Agency (MPCA). The information obtained will be used to establish a baseline from which to measure mercury emission reductions. Mercury emission reduction plans must be filed by utilities by Dec. 31, 2007 (dry scrubbed units) and Dec. 31, 2009 (wet scrubbed units) that propose to implement technologies most likely to reduce emissions by 90 percent. Implementation would occur by Dec. 31, 2009 for one of the dry scrubbed units, Dec. 31, 2010 for the remaining dry scrubbed unit and Dec. 31, 2014 for wet scrubbed units. The cost of controls will be determined as part of the engineering analysis portion of the mercury reduction plans and is currently estimated to range from $22.7 to $280.2 million for the mercury control and continuous monitoring equipment, with increased operating and maintenance expenses estimated to range from approximately $22.6 to $48.4 million. The lower values include costs to achieve a 50 percent mercury reduction for Sherco units 1 and 2, beginning in 2010. The higher values include costs to try to achieve a 90 percent mercury reduction for Sherco units 1 and 2, beginning in 2010 and escalating to 2013. The lower cost estimates are also included above as part of the total cost estimate to comply with CAMR. Utilities subject to the Act may also submit plans to address non-mercury pollutants subject to federal and state statutes and regulations, which became effective after Dec. 31, 2004. Cost recovery provisions of the Act also apply to these other environmental initiatives. On Sept. 15, 2006, NSP-Minnesota filed a request with the MPUC for recovery of up to $6.3 million of certain environmental improvement costs that are expected to be recoverable under the Act. On Jan. 11, 2007, the MPUC approved this request to defer these costs as a regulatory asset with a cap of $6.3 million. To date NSP-Minnesota has spent approximately $1.2 million on mercury monitoring implementation.

 

Regional Haze Rules — On June 15, 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

 

23



 

facilities in several states will be subject to BART requirements. Some of these facilities are located in regions where CAIR is effective. CAIR has precedence over BART. Therefore, BART requirements will be deemed to be met through compliance with CAIR requirements.

 

The EPA required states to develop implementation plans to comply with BART by December 2007. 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. On May 30, 2006, the Colorado Air Quality Control Commission promulgated BART regulations requiring certain major stationary sources to evaluate and install, operate and maintain BART technology or an approved BART alternative to make reasonable progress toward meeting the national visibility goal. On Aug. 1, 2006, PSCo submitted its BART alternatives analysis to the CAPCD. As set forth in its analysis, PSCo estimates that implementation of the BART alternatives will cost approximately $211 million in capital costs, which includes approximately $62 million in environmental upgrades for the existing Comanche Station project, 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 2011 and 2014. The CAPCD expects to finalize the regional haze state implementation plan in  early 2008 for submittal to the EPA later in the year. BART emission controls associated with the plan must be installed within five years of EPA approval. On June 4, 2007, the CAPCD approved PSCo’s BART analysis and obtained public comment on its BART determination and PSCo’s BART permits. A public hearing before the Air Quality Control Commission is scheduled for Dec. 20, 2007 to review and consider the approval of the BART permits for PSCo.

 

NSP-Minnesota submitted its BART alternatives analysis for Sherco units 1 and 2 on Oct. 26, 2006. The MPCA reviewed the BART analyses for all units in Minnesota and determined that overall, compliance with CAIR is better than BART. At this time, the MPCA is not requiring any BART specific controls that go beyond controls required for CAIR compliance.

 

Voluntary Capacity Upgrade and Emissions Reduction Filing  On Jan. 2, 2007, NSP-Minnesota submitted a filing to the MPUC for a major emissions reduction project at Sherco Units 1, 2 and 3 to reduce emissions and expand capacity. The preliminary projected cost of this project is estimated at $900 million and encompasses the higher value mercury control costs discussed above in the Minnesota Mercury Legislation section. NSP-Minnesota’s investments are subject to the MPUC approval of a cost recovery mechanism. An updated regulatory filing detailing the proposed project is planned in the fourth quarter of 2007.

 

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” 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 challenging the phase II rulemaking. On Jan. 25, 2007, the court issued its decision and remanded virtually every aspect of 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 court-ordered remands. As a result, the rule’s compliance requirements and associated deadlines are currently unknown. It is not possible to provide an accurate estimate of the overall cost of this rulemaking at this time due to the many uncertainties involved.

 

New York Office of the Attorney General Subpoena - On Sept.14, 2007 the Office of the New York Attorney General (NYAG) issued a subpoena pursuant to the Martin Act, a New York statute, to Xcel Energy. The subpoena seeks information and documents related to Xcel Energy’s analysis of risks posed by climate change and possible climate legislation and its disclosures of such risks to investors. In a letter accompanying the subpoena, the NYAG asserts that the increase in CO2 emissions upon completion of construction of Comanche 3 (a coal-fired unit), “in combination with Xcel’s other coal-fired plants, will subject Xcel to increased financial, regulatory and litigation risks” which need to be disclosed to shareholders. Xcel Energy believes it has fully disclosed these risks, to the extent they can be ascertained, and such disclosures belie the concerns expressed by the NYAG.

 

PSCo Notice of Violation  On July 1, 2002, PSCo received a Notice of Violation (NOV) from the EPA alleging violations of the New Source Review (NSR) requirements of the Clean Air Act (CAA) at the Comanche and Pawnee plants 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. It 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.

 

24



 

Arandell vs. e prime, Xcel Energy, NSP-Wisconsin et al.   In February 2007, a complaint was filed alleging that NSP-Wisconsin, Xcel Energy and e prime, among others, engaged in fraud and anticompetitive activities in conspiring to restrain the trade of natural gas and manipulate natural gas prices. The plaintiffs seek a declaration that contracts for natural gas entered into between Jan. 1, 2000 and Oct. 31, 2002 are void, that they are entitled to repayment for amounts paid for natural gas during that time period, and that treble damages are appropriate. The case was filed in the Wisconsin State Court (Dane County), and then removed to U.S. District Court for the Western District of Wisconsin. In June 2007, the plaintiffs filed a motion to remand the matter to state court, which was denied and then transferred by the Multi-District Litigation (MDL) panel to Federal District Court Judge Pro in Nevada, who is the judge assigned to western area wholesale natural gas marketing litigation. In July 2007, plaintiffs filed an amended complaint in Federal District Court in Nevada, which includes allegations against NRG, a former Xcel Energy subsidiary. A motion to dismiss was filed by the defendants in September 2007.

 

Heartland Regional Medical Center vs. e prime, Xcel Energy et al. In March 2007, a complaint was filed in the Circuit Court of Buchanan County, Missouri on behalf of a purported class of natural gas purchasers alleging that defendants, including e prime and Xcel Energy, engaged in a conspiracy and falsely reported natural gas trades in an effort to artificially raise natural gas prices. The complaint alleges restraint of trade, price manipulation, and violation of Missouri’s antitrust laws. e prime and Xcel Energy deny the allegations and, together with the other defendants, intend to seek dismissal of all claims.

 

Bender et al. vs. Xcel Energy On July 2, 2004, five former NRG officers filed a lawsuit against Xcel Energy in the U.S. District Court for the District of Minnesota. The lawsuit alleges, among other things, that Xcel Energy violated the Employee Retirement Income Security Act (ERISA) by refusing to make certain deferred compensation payments to the plaintiffs. The complaint also alleges interference with ERISA benefits, breach of contract related to the nonpayment of certain stock options and unjust enrichment. The complaint alleges damages of approximately $6 million. Xcel Energy believes the suit is without merit. On Jan. 19, 2005, Xcel Energy filed a motion for summary judgment. On July 26, 2005, the court issued an order granting Xcel Energy’s motion for summary judgment in part with respect to claims for interference with ERISA benefits, breach of contract for nonpayment of stock options and unjust enrichment. The court denied Xcel Energy’s motion in part with respect to the allegations of nonpayment of deferred compensation benefits. Plaintiffs and Xcel Energy filed additional cross motions for summary judgment, with oral arguments presented on Feb. 24, 2006.

 

On May 17, 2006, the court granted Xcel Energy’s motion for summary judgment in full and denied the plaintiff’s motion for summary judgment in full. Plaintiffs have appealed to the Eighth Circuit Court of Appeals. Oral arguments were presented Jan. 11, 2007 and a decision is pending.

 

Carbon Dioxide Emissions Lawsuit On July 21, 2004, the attorneys general of eight states and New York City, as well as several environmental groups, filed lawsuits in U.S. District Court for the Southern District of New York against five utilities, including Xcel Energy, to force reductions in carbon dioxide (CO2) emissions. The other utilities include American Electric Power Co., Southern Co., Cinergy Corp. and Tennessee Valley Authority. CO2 is emitted whenever fossil fuel is combusted, such as in automobiles, industrial operations and coal- or natural gas-fired power plants. 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 judge granted the motion to dismiss on constitutional grounds. Plaintiffs filed an appeal to the Second Circuit Court of Appeals. On June 21, 2007 the Second Circuit 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 Clean Air Act. In response to the request of the Second Circuit Court of Appeals, the defendant utilities filed a letter brief on July 6, 2007, stating the position that the United States Supreme Court’s decision supports the arguments raised by the utilities on appeal. It is unknown when the Second Circuit Court of Appeals will rule on the appeal.

 

Texas-Ohio Energy, Inc. vs. Centerpoint Energy et al. On Nov. 19, 2003, a class action complaint filed in the U.S. District Court for the Eastern District of California by Texas-Ohio Energy, Inc. was served on Xcel Energy naming e prime as a defendant. The lawsuit, filed on behalf of a purported class of large wholesale natural gas purchasers, alleges that e prime falsely reported natural gas trades to market trade publications in an effort to artificially raise natural gas prices in California. The case has been conditionally transferred by the MDL panel to U.S. District Judge Pro, in Nevada, who is the judge assigned to western area wholesale natural gas marketing litigation. In an order entered April 8, 2005, Judge Pro granted the defendants’ motion to dismiss based on the filed rate doctrine. On May 9, 2005, plaintiffs filed an appeal of this decision to the 9th Circuit Court of Appeals and  on Sept. 24, 2007 the 9th Circuit Court of Appeals reversed the dismissal and remanded to Judge Pro for consideration of whether any of Plaintiffs’ claims are based on retail rates not directly barred by the filed rate doctrine.

 

Fairhaven Power Company vs. Encana Corporation et al. On Sept. 14, 2004, a class action complaint was filed in the U.S. District Court for the Eastern District of California by Fairhaven Power Co. and subsequently served on Xcel Energy. The lawsuit, filed on behalf of a purported class of natural gas purchasers, alleges that Xcel Energy falsely reported natural gas trades to market trade publications in an effort to artificially raise natural gas prices in California and engaged in a conspiracy with other sellers of

 

25



 

natural gas to inflate prices. This case has been consolidated with Texas-Ohio Energy, Inc. vs. Centerpoint Energy et al. and assigned to U.S. District Judge Pro. Defendants filed a motion to dismiss, which was granted on Dec. 19, 2005. The plaintiffs subsequently appealed and on Sept. 24, 2007, the 9th Circuit Court of Appeals reversed the dismissal and remanded to Judge Pro for consideration of whether any of plaintiffs’ claims are based on retail rates not directly barred by the filed rate doctrine.

 

Utility Savings and Refund Services LLP vs. Reliant Energy Services Inc. On Nov. 29, 2004, a class action complaint was filed in the U.S. District Court for the Eastern District of California by Utility Savings and Refund Services LLP and subsequently served on Xcel Energy. The lawsuit, filed on behalf of a purported class of natural gas purchasers, alleges that Xcel Energy falsely reported natural gas trades to market trade publications in an effort to artificially raise natural gas prices in California and engaged in a conspiracy with other sellers of natural gas to inflate prices. This case has been consolidated with Texas-Ohio Energy, Inc. vs. Centerpoint Energy et al. and assigned to U.S. District Judge Pro. Defendants filed a motion to dismiss, which was granted on Dec. 19, 2005. Plaintiffs subsequently appealed and on Sept. 24, 2007, the 9th Circuit Court of Appeals reversed the dismissal and remanded to Judge Pro for consideration of whether any of plaintiffs’ claims are based on retail rates not directly barred by the filed rate doctrine.

 

Abelman Art Glass vs. Ercana Corporation et al. On Dec. 13, 2004, a class action complaint was filed in the U.S. District Court for the Eastern District of California by Abelman Art Glass and subsequently served on Xcel Energy. The lawsuit, filed on behalf of a purported class of natural gas purchasers, alleges that Xcel Energy falsely reported natural gas trades to market trade publications in an effort to artificially raise natural gas prices in California and engaged in a conspiracy with other sellers of natural gas to inflate prices. This case has been consolidated with Texas-Ohio Energy, Inc. vs. Centerpoint Energy et al and assigned to U.S. District Judge Pro. Defendants filed a motion to dismiss, which was granted on Dec. 19, 2005. Plaintiffs subsequently appealed to the 9th Circuit Court of Appeals and on Sept. 24, 2007, the 9th Circuit Court of Appeals reversed the dismissal and remanded to Judge Pro for consideration of whether any of plaintiffs’ claims are based on retail rates not directly barred by the filed rate doctrine.

 

Sinclair Oil Corporation vs. e prime, inc. and Xcel Energy Inc. On July 18, 2005, Sinclair Oil Corporation filed a lawsuit against Xcel Energy and its former subsidiary e prime, inc. in the U.S. District Court for the Northern District of Oklahoma alleging liability and damages for purported misreporting of price information for natural gas to trade publications in an effort to artificially increase natural gas prices. The complaint also alleges that e prime and Xcel Energy engaged in a conspiracy with other natural gas sellers to inflate prices through alleged false reporting of natural gas prices. In response, e prime and Xcel Energy filed a motion with the MDL panel to have the matter transferred to U.S. District Judge Pro, who is the judge assigned to western area wholesale natural gas marketing litigation and filed a second motion to dismiss the lawsuit. In response to this motion, this matter was conditionally transferred to U.S. District Court Judge Pro. Judge Pro granted the motion to dismiss, and Sinclair appealed to the Ninth Circuit Court of Appeals. Sinclair’s appeal was stayed pending the Ninth Circuit’s disposition of the Abelman Art Glass and Texas-Ohio appeals and will remain in effect until Oct. 26, 2007, at which time it will likely be considered by the court in light of the decision in the Abelman, Fairhaven, Utility Savings and Texas-Ohio cases.

 

Ever-Bloom Inc. vs. Xcel Energy Inc. and e prime et al. On June 21, 2005, a class action complaint was filed in the U.S. District Court for the Eastern District of California by Ever-Bloom, Inc. The lawsuit names as defendants, among others, Xcel Energy and e prime. The lawsuit, filed on behalf of a purported class of natural gas purchasers, alleges that defendants falsely reported natural gas trades to market trade publications in an effort to artificially raise natural gas prices in California, purportedly in violation of the Sherman Act. This matter was stayed pending the outcome of cases on appeal to the Ninth Circuit Court of Appeals.

 

Learjet, Inc. vs. e prime and Xcel Energy et al. On Nov. 4, 2005, a purported class action complaint was filed in State Court for Wyandotte County of Kansas on behalf of all natural gas producers in Kansas. The lawsuit alleges that e prime, Xcel Energy and other named defendants conspired to raise the market price of natural gas in Kansas by, among other things, inaccurately reporting price and volume information to the market trade publications. On Dec. 7, 2005, the state court granted the defendants motion to remove this matter to the U.S. District Court in Kansas. Plaintiffs have filed a motion for remand, which was denied on Aug. 3, 2006. Plaintiffs in this matter and in the J.P. Morgan Trust case, discussed below, have moved the judicial panel on MDL for a separate MDL docket to be set up in Kansas Federal Court. Xcel Energy’s and e prime’s motion to dismiss the complaint was denied in July 2007, and in September 2007 both entities filed an answer to the complaint.

 

J.P. Morgan Trust Company vs. e prime and Xcel Energy Inc. et al. On Oct. 17, 2005, J.P. Morgan Trust Company, in its capacity as the liquidating trustee for Farmland Industries Liquidating Trust, filed an amended complaint in Kansas State Court adding defendants, including Xcel Energy and e prime, to a previously filed complaint alleging that the defendants inaccurately reported natural gas trades to market trade publications in an effort to artificially raise natural gas prices. The lawsuit was removed to the U.S. District Court in Kansas and subsequently transferred to U.S. District Court Judge Pro in Nevada pursuant to an order from the MDL panel. A motion to remand to state court filed by plaintiffs has been denied. A motion to dismiss plaintiff’s case was granted by Judge Pro in December 2006. Plaintiff subsequently filed a motion to amend the judgment and defendants filed an opposition to that motion in February 2007. In July 2007, Judge Pro reversed his dismissal of the complaint and ordered defendants to file answers. In September 2007, Xcel Energy and e prime filed their answer to the complaint.

 

26



 

Breckenridge Brewery vs. e prime and Xcel Energy Inc. et al. In May, 2006, Breckenridge Brewery, a Colorado corporation, filed a complaint in Colorado State District Court for the City and County of Denver alleging that the defendants, including e prime and Xcel Energy, unlawfully prevented full and free competition in the trading and sale of natural gas, or controlled the market price of natural gas, and engaged in a conspiracy in constraint of trade. Notice of removal to federal court on behalf of Xcel Energy Inc. and
e prime, inc. was filed in June 2006. On July 6, 2006, the Colorado State District Court granted an enlargement of time within which to file a pleading in response to the complaint. Plaintiffs filed a motion to remand the matter to state court, which was denied in October 2006, and the matter has been transferred to U.S. District Court Judge Pro, in Nevada. Defendants’ motion to dismiss, filed in January 2007, was denied in July 2007. Defendants answered the complaint and in September 2007 filed a motion for summary judgment. In October 2007, plaintiffs moved to amend the complaint by adding e prime Energy Marketing as a defendant.

 

Missouri Public Service Commission vs. e prime, inc. and Xcel Energy Inc. On Oct. 24, 2006, the Missouri Public Utilities Commission filed a complaint in State Court for Jackson County of Missouri alleging that e prime, Xcel Energy and 21 other defendants falsely reported natural gas trades to market trade publications in an effort to artificially raise natural gas prices. The complaint further alleges that such conduct constitutes a violation of the Missouri Antitrust Law, fraud and unjust enrichment. This matter has been removed to U.S. District Court, and plaintiffs have indicated they intend to file a motion to remand to state court. Xcel Energy and e prime deny plaintiffs’ allegations and intend to vigorously defend themselves in this action.

 

Comanche 3 Permit Litigation On Aug. 4, 2005, Citizens for Clean Air and Water in Pueblo and Southern Colorado and Clean Energy Action filed a complaint against the CAPCD alleging that the division improperly granted permits to PSCo under Colorado’s Prevention of Significant Deterioration program for the construction and operation of Comanche 3. PSCo intervened in the case. On June 20, 2006, the court ruled in PSCo’s favor and held that the Comanche 3 permits had been properly granted and plaintiffs’ claims to the contrary were without merit. Plaintiffs have appealed this decision. On Nov. 22, 2006, plaintiffs filed their opening briefs. PSCo’s response was filed Dec. 22, 2006. On Oct. 16, 2007, oral arguments were presented to the Colorado Court of Appeals, who took the matter under advisement and is expected to issue an opinion in due course.

 

Fru-Con Construction Corporation vs. Utility Engineering (UE) et al. On March 28, 2005, Fru-Con Construction Corporation (Fru-Con) commenced a lawsuit in U.S. District Court for 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. UE denies this claim and intends to vigorously defend itself. Because this lawsuit was commenced prior to the April 8, 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. On June 1, 2005, UE filed a motion to dismiss Fru-Con’s complaint. A hearing concerning this motion was held on July 18, 2005, with the court taking the matter under advisement. On Aug. 4, 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.

 

Metropolitan Airports Commission vs. Northern States Power Company On Dec. 30, 2004, the Metropolitan Airports Commission (MAC) filed a complaint in Minnesota State District Court in Hennepin County asserting that NSP-Minnesota is required to relocate facilities on MAC property at the expense of NSP-Minnesota. MAC claims that approximately $7.1 million charged by NSP-Minnesota over the past five years for relocation costs should be repaid. Both parties asserted cross motions for partial summary judgment on a separate and less significant claim concerning legal obligations associated with rent payments allegedly due and owing by NSP-Minnesota to MAC for the use of its property for a substation that serves MAC. A hearing regarding these cross motions was held in January 2006. In February 2006, the court granted MAC’s motion on this issue, finding that there was a valid lease and that the past course of action between the parties required NSP-Minnesota to continue making rent payments. NSP-Minnesota had made rent payments for 45 years. Depositions of key witnesses took place in February, March and April of 2006. The parties entered into settlement negotiations in May 2006, and in August 2006 reached an oral settlement of the dispute. The final form of the settlement documents was agreed upon and the settlement documents were executed in September 2007. The court  filed an order of dismissal on Oct. 15, 2007. The settlement is not expected to have a material impact on Xcel Energy’s consolidated financial statements.

 

Siewert vs. Xcel Energy Plaintiffs, the owners and operators of a Minnesota dairy farm, brought an action 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’ expert report on the economic damage to their dairy farm states that the total present value of plaintiffs’ loss is $6.8 million. NSP-Minnesota denies all allegations and made motions to exclude the testimony of plaintiffs’ experts. Both sides made motions for summary

 

27



 

judgment, which were denied in September 2007, except that plaintiffs’ trespass claims were dismissed. NSP-Minnesota filed a motion to certify questions for immediate appellate review on Oct. 16, 2007, which is scheduled to be heard on Oct. 30, 2007. NSP-Minnesota has also petitioned the Minnesota Court of Appeals for permission to appeal. The trial is scheduled to commence in January 2008.

 

Hoffman vs. Northern States Power Company On March 15, 2006, a purported class action complaint was filed in Minnesota State District Court in Hennepin County, on behalf of NSP-Minnesota’s residential customers in Minnesota, North Dakota and South Dakota for alleged breach of a contractual obligation to maintain and inspect the points of connection between NSP-Minnesota’s wires and customers’ homes within the meter box. Plaintiffs claim NSP-Minnesota’s alleged breach results in an increased risk of fire and is in violation of tariffs on file with the MPUC. Plaintiffs seek injunctive relief and damages in an amount equal to the value of inspections plaintiffs claim NSP-Minnesota was required to perform over the past six years. NSP-Minnesota filed a motion for dismissal on the pleadings, which was heard on Aug. 16, 2006. In November 2006, the court issued an order denying NSP-Minnesota’s motion. On Nov. 28, 2006, pursuant to a motion by NSP-Minnesota, the court certified the issues raised in NSP-Minnesota’s original motion as important and doubtful. This certification permits NSP-Minnesota to file an appeal, and it has done so. Briefs have been filed, and oral arguments were heard Oct. 24, 2007.

 

Comer vs. Xcel Energy Inc. et al. On April 25, 2006, Xcel Energy received notice of a purported class action lawsuit filed in U.S. District Court for 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. On July 19, 2006, Xcel Energy filed a motion to dismiss the lawsuit in its entirety. On Aug. 30, 2007, the court dismissed the lawsuit in its entirety against all defendants on constitutional grounds. On Sept. 17, 2007, plaintiffs filed a notice of appeal to the Fifth Circuit.

 

Qwest vs. Xcel Energy Inc. - On June 24, 2004, an employee of PSCo was injured when a pole owned by Qwest malfunctioned. The employee is seeking damages of approximately $7 million. On Sept. 6, 2005, an action against Qwest relating to the incident was filed in Denver District Court by the employee. On April 18, 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 has asserted that PSCo had an affirmative duty to properly train and instruct its employees on pole safety, including testing the pole for soundness before climbing. PSCo filed a counterclaim on May 15, 2006, 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. On May 14, 2007  this matter went to trial. The trial concluded on May 22, 2007 with a jury verdict that found Qwest solely liable for the accident and damages. Qwest has filed post-trial motions and has indicated that, if the motions are unsuccessful, it will appeal the verdict.

 

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, on Oct. 28, 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. On Nov. 12, 2003, NSP-Wisconsin commenced suit in Wisconsin state circuit court against St. Paul Fire & Marine Insurance Co. and its other insurers. Subsequently, the Minnesota court enjoined NSP-Wisconsin from pursuing the Wisconsin litigation. Although the Wisconsin action has not been dismissed, the January 2007 trial date was adjourned and has not been rescheduled.

 

NSP-Wisconsin has reached settlements with 22 insurers, and these insurers have been dismissed from both the Minnesota and Wisconsin actions.

 

On July 6, 2007, the Minnesota trial court issued its third decision on allocation, reaffirming its prior rulings that Minnesota law on allocation should apply and ordering the dismissal, without prejudice, of eleven insurers whose coverage would not be triggered under such an allocation method. On  Sept. 16, 2007, NSP-Wisconsin commenced an appeal in the Court of Appeals for Minnesota challenging the dismissal of these carriers.

 

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 operate as a credit to ratepayers. None of the aforementioned lawsuit settlements are expected to have a material effect on Xcel Energy’s consolidated financial statements.

 

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 an active participant in the hearings. In September 2001, the presiding ALJ concluded that prices in the Pacific Northwest during the referenced period

 

28



 

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 regarding the use of certain strategies and how they may have impacted the markets in the Pacific Northwest markets. For the referenced period, parties have claimed that the total amount of transactions with PSCo subject to refund are $34 million. On June 25, 2003, the FERC issued an order terminating the proceeding without ordering further proceedings. On Nov. 10, 2003, in response to requests for rehearing, FERC reaffirmed this ruling to terminate the proceeding without refunds. Certain purchasers filed appeals of the FERC’s orders in this proceeding with the United States Court of Appeals for the Ninth Circuit.

 

In an order issued on Aug. 24, 2007, the Ninth Circuit issued an order remanding the proceeding back to the FERC. The court preliminarily determined that it had jurisdiction to review the FERC’s decision not to order refunds. In remanding the case back to FERC, the court directed that the FERC consider evidence that had been presented regarding intentional market manipulation in the California markets and its potential ties to transactions in the Pacific Northwest. The court also indicated that the FERC should consider other of its rulings addressing overcharges in the California organized markets.

 

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 United  States Department of Energy’s (DOE) failure to begin disposing of spent nuclear fuel by Jan. 31, 1998, as required by the contract between the DOE and NSP-Minnesota. When the matter went to trial in October 2006, NSP-Minnesota was claiming damages in excess of $100 million through Dec. 31, 2004. On Sept. 26, 2007, the court awarded NSP-Minnesota $116.5 million in damages. On Oct. 11, 2007 the DOE filed a motion for reconsideration in which it asks the court to reverse several of its key findings. NSP-Minnesota has been given until Nov. 13, 2007 to respond to the motion. The DOE has 60 days from Sept. 26, 2007, in which to file an appeal. Results of the judgment will not be recorded in earnings until the regulatory treatment and amounts to be shared with rate payers has been resolved. Given the uncertainty of a potential appeal and regulatory treatment by the various utility commissions, it is unclear as to how much, if any, of this judgment will ultimately have a net impact on earnings.

 

On Aug. 15, 2007, NSP-Minnesota filed a second complaint against the DOE in the Court of Federal Claims, again claiming breach of contract damages for the DOE’s continuing failure to abide by the terms of the contract. This lawsuit claims damages for the period Jan. 1, 2005 through June 30, 2007, 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. The amount of such damages is expected to exceed $40 million. The government has asked for and received an extension to file its answer, and its answer is now due Dec.14, 2007.

 

Mallon v. Xcel Energy Inc.

 

On July 6, 2007 Theodore Mallon and TransFinancial Corporation filed a declaratory judgment action against Xcel Energy in United States District Court in Colorado (Mallon Federal Action). In this lawsuit, plaintiffs seek a determination that Xcel Energy is not entitled to assert claims against plaintiffs related to the 1984 and 1985 sale of COLI to PSCo, a predecessor of Xcel Energy. On Aug. 15, 2007, Xcel Energy, PSCo and PSRI commenced a lawsuit in state court in Boulder County, Colo. against Mallon and TransFinancial Corporation (Mallon State Action). In the Mallon State Action, Xcel Energy, PSCo and PSRI, a subsidiary of PSCo seek damages against Mallon and TransFinancial for, among other things, breach of contract and breach of fiduciary duties associated with the sale of the COLI policies. On Aug. 15, 2007, Xcel Energy also filed a motion to stay or, in the alternative, to dismiss the Mallon Federal Action. A motion to stay the Mallon State Court action was subsequently filed by plaintiffs Mallon and TransFinancial on Sept. 18, 2007. The motions in both the state and federal court proceedings are still pending and it is uncertain when a decision will be issued by either court.

 

Other Contingencies

 

        See Note 7 to the consolidated financial statements for discussion of exposures under various guarantees.

 

7.              Short-Term Borrowings and Other Financing Instruments

 

Short-Term Borrowings

 

At Sept. 30, 2007, Xcel Energy and its subsidiaries had approximately $420.2 million of short-term debt outstanding at a weighted average interest rate of 5.58 percent.

 

Guarantees

 

Xcel Energy provides various guarantees and bond indemnities supporting certain subsidiaries. The guarantees issued by Xcel Energy guarantee payment or performance by its subsidiaries under specified agreements or transactions. As a result, Xcel Energy’s exposure

 

29



 

under the guarantees is based upon the net liability of the relevant subsidiary under the specified agreements or transactions. Most of the guarantees issued by Xcel Energy limit the exposure of Xcel Energy to a maximum amount stated in the guarantees. On Sept. 30, 2007, Xcel Energy had issued guarantees of up to $75.2 million with $17.5 million of known exposure under these guarantees. In addition, Xcel Energy provides indemnity protection for bonds issued for itself and its subsidiaries. The total amount of bonds with this indemnity outstanding as of Sept. 30, 2007, was approximately $31.6 million. The total exposure of this indemnification cannot be determined at this time. Xcel Energy believes the exposure to be significantly less than the total amount of bonds outstanding.

 

8. Long-Term Borrowings and Other Financing Instruments

 

Long-Term Borrowings

 

During the second quarter of 2007, approximately $126 million of the Xcel convertible notes due Nov. 21, 2007, were converted to common stock. There were no conversions during the third quarter of 2007.

 

On June 26, 2007, NSP-Minnesota issued $350 million of 6.20 percent first mortgage bonds, series due July 1, 2037. NSP-Minnesota added the net proceeds from the sale of the first mortgage bonds to its general funds and applied a portion of the proceeds to the repayment of commercial paper.

 

On Aug. 1, 2007, NSP-Minnesota redeemed all of its outstanding 8.00 percent Notes, Series due 2042, at a redemption price equal to 100 percent of the principal amount of the notes ($25.00), plus accrued and unpaid interest on the notes, if any, to the redemption date. Upon redemption, Xcel Energy recognized approximately $9.3 million in interest expense due to unwinding a fair value interest rate derivative.

 

On Aug. 15, 2007, PSCo issued $350 million of 6.25 percent first mortgage bonds, series due 2037. PSCo added the net proceeds from the sale of the first mortgage bonds to its general funds and applied a portion of the proceeds to the repayment of commercial paper, including commercial paper incurred to fund the payment at maturity of $100 million of 7.11 percent secured medium-term notes, which matured on March 5, 2007.

 

Credit Facility Borrowings – On Sept. 30, 2007, Xcel Energy and its utility subsidiaries had the following borrowings against their five-year unsecured credit facilities:

 

(Millions of dollars)

 

Facility

 

Borrowings

 

NSP-Minnesota

 

$

500

 

$

200

 

PSCo

 

700

 

 

SPS

 

250

 

125

 

Xcel Energy – Holding Company

 

800

 

150

 

Total

 

$

2,250

 

$

475

 

 

The weighted average interest rate on the borrowings was approximately 5.83 percent. The borrowings were all repaid on Oct. 1, 2007.

 

Debt Exchange

 

On March 30, 2007, Xcel Energy settled an exchange offer for up to $350 million aggregate principal amount of its 7 percent Senior Notes, Series due 2010 (the Old Notes). Xcel Energy accepted approximately $241.4 million aggregate principal amount of its Old Notes in exchange for approximately $254.0 million aggregate principal amount of a new series of 5.613 percent senior notes due April 1, 2017 (the New Notes). The $12.6 million non-cash increase in the aggregate principal amount was a result of financing the premium associated with the exchange. In addition, Xcel Energy paid the following amounts in cash: (i) approximately $4.8 million to certain investors as an early participation payment for Old Notes validly tendered prior to 5:00 p.m., New York City time, on March 13, 2007 and accepted for exchange; (ii) approximately $57,000 in cash in lieu of New Notes; and (iii) accrued and unpaid interest to, but not including, the settlement date with respect to the Old Notes accepted for exchange.

 

The New Notes were issued only to holders of Old Notes that certified certain matters to Xcel Energy, including their status as either “qualified institutional buyers,” as that term is defined in Rule 144A under the Securities Act of 1933, or persons other than “U.S. persons,” as that term is defined in Rule 902 under the Securities Act of 1933. The New Notes were issued with a registration rights agreement.

 

In accordance with the Emerging Issues Task Force Issue No. 96-19 (EITF 96-19), Debtor’s Accounting for a Modification or Exchange of Debt Instruments, this transaction was accounted for as an exchange. As such, the fees paid to the bondholders have been associated with the replacement debt instruments and, along with the existing unamortized discount, will be amortized as an adjustment of interest expense over the remaining term of the replacement debt instruments. Also, as required by EITF 96-19, the fees

 

30



 

paid to third parties were expensed as incurred and $1.7 million was included in interest charges and other financing costs in the Consolidated Statements of Income.

 

On June 19, 2007, Xcel Energy filed a registration statement with the SEC to exchange the New Notes for exchange notes, which have terms identical in all material respects to the New Notes, except that the exchange notes do not contain transfer restrictions nor are they subject to registration rights.

 

9.              Derivative Valuation and Financial Impacts

 

Xcel Energy and its subsidiaries use a number of different derivative instruments in connection with their utility operations, short-term wholesale and commodity trading activities, including forward contracts, futures, swaps and options. These derivative instruments are utilized in connection with various commodity prices, certain energy related products, including emission allowances and renewable energy credits and interest rates. All derivative instruments not qualifying for the normal purchases and normal sales exception, as defined by SFAS 133-”Accounting for Derivative Instruments and Hedging Activities,” as amended (SFAS 133), are recorded at fair value. The presentation of these derivative instruments is dependent on the designation of a qualifying hedging relationship. The adjustment to fair value of derivative instruments not designated in a qualifying hedging relationship is reflected in current earnings or as a regulatory balance.

 

Xcel Energy records the fair value of its derivative instruments in its Consolidated Balance Sheets as separate line items identified as Derivative Instruments Valuation in both current and noncurrent assets and liabilities. The fair value of all interest rate swaps is determined through counterparty valuations, internal valuations and broker quotes. There have been no material changes in the techniques or models used in the valuation of interest rate swaps during the periods presented.

 

Qualifying hedging relationships are designated as either a hedge of a forecasted transaction or future cash flow (cash flow hedge), or a hedge of a recognized asset, liability or firm commitment (fair value hedge). The types of qualifying hedging transactions in which Xcel Energy and its subsidiaries are currently engaged are discussed below.

 

Cash Flow Hedges

 

Xcel Energy and its subsidiaries enter into derivative instruments to manage variability of future cash flows from changes in commodity prices and interest rates.

 

As of Sept. 30, 2007, Xcel Energy and its utility subsidiaries had various commodity-related contracts designated as cash flow hedges extending through December 2009. The fair value of these cash flow hedges is recorded in Other Comprehensive Income or deferred as a regulatory asset or liability. This classification is based on the regulatory recovery mechanisms in place. This could include the purchase or sale of energy or energy-related products, the use of natural gas to generate electric energy or gas purchased for resale.

 

Xcel Energy and its 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 designated as cash flow hedges for accounting purposes, and the change in the fair value of these instruments is recorded as a component of Other Comprehensive Income.

 

As of Sept. 30, 2007, Xcel Energy had net gains of approximately $1.1 million in Accumulated Other Comprehensive Income related to interest rate cash flow hedge contracts that are expected to be recognized in earnings during the next 12 months.

 

Gains or losses on hedging transactions for the sales of energy or energy-related products are recorded as a component of revenue, hedging transactions for fuel used in energy generation are recorded as a component of fuel costs, hedging transactions for gas purchased for resale are recorded as a component of gas costs and interest rate hedging transactions are recorded as a component of interest expense. Certain utility subsidiaries are allowed to recover in electric or gas rates the costs of certain financial instruments purchased to reduce commodity cost volatility. There was an immaterial amount of ineffectiveness in the third quarter of 2007.

 

The impact of qualifying 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,

 

(Millions of Dollars)

 

2007

 

2006

 

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

 

$

8.3

 

$

19.5

 

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

 

(2.0

)

(16.1

)

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

 

(0.2

)

0.2

 

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

 

$

6.1

 

$

3.6

 

 

31



 

 

 

Nine months ended Sept. 30,

 

(Millions of Dollars)

 

2007

 

2006

 

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

 

$

2.2

 

$

(8.8

)

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

 

4.6

 

12.7

 

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

 

(0.7

)

(0.3

)

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

 

$

6.1

 

$

3.6

 

 

Fair Value Hedges

 

The effective portion of the change in the fair value of a derivative instrument qualifying as a fair value hedge is offset against the change in the fair value of the underlying asset, liability or firm commitment being hedged. That is, fair value hedge accounting allows the gains or losses of the derivative instrument to offset, in the same period, the gains and losses of the hedged item.

 

Derivatives Not Qualifying for Hedge Accounting

 

Xcel Energy and its subsidiaries enter into certain commodity-based derivative transactions, not included in trading operations, which do not qualify for hedge accounting treatment. These derivative instruments are accounted for on a mark-to-market basis in the Consolidated Statements of Income. The results of these transactions are recorded as a component of Operating Expenses on the Consolidated Statements of Income.

 

Normal Purchases or Normal Sales Contracts

 

Xcel Energy’s utility subsidiaries enter into contracts for the purchase and sale of various commodities for use in their business operations. SFAS 133 requires a company to evaluate these contracts to determine whether the contracts are derivatives. Certain contracts that meet the definition of a derivative may be exempted from SFAS 133 as normal purchases or normal sales.

 

Xcel Energy evaluates all of its contracts when such contracts are entered to determine if they are derivatives and, if so, if they qualify to meet the normal designation requirements under SFAS 133. None of the contracts entered into within the commodity trading operations qualify for a normal designation.

 

10.       Detail of Interest and Other Income (Expense), Net

 

Interest and other income, net of nonoperating expenses, for the three and nine months ended Sept. 30 consisted of the following:

 

 

 

Three months ended Sept. 30,

 

Nine months ended Sept. 30,

 

(Thousands of dollars)

 

2007

 

2006

 

2007

 

2006

 

Interest income

 

$

6,101

 

$

4,158

 

$

15,180

 

$

13,811

 

Equity income in unconsolidated affiliates

 

616

 

1,192

 

2,800

 

3,470

 

Other nonoperating income

 

1,479

 

2,190

 

2,710

 

6,284

 

Minority interest income

 

225

 

1,795

 

472

 

2,098

 

Other nonoperating expense

 

(1,973

)

(3,753

)

(5,659

)

(9,688

)

Total interest and other income, net

 

$

6,448

 

$

5,582

 

$

15,503

 

$

15,975

 

 

11. Common Stock and Equivalents

 

Xcel Energy has common stock equivalents consisting of convertible senior notes, 401(k) equity awards and stock options. Restricted stock units and performance shares are included as common stock equivalents when all necessary conditions for issuance have been satisfied by the end of the reporting period. For the three and nine months ended Sept. 30, 2007, Xcel Energy had approximately 9.5 million and 10.3 million options outstanding, respectively, that were antidilutive and, therefore, excluded from the dilutive earnings per share calculation. For the three and nine months ended Sept. 30, 2006, Xcel Energy had approximately 11.1 million and 12.7 million options outstanding, respectively, that were antidilutive.

 

32



 

The dilutive impacts of common stock equivalents affected earnings per share as follows for the three and nine months ending Sept. 30, 2007 and 2006:

 

 

 

Three months ended Sept. 30, 2007

 

Three months ended Sept. 30, 2006

 

(Amounts in thousands, except per share amounts)

 

Income

 

Shares

 

Per-share
Amount

 

Income

 

Shares

 

Per-share
Amount

 

Income from continuing operations

 

$

246,345

 

 

 

 

 

$

213,848

 

 

 

 

 

Less: Dividend requirements on preferred stock

 

(1,060

)

 

 

 

 

(1,060

 

 

 

 

Basic earnings per share:

 

 

 

 

 

 

 

 

 

 

 

 

 

Income from continuing operations

 

245,285

 

419,822

 

$

0.58

 

212,788

 

406,123

 

$

0.52

 

Effect of dilutive securities:

 

 

 

 

 

 

 

 

 

 

 

 

 

Convertible debt

 

2,190

 

13,094

 

 

 

3,787

 

23,317

 

 

 

401(k) equity awards

 

 

435

 

 

 

 

518

 

 

 

Stock options

 

 

36

 

 

 

 

42

 

 

 

Diluted earnings per share:

 

 

 

 

 

 

 

 

 

 

 

 

 

Income from continuing operations and assumed conversions

 

$

247,475

 

433,387

 

$

0.57

 

$

216,575

 

430,000

 

$

0.50

 

 

 

 

Nine months ended Sept. 30, 2007

 

Nine months ended Sept. 30, 2006

 

(Amounts in thousands, except per share amounts)

 

Income

 

Shares

 

Per-share
Amount

 

Income

 

Shares

 

Per-share
Amount

 

Income from continuing operations

 

$

484,628

 

 

 

 

 

$

455,057

 

 

 

 

 

Less: Dividend requirements on preferred stock