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

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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

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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

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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

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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

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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

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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

 

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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

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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,

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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;

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·                  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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