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 June 30, 2006

 

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
incorporation or organization)

 

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

 

 

 

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 July 28, 2006

Common Stock, $2.50 par value

 

405,967,399 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

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 4. Submission of Matters to a Vote of Security Holders

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)

(Thousands of Dollars, Except Per Share Data)

 

Three Months Ended June 30,

 

Six Months Ended June 30,

 

 

 

2006

 

2005

 

2006

 

2005

 

Operating revenues

 

 

 

 

 

 

 

 

 

Electric utility

 

$

1,786,571

 

$

1,720,431

 

$

3,632,443

 

$

3,255,378

 

Natural gas utility

 

270,990

 

326,347

 

1,289,130

 

1,161,402

 

Nonregulated and other

 

16,312

 

17,277

 

40,404

 

37,808

 

Total operating revenues

 

2,073,873

 

2,064,055

 

4,961,977

 

4,454,588

 

 

 

 

 

 

 

 

 

 

 

Operating expenses

 

 

 

 

 

 

 

 

 

Electric fuel and purchased power — utility

 

951,214

 

912,400

 

1,945,909

 

1,673,809

 

Cost of natural gas sold and transported — utility

 

168,822

 

232,039

 

1,019,247

 

900,824

 

Cost of sales — nonregulated and other

 

4,437

 

5,158

 

12,667

 

13,418

 

Other operating and maintenance expenses — utility

 

443,137

 

437,639

 

878,383

 

840,109

 

Other operating and maintenance expenses — nonregulated

 

6,614

 

9,274

 

12,178

 

16,418

 

Depreciation and amortization

 

203,665

 

193,976

 

406,325

 

385,670

 

Taxes (other than income taxes)

 

71,326

 

71,334

 

149,861

 

147,086

 

Total operating expenses

 

1,849,215

 

1,861,820

 

4,424,570

 

3,977,334

 

Operating income

 

224,658

 

202,235

 

537,407

 

477,254

 

 

 

 

 

 

 

 

 

 

 

Interest and other income — net of nonoperating expense (see Note 8)

 

921

 

4,516

 

537

 

2,442

 

Allowance for funds used during construction - equity

 

4,668

 

5,450

 

8,452

 

10,633

 

 

 

 

 

 

 

 

 

 

 

Interest charges and financing costs

 

 

 

 

 

 

 

 

 

Interest charges — includes other financing costs of $6,393, $6,418, $12,605 and $12,897, respectively

 

119,283

 

114,375

 

238,657

 

228,017

 

Allowance for funds used during construction - debt

 

(7,509

)

(4,534

)

(13,882

)

(9,368

)

Total interest charges and financing costs

 

111,774

 

109,841

 

224,775

 

218,649

 

Income from continuing operations before income taxes

 

118,473

 

102,360

 

321,621

 

271,680

 

Income taxes

 

20,537

 

24,684

 

73,873

 

69,541

 

Income from continuing operations

 

97,936

 

77,676

 

247,748

 

202,139

 

Income from discontinued operations — net of tax (see Note 2)

 

339

 

5,730

 

1,825

 

2,745

 

Net income

 

98,275

 

83,406

 

249,573

 

204,884

 

Dividend requirements on preferred stock

 

1,060

 

1,060

 

2,120

 

2,120

 

Earnings available to common shareholders

 

$

97,215

 

$

82,346

 

$

247,453

 

$

202,764

 

 

 

 

 

 

 

 

 

 

 

Weighted average common shares outstanding (thousands)

 

 

 

 

 

 

 

 

 

Basic

 

405,434

 

402,214

 

404,783

 

401,668

 

Diluted

 

429,099

 

425,552

 

428,349

 

425,004

 

Earnings per share — basic

 

 

 

 

 

 

 

 

 

Income from continuing operations

 

$

0.24

 

$

0.19

 

$

0.61

 

$

0.50

 

Discontinued operations

 

 

0.01

 

 

 

Earnings per share — basic

 

$

0.24

 

$

0.20

 

$

0.61

 

$

0.50

 

Earnings per share — diluted

 

 

 

 

 

 

 

 

 

Income from continuing operations

 

$

0.24

 

$

0.19

 

$

0.59

 

$

0.49

 

Discontinued operations

 

 

0.01

 

0.01

 

 

Earnings per share — diluted

 

$

0.24

 

$

0.20

 

$

0.60

 

$

0.49

 

 

See Notes to Consolidated Financial Statements

3




XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
(Thousands of Dollars, Except Per Share Data)

 

 

 

Six Months Ended
June 30,

 

 

 

2006

 

2005

 

Operating activities

 

 

 

 

 

Net income

 

$

249,573

 

$

204,884

 

Remove income from discontinued operations

 

(1,825

)

(2,745

)

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

 

 

 

 

 

Depreciation and amortization

 

422,695

 

395,749

 

Nuclear fuel amortization

 

22,395

 

19,673

 

Deferred income taxes

 

(41,460

)

29,983

 

Amortization of investment tax credits

 

(4,902

)

(5,809

)

Allowance for equity funds used during construction

 

(8,452

)

(10,633

)

Undistributed equity in earnings of unconsolidated affiliates

 

(1,431

)

(414

)

Write down of assets

 

 

3,258

 

Unrealized (gain) loss on derivative instruments

 

(4,947

)

1,614

 

Settlement of interest rate swap

 

13,844

 

 

Change in accounts receivable

 

243,057

 

(11,126

)

Change in inventories

 

139,640

 

107,760

 

Change in other current assets

 

427,733

 

45,726

 

Change in accounts payable

 

(301,555

)

(136,365

)

Change in other current liabilities

 

(17,994

)

(35,401

)

Change in other noncurrent assets

 

(26,567

)

8,498

 

Change in other noncurrent liabilities

 

35,443

 

76,031

 

Operating cash flows provided by discontinued operations

 

75,530

 

106,536

 

Net cash provided by operating activities

 

1,220,777

 

797,219

 

 

 

 

 

 

 

Investing activities

 

 

 

 

 

Utility capital/construction expenditures

 

(733,187

)

(628,623

)

Allowance for equity funds used during construction

 

8,452

 

10,633

 

Purchase of investments in external decommissioning fund

 

(11,570

)

(70,360

)

Proceeds from the sale of investments in external decommissioning fund

 

14,083

 

30,745

 

Nonregulated capital expenditures and asset acquisitions

 

(433

)

(4,424

)

Restricted cash

 

2,132

 

1,621

 

Other investments

 

3,833

 

2,834

 

Investing cash flows provided by discontinued operations

 

42,377

 

83,357

 

Net cash used in investing activities

 

(674,313

)

(574,217

)

 

 

 

 

 

 

Financing activities

 

 

 

 

 

Short-term borrowings — net

 

(608,120

)

(17,300

)

Proceeds from issuance of long-term debt

 

882,877

 

1,283,388

 

Repayment of long-term debt, including reacquisition premiums

 

(570,426

)

(1,287,463

)

Proceeds from issuance of common stock

 

3,628

 

3,778

 

Dividends paid

 

(175,939

)

(167,845

)

Financing cash flows used in discontinued operations

 

 

(200

)

Net cash used in financing activities

 

(467,980

)

(185,642

)

 

 

 

 

 

 

Net increase in cash and cash equivalents

 

78,484

 

37,360

 

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

 

10,533

 

(11,334

)

Cash and cash equivalents at beginning of year

 

72,196

 

23,361

 

Cash and cash equivalents at end of quarter

 

$

161,213

 

$

49,387

 

Supplemental disclosure of cash flow information:

 

 

 

 

 

Cash paid for interest (net of amounts capitalized)

 

$

212,719

 

$

206,488

 

Cash paid for income taxes (net of refunds received)

 

$

(7,083

)

$

6,497

 

Supplemental disclosure of non-cash investing transactions:

 

 

 

 

 

Property, plant and equipment additions

 

$

47,345

 

$

27,743

 

Supplemental disclosure of non-cash financing transactions:

 

 

 

 

 

Issuance of common stock for reinvested dividends and 401K’s

 

$

37,095

 

$

30,114

 

 

See Notes to Consolidated Financial Statements

4




XCEL ENERGY INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS (UNAUDITED)
(Thousands of Dollars)

 

 

June 30, 2006

 

Dec. 31, 2005

 

ASSETS

 

 

 

 

 

Current assets:

 

 

 

 

 

Cash and cash equivalents

 

$

161,213

 

$

72,196

 

Accounts receivable — net of allowance for bad debts of $30,237 and $39,798, respectively

 

768,607

 

1,011,569

 

Accrued unbilled revenues

 

398,680

 

614,016

 

Materials and supplies inventories — at average cost

 

169,383

 

159,560

 

Fuel inventory — at average cost

 

75,630

 

64,987

 

Natural gas inventories — at average cost

 

150,504

 

310,610

 

Recoverable purchased natural gas and electric energy costs

 

169,167

 

395,070

 

Derivative instruments valuation

 

169,296

 

213,138

 

Prepayments and other

 

169,254

 

99,904

 

Current assets held for sale and related to discontinued operations

 

251,826

 

200,811

 

Total current assets

 

2,483,560

 

3,141,861

 

Property, plant and equipment, at cost:

 

 

 

 

 

Electric utility plant

 

19,140,512

 

18,870,516

 

Natural gas utility plant

 

2,813,883

 

2,779,043

 

Common utility and other

 

1,496,780

 

1,518,266

 

Construction work in progress

 

1,100,868

 

783,490

 

Total property, plant and equipment

 

24,552,043

 

23,951,315

 

Less accumulated depreciation

 

(9,588,028

)

(9,357,414

)

Nuclear fuel — net of accumulated amortization: $1,212,781 and $1,190,386, respectively

 

122,246

 

102,409

 

Net property, plant and equipment

 

15,086,261

 

14,696,310

 

Other assets:

 

 

 

 

 

Nuclear decommissioning fund and other investments

 

1,169,974

 

1,145,659

 

Regulatory assets

 

939,610

 

963,403

 

Derivative instruments valuation

 

522,963

 

451,937

 

Prepaid pension asset

 

693,359

 

683,649

 

Other

 

150,039

 

164,212

 

Noncurrent assets held for sale and related to discontinued operations

 

213,080

 

401,285

 

Total other assets

 

3,689,025

 

3,810,145

 

Total assets

 

$

21,258,846

 

$

21,648,316

 

 

 

 

 

 

 

LIABILITIES AND EQUITY

 

 

 

 

 

Current liabilities:

 

 

 

 

 

Current portion of long-term debt

 

$

810,918

 

$

835,495

 

Short-term debt

 

138,000

 

746,120

 

Accounts payable

 

922,878

 

1,187,489

 

Taxes accrued

 

171,443

 

235,056

 

Dividends payable

 

91,298

 

87,788

 

Derivative instruments valuation

 

73,992

 

191,414

 

Other

 

325,840

 

345,807

 

Current liabilities held for sale and related to discontinued operations

 

35,166

 

43,657

 

Total current liabilities

 

2,569,535

 

3,672,826

 

Deferred credits and other liabilities:

 

 

 

 

 

Deferred income taxes

 

2,268,432

 

2,191,794

 

Deferred investment tax credits

 

126,498

 

131,400

 

Regulatory liabilities

 

1,747,128

 

1,710,820

 

Derivative instruments valuation

 

555,703

 

499,390

 

Asset retirement obligations

 

1,329,873

 

1,292,006

 

Customer advances

 

313,906

 

310,092

 

Minimum pension liability

 

88,280

 

88,280

 

Benefit obligations and other

 

354,351

 

343,201

 

Noncurrent liabilities held for sale and related to discontinued operations

 

4,852

 

6,936

 

Total deferred credits and other liabilities

 

6,789,023

 

6,573,919

 

Minority interest in subsidiaries

 

2,973

 

3,547

 

Commitments and contingent liabilities (see Note 5)

 

 

 

 

 

Capitalization:

 

 

 

 

 

Long-term debt

 

6,237,085

 

5,897,789

 

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: June 30, 2006 — 405,560,301; Dec. 31, 2005 — 403,387,159

 

5,555,250

 

5,395,255

 

Total liabilities and equity

 

$

21,258,846

 

$

21,648,316

 

 

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

 

 

 

Accumulated

 

 

 

 

 

Number
of Shares

 

Par Value

 

Capital in
Excess of
Par Value

 

Retained
Earnings

 

Other
Comprehensive
Income (Loss)

 

Total
Stockholders’
Equity

 

Three months ended June 30, 2005 and 2006

 

 

 

 

 

 

 

 

 

 

 

 

 

Balance at March 31, 2005

 

401,835

 

$

1,004,588

 

$

3,932,549

 

$

433,679

 

$

(103,909

)

$

5,266,907

 

Net income

 

 

 

 

 

 

 

83,406

 

 

 

83,406

 

Net derivative instrument fair value changes during the period (see Note 7)

 

 

 

 

 

 

 

 

 

(24,290

)

(24,290

)

Unrealized loss - marketable securities

 

 

 

 

 

 

 

 

 

(32

)

(32

)

Comprehensive income for the period

 

 

 

 

 

 

 

 

 

 

 

59,084

 

Dividends declared: Cumulative preferred stock

 

 

 

 

 

 

 

(1,060

)

 

 

(1,060

)

Common stock

 

 

 

 

 

 

 

(86,507

)

 

 

(86,507

)

Issuances of common stock

 

523

 

1,306

 

7,660

 

 

 

 

 

8,966

 

Balance at June 30, 2005

 

402,358

 

$

1,005,894

 

$

3,940,209

 

$

429,518

 

$

(128,231

)

$

5,247,390

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Balance at March 31, 2006

 

405,087

 

$

1,012,719

 

$

3,994,628

 

$

625,283

 

$

(114,039

)

$

5,518,591

 

Net income

 

 

 

 

 

 

 

98,275

 

 

 

98,275

 

Net derivative instrument fair value changes during the period (see Note 7)

 

 

 

 

 

 

 

 

 

10,320

 

10,320

 

Unrealized gain - marketable securities

 

 

 

 

 

 

 

 

 

6

 

6

 

Comprehensive income for the period

 

 

 

 

 

 

 

 

 

 

 

108,601

 

Dividends declared: Cumulative preferred stock

 

 

 

 

 

 

 

(1,060

)

 

 

(1,060

)

Common stock

 

 

 

 

 

 

 

(90,235

)

 

 

(90,235

)

Issuances of common stock

 

473

 

1,182

 

7,459

 

 

 

 

 

8,641

 

Share-based compensation (see Note 1)

 

 

 

 

 

10,712

 

 

 

 

 

10,712

 

Balance at June 30, 2006

 

405,560

 

$

1,013,901

 

$

4,012,799

 

$

632,263

 

$

(103,713

)

$

5,555,250

 

 

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

 

 

 

Accumulated

 

 

 

 

 

Number
of Shares

 

Par Value

 

Capital in
Excess of
Par Value

 


Retained
Earnings

 

Other
Comprehensive
Income (Loss)

 

Total
Stockholders’
Equity

 

Six months ended June 30, 2005 and 2006

 

 

 

 

 

 

 

 

 

 

 

 

 

Balance at Dec. 31, 2004

 

400,462

 

$

1,001,155

 

$

3,911,056

 

$

396,641

 

$

(105,934

)

$

5,202,918

 

Net income

 

 

 

 

 

 

 

204,884

 

 

 

204,884

 

Minimum pension liability

 

 

 

 

 

 

 

 

 

220

 

220

 

Net derivative instrument fair value changes during the period (see Note 7)

 

 

 

 

 

 

 

 

 

(22,512

)

(22,512

)

Unrealized loss - marketable securities

 

 

 

 

 

 

 

 

 

(5

)

(5

)

Comprehensive income for the period

 

 

 

 

 

 

 

 

 

 

 

182,587

 

Dividends declared:
Cumulative preferred stock

 

 

 

 

 

 

 

(2,120

)

 

 

(2,120

)

Common stock

 

 

 

 

 

 

 

(169,887

)

 

 

(169,887

)

Issuances of common stock

 

1,896

 

4,739

 

29,153

 

 

 

 

 

33,892

 

Balance at June 30, 2005

 

402,358

 

$

1,005,894

 

$

3,940,209

 

$

429,518

 

$

(128,231

)

$

5,247,390

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Balance at Dec. 31, 2005

 

403,387

 

$

1,008,468

 

$

3,956,710

 

$

562,138

 

$

(132,061

)

$

5,395,255

 

Net income

 

 

 

 

 

 

 

249,573

 

 

 

249,573

 

Net derivative instrument fair value changes during the period (see Note 7)

 

 

 

 

 

 

 

 

 

28,320

 

28,320

 

Unrealized gain - marketable securities

 

 

 

 

 

 

 

 

 

28

 

28

 

Comprehensive income for the period

 

 

 

 

 

 

 

 

 

 

 

277,921

 

Dividends declared:
Cumulative preferred stock

 

 

 

 

 

 

 

(2,120

)

 

 

(2,120

)

Common stock

 

 

 

 

 

 

 

(177,328

)

 

 

(177,328

)

Issuances of common stock

 

2,173

 

5,433

 

35,290

 

 

 

 

 

40,723

 

Share-based compensation (see Note 1)

 

 

 

 

 

20,799

 

 

 

 

 

20,799

 

Balance at June 30, 2006

 

405,560

 

$

1,013,901

 

$

4,012,799

 

$

632,263

 

$

(103,713

)

$

5,555,250

 

 

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 June 30, 2006, and Dec. 31, 2005; the results of its operations and changes in stockholders’ equity for the three and six months ended June 30, 2006 and 2005; and its cash flows for the six months ended June 30, 2006 and 2005. 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.

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 Annual Report on Form 10-K for the year ended Dec. 31, 2005 appropriately represent, in all material respects, the current status of accounting policies, and are incorporated herein by reference.

Statement of Financial Accounting Standards (SFAS) No. 123 (Revised 2004) — “Share Based Payment” (SFAS No. 123R) — In December 2004, the Financial Accounting Standards Board (FASB) issued SFAS No. 123R related to equity-based compensation. This statement replaces the original SFAS No. 123 — “Accounting for Stock-Based Compensation.”  Under SFAS No. 123R, companies are no longer allowed to account for their share-based payment awards using the intrinsic value method, which did not require any expense to be recorded on stock options granted with an equal to or greater than fair market value exercise price. Instead, equity-based compensation arrangements will be measured and recognized based on the grant-date fair value using an option-pricing model (such as Black-Scholes or Binomial) that considers at least six factors identified in SFAS No. 123R. An expense related to the difference between the grant-date fair value and the purchase price would be recognized over the vesting period of the options. Under previous guidance, companies were allowed to initially estimate forfeitures or recognize them as they actually occurred. SFAS No. 123R requires companies to estimate forfeitures on the date of grant and to adjust that estimate when information becomes available that suggests actual forfeitures will differ from previous estimates. Revisions to forfeiture estimates will be recorded as a cumulative effect of a change in accounting estimate in the period in which the revision occurs.

Previous accounting guidance allowed for compensation expense related to share-based payment awards to be reversed if the target was not met. However, under SFAS No. 123R, compensation expense for share-based payment awards that expire unexercised due to the company’s failure to reach a certain target stock price cannot be reversed. Any accruals made for Xcel Energy’s restricted stock unit award that was granted in 2004 and is based on a total shareholder return (TSR) cannot be reversed if the target is not met. Implementation of SFAS No. 123R is required for annual periods beginning after June 15, 2005. Xcel Energy adopted the provisions in the first quarter of 2006. Since stock options had vested and other awards were recorded at their fair values prior to implementation of SFAS No. 123R, implementation did not have a material impact on net income or earnings per share. Pro forma net income under SFAS No. 123R for the quarter ended and year-to-date June 30, 2005 would not have been materially different than what was recorded.

Since the vesting of the 2004 restricted stock units is predicated on the achievement of a market condition, the achievement of a TSR, the fair value used to calculate the expense related to this award is based on the stock price on the date of grant adjusted for the uncertainty surrounding the achievement of the TSR. Since the vesting of the 2005 and 2006 restricted stock units is predicated on the achievement of a performance condition, the achievement of an earnings per share or environmental measures target, fair values used to calculate the expense on these plans are based on the stock price on the date of grant. The performance share plan awards have been historically settled partially in cash and therefore do not qualify as an equity award, but are accounted for as a liability award. As a liability award, the fair value on which expense is based is remeasured each period based on the current stock price, and final expense is based on the market value of the shares on the date the award is settled. Compensation expense related to share-based awards of approximately $13.9 million and $16.8 million was recorded in the second quarter of 2006 and 2005, respectively. Compensation expense related to share-based awards of approximately $21.0 million and $19.6 million was recorded in the first six months of 2006 and 2005, respectively. As of June 30, 2006, there was approximately $33.6 million of total unrecognized compensation cost related to non-vested share-based compensation awards. Total unrecognized compensation expense will be adjusted for future changes in estimated forfeitures. We expect to recognize that cost over a weighted-average period of 1.6 years.  The amount of cash used to settle these awards was $11.3 million and $3.6 million for the first six months of 2006 and 2005, respectively.

There have been no material changes to outstanding stock options in the second quarter of 2006.

See Note 9 to the consolidated financial statements in Xcel Energy’s Annual Report on Form 10-K for the year ended Dec. 31, 2005 for a description of Xcel Energy’s stock-based plans.

Metro Emissions Reduction Project (MERP) Accounting Allowance for funds used during construction (AFDC) is an amount capitalized as a part of construction costs representing the cost of financing the construction. Generally these costs are recovered from customers as the related property is depreciated. The Minnesota Public Utilities Commission (MPUC) has approved a more current

8




recovery of the financing costs related to the MERP. The in-service plant costs, including the financing costs during construction, are recovered from customers through a MERP rider resulting in a lower recognition of AFDC.

FASB Interpretation No. 48 (FIN 48) In July 2006, the FASB issued FIN 48, “Accounting for Uncertainty in Income Taxes —an interpretation of FASB Statement No. 109”.  FIN 48 prescribes a comprehensive financial statement model of how a company should recognize, measure, present, and disclose uncertain tax positions that the 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 the effective date.  Initial derecognition amounts would be reported as a cumulative effect of a change in accounting principle.

FIN 48 is effective for fiscal years beginning after Dec. 15, 2006.  Xcel Energy is assessing the impact of the new guidance on all of its open tax positions.

Reclassifications Certain items in the statements of income, balance sheets and the statements of cash flows have been reclassified from prior-period presentation to conform to the 2006 presentation. These reclassifications had no effect on net income or earnings per share. The reclassifications were primarily related to the presentation of Quixx Corp. (Quixx), a former subsidiary of Xcel Energy’s non-regulated subsidiary, Utility Engineering (UE), that partners in cogeneration projects, as discontinued operations.

2. 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 on a net basis as discontinued operations. In addition, the assets and liabilities of the businesses divested and held for sale in 2006 and 2005 have been reclassified to assets and liabilities held for sale in the accompanying Consolidated Balance Sheets.

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. Amounts previously reported for 2005 have been restated to conform to the 2006 discontinued operations presentation.

Regulated Utility Segments

During 2004, Xcel Energy reached an agreement to sell its regulated electric and natural gas subsidiary, Cheyenne Light Fuel and Power Company (CLF&P). The sale was completed on Jan. 21, 2005.

Nonregulated Subsidiaries — All Other Segment

Utility Engineering In March 2005, Xcel Energy agreed to sell UE to Zachry Group, Inc. (Zachry). In April 2005, Zachry acquired all of the outstanding shares of UE. Xcel Energy recorded an insignificant loss in the first quarter of 2005 as a result of the transaction. In August 2005, Xcel Energy’s board of directors approved management’s plan to pursue the sale of Quixx, which was not included in the sale of UE to Zachry.

Seren On Sept. 27, 2004, Xcel Energy’s board of directors approved management’s plan to pursue the sale of Seren Innovations, Inc., a wholly owned broadband subsidiary.  On May 25, 2005, Xcel Energy reached an agreement to sell Seren’s California assets to WaveDivision Holdings, LLC, which was completed in November 2005. In July 2005, Xcel Energy reached an agreement to sell Seren’s Minnesota assets to Charter Communications, which was completed in January 2006.

NRG In December 2003, Xcel Energy divested its ownership interest in NRG Energy Inc. (NRG), a former independent power production subsidiary that had filed for bankruptcy protection in May 2003. Cash flows from receipt of NRG-related deferred income tax benefits occurred in 2004 and 2005. Approximately $385 million of remaining deferred tax benefits related to NRG are classified as a component of discontinued operations assets listed below.

9




Summarized Financial Results of Discontinued Operations

 

(Thousands of dollars)

 

Utility Segments

 

All Other

 

Total

 

 

 

 

 

 

 

 

 

Three months ended June 30, 2006

 

 

 

 

 

 

 

Operating revenue

 

$

 

$

2,009

 

$

2,009

 

Operating expenses and other income

 

(30

)

1,533

 

1,503

 

Pretax income from operations of discontinued components

 

30

 

476

 

506

 

Income tax expense

 

15

 

152

 

167

 

Net income from discontinued operations

 

$

15

 

$

324

 

$

339

 

 

 

 

 

 

 

 

 

Three months ended June 30, 2005

 

 

 

 

 

 

 

Operating revenue and equity in project income

 

$

 

$

7,379

 

$

7,379

 

Operating expenses and other income

 

 

(1,642

)

(1,642

)

Pretax income from operations of discontinued components

 

 

9,021

 

9,021

 

Income tax expense

 

 

3,291

 

3,291

 

Net income from operations of discontinued components

 

$

 

$

5,730

 

$

5,730

 

 

 

(Thousands of dollars)

 

Utility Segments

 

All Other

 

Total

 

 

 

 

 

 

 

 

 

Six months ended June 30, 2006

 

 

 

 

 

 

 

Operating revenue

 

$

 

$

4,838

 

$

4,838

 

Operating expenses and other income

 

(18

)

6,165

 

6,147

 

Pretax income (loss) from operations of discontinued components

 

18

 

(1,327

)

(1,309

)

Income tax benefit

 

(1,165

)

(1,969

)

(3,134

)

Net income from discontinued operations

 

$

1,183

 

$

642

 

$

1,825

 

 

 

 

 

 

 

 

 

Six months ended June 30, 2005

 

 

 

 

 

 

 

Operating revenue and equity in project income

 

$

6,579

 

$

32,065

 

$

38,644

 

Operating expenses and other income

 

6,131

 

28,122

 

34,253

 

Pretax income from operations of discontinued components

 

448

 

3,943

 

4,391

 

Income tax expense

 

268

 

1,378

 

1,646

 

Net income from operations of discontinued components

 

$

180

 

$

2,565

 

$

2,745

 

 

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

(Thousands of dollars)

 

June 30, 2006

 

Dec. 31, 2005

 

 

 

 

 

 

 

Cash

 

$

23,191

 

$

12,658

 

Trade receivables — net

 

2,388

 

6,101

 

Deferred income tax benefits

 

200,674

 

157,812

 

Other current assets

 

25,573

 

24,240

 

Current assets held for sale and related to discontinued operations

 

$

251,826

 

$

200,811

 

Property, plant and equipment — net

 

$

2,988

 

$

29,845

 

Deferred income tax benefits

 

200,138

 

352,171

 

Other noncurrent assets

 

9,954

 

19,269

 

Noncurrent assets held for sale and related to discontinued operations

 

$

213,080

 

$

401,285

 

Accounts payable — trade

 

$

4,025

 

$

7,657

 

Other current liabilities

 

31,141

 

36,000

 

Current liabilities held for sale and related to discontinued operations

 

$

35,166

 

$

43,657

 

Other noncurrent liabilities

 

$

4,852

 

$

6,936

 

Noncurrent liabilities held for sale and related to discontinued operations

 

$

4,852

 

$

6,936

 

 

10




3.     Tax Matters — Corporate-Owned Life Insurance

Interest Expense Deductibility —  As previously disclosed, 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 policy loan interest expense that had accrued during tax years 1993 and 1994 on policy loans related to its company-owned life insurance (COLI) policies that insured certain lives of employees of Public Service Company of Colorado (PSCo).  These policies are owned and managed by PSR Investments, Inc. (PSRI), a wholly owned subsidiary of PSCo.

After Xcel Energy filed this suit, the IRS sent its two statutory notices of deficiency of tax, penalty and interest for taxable years 1995 through 1999.  Xcel Energy has filed U.S. Tax Court petitions challenging those notices.  Xcel Energy anticipates the dispute relating to its claimed interest expense deductions for tax years 1993 and later will be resolved in the refund suit that is pending in the Minnesota federal district court and the Tax Court petitions will be held in abeyance pending the outcome of the refund litigation.  Xcel Energy has also been notified by the IRS that a statutory notice of deficiency for tax years 2000 through 2003 will be issued in third quarter 2006.

On Oct. 12, 2005, the district court denied Xcel Energy’s motion for summary judgment on the grounds that there were disputed issues of material fact that required a trial for resolution.  At the same time, the district court denied the government’s motion for summary judgment that was based on its contention that PSCo had lacked an insurable interest in the lives of the employees insured under the COLI policies.  However, the district court granted Xcel Energy’s motion for partial summary judgment on the grounds that PSCo did have the requisite insurable interest.

On May 5, 2006, Xcel Energy filed a second motion for summary judgment. Oral arguments are scheduled to be presented on Aug. 8, 2006. If this motion is denied, the district court has ordered the parties to be ready for trial by Jan. 2, 2007.

Xcel Energy believes that the tax deduction for interest expense on the COLI policy loans is in full compliance with the tax law. Accordingly, PSRI has not recorded any provision for income tax or related interest or penalties that may be imposed by the IRS, and has continued to take deductions for interest expense related to policy loans on its income tax returns for subsequent years.  As discussed above, the litigation could require several years to reach final resolution.  Defense of Xcel Energy’s position may require significant cash outlays, which may or may not be recoverable in a court proceeding.  Although the ultimate resolution of this matter is uncertain, it could have a material adverse effect on Xcel Energy’s financial position, results of operations and cash flows.

Should the IRS ultimately prevail on this issue, tax and interest payable through Dec. 31, 2006, would reduce retained earnings by an estimated $419 million.  In 2004, Xcel Energy received formal notification that the IRS will seek penalties. If penalties (plus associated interest) also are included, the total exposure through Dec. 31, 2006, is approximately $497 million.  Xcel Energy annual earnings for 2006 would be reduced by approximately $44 million, after tax, or 10 cents per share, if COLI interest expense deductions were no longer available.

4. Rates and Regulation

Midwest Independent Transmission System Operator, Inc. (MISO) Operations — Two of Xcel Energy’s regulated utility subsidiaries, Northern States Power Company, a Minnesota corporation (NSP-Minnesota), and Northern States Power Company, a Wisconsin corporation (NSP-Wisconsin), are members of the MISO. The MISO is a regional transmission organization (RTO) that provides transmission tariff administration services for electric transmission systems, including those of NSP-Minnesota and NSP-Wisconsin. In 2002, NSP-Minnesota and NSP-Wisconsin received all required regulatory approvals to transfer functional control of their high voltage (100 kilovolts and greater) transmission systems to the MISO. The MISO exercises functional control over the operations of these facilities and the facilities of certain neighboring electric utilities.  On April 1, 2005, MISO initiated a regional Day 2 wholesale energy market pursuant to its transmission and energy markets tariff.

MISO Cost Recovery

While the Day 2 market is designed to provide efficiencies through region-wide generation dispatch and increased reliability, there are costs associated with the Day 2 market. NSP-Minnesota and NSP-Wisconsin have attempted to address these costs with regulators in their respective jurisdictions as outlined below.

On Feb. 24, 2006, the MPUC ordered jurisdictional investor-owned utilities in the state, including NSP-Minnesota, to participate with the Minnesota Department of Commerce and other parties in a proceeding to evaluate suitability of recovery of some of the MISO Day 2 energy market costs in the variable fuel cost adjustment (FCA). The Minnesota utilities and other parties filed a joint report with the MPUC on June 22, 2006 recommending pass-through of MISO energy market costs in the FCA, with the exception of two components which would be included in base retail electric rates in a future rate case upon a showing of MISO regional market benefits.  The two components are MISO Schedule 16, which recoups MISO costs for administration of financial transmission rights (FTRs); and Schedule 17, which recoups the cost of MISO’s market computer systems and staff.  The MPUC has requested written comments on the joint report, and action by the MPUC in response to the recommendations in this report is anticipated sometime later in 2006.  An adverse MPUC

11




ruling on cost recovery of MISO Day 2 market costs could have a material financial impact on NSP-Minnesota.

On June 16, 2006, the Public Service Commission of Wisconsin (PSCW) issued its written order regarding the joint request for escrow accounting treatment of MISO Day 2 costs made by NSP-Wisconsin and other Wisconsin utilities.  The order confirms continued deferred accounting treatment for congestion costs, net line losses, and costs of acquiring FTRs not received in the MISO allocation process, as previously authorized by the PSCW.  The order also clarifies that deferral is authorized for several additional MISO Day 2 cost and revenue types not explicitly addressed in the original PSCW order issued March 29, 2005.  While deferral for most of the additional cost and revenue types was granted retroactive to April 1, 2005, a few types are deferrable beginning June 8, 2006.  To date, NSP-Wisconsin has deferred a total of approximately $6.2 million of MISO Day 2 costs.

Revenue Sufficiency Guarantee Charges

On April 25, 2006, the Federal Energy Regulatory Commission (FERC) issued an order determining that MISO had incorrectly applied its energy markets tariff 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 certain MISO customers and paid to others.  Based on the FERC order, Xcel Energy could be required to make net payments to MISO.  The FERC granted a rehearing on the issue for purposes of further consideration on June 23, 2006, and is expected to issue a final order later in 2006.  Xcel Energy has reserved $5.7 million in the event the FERC order is upheld on rehearing and appeal.

Joint and Common Wholesale Energy Market

On March 16, 2006, the FERC dismissed complaints filed by Wisconsin Public Service Corp. et al. (WPS) asking the FERC to order MISO and the PJM Interconnection, Inc. (PJM) to establish a joint and common wholesale energy market (JCM) for the two neighboring RTOs. Xcel Energy opposed the WPS complaints, arguing that MISO and PJM are completing projects shown to be cost beneficial to market participants, and a full JCM could substantially increase market operations costs with limited benefits in terms of energy savings. In dismissing the complaints, the FERC ruled the progress by MISO and PJM toward the JCM was satisfactory.

Ancillary Service Markets

MISO and its stakeholders are developing proposals to establish ancillary service markets within its footprint. The proposals would increase market efficiency by providing a reduced allocation of generation contingency reserves for market participants and by creating economic market opportunities to obtain alternative sources of generating reserves. The proposed implementation of these market design improvements is scheduled for phase-in over the course of 2007, subject to project actions by MISO. NSP-Minnesota signed a memoranda of understanding with MISO that permit NSP-Minnesota to participate in the development of agreements relating to regional generation reserve sharing.  The MISO generation reserve sharing pool agreement was executed by numerous parties on July 31, 2006; however, the agreement provides an “opt out” in the event participation is lower than anticipated.  Final participation will be determined by Aug. 4, 2006.  NSP-Minnesota and NSP-Wisconsin will participate through a collective of participants in the existing Mid-Continent Area Power Pool generation reserve sharing agreement, which would be replaced by the MISO arrangement for contingency reserves.

FERC Transmission Rate Case (PSCo and SPS ) On Sept. 2, 2004, Xcel Energy filed on behalf of PSCo and Southwestern Public Service Company (SPS) an application to increase wholesale transmission service and ancillary service rates within the Xcel Energy joint open access transmission tariff. PSCo and SPS requested an increase in annual transmission service and ancillary services revenues of $6.1 million. On Feb. 6, 2006, the parties in the proceeding submitted an uncontested offer of settlement that contains a $1.6 million rate increase for PSCo, a formula transmission service rate for PSCo, a 10.5 percent rate of return on common equity, and the phased inclusion of PSCo’s 345 kilovolt tie line costs in wholesale transmission service rates;  the settlement results in a $1.1 million stated rate increase for SPS effective June 2005, and SPS can file a further rate increase effective Oct. 1, 2006. On April 5, 2006, the FERC issued an order approving the uncontested settlement. PSCo placed the final rates in effect on June 1, 2005 and issued refunds of approximately $3.7 million.

Most transmission service users of the SPS system take service under the Southwest Power Pool (SPP) regional open access transmission tariff.  On May 6, 2006, SPP submitted a compliance filing to the April 5, 2006, FERC order to include the SPS settlement rates in the SPP tariff effective retroactive to June 1, 2005.  Certain customer parties protested the SPP filing as inconsistent with the Feb. 6, 2006 settlement.  SPP and SPS filed answers responding to the protests.   Final FERC action is pending.

Other Regulatory Matters — NSP-Minnesota

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, 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. In March 2006, the MPUC approved a new depreciation order, which lowered decommissioning accruals for 2006 from anticipated levels.  Due to the seasonality of sales,

12




the rate increase will not be recognized ratably throughout 2006.

On April 13, 2006, intervenors filed testimony regarding the Minnesota electric rate case. In its testimony, the Minnesota Department of Commerce proposed an increase in annual revenues of approximately $90 million, a return on equity of 10.64 percent and a proposed equity ratio of 51.37 percent, resulting in an overall return on rate base of 8.81 percent. The primary adjustments related to return on equity, nuclear decommissioning expense, ratemaking treatment of wholesale margins, adjustments to fuel expense and an increase in sales volumes. On the latter two issues the Department of Commerce indicated that the recommendations might change if NSP-Minnesota is able to supply additional information in its rebuttal testimony. The nuclear decommissioning recovery was reduced by $10.2 million and $21.1 million for the second quarter and first six months of 2006, respectively. The annual recovery decreased from $80.8 million to $42.5 million. The decrease was attributed to a change in cost estimate and recovery parameters.

The Office of Attorney General also filed testimony. It proposed two adjustments related to income taxes and wholesale margins that would result in a decrease in 2006 annual revenues of approximately $20 million. On March 30, 2006, NSP-Minnesota filed rebuttal testimony reducing the requested rate increase to $156 million. Evidentiary hearings concluded on April 27, 2006.

On April 24, 2006, NSP-Minnesota reached a settlement agreement regarding the treatment of wholesale electric sales margins. The settlement is with five intervenor groups, including the Office of Attorney General and a large industrial customer group.

The settlement resolves recommendations of most parties regarding the treatment of wholesale electric sales margins. Significant components of the settlement agreement are as follows:

·                  No credit to base electric rates for wholesale electric sales margins;

·                  Wholesale electric sales margins derived from excess generation capacity will be flowed through the FCA as an offset to fuel and energy costs;

·                  80 percent of wholesale margins derived from the sales from NSP-Minnesota’s ancillary services obligations (e.g. spinning reserves) will be flowed through the FCA as an offset to fuel and energy costs and NSP-Minnesota will retain 20 percent; and

·                  25 percent of proprietary margins, sales that do not arise from the use of NSP-Minnesota generating assets, will be flowed through the FCA as an offset to fuel and energy costs, and 75 percent will be retained by NSP-Minnesota.

The settlement agreement is pending approval by the MPUC and will be considered in the MPUC’s determination of NSP-Minnesota’s overall requested increase.

On July 6, 2006, the administrative law judge (ALJ) recommended an overall increase in revenues for the 2006 test year of approximately $135 million.  For 2007, the ALJ recommended the increase be revised downward to $119 million to reflect the increased revenues expected due to the return of Flint Hills, an oil refinery, as a full-requirements customer.  The MPUC is expected to hold oral arguments in August and issue its final order in September 2006.

Excelsior Energy In December 2005, Excelsior Energy Inc., an independent energy developer, filed for approval of a proposed power purchase agreement with NSP-Minnesota for its proposed integrated gas combined cycle (IGCC) plant to be located in northern Minnesota.  Excelsior Energy filed this petition pursuant to Minnesota law, which provides certain considerations for a qualifying Innovative Energy Project, subject to MPUC public interest determinations. Excelsior Energy asked the MPUC to open a contested case proceeding to:

·                  Approve, disapprove, amend, or modify the terms and conditions of Excelsior Energy’s proposed power purchase agreement;

·                  Determine that Excelsior Energy’s coal-fueled IGCC plant is, or is likely to be, a least-cost resource, obligating NSP-Minnesota to use the plant’s generation for at least 2 percent of the energy supplied to its retail customers; and

·                  Determine that at least 13 percent of the energy supplied to NSP-Minnesota retail customers should come from the IGCC plant by 2013.

The MPUC referred this matter to a contested case hearing to develop the facts and issues that must be resolved to act on Excelsior’s petition, including development of as much contract price information as possible. The contested case proceeding is scheduled to consider a 603 megawatt unit in phase I of the proceedings, which are currently underway, and consider a second 603 megawatt unit in phase II of the proceedings, which are scheduled to begin in 2007. A report from the ALJs on phase I is expected in early 2007 and a report from the ALJs on phase II is expected in summer 2007. NSP-Minnesota anticipates opposing or seeking significant modification on Excelsior Energy’s petition and power purchase agreement. NSP-Minnesota will request that all costs associated with the proposed power purchase agreement, if approved, will be recoverable in customer rates.

NSP 2004 Resource Plan On Nov. 1, 2004, NSP-Minnesota filed its proposed resource plan for the period 2005 through 2019.  The proposed plan identified needed resources and proposed processes for acquiring resources to meet those needs, which included the need for base load capacity beginning 2013.  A series of comments and replies occurred on both the proposed plan and the proposed resource acquisition processes.  On July 28, 2006, the MPUC issued an order that, among other things:

·                  Approves NSP-Minnesota’s proposal to proceed with a request for proposal for 136 megawatts of peaking resources with an intended in service date of 2011;

·                  Identifies a base load resource need of 375 megawatts beginning in 2015 and requires NSP-Minnesota to file a certificate of need application for a proposed base load resource to begin the acquisition process by Nov. 1, 2006;

13




·                  Requires NSP-Minnesota to file for any mandatory MPUC review or approvals of proposed upgrades to existing base load and nuclear power plants (Sherco, Prairie Island, and Monticello) by Dec. 31, 2006;

·                  Approves an acquisition of 1,680 megawatts of wind generation resource over the planning period; and

·                  Accepts the proposed increases in demand-side management and energy-savings goals.

Other Regulatory Matters — NSP-Wisconsin

2006 Fuel Cost Recovery NSP-Wisconsin’s electric fuel costs for March 2006 were approximately $2.1 million, or 20 percent, lower than authorized in the 2006 Wisconsin electric rate case and outside the established fuel monitoring range under the Wisconsin fuel rules.  Year-to-date fuel costs through March were approximately $1.9 million, or 6 percent, lower than authorized, resulting in an over recovery of $1.9 million.  On May 4, 2006, the PSCW opened a proceeding to determine if a rate reduction (fuel credit factor) should be implemented, and made new rates reflecting the lower fuel costs effective May 4, 2006, subject to refund pending a full review of 2006 fuel costs.

In late May 2006, NSP-Wisconsin provided the PSCW with an updated forecast of fuel costs for the remainder of 2006 showing NSP-Wisconsin’s fuel costs will be within the authorized range by year-end, and no rate reduction is warranted.  The PSCW’s investigation is ongoing.

Fuel costs for the Wisconsin retail jurisdiction through June 2006 were $0.8 million, or 1.0 percent lower than authorized in the 2006 rate case.  However, NSP-Wisconsin’s forecast continues to show that by year-end, fuel costs will be within the authorized range.  NSP-Wisconsin anticipates the PSCW will complete their investigation and issue an order later this year.

Wholesale Rate Case Application On July 31, 2006, NSP-Wisconsin filed a Section 205 rate case at the FERC requesting a base rate increase of approximately $4 million, or 15 percent, for its ten wholesale municipal electric sales customers.  The last rate increase for these customers was in 1993. NSP-Wisconsin’s wholesale customers are currently served under a bundled full requirements tariff, with rates based on embedded costs, and a monthly FCA.  NSP-Wisconsin proposes to unbundle transmission service and revise the fuel costs adjustment clause (FCAC) to reflect current FERC regulatory policies, the advent of MISO operations and the Day 2 energy market.

Other Regulatory Matters — PSCo

PSCo Electric Rate Case —  On April 14, 2006, PSCo filed with the Colorado Public Utilities Commission (CPUC) to increase electricity rates by $210 million annually, beginning Jan. 1, 2007. The request is based on a return on equity of 11 percent, an equity ratio of 59.9 percent and an electric rate base of $3.4 billion.  No interim rate increase has been implemented.  A decision is expected by the end of 2006. The expected procedural schedule is listed below.

·

 

Intervenor Testimony

 

Aug. 18, 2006

·

 

Rebuttal Testimony

 

Sept. 29, 2006

·

 

Hearings

 

Oct. 23, 2006 through Nov. 9, 2006

·

 

Statement of Position

 

Nov. 20, 2006

·

 

Deliberations

 

Dec. 1, 2006

·

 

Initial Decision

 

Dec. 18, 2006

 

PSCo 2003 Resource Plan — On June 2, 2006, PSCo filed a motion with the CPUC requesting permission to withdraw an earlier application it made, which requested CPUC approval to shorten the ten-year resource acquisition period of its 2003 resource plan by one year resulting in a nine year acquisition period (2004-2012). PSCo’s original application also sought to reject all bids offering  power supplies starting in 2013 that it received in response to its Feb. 24, 2005 all-source solicitation.  On  June 7, 2006, the CPUC approved PSCo’s motion and directed PSCo to complete the evaluation of bids and negotiation of contracts offering new power supplies starting in year 2013 by Dec. 15, 2006.

PSCo Renewable Portfolio Standards In November 2004, an amendment to the Colorado statutes was passed by referendum requiring implementation of a renewable energy portfolio standard for electric service. The law requires PSCo to generate, or cause to be generated, a certain level of electricity from eligible renewable resources. During 2006, the CPUC determined that compliance with the renewable energy portfolio standard should be measured through the acquisition of renewable energy credits either with or without the accompanying renewable energy; that the utility purchaser owns the renewable energy credits associated with existing contracts where the power purchase agreement is silent on the issue; that Colorado utilities should be required to file implementation plans and the methods utilities should use for determining the budget available for renewable resources.  In April 2006, the CPUC issued rules that establish the process utilities are to follow in implementing the renewable energy portfolio standard.  PSCo is scheduled to file its first annual compliance plan under these rules by Aug. 31, 2006.

On Dec. 1, 2005, PSCo filed with the CPUC to implement a new rate rider that would apply to each customer’s total electric bill,

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providing approximately $22 million in annual revenue (1.0 percent of total retail revenue). The revenues collected under the rider will be used to acquire sufficient solar generation resources to meet the requirements of the Colorado renewable energy portfolio standard. On Feb. 14, 2006, PSCo and the other parties to the case filed a stipulation agreeing to reduce the rider to 0.60 percent. The CPUC approved the stipulation on February 22, 2006. The rider became effective March 1, 2006.  PSCo’s compliance plan will address whether modification to the level of this rider is necessary to meet the requirements of the renewable energy portfolio standard.

PSCo Quality of Service Plan PSCo was required to make a filing regarding the future of its quality of service plan (QSP), which expires at the end of 2006. In the initial filing, PSCo proposed a service quality monitoring and reporting plan. After reviewing the responses of the CPUC staff and other intervenors, PSCo negotiated a new QSP that will extend through calendar year 2010. The plan establishes performance measures and provides for associated bill credits for failure to achieve regional electric distribution system reliability, electric service continuity and restoration thresholds, customer complaints and telephone response times. If the performance thresholds are not met, the annual bill credit exposures are approximately $7 million for regional reliability and $1 million each for the continuity, reliability, customer complaints and telephone response time thresholds. Each of PSCo’s nine operating regions has its own calculated reliability metric and the bill credits would be apportioned among the regions. PSCo would have to fail the operating threshold two years in a row before paying reliability bill credits. The bill credit levels would not escalate. If the credits are required to be paid, the stated amounts would be grossed up for taxes. The proposed plan is pending CPUC approval.

Controlled Outage Investigation On July 7, 2006, the CPUC discussed a CPUC staff report regarding its investigation of the controlled outages of Feb. 18, 2006, which affected an estimated 323,000 customers in Colorado for approximately 30 minutes.  The investigation reviewed natural gas supply issues, the causes of unplanned outages on several PSCo-owned and independent power generation facilities, transmission availability, customer interruption procedures, emergency preparedness and internal and external communications.  The CPUC report made over 90 recommendations and directed PSCo to respond within two weeks with its plans to implement certain procedures to address curtailment situations if they arise this summer.  In addition, the CPUC directed PSCo to respond to various other recommendations by the middle of August.  The CPUC’s recommendations are directed at ensuring that there is an appropriate level of situational awareness between the operational status of the interdependent gas and electric supply systems so that adequate pipeline delivery pressures are available during critical peak periods.

Other Regulatory Matters — SPS

SPS 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 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 using the FCAC provisions 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 FCAC recovery to reflect fuel costs recovered from certain wholesale sales to other utilities, and that SPS had inappropriately allocated average fuel and purchased power costs to other of SPS’ wholesale customers, effectively raising the fuel costs charges to complainants. Cap Rock Energy Corporation (Cap Rock), another 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. Hearings on the complaint were held in February and March 2006.

On May 24, 2006, a FERC 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.  FERC’s order may or may not follow any of the ALJ’s recommendation.

In the recommended decision, the ALJ resolved a number of disputed cost of service issues and ordered a compliance filing to determine the extent to which base revenues recovered under currently effective rates for the period beginning Jan. 1, 2005, through June 11, 2006 should be refunded to wholesale customers. The ALJ also found that SPS should recalculate its 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 at market-based rates during this period based on the view that such sales should be treated as opportunity sales.

SPS believes the ALJ has 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 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.  The ALJ failed to acknowledge either factor.

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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 rules of law and FERC 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.

Based on FERC’s regulations and rules of law, SPS has evaluated all sales made from Jan. 1, 1999, to Dec. 31, 2005.  Notwithstanding that, SPS believes it should ultimately prevail in this proceeding.  SPS has accrued approximately $7 million, of which $4 million was recorded in the second quarter of 2006, related to both the base-rate and fuel items.  However, if the FERC were to adopt the majority of the ALJ’s recommendations, SPS’ refund exposure could be approximately $50 million.

On Sept. 15, 2005, PNM filed a separate complaint at the FERC in which it contended that its demand charge under an existing interruptible power supply contract with SPS is excessive and that SPS has overcharged PNM for fuel costs under three separate agreements through erroneous FCAC calculations.  PNM’s arguments mirror those that it made as an intervenor in the cooperatives’ complaint case, and SPS believes that they have little merit.  SPS submitted a response to PNM’s complaint in October 2005.  In November 2005, the FERC accepted PNM’s complaint.  In July 2006, SPS and PNM reached a settlement in principle.  A final settlement agreement will be filed for FERC approval.  Hearings scheduled for December 2006 will be held in abeyance. Based on the fact that many of these issues are already being reviewed by the FERC in the complaint case filed by the cooperatives discussed above, the current status and expected outcome of this proceeding, SPS does not anticipate any additional liability.

SPS  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 set the $2.5 million power rate increase to become effective on July 1, 2006, subject to refund. The FERC also set the rate increase request for hearing and settlement judge procedures. The case is presently in the settlement judge procedures and an agreement in principle has been reached for base rates for the full-requirements customers and PNM; other wholesale customers have not settled, however.  The revised base rates were placed in effect July 1, 2006, subject to refund.

SPP Energy Imbalance Service On June 15, 2005, SPP, of which SPS is a member, filed proposed tariff provisions to establish an Energy Imbalance Service (EIS) wholesale energy market for the SPP region, using a phased approach toward the development of a fully-functional locational marginal pricing energy market with appropriate FTRs, to be effective March 1, 2006. On Sept. 19, 2005, the FERC issued an order rejecting the SPP EIS proposal and providing guidance and recommendations to SPP; however, the FERC did not require SPP to implement a full Day 2 market similar to MISO. On Jan. 4, 2006, SPP submitted proposed tariff revisions  to implement an EIS market and establish a market monitoring and market power mitigation plan. On March 20, 2006, the FERC issued an order conditionally accepting the proposed market, suspending the implementation until Oct. 1, 2006.  The FERC found the proposal lacking, particularly with respect to the hiring of an external market monitor, the loss compensation mechanisms and the lack of several standard forms for service.  The FERC directed SPP to implement safeguards for the first six months of the imbalance markets including a two tier cap, a market readiness certification and price correction authority. SPP and market participants engaged in a series of technical conferences in order to comply with the FERC’s order.  On May 19, 2006, SPP filed proposed tariff revisions pursuant to the FERC’s January 4th Order.  Several parties filed comments and protests to the SPP compliance filing, including SPS.  SPP filed an answer to the protests.  On July 20, 2006, the FERC accepted in part, and rejected in part, SPP’s proposed market provisions, to become effective on Oct. 1, 2006.  On July 25, 2006, SPP changed the implementation date to Nov. 1, 2006. SPS has not yet requested New Mexico Public Regulation Commission (NMPRC) or Public Utility Commission of Texas (PUCT) approval regarding accounting and ratemaking treatment of EIS costs.

Texas Energy Legislation The 2005 Texas Legislature passed a law, effective June 18, 2005, establishing statutory authority for electric utilities outside of the Electric Reliability Council of Texas in the SPP or the Western Electricity Coordinating Council to have timely recovery of transmission infrastructure investments. After notice and hearing, the PUCT may allow recovery on an annual basis of the reasonable and necessary expenditures for transmission infrastructure improvement costs and changes in wholesale transmission charges under a tariff approved by the FERC. The PUCT will initiate a rulemaking for this process that is expected to take place in the second half of 2006.

Fuel Cost Recovery Mechanisms Fuel and purchased energy costs are recovered in Texas through a fixed-fuel and purchased energy recovery factor, which is part of SPS’ retail electric rates.  The Texas retail fuel factors change each November and May based on the projected cost of natural gas.  If it appears SPS will materially over-recover or under-recover these costs, the factor may be revised based on application by SPS or action by the PUCT.  In the first quarter of 2006, SPS revised its estimate of the allocation of fuel under-recoveries to its Texas jurisdiction for 2004 and 2005 and recorded an asset of approximately $7 million.  In the second quarter of 2006, SPS finalized its fuel analysis based on a distribution system loss approach.  Pursuant to this analysis, the total unrecovered fuel balance is $21.7 million.  Because of uncertainty regarding ultimate recovery, a settlement reserve was recorded equal to the entire amount.  SPS filed a fuel reconciliation application in May 2006.  See discussion below.

SPS Texas Retail Fuel Factor Change On March 7, 2006, SPS filed an application to change its fuel factors

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effective May 1, 2006, to more accurately track fuel cost during the summer months.  On April 17, 2006, the proposed factors were approved on an interim basis, and on May 25, 2006, the factors were granted final approval.

SPS Texas Retail Fuel Surcharge Case On May 5, 2006, SPS requested authority to surcharge approximately $43.9 million of Texas retail fuel and purchased energy cost under-collection that accrued from October 2005 through March 2006.  The case has been referred to the State Office Of Administrative Hearing (SOAH) for a contested hearing.  Intervenors have requested that this case be consolidated with SPS’ pending fuel reconciliation case discussed below, since findings in the fuel reconciliation case could reduce the amount of the under-collection. At a pre-hearing conference on June 26, 2006, the ALJ denied the motion to consolidate and set the case for hearing on its merits on Aug. 14, 2006.

SPS 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, or 6.0 percent.  The rate filing is based on a historical test year, an electric rate base of $943 million, a requested return on equity of 11.6 percent and a common equity ratio of 51.1 percent.  Final rates are expected to be effective in the first quarter of 2007.  No interim rate increase has been implemented.  Following is the expected procedural schedule.

·

 

Intervenor Testimony

 

Oct. 24 & 31, 2006

·

 

PUCT Staff Testimony

 

Nov. 7, 2006

·

 

Hearings

 

Nov. 28 - Dec. 21, 2006

·

 

Proposal for Decision

 

To be determined

·

 

Agreed Jurisdictional Deadline

 

March 2, 2007

 

The fuel reconciliation portion requests approval of approximately $957 million of Texas jurisdictional fuel and purchased power costs for the 2004 through 2005 period. The fuel reconciliation case was transferred to the SOAH with the base rate case and has the same procedural schedule.  As a part of the fuel reconciliation case, fuel and purchased energy costs, which are recovered in Texas through a fixed-fuel and purchased energy recovery factor as a part of SPS’ retail electric rates, will be reviewed.

New Mexico Fuel Review On Jan. 28, 2005, the NMPRC accepted the staff petition for a review of SPS’ fuel and purchased power cost. The staff requested a formal review of SPS’ fuel and purchased power cost adjustment clause (FPPCAC) for the period of Oct. 1, 2001 through August 2004. The hearing in the fuel review case was held April 22, 2006. A proposed recommended decision was filed by the parties on July 28, 2006, and a NMPRC decision is expected in late 2006.

New Mexico Fuel Factor Continuation Filing On Aug. 18, 2005, SPS filed with the NMPRC requesting continuation of the use of SPS’ FPPCAC and current monthly factor cost recovery methodology.  This filing was required by NMPRC rule.  Testimony has been 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 ineligible 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 have requested disallowances for past periods, which in the aggregate total approximately $45 million.  Other issues in the case include the treatment of renewable energy certificates and sulfur dioxide allowance credit proceeds in relation to SPS’ New Mexico retail fuel and purchased power recovery clause.  The hearing was held in April 2006, and a NMPRC decision is expected in late 2006.

5. Commitments and Contingent Liabilities

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 is pursuing or intends to pursue insurance claims and believes it will recover some portion of these costs through such 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 for such unrecoverable amounts in its consolidated financial statements.

Ashland Manufactured Gas Plant Site—NSP-Wisconsin was named a potentially responsible party (PRP) for creosote and coal tar contamination at a site in Ashland, Wis. The Ashland site includes property owned by NSP-Wisconsin, which was previously a manufactured gas plant (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. The U.S. Environmental Protection Agency (EPA) and Wisconsin Department of Natural Resources (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 $25.3 million for its potential liability for remediating the Ashland site.  Since NSP-Wisconsin cannot currently estimate the cost of remediating the Ashland site, the recorded liability is based upon the minimum of the estimated range of remediation costs, using information available to date and reasonably effective remedial methods.  Of the total accrued, NSP-Wisconsin recorded an additional $5.7 million in the second quarter 2006 to reflect estimated legal defense and additional work plan costs.

Regional Haze Rules The EPA requires states to develop implementation plans to comply with regional haze rules that require emission controls, known as best available retrofit technology (BART), by December 2007. States are required to identify the facilities that will have to reduce emissions under BART and then set BART emissions limits for those facilities. Colorado is the first state in Xcel Energy’s region to begin its BART rule development as the first step toward the December 2007 deadline. Xcel Energy is actively involved in the stakeholder process in Colorado and will also be involved as other states in its service territory begin their process. 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 Colorado Air Pollution Control Division.  As set forth in its analysis, PSCo estimates that implementation of the BART alternatives will cost approximately $165 million in capital costs, which includes approximately $62 million in environmental upgrades for the existing Comanche Station project.  Xcel Energy believes the cost of any required capital investment will be recoverable from customers.  Emissions controls will be installed between 2010 and 2012 and must be operational by 2013.

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Minnesota has begun implementing its BART strategy as the first step toward the December 2007 deadline. By Sept. 10, 2006, each BART-eligible source in Minnesota must perform and submit an analysis of the need for additional emission controls for sulfur dioxide (SO2) and/or nitrous oxide (NOx). The Sherburne County generating plant is the only NSP-Minnesota facility that is required to perform such an analysis and may eventually be required to install additional emission controls.

Clean Air Interstate Rule —  In March 2005, the EPA issued the Clean Air Interstate Rule (CAIR), which further regulates SO2 and NOx emissions.  Under CAIR’s cap-and-trade structure, utilities can comply through capital investments in emission controls or purchase of emission “allowances” from other utilities making reductions on their systems.  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 predict the ultimate amount and timing of capital expenditures and operating expenses.

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 National Ambient Air Quality Standard in any downwind jurisdiction. 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 CAIR. El Paso Electric Co. joined in the request for reconsideration. 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 United States Court of Appeals for the District of Columbia Circuit.

Based on the preliminary analysis of various scenarios of capital investment and allowance purchases, Xcel Energy currently believes the preferred scenario for SPS will be capital investments of approximately $30 million for NOx controls with NOx allowance purchases of an estimated $4 million in 2009.  Annual purchases of SO2 allowances are estimated in the range of $15 million to $25 million each year, beginning in 2012 for Phase I based on allowance costs and fuel quality as of July 2006.

On June 13, 2006, the Minnesota Pollution Control Agency (MPCA) issued a draft rule for implementing the CAIR in Minnesota, which further regulates SO2 and NOx emissions.  This proposal would require more stringent emission reductions than the federal CAIR program, resulting in additional implementation costs.  A stakeholder process is ongoing, and a proposed rule is expected in September 2006.

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.

Polychlorinated Biphenyl (PCB) Storage and Disposal In August 2004, Xcel Energy received notice from the EPA contending SPS violated PCB storage and disposal regulations with respect to storage of a drained transformer and related solids. The EPA contended the fine for the alleged violation was approximately $1.2 million. Xcel Energy contested the fine and submitted a voluntary disclosure to the EPA. On April 17, 2006, SPS received a notice of determination from the EPA stating that the voluntary disclosure had been reviewed and that SPS had met all conditions of the EPA’s audit policy. Accordingly, the EPA will mitigate 100 percent of the gravity-based penalty for the disclosed violation, and no economic penalty will be assessed.

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. Xcel Energy continues to evaluate the strategy for complying with CAMR.  Compliance may be achieved by either adding mercury controls or purchasing allowances or a combination of both.  The capital cost is estimated at $29.3 million for the mercury control equipment. Colorado is required to submit a plan to EPA by Oct. 31, 2006 to limit mercury emissions from coal-fired electric utility steam generating units consistent with federal standards of performance.  On June 6, 2006, the Colorado Department of Public Health and Environment issued a draft rule for implementing CAMR in Colorado.  The proposed rule provides for fewer mercury allowances than the federal program, which may result in additional implementation costs.  A stakeholder process is ongoing, with a hearing before the Colorado Air Quality Control Commission currently scheduled for Nov. 16-17, 2006.

Minnesota Mercury Legislation — The Governor of Minnesota signed mercury reduction legislation in 2006.  This legislation requires the installation of mercury monitoring equipment by July 1, 2007; submittal of mercury emission reduction plans for dry scrubbed units by Dec. 31, 2007 and for wet scrubbed units by Dec. 31, 2009; and installation of mercury emission control equipment at NSP-Minnesota’s Allen S. King and Sherburne County (Sherco) generating facilities in Minnesota.  Mercury emission control equipment must be installed on unit 3 of Sherco and at Allen S. King by Dec. 31, 2009 and Dec. 31, 2010.  Sherco units 1 and 2 modifications are required by Dec. 31, 2014.  The cost of controls will be determined as part of the engineering analysis portion of the mercury reduction plans and is not currently estimable. The legislation includes full and timely cost recovery provisions for both the costs of complying with this statute and any federal and state environmental regulations effective after Dec. 31, 2004.

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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.

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 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 Multi-District Litigation (MDL) Panel to have the matter transferred to U.S. District Judge Pro and filed a second motion to dismiss the lawsuit.  In response to this motion, this matter has been  transferred to U.S. District Court Judge Pro.  Judge Pro granted the motions to dismiss and plaintiffs have appealed.  The 9th Circuit Court of Appeals has stayed this appeal until November 20, 2006, pending the court’s decision in the prior appeal filed in Abelman Art Glass vs. e prime et al.

J.P. Morgan Trust Company vs. e prime and Xcel Energy Inc. et al. — On Oct. 17, 2005, J.P. Morgan, 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 increase 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 this case to state court has been filed by plaintiffs and on March 2, 2006, Judge Pro granted plaintiffs’ motion for remand, but vacated this order on March 8, 2006, and will give the matter further consideration. This case is in the early stages, there has been no discovery, and e prime and Xcel Energy intend to vigorously defend themselves against these claims.

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 the 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 such 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 meaningful settlement negotiations in May 2006, and such negotiations are ongoing.  Trial remains set for August 2006, but is likely to be continued due to ongoing negotiations.  If settlement discussions are not productive, additional summary judgment motions are likely prior to trial.

Hoffman vs. Northern States Power Company — On March 15, 2006, a purported class action complaint was filed in Minnesota state district court, 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 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 has filed a motion for dismissal on the pleadings, scheduled to be heard on August 16, 2006.

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’ carbon dioxide 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 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.

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 of 1974 (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

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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 have 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 filed notice of intent to appeal to the U.S. Court of Appeals for the Eighth Circuit.

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 Colorado Air Pollution Control Division 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.  It is uncertain whether plaintiffs will appeal.

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 have filed a motion to remand the matter to state court.

NewMech vs. Northern States Power Company — On May 16, 2006, NewMech served and filed a complaint against NSP-Minnesota, Southern Minnesota Municipal Power Agency (SMMPA), and Benson Engineering in the Minnesota State District Court, Sherburne County, alleging entitlement to payment in the amount of approximately $4.2 million for unpaid costs allegedly associated with construction work done by NewMech at NSP-Minnesota and SMMPA’s jointly owned Sherco 3 generating plant in 2005.  NewMech had previously served a mechanic’s lien, and seeks, through this action, foreclosure of the lien and sale of the property.  NewMech additionally seeks the claimed damages as a result of an alleged breach of contract by NSP-Minnesota.  NSP-Minnesota, SMMPA and Benson have filed answers denying NewMech’s allegations.  Additionally, NSP-Minnesota and SMMPA have counterclaimed for damages in excess of $7 million for breach of contract, delay in contract performance, misrepresentation and fraudulent inducement to enter into the contract, and slander of title.

Department of Labor Audit — In 2001, Xcel Energy received notice from the U.S. Department of Labor (DOL) Employee Benefit Security Administration that it intended to audit the Xcel Energy pension plan. After multiple on-site meetings and interviews with Xcel Energy personnel, the DOL indicated on Sept. 18, 2003, that it is prepared to take the position that Xcel Energy, as plan sponsor and through its delegate, the Pension Trust Administration Committee, breached its fiduciary duties under ERISA with respect to certain investments made in limited partnerships and hedge funds in 1997 and 1998.  The DOL has offered to conclude the audit if Xcel Energy is willing to contribute to the plan the full amount of losses from the questioned investments, or approximately $7 million.  On July 19, 2004, Xcel Energy formally responded with a letter to the DOL that asserted no fiduciary violations have occurred and extended an offer to meet to discuss the matter further.  In 2005, and again in January 2006, the DOL submitted two additional requests for information related to the investigation, and Xcel Energy submitted timely responses to each request.

On June 12, 2006, the DOL issued a letter to the Xcel Energy Pension Trust Administration Committee indicating that, although there may have been a breach of the Committee’s fiduciary obligations under ERISA, the DOL will not pursue any action against the Committee or the pension plan with respect to these alleged breaches due, in part, to the steps the Committee has taken in outsourcing certain investment management and administration functions to third parties.

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 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 four other utility companies filed a motion to dismiss the lawsuit, contending, among other reasons, that the lawsuit is an attempt to usurp the policy-setting role of the U.S. Congress and the president.  On Sept. 19, 2005, the judge granted the defendants’ motion to dismiss on constitutional grounds.  Plaintiffs filed an appeal to the Second Circuit. Oral arguments were presented on June 7, 2006 and a decision on the appeal is pending.

Other Contingencies

The circumstances set forth in Notes 13, 14 and 15 to the consolidated financial statements in Xcel Energy’s Annual Report on Form 10-K for the year ended Dec. 31, 2005 and Notes 3, 4 and 5 to the consolidated financial statements in this Quarterly Report on

20




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:

·             Tax Matters — See Note 3 to the consolidated financial statements for discussion of exposures regarding the tax deductibility of corporate-owned life insurance loan interest; and

·             Guarantees — See Note 6 to the consolidated financial statements for discussion of exposures under various guarantees.

6. Short-Term Borrowings and Other Financing Instruments

Short-Term Borrowings

At June 30, 2006, Xcel Energy and its subsidiaries had $138.0 million of short-term debt outstanding at a weighted average yield of 5.43 percent.

Guarantees

Xcel Energy provides various guarantees and bond indemnities supporting certain of its 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 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 June 30, 2006, Xcel Energy had issued guarantees of up to $71.5 million with no 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 June 30, 2006, was approximately $133.2 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.

7. Derivative Valuation and Financial Impacts

Xcel Energy and its subsidiaries use a number of different derivative instruments in connection with their utility commodity price, interest rate, short-term wholesale and commodity trading activities, including forward contracts, futures, swaps and options. All derivative instruments not qualifying for the normal purchases and normal sales exception, as defined by SFAS No. 133— “Accounting for Derivative Instruments and Hedging Activities,” 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. This classification is dependent on the applicability of any regulatory mechanism in place. This includes certain instruments used to mitigate market risk for the utility operations and all instruments related to the commodity trading operations. The designation of a cash flow hedge permits the classification of fair value to be recorded within Other Comprehensive Income, to the extent effective. The designation of a fair value hedge permits a derivative instrument’s gains or losses to offset the related results of the hedged item in the Consolidated Statements of Income.

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. These derivative instruments are designated as cash flow hedges for accounting purposes, and the changes in the fair value of these instruments are recorded as a component of Other Comprehensive Income.

At June 30, 2006, Xcel Energy and its utility subsidiaries had various commodity-related contracts designated as cash flow hedges extending through 2009. The fair value of these cash flow hedges is recorded in either Other Comprehensive Income or deferred as a regulatory asset or liability. This classification is based on the regulatory recovery mechanisms in place. Amounts deferred in these accounts are recorded in earnings as the hedged purchase or sales transaction is settled. 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. As of June 30, 2006, Xcel Energy had no amounts in Accumulated Other Comprehensive Income related to commodity cash flow hedge contracts that are expected to be recognized in earnings during the next 12 months as the hedged transactions settle.

21




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 June 30, 2006, Xcel Energy had net gains of approximately $2.7 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 no hedge ineffectiveness in the second quarter of 2006.

The impact of qualifying cash flow hedges on Xcel Energy’s Accumulated Other Comprehensive Income, included in the Consolidated Statements of Stockholders’ Equity and Comprehensive Income, is detailed in the following table:

 

 

 

Three months ended
June 30,

 

(Millions of Dollars)

 

2006

 

2005

 

 

 

 

 

 

 

Accumulated other comprehensive income related to cash flow hedges at March 31

 

$

9.2

 

$

1.9

 

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

 

12.1

 

(22.0

)

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

 

(1.8

)

(2.3

)

Accumulated other comprehensive income (loss) related to cash flow hedges at June 30

 

$

19.5

 

$

(22.4

)

 

 

 

Six months ended
June 30,

 

(Millions of Dollars)

 

2006

 

2005

 

 

 

 

 

 

 

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

 

$

(8.8

)

$

0.1

 

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

 

28.8

 

(17.9

)

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

 

(0.5

)

(4.6

)

Accumulated other comprehensive income (loss) related to cash flow hedges at June 30

 

$

19.5

 

$

(22.4

)

 

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 have commodity trading operations that enter into derivative instruments. 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 on a net basis within Operating Revenues on the Consolidated Statements of Income.

Xcel Energy and its subsidiaries also 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 accordance with SFAS No. 133.

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 No. 133 requires a company to evaluate these contracts to determine whether the contracts are derivatives. Certain contracts that literally meet the definition of a derivative may be exempted from SFAS No. 133 as normal purchases or normal sales. Normal purchases and normal sales are contracts that provide for the purchase or sale of something other than a financial or derivative instrument that will be delivered in quantities expected to be used or sold over a reasonable period in the normal course of business. In addition, normal purchases and normal sales contracts must have a price based on an underlying that is clearly and closely related to the asset being purchased or sold. An underlying is a specified interest rate, security price, commodity price, foreign exchange rate, index of prices or rates, or other variable, including the occurrence or nonoccurrence of a specified event, such as a scheduled payment under a contract.

22




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 No. 133, as amended. None of the contracts entered into within the commodity trading operations qualify for a normal designation.

In 2003, as a result of FASB Statement 133 Implementation Issue No. C20, Xcel Energy began recording several long-term power purchase agreements at fair value due to accounting requirements related to underlying price adjustments. As these purchases are recovered through normal regulatory recovery mechanisms in the respective jurisdictions, the changes in fair value for these contracts were offset by regulatory assets and liabilities. During the first quarter of 2006, Xcel Energy qualified these contracts under the normal purchase exception. Based on this qualification, the contracts will no longer be adjusted to fair value and the previous carrying value of these contracts will be amortized over the remaining contract lives along with the offsetting regulatory balances.

Normal purchases and normal sales contracts are accounted for as executory contracts as required under other generally accepted accounting principles (GAAP).

8. Detail of Interest and Other Income (Expense) - Net

Interest and other income, net of nonoperating expenses, for the three and six months ended June 30 consisted of the following:

 

 

Three months ended
June 30,

 

(Thousands of Dollars)

 

2006

 

2005

 

 

 

 

 

 

 

Interest income

 

5,720

 

4,261

 

Equity income in unconsolidated affiliates

 

1,092

 

814

 

Other nonoperating income

 

2,828

 

5,443

 

Loss on the sale of investments

 

(909

)

 

Minority interest income

 

253

 

408

 

Interest expense on corporate-owned life insurance and other employee-related insurance policies

 

(7,977

)

(4,841

)

Other nonoperating expense

 

(86

)

(1,569

)

Total interest and other income - net

 

$

921

 

$

4,516

 

 

 

 

Six months ended
June 30,

 

(Thousands of Dollars)

 

2006

 

2005

 

 

 

 

 

 

 

Interest income

 

9,799

 

6,640

 

Equity income in unconsolidated affiliates

 

2,278

 

1,313

 

Other nonoperating income

 

4,319

 

6,752

 

Loss on the sale of investments

 

(1,818

)

 

Minority interest income

 

303

 

519

 

Interest expense on corporate-owned life insurance and other employee-related insurance policies

 

(13,558

)

(9,536

)

Other nonoperating expense

 

(786

)

(3,246

)

Total interest and other income - net

 

$

537

 

$

2,442

 

 

23




9. Common Stock and Equivalents

Xcel Energy has common stock equivalents consisting of convertible senior notes and stock options. The dilutive impacts of common stock equivalents affected earnings per share as follows for the three and six months ending June 30, 2006 and 2005:

 

 

Three months ended June 30, 2006

 

Three months ended June 30, 2005

 

(Amounts in thousands, except per share amounts)

 

Income

 

Shares

 

Per-share
Amount

 

Income

 

Shares

 

Per-share
Amount

 

Income from continuing operations

 

$

97,936

 

 

 

 

 

$

77,676

 

 

 

 

 

Less: Dividend requirements on preferred stock

 

(1,060

)

 

 

 

 

(1,060

)

 

 

 

 

Basic earnings per share:

 

 

 

 

 

 

 

 

 

 

 

 

 

Income from continuing operations

 

96,876

 

405,434

 

$

0.24

 

76,616

 

402,214

 

$

0.19

 

Effect of dilutive securities:

 

 

 

 

 

 

 

 

 

 

 

 

 

$230 million convertible debt

 

3,044

 

18,654

 

 

 

2,896

 

18,654

 

 

 

$57.5 million convertible debt

 

779

 

4,663

 

 

 

724

 

4,663

 

 

 

401(k) match

 

 

330

 

 

 

 

 

 

 

Stock options

 

 

18

 

 

 

 

21

 

 

 

Diluted earnings per share:

 

 

 

 

 

 

 

 

 

 

 

 

 

Income from continuing operations and assumed conversions

 

$

100,699

 

429,099

 

$

0.24

 

$

80,236

 

425,552

 

$

0.19

 

 

 

 

Six months ended June 30, 2006

 

Six months ended June 30, 2005

 

(Amounts in thousands, except per share amounts)

 

Income

 

Shares

 

Per-share
Amount

 

Income

 

Shares

 

Per-share
Amount

 

Income from continuing operations

 

$

247,748

 

 

 

 

 

$

202,139

 

 

 

 

 

Less: Dividend requirements on preferred stock

 

(2,120

)

 

 

 

 

(2,120

)

 

 

 

 

Basic earnings per share:

 

 

 

 

 

 

 

 

 

 

 

 

 

Income from continuing operations

 

245,628

 

404,783

 

$

0.61

 

200,019

 

401,668

 

$

0.50

 

Effect of dilutive securities:

 

 

 

 

 

 

 

 

 

 

 

 

 

$230 million convertible debt

 

6,002

 

18,654

 

 

 

5,707

 

18,654

 

 

 

$57.5 million convertible debt

 

1,501

 

4,663

 

 

 

1,427

 

4,663

 

 

 

401(k) match

 

 

231

 

 

 

 

 

 

 

Stock options

 

 

18

 

 

 

 

19

 

 

 

Diluted earnings per share:

 

 

 

 

 

 

 

 

 

 

 

 

 

Income from continuing operations and assumed conversions

 

$

253,131

 

428,349

 

$

0.59

 

$

207,153

 

425,004

 

$

0.49

 

 

10. Benefit Plans and Other Postretirement Benefits

Components of Net Periodic Benefit Cost

 

 

Three months ended June 30,

 

 

 

2006

 

2005

 

2006

 

2005

 

(Thousands of dollars)

 

Pension Benefits

 

Postretirement Health
Care Benefits

 

Service cost

 

$

14,380

 

$

12,980

 

$

1,479

 

$

1,599

 

Interest cost

 

38,197

 

39,496

 

13,287

 

13,663

 

Expected return on plan assets

 

(67,551

)

(69,484

)

(7,110

)

(6,267

)

Amortization of transition obligation

 

 

 

3,577

 

3,644

 

Amortization of prior service cost (credit)

 

7,421

 

7,496

 

(545

)

(544

)

Amortization of net (gain) loss

 

4,165

 

(39

)

5,875

 

6,460

 

Net periodic benefit cost (credit)

 

(3,388

)

(9,551

)

16,563

 

18,555

 

Credits not recognized due to the effects of regulation

 

3,893

 

6,500

 

 

 

Additional cost recognized due to the effects of regulation

 

 

 

973

 

973

 

Net benefit cost (credit) recognized for financial reporting

 

$

505

 

$

(3,051

)

$

17,536

 

$

19,528

 

 

24




 

 

 

Six months ended June 30,

 

 

 

2006

 

2005

 

2006

 

2005

 

(Thousands of dollars)

 

Pension Benefits

 

Postretirement Health
Care Benefits

 

 

 

 

 

 

 

 

 

 

 

Service cost

 

$

30,814

 

$

30,230

 

$

3,316

 

$

3,342

 

Interest cost

 

77,706

 

80,492

 

26,470

 

27,530

 

Expected return on plan assets

 

(134,032

)

(139,758

)

(13,378

)

(12,850

)

Amortization of transition obligation

 

 

 

7,222

 

7,289

 

Amortization of prior service cost (credit)

 

14,848

 

15,018

 

(1,090

)

(1,089

)

Amortization of net loss

 

8,676

 

3,410

 

12,398

 

13,123

 

Net periodic benefit cost (credit)

 

(1,988

)

(10,608

)

34,938

 

37,345

 

Credits not recognized due to the effects of regulation

 

6,318

 

9,684

 

 

 

Additional cost recognized due to the effects of regulation

 

 

 

1,946

 

1,946

 

Net benefit cost (credit) recognized for financial reporting

 

$

4,330

 

$

(924

)

$

36,884

 

$

39,291

 

 

11. Segment Information

Xcel Energy has the following reportable segments: Regulated Electric Utility, Regulated Natural Gas Utility and All Other. Commodity trading operations performed by regulated operating companies are not a reportable segment. Commodity trading results are included in the Regulated Electric Utility segment.

(Thousands of Dollars)

 

Regulated
Electric
Utility

 

Regulated
Natural Gas
Utility

 

All
Other

 

Reconciling
Eliminations

 

Consolidated
Total

 

 

 

 

 

 

 

 

 

 

 

 

 

Three months ended June 30, 2006

 

 

 

 

 

 

 

 

 

 

 

Operating revenues from external customers

 

$

1,786,571

 

$

270,990

 

$

16,312

 

$

 

$

2,073,873

 

Intersegment revenues

 

225

 

1,228

 

 

(1,453

)

 

Total revenues

 

$

1,786,796

 

$

272,218

 

$

16,312

 

$

(1,453

)

$

2,073,873

 

Income (loss) from continuing operations

 

$

93,783

 

$

2,955

 

$

20,783

 

$

(19,585

)

$

97,936

 

Three months ended June 30, 2005

 

 

 

 

 

 

 

 

 

 

 

Operating revenues from external customers

 

$

1,720,431

 

$

326,347

 

$

17,277

 

$

 

$

2,064,055

 

Intersegment revenues

 

(48

)

3,973

 

 

(3,925

)

 

Total revenues

 

$

1,720,383

 

$

330,320

 

$

17,277

 

$

(3,925

)

$

2,064,055

 

Income (loss) from continuing operations

 

$

88,751

 

$

931

 

$

7,718

 

$

(19,724

)

$

77,676

 

 

(Thousands of Dollars)

 

Regulated
Electric
Utility

 

Regulated
Natural Gas
Utility

 

All
Other

 

Reconciling
Eliminations

 

Consolidated
Total

 

Six months ended June 30, 2006

 

 

 

 

 

 

 

 

 

 

 

Operating revenues from external customers

 

$

3,632,443

 

$

1,289,130

 

$<